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, 2021 or

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

For the transition period from _____ to _____

001-03280

(Commission File Number)

Public Service Company of Colorado

(Exact name of registrant as specified in its charter)

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

303	571-7511
(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
N/A	N/A	N/A

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☒ No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. ☐ Large accelerated filer ☐ Accelerated filer ☒ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

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. 23, 2022, 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 2022 Annual Meeting of Shareholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 5, 2022. Such information set forth under such heading is incorporated herein by this reference hereto.

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

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TABLE OF CONTENTS

PART I
Item 1 —	Business	3
Item 1A —	Risk Factors	8
Item 1B —	Unresolved Staff Comments	15
Item 2 —	Properties	15
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 —	[Reserved]	16
Item 7 —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 7A —	Quantitative and Qualitative Disclosures About Market Risk	20
Item 8 —	Financial Statements and Supplementary Data	21
Item 9 —	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	49
Item 9A —	Controls and Procedures	49
Item 9B —	Other Information	49
Item 9C —	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	49
PART III
Item 10 —	Directors, Executive Officers and Corporate Governance	49
Item 11 —	Executive Compensation	49
Item 12 —	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	49
Item 13 —	Certain Relationships and Related Transactions, and Director Independence	49
Item 14 —	Principal Accountant Fees and Services	49
PART IV
Item 15 —	Exhibit and Financial Statement Schedules	50
Item 16 —	Form 10-K Summary	52
Signatures		53

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

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PART I

ITEM 1 — BUSINESS

Definitions of Abbreviations

Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
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 its subsidiaries

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

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

Other
AFUDC	Allowance for funds used during construction
ARO	Asset retirement obligation
ASC	FASB Accounting Standards Codification
C&I	Commercial and Industrial
CCR	Coal combustion residuals
CCR Rule	Final rule (40 CFR 257.50 - 257.107) published by the EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste
CEO	Chief executive officer
CFO	Chief financial officer
CIG	Colorado Interstate Gas Company, LLC
COEO	Colorado Energy Office
COVID-19	Novel coronavirus
CWA	Clean Water Act
CWIP	Construction work in progress
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit

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
ISO	Independent System Operators
ITC	Investment tax credit
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
NOPR	Notice of proposed rulemaking
O&M	Operating and maintenance
PFAS	Per- and PolyFluoroAlkyl Substances
Post-65	Post-Medicare
PPA	Purchased power agreement
Pre-65	Pre-Medicare
PTC	Production tax credit
REC	Renewable energy credit
ROE	Return on equity
ROU	Right-of-use
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Global Ratings
SERP	Supplemental executive retirement plan
SPP	Southwest Power Pool, Inc.
TCJA	2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act
VaR	Value at Risk
VIE	Variable interest entity

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

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Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including those relating to future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2021 (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, including potential workforce impacts resulting from vaccination requirements, quarantine policies or government restrictions, and sales volatility; 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; violations of our Codes of Conduct; 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, supply chain constraints and their impact on capital expenditures and/or the ability of PSCo to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; tax laws; 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; costs of potential regulatory penalties; and regulatory changes and/or limitations related to the use of natural gas as an energy source.

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.

Company 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	1.5 million
Total assets	$22.0 billion
Rate Base (estimated)	$14.0 billion
ROE (net income / average stockholder's equity)	8.23%
Electric generating capacity	6,228 MW
Gas storage capacity	32.5 Bcf
Electric transmission lines (conductor miles)	24,116 miles
Electric distribution lines (conductor miles)	78,712 miles
Natural gas transmission lines	2,174 miles
Natural gas distribution lines	23,243 miles

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Electric Operations

Electric operations consist of energy supply, generation, transmission and distribution activities. PSCo had electric sales volume of 33,519 (millions of KWh), 1.5 million customers and electric revenues of $3,413 (millions of dollars) for 2021.

Retail Sales/Revenue Statistics (a)

	2021			2020
KWH sales per retail customer	18,741			18,919
Revenue per retail customer	$	1,975		$	1,839
Residential revenue per KWh	12.46		¢	11.46		¢
Large C&I revenue per KWh	7.2		¢	6.51		¢
Small C&I revenue per KWh	10.46		¢	9.71		¢
Total retail revenue per KWh	10.54		¢	9.72		¢

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

Owned and Purchased Energy Generation — 2021

Electric Energy Sources

Total electric energy generation by source (including energy market purchases) for the year ended Dec. 31, 2021:

*Distributed generation from the Solar*Rewards® program is not included (approximately 627 million KWh for 2021).

Carbon–Free

PSCo’s carbon–free energy portfolio includes wind, hydroelectric and solar power from both owned generating facilities and PPAs. Carbon–free percentages will vary year over year based on system additions, commodity costs, weather, system demand and transmission constraints.

See Item 2 — Properties for further information.

Carbon–free energy as a percentage of total energy for 2021:

* Includes biomass and hydroelectric.

Wind

Owned — Owned and operated wind farms with corresponding capacity:

2021		2020
Wind Farms	Capacity (a)	Wind Farms	Capacity (b)
2	1,059 MW	2	1,059 MW

(a)Summer 2021 net dependable capacity.

(b)Summer 2020 net dependable capacity.

PPAs — Number of PPAs with capacity range:

2021		2020
PPAs	Range	PPAs	Range
17	23 MW — 301 MW	17	23 MW — 301 MW

Capacity — Wind capacity:

2021	2020
4,085 MW	4,085 MW

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

2021		2020
$	17	$	35

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

2021		2020
$	35	$	40

Solar

Solar energy PPAs:

Type	Capacity (MW)
Distributed Generation	736
Utility-Scale	562
Total	1,298

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

2021		2020
$	67	$	89

Solar Development

PSCo placed approximately 260 MW of PPAs into service during 2021.

Other

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

See Item 2 — Properties for further information.

Fossil Fuel

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

See Item 2 — Properties for further information.

Coal

PSCo owns and operates coal units with approximately 2,000 MW of total 2021 net summer dependable capacity.

Approved early coal plant retirements:

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

(a)Based on PSCo’s ownership interest.

Proposed
Year	Plant Unit	Capacity (MW)
2025	Pawnee (a)	505
2027	Hayden 2	98 (b)
2028	Hayden 1	135 (c)
2034	Comanche 3	500 (d)

(a)Reflects conversion from coal to natural gas.

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

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

(d)Based on PSCo’s ownership of 67%.

Coal Fuel Cost

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

	Coal
	Cost		Percent
2021	$	1.43	62	%
2020	1.41		51

Natural Gas

PSCo has six natural gas plants with approximately 2,900 MW of total 2021 net summer dependable capacity.

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
2021	$	8.38	38	%
2020	3.01		49

Capacity and Demand

Uninterrupted system peak demand and occurrence date:

System Peak Demand (MW)
2021		2020
6,958	July 28	6,899	Aug. 17

Transmission

Transmission lines deliver electricity over long distances from power sources to transmission substations closer to customers. A strong transmission system ensures continued reliable and affordable service, ability to meet state and regional energy policy goals, and support for a diverse generation mix, including renewable energy. PSCo owns more than 24,000 conductor miles of transmission lines across its service territory.

Notable upcoming projects:

Project	Miles	Size (KV)	Completion Date
Colorado Energy Plan	15	345	2022
Pathway	560	345	2027

See Item 2 - Properties for further information.

Distribution

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

See Item 2 - Properties for further information.

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Natural Gas Operations

Natural gas operations consist of purchase, transportation and distribution of natural gas to end-use residential, C&I and transport customers. PSCo had natural gas deliveries of 289,982 (thousands of MMBtu), 1.5 million customers and natural gas revenues of $1,355 (millions of dollars) for 2021.

Sales/Revenue Statistics (a)

	2021		2020
MMBtu sales per retail customer	99		101
Revenue per retail customer	$	797	$	632
Residential revenue per MMBtu	8.35		6.47
C&I revenue per MMBtu	7.35		5.70
Transportation and other revenue per MMBtu	1.37		0.65

(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:

2021		2020
MMBtu	Date (a)	MMBtu	Date
2,316,283	Feb. 14	1,931,888	Feb. 4

(a)Reflective of Winter Storm Uri.

Natural Gas Supply and Costs

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

2021 (a)		2020
$	6.06	$	2.52

(a)Reflective of Winter Storm Uri.

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.

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FERC Order No. 1000 established competition for ownership of certain new electric transmission facilities under Federal regulations. Some states have state laws that allow the incumbent a Right of First Refusal to own these transmission facilities.

FERC Order 2222 requires that RTO and ISO markets allow participation of aggregations of distributed energy resources. This order is expected to incentivize distributed energy resource adoption, however implementation is expected to vary by RTO/ISO and the near, medium, and long-term impacts of Order 2222 remain unclear.

PSCo has franchise agreements with cities subject to periodic renewal; however, a city could seek alternative means to access electric power or gas, such as municipalization.

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

Governmental Regulations

Public Utility Regulation

See Item 7 for discussion of public utility regulation.

Environmental Regulation

Our facilities are regulated by federal and state agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid and hazardous wastes or substances. Certain PSCo activities require registrations, permits, licenses, inspections and approvals from these agencies. PSCo has received necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Our facilities strive to operate in compliance with applicable environmental standards and related monitoring and reporting requirements. However, it is not possible to determine what additional facilities or modifications 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.

The Denver North Front Range Non-attainment Area does not meet the 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 requires states to develop plans by 2022 for GHG reductions from coal-fired power plants. In January 2021, the U.S. Court of Appeals for the D.C. Circuit issued a decision vacating and remanding the Affordable Clean Energy rule. That decision would allow the EPA to proceed with alternate regulation of coal-fired power plants. However, the Court of Appeals decision is now before the U.S. Supreme Court, where the Court is expected to rule on the nature and extent of the EPA’s GHG regulatory authority. If any new rules require additional investment, PSCo believes that the cost of these initiatives or replacement generation would be recoverable through rates based on prior state commission practices.

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

Emerging Environmental Regulation

New regulations and legislation are being considered to regulate PFAS in drinking water, water discharges, commercial products, wastes, and other areas. PFAS are man-made chemicals found in many consumer products that can persist and accumulate in the environment. These chemicals have received heightened attention from environmental regulators. Increased regulation of PFAS and other emerging contaminants at the federal, state, and local level could have a potential adverse effect on our operations but at this time, it is uncertain what impact, if any, there will be on our operations, financial condition or cash flows. PSCo will continue to monitor these regulatory developments and their potential impact on its operations.

Other

Our operations are subject to workplace safety standards under the Federal Occupational Safety and Health Act of 1970 (“OSHA”) and comparable state laws that regulate the protection of worker health and safety. In addition, the Company is subject to other government regulations impacting such matters as labor, competition, data privacy, etc. Based on information to date and because our policies and business practices are designed to comply with all applicable laws, we do not believe the effects of compliance on our operations, financial condition or cash flows are material.

Employees

As of Dec. 31, 2021, PSCo had 2,314 full-time employees and no part-time employees, of which 1,818 were covered under collective-bargaining agreements.

ITEM 1A — RISK FACTORS

Xcel Energy, which includes PSCo, is subject to a variety of risks, many of which are beyond our control. Risks that may adversely affect the business, financial condition, results of operations or cash flows are described below. Although the risks are organized by heading, and each risk is described separately, many of the risks are interrelated. These risks should be carefully considered together with the other information set forth in this report and future reports that Xcel Energy files with the SEC. You should not interpret the disclosure of any risk factor to imply that the risk has not already materialized. While we believe we have identified and discussed below the key risk factors affecting our business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant that may adversely affect our business, financial condition, results of operations or cash flows in the future.

Oversight of Risk and Related Processes

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

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.

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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.

Operational Risks

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

Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses to employees, third-party contractors, customers or the public.

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

Other uncertainties and risks inherent in operating and maintaining PSCo's facilities include, but are not limited to:

•Risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned.

•Failures in the availability, acquisition or transportation of fuel or other 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.

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The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. Higher electric demand may require us to adopt new technologies and make significant transmission and distribution investments including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. Evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may impact our resource mix and put pressure on our ability to recover capital investments in natural gas generation and delivery. Multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets.

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

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

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

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

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.

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 programs and procedures 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.

In 2021, the competition for talent has become increasingly intense as a result of the ongoing “great resignation”, and we may experience increased employee turnover due to this tightening labor market. In addition, specialized knowledge is required of our technical employees for construction and operation of transmission, generation and distribution assets, which may pose additional difficulty for us as we work to recruit, retain and motivate employees in this climate. Failure to hire and adequately train replacement employees, including the transfer of significant 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 or contractor unavailability could impact ongoing operations, restoration operations, our reputation and could introduce financial risk or risks of fines.

Our employees, directors, third-party contractors, or suppliers may violate or be perceived to violate our Codes of Conduct, which could have an adverse effect on our reputation.

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

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

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

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We have historically paid quarterly dividends to Xcel Energy Inc. In 2021, 2020 and 2019 we paid $467 million, $831 million and $457 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.

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, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios and impacts of tax policy may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.

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

We are subject to capital market and interest rate risks.

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

We are subject to credit risks.

Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in 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 ISO, SPP, PJM Interconnection, LLC, Midcontinent ISO, 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, 2021, Xcel Energy Inc. and its utility subsidiaries had approximately $21.8 billion of long-term debt and $1.6 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.

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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, 2021, Xcel Energy had guarantees outstanding with a $1 million maximum stated amount and immaterial exposure. Xcel Energy also had additional guarantees of $59 million at Dec. 31, 2021 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/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies such as tax normalization may impact our ability to economically deliver certain types of resources relative to market prices.

Macroeconomic Risks

Economic conditions impact our business.

Our operations are affected by 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.

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 continues to impact countries, communities, supply chains and markets. A high degree of uncertainty continues to exist regarding the pandemic; the duration and magnitude of business restrictions (domestically and globally); the potential shortages of employees and third-party contractors due to quarantine policies, vaccination requirements or government restrictions; re-shutdowns, if any, and the level and pace of economic recovery.

PSCo has experienced and may continue to experience sales volatility and shifts between residential and C&I sales as a result of COVID-19. PSCo has a decoupling mechanism in Colorado for residential and non-demand small C&I electric customer classes. These mechanisms mitigate the impact of changes to sales levels as compared to a baseline.

Although the financial impact of the pandemic on our financial results has largely been mitigated, 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.

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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. PSCo participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to 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 GridEx, which is the largest grid security exercise in North America. 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. During the normal course of business, we have experienced and expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure and other assets. To date, no cybersecurity incident or attack has had a material impact on our business or results of operation.

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.

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. In April 2021, ahead of the United Nations Climate Change Conference in Glasgow, the Biden Administration committed the U.S. to a Nationally Determined Contribution of 50-52% net GHG emissions reduction economy-wide from 2005 levels. This commitment and other agreements made in Glasgow 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.

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.

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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.

The continued use of natural gas for both power generation and gas distribution have increasingly become a public policy advocacy target. These efforts may result in a limitation of natural gas as an energy source for both power generation and heating, which could impact our ability to reliably and affordably serve our customers.

In recent years, there have been various local and state agency proposals within and outside our service territories that would attempt to restrict the use and availability of natural gas. If such policies were to prevail, we may be forced to make new resource investment decisions which could potentially result in stranded costs if we are not able to fully recover costs and investments and impact the overall reliability of our service.

Environmental 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.

Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues.

Climate change may impact the economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

We have committed to a number of long-term climate change goals, which in part are dependent on future technologies not currently in existence. Given the long-term nature of these goals, there is an inherent uncertainty due to internal and external factors regarding our ability to achieve our stated climate change goals. To the extent climate change goals are not met, this could negatively impact our reputation and potentially result in financial risk.

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.

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While we carry liability insurance, given an extreme event, if PSCo was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows. Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants and increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks.

ITEM 1B — UNRESOLVED STAFF COMMENTS

None.

ITEM 2 — PROPERTIES

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

Station, Location and Unit at Dec. 31, 2021	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	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	973
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	6,228

(a)    Summer 2021 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).

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2021:

Conductor Miles
Transmission
345 KV	4,978
230 KV	12,141
138 KV	92
115 KV	5,075
Less than 115 KV	1,830
Total Transmission	24,116
Distribution
Less than 115 KV	78,712
Total	102,828

PSCo had 237 electric utility transmission and distribution substations at Dec. 31, 2021.

Natural gas utility mains at Dec. 31, 2021:

Miles
Transmission	2,174
Distribution	23,243

ITEM 3 — LEGAL PROCEEDINGS

PSCo is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation.

Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to, when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on PSCo’s consolidated financial statements. Legal fees are generally expensed as incurred.

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

ITEM 4 — MINE SAFETY DISCLOSURES

None.

PART II

ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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

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

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The dividends declared during 2021 and 2020 were as follows:

(Millions of Dollars)	2021		2020
First quarter	$	115	$	103
Second quarter	120		465
Third quarter	127		128
Fourth quarter	104		128

ITEM 6 — [RESERVED]

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

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

Non-GAAP Financial Measures

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

Earnings Adjusted for Certain Items (Ongoing Earnings)

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

We use these non-GAAP financial measures to evaluate and provide details of PSCo’s core earnings and underlying performance. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of PSCo. For the years ended Dec. 31, 2021 and 2020, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.

Results of Operations

2021 Comparison to 2020

PSCo’s net income was $660 million for 2021, compared with $588 million for 2020, driven by capital investment recovery and other regulatory outcomes. Higher revenues were partially offset by increased depreciation, O&M expenses and other taxes (other than income taxes).

Electric Margin

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

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

Electric Revenues, Fuel and Purchased Power and Electric Margin

(Millions of Dollars)	2021		2020
Electric revenues	$	3,413	$	3,116
Electric fuel and purchased power	(1,336)		(1,132)
Electric margin	$	2,077	$	1,984

Changes in Electric Margin

(Millions of Dollars)	2021 vs. 2020
Non-fuel riders	$	107
Regulatory rate outcome	20
Proprietary commodity trading, net of sharing (a)	15
PTCs flowed back to customers (offset by lower ETR)	(44)
Other (net)	(5)
Total increase in electric margin	$	93

(a)Includes $11 million of net gains recognized in the first quarter of 2021, driven by market changes associated with Winter Storm Uri. Additional amounts are primarily related to long-term physical generation contracts, which have increased in value as a result of higher energy prices.

Natural Gas Margin

Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for the cost of natural gas sold are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.

Natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas generally have minimal earnings impact due to cost recovery mechanisms.

Natural Gas Revenues, Cost of Natural Gas Sold and Transported and Natural Gas Margin

(Millions of Dollars)	2021		2020
Natural gas revenues	$	1,355	$	1,024
Cost of natural gas sold and transported	(606)		(374)
Natural gas margin	$	749	$	650

Changes in Natural Gas Margin

(Millions of Dollars)	2021 vs. 2020
Regulatory rate outcomes	$	89
Infrastructure and integrity riders	5
Estimated impact of weather	(9)
Other	14
Total increase in natural gas margin	$	99

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Non-Fuel Operating Expenses and Other Items

Taxes (Other than Income Taxes) — Taxes (other than income taxes) increased $22 million year-to-date, primarily due to higher property taxes.

Depreciation and Amortization — Depreciation and amortization increased $89 million, year-to-date. The increase was primarily due to the in-servicing of the Cheyenne Ridge wind farm, new depreciation rates, normal system expansion and Comanche related regulatory asset amortization, partially offset by a decrease in amortization of pension regulatory assets.

Income Taxes — Income tax expense decreased $12 million for 2021, primarily driven by an increase in wind PTCs. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. These were partially offset by higher pretax earnings in 2021 and additional expense related to unrecognized tax benefits.

Other

Comanche Unit 3 Outage

In January 2022, PSCo experienced an incident at the Comanche Unit 3 plant (750 MW, coal-fueled electric generating unit) resulting in damage and an outage that is expected to last approximately two months. PSCo has notified the CPUC and informed them that it will not seek recovery of any replacement power costs above the expected costs if Comanche 3 had been in service. The estimated incremental replacement power costs could be approximately $10 million, assuming a two month outage, normal weather and current market pricing.

Marshall Wildfire

In December 2021, a wildfire ignited in Boulder County, Colorado (the “Marshall Fire”), which burned over 6,000 acres and destroyed or damaged over 1,000 structures. While there were no downed power lines in the ignition area, the determination of the cause of the Marshall Fire is pending. In Colorado, the standard of review governing liability differs from the “inverse condemnation” or strict liability standard utilized in California. In Colorado, courts look to whether electric power companies have operated their system with a heightened duty of care consistent with the practical conduct of its business, and liability does not extend to occurrences that cannot be reasonably anticipated. In addition, PSCo has been operating under a commission approved wildfire mitigation plan and carries wildfire liability insurance. However, in the unlikely event we were found liable, the damages awarded could exceed our coverage and negatively impact our results of operations, financial conditions or cash flows.

Winter Storm Uri

In February 2021, the United States experienced Winter Storm Uri. Extreme cold temperatures impacted certain operational assets as well as the availability of renewable generation. The cold weather also affected the country’s supply and demand for natural gas. These factors contributed to extremely high market prices for natural gas and electricity. As a result of the extremely high market prices, PSCo incurred net natural gas, fuel and purchased energy costs of approximately $610 million (largely deferred as regulatory assets).

PSCo has natural gas, fuel and purchased energy mechanisms in each jurisdiction for recovering incurred costs. However, the utility subsidiaries have deferred February 2021 cost increases for future recovery and sought recovery of the cost increases over a period of up to 30 months to mitigate the impact to customer bills. Additionally, we did not request recovery of financing costs in order to further limit the impact to our customers.

Regulatory Overview — In May, PSCo filed a request with the CPUC to recover $263 million in weather-related electric costs, $287 million in incremental natural gas costs and $4 million in incremental steam costs over 24 months with no financing charge.

In September, intervenors filed testimony. The CPUC Staff recommended disallowances of approximately $99 million (electric) and $105 million (natural gas). Additionally, they proposed to net approximately $50 million of regulatory liabilities (decoupling related) from electric costs. The Utility Consumer Advocate recommended disallowances of approximately $131 million. The COEO recommended disallowances of approximately $46 million for not utilizing demand response programs during the event.

In October, a partial settlement was reached with the CPUC Staff and the COEO, allowing full recovery of Winter Storm Uri deferred net natural gas, fuel and purchased energy costs of $263 million (electric utility) and $287 million (natural gas utility) over a 24-month and 30-month period, respectively, with no carrying charges through a rider mechanism.

A decision is expected in the first quarter of 2022. In addition, the CPUC is considering prospective changes in fuel cost recovery.

Public Utility Regulation

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

Rates are designed to recover plant investment, operating costs and an allowed return on investment. PSCo requests changes in utility rates through commission filings. Changes in operating costs can affect PSCo’s financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital.

In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact PSCo’s results of operations.

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.
SPP Western Energy Imbalance Service Market	Balances generation and load regionally and in real time for participants in the Western Interconnection

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Recovery Mechanisms

Mechanism	Additional Information
ECA	Recovers fuel and purchased energy costs. Short-term sales margins are shared with customers. The ECA is revised quarterly.
Purchased Capacity Cost Adjustment	Recovers purchased capacity payments.
Steam Cost Adjustment	Recovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly.
DSM Cost Adjustment	Recovers electric and gas DSM, interruptible service costs and performance initiatives for achieving energy savings goals.
RES Adjustment	Recovers the incremental costs of compliance with the RES with a maximum of 1% of the customer’s bill.
Colorado Energy Plan Adjustment	Recovers the early retirement costs of Comanche units 1 and 2 to a maximum of 1% of the customer’s bill.
Wind Cost Adjustment	Recovers costs for customers who choose renewable resources.
Transmission Cost Adjustment	Recovers costs for transmission investment between rate cases.
Clean Air Clean Jobs Act	Recovers costs associated with the Clean Air Clean Jobs Act.
Fuel Clause Adjustment	PSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up.
GCA	Recovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates.
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.

Pending and Recently Concluded Regulatory Proceedings

Colorado Natural Gas Rate Case — In January 2022, PSCo filed a request with the CPUC seeking a net increase to retail natural gas rates of $107 million. The total change to base rates is $215 million, reflecting the transfer of $108 million previously recovered from customers through the PSIA rider, which was closed to new investments at the end of 2021. The request is based on a 10.25% ROE, an equity ratio of 55.66% and a 2022 current test year. PSCo has requested a proposed effective date of Nov. 1, 2022.

Additionally, PSCo’s request includes step revenue increases of $40 million in 2023 (effective Nov. 1, 2023) and $41 million in 2024 (effective Nov. 1, 2024) related to continued capital investment. Under this proposal, PSCo would not request another base rate change prior to Nov. 1, 2025. An informational historical test year, including a 10.75% ROE, was also filed as required by the CPUC.

Revenue Request (millions of dollars)	2022
Changes since 2020 rate case:
Plant related investments (a)	$	210
Operations and maintenance, amortization and other expenses	11
Property tax expense	11
Sales growth	(17)
Net increase to revenue	215
Previously authorized costs:
Transfer of costs previously recovered through the PSIA rider	(108)
Total base revenue request	$	107
Projected 2022 year-end rate base (billions of dollars)	$	3.6

(a)    Includes approximately $28 million as a result of the increase in ROE from 9.2% to 10.25%.

Colorado Electric Rate Request — In July 2021, PSCo filed a request with the CPUC seeking a net electric rate increase of $343 million (or 12.4%). The total request reflects a $470 million increase, which includes $127 million of previously authorized costs currently recovered through various rider mechanisms. The request is based on a 10.0% ROE, an equity ratio of 55.64%, a 2022 forecast test year, a rate base of $10.3 billion and impacts of a new depreciation study.

In January 2022, PSCo reached an unopposed comprehensive settlement. The CPUC is expected to rule on the settlement in March 2022 with final rates expected to be effective in April 2022. Key settlement terms include:

•A net electric rate increase of $177 million. The total change in base rates is $299 million, which includes $122 million of revenue previously collected through various rider mechanisms.

•A ROE of 9.3% and an equity ratio of 55.69%.

•A current 2021 test year (average rate base) with the transfer of Cheyenne Ridge, Wildfire Mitigation Plan and Advanced Grid Intelligence and Security investments at year-end rate base.

•Approval of all of PSCo’s proposed depreciation adjustments.

•Continuation of the property tax, qualified pension, and non-qualified pension trackers.

•Continuation of Advanced Grid Intelligence and Security deferral including interest equivalent to PSCo's weighted average cost of capital once the balance exceeds $50 million.

•Continuation of the Wildfire Mitigation Plan deferral, with a debt return.

PSIA Rider Extension — In October 2021, the CPUC approved a settlement agreement to allow the rider to end on Dec. 31, 2021, transfer the investments recovered under the rider to base rates Jan. 1, 2022, and defer $9 million of depreciation expense and return on $143 million in project costs in 2022.

Pathway Transmission Expansion Settlement — In November 2021, PSCo filed a non-unanimous settlement agreement with Staff and several other parties regarding its CPCN request for the Pathway Transmission project.

Key settlement terms include:

•The parties agreed that PSCo met the burden of proof demonstrating that the project was needed to facilitate the renewables in the Integrated Resource Plan and is in the public interest.

•Agreed to a cost estimate of $1.7 billion and recovery through the transmission rider.

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•The Pathway project will also include a Performance Incentive Mechanism such that applicable costs in a given year above or below a 5% dead band would allow for a ROE penalty or adder.

•Parties agreed to conditional CPCN approval for 345 kV extension project subject to the project being included in the final approved Integrated Resource Plan with a cost estimate of $247 million.

The settlement agreement is currently being deliberated by the CPUC.

Resource Plan Settlement — In November 2021, PSCo and intervenors filed a partial settlement of the resource plan, which will result in an expected 87% carbon reduction and an 80% renewable mix by 2030. A CPUC decision is expected in the first quarter of 2022. Key settlement terms include:

•Early retirement of Hayden: Unit 2 in 2027 (was 2036); and Unit 1 in 2028 (was 2030).

•Conversion of Pawnee to burn natural gas by 2026.

•Early retirement of Comanche 3 in 2034 with reduced operations beginning in 2025.

•Addition of ~2,300 MW of wind.

•Addition of ~1,600 MW of utility-scale solar.

•Addition of 400 MW of storage.

•Addition of 1,300 MW of flexible, dispatchable generation.

•Addition of ~1,200 MW of distributed solar resources through our renewable energy programs.

Partial Settlement — In October 2021, PSCo filed a comprehensive settlement with the CPUC Staff and the COEO, which proposed to address four outstanding regulatory items, including recovery of fuel costs related to Winter Storm Uri, disputed revenue associated with the 2020 electric decoupling pilot program year, replacement power costs associated with an extended outage at Comanche Unit 3 during 2020 and deferred customer bad debt balances associated with COVID-19. The Utility Consumer Advocate has not signed the settlement. A hearing and a CPUC decision on the settlement is expected in the first quarter of 2022.

Key terms of the proposed settlement:

•PSCo would fully recover Winter Storm Uri deferred net natural gas, fuel and purchased energy costs of $263 million (electric utility) and $287 million (natural gas utility) over a 24-month and 30-month period, respectively, with no carrying charges through a rider mechanism. Recovery would commence Jan. 1, 2022 for electric costs and April 1, 2022 for natural gas costs.

•PSCo will refund electric customers $41 million (previously deferred) related to the 2020 electric decoupling pilot program.

•PSCo agreed to forego recovery of $14 million for replacement power costs due to an extended outage at Comanche Unit 3 during 2020 (approved by the CPUC in February 2022 as part of the 2020 ECA settlement agreement).

•PSCo also agreed to not seek recovery of COVID-19 related bad debt expense, previously deferred as a regulatory asset, and recorded an additional $11 million of incremental bad debt expense for the period ended Dec. 31, 2021.

Decoupling Filing — PSCo's 2019 Electric Rate Case included a decoupling program, effective April 1, 2020 through Dec. 31, 2023. The program applies to Residential and metered small C&I customers who do not pay a demand charge. The program includes a refund and surcharge cap not to exceed 3% of forecasted base rate revenue for a specified period.

In April 2021, PSCo made its annual filing for 2020, and the revised tariff went into effect by operation of law on June 1, 2021. In the annual filing review, the CPUC indicated they may pursue reopening the case in order to revisit the cap. As of Dec. 31, 2021, PSCo has recognized a refund for Residential customers and a surcharge for C&I customers based on 2020 and 2021 results.

In October 2021, a settlement was reached on Winter Storm Uri costs and also addressed certain components of decoupling. See Partial Settlement disclosure above for further discussion.

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 unit. 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 incurred replacement power costs of approximately $16 million during the outage.

In October 2020, the CPUC initiated a review of Comanche Unit 3’s performance. In March 2021, the CPUC Staff issued a report, which noted higher-than average outages and included criticisms of PSCo’s operations of Comanche Unit 3 over the last ten years. The report recommended thorough explanation of the future of Comanche Unit 3 operations in the next resource plan, performance standards for all company-owned generation and a review of outage and repair costs in upcoming ECA proceedings.

In October 2021, a comprehensive settlement was reached, which addressed treatment of 2020 Comanche Unit 3 replacement power costs. See Partial Settlement disclosure above for further discussion.

2019 Electric Rate Case Appeal — In August 2020, PSCo filed an appeal with the Denver District Court seeking a review of CPUC decisions on gains and losses on sales of assets, oil and gas royalty revenues, Board of Directors equity compensation and a true-up surcharge to collect the difference between rates from February through August 2020 based on the CPUC’s decision on the Company’s Application for Reconsideration, Rehearing or Reargument and rates that were actually in place. In January 2022, the Denver District Court issued its decision that the CPUC’s approach to gains and losses on certain sales of assets was legally erroneous and confiscatory to PSCo and set aside and remanded the issue for further consideration. The District Court affirmed the CPUC with respect to the remaining decisions.

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GCA NOPR — In June 2021, the CPUC issued a NOPR addressing the recovery of costs through the GCA. The proposed rule would establish an annual forecast of GCA costs for each utility and allow each utility to recover only 90%-95% of any costs in excess of the forecasted amount. The proposed rule would allow utilities to earn an incentive equal to an undefined portion of any savings relative to forecasted costs. Comments were filed and requested that the CPUC delay the rule making process until after the 2021 - 2022 heating season; in part because utilities have already proceeded with purchasing gas for the upcoming heating season in accordance with prior CPUC decisions. The CPUC has reopened the GCA NOPR matter and the parties will submit follow-up comments during the first quarter of 2022.

Purchased Power and Transmission Service Providers

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

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

Energy Markets — PSCo plans to join the SPP Western Energy Imbalance Service Market in April 2023. This market is an incremental step in the participation in the organized wholesale market. Energy imbalance markets allow participants to buy and sell power close to the time electricity is consumed and gives system operators real-time visibility across neighboring grids. The result improves balancing supply and demand at a lower cost.

Purchased Transmission Services — In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers.

Wholesale and Commodity Marketing Operations

PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. PSCo uses physical and financial instruments to minimize commodity price 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.

Fair value of net commodity trading contracts as of Dec. 31, 2021:

	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)		$	6	$	6	$	1	$	1	$	14
PSCo (b)		(37)		(48)		—		—		(85)
		$	(31)	$	(42)	$	1	$	1	$	(71)

	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)		$	27	$	29	$	—	$	—	$	56

(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)	2021		2020
Fair value of commodity trading net contracts outstanding at Jan. 1	$	(46)	$	(57)
Contracts realized or settled during the period	4		2
Commodity trading contract additions and changes during the period	27		9
Fair value of commodity trading net contracts outstanding at Dec.31	$	(15)	$	(46)

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At Dec. 31, 2021, a 10% increase in market prices for commodity trading contracts through the forward curve would increase pretax income from continuing operations by approximately $10 million, whereas a 10% decrease would decrease pretax income from continuing operations by approximately $10 million. At Dec. 31, 2020, a 10% increase in market prices for commodity trading contracts 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. 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
2021	$	1	$	3	$	2	$	52	$	1
2020	1		3		1		2		1

A short-term increase in VaR occurred during the week of Feb. 12, 2021 through Feb. 18, 2021. On Feb. 17, 2021, the portfolio VaR reached a high of $52 million. This increase in VaR was driven by the unprecedented market conditions during Winter Storm Uri. Prior to this widespread weather event, VaR was $1 million and returned to $1 million by Feb. 19, 2021.

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 2021 and 2020, 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, 2021, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $6 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $5 million. 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.

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, 2021. 

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, 2021.

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

ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

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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, 2021. 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, 2021, PSCo’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.

/s/ ROBERT C. FRENZEL	/s/ BRIAN J. VAN ABEL
Robert C. Frenzel	Brian J. Van Abel
Chairman, Chief Executive Officer and Director	Executive Vice President, Chief Financial Officer and Director
Feb. 23, 2022	Feb. 23, 2022

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Public Service Company of Colorado and subsidiaries (the "Company") as of December 31, 2021 and 2020, the related consolidated statements of income, comprehensive income, common stockholder's equity and cash flows for each of the three years in the period ended December 31, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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.

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

How the Critical Audit Matter Was Addressed in the Audit

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

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

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

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

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

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 23, 2022

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

24

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in millions)

	Year Ended Dec. 31
	2021		2020		2019
Operating revenues
Electric	$	3,413	$	3,116	$	3,033
Natural gas	1,355		1,024		1,161
Other	47		43		43
Total operating revenues	4,815		4,183		4,237
Operating expenses
Electric fuel and purchased power	1,336		1,132		1,083
Cost of natural gas sold and transported	606		374		526
Cost of sales — steam and other	15		13		17
Operating and maintenance expenses	831		811		810
Demand side management expenses	132		141		136
Depreciation and amortization	744		655		602
Taxes (other than income taxes)	256		234		206
Total operating expenses	3,920		3,360		3,380
Operating income	895		823		857
Other income (expense), net	4		(1)		3
Allowance for funds used during construction — equity	28		35		22
Interest charges and financing costs
Interest charges — includes other financing costs of $8, $7 and $7, respectively	243		238		235
Allowance for funds used during construction — debt	(9)		(14)		(11)
Total interest charges and financing costs	234		224		224
Income before income taxes	693		633		658
Income tax expense	33		45		80
Net income	$	660	$	588	$	578

See Notes to Consolidated Financial Statements

25

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(amounts in millions)

	Year Ended Dec. 31
	2021		2020		2019
Net income	$	660	$	588	$	578
Other comprehensive income (loss)
Pension and retiree medical benefits:
Reclassification of loss (gain) to net income, net of tax of $—, $1 and $(1), respectively	—		2		(3)
Derivative instruments:
Reclassification of loss to net income, net of tax of $—, $— and $—, respectively	2		1		2
Total other comprehensive income (loss)	2		3		(1)
Total comprehensive income	$	662	$	591	$	577

See Notes to Consolidated Financial Statements

26

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in millions)

	Year Ended Dec. 31
	2021		2020		2019
Operating activities
Net income	$	660	$	588	$	578
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	754		656		607
Deferred income taxes	21		2		97
Amortization of investment tax credits	11		—		—
Allowance for equity funds used during construction	(28)		(35)		(22)
Provision for bad debts	26		24		17
Net realized and unrealized hedging and derivative transactions	(44)		(14)		62
Changes in operating assets and liabilities:
Accounts receivable	(58)		(51)		(22)
Accrued unbilled revenues	(52)		(5)		20
Inventories	(71)		(27)		(27)
Prepayments and other	(23)		(8)		(29)
Accounts payable	66		(14)		(44)
Net regulatory assets and liabilities	(526)		58		35
Other current liabilities	30		45		—
Pension and other employee benefit obligations	(53)		(41)		(47)
Other, net	14		(4)		3
Net cash provided by operating activities	727		1,174		1,228
Investing activities
Utility capital/construction expenditures	(1,604)		(1,671)		(1,691)
Investments in utility money pool arrangement	(273)		(122)		(641)
Repayments from utility money pool arrangement	273		122		641
Net cash used in investing activities	(1,604)		(1,671)		(1,691)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	11		136		(307)
Borrowings under utility money pool arrangement	743		1,189		100
Repayments under utility money pool arrangement	(800)		(1,171)		(61)
Proceeds from issuance of long-term debt	737		735		928
Repayments of long-term debt	—		(400)		(400)
Capital contributions from parent	650		856		638
Dividends paid to parent	(467)		(831)		(457)
Net cash provided by financing activities	874		514		441
Net change in cash and cash equivalents	(3)		17		(22)
Cash, cash equivalents and restricted cash at beginning of period	28		11		33
Cash, cash equivalents and restricted cash at end of period	$	25	$	28	$	11
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(230)	$	(211)	$	(209)
Cash paid for income taxes, net	(14)		(23)		(5)
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	$	157	$	197	$	234
Inventory transfers to property, plant and equipment	10		35		32
Operating lease right-of-use assets	—		14		654
Allowance for equity funds used during construction	28		35		22

See Notes to Consolidated Financial Statements

27

PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(amounts in millions, except share and per share)

	Dec. 31
	2021		2020
Assets
Current assets
Cash and cash equivalents	$	25	$	28
Accounts receivable, net	374		342
Accounts receivable from affiliates	13		8
Accrued unbilled revenues	350		298
Inventories	245		189
Regulatory assets	353		121
Derivative instruments	39		21
Prepayments and other	104		82
Total current assets	1,503		1,089
Property, plant and equipment, net	18,444		17,470
Other assets
Regulatory assets	1,293		1,059
Derivative instruments	27		16
Operating lease right-of-use assets	409		500
Other	246		231
Total other assets	1,975		1,806
Total assets	$	21,922	$	20,365
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	300	$	—
Borrowings under utility money pool arrangement	—		57
Short-term debt	147		136
Accounts payable	531		452
Accounts payable to affiliates	69		58
Regulatory liabilities	95		100
Taxes accrued	252		251
Accrued interest	58		61
Dividends payable to parent	104		105
Derivative instruments	30		27
Operating lease liabilities	84		97
Other	109		84
Total current liabilities	1,779		1,428
Deferred credits and other liabilities
Deferred income taxes	1,960		1,897
Regulatory liabilities	2,397		2,337
Asset retirement obligations	422		399
Derivative instruments	29		51
Customer advances	160		168
Pension and employee benefit obligations	23		161
Operating lease liabilities	351		432
Other	190		176
Total deferred credits and other liabilities	5,532		5,621
Commitments and contingencies
Capitalization
Long-term debt	6,167		5,724
Common stock — 100 shares authorized of $0.01 par value; 100 shares outstanding at Dec. 31, 2021 and Dec. 31, 2020, respectively	—		—
Additional paid in capital	6,426		5,770
Retained earnings	2,040		1,846
Accumulated other comprehensive loss	(22)		(24)
Total common stockholder's equity	8,444		7,592
Total liabilities and stockholder's equity	$	21,922	$	20,365
See Notes to Consolidated Financial Statements

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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, 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
Net income						660				660
Other comprehensive income								2		2
Common dividends declared to parent						(466)				(466)
Contribution of capital by parent				656						656
Balance at Dec. 31, 2021	100	$	—	$	6,426	$	2,040	$	(22)	$	8,444
See Notes to Consolidated Financial Statements

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PUBLIC SERVICE COMPANY of COLORADO

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

General — PSCo is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and 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, 2021 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 for items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results.

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

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

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

Estimates 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 an evaluation of whether future recovery is expected.

Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize 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.

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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 commission-approved useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Plant removal costs are recovered in rates as authorized by the appropriate regulatory entities. The amount of removal costs is based on current factors used in existing depreciation rates. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.2% in 2021, 3.1% in 2020 and 2.9% in 2019.

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. For certain environmental costs related to facilities currently in use, such as for emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs are regularly adjusted as estimates are revised and remediation 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, 2021 and 2020, the allowance for bad debts was $40 million and $29 million, respectively.

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

(Millions of Dollars)	Dec. 31, 2021		Dec. 31, 2020
Inventories
Materials and supplies	$	70	$	63
Fuel	71		73
Natural gas	104		53
Total inventories	$	245	$	189

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

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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 or from other instances where the regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers.

See Note 6 for further information.

Conservation Programs — 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 reduces recoverable fuel and purchased power costs for the cost of RECs received. An inventory accounting model is used to account for RECs recognized on the consolidated balance sheets, however these assets are classified as regulatory assets if amounts are recoverable in future rates.

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

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.

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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.

3. Plant, Property and Equipment

Major classes of property, plant and equipment

(Millions of Dollars)	Dec. 31, 2021		Dec. 31, 2020
Property, plant and equipment, net
Electric plant	$	16,543	$	15,736
Natural gas plant	5,471		5,037
Common and other property	1,224		1,191
Plant to be retired (a)	182		225
CWIP	681		510
Total property, plant and equipment	24,101		22,699
Less accumulated depreciation	(5,657)		(5,229)
Property, plant and equipment, net	$	18,444	$	17,470

(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, 2021:

(Millions of Dollars, Except Percent Owned)	Plant in Service		Accumulated Depreciation		Percent Owned
Electric generation:
Hayden Unit 1	$	156	$	99	76	%
Hayden Unit 2	151		78		37
Hayden common facilities	42		27		53
Craig Units 1 and 2	81		48		10
Craig common facilities	39		25		7
Comanche Unit 3	917		154		67
Comanche common facilities	28		2		82
Electric transmission:
Transmission and other facilities	182		63		Various
Gas transmission:
Rifle, CO to Avon, CO	22		8		60
Gas transmission compressor	8		2		50
Total (a)	$	1,626	$	506

(a)Projects additionally include $3 million in CWIP.

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

4. Regulatory Assets and Liabilities

Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. PSCo would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP.

Components of regulatory assets:

(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2021				Dec. 31, 2020
Regulatory Assets			Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations	9	Various	$	26	$	331	$	28	$	478
Deferred natural gas, electric, steam energy/fuel costs		One to three years	218		320		6		—
Depreciation differences		One to ten years	16		173		16		154
Net AROs (a)	1, 10	Various	—		154		—		132
Recoverable deferred taxes on AFUDC		Plant lives	—		116		—		110
Excess deferred taxes — TCJA	7	Various	2		56		3		56
Purchased power contract costs		Term of related contract	3		19		3		22
Property tax		Various	16		16		16		21
Gas pipeline inspection costs		One to two years	—		12		—		9
Conservation programs (b)	1	One to two years	11		11		11		11
Losses on reacquired debt		Term of related debt	1		2		1		3
Contract valuation adjustments (c)	1, 8	Less than one year	3		—		6		—
Other		Various	57		83		31		63
Total regulatory assets			$	353	$	1,293	$	121	$	1,059

(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.

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Components of regulatory liabilities:

(Millions of Dollars)	See Note(s)	Remaining Amortization Period	Dec. 31, 2021				Dec. 31, 2020
Regulatory Liabilities			Current		Noncurrent		Current		Noncurrent
Deferred income tax adjustments and TCJA refunds (a)	7	Various	$	2	$	1,328	$	5	$	1,368
Plant removal costs	1, 10	Various	—		651		—		615
Effects of regulation on employee benefit costs (b)		Various	—		216		—		203
Renewable resources and environmental initiatives		Various	—		91		—		59
ITC deferrals	1	Various	—		42		—		40
Revenue decoupling		One to two years	9		41		10		41
Conservation programs (c)	1	Less than one year	34		—		39		—
Deferred natural gas, electric, steam energy/fuel costs		Less than one year	29		—		17		—
Other		Various	21		28		29		11
Total regulatory liabilities (d)			$	95	$	2,397	$	100	$	2,337

(a)Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes due to the TCJA.

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

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

(d)Revenue subject to refund of $2 million for 2021 is included in other current liabilities and none for 2020.

At Dec. 31, 2021 and 2020, 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 $639 million and $195 million at Dec. 31, 2021 and 2020, respectively, of past expenditures not earning a return. Amounts are related to Winter Storm Uri costs, 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:

(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2021			Year Ended Dec. 31
				2021			2020			2019
Borrowing limit	$	250		$	250		$	250		$	250
Amount outstanding at period end	—			—			57			39
Average amount outstanding	14			12			59			7
Maximum amount outstanding	74			243			250			50
Weighted average interest rate, computed on a daily basis	0.05		%	0.07		%	0.60		%	2.29		%
Weighted average interest rate at end of period	N/A			N/A			0.70			1.63

Commercial Paper — Commercial paper borrowings:

(Millions of Dollars, Except Interest Rates)	Three Months Ended Dec. 31, 2021			Year Ended Dec. 31
				2021			2020			2019
Borrowing limit	$	700		$	700		$	700		$	700
Amount outstanding at period end	147			147			136			—
Average amount outstanding	6			26			30			154
Maximum amount outstanding	150			322			230			432
Weighted average interest rate, computed on a daily basis	0.21		%	0.19		%	1.59		%	2.67		%
Weighted average interest rate at end of period	0.22			0.22			0.20			N/A

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, 2021 and 2020, there were $8 million of letters of credit outstanding under the credit facility, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

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

Features of PSCo’s credit facility:

Debt-to-Total Capitalization Ratio (a)				Amount Facility May Be Increased (millions of dollars)		Additional Periods for Which a One-Year Extension May Be Requested (b)
2021		2020
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, 2021, PSCo was in compliance with all financial covenants.

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PSCo had the following committed credit facility available as of Dec. 31, 2021 (in millions of dollars):

Credit Facility (a)		Drawn (b)		Available
$	700	$	155	$	545

(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, 2021 and 2020.

Long-Term Borrowings and Other Financing Instruments

Generally, all property of PSCo is subject to the lien 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 (in millions of dollars):

Financing Instrument	Interest Rate		Maturity Date	2021		2020
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 (b)	1.90		Jan. 15, 2031	375		375
First mortgage bonds (a)	1.875		June 15, 2031	750		—
First mortgage bonds	6.25		Sept. 1, 2037	350		350
First mortgage bonds	6.50		Aug. 1, 2038	300		300
First mortgage bonds	4.75		Aug. 15, 2041	250		250
First mortgage bonds	3.60		Sept. 15, 2042	500		500
First mortgage bonds	3.95		March 15, 2043	250		250
First mortgage bonds	4.30		March 15, 2044	300		300
First mortgage bonds	3.55		June 15, 2046	250		250
First mortgage bonds	3.80		June 15, 2047	400		400
First mortgage bonds	4.10		June 15, 2048	350		350
First mortgage bonds	4.05		Sept. 15, 2049	400		400
First mortgage bonds	3.20		March 1, 2050	550		550
First mortgage bonds (b)	2.70		Jan. 15, 2051	375		375
Unamortized discount				(33)		(30)
Unamortized debt issuance cost				(50)		(46)
Current maturities				(300)		—
Total long-term debt				$	6,167	$	5,724

(a)2021 financing.

(b)2020 financing.

Maturities of long-term debt:

(Millions of Dollars)
2022	$	300
2023	250
2024	—
2025	250
2026	—

Deferred Financing Costs — Deferred financing costs of approximately $50 million and $46 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2021 and 2020, 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) 2021 and 2020
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, 2021
(Millions of Dollars)	Electric		Natural Gas		All Other		Total
Major revenue types
Revenue from contracts with customers:
Residential	$	1,174	$	816	$	12	$	2,002
C&I	1,660		308		30		1,998
Other	49		—		—		49
Total retail	2,883		1,124		42		4,049
Wholesale	228		—		—		228
Transmission	75		—		—		75
Other	44		159		—		203
Total revenue from contracts with customers	3,230		1,283		42		4,555
Alternative revenue and other	183		72		5		260
Total revenues	$	3,413	$	1,355	$	47	$	4,815

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	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

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. The statute of limitations applicable to Xcel Energy’s consolidated federal tax returns expire as follows:

Tax Year(s)	Expiration
2014 - 2016	December 2022
2018	September 2022

Additionally, the statute of limitations related to certain federal tax credit carryforwards will remain open until those credits are utilized in subsequent returns. Further, the statute of limitations related to the additional federal tax loss carryback claim filed in 2020 has been extended. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.

State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2021, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2014. 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 ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which deductibility is highly certain, but for which there is uncertainty about the timing. A change in the timing of deductibility would not affect the ETR but would accelerate the payment to the taxing authority.

Unrecognized tax benefits - permanent vs temporary:

(Millions of Dollars)	Dec. 31, 2021		Dec. 31, 2020
Unrecognized tax benefit — Permanent tax positions	$	9	$	7
Unrecognized tax benefit — Temporary tax positions	2		2
Total unrecognized tax benefit	$	11	$	9

Changes in unrecognized tax benefits:

(Millions of Dollars)	2021		2020		2019
Balance at Jan. 1	$	9	$	12	$	10
Additions based on tax positions related to the current year	2		2		1
Additions for tax positions of prior years	—		6		1
Reductions for tax positions of prior years	—		(11)		—
Balance at Dec. 31	$	11	$	9	$	12

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

(Millions of Dollars)	Dec. 31, 2021		Dec. 31, 2020
NOL and tax credit carryforwards	$	(11)	$	(8)

As the IRS progresses its review of the tax loss carryback claims and as state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $2 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)	2021		2020		2019
Payable for interest related to unrecognized tax benefits at Jan. 1	$	—	$	(1)	$	(1)
Interest income related to unrecognized tax benefits	—		1		—
Payable for interest related to unrecognized tax benefits at Dec. 31	$	—	$	—	$	(1)

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2021, 2020 or 2019.

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

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

(Millions of Dollars)	2021		2020
Federal NOL carryforward	$	161	$	—
Federal tax credit carryforwards	259		143
State NOL carryforwards	342		190
State tax credit carryforwards, net of federal detriment (a)	17		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 Dec. 31, 2021 and 2020.

(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $2 million as of Dec. 31, 2021 and 2020.

Federal carryforward periods expire between 2031 and 2041 and state carryforward periods expire between 2022 and 2041.

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:

	2021		2020 (a)		2019 (a)
Federal statutory rate	21.0	%	21.0	%	21.0	%
State income tax on pretax income, net of federal tax effect	3.6		3.6		3.6
Increases (decreases) in tax from:
Wind PTCs	(14.3)		(10.3)		(7.5)
Plant regulatory differences (b)	(4.6)		(5.0)		(3.3)
Other tax credits, net NOL & tax credit allowances	(1.0)		(1.1)		(1.3)
Change in unrecognized tax benefits	0.3		(0.2)		0.3
Other, net	(0.2)		(0.9)		(0.6)
Effective income tax rate	4.8	%	7.1	%	12.2	%

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

(b)Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred 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)	2021		2020		2019
Current federal tax expense (benefit)	$	16	$	44	$	(9)
Current state tax expense (benefit)	—		4		(5)
Current change in unrecognized tax benefit	(1)		(3)		(1)
Deferred federal tax (benefit) expense	(13)		(26)		61
Deferred state tax expense	31		26		33
Deferred change in unrecognized tax expense	3		2		3
Deferred ITCs	(3)		(2)		(2)
Total income tax expense	$	33	$	45	$	80

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

(Millions of Dollars)	2021		2020		2019
Deferred tax expense excluding items below	$	63	$	46	$	132
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(42)		(43)		(35)
Tax expense allocated to other comprehensive income, adoption of ASC Topic 326, and other	—		(1)		—
Deferred tax expense	$	21	$	2	$	97

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

(Millions of Dollars)	2021		2020 (a)
Deferred tax liabilities:
Differences between book and tax bases of property	$	2,226	$	2,132
Regulatory assets	258		257
Deferred fuel costs	126		(3)
Operating lease assets	106		129
Pension expense and other employee benefits	23		19
Other	7		6
Total deferred tax liabilities	$	2,746	$	2,540
Deferred tax assets:
Regulatory liabilities	$	323	$	319
Tax credit carryforward	276		161
Operating lease liabilities	106		129
Bad debts	10		8
NOL carryforward	46		7
Deferred ITCs	8		5
Tax credit valuation allowances	(8)		(8)
Other	25		22
Total deferred tax assets	$	786	$	643
Net deferred tax liability	$	1,960	$	1,897

(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 NAV.

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

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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, 2021, 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. As of Dec. 31, 2021, PSCo had no unsettled interest rate derivatives.

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 of unrealized losses or gains on these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms.

As of Dec. 31, 2021, 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, 2021	Dec. 31, 2020
MWh of electricity	15	17
MMBtu of natural gas	71	93

(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, 2021, four of PSCo’s 10 most significant counterparties for these activities, comprising $53 million or 40% of this credit exposure, had investment grade credit ratings from S&P, Moody’s or Fitch Ratings. Five of the 10 most significant counterparties, comprising $20 million or 15% 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. One of these significant counterparties, comprising $38 million, or 29%, 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, RTOs 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)	2021		2020		2019
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(23)	$	(24)	$	(26)
After-tax net realized losses on derivative transactions reclassified into earnings	2		1		2
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(21)	$	(23)	$	(24)

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, 2021
Other derivative instruments
Natural gas commodity	$	—	$	(1)
Total	$	—	$	(1)
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)

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	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, 2021
Derivatives designated as cash flow hedges
Interest rate	$	2	(a)	$	—		$	—
Total	$	2		$	—		$	—
Other derivative instruments
Commodity trading	$	—		$	—		$	12	(b)
Natural gas commodity	—			4		(c)	(15)		(c)
Total	$	—		$	4		$	(3)

	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)

	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)    Settlement losses related to natural gas operations 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, as appropriate.

PSCo had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2021, 2020 and 2019. 

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, 2021 and 2020, 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, 2021 and 2020, there were approximately $16 million and $46 million of derivative instruments in a liability position with such underlying contract provisions, respectively.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that 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, 2021 and 2020.

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

	Dec. 31, 2021												Dec. 31, 2020
	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	$	12	$	97	$	—	$	109	$	(81)	$	28	$	1	$	41	$	1	$	43	$	(28)	$	15
Natural gas commodity	—		11		—		11		—		11		—		6		—		6		—		6
Total current derivative assets	$	12	$	108	$	—	$	120	$	(81)	$	39	$	1	$	47	$	1	$	49	$	(28)	$	21
Noncurrent derivative assets
Other derivative instruments:
Commodity trading	$	10	$	28	$	54	$	92	$	(65)	$	27	$	1	$	27	$	8	$	36	$	(20)	$	16
Total noncurrent derivative assets	$	10	$	28	$	54	$	92	$	(65)	27		$	1	$	27	$	8	$	36	$	(20)	$	16
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	6	$	90	$	16	$	112	$	(85)	$	27	$	1	$	46	$	7	$	54	$	(33)	$	21
Natural gas commodity	—		3		—		3		—		3		—		6		—		6		—		6
Total current derivative liabilities	$	6	$	93	$	16	$	115	$	(85)	$	30	$	1	$	52	$	7	$	60	$	(33)	$	27
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	3	$	—	$	101	$	104	$	(75)	$	29	$	1	$	24	$	46	$	71	$	(20)	$	51
Total noncurrent derivative liabilities	$	3	$	—	$	101	$	104	$	(75)	$	29	$	1	$	24	$	46	$	71	$	(20)	$	51

(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, 2021 and 2020. At Dec. 31, 2021 and 2020, derivative assets and liabilities include no obligations to return cash collateral, respectively. At Dec. 31, 2021 and 2020, derivative assets and liabilities include rights to reclaim cash collateral of $14 million and $5 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, 2021, 2020 and 2019:

	Year Ended Dec. 31
(Millions of Dollars)	2021		2020		2019
Balance at Jan. 1	$	(44)	$	(13)	$	—
Settlements	4		—		(2)
Net transactions recorded during the period:
Losses recognized in earnings (a)	(23)		(31)		(11)
Balance at Dec. 31	$	(63)	$	(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, 2021, 2020 and 2019.

Fair Value of Long-Term Debt

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

	2021				2020
(Millions of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	6,467	$	7,291	$	5,724	$	7,040

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, 2021 and 2020, 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 2.26, 2.24 and 3.11 percent in 2021, 2020, and 2019, 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, 2021 and 2020 were $43 million and $43 million, respectively, of which $2 million was attributable to PSCo in 2021 and 2020, respectively. Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $4 million in 2021 and $6 million in 2020, respectively, of which immaterial amounts were attributable to PSCo.

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Xcel Energy, which includes PSCo, investment-return assumption considers the expected long-term performance for each of the asset classes in its pension and postretirement health care portfolio. Xcel Energy considers the historical returns achieved by its asset portfolios over long time periods, as well as long-term projected return levels. 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 2021 were above the assumed level of 6.38%.

•Investment returns in 2020 were above the assumed level of 6.84%.

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

•In 2022, PSCo’s expected investment-return assumption is 6.39%.

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 consider many factors and generally result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.

Plan Assets

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

	Dec. 31, 2021 (a)										Dec. 31, 2020 (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	$	49	$	—	$	—	$	—	$	49	$	75	$	—	$	—	$	—	$	75
Commingled funds	492		—		—		409		901		518		—		—		388		906
Debt securities	—		360		2		—		362		—		270		1		—		271
Equity securities	24		—		—		—		24		27		—		—		—		27
Other	—		3		—		12		15		2		2		—		—		4
Total	$	565	$	363	$	2	$	421	$	1,351	$	622	$	272	$	1	$	388	$	1,283

(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, 2021 (a)										Dec. 31, 2020 (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	$	25	$	—	$	—	$	—	$	25	$	24	$	—	$	—	$	—	$	24
Insurance contracts	—		46		—		—		46		—		45		—		—		45
Commingled funds	57		—		—		68		125		64		—		—		61		125
Debt securities	—		194		1		—		195		—		207		—		—		207
Other	—		2		—		—		2		—		3		—		—		3
Total	$	82	$	242	$	1	$	68	$	393	$	88	$	255	$	—	$	61	$	404

(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 2021 or 2020.

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Funded Status — Benefit obligations for both pension and postretirement plans decreased from Dec. 31, 2020 to Dec. 31, 2021, due primarily to benefit payments and increases in discount rates used in actuarial valuations. Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for PSCo are as follows:

	Pension Benefits				Postretirement Benefits
(Millions of Dollars)	2021		2020		2021		2020
Change in Benefit Obligation:
Obligation at Jan. 1	$	1,428	$	1,330	$	415	$	380
Service cost	32		30		1		1
Interest cost	39		46		11		13
Plan amendments	—		—		—		—
Actuarial (gain) loss	(57)		102		(31)		52
Plan participants’ contributions	—		—		7		6
Medicare subsidy reimbursements	—		—		2		1
Benefit payments	(79)		(80)		(36)		(38)
Obligation at Dec. 31	$	1,363	$	1,428	$	369	$	415
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	1,283	$	1,124	$	404	$	401
Actual return on plan assets	102		189		15		32
Employer contributions	45		50		3		3
Plan participants’ contributions	—		—		7		6
Benefit payments	(79)		(80)		(36)		(38)
Fair value of plan assets at Dec. 31	$	1,351	$	1,283	$	393	$	404
Funded status of plans at Dec. 31	$	(12)	$	(145)	$	24	$	(11)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Noncurrent assets	6		—		24		—
Noncurrent liabilities	(18)		(145)		—		(11)
Net amounts recognized	$	(12)	$	(145)	$	24	$	(11)

Accumulated benefit obligation for the pension plan was $1,291 million and $1,353 million as of Dec. 31, 2021 and 2020, respectively.

	Pension Benefits				Postretirement Benefits
Significant Assumptions Used to Measure Benefit Obligations:	2021		2020		2021		2020
Discount rate for year-end valuation	3.08	%	2.71	%	3.09	%	2.65	%
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		5.30	%	5.50	%
Health care costs trend rate — initial: Post-65	N/A		N/A		4.90	%	5.00	%
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		4		5

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

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

	Pension Benefits									Postretirement Benefits
(Millions of Dollars)	2021			2020			2019			2021			2020			2019
Service cost	$	32		$	30		$	26		$	1		$	—		$	1
Interest cost	39			46			52			11			13			15
Expected return on plan assets	(73)			(70)			(69)			(16)			(17)			(19)
Amortization of prior service credit	—			(3)			(3)			(4)			(4)			(5)
Amortization of net loss	32			30			25			3			1			3
Settlement charge (a)	—			—			3			—			—			—
Net periodic pension cost (credit)	30			33			34			(5)			(7)			(5)
Effects of regulation	—			4			4			2			3			1
Net benefit cost (credit) recognized for financial reporting	$	30		$	37		$	38		$	(3)		$	(4)		$	(4)
Significant Assumptions Used to Measure Costs:
Discount rate	2.71		%	3.49		%	4.31		%	2.65		%	3.47		%	4.32		%
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	6.38			6.84			6.84			4.10			4.50			4.50

(a)A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2019, as a result of lump-sum distributions during the plan year, PSCo recorded a total pension settlement charge of $3 million. An immaterial amount was recorded in the income statement in 2019. There were no settlement charges recorded to the qualified pension plans in 2021 or 2020.

	Pension Benefits				Postretirement Benefits
(Millions of Dollars)	2021		2020		2021		2020
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	313	$	432	$	48	$	81
Prior service credit	(1)		(1)		(2)		(6)
Total	$	312	$	431	$	46	$	75
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	$	24	$	25	$	—	$	—
Noncurrent regulatory assets	288		404		46		75
Deferred income taxes	—		1		—		—
Net-of-tax accumulated other comprehensive income	—		1		—		—
Total	$	312	$	431	$	46	$	75

Measurement date Dec. 31, 2021 Dec. 31, 2020 Dec. 31, 2021 Dec. 31, 2020

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 2019 - 2022 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:

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

•$131 million in 2021, of which $46 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.

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:

•$9 million in January 2022, of which an immaterial amount is attributable to PSCo.

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

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Targeted asset allocations:

	Pension Benefits				Postretirement Benefits
	2021		2020		2021		2020
Domestic and international equity securities	33	%	35	%	15	%	15	%
Long-duration fixed income securities	37		35		—		—
Short-to-intermediate fixed income securities	11		13		71		72
Alternative investments	17		15		8		9
Cash	2		2		6		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 2020 and 2019, there were no significant plan amendments made which affected the projected benefit obligation.

In 2021, Xcel Energy amended the Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans.

Projected Benefit Payments

PSCo’s projected benefit payments:

(Millions of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2022	$	83	$	30	$	2	$	28
2023	82		29		2		27
2024	82		29		2		27
2025	82		28		2		26
2026	81		27		2		25
2027-2031	388		123		13		110

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 2021 and 2020 and $11 million in 2019.

10. Commitments and Contingencies

Legal

PSCo is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.

In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on

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

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

One case remains active which includes a multi-district litigation matter consisting of a Wisconsin purported class (Arandell Corp.).

Arandell Corp. — The trial has been vacated and will be rescheduled after the court rules on the pending motions for reconsideration and for class certification. Xcel Energy has concluded that a loss is remote for the remaining lawsuit.

Breckenridge/Colorado — In February 2019, the MDL panel remanded Breckenridge back to the U.S. District Court in Colorado. Settlement of approximately $3 million was reached in February 2021. In July 2021, the settlement was approved.

Rate Matters

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

Comanche Unit 3 Litigation — In February 2021, the joint owners of Comanche Unit 3 (CORE Electric Cooperative, formerly known as Intermountain Rural Electrical Association, and Holy Cross Electric) served PSCo with a notice of claim related to Comanche Unit 3's operation and availability.

In September 2021, CORE Electric Cooperative filed a lawsuit in Colorado state court seeking an unspecified amount of damages. CORE Electric Cooperative alleges PSCo breached ownership agreement terms by failing to operate Comanche Unit 3 in accordance with prudent utility practices. PSCo filed a Motion to Dismiss several of CORE’s claims. In January 2022 the Court granted PSCo’s Motion to Dismiss CORE’s claim for damages for replacement power costs, claims for unjust enrichment and declaratory judgment. CORE’s claims for breach of contract, breach of the duty of good faith and fair dealing, and waste remain pending.

In November 2021, PSCo resolved all differences with Holy Cross Electric related to their claim.

Environmental

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

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Site Remediation

Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. 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.

Historical MGP, Landfill and Disposal Sites

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

PSCo has recognized its best estimate of costs/liabilities from final resolution of these issues; however, the outcome and timing are unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.

Environmental Requirements — Water and Waste

Coal Ash Regulation — 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 five 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. Based on further assessments, PSCo is evaluating options for corrective action at two locations, one of which indicates potential offsite impacts to groundwater. The total cost is uncertain, but could be up to $35 million. PSCo is continuing to assess the financial and regulatory impacts.

In August 2020, the EPA published its final rule to implement closure by April 2021 for all CCR impoundments affected by the August 2018 D.C. Circuit ruling. This final rule required PSCo to expedite closure plans for one impoundment.

PSCo also built an alternative collection and treatment system to remove the Comanche Station bottom ash pond from service. The total cost of the alternate treatment system is approximately $25 million. PSCo worked expeditiously to meet the April 11, 2021 deadline, but was not able to remove the pond from service until June 18, 2021. PSCo expects to negotiate a compliance order with the EPA addressing the closure deadline as well as other potential issues. PSCo will also now proceed with closure of the pond, at an estimated cost of $3 million.

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

Federal CWA Waters of the U.S. Rule — PSCo is monitoring ongoing changes to the definition of Waters of the U.S. under the CWA. Regardless of which definition is applicable in the state 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 future 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:

	2021
(Millions  of Dollars)	Jan. 1, 2021		Accretion		Cash Flow Revisions (a)		Dec. 31, 2021 (b)
Electric
Steam, hydro and other production	$	137	$	5	$	10	$	152
Wind	40		2		—		42
Distribution	15		1		—		16
Natural gas
Transmission and distribution	203		9		(8)		204
Miscellaneous	3		—		5		8
Common
Miscellaneous	1		(1)		—		—
Total liability	$	399	$	16	$	7	$	422

(a)In 2021, AROs were revised for changes in timing and estimates of cash flows. Revisions in steam, hydro, and other production AROs primarily related to changes in cost estimates for remediation of ash containment facilities. Changes in gas transmission and distribution AROs were primarily related to changes in labor rates coupled with increased gas line mileage and number of services.

(b)There were no ARO amounts incurred or settled in 2021.

45

	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 of ash containment facilities.

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, 2021. 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, 2021		Dec. 31, 2020
PPAs	$	600	$	591
Other	77		68
Gross operating lease ROU assets	677		659
Accumulated amortization	(268)		(159)
Net operating lease ROU assets	$	409	$	500

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, 2021		Dec. 31, 2020
Gas storage facilities	$	201	$	201
Gas pipeline	21		21
Gross finance lease ROU assets	222		222
Accumulated amortization	(97)		(90)
Net finance lease ROU assets	$	125	$	132

Components of lease expense:

(Millions of Dollars)	2021		2020		2019
Operating leases
PPA capacity payments	$	102	$	100	$	98
Other operating leases (a)	16		13		14
Total operating lease expense (b)	$	118	$	113	$	112
Finance leases
Amortization of ROU assets	$	7	$	7	$	6
Interest expense on lease liability	17		18		19
Total finance lease expense	$	24	$	25	$	25

(a)Includes short-term lease expense of $1 million, $1 million and $2 million for 2021, 2020 and 2019, 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, 2021:

(Millions of Dollars)	PPA (a) (b) Operating Leases		Other Operating Leases		Total Operating Leases		Finance Leases
2022	$	84	$	16	$	100	$	21
2023	70		11		81		20
2024	63		11		74		20
2025	63		5		68		19
2026	59		1		60		18
Thereafter	104		11		115		362
Total minimum obligation	443		55		498		460
Interest component of obligation	(57)		(6)		(63)		(335)
Present value of minimum obligation	$	386	$	49	435		125
Less current portion					(84)		(4)
Noncurrent operating and finance lease liabilities					$	351	$	121
Weighted-average remaining lease term in years					6.5		37.3

(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.

46

PPAs and Fuel Contracts

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

Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $2 million, $10 million and $12 million in 2021, 2020 and 2019, 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, 2021, 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
2022	$	3
2023	3
2024	3
2025	3
2026	3
Thereafter	3
Total	$	18

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 2023 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, 2021:

(Millions of Dollars)	Coal		Natural gas supply		Natural gas storage and transportation
2022	$	186	$	324	$	116
2023	102		75		67
2024	67		3		37
2025	28		—		36
2026	29		—		35
Thereafter	30		—		440
Total	$	442	$	402	$	731

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 of capacity under long-term PPAs at both Dec. 31, 2021 and 2020 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:

	2021
(Millions of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit Pension and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(23)		$	(1)		$	(24)
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 $—, respectively)	1			—		(b)	1
Net current period other comprehensive income (loss)	2			—			2
Accumulated other comprehensive loss at Dec. 31	$	(21)		$	(1)		$	(22)

(a)Included in interest charges.

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

	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 (gains) reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $— and $—, respectively)	1		(a)	—			1
Amortization of net actuarial gains (net of taxes of $— and $1, respectively)	—			2		(b)	2
Net current period other comprehensive income	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.

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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, transmits and distributes electricity in Colorado. This segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes PSCo’s wholesale commodity and trading operations.

•Regulated Natural Gas — The regulated natural gas utility segment 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. Reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations, which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

Certain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

PSCo’s segment information:

(Millions of Dollars)	2021		2020		2019
Regulated Electric
Operating revenues — external	$	3,413	$	3,116	$	3,033
Intersegment revenue	1		1		1
Total revenues	$	3,414	$	3,117	$	3,034
Depreciation and amortization	566		497		455
Interest charges and financing costs	179		173		173
Income tax (benefit) expense	(16)		13		45
Net income	495		460		465
Regulated Natural Gas
Total revenues	$	1,355	$	1,024	$	1,161
Depreciation and amortization	171		152		141
Interest charges and financing costs	53		50		50
Income tax expense	45		29		33
Net income	168		126		119
All Other
Total revenues (a)	$	47	$	43	$	43
Depreciation and amortization	7		6		6
Interest charges and financing costs	2		1		1
Income tax expense	4		3		2
Net (loss) income	(3)		2		(6)
Consolidated Total
Total revenues (a)	$	4,816	$	4,184	$	4,238
Reconciling eliminations	(1)		(1)		(1)
Total operating revenues	$	4,815	$	4,183	$	4,237
Depreciation and amortization	744		655		602
Interest charges and financing costs	234		224		224
Income tax expense	33		45		80
Net income	660		588		578

(a)    Operating revenues include $5 million of other affiliate revenue for the years ended Dec. 31, 2021, 2020 and 2019, 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)	2021		2020		2019
Operating revenues:
Other	$	5	$	5	$	5
Operating expenses:
Other operating expenses — paid to Xcel Energy Services Inc.	617		571		532

48

Accounts receivable and payable with affiliates at Dec. 31:

	2021				2020
(Millions of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Minnesota	$	—	$	16	$	—	$	1
NSP-Wisconsin	—		2		—		1
SPS	—		7		—		6
Other subsidiaries of Xcel Energy Inc.	13		44		8		50
	$	13	$	69	$	8	$	58

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

None.

ITEM 9A — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

PSCo maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the CEO and CFO, allowing timely decisions regarding required disclosure. 

As of Dec. 31, 2021, 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.

Internal Control Over Financial Reporting

No changes in PSCo’s internal control over financial reporting occurred during the most recent fiscal quarter ended Dec. 31, 2021 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, 2021 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, PSCo conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, PSCo did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board, as approved by the SEC and as indicated in PSCo’s Management Report on Internal Controls over Financial Reporting, which is contained in Item 8 herein.

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

ITEM 9B — OTHER INFORMATION

None.

ITEM 9C — DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

PART III

Items 10, 11, 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 2022 Annual Meeting of Shareholders, which is incorporated by reference.

ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information required under this Item (aggregate fees billed to us by our principal accountant, Deloitte & Touche LLP (PCAOB ID No. 34)) is contained in Xcel Energy Inc.’s Proxy Statement for its 2022 Annual Meeting of Shareholders, which is incorporated by reference.

49

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, 2021.
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Consolidated Statements of Income — For each of the three years ended Dec. 31, 2021, 2020 and 2019.
	Consolidated Statements of Comprehensive Income — For each of the three years ended Dec. 31, 2021, 2020 and 2019.
	Consolidated Statements of Cash Flows — For each of the three years ended Dec. 31, 2021, 2020 and 2019.
	Consolidated Balance Sheets — As of Dec. 31, 2021 and 2020.
	Consolidated Statements of Common Stockholder’s Equity — For each of the three years ended Dec. 31, 2021, 2020 and 2019.
2	Schedule II — Valuation and Qualifying Accounts and Reserves for each of the years ended Dec. 31, 2021, 2020 and 2019.
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
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
4.15*	Supplemental Indenture dated as of February 1, 2021 between PSCo and U.S. Bank National Association, as successor Trustee, creating $750 million principal of 1.875% First Mortgage Bonds, Series No. 37 due 2031	PSCo Form 8-K dated March 1, 2021	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

50

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 Award Agreement for Restricted Stock Units and/or Performance Share Units under the Xcel Energy Inc. 2015 Omnibus Incentive Plan for awards since 2020	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019	10.32
10.20*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc. as amended and restated effective Feb. 23, 2011	Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011	Appendix A
10.21*+	Stock Equivalent Program for Non-Employee Directors of Xcel Energy Inc. under the Xcel Energy Inc. 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 8-K dated May 20, 2015	10.02
10.22*+	Summary of Non-Employee Director Compensation, effective as of Oct. 1, 2021	Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2021	10.01
10.23*+	Stock Program for Non-Employee Directors of Xcel Energy Inc. as Amended and Restated on Dec. 12, 2017 under the 2015 Omnibus Incentive Plan	Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018	10.36
10.24*+	Form of Services Agreement between Xcel Energy Services Inc. and utility companies	Xcel Energy Inc. Form U5B dated Nov. 16, 2000	H-1
10.25*	Proposed Settlement Agreement, excerpts, as filed with the CPUC	Xcel Energy Inc. Form 8-K dated Dec. 3, 2004	99.02
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)

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SCHEDULE II

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

	Allowance for bad debts
(Millions of Dollars)	2021		2020		2019
Balance at Jan. 1	$	29	$	21	$	21
Additions charged to costs and expenses	26		24		17
Additions charged to other accounts (a)	4		4		6
Deductions from reserves (b)	(19)		(20)		(23)
Balance at Dec. 31	$	40	$	29	$	21

(a)Recovery of amounts previously written-off.

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

Item 16 — Form 10-K Summary

None.

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Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned thereunto duly authorized.

	PUBLIC SERVICE COMPANY OF COLORADO
Feb. 23, 2022	/s/ BRIAN J. VAN ABEL
	Brian J. Van Abel
	Executive Vice President, Chief Financial Officer and Director

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the date indicated above.

/s/ ROBERT C. FRENZEL	/s/ ALICE K. JACKSON
Robert C. Frenzel	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)

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.

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