0000072903 us-gaap:OtherCurrentAssetsMember xel:NaturalGasCommodityContractMember us-gaap:FairValueInputsLevel3Member us-gaap:FairValueMeasurementsRecurringMember us-gaap:NondesignatedMember 2019-12-31
XCEL ENERGY INC000007290312/312021FYFALSEP1YP5YP1YP1YP2YP1YP2YP8YP1YP2YP1YP2YP2YP1YP2YP1YP2YP1YP2YP1YP3YP3YP3YP5Y
Quarter Ended
(Amounts in millions, except per share data)March 31, 2021June 30, 2021Sept. 30, 2021Dec. 31, 2021
Operating revenues$2,811 $2,586 $3,182 $2,947 
Operating income455 422 813 426 
Net income295 287 603 288 
EPS total — basic$0.56 $0.54 $1.15 $0.54 
EPS total — diluted0.560.541.140.54
Cash dividends declared per common share0.430.430.430.43
Quarter Ended
(Amounts in millions, except per share data)March 31, 2020June 30, 2020Sept. 30, 2020Dec. 31, 2020
Operating revenues$2,811 $2,586 $3,182 $2,947 
Operating income455 422 813 426 
Net income295 287 603 288 
EPS total — basic$0.56 $0.54 $1.15 $0.54 
EPS total — diluted0.560.541.140.54
Cash dividends declared per common share0.430.430.430.43
Quarter Ended
(Amounts in millions, except per share data)March 31, 2021June 30, 2021Sept. 30, 2021Dec. 31, 2021
Operating revenues$2,811 $2,586 $3,182 $2,947 
Operating income455 422 813 426 
Net income295 287 603 288 
EPS total — basic$0.56 $0.54 $1.15 $0.54 
EPS total — diluted0.560.541.140.54
Cash dividends declared per common share0.430.430.430.43
Quarter Ended
(Amounts in millions, except per share data)March 31, 2020June 30, 2020Sept. 30, 2020Dec. 31, 2020
Operating revenues$2,811 $2,586 $3,182 $2,947 
Operating income455 422 813 426 
Net income295 287 603 288 
EPS total — basic$0.56 $0.54 $1.15 $0.54 
EPS total — diluted0.560.541.140.54
Cash dividends declared per common share0.430.430.430.43
2,8112,5863,1822,9474554228134262952876032880.560.541.150.540.560.541.140.540.430.430.430.432,8112,5863,1822,9474554228134262952876032880.560.541.150.540.560.541.140.540.430.430.430.43


xel-20211231_g1.jpg
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, 20192021 or
☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____ to _____
001-3034
(Commission File Number)
Xcel Energy Inc.
(Exact name of registrant as specified in its charter)
Minnesota41-0448030
(State or Other Jurisdiction of Incorporation or Organization)(IRS Employer Identification No.)
414 Nicollet MallMinneapolisMinnesota55401
(Address of Principal Executive Offices)

(Zip Code)
612330-5500
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading SymbolSymbol(s)Name of each exchange on which registered
Common Stock, $2.50 par value per shareXELNasdaq Stock Market LLC

Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☒ No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 
☒ Yes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation
S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. ☒ Large accelerated filer ☐ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ Yes
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No
As of June 28, 2019,30, 2021, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $30,629,347,167 and there were 514,865,476 shares of common stock outstanding.$35,463,594,471.
As of Feb. 13, 2020,17, 2022, there were 524,669,024544,213,730 shares of common stock outstanding, $2.50 par value.
DOCUMENTS INCORPORATED BY REFERENCE
ThePortions of the Registrant’s definitive Proxy Statement for its 20202022 Annual Meeting of Shareholders isare incorporated by reference into Part III of this Form 10-K.
1

TABLE OF CONTENTS
PART I
Item 1 —
3
Item 1A —
17
Item 1B —
23
Item 2 —
24
Item 3 —
25
Item 4 —
25
PART III
Item 1 —
Business
3
Definitions of Abbreviations
3
Forward-Looking Statements
4
Where to Find More Information
4
Company Overview
5
Electric Operations
9
Natural Gas Operations
12
General
13
Public Utility Regulation
13
Environmental
13
Capital Spending and Financing
14
Employees
14
Information about our Executive Officers
14
Item 1A —
Risk Factors
15
Item 1B —
Unresolved Staff Comments
20
Item 2 —
Properties
20
Item 3 —
Legal Proceedings
21
Item 4 —
Mine Safety Disclosures
21
PART II
Item 5 —
2125
Item 6 —
2126
Item 7 —
2226
Item 7A —
4045
Item 8 —
4045
Item 9 —
7781
Item 9A —
7781
Item 9B —
7782
Item 9C —
82
PART III
PART III
Item 10 —
7782
Item 11 —
7782
Item 12 —
7782
Item 13 —
7782
Item 14 —
7782
PART IV
Item 15 —
7882
Item 16 —
8488
8589

2
Table of Contents
PART I
ITEM 1 — BUSINESS
Definitions of Abbreviations
Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
Capital ServicesCapital Services, LLC
EloigneEloigne Company
e primee prime inc.
NSP-MinnesotaNorthern States Power Company, a Minnesota corporation
NSP SystemThe electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota
NSP-WisconsinNorthern States Power Company, a Wisconsin corporation
Operating companiesNSP-Minnesota, NSP-Wisconsin, PSCo and SPS
PSCoPublic Service Company of Colorado
SPSSouthwestern Public Service Co.
Utility subsidiariesNSP-Minnesota, NSP-Wisconsin, PSCo and SPS
WGIWestGas InterState, Inc.
WYCOWYCO Development, LLC
Xcel EnergyXcel Energy Inc. and its subsidiaries
Federal and State Regulatory Agencies
CPUCColorado Public Utilities Commission
D.C. CircuitDOCUnited States Court of Appeals for the District of Columbia Circuit
DOCMinnesota Department of Commerce
DOEUnited States Department of Energy
DOTUnited States Department of Transportation
EPAUnited States Environmental Protection Agency
FERCFederal Energy Regulatory Commission
Fifth CircuitIRSUnited States Court of Appeals for the Fifth Circuit
IRSInternal Revenue Service
Minnesota District CourtMPSCU.S. District Court for the District of Minnesota
MPSCMichigan Public Service Commission
MPUCMinnesota Public Utilities Commission
NDPSCNorth Dakota Public Service Commission
NERCNorth American Electric Reliability Corporation
NMPRCNew Mexico Public Regulation Commission
NRCNuclear Regulatory Commission
OAGPHMSAMinnesota Office of the Attorney General
PHMSAPipeline and Hazardous Materials Safety Administration
PSCWPublic Service Commission of Wisconsin
PUCTPublic Utility Commission of Texas
SDPUCSECSouth Dakota Public Utilities Commission
SECSecurities and Exchange Commission
TCEQTexas Commission on Environmental Quality
Electric, Purchased Gas and Resource Adjustment Clauses
CIPConservation improvement program
DCRFDSMDistribution cost recovery factor
DSMDemand side management
DSMCAECADemand side management cost adjustment
ECARetail electric commodity adjustment
EECRFFCAEnergy efficiency cost recovery factor
FCAFuel clause adjustment
FPPCACGCAFuel and purchased power cost adjustment clause
GCAGas cost adjustment
GUICGas utility infrastructure cost rider
PSIAPipeline system integrity adjustment
RESRenewable energy standard
TCRTransmission cost recovery
PCCAPurchased capacity cost adjustmentOther
PCRFAFUDCPower cost recovery factor
PGAPurchased gas adjustment
PSIAPipeline system integrity adjustment
RDFRenewable development fund
RERRenewable energy rider
RESRenewable energy standard
RESARenewable energy standard adjustment
SCASteam cost adjustment
SEPState energy policy rider
TCATransmission cost adjustment
TCRTransmission cost recovery adjustment
TCRFTransmission cost recovery factor
Other
ADITAccumulated deferred income taxes
AFUDCAllowance for funds used during construction
AROALJAdministrative Law Judge
AROAsset retirement obligation
ASCFASB Accounting Standards Codification
ASUATMFASB Accounting Standards UpdateAt-the-market
BARTBest available retrofit technology
BoulderC&ICity of Boulder, CO
C&ICommercial and Industrial
CACJACAGRClean Air Clean Jobs ActCorporate annual growth rate
CAISOCapX2020California Independent System Operator
CapX2020Alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort
CBACCRCollective-bargaining agreement
CCRCoal combustion residuals
CCR RuleFinal rule (40 CFR 257.50 - 257.107) published by the EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste
CDDCooling degree-days
CEOChief executive officer
CFOChief financial officer
CEPCIGColorado Energy Plan
CIGColorado Interstate Gas Company, LLC
CPCNCOEOColorado Energy Office
CONCertificate of public convenience and necessityNeed
CWACOVID-19Novel coronavirus
CUBCitizens Utility Board
CWAClean Water Act
CWIPConstruction work in progress
DECOND.C. CircuitUnited States Court of Appeals for the District of Columbia Circuit
DECONDecommissioning method where radioactive contamination is removed and safely disposed of at a requisite facility or decontaminated to a permitted level.level
DRCDRIPDevelopment Recovery Company
DRIPDividend Reinvestment Program
EEIEdison Electric Institute
ELGEIPEnergy Impact Partners
ELGEffluent limitations guidelines
EMANIEuropean Mutual Association for Nuclear Insurance
EPSEarnings per share
EPUESGExtended power uprateEnvironmental, Social and Governance
ETREffective tax rate
FASBEVsElectric Vehicles
FASBFinancial Accounting Standards Board
FTRFifth CircuitUnited States Court of Appeals for the Fifth Circuit
FTRFinancial transmission right
GAAPGenerally accepted accounting principles
GEGeneral Electric
GHGGreenhouse gas

HDDHeating degree-days
HDDINPOHeating degree-daysInstitute of Nuclear Power Operations
IMIPCCIntegrated marketIntergovernmental Panel on Climate Change
IPPIndependent power producing entity
IRPISOIntegrated Resource PlanIndependent System Operator
ITCInvestment Tax Credit
JOALP&LJoint operating agreementLubbock Power & Light
LSP TransmissionMECLSP Transmission Holdings, LLC
MDLMulti-district litigation
MECMankato Energy Center
MGPManufactured gas plant
MISOMidcontinent Independent System Operator, Inc.
Moody’sNAAQSMoody’s Investor Services
NAAQSNational Ambient Air Quality Standard
Native loadDemand of retail and wholesale customers that a utility has an obligation to serve under statute or contract
NAVNet asset value
NEILNuclear Electric Insurance Ltd.
NOINOLNotice of Inquiry
NOLNet operating loss
NOPRNotice of proposed rulemaking
O&MOperating and maintenance
OATTOAGMinnesota Office of the Attorney General
OATTOpen Access Transmission Tariff
PIPFASPer- and PolyFluoroAlkyl Substances
PIPrairie Island nuclear generating plant
Post-65Post-Medicare
PPAPurchased power agreement
Pre-65Pre-Medicare
PTCProduction tax credit
RECRenewable energy credit
3
Table of Contents
ROEReturn on equity
ROFRROURight-of-first-refusalRight-of-use
ROURTORight-of-use
RPSRenewable portfolio standards
RTORegional Transmission Organization
Standard & Poor’sS&PStandard & Poor’s Global Ratings Services
SERPSupplemental executive retirement plan
SMMPASouthern Minnesota Municipal Power Agency
SO2
Sulfur dioxide
SPPSouthwest Power Pool, Inc.
TCEHTCJATexas Competitive Energy Holdings
TCJA2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act
THITemperature-humidity index
TOsTOTransmission ownersowner
TransCoTSRTransmission-only subsidiary
TSRTotal shareholder return
VaRValue at Risk
VIEVariable interest entity
WOTUSMeasurements
BcfWaters of the U.S.Billion cubic feet
KVKilovolts
KWhKilowatt hours
MMBtuMillion British thermal units
MWMegawatts
MWhMegawatt hours

Measurements
BcfBillion cubic feet
KVKilovolts
KWhKilowatt hours
MMBtuMillion British thermal units
MWMegawatts
MWhMegawatt hoursWhere to Find More Information
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. Xcel Energy intends to make future announcements regarding Company developments and financial performance through its website, www.xcelenergy.com, as well as through press releases, filings with the SEC, conference calls and webcasts.
Forward-Looking Statements
Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including the 2020those relating to 2022 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information.
The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 20192021 (including the items described under Factors Affecting Results of Operations; and the other risk factors listed from time to time by Xcel Energy Inc. in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K 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, including our nuclear generation facilities;facilities and other utility operations; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; violations of our Codes of Conduct; ability to recover costs,costs; changes in regulation and subsidiaries’ ability to recover costs from customers; 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 andand/or the ability of Xcel Energy Inc. and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; and costs of potential regulatory penalties.penalties; and regulatory changes and/or limitations related to the use of natural gas as an energy source.

4
Table of Contents
Where to Find More Information
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.

Overview
Xcel Energy (the “Company”) is a major U.S. regulated electric and natural gas delivery company headquartered in Minneapolis, Minnesota (incorporated in Minnesota in 1909). The CompanyXcel Energy serves customers in eight mid-western and western states, including portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Xcel Energy provides a comprehensive portfolio of energy-related products and services to approximately 3.7 million electric customers and 2.1 million natural gas customers through four utility subsidiaries (i.e., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS). Along with the utility subsidiaries, the transmission-only subsidiaries, WYCO (a joint venture formed with CIG to develop and lease natural gas pipelines, storage and compression facilities) and WGI (an interstate natural gas pipeline company) comprise the regulated utility operations. The Company’s significantXcel Energy’s nonregulated subsidiaries areinclude Eloigne, Capital Services, Venture Holdings and Nicollet Project Holdings.
xel-20211231_g2.jpg
 Utility Subsidiaries’ Service Territory
 Utility Subsidiaries’ Service Territory
xel-20211231_g3.jpg
Electric customers3.7 million
Natural gas customers2.1 million
Total assets$50.457.9 billion
Electric generating capacity18,73020,653 MW
Natural gas storage capacity53.4 Bcf
Electric transmission lines (conductor miles)108,238111,434 miles
Electric distribution lines (conductor miles)207,524210,470 miles
Natural gas transmission lines2,1772,293 miles
Natural gas distribution lines35,62436,510 miles
Natural gas storage capacity53.4 Bcf
Strategy
Xcel Energy strives to be the preferred and trusted provider of the energy our customers need, while offering a competitive total return to shareholders. We deliver on our vision through three strategic priorities:
Vision, Mission and ValuesLEAD THE CLEAN ENERGY TRANSITIONENHANCE THE CUSTOMER EXPERIENCEKEEP BILLS LOW
Sustainability is embedded in our strategy. We are retiring coal plants, adding renewables, exploring new technologies and helping to electrify other sectors, while maintaining customer affordability and supporting our employees and communities.
valuesa.jpgWe are the first U.S. energy provider to set aggressive goals for reducing GHG emissions across three large sectors of the economy: electricity, natural gas use in buildings and transportation.

Our sustainability commitments include:
xel-20211231_g4.jpg
(1)Includes owned and purchased electricity provided to customers.
(2)Spans natural gas supply, distribution and customer use; includes net-zero methane emissions on our natural gas system by 2030.
We demonstrate environmental, social and governance leadership by engaging with stakeholders and mitigating risk, while staying committed to our customers, employees and communities.
5
Table of Contents
Rooted in a culture of compliance and ethical conduct, our decisions and actions are guided by our Code of Conduct and our four values:
Strategic PrioritiesConnectedCommittedSafeTrustworthy
These values are reinforced by policies that govern safety practices, ethical standards and conduct, environmental performance, diversity and inclusion, political contributions, and other aspects of our business.
strategicprioritiesa03.jpgOur values, culture and Code of Conduct serve as the foundation upon which Xcel Energy’s Board of Directors, employees, contractors and suppliers approach their work in delivering on our three strategic priorities.
Lead the Clean Energy Transition
For more than a decade, Xcel Energy has proactively managed the risk of climate change and worked to meet increasing customer demand for renewable energy throughcleaner energy.
Xcel Energy was the first major U.S. utility to establish a clean energy strategy that consistently seeks to reducecarbon-free vision, targeting 100% carbon-free electricity by 2050 and an interim goal of 80% reduction in carbon emissions by 2030 (from 2005 levels), including owned and aims to transition our operationspurchased power. A lead author for the future.IPCC confirmed that our vision aligns with science-based scenarios likely to limit global warming to 1.5 degrees Celsius from pre-industrial levels.
xel-20211231_g5.jpg
Goal includes owned and purchased power.
The pace of achieving a carbon-free vision is governed by reliability and customer affordability. Our filed resource plans outline a clear, transparent path to achieve an 80% carbon reduction using current technologies, while maintaining customer bill increases at or below the rate of inflation. Moving from 80% carbon reduction to 100% carbon-free electricity will require new dispatchable and scalable technologies that are economically viable, as well as supportive public policy. Resiliency and innovation also remain paramount to a successful transition, as does the economic vitality of our communities.
As we prepare for early coal plant retirements, we provide employees advanced notice and offer retraining and relocation opportunities, with no layoffs to date. We have successfullyalso help attract and make investments to offset community economic impacts. Xcel Energy has a long track record of working with our communities on energy, climate and environmental initiatives that impact them and has publicly committed to furthering environmental justice.
We consistently set aggressive goals and hold ourselves accountable to our customers, communities and investors, as well as, to our own values. Xcel Energy instituted oversight of environmental performance by the Board of Directors beginning in 2000 and was among the first U.S. utilities to tie carbon reduction to executive compensation over fifteen years ago.
Through 2021, we reduced our carbon emissions from generation serving our customers by nearly 44% froman estimated 50% (from 2005 to 2019levels) and we areremain on track to reach 60% renewableachieve 80% carbon reduction by 2030.
Other notable environmental improvements include:
xel-20211231_g6.jpg
Results from owned generation except for water, which includes owned and purchased power.
*Coal ash reduction is as of 2020.
Xcel Energy has provided a voluntary, third-party verified annual GHG disclosure since 2005, longer than any other U.S. utility. We are a founding member of The Climate Registry and a supporter of the Task Force on Climate-Related Financial Disclosures. Our disclosures also align with the Global Reporting Initiative, Sustainability Accounting Standards Board and United Nations Sustainable Development Goals frameworks.
Since year-end 2020, we have completed four wind farms, adding ~800 MW (includes the Dakota Range project which went in service in January 2022) of owned wind to our system that provides significant environmental benefits and cost savings for our customers. Xcel Energy’s wind capacity is now over 11,000 MW, including nearly 4,500 MW of owned wind.
By 2030, we project that approximately 80% of our energy will come from carbon-free resources.
xel-20211231_g7.jpg
Based on resource plans filed in Minnesota and Colorado, Xcel Energy anticipates nearly 10,000 MW of additional renewables over the next decade, and expects to be coal-free by 2034.
Colorado resource plan — settlement pending CPUC approval
•87% carbon reduction by 2030 and full coal exit by 2034.
•~3,900 MW of wind and solar additions.
•~1,700 MW of flexible resources and storage.
•~1,200 MW of distributed solar generation.
Minnesota resource plan — approved by MPUC
•85% carbon reduction and full coal exit by 2030.
•4,650 MW of wind and solar additions by 2032; the plan includes an additional 1,100 MW of renewables beyond 2032.
•Transmission infrastructure to connect new renewables to the grid.
•Extension of the Monticello nuclear plant through 2040.
•~3,800 MW of firm peaking capacity for reliability before 2030, including hydrogen-ready combustion turbines, the combustion turbines will need to go through a CON process.
•Additional ~2,100 MW of firm capacity and storage post 2030, to be addressed in future proceedings.
Texas and New Mexico
•Proposed full coal exit by 2034 upon early retirement of our Tolk plant.
•Conversion of our Harrington coal plant to natural gas.
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We expectplan to limit coal usage through dispatching units seasonally where possible. Natural gas and other dispatchable resources will be used as needed for reliability and resiliency as more renewables come on the system.
Significant transmission expansion will be required to enable future renewables. Our Pathway project (if approved) in Colorado will provide over 560 miles of transmission lines and enable nearly 5,500 MW of new renewables, including access to some of the region’s richest wind resources. We also anticipate expansion in the Upper Midwest over the next decade as part of MISO’s transmission expansion planning effort, creating investment opportunity.
Our clean energy leadership encompasses our natural gas business as well. In 2021, we committed to reduce our carbon footprintGHG emissions by 80%25% by 2030 (over 2005 levels)from 2020 levels and aspiredeliver net-zero natural gas service by 2050, including customer use.
Plans include:
•Influencing suppliers - pursue certified low/no net emissions supply.
•Operating the cleanest possible system – incorporate clean fuels.
•Offering customer options – encourage electrification, where beneficial.
Xcel Energy’s leadership also extends beyond our electric and gas businesses to serve all customers with 100% carbon-free electricity by 2050.
leadthecleanenergytransition.jpg
other parts of the economy. In addition to increasingtransitioning our renewableown generation Xcel Energy is transitioning howfleet, we produce, deliverare helping to decarbonize other sectors, starting with transportation. We aim to enable 1.5 million EVs across our states by 2030, representing a nearly $2 billion investment, 0.6% to 0.7% incremental annual retail sales growth and encourage the efficient useavoidance of energy by:
Offering energy efficiency programs;
Retiring coal units and modernizing generating plants; and
Advancing power grid capabilities.
We are working to add over 4,700 MWroughly 5 million tons of wind energy to our system by 2021, including 3,500 MW of owned wind and 1,200 MW of PPAs. Of the 3,500 MW of owned wind, 1,300 MW are now in service and 2,200 MW are under development or construction. This will bring our total wind capacity to over 11,000 MW by 2021.CO2 emissions annually.
Our long-term plan includes the addition of approximately 5,000 MW of solar energy by the early 2030s, 275 MW of battery storage and a potential ten-year extension of our Monticello nuclear plant. It also includes the retirement of multiple coal units totaling approximately 2,000 MW. Xcel Energy plans to continue to evaluate its coal fleet for other potential early retirements as part of state resource plans or other regulatory proceedings.
Enhance the Customer Experience
Customers’ energy expectations continue to evolve and Xcel Energy is committed to providing thehas a comprehensive suite of renewable and conservation programs that provide customers with clean energy options and solutions they want and value.
Xcel Energy continues to expand its renewable energy production and offerings, and further develop and promote DSM and conservation programs. Over the past decade, the Company has spent over $2.1 billion on these programs.
help keep their bills low. We are also in the process of transforming and expanding our electric grid to accommodate increased load growth, renewable energy and distributed energy resources.
In 2021, Xcel Energy installed over 300,000 smart meters and plans to install more than one million in 2022. Xcel Energy also launched 12 EV programs for residential and commercial customers, received approval of our New Mexico plan, and continued to prepare for increased levels of renewables, distributed energy resources and corresponding data growth, while maintaining high levels of reliability and security.
We have partnered with policymakers, state agencies and innovative companies to develop nation-leading electric vehicle solutions for our customers. We are preparing for a substantial amount of electric vehicles on roadsEV adoption across our service territory by 2030states.
For our local communities, we initiated 20 economic development projects in 2021, which are projected to lead to over $1 billion in capital investments and are focused on providing helpful information, making installations simple and keeping customer bills affordable through new rates and programs. We anticipate offering innovative programs for electric vehicle customers in Minnesota, Wisconsin, and Colorado this year. We are filing comprehensive Transportation Electrification Plans in both Colorado and New Mexico in the coming year.
We continue to develop and deliver new renewable energy solutions for5,000 jobs. Additionally, over 60% of our residential and C&I customers who want more directly sourced energy. Through programs such as Renewable*Connect® and Windsource®, we match our customers’ needs without them needing to add expensive or on‑site equipment.supply chain spend was local.
Keep Bills Low
AffordabilityCustomer affordability is critical part of our customers’ experience. Weto successful strategy execution and we are focused on the impact our operations, regulation and legislation have on their bills. Our objective isworking to keep bill increases at or below the rate of inflation. Since 2013, we have managed average residential bill growth to below 1% annually, with electric and natural gas bill increases of 0.8% and 0.3%, respectively.
Xcel Energy has invested more than $2 billion over the past decade in a comprehensive suite of conservation programs. We have kept O&M expenses flat since 2014, while adding significant renewables and without compromising safety or reliability.
Xcel Energy continues to prudently invest in appropriate areas consistent with its continuing commitment to minimize costs through ongoing process and technology improvements.
Our utility service territories benefit from the geographic concentration of favorable renewable resources. Strongadvantages in wind and high solar generationalso enable customer savings, which we call our “Steel for Fuel” strategy. High capacity factors, lower the lifetime cost of these resources. This, coupled with renewable tax credits and avoided fuel costs, enables us to invest in more renewable generation, in which the capital costs are largely or completely offset by fuel savings. We call this our “Steel for Fuel” strategy.
Steel for Fuel not only expands the Company’s renewable portfolio, but allows delivery of carbon-free energy without raising customer bills through replacement of fossil fuel generation or fuel-free wind and solar.
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enable Xcel Energy is working to keep long-term O&M expense relatively flat without compromising reliability or safety. We intend to accomplish this objectiveadd renewables while saving customers money. To date, we have delivered more than $1.8 billion in customer savings by continually improving processes, leveraging technology, proactively managing risk and maintaining a workforce prepared to meet the needs of our business today and tomorrow.
O&M declined 0.6% in 2019 even as we took the opportunity to invest more in key strategic and operational areas, including reducing operational risks and enhancing our customers’ experience. While Xcel Energy continues to invest prudently in appropriate areas, we remain committedadding owned wind to our long-term objectivesystem.
In addition to continued savings from economic renewables, disciplined cost control and future coal plant retirements, we anticipate sales growth from electric vehicles will help keep bills low for all customers in the long term, as well as provide customers with annual fuel savings (equivalent cost per gallon for fueling with electricity vs. gasoline) of improving operating efficiencies and taking costs out of the business.approximately $1 billion by 2030.

Deliver a Competitive Total Return to Investors and Maintain Strong Investment Grade Credit Rating
Successful strategy execution, of our strategic objectives should allow Xcel Energy to continue to deliver a competitive total return for our shareholders.
Throughalong with our disciplined approach to business growth, financial investment, operations and safety, we are well positionedmanagement of environmental, social and governance issues, positions us to continue delivering on our value proposition.a competitive TSR.
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We have consistently achieved our financial objectives, meeting or exceeding our initial earnings guidance range for fifteen17 consecutive years and delivering dividend growth for sixteen18 consecutive years.
Our ongoingOver the past five years, GAAP earnings have grown 6.1%by 6% annually since 2005 and our annual dividend has grown 6.3% annually from 2013-2019. We workgrowth was 6.1%. Xcel Energy works to maintain senior secured debt credit ratings in the A range and senior unsecured debt credit ratings in the BBB+ to A range. Our currentCurrent ratings are consistent with this objective.goal.
Environmental, Social and Governance LeadershipHuman Capital
Xcel Energy has consistently demonstrated industry leadership in mitigating climate, operationalemployees are the driving force behind our Company’s success. Our strategic, data-driven approach to workforce planning helps ensure we will continue to have the skills and financial risks, while remainingcapabilities required to meet the evolving needs of our business, customers and communities. We are also deeply committed to diversity, equity, human rights and safety.
Safety
Continuously elevating the quality and safety of the workplace is a top priority. We are considered a benchmark company for our Safety Always approach, focused on eliminating life-altering injuries through a trusted, transparent culture and the use of critical controls. All employees have “stop work authority” and are expected to keep each other, our customers communities, employees and investors. We have delivered tangible environmental, socialthe public safe. Employees are encouraged to speak up, share experiences and governance results in alignment with our four corporate values - committed, connected, safelearn from events to help protect themselves, their coworkers and trustworthy.the public.
The Board of Directors has oversight for employee and public safety through the Operations, Nuclear, Environmental and Safety committee, both of which are also tied to annual incentive compensation.
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Table of Contents
Benefits
Xcel Energy has been the number one U.S. wind provider for 12 of the past 14 years.offers a competitive benefits package, including: performance-based compensation, supported by a management system that emphasizes ongoing coaching conversations. Benefits also include floating holidays and recognition, retirement and holistic well-being programs.
Management continuously evaluates benefits to maintain a market competitive, performance-based, shareholder-aligned total rewards package that supports our ability to attract, engage and retain a talented and diverse workforce, while reinforcing and rewarding strong performance.
Diversity, Equity, Inclusion and Human Rights
We continue to lead the industry with one of the most aggressive carbon reduction goals among our peers. Our plans to achieve 80% reduction by 2030 are aligned with Paris Accord goals and have been independently validated by an Intergovernmental Panel on Climate Change expert.
In December 2018, Xcel Energy became the first major electric utility in the country to announce an aspiration to produce 100% carbon-free electricity for customers by 2050.
Social
Xcel Energy works to mitigate the employee and community impacts of early plant retirements. We provide affected employees with advanced notice and offer retraining and relocation opportunities. Through these efforts and natural attrition, Xcel Energy has had no layoffs as a result of plant retirements.
We have also worked to foster economic sustainability and continued affordability through partnering with communities, policymakers and customers impacted by coal plant retirements, to build facilities and attract new businesses. Examples include:
Near our Sherco plant, scheduled to close by 2030, we are partnering with local leadership and a major data center to locate a $600 million data center. Additionally, Xcel Energy actively worked to relocate a metal recycling plant near our plant; and
We retained Evraz Steel in Colorado, a major Pueblo employer, by partnering with the company and communityaim to create an affordable solar solution to meet their needs.inclusive culture where employees are treated equitably, and diversity is not only accepted but celebrated. This starts with our Board of Directors, of which eight members were elected in the past five years.
Xcel Energy is an active community member. We recognize and carefully evaluate the broader potential economic impacts of our decisions and work to proactively support the people and economic health of our communities. In 2019, we spent $3.1 billion locally, donated nearly $11 million to local charities, continued to offer employees 40 hours of volunteer paid time off annually and our employees served on over 500 non-profit boards. Donations include Xcel Energy employee and Xcel Energy Foundation gifts.
As a member of diverse communities, we value and celebrate diversity and inclusion. For example:
Xcel Energy has offered domestic partner benefits since 1995;xel-20211231_g9.jpg
The Company’s CEO has signed the Action for Diversity & Inclusion Pledge, for the advancementBoard of Directors oversees our workforce strategy, including diversity and inclusion within the workplace, andinitiatives. In 2021, Xcel Energy hasadded an employee-led Diversity & Inclusion Council;
We have been selected among the nation’s top corporations for lesbian, gay, bisexual, transgender, and queer equality by earning a perfect score on the Human Rights Campaign’s 2019 Corporate Equality Index for the past 4 years; and
Xcel Energy was named to the 2019 Military Times Best for Vets Employers rankings for the sixth straight year and currently employs more than 1,000 veterans, nearly 10% of our workforce.
Governance
Xcel Energy has a diverse and qualified Board of Directors committed to effective governance.
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The Company first adopted an environmental policy and instituted Board of Directors’ oversight of environmental performance in 2000, followed by publication of our corporate responsibility report in 2005.
We consistently set aggressive goals and hold ourselves accountable, to our customers, our communities and our investors. Additionally, Xcel Energy was among the first U.S. utilities to tie carbon reduction directly to executive compensation over fifteen years ago and is one of three peer utilities who do so today.
We are alsoincentive-based metric focused on safety for our employeesdiverse interview panels, executive sponsorship and our communities. In 2019, 60%employee feedback on inclusion in the workplace. A total of 70% of annual incentive pay was tied to safety, system reliability and system reliability. Employeesdiversity, equity and inclusion metrics.
In 2021, nearly all offers made had diverse hiring panels and executive sponsors consistently met with their employee counterparts at every levelleast monthly. We have “stopalso disclosed our Equal Employment Opportunity Employer Information Report (EEO-1).
Our CEO and senior executives lead by example, fostering an open and inclusive work authority”environment through their interactions, communications and are instrumentalpersonal sponsorship of diverse talent throughout the organization.
We partner with educational and community organizations to attract and hire diverse employees who reflect the communities we serve and live our values. Workforce demographics as of December 2021 (unless otherwise noted):
FemaleEthnically Diverse
Board of Directors (a)
23 %15 %
CEO direct reports (a)
36 %18 %
Management22 %11 %
Employees24 %17 %
New hires39 %26 %
Interns (hired throughout 2021)34 %27 %
(a)Demographics as of Feb. 1, 2022.
Veteran hiring is also a focus, with roughly 10% of employees having served in keeping eachthe military.
To help foster a culture of inclusivity, leaders and employees receive training on microinequities and unconscious bias. The Company hosts 11 business resource groups to support employee interests and obtain diverse perspectives when solving challenges and achieving goals.
Xcel Energy also respects employees’ freedom of association and their right to collectively organize. As of Dec. 31, 2021, approximately 44% of our employees were covered by collective bargaining agreements.
Employees Covered by Collective Bargaining AgreementsTotal Full-Time Employees
NSP-Minnesota2,020 3,083 
NSP-Wisconsin382 518 
PSCo1,818 2,314 
SPS736 1,099 
XES— 4,307 
Total4,956 11,321 
Employee turnover for 2021 and future projected retirement eligibility:
Employee TurnoverRetirement Eligibility
Bargaining7 %Within next 5 years26 %
Non-Bargaining15 %Within next 10 years40 %
Overall (a)
12 %
(a)31% of turnover was due to retirements.
Xcel Energy has publicly confirmed our commitment to the advancement and protection of human rights, consistent with U.S. human rights laws and the general principles in the International Labour Organization Conventions. Code of Conduct training is required for all employees annually and the Board of Directors.
The Company does not tolerate Code violations or other unacceptable behaviors. We expect and our surrounding communities safe.offer employees multiple avenues to raise concerns or report wrong-doing and do not permit any retaliation.
Xcel Energy recently received the following recognitions:
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FortuneHuman Rights CampaignGI JobsMilitary Times
World’s Most Admired CompaniesBest Places to Work for LGBTQ EqualityMilitary Friendly EmployerBest for Vets

8

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Utility Subsidiaries
NSP-Minnesota
xel-20211231_g14.jpg
Electric customers1.5 millionNSP-Minnesota conducts business in Minnesota, North Dakota and South Dakota and has electric operations in all three states including the generation, purchase, transmission, distribution and sale of electricity. NSP-Minnesota and NSP-Wisconsin electric operations are managed on the NSP System. NSP-Minnesota also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in Minnesota and North Dakota.
Natural gas customers0.60.5 million
Consolidated earnings contribution35% to 45%
Total assets$19.922.8 billion
Rate Base (estimated)$11.213.7 billion
ROE (net income / average stockholder's equity)9.31%8.45%
Electric generating capacity7,7128,628 MW
Gas storage capacity17.1 Bcf
Electric transmission lines (conductor miles)33,52834,155 miles
Electric distribution lines (conductor miles)80,18681,406 miles
Natural gas transmission lines8685 miles
Natural gas distribution lines10,51810,741 miles
NSP-Wisconsin
xel-20211231_g15.jpg
Electric customers0.3 millionNSP-Wisconsin conducts business in Wisconsin and Michigan and generates, transmits, distributes and sells electricity. NSP-Minnesota and NSP-Wisconsin electric operations are managed on the NSP System. NSP-Wisconsin also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas.
Natural gas customers0.1 million
Consolidated earnings contribution5% to 10%
Total assets$2.83.1 billion
Rate Base (estimated)$1.72.0 billion
ROE (net income / average stockholder's equity)8.27%9.92%
Electric generating capacity548 MW
Gas storage capacity3.8 Bcf
Electric transmission lines (conductor miles)12,28512,409 miles
Electric distribution lines (conductor miles)27,50427,701 miles
Natural gas transmission lines3 miles
Natural gas distribution lines2,4732,526 miles
PSCo
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Electric customers1.5 millionPSCo conducts business in Colorado and generates, purchases, transmits, distributes and sells electricity. PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas.
Natural gas customers1.41.5 million
Consolidated earnings contribution35% to 45%
Total assets$19.022.0 billion
Rate Base (estimated)$12.414.0 billion
ROE (net income / average stockholder's equity)8.69%8.23%
Electric generating capacity5,6666,228 MW
Gas storage capacity32.5 Bcf
Electric transmission lines (conductor miles)24,00824,116 miles
Electric distribution lines (conductor miles)78,02378,712 miles
Natural gas transmission lines2,057miles2,174 miles
Natural gas distribution lines22,63323,243 miles
SPS
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Electric customers0.4 millionSPS conducts business in Texas and New Mexico and generates, purchases, transmits, distributes and sells electricity.
Consolidated earnings contribution15% to 20%
Total assets$7.99.3 billion
Rate baseBase (estimated)$4.96.4 billion
ROE (net income / average stockholder's equity)9.71%9.22%
Electric generating capacity4,8045,249 MW
Electric transmission lines (conductor miles)38,41840,754 miles
Electric distribution lines (conductor miles)21,81022,651 miles

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Operations Overview
Utility operations are generally conducted as either electric or gas utilities in our four utility subsidiaries.
Electric Operations
Electric operations consist of energy supply, generation, transmission and distribution activities across all four operating companies. Xcel Energy had electric sales volume of 116,317115,474 (millions of KWh), 3,662,7013.7 million customers and electric revenues of $9,575$11,205 (millions of dollars) for 2019.
2021.
electricsalesvolume2019.jpgelectriccustomers2019.jpgelectricrevenue2019.jpg
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Retail Sales/Revenue Statistics(a)
20212020
KWh sales per retail customer23,968 23,910 
Revenue per retail customer$2,405 $2,199 
Residential revenue per KWh12.94 ¢12.12 ¢
Large C&I revenue per KWh6.60 ¢5.78 ¢
Small C&I revenue per KWh10.47 ¢9.56 ¢
Total retail revenue per KWh10.03 ¢9.20 ¢
  2019 2018
KWh sales per retail customer 24,712
 25,263
Revenue per retail customer $2,244
 $2,257
Residential revenue per KWh 
11.97¢ 
11.78¢
Large C&I revenue per KWh 
5.96¢ 
5.91¢
Small C&I revenue per KWh 
9.43¢ 
9.21¢
Total retail revenue per KWh 
9.08¢ 
8.93¢
(a) See Note 6 to the consolidated financial statements for further information.
Owned and Purchased Energy Generation — 20192021
ownedvspurchase.jpgxel-20211231_g21.jpg
Electric Energy Sources
Total electric energy generation by source (including energy market purchases) for the year ended Dec. 31, 2019:
2021:
xcelenergymix2019.jpgxel-20211231_g22.jpgnspmenergymix2019.jpgxel-20211231_g23.jpgpscoenergymix2019.jpgxel-20211231_g24.jpgspsenergymix2019.jpg

xel-20211231_g25.jpg
*Distributed generation from the Solar*Rewards® program is not included (approximately 538666 million KWh for 2019)2021).

Renewable Energy Sources10
Table of Contents
Carbon-Free
Xcel Energy’s renewablecarbon-free energy portfolio includes wind, nuclear, hydroelectric, biomass and solar power from both owned generatinggeneration facilities and PPAs. RenewableCarbon-free percentages will vary year over yearyear-over-year based on system additions, commodity costs, weather, system demand and transmission constraints.
See Item 2 — Properties for further information.
RenewableCarbon-free energy as a percentage of total energy for 2019:2021:
renewablebreakout.jpgxel-20211231_g26.jpg
(a)
* Includes biomass and hydroelectric.
Includes biomass and hydroelectric
Wind Energy Sources
Owned — Owned and operated wind farms with corresponding capacity:
Utility Subsidiary20212020
Wind Farms
Capacity (MW) (a)
Wind Farms
Capacity (MW) (b)
NSP System142,031111,540
PSCo21,05921,059
SPS29842967
Total184,075153,566
  2019 2018
Utility Subsidiary Wind Farms Capacity Wind Farms Capacity
NSP System 7 1,090 MW 5 840 MW
PSCo 1 600 MW 1 600 MW
SPS 1 478 MW — —
(a) Summer 2021 net dependable capacity.
(b) Summer 2020 net dependable capacity.
PPAs — Number of PPAs with capacity range:
Utility Subsidiary 2019 2018Utility Subsidiary20212020
PPAs Range PPAs RangePPAsRange (MW)PPAsRange (MW)
NSP System 131 0.7 MW — 205.5 MW 132 0.7 MW - 205.5 MWNSP System1281 — 2061291 — 206
PSCo 20 2.0 MW — 300.5 MW 19 2.0 MW - 300.5 MWPSCo1723 — 3011723 — 301
SPS 18 0.7 MW — 250.0 MW 18 0.7 MW - 250.0 MWSPS171 — 250181 — 250
Capacity — Wind capacity:capacity (MW):
Utility Subsidiary 2019 2018Utility Subsidiary20212020
NSP System 2,780 MW 2,550 MWNSP System3,9973,348
PSCo 3,165 MW  3,160 MWPSCo4,0854,085
SPS 2,045 MW 1,565 MWSPS2,5482,535
Average Cost (Owned) — Average cost per MWh of wind energy from owned generation:
Utility Subsidiary20212020
NSP System$25 $23 
PSCo17 35 
SPS17 17 


Utility Subsidiary (a)
 2019 2018
NSP System $35
 $37
PSCo 47
 —
(a)
The table reflects owned wind sites that were in commercial operation for the full calendar year. The Hale wind farm for SPS was put into service in June 2019 and the Rush Creek wind farm was put into service in December 2018.
Average Cost (PPAs) — Average cost per MWh of wind energy under existing PPAs:
Utility Subsidiary 2019 2018Utility Subsidiary20212020
NSP System $41
 $44
NSP System$37 $38 
PSCo 41
 43
PSCo35 40 
SPS 25
 26
SPS27 26 
Wind Energy Development
Xcel Energy is executing the largest multi-state wind investment in the nation and placed approximately 1,300500 MW of owned wind and approximately 300255 MW of PPAs into service during 2018-2019:
2021:
ProjectUtility SubsidiaryCapacity
Rush CreekPSCo582 MW
HaleSPS460 MW
FoxtailNSP-Minnesota150 MW
Lake BentonNSP-Minnesota99 MW
Various PPAsVarious~300 MW
As part of the multi-state wind investment, Xcel Energy currently has approximately 2,200 MW of owned wind under development or construction and approximately 900 MW of planned PPAs with an estimated completion date of 2021 or earlier:
ProjectUtility SubsidiaryCapacityEstimated Completion (MW)
FreebornNSP-Minnesota200 MW2020
Blazing Star 1NSP-Minnesota200 MW2020
Blazing Star 2NSP-Minnesota
200 MW
2020(a)(b)
FreebornNSP-Minnesota
Crowned Ridge200 (a)(b)
NSP-Minnesota200 MW2020
MowerNSP-Minnesota
Jeffers91 (a)(b)
NSP-Minnesota44 MW2020
Community Wind North(b)
NSP-Minnesota26 MW2020
Dakota RangeNSP-Minnesota300 MW2021
Cheyenne RidgePSCo500 MW2020
SagamoreSPS522 MW2020
Various PPAsVarious
~900 MW
2020 - 2021255(c)
(a) Summer 2021 net dependable capacity.
(b) Values disclosed are the maximum generation levels. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
(c) Based on contracted capacity.
Xcel Energy currently has approximately 1,050 MW of owned wind under development or being repowered. In addition, we expect to add approximately 200 MW of planned PPAs.
ProjectUtility SubsidiaryCapacity (MW)Estimated Completion
Northern WindNSP-Minnesota1002022
NoblesNSP-Minnesota2002022
Dakota RangeNSP-Minnesota300
     2022 (a)
Grand MeadowNSP-Minnesota1002023
Border WindsNSP-Minnesota1502025
Pleasant ValleyNSP-Minnesota2002025
Various PPAsVarious~2002022
(a) Placed in service in January 2022.
Solar
Solar PPA(s):
(a)
Build-own-transfer project.
(b)
Repowering project.
Solar Energy Sources
Solar energy PPA(s):
TypeUtility SubsidiaryCapacity (MW)
Distributed GenerationNSP System736 MW994
Utility-ScaleNSP System266 MW268
Distributed GenerationPSCo557 MW736
Utility-ScalePSCo305 MW562
Distributed GenerationSPS10 MW15
Utility-ScaleSPS191 MW192
Total2,767
Average Cost (PPAs) — Average cost per MWh of solar energy under existing PPAs:
Utility Subsidiary20212020
NSP System$90 $90 
PSCo67 89 
SPS61 59 



11
Table of Contents
Other Carbon-Free Energy SourcesSolar Development
Xcel Energy’s other carbon-free energy portfolio includes nuclear from owned generating facilities.In June 2021, the PSCW approved NSP-Wisconsin’s request to purchase the 74 MW Western Mustang build-own-transfer solar facility for approximately $100 million. Also, as part of the Minnesota Recovery and Relief Recovery docket, NSP-Minnesota proposed to add 460 MW of solar facilities at the Sherco site with an incremental investment of approximately $575 million. An MPUC decision is expected by the third quarter of 2022.
See Item 2 — Properties for further information.PSCo placed approximately 260 MW of PPAs into service during 2021.
Nuclear Energy Sources
Xcel Energy has two nuclear plants with approximately 1,700 MW of total 20192021 net summer dependable capacity that serves the NSP-System.NSP System. Our nuclear fleet has become one of the safestbest performing and well-rundependable in the nation, as rated by both the NRC and INPO.
The Company Xcel Energy secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication to operate its nuclear plants. TheWe use varying contract strategy involves a portfolio of spot purchases and medium and long-term contractslengths as well as multiple producers for uranium concentrates, conversion services and enrichment services with multiple producers and with a focus on diversification and alternate sources to minimize potential impacts caused by supply interruptions due to geographical and world political issues.
Nuclear Fuel Cost
Delivered cost per MMBtu of nuclear fuel consumed for owned electric generation and the percentage of total fuel requirements:
Utility SubsidiaryNuclear
NSP SystemCostPercent
2021$0.77 46 %
20200.80 51 
Utility Subsidiary Nuclear
NSP System Cost Percent
2019 $0.81
 45%
2018 0.80
 45
Other
Xcel Energy’s other carbon-free energy portfolio includes hydro from owned generating facilities.
See Item 2 — Properties for further information.
Fossil Fuel Energy Sources
Xcel Energy’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 Energy Sources
Xcel Energy owns and operates nine coal plantsunits with approximately 6,500 MW of total 20192021 net summer dependable capacity.
Our operating companies have embarked on an industry-leading coal retirement program with permission from its key regulatory bodies.
Approved and proposedearly coal plant retirements:
Approved (2019 to 2027)
YearUtility SubsidiaryPlantCapacity
2022PSCoComanche 1325 MW
2023NSP-MinnesotaSherco 2682 MW
2025PSCoComanche 2335 MW
2025PSCoCraig 142 MW
2026NSP-MinnesotaSherco 1680 MW
YearUtility SubsidiaryPlant UnitCapacity (MW)
2022PSCoComanche 1325
2023NSP-MinnesotaSherco 2682
2024SPS
Harrington (a)
1,018
2025PSCoComanche 2335
2025PSCoCraig 1
42 (b)
2026NSP-MinnesotaSherco 1680
2028PSCoCraig 2
40 (b)
2028NSP-MinnesotaA.S. King511
2030NSP-MinnesotaSherco 3
517 (b)
Proposed (2028 to 2030)
YearUtility SubsidiaryPlantCapacity
2028NSP-MinnesotaA.S King511 MW
2030NSP-MinnesotaSherco 3517 MW
(a)Reflects expected conversion from coal to natural gas following the TCEQ order that Harrington cease use of coal fuel by Jan. 1, 2025, pending PUCT and NMPRC review.
(b)Based on Xcel Energy’s ownership interest.
Proposed
YearUtility SubsidiaryPlant UnitCapacity (MW)
2025PSCo
Pawnee (a)
505
2027PSCoHayden 2
98 (b)
2028PSCoHayden 1
135 (c)
2034SPSTolk 1532
2034SPSTolk 2535
2034PSCoComanche 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 fuel requirements:
Coal (a)
Utility SubsidiaryCostPercent
NSP System
2021$1.60 39 %
20201.97 31 
PSCo
20211.43 62 
20201.41 51 
SPS
20212.07 66 
20202.28 40 
  
Coal (a)
Utility Subsidiary Cost Percent
NSP System    
2019 $2.02
 36%
2018 2.13
 42
PSCo    
2019 1.45
 55
2018 1.45
 62
SPS    
2019 2.19
 45
2018 2.04
 56
(a)(a)    Includes refuse-derived fuel and wood for the NSP System.
Includes refuse-derived fuel and wood for the NSP System.
Natural Gas Energy Sources
Xcel Energy has 22 natural gas plants with approximately 7,900 MW of total 20192021 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
Utility SubsidiaryCostPercent
NSP System
2021 (a)
$4.98 15 %
20202.67 17 
PSCo
2021 (a)
8.38 38 
20203.01 49 
SPS
2021 (a)
6.72 34 
20201.43 60 
(a)
Reflective of Winter Storm Uri.
  Natural Gas
Utility Subsidiary Cost Percent
NSP System    
2019 $3.09
 19%
2018 3.87
 13
PSCo    
2019 3.27
 45
2018 3.74
 38
SPS    
2019 1.14
 55
2018 2.24
 44
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Capacity and Demand
Uninterrupted system peak demand and occurrence date for the regulated utilities:
System Peak Demand (MW)
20212020
NSP System
8,837 June 98,571 July 8
PSCo6,958 July 286,899 Aug. 17
SPS4,054 Aug. 94,195 July 14
  System Peak Demand (in MW)
Utility Subsidiary 2019 2018
NSP System  
 8,774
 July 19 8,927
 June 29
PSCo 7,111
 July 19 6,718
 July 10
SPS 4,261
 Aug. 5 4,648
 July 19
Transmission
Transmission lines deliver electricity at high voltages and over long distances from power sources to transmission substations closer to homes and businesses.customers. A strong transmission system ensures continued reliable and affordable service, ability to meet state and regional energy policy goals, and support for a diverse generation mix, including renewable energy. Xcel Energy owns more than 20,000111,000 conductor miles of transmission lines, serving 22,000 MW of customer load.load, across its service territory.

Transmission projects completed in 20192021 include:
ProjectUtility SubsidiaryMilesSize (KV)
Hibbing Taconite RelocationNSP-Minnesota3 500 
Huntley - WilmarthNSP-Minnesota50 345 
Helena Scott CountyNSP-Minnesota16 345 
Centerville to Lincoln CountyNSP-Minnesota14 69 
Turtle Lake AlmenaNSP-Wisconsin4 69 
Roadrunner-China DrawSPS41 345 

ProjectUtility SubsidiaryMilesSize
Maple River-Red RiverNSP-Minnesota5
115 KV
Nelson-WabashaNSP-Wisconsin2
69 KV
Pawnee-Daniels ParkPSCo125
345 KV
Thornton SubstationPSCo2
115 KV
TUCO-Yoakum-HobbsSPS64
345 KV
NEF-CardinalSPS15
115 KV
Potash Junction-Livingston RidgeSPS15
115 KV
Mustang-ShellSPS9
115 KV
North Loving-South LovingSPS3
115 KV
Cunningham-Monument TapSPS7
115 KV
Notable upcoming projects:
Project Utility Subsidiary Miles Size Completion Date
Huntley-Wilmarth NSP-Minnesota 50
 345 KV 2021
Bayfield Second Circuit NSP-Wisconsin 19
 35 KV 2022
Cheyenne Ridge PSCo 65
 345 KV 2020
TUCO-Yoakum-Hobbs SPS 106
 345 KV 2020
Eddy-Kiowa SPS 34
 345 KV 2020
ProjectUtility SubsidiaryMilesSize (KV)Completion Date
Baytown to Long LakeNSP-Minnesota9 115 2022
Bird Island - Atwater - Big SwanNSP-Minnesota68 69 2022
Pipestone - TracyNSP-Minnesota46 69 2022
Line Rebuild - CentralNSP-Minnesota24 69 2022
West St. Cloud to Millwood TapNSP-Minnesota24 69 2022
Bayfield Second CircuitNSP-Wisconsin19 35 2022
Colorado Energy PlanPSCo15 345 2022
Tolk Plant Substation
        Bus ReconfigurationSPSn/a345, 2302022
Twist to Wilco LineSPS4 1152024
PathwayPSCo560 3452027
See Item 2 - Properties for further information.
Distribution
Distribution lines allow electricity to travel at lower voltages from substations directly to homes and businesses in neighborhoods and cities around the country.customers. Xcel Energy has a vast distribution network, owning and operating thousands ofapproximately 210,000 conductor miles of distribution lines across our eight-state service territory, both above ground and underground.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. Over the next five years, the Company willmulti-year project that started in 2016, Xcel Energy plans to invest $1.4approximately $1.7 billion implementing new network infrastructure, smart meters, advanced software, equipment sensors and related data analytics capabilities. These investmentsTo date, Xcel Energy has spent approximately $568 million on these investments.
Investments of this nature will further improve reliability and reduce outage restoration times for our customers, while at the same time enabling new options and opportunities for increased efficiency savings. The new capabilities will also enable integration of battery storage and other distributed energy resources into the grid, including electric vehicles.
In 2019, Xcel Energy implemented foundational software and completed our initial smart meter deployment in Colorado as planned, with full-scale implementation to follow. We also requested approval to expand our advanced grid program to benefit our Minnesota customers and expect a Commission decision in late 2020. We plan to have smart meters implemented across our Colorado and Minnesota service territories by the end of 2024.
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 useend-use residential, C&I and transport customers in NSP-Minnesota, NSP-Wisconsin and PSCo. Xcel Energy had natural gas deliveries of 463,185of 405,895 (thousands of MMBtu), 2,068,1292.1 million customers and natural gas revenues of $1,868$2,132 (millions of dollars) for 2019.
2021.
gasdeliveries2019.jpggascustomers2019.jpggasrevenue2019.jpg
xel-20211231_g27.jpgxel-20211231_g28.jpgxel-20211231_g29.jpg
Sales/Revenue Statistics
  2019 2018
MMBtu sales per retail customer 129.31
 120.51
Revenue per retail customer $851.94
 $785.86
Residential revenue per MMBtu 7.14
 7.01
C&I revenue per MMBtu 5.73
 5.76
Transportation and other revenue per MMBtu 0.57
 0.80
(a)
20212020
MMBtu sales per retail customer114 118 
Revenue per retail customer$917 $720 
Residential revenue per MMBtu8.61 6.64 
C&I revenue per MMBtu7.20 5.22 
Transportation and other revenue per MMBtu1.20 0.67 
(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:
20212020
Utility SubsidiaryMMBtu
Date (a)
MMBtuDate
NSP-Minnesota899,133 Feb. 11871,921 Jan. 16
NSP-Wisconsin167,656 Feb. 11150,320 Dec. 24
PSCo2,316,283 Feb. 141,931,888 Feb. 4
(a)Reflective of Winter Storm Uri.
  2019 2018
Utility Subsidiary MMBtu Date MMBtu Date
NSP-Minnesota 897,615
(a) 
Feb. 25 786,751
 Jan. 12
NSP-Wisconsin 166,009
(a) 
Jan. 30 159,700
 Jan. 5
PSCo 2,139,420
(a) 
March 3 1,903,878
 Feb. 20
(a)
Increase in maximum MMBtu output due to colder winter temperatures in 2019.

Natural Gas Supply and Cost
Xcel Energy actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio, which provides increasedincrease flexibility, decreaseddecrease interruption, and financial risk,risks and economic customer rates. In addition, the utility subsidiaries conduct natural gas price hedging activities approved by their statestates’ commissions.
Average delivered cost per MMBtu of natural gas for regulated retail distribution:
Utility Subsidiary
2021 (a)
2020
NSP-Minnesota$7.48 $3.32 
NSP-Wisconsin7.11 3.08 
PSCo6.06 2.52 
(a)Reflective of Winter Storm Uri.
Utility Subsidiary 2019 2018
NSP-Minnesota $3.71
 $4.03
NSP-Wisconsin 3.49
 3.84
PSCo 2.95
 3.20
NSP-Minnesota, NSP-Wisconsin and PSCo have natural gas supply transportation and storage agreements that include obligations for purchase and/or delivery of specified volumes or to make payments in lieu of delivery.
See Item 2 - Properties for further information.
General
General Economic Conditions
Economic conditions may have a material impact on Xcel Energy’s operating results. Other events impact overall economic conditions and managementManagement cannot predict the impact of fluctuating energy prices, pandemics, terrorist activity, war or the threat of war. We could experience a material impact to itsour results of operations, future growth or ability to raise capital resulting from a sustained general slowdown in economic growth or a significant increase in interest rates.rates or inflation.
Seasonality
Demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, Xcel Energy’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.
Competition
The CompanyXcel Energy is subject to public policies that promote competition and development of energy markets. Xcel Energy’s industrial and large commercial customers have the ability to generate their own electricity. In addition, customers may have the option of substituting other fuels or relocating their facilities to a lower cost region.
Customers have the opportunity to supply their own power with distributed generation including solar generation and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them.

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Several states have incentives for the development of rooftop solar, community solar gardens and other distributed energy resources. Distributed generating resources are potential competitors to Xcel Energy’s electric service business with these incentives and federal tax subsidies.
The FERC has continued to promote competitive wholesale markets through open access transmission and other means. Xcel Energy’s wholesale customers can purchase their output from generation resources of competing suppliers or non-contracted quantities and use the transmission systems of the utility subsidiaries on a comparable basis to serve their native load.
FERC Order No. 1000 established competition for construction and operationownership of certain new electric transmission facilities. State utilities commissionsfacilities under Federal regulations. Some states have also createdstate 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 planning programs that promote competition for electricity generation resources usedadoption, however implementation is expected to provide service to retail customers.vary by RTO/ISO and the near, medium, and long-term impacts of Order 2222 remain unclear.
Xcel Energy Inc.’s utility subsidiaries have franchise agreements with cities subject to periodic renewal; however, a city could seek alternative means to access electric power or gas, such as municipalization.
While each utility subsidiary faces these challenges, Xcel Energy believes their rates and services are competitive with alternatives currently available.
Governmental Regulations
Public Utility Regulation
See Item 7 for discussion of public utility regulation.
Environmental
Environmental Regulation
Our facilities are regulated by federal and state agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous wastes or substances. Various companyCertain Xcel Energy activities require registrations, permits, licenses, inspections and approvals from these agencies.
Xcel Energy has received necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Our facilities have been designed and constructedstrive to operate in compliance with applicable environmental standards and related monitoring and reporting requirements.
However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to regulations, interpretations or enforcement policies or what effect future laws or regulations may have. We may be required to incur expenditures in the future for remediation of MGP and other sites if it is determined that prior compliance efforts are not sufficient.sites.
In Minnesota, Texas and Wisconsin, Xcel Energy must comply with emission budgetslevels in Minnesota, Texas and Wisconsin that may require the purchase of emission allowances from other utilities.allowances. The Denver North Front Range NonattainmentNon-attainment Area does not meet either the 2008 or 2015 ozone NAAQS. Colorado will continue to consider further reductions available in the non-attainment area as it develops plans to meet ozone standards. GasNatural 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 present/future environmental regulations to encourage use of clean energy technologies and regulate emissions of GHGs. We have undertaken numerous initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. If futureFuture environmental regulations do not take into consideration investments already made or if additional initiatives or emission reductions are required,may result in substantial costs may be incurred.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. The state plans, due toIn 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 in July 2022, will evaluateto 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 potentiallyextent of the EPA’s GHG regulatory authority. If any new rules require heat rate improvements at existing coal-fired plants. It is not yet known how these state plans will affect our existing coal plants, but they could require substantial additional investment, even in plants slated for retirement. Xcel Energy believes based on prior state commission practice,that the cost of these initiatives or replacement generation would be recoverable through rates.
rates based on prior state commission practices.

In October 2020, the TCEQ approved an agreement that SPS will convert the Harrington plant from coal to natural gas by Jan. 1, 2025. This conversion is necessary to attain Federal Clean Air Act standards for emissions of SO2.
In 2019, Xcel Energy estimatesseeks 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 reduced the carbon emissions associated with the electric generating resources, both ownedis uncertain what impact, if any, there will be on our operations, financial condition or cash flows. Xcel Energy will continue to monitor these regulatory developments and under PPAs, used to servetheir potential impact on its customers by approximately 44% from 2005 levels.operations.
Environmental Costs
Environmental costs include accrualsamounts for nuclear plant decommissioning and payments for storage of spent nuclear fuel, disposal of hazardous materials and waste, remediation of contaminated sites, monitoring of discharges to the environment and compliance with laws and permits with respect to emissions.
Costs charged to operating expenses for nuclear decommissioning, spent nuclear fuel disposal, environmental monitoring and remediation and disposal of hazardous materials and waste were approximately:
•
$345million in 2019;
•$335365 million in 2018; and2021.
•$315400 million in 2017.2020.
•$345 million in 2019.
Average annual expense of approximately $400$425 million from 20202022 – 20242026 is estimated for similar costs. The precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are unknown. Additionally, the extent to which environmental costs will be included in and recovered through rates may fluctuate.
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Capital expenditures for environmental improvements were approximately:
•$60 million in 2021.
•$30 million in 2019;2020.
•$5030 million in 2018; and
$60 million in 2017. 2019.
See Item 7 — Capital Requirements for further discussion.
Other
Our operations are subject to workplace safety standards under the Federal Occupational Safety and Health Act of 1970 (“OSHA”) and comparable state laws that regulate the protection of worker health and safety. In addition, the Company is subject to other government regulations impacting such matters as labor, competition, data privacy, etc. Based on information to date and because our policies and business practices are designed to comply with all applicable laws, we do not believe the effects of compliance on our operations, financial condition or cash flows are material.
Capital Spending and Financing
See Item 7 for discussion of capital expenditures and funding sources.
Employees
Executive Officers (a)
As of Dec. 31, 2019, Xcel Energy had 11,273 full-time employees and 44 part-time employees, of which 5,091 were covered under CBAs.
  Employees Covered by CBAs Total Employees
NSP-Minnesota 2,036
 3,203
NSP-Wisconsin 392
 538
PSCo 1,884
 2,369
SPS 779
 1,158
XES —
 4,005
Total 5,091
 11,273
Name
Age(b)
Current and Recent PositionsTime in Position
Information about our Executive Officers (a)
NameRobert C. Frenzel
Age 51(b)
Current and Recent PositionsTime in Position
Ben Fowke (c)
61Chairman of the Board of Directors, Xcel Energy Inc.December 2021 — Present
President and Chief Executive Officer and Director, Xcel Energy Inc.August 20112021 — Present
Chief Executive Officer, NSP-Minnesota, NSP-Wisconsin, PSCo, and SPSJanuary 2015August 2021 — Present
President and Chief Operating Officer, Xcel Energy Inc.March 2020 — August 2021
Executive Vice President, Chief Financial Officer, Xcel Energy Inc.May 2016 — March 2020
Senior Vice President and Chief Financial Officer, Luminant, a subsidiary of Energy Future Holdings Corp.(c)
February 2012 — April 2016
Brett C. Carter (d)
5355Executive Vice President and Chief Customer and Innovation Officer, Xcel Energy Inc.May 2018 — Present
Senior Vice President and Shared Services Executive, Bank of America, an institutional investment bank and financial services companyOctober 2015 — May 2018
Patricia Correa48Senior Vice President, and Chief Operating Officer, Bank of AmericaMarch 2015 — October 2015
Senior Vice President and Chief Distribution Officer, Duke Energy Co., an electric power companyFebruary 2013 — March 2015
Christopher B. Clark53President and Director, NSP-MinnesotaJanuary 2015 — Present
David L. Eves (d)
61Executive Vice President and Group President, Utilities, Xcel Energy Inc.March 2018 — Present
President and Director, PSCoJanuary 2015 — February 2018
Darla Figoli57Senior Vice President, Human Resources & Employee Services, Chief Human Resources Officer, Xcel Energy Inc.May 2018February 2022 — Present
Senior Vice President, Human Resources, and Employee Services, Xcel Energy Inc.Eaton Corporation, a power management companyMay 2015July 2019 — May 2018January 2022
Vice President, Human Resources, Xcel Energy Inc.Eaton CorporationFebruary 2010March 2016 — May 2015July 2019
Robert C. Frenzel (c)
49Senior Director, Talent & Organization Development, Kellogg Company, a food manufacturing companyJuly 2015 — March 2016
Timothy O’Connor62Executive Vice President, Chief FinancialOperations Officer, Xcel Energy Inc.May 2016August 2021 — Present
Senior Vice President and Chief Financial Officer, Luminant, a subsidiary of Energy Future Holdings Corp. (e)
February 2012 — April 2016
David T. Hudson59President and Director, SPSJanuary 2015 — Present
Alice Jackson41President and Director, PSCoMay 2018 — Present
Area Vice President, Strategic Revenue Initiatives, Xcel Energy Services Inc.November 2016 — May 2018
Regional Vice President, Rates and Regulatory Affairs, PSCoNovember 2013 — November 2016
Kent T. Larson (f)
60Executive Vice President, and Group President Operations,Chief Generation Officer, Xcel Energy Inc.January 2015March 2020 — PresentAugust 2021
Timothy O’Connor (g)
60Senior Vice President, Chief Nuclear Officer, Xcel Energy Services Inc.IncFebruary 2013 — PresentMarch 2020
Judy M. PoferlFrank Prager (h)
6059Senior Vice President, Corporate SecretaryStrategy, Planning and Executive Services,External Affairs, Xcel Energy Inc.March 2020 — Present
Vice President, Policy and Federal Affairs, Xcel Energy Services Inc.January 2015 — PresentMarch 2020
Jeffrey S. SavageAmanda Rome4841Senior Vice President, Controller, Xcel Energy Inc.January 2015 — Present
Mark E. Stoering59President and Director, NSP-WisconsinJanuary 2015 — Present
Scott M. Wilensky63Executive Vice President, General Counsel, Xcel Energy Inc.June 2020 — Present
Vice President and Deputy General Counsel, Xcel Energy Services Inc.October 2019 — June 2020
Managing Attorney, Xcel Energy Services Inc.July 2018 — October 2019
Rotational Position, Xcel Energy Services Inc.January 2018 — July 2018
Lead Assistant General Counsel, Xcel Energy Services Inc.July 2015 — January 2018
Jeffrey S. Savage (e)
50Senior Vice President, Controller, Xcel Energy Inc.January 2015 — Present
(a)
No family relationships exist between any of the executive officers or directors.
(b)
Ages as of Dec. 31, 2019.
(c)
Effective March 31, 2020, Mr. Fowke will cease to serve as President and Mr. Frenzel will become President and Chief Operating Officer of Xcel Energy Inc.  At the same time, Brian J. Van Abel will become 40Executive Vice President, Chief Financial Officer, of Xcel Energy Inc.March 2020 — Present
Senior Vice President, Finance and Corporate Development, Xcel Energy Services Inc.September 2018 — March 2020
(d)
Effective May 1, 2020, Mr. Eves will be retiring from the Company after retiring from his executive officer positions effective March 30, 2020.Vice President, Treasurer, Xcel Energy Services Inc.July 2015 — September 2018
(a)No family relationships exist between any of the executive officers or directors.
(b)Ages as of Feb. 23, 2022.
(c)In April 2014, Energy Future Holdings Corp., the majority of its subsidiaries, including Texas Competitive Energy Holdings the parent company of Luminant, filed a voluntary bankruptcy petition under Chapter 11 of the United States Bankruptcy Code. Texas Competitive Energy Holdings emerged from Chapter 11 in October 2016. 
(d)Effective March 1, 2022, Mr. Carter will assume the role of Executive Vice President, Group President, Utilities, and Chief Customer Officer.
(e)Effective March 1, 2022, Mr. Savage will assume the role of Chief Audit and Financial Services Officer and will no longer be serving as an executive officer.

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(e)
In April 2014, Energy Future Holdings Corp., the majority of its subsidiaries, including TCEH the parent company of Luminant, filed a voluntary bankruptcy petition under Chapter 11 of the United States Bankruptcy Code. TCEH emerged from Chapter 11 in October 2016. 
(f)
Effective May 31, 2020, Mr. Larson will be leaving the Company after ceasing to serve in his executive officer positions effective March 30, 2020. 
(g)
Effective March 31, 2020, Mr. O’Connor will become Executive Vice President, Chief Generation Officer.
(h)
Effective March 31, 2020, Ms. Poferl will be retiring from the Company. Frank Prager has been elected to serve with the title of Senior Vice President, Strategy and Planning and External Affairs effective March 1, 2020.

ITEM 1A — RISK FACTORS
Xcel Energy is subject to a variety of risks, many of which are beyond our control. Risks that may adversely affect the business, financial condition, results of operations or cash flows are described below. Although the risks are organized by heading, and each risk is described separately, many of the risks are interrelated. These risks should be carefully considered together with the other information set forth in this report and future reports that we file with the SEC. You should not interpret the disclosure of any risk factor to imply that the risk has not already materialized.
While we believe we have identified and discussed below the key risk factors affecting our business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant that may adversely affect our business, financial condition, results of operations or cash flows in the future.
Oversight of Risk and Related Processes
The Board of Directors is responsible for the oversight of material risk and maintaining an effective risk monitoring process. Management and the Board of Directors’ committees have responsibility for overseeing the identification and mitigation of key risks and reporting its assessments and activities to the full Board of Directors.
Xcel Energy maintains a robust compliance program and promotes a culture of compliance beginning with the tone at the top. The risk mitigation process includes adherence to our code of conduct and compliance policies, operation of formal risk management structures and overall business management. Xcel Energy further mitigates inherent risks through formal risk committees and corporate functions such as internal audit, and internal controls over financial reporting and legal.
Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Identification and risk analysis occurs formally through risk assessment conducted by senior management, the financial disclosure process, hazard risk procedures, internal audit and compliance with financial and operational controls.
Management also identifies and analyzes risk through the business planning process, development of goals and establishment of key performance indicators, including identification of barriers to implementing the Company’sXcel Energy’s strategy. The business planning process also identifies likelihood and mitigating factors to prevent the assumption of inappropriate risk to meet goals.
Management communicates regularly with the Board of Directors and key stakeholders regarding risk. Senior management presents and communicates a periodic risk assessment to the Board of Directors, providing information on the risks that management believes are material, including financial impact, timing, likelihood and mitigating factors. The Board of Directors regularly reviews management’s key risk assessments, which includes areas of existing and future macroeconomic, financial, operational, policy, environmental and security risks.
The oversight, management and mitigation of risk is an integral and continuous part of the Board of Directors’ governance of Xcel Energy. The Board of Directors assigns oversight of critical risks to each of its four committees to ensure these risks are well understood and given appropriate focus.
The Audit Committee is responsible for reviewing the adequacy of the committee’s risk oversight and affirming appropriate aggregate oversight occurs. Committees regularly report on their oversight activities and certain risk issues may be brought to the full Board of Directors for consideration when deemed appropriate.
New risks are considered and assigned as appropriate during the annual Board of Directors and committee evaluation process, resulting in updates to the committee charters and annual work plans. Additionally, the Board of Directors conducts an annual strategy session where Xcel Energy’s future plans and initiatives are reviewed.
Risks Associated with Our Business
Operational Risks
Our natural gas and electric generation/transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.
Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages.
These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses.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.flows as well as potential loss of reputation.
Other uncertainties and risks inherent in operating and maintaining Xcel Energy's facilities include, but are not limited to:
•Risks associated with facility start-up operations, such as whether the facility will achieve projected operating performance on schedule and otherwise as planned.
•Failures in the availability, acquisition or transportation of fuel or other 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.
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Additionally, compliance with existing and potential new regulations related to the operation and maintenance of our natural gas infrastructure could result in significant costs. The PHMSA is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. The PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with these regulations and systematically monitor and renew infrastructure over time, however, a significant incident or material finding of non-compliance could result in penalties and higher costs of operations.
Our natural gas and electric transmission and distribution operations are dependent upon complex information technology systems and network infrastructure, the failure of which could disrupt our normal business operations, which could have a material adverse effect on our ability to process transactions and provide services.
Our utility operations are subject to long-term planning and project risks.
Most electric utility investments are planned to be used for decades. Transmission and generation investments typically have long lead times and are planned well in advance of in-service dates and typically subject to long-term resource plans. These plans are based on numerous assumptions such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. Xcel Energy’s long-term resource plan is dependent on our ability to obtain required approvals, develop necessary technical expertise, allocate and coordinate sufficient resources and adhere to budgets and timelines.
In addition, the long-term nature of both our planning and our asset lives are subject to risk. The electric utility sector is undergoing a period of significant change. For example,change (e.g., increases in energy efficiency, wider adoption of lower cost renewable generation, distributed generation and shifts away from coalfossil fuel generation to decrease carbon emissions and increasing use of natural gas in electric generation driven by lower natural gas prices.renewable generation). Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, as well asand potentially stranded costs if we are not able to fully recover costs and investments.
Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure, which increases exposure to technology obsolescence. Evolving stakeholder preference for lower emission generation sources may pressure our investments in natural gas generation and delivery.

The magnitude and timing of resource additions and changes in customer demand may not coincide whilewith evolving customer preference for resource generation may change,resources and end-uses, which introduces further uncertainty into long-term planning. Additionally, multipleEfforts 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, uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.
Our utilities are highly dependent on suppliers to deliver components in accordance with short and long-term project schedules.
Our products contain components that are globally sourced from suppliers who, in turn, source components from their suppliers. A shortage of key components in which an alternative supplier is not identified could significantly impact 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 in most of our states, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries could impact our cash flows.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, Xcel Energy is unable to fully assure that its risk management programs and procedures would be effective to protect against all significant adverse market deviations.
In addition, Xcel Energy 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, Xcel Energy’s results of operations, financial condition or cash flows could be materially impacted.
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Failure to attract and retain a qualified workforce could have an adverse effect on operations. 
CertainIn 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. The Company’s business strategy is dependent on our abilityassets, which may pose additional difficulty for us as we work to recruit, retain and motivate employees. Competition for skilled employees is high in the areas of business operations.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. We have seen a tightening of supply for engineers and skilled laborers in certain markets and are implementing plans to retain these employees. 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.
Xcel Energy does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. However, it is not always possible to identify and deter misconduct by employees and other third-parties, which may result in governmental investigations, other actions or lawsuits. If such actions are taken against us we may suffer loss of reputation and such actions could have a material effect on our financial condition, results of operations and cash flows.
Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.
NSP-Minnesota has two nuclear generation plants, PI and Monticello. Risks of nuclear generation include:
•Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal;disposal.
•Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor; andreactor.
•Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change.
The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved. Revised NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the Institute for Nuclear Power OperationsINPO reviews NSP-Minnesota’s nuclear operations and nuclear generation facilities.operations. Compliance with the Institute for Nuclear Power Operations’INPO’s recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.
If ana nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota’s compliance costs.
NSP-Wisconsin’s production and transmission system is operated on an integrated basis with NSP-Minnesota and may be subject to risks associated with NSP-Minnesota’s nuclear generation.
Financial Risks
Our profitability depends on the ability of our utility subsidiaries to recover their costs and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers.
We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.
The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and earning a return on capital investment. Our rates are generally regulated and are based on an analysis of the utility’s costs incurred in a test year. The utility subsidiaries are subject to both future and historical test years depending upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. Rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital.
There can also be no assurance that our regulatory commissions will judge all the costs of our utility subsidiaries to be prudent, which could result in disallowances, or that the regulatory process will always result in rates that will produce full recovery.
Overall, management believes prudently incurred costs are recoverable given the existing regulatory framework. However, there may be changes in the regulatory environment that could impair the ability of our utility subsidiaries to recover costs historically collected from customers, or these subsidiaries could exceed caps on capital costs (e.g., wind projects) required by commissions and result in less than full recovery.

Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
In a continued low interest rate environment, there has been increased downward pressure on allowed ROE. Conversely, higherHigher than expected inflation or tariffs may increase costs of construction and operations. Also, rising fuel costs could increase the risk that our utility subsidiaries will not be able to fully recover their fuel costs from their customers.
Adverse regulatory rulings or the imposition of additional regulations could have an adverse impact on our results of operations and materially affect our ability to meet our financial obligations, including debt payments and the payment of dividends on common stock.
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Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.
We cannot be assured that our current credit ratings or our subsidiaries’ 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, significantlyuse 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 andor lower proceeds from equity issuances. It could also impact our ability to access capital markets. Also, our utility subsidiaries may enter into contracts that require posting of collateral or settlement of applicable contracts 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. Capital markets are global and impacted by issues and events throughout the world. 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.rates or lower proceeds from equity issuances. Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results.
The performance of capital markets impacts the value of assets held in trusts to satisfy future obligations to decommission NSP-Minnesota’s nuclear plants and satisfy our defined benefit pension and postretirement benefit plan obligations. These assets are subject to market fluctuations and yield uncertain returns, which may fall below expected returns. A decline in the market value of these assets may increase funding requirements. Additionally, the fair value of the debt securities held in the nuclear decommissioning and/or pension trusts may be impacted by changes in interest rates.
We are subject to credit risks.
Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and local economies in the geographic areas we serve, including local unemployment rates.
Credit risk also includes the risk that various 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.
The CompanyXcel Energy may at times 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, such as CAISO,(e.g., California Independent System Operator, SPP, PJM Interconnection, LLC, MISO and Electric Reliability Council of Texas,Texas), in which any credit losses are socialized to all market participants.
We have additional indirect credit exposure to financial institutions in the form offrom letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.
Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.
We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related toof these plans. Estimates and assumptions may change. In addition, the Pension Protection Act changedsets the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and related contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year, due to high numbers of retirements or employees leaving, would trigger settlement accounting and could require Xcel Energy to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid.
Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future obligations and benefit costs.
Increasing costs associated with health care plans may adversely affect our results of operations.
Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.
We must rely on cash from our subsidiaries to make dividend payments.
Investments in our subsidiaries are our primary assets. Substantially all of our operations are conducted by our subsidiaries. Consequently, our operating cash flow and ability to service our debt and pay dividends depends upon the operating cash flows of our subsidiaries and their payment of dividends.
Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for dividends on our common stock. In addition, each subsidiary’s ability to pay dividends depends on statutory and/or contractual restrictions which may include requirements to maintain minimum levels of equity ratios, working capital or assets.
If the utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected. Our utility subsidiaries are regulated by state utility commissions, which possess broad powers to ensure that the needs of the utility customers are met. We may be negatively impacted by the actions of state commissions that limit the payment of dividends by our utility subsidiaries.

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Federal tax law may significantly impact our business.
Our utility subsidiaries collect through regulated rates estimated federal, state and local tax payments.payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the valuevalue/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. ThereIf tax rates are increased, there could be timing delays before regulated rates provide for realizationrecovery of such tax changesincreases in revenues. In addition, certain IRS tax policies, such as tax normalization, may impact our ability to economically deliver certain types of resources relative to market prices.
Macroeconomic Risks
Economic conditions impact our business.
Xcel Energy’s operations are affected by local, national and worldwide economic conditions, which correlates to customers/sales growth(decline)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.
Our utility subsidiaries face competitive factors, which could have an adverse impact on our financial condition, results of operations and cash flows. Further, worldwide economic activity impacts the demand for basic commodities necessary for utility infrastructure, which may inhibit our ability to acquire sufficient supplies. We operate in a capital intensivecapital-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.
Xcel Energy has experienced and may continue to experience sales volatility and shifts between residential and C&I sales as a result of COVID-19. Xcel Energy has a decoupling mechanism in Colorado for residential and non-demand small C&I electric customer classes. In Minnesota, Xcel Energy has historically had a sales true-up mechanism for all electric customer classes which has ended in 2021. We are requesting implementation of a new sales true-up mechanism for 2022 - 2024. These mechanisms mitigate the impact of changes to sales levels as compared to a baseline.
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.
We also face the risks of possible loss of business due to significant events such as severe storm,storms, severe temperature extremes, wildfires (particularly in Colorado), widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a disruption of work force within our operating systems (or on a neighboring system).workforce disruption.
The recent coronavirus outbreak in China is an example of howIn addition, major catastrophic events throughout the world may disrupt our business. While we are a domestic company, the CompanyXcel Energy participates in a global supply chain, which includes materials and components that are sourced from China.globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to reliably serve our customers.
Disruption due to events such as those noted aboveA 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.
Xcel Energy participates in biennialGridEx, which is the largest grid security and emergency response exercises (GridEx).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, shareholders and other individuals.
The Company’sXcel Energy’s generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error.
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The utility industry has been the target of several attacks on operational systems and has seen an increased volume and sophistication of cyber security incidents from international activist organizations, 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.
Xcel Energy’s generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident 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 and new interpretations of existing lawsmay create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. Such regulationsInternational agreements could impose substantial costs.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.
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.
Although the United States has not adopted any international or federal GHG emission reduction targets, many states and localities may continue to pursue climate policies in the absence of federal mandates. 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. While those actions likely would have put Xcel Energy in a good position to meet federal or international standards being discussed, the lack of federal action does not adversely impact these state-endorsed actions and plans.
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 have become more active in pursuingmay pursue penalties. CertainIn addition, certain states additionally 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.
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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. Environmental regulations may also lead to shutdown of existing facilities. 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 (i.e., clean-up) 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 the 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 a region’sthe 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.
While we carry liability insurance, given an extreme event, if Xcel Energy was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows.
Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of unitspower plants and increase the price paidcost 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.
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ITEM 2 — PROPERTIES
Virtually all of the utility plant property of the operating companies is subject to the lien of their respective first mortgage bond indentures.
NSP-Minnesota
Station, Location and Unit at Dec. 31, 2021
FuelInstalled
MW (a)
Steam:
A.S. King-Bayport, MN, 1 Unit (f)
Coal1968511 
Sherco-Becker, MN (e)
Unit 1Coal1976680 
Unit 2Coal1977682 
Unit 3Coal1987517 (b)
Monticello, MN, 1 UnitNuclear1971617 
PI-Welch, MN
Unit 1Nuclear1973521 
Unit 2Nuclear1974519 
Various locations, 4 UnitsWood/RefuseVarious36 (c)
Combustion Turbine:
Angus Anson-Sioux Falls, SD, 3 UnitsNatural Gas1994 - 2005327 
Black Dog-Burnsville, MN, 3 UnitsNatural Gas1987 - 2018494 
Blue Lake-Shakopee, MN, 6 UnitsNatural Gas1974 - 2005447 
High Bridge-St. Paul, MN, 3 UnitsNatural Gas2008530 
Inver Hills-Inver Grove Heights, MN, 6 UnitsNatural Gas1972252 
Riverside-Minneapolis, MN, 3 UnitsNatural Gas2009454 
Various locations, 7 UnitsNatural GasVarious10 
Wind:
Blazing Star 1-Lincoln County, MN, 100 UnitsWind2020200 (d)
Blazing Star 2-Lincoln County, MN, 100 UnitsWind2021200 (d)
Border-Rolette County, ND, 75 UnitsWind2015148 (d)
Community Wind North-Lincoln County, MN, 12 UnitsWind202026 (d)
Courtenay Wind-Stutsman County, ND, 100 UnitsWind2016190 (d)
Crowned Ridge 2-Grant County, SD, 88 UnitsWind2020192 (d)
Foxtail-Dickey County, ND, 75 UnitsWind2019150 (d)
Freeborn-Freeborn County, MN, 100 UnitsWind2021200 (d)
Grand Meadow-Mower County, MN, 67 UnitsWind200899 (d)
Jeffers-Cottonwood County, MN, 20 UnitsWind202043 (d)
Lake Benton-Pipestone County, MN, 44 UnitsWind201999 (d)
Mower-Mower County, MN, 43 UnitsWind202191 (d)
Nobles-Nobles County, MN, 134 UnitsWind2010197 (d)
Pleasant Valley-Mower County, MN, 100 UnitsWind2015196 (d)
Total8,628 
(a)Summer 2021 net dependable capacity.
(b)Based on NSP-Minnesota’s ownership of 59%.
(c)Refuse-derived fuel is made from municipal solid waste.
(d)Values disclosed are the generation levels at the point-of-interconnection for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
(e)A.S. King is expected to be retired early in 2028.
(f)Sherco Unit 1, 2, and 3 are expected to be retired early in 2026, 2023 and 2030, respectively.
NSP-Minnesota
Station, Location and Unit
 Fuel Installed 
MW (a)
 
Steam:       
A.S. King-Bayport, MN, 1 Unit Coal 1968 511
 
Sherco-Becker, MN       
Unit 1 Coal 1976 680
 
Unit 2 Coal 1977 682
 
Unit 3 Coal 1987 517
(b) 
Monticello, MN, 1 Unit Nuclear 1971 617
 
PI-Welch, MN       
Unit 1 Nuclear 1973 521
 
Unit 2 Nuclear 1974 519
 
Various locations, 4 Units Wood/Refuse Various 36
(c) 
Combustion Turbine:       
Angus Anson-Sioux Falls, SD, 3 Units Natural Gas 1994 - 2005 327
 
Black Dog-Burnsville, MN, 3 Units Natural Gas 1987 - 2018 494
 
Blue Lake-Shakopee, MN, 6 Units Natural Gas 1974 - 2005 453
 
High Bridge-St. Paul, MN, 3 Units Natural Gas 2008 530
 
Inver Hills-Inver Grove Heights, MN, 6 Units Natural Gas 1972 282
 
Riverside-Minneapolis, MN, 3 Units Natural Gas 2009 454
 
Various locations, 7 Units Natural Gas Various 10
 
Wind:       
Border-Rolette County, ND, 75 Units Wind 2015 148
(d) 
Courtenay Wind-Stutsman County, ND, 100 Units Wind 2016 190
(d) 
Foxtail-Dickey County, ND, 75 Units Wind 2019 150
(d) 
Grand Meadow-Mower County, MN, 67 Units Wind 2008 99
(d) 
Lake Benton-Pipestone County, MN, 44 Units Wind 2019 99
(d) 
Nobles-Nobles County, MN, 134 Units Wind 2010 197
(d) 
Pleasant Valley-Mower County, MN, 100 Units Wind 2015 196
(d) 
    Total 7,712
 
(a)
Summer 2019 net dependable capacity.
(b)
Based on NSP-Minnesota’s ownership of 59%.
(c)
Refuse-derived fuel is made from municipal solid waste.
(d)
Values disclosed are the maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
NSP-Wisconsin
Station, Location and Unit at Dec. 31, 2021
FuelInstalled
MW (a)
Steam:
Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 
French Island-La Crosse, WI, 2 UnitsWood/Refuse1940 - 194816 (b)
Combustion Turbine:
French Island-La Crosse, WI, 2 UnitsOil1974122 
Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973234 
Hydro:
Various locations, 63 UnitsHydroVarious135 
Total548 
(a)Summer 2021 net dependable capacity.
(b)Refuse-derived fuel is made from municipal solid waste.
PSCo
Station, Location and Unit at Dec. 31, 2021
FuelInstalled
MW (a)
Steam:
Comanche-Pueblo, CO (b)
Unit 1Coal1973325 
Unit 2Coal1975335 
Unit 3Coal2010500 (c)
Craig-Craig, CO, 2 Units (d)
Coal1979 - 198082 (e)
Hayden-Hayden, CO, 2 Units
Coal1965 - 1976233 (f)
Pawnee-Brush, CO, 1 UnitCoal1981505 
Cherokee-Denver, CO, 1 UnitNatural Gas1968310 
Combustion Turbine:
Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 
Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 
Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 2009973 
Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004580 
Various locations, 8 UnitsNatural GasVarious251 
Hydro:
Cabin Creek-Georgetown, CO
Pumped Storage, 2 UnitsHydro1967210 
Various locations, 8 UnitsHydroVarious25 
Wind:
Rush Creek, CO, 300 unitsWind2018582 (g)
Cheyenne Ridge, CO, 229 unitsWind2020477 (g)
Total6,228 
(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).
NSP-Wisconsin
Station, Location and Unit
 Fuel Installed 
MW (a)
 
Steam:       
Bay Front-Ashland, WI, 2 Units Coal/Wood/Natural Gas 1948 - 1956 41
 
French Island-La Crosse, WI, 2 Units Wood/Refuse 1940 - 1948 16
(b) 
Combustion Turbine:       
French Island-La Crosse, WI, 2 Units Oil 1974 122
 
Wheaton-Eau Claire, WI, 5 Units Natural Gas/Oil 1973 234
 
Hydro:       
Various locations, 63 Units Hydro Various 135
 
    Total 548
 
24
(a)
Summer 2019 net dependable capacity.
(b)
Refuse-derived fuel is made from municipal solid waste.
PSCo
Station, Location and Unit
 Fuel Installed 
MW (a)
 
Steam:       
Comanche-Pueblo, CO (b)
       
Unit 1 Coal 1973 325
 
Unit 2 Coal 1975 335
 
Unit 3 Coal 2010 500
(c) 
Craig-Craig, CO, 2 Units (d)
 Coal 1979 - 1980 82
(e) 
Hayden-Hayden, CO, 2 Units Coal 1965 - 1976 233
(f) 
Pawnee-Brush, CO, 1 Unit Coal 1981 505
 
Cherokee-Denver, CO, 1 Unit Natural Gas 1968 310
 
Combustion Turbine:       
Blue Spruce-Aurora, CO, 2 Units Natural Gas 2003 264
 
Cherokee-Denver, CO, 3 Units Natural Gas 2015 576
 
Fort St. Vrain-Platteville, CO, 6 Units Natural Gas 1972 - 2009 968
 
Rocky Mountain-Keenesburg, CO, 3 Units Natural Gas 2004 580
 
Various locations, 6 Units Natural Gas Various 171
 
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) 
    Total 5,666
 
(a)
Summer 2019 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 is expected to be retired early in 2025.
(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 maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).

SPS
Station, Location and Unit at Dec. 31, 2021
FuelInstalled
MW (a)
Steam:
Cunningham-Hobbs, NM, 2 UnitsNatural Gas1957 - 1965225 
Harrington-Amarillo, TX, 3 Units (b)
Coal1976 - 19801,018 
Jones-Lubbock, TX, 2 UnitsNatural Gas1971 - 1974486 
Maddox-Hobbs, NM, 1 UnitNatural Gas1967112 
Nichols-Amarillo, TX, 3 UnitsNatural Gas1960 - 1968457 
Plant X-Earth, TX, 4 UnitsNatural Gas1952 - 1964298 
Tolk-Muleshoe, TX, 2 Units (d)
Coal1982 - 19851,067 
Combustion Turbine:
Cunningham-Hobbs, NM, 2 UnitsNatural Gas1997207 
Jones-Lubbock, TX, 2 UnitsNatural Gas2011 - 2013334 
Maddox-Hobbs, NM, 1 UnitNatural Gas1963 - 197661 
Wind:
Hale-Plainview, TX, 239 UnitsWind2019477 (c)
Sagamore-Dora, NM, 240 UnitsWind2020507 (c)
Total5,249 
SPS
Station, Location and Unit
 Fuel Installed 
MW (a)
 
Steam:       
Cunningham-Hobbs, NM, 2 Units Natural Gas 1957 - 1965 189
 
Harrington-Amarillo, TX, 3 Units Coal 1976 - 1980 1,018
 
Jones-Lubbock, TX, 2 Units Natural Gas 1971 - 1974 486
 
Maddox-Hobbs, NM, 1 Unit Natural Gas 1967 112
 
Nichols-Amarillo, TX, 3 Units Natural Gas 1960 - 1968 457
 
Plant X-Earth, TX, 4 Units Natural Gas 1952 - 1964 411
 
Tolk-Muleshoe, TX, 2 Units Coal 1982 - 1985 1,067
 
Combustion Turbine:       
Cunningham-Hobbs, NM, 2 Units Natural Gas 1997 209
 
Jones-Lubbock, TX, 2 Units Natural Gas 2011 - 2013 334
 
Maddox-Hobbs, NM, 1 Unit Natural Gas 1963 - 1976 61
 
Wind:       
Hale-Plainview, TX, 239 Units Wind 2019 460
(b) 
    Total 4,804
 
(a)    Summer 2021 net dependable capacity.
(b)    Harrington is expected to be converted to natural gas by the end of 2024.
(c)     Values disclosed are the generation levels at the point-of-interconnection for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
(d)    Tolk Unit 1 and 2 are proposed to be retired in 2034.
(a)
Summer 2019 net dependable capacity.
(b)
Values disclosed are the maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
Electric utility overhead and underground transmissiontransmission and distribution lines (measured in conductor miles) at Dec. 31, 2019:2021:
Conductor Miles NSP-Minnesota NSP-Wisconsin PSCo SPSConductor MilesNSP-MinnesotaNSP-WisconsinPSCoSPS
TransmissionTransmission
500 KV 2,917
 —
 —
 —
500 KV2,915 — — — 
345 KV 13,133
 3,337
 5,036
 9,566
345 KV13,570 2,943 4,978 11,688 
230 KV 2,203
 —
 12,108
 9,784
230 KV2,300 — 12,141 9,763 
161 KV 673
 1,821
 —
 —
161 KV640 1,778 — — 
138 KV —
 —
 92
 —
138 KV— — 92 — 
115 KV 8,045
 1,815
 5,055
 14,662
115 KV8,086 1,818 5,075 14,880 
Less than 115 KV 86,743
 32,816
 79,740
 26,216
Less than 115 KV6,644 5,870 1,830 4,423 
Total TransmissionTotal Transmission34,155 12,409 24,116 40,754 
DistributionDistribution
Less than 115 KVLess than 115 KV81,406 27,701 78,712 22,651 
TotalTotal115,561 40,110 102,828 63,405 
Electric utility transmission and distribution substations at Dec. 31, 2019:2021:
NSP-MinnesotaNSP-WisconsinPSCoSPS
Quantity354 204 237 458 
  NSP-Minnesota NSP-Wisconsin PSCo SPS
Quantity 346
 204
 233
 452
Natural gas utility mains at Dec. 31, 2019:2021:
MilesNSP-MinnesotaNSP-WisconsinPSCoSPSWGI
Transmission85 3 2,174 20 11 
Distribution10,741 2,526 23,243 — — 





Miles NSP-Minnesota NSP-Wisconsin PSCo SPS WGI
Transmission 86
 3
 2,057
 20
 11
Distribution 10,518
 2,473
 22,633
 —
 —
ITEM 3 — LEGAL PROCEEDINGS
Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation.
Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s consolidated financial statements. Unless otherwise required by GAAP, legalLegal fees are generally expensed as incurred.
See Note 12 to the consolidated financial statements, Item 1 and Item 7 for further information.
ITEM 4 — MINE SAFETY DISCLOSURES
None.
PART II
ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Stock Data
Xcel Energy Inc.’s common stock wasis listed on the New York Stock Exchange (NYSE) in 2017, but moved to the Nasdaq Global Select Market (Nasdaq) in 2018.. The trading symbol is XEL. The number of common stockholders of record as of Feb. 19, 202017, 2022 was approximately 54,543.49,137.
The following compares our cumulative TSR on common stock with the cumulative TSR of the EEI Investor-Owned Electrics Index and the Standard & Poor’sS&P 500 Composite Stock Price Index over the last five years.
The EEI Investor-Owned Electrics Index (market capitalization-weighted) included 4039 companies at year-end and is a broad measure of industry performance.
Comparison of Five Year Cumulative Total Return*
fiveyearreturn.jpg
*$100 invested on Dec. 31, 2014 in stock or index — including reinvestment of dividends. Fiscal years ended Dec. 31.
Securities Authorized for Issuance Under Equity Compensation Plansxel-20211231_g30.jpg
Information required under Item 5*    $100 invested on Dec. 31, 2016 in stock or index — Securities Authorized for Issuance under Equity Compensation Plans is contained in Xcel Energy’s Proxy Statement for its 2020 Annual Meetingincluding reinvestment of Shareholders, which is incorporated by reference.dividends. Fiscal years ended Dec. 31.
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Purchases of Equity Securities by Issuer and Affiliated Purchasers
For the quarter ended Dec. 31, 2019,2021, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers.


ITEM 6 — SELECTED FINANCIAL DATA[RESERVED]
Selected financial data for Xcel Energy related to the five most recent years ended Dec. 31:    
(Millions of Dollars, Millions of Shares, Except Per Share Data) 2019 2018 2017 2016 2015
Operating revenues $11,529
 $11,537
 $11,404
 $11,107
 $11,024
Operating expenses (a)
 9,425
 9,572
 9,181
 8,867
 9,024
Net income 1,372
 1,261
 1,148
 1,123
 984
Earnings available to common shareholders 1,372
 1,261
 1,148
 1,123
 984
Diluted earnings per common share 2.64
 2.47
 2.25
 2.21
 1.94
Financial information          
Dividends declared per common share 1.62
 1.52
 1.44
 1.36
 1.28
Total assets (b) (c)
 50,448
 45,987
 43,030
 41,155
 38,821
Long-term debt (c) (d)
 17,407
 15,803
 14,520
 14,195
 12,399
(a)
As a result of adopting ASU No. 2017-07 (Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715), $33 million and $26 million of pension costs were retrospectively reclassified from O&M expenses to other income, net on the consolidated statements of income for the years ended Dec. 31, 2017 and Dec. 31, 2016, respectively.
(b)
As a result of adopting ASU No. 2015-17 (Balance Sheet Classification of Deferred Taxes, Topic 740), $140 million of current deferred income taxes was retrospectively reclassified to long-term deferred income tax liabilities on the consolidated balance sheet as of Dec. 31, 2015.
(c)
As a result of adopting ASU No. 2015-03 (Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30), $92 million of deferred debt issuance costs was retrospectively reclassified from other noncurrent assets to long-term debt on the consolidated balance sheet as of Dec. 31, 2015.
(d)
As a result of adopting Leases, Topic 842, finance lease obligations of $77 million are included in other noncurrent liabilities on the consolidated balance sheet at Dec. 31, 2019. These obligations were included in long-term debt prior to 2019.
ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing ROE, electric margin, natural gas margin, ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from measures calculated and presented in accordance with GAAP.
Xcel Energy’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.
Ongoing ROE
Ongoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity’s average stockholder’s equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results.
Electric and Natural Gas Margins
Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for electric fuel and purchased power and the cost of natural gas are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues. Management believes electric and natural gas margins provide the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses.
These margins can be reconciled to operating income, a GAAP measure, by including other operating revenues, cost of sales-other, O&M expenses, conservation and DSM expenses, depreciation and amortization and taxes (other than income taxes).
Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)
GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.
We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. For the years ended Dec. 31, 20192021 and Dec. 31, 2018,2020, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.



Results of Operations
Diluted EPS for Xcel Energy at Dec. 31:
20212020
Diluted Earnings (Loss) Per ShareGAAP and Ongoing Diluted EPSGAAP and Ongoing Diluted EPS
PSCo$1.22 $1.11 
NSP-Minnesota1.12 1.12 
SPS0.59 0.56 
NSP-Wisconsin0.20 0.20 
Earnings from equity method investments — WYCO0.05 0.05 
Regulated utility (a)
3.18 3.04 
Xcel Energy Inc. and Other(0.22)(0.25)
Total (a)
$2.96 $2.79 
  2019 2018
Diluted Earnings (Loss) Per Share GAAP and Ongoing Diluted EPS GAAP and Ongoing Diluted EPS
PSCo $1.11
 $1.08
NSP-Minnesota 1.04
 0.96
SPS 0.51
 0.42
NSP-Wisconsin 0.15
 0.19
Equity earnings of unconsolidated subsidiaries (a)
 0.05
 0.04
Regulated utility (b)
 2.86
 2.69
Xcel Energy Inc. and other (0.22) (0.22)
Total (b)
 $2.64
 $2.47
(a)(a)    Amounts may not add due to rounding.
Includes income taxes.
(b)
Amounts may not add due to rounding.
Xcel Energy’s management believes that ongoing earnings reflects management’s performance in operating the CompanyXcel Energy and provides a meaningful representation of the performance of Xcel Energy’s core business. In addition, Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors.
20192021 Comparison with 20182020
Xcel Energy — GAAP and ongoing earnings increased $0.17 per share.share for 2021. The increase was driven by capital investment recovery and other regulatory outcomes, partially offset by increases in depreciation and lower AFUDC. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in revenues are offset by the related variation in costs).
PSCo — Earnings increased as a result of higher electric margins primarily due to non-fuel riders$0.11 per share for 2021, driven by capital investment recovery and other regulatory rate outcomes, higher natural gas margins and loweroutcomes. Higher revenues were partially offset by increased depreciation, O&M expenses primarilyand other taxes (other than income taxes).
NSP-Minnesota — Earnings were flat for 2021 compared to 2020, reflecting capital investment recovery offset by lower AFUDC, increasedadditional depreciation and interest expenses.charges.
utilitysub2019gaapeps.jpg
PSCoSPS — Earnings increased $0.03 per share for 2019, reflecting higher electric margin due primarily2021, largely related to capital ridersinvestment recovery, other regulatory outcomes and increased natural gas margin attributable to capital riders, weatherhigher sales and sales growth,demand, partially offset by lower AFUDC driven by the Rush Creek wind project that was placed in service in 2018 and higher depreciation, interest and O&M.
NSP-Minnesota — Earnings increased $0.08 per share for 2019, reflecting higher electric margin resulting from regulatory rate outcomes and capital riders and lower O&M, partially offset by increased depreciation.
SPS — Earnings increased $0.09 per share, reflecting higher electric margin attributable to purchased capacity costs, regulatory rate outcomes and demand revenue and higher AFUDC, partially offset by increased interest and depreciation.decreased AFUDC.
NSP-Wisconsin — Earnings decreased $0.04 per share, reflecting lower electric margin, primarily relatedwere flat for 2021 compared to sales decline and the impact of unfavorable weather, higher depreciation and lower AFUDC.2020.
Xcel Energy Inc. and otherOther — Xcel Energy Inc. and other primarilyPrimarily includes financing costs at the holding company.company, offset by earnings from EIP investments.
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Changes in Diluted EPS
Components significantly contributing to changes in EPS:
2019 vs. 2018
   
Diluted Earnings (Loss) Per Share Dec. 31
GAAP and ongoing diluted EPS - 2018 $2.47
   
Components of change — 2019 vs. 2018  
Higher electric margins 0.29
Lower ETR (a)
 0.15
Higher natural gas margins 0.08
Lower O&M 0.02
Higher depreciation and amortization (0.18)
Higher interest (0.11)
Lower AFUDC (0.08)
GAAP and ongoing diluted EPS — 2019 $2.64
2021 vs. 2020
Diluted Earnings (Loss) Per ShareDec. 31
GAAP and ongoing diluted EPS — 2020$2.79
Components of change — 2021 vs. 2020
Higher electric revenues, net of electric fuel and purchased power0.26 
Lower ETR (a)
Includes PTCs0.17 
Higher natural gas revenues, net of cost of natural gas sold and timing of tax reform regulatory decisions, which are primarily offsettransported0.15 
Changes in electric margin.taxes (other than income taxes)(0.03)
Lower AFUDC(0.10)
Higher depreciation and amortization(0.24)
Other (net)(0.04)
GAAP and ongoing diluted EPS — 2021$2.96
(a)Includes PTCs and plant regulatory amounts, which are primarily offset as a reduction to electric revenues.
ROE for Xcel Energy and its utility subsidiaries at Dec. 31:subsidiaries:
 2019 201820212020
ROE GAAP and Ongoing ROE GAAP and Ongoing ROEROEGAAP and Ongoing ROEGAAP and Ongoing ROE
NSP-MinnesotaNSP-Minnesota8.45 %9.20 %
PSCo 8.69% 9.10%PSCo8.23 8.06 
NSP-Minnesota 9.31
 8.91
SPS 9.71
 9.14
SPS9.22 9.54 
NSP-Wisconsin 8.27
 10.77
NSP-Wisconsin9.92 10.52 
Operating Companies 9.06
 9.14
Operating Companies8.58 8.87 
Xcel Energy 10.78
 10.65
Xcel Energy10.58 10.59 
Statement of Income Analysis
The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.
Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. However, sales true-up and decoupling mechanisms in Minnesota and Colorado predominately mitigate the positive and adverse impacts of weather.
Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather.

Normal weather conditions are defined as either the 20-year10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates.
Percentage (decrease) increase (decrease) in normal and actual HDD, CDD and THI:
2019 vs.
Normal		 2018 vs.
Normal		 2019 vs.
2018		2021 vs.
Normal		2020 vs.
Normal		2021 vs. 2020
HDD10.4 % 2.2% 6.8 %HDD(6.6)%(3.1)%(4.3)%
CDD5.4
 26.7
 (15.5)CDD12.2 22.2 (9.2)
THI(8.8) 37.3
 (33.2)THI26.8 6.3 20.7 
Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:
 2019 vs.
Normal		 2018 vs.
Normal		 2019 vs.
2018
Retail electric$0.040
 $0.114
 $(0.074)
Firm natural gas0.027
 0.007
 0.020
Total (excluding decoupling)$0.067
 $0.121
 $(0.054)
Decoupling — Minnesota electric—
 (0.051) 0.051
Total (adjusted for recovery from decoupling)$0.067
 $0.070
 $(0.003)
2021 vs.
Normal		2020 vs.
Normal		2021 vs. 2020
Retail electric$0.096 $0.090 $0.006 
Decoupling and sales true-up(0.066)(0.041)(0.025)
Electric total$0.030 $0.049 $(0.019)
Firm natural gas(0.025)(0.011)(0.014)
Total$0.005 $0.038 $(0.033)
Sales Growth(Decline)— Sales growth (decline) for actual and weather-normalized sales:
2021 vs. 2020
PSCoNSP-MinnesotaSPSNSP-WisconsinXcel Energy
Actual
Electric residential— %2.2 %(4.7)%0.5 %0.3 %
Electric C&I0.4 2.3 2.9 3.6 2.0 
Total retail electric sales0.3 2.2 1.4 2.7 1.4 
Firm natural gas sales(1.1)(4.0)N/A(5.0)(2.2)
2021 vs. 2020
PSCoNSP-MinnesotaSPSNSP-WisconsinXcel Energy
Weather-normalized
Electric residential1.5 %0.3 %(1.0)%(0.2)%0.5 %
Electric C&I0.4 1.7 3.3 3.3 1.9 
Total retail electric sales0.8 1.2 2.5 2.2 1.4 
Firm natural gas sales1.3 (2.2)N/A(4.1)(0.1)
2021 vs. 2020 (2020 Leap Year Adjusted)
PSCoNSP-MinnesotaSPSNSP-WisconsinXcel Energy
Weather-normalized
Electric residential1.7 %0.6 %(0.7)%0.1 %0.8 %
Electric C&I0.7 1.9 3.6 3.6 2.1 
Total retail electric sales1.1 1.5 2.7 2.5 1.7 
Firm natural gas sales1.8 (1.7)N/A(3.6)0.4 

  2019 vs. 2018
  PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Actual          
Electric residential 0.1 % (3.5)% 0.3% (1.8)% (1.5)%
Electric C&I (0.6) (4.0) 3.5
 (3.2) (1.1)
Total retail electric sales (0.3) (3.9) 2.8
 (2.8) (1.2)
Firm natural gas sales 12.9
 3.6
 N/A
 (2.0) 8.8
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  2019 vs. 2018
  PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-normalized        
Electric residential (0.1)% 0.1 % 1.9% 1.1 % 0.4 %
Electric C&I (0.6) (3.0) 3.8
 (2.6) (0.5)
Total retail electric sales (0.3) (2.1) 3.4
 (1.6) (0.3)
Firm natural gas sales 4.1
 1.1
 N/A
 (2.5) 2.7
Weather-normalized 2019 Electric Sales Growth (Decline)and leap-year adjusted electric sales growth (decline) — year-to-date
Weather-adjusted sales results for each of our utility subsidiaries in 2021 reflect improving economies as the adverse effects of COVID-19 lessen. The recovery reflects increased sales in the C&I sector as businesses return to a more normal level. Residential sales remain elevated from pre-pandemic levels due to continuance of individuals working from home.
•PSCo — Residential sales declinedrose based on a 1.2% increase in customers, combined with higher use per customer. The growth in C&I sales was due to lower use per customer,a 1.2% increase in customers, partially offset by an increased number of customers. The decline in C&I was mainly due toslightly lower use per customer, primarily led by customers in the food products and service industries,services sector.
•NSP-Minnesota — Residential sales growth reflects a 1.2% increase in customers, partially offset by growth in the metal mining and fabricated metal and industries. The decrease in customer use was partially offset by an increase in the number of C&I customers;
NSP-Minnesota — Flat residential sales reflecta lower use per customer offset by customer additions.customer. The declinegrowth in C&I sales was a result of customer growth being offset by lower use per customer, and certain customers moving to co-generation. Decreased sales to C&I customers were driven by the energy and manufacturing sectors;
SPS — Residential sales grew largely due to ana 0.9% increase in customers and higher use per customer.customer, primarily in the manufacturing, retail and services sectors.
•SPS — Residential sales declined as lower use per customer offset a 0.9% increase in customers. C&I sales grew based onincreased due to a 0.5% increase in customers and higher use per small C&I customer, and an overall increase in the number of C&I customers. In addition, the increase in C&I sales wasprimarily driven by the oil and natural gas industry in the Southeastern New Mexico, Permian Basin area; and professional services sectors.
•NSP-Wisconsin — Residential sales growth was primarily attributable to a 0.8% increase in customer additions, and morepartially offset by slightly lower use per customer. The declinegrowth in C&I sales was largely due to lower use per customera 1.1% increase in customers, primarily led by increases in the manufacturing, health care and decreased sales to the frac sand mining, food and manufacturing sectors, which was partially offset by customer additions.retail trade sectors.
Weather-normalized 2019 Natural Gas Sales Growth
Overalland leap-year adjusted natural gas sales growth (decline) — year-to-date
•Natural gas sales primarily reflect ana 1.2% increase in the number ofresidential customers combined with higher customer use, particularlyand a 0.5% increase in C&I at PSCo. This wascustomers, partially offset by a declinedecrease in C&I sales at NSP-Wisconsin, driven by the frac sand mining industry.use per customer.
Weather-normalized sales for 2020 are projected to increase ~1% over 2019 levels for retail electric and natural gas customers, including the impact of leap year.
Electric MarginNSP-Minnesota
Station, Location and Unit at Dec. 31, 2021
FuelInstalled
MW (a)
Steam:
A.S. King-Bayport, MN, 1 Unit(f)
Coal1968511 
Sherco-Becker, MN(e)
Unit 1Coal1976680 Unit 2Coal1977682 Unit 3Coal1987517 (b)Monticello, MN, 1 UnitNuclear1971617 PI-Welch, MNUnit 1Nuclear1973521 Unit 2Nuclear1974519 Various locations, 4 UnitsWood/RefuseVarious36 (c)Combustion Turbine:Angus Anson-Sioux Falls, SD, 3 UnitsNatural Gas1994 - 2005327 Black Dog-Burnsville, MN, 3 UnitsNatural Gas1987 - 2018494 Blue Lake-Shakopee, MN, 6 UnitsNatural Gas1974 - 2005447 High Bridge-St. Paul, MN, 3 UnitsNatural Gas2008530 Inver Hills-Inver Grove Heights, MN, 6 UnitsNatural Gas1972252 Riverside-Minneapolis, MN, 3 UnitsNatural Gas2009454 Various locations, 7 UnitsNatural GasVarious10 Wind:Blazing Star 1-Lincoln County, MN, 100 UnitsWind2020200 (d)Blazing Star 2-Lincoln County, MN, 100 UnitsWind2021200 (d)Border-Rolette County, ND, 75 UnitsWind2015148 (d)Community Wind North-Lincoln County, MN, 12 UnitsWind202026 (d)Courtenay Wind-Stutsman County, ND, 100 UnitsWind2016190 (d)Crowned Ridge 2-Grant County, SD, 88 UnitsWind2020192 (d)Foxtail-Dickey County, ND, 75 UnitsWind2019150 (d)Freeborn-Freeborn County, MN, 100 UnitsWind2021200 (d)Grand Meadow-Mower County, MN, 67 UnitsWind200899 (d)Jeffers-Cottonwood County, MN, 20 UnitsWind202043 (d)Lake Benton-Pipestone County, MN, 44 UnitsWind201999 (d)Mower-Mower County, MN, 43 UnitsWind202191 (d)Nobles-Nobles County, MN, 134 UnitsWind2010197 (d)Pleasant Valley-Mower County, MN, 100 UnitsWind2015196 (d)Total8,628 
(a)Summer 2021 net dependable capacity.
(b)Based on NSP-Minnesota’s ownership of 59%.
(c)Refuse-derived fuel is made from municipal solid waste.
(d)Values disclosed are the generation levels at the point-of-interconnection for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
(e)A.S. King is expected to be retired early in 2028.
(f)Sherco Unit 1, 2, and 3 are expected to be retired early in 2026, 2023 and 2030, respectively.
NSP-Wisconsin
Station, Location and Unit at Dec. 31, 2021
FuelInstalled
MW (a)
Steam:
Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 
French Island-La Crosse, WI, 2 UnitsWood/Refuse1940 - 194816 (b)
Combustion Turbine:
French Island-La Crosse, WI, 2 UnitsOil1974122 
Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973234 
Hydro:
Various locations, 63 UnitsHydroVarious135 
Total548 
(a)Summer 2021 net dependable capacity.
(b)Refuse-derived fuel is made from municipal solid waste.
PSCo
Station, Location and Unit at Dec. 31, 2021
FuelInstalled
MW (a)
Steam:
Comanche-Pueblo, CO (b)
Unit 1Coal1973325 
Unit 2Coal1975335 
Unit 3Coal2010500 (c)
Craig-Craig, CO, 2 Units (d)
Coal1979 - 198082 (e)
Hayden-Hayden, CO, 2 Units
Coal1965 - 1976233 (f)
Pawnee-Brush, CO, 1 UnitCoal1981505 
Cherokee-Denver, CO, 1 UnitNatural Gas1968310 
Combustion Turbine:
Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 
Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 
Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 2009973 
Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004580 
Various locations, 8 UnitsNatural GasVarious251 
Hydro:
Cabin Creek-Georgetown, CO
Pumped Storage, 2 UnitsHydro1967210 
Various locations, 8 UnitsHydroVarious25 
Wind:
Rush Creek, CO, 300 unitsWind2018582 (g)
Cheyenne Ridge, CO, 229 unitsWind2020477 (g)
Total6,228 
(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).
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SPS
Station, Location and Unit at Dec. 31, 2021
FuelInstalled
MW (a)
Steam:
Cunningham-Hobbs, NM, 2 UnitsNatural Gas1957 - 1965225 
Harrington-Amarillo, TX, 3 Units (b)
Coal1976 - 19801,018 
Jones-Lubbock, TX, 2 UnitsNatural Gas1971 - 1974486 
Maddox-Hobbs, NM, 1 UnitNatural Gas1967112 
Nichols-Amarillo, TX, 3 UnitsNatural Gas1960 - 1968457 
Plant X-Earth, TX, 4 UnitsNatural Gas1952 - 1964298 
Tolk-Muleshoe, TX, 2 Units (d)
Coal1982 - 19851,067 
Combustion Turbine:
Cunningham-Hobbs, NM, 2 UnitsNatural Gas1997207 
Jones-Lubbock, TX, 2 UnitsNatural Gas2011 - 2013334 
Maddox-Hobbs, NM, 1 UnitNatural Gas1963 - 197661 
Wind:
Hale-Plainview, TX, 239 UnitsWind2019477 (c)
Sagamore-Dora, NM, 240 UnitsWind2020507 (c)
Total5,249 
(a)    Summer 2021 net dependable capacity.
(b)    Harrington is expected to be converted to natural gas by the end of 2024.
(c)     Values disclosed are the generation levels at the point-of-interconnection for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
(d)    Tolk Unit 1 and 2 are proposed to be retired in 2034.
Electric utility overhead and underground transmission and distribution lines at Dec. 31, 2021:
Conductor MilesNSP-MinnesotaNSP-WisconsinPSCoSPS
Transmission
500 KV2,915 — — — 
345 KV13,570 2,943 4,978 11,688 
230 KV2,300 — 12,141 9,763 
161 KV640 1,778 — — 
138 KV— — 92 — 
115 KV8,086 1,818 5,075 14,880 
Less than 115 KV6,644 5,870 1,830 4,423 
Total Transmission34,155 12,409 24,116 40,754 
Distribution
Less than 115 KV81,406 27,701 78,712 22,651 
Total115,561 40,110 102,828 63,405 
Electric utility transmission and distribution substations at Dec. 31, 2021:
NSP-MinnesotaNSP-WisconsinPSCoSPS
Quantity354 204 237 458 
Natural gas utility mains at Dec. 31, 2021:
MilesNSP-MinnesotaNSP-WisconsinPSCoSPSWGI
Transmission85 3 2,174 20 11 
Distribution10,741 2,526 23,243 — — 





ITEM 3 — LEGAL PROCEEDINGS
Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation.
Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s consolidated financial statements. Legal fees are generally expensed as incurred.
See Note 12 to the consolidated financial statements, Item 1 and Item 7 for further information.
ITEM 4 — MINE SAFETY DISCLOSURES
None.
PART II
ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Stock Data
Xcel Energy Inc.’s common stock is listed on the Nasdaq Global Select Market (Nasdaq). The trading symbol is XEL. The number of common stockholders of record as of Feb. 17, 2022 was approximately 49,137.
The following compares our cumulative TSR on common stock with the cumulative TSR of the EEI Investor-Owned Electrics Index and the S&P 500 Composite Stock Price Index over the last five years.
The EEI Investor-Owned Electrics Index (market capitalization-weighted) included 39 companies at year-end and is a broad measure of industry performance.
Comparison of Five Year Cumulative Total Return*
xel-20211231_g30.jpg
*    $100 invested on Dec. 31, 2016 in stock or index — including reinvestment of dividends. Fiscal years ended Dec. 31.
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Purchases of Equity Securities by Issuer and Affiliated Purchasers
For the quarter ended Dec. 31, 2021, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers.
ITEM 6 — [RESERVED]
ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing ROE, ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from measures calculated and presented in accordance with GAAP.
Xcel Energy’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.
Ongoing ROE
Ongoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity’s average stockholder’s equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results.
Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)
GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.
We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. For the years ended Dec. 31, 2021 and 2020, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.


Results of Operations
Diluted EPS for Xcel Energy at Dec. 31:
20212020
Diluted Earnings (Loss) Per ShareGAAP and Ongoing Diluted EPSGAAP and Ongoing Diluted EPS
PSCo$1.22 $1.11 
NSP-Minnesota1.12 1.12 
SPS0.59 0.56 
NSP-Wisconsin0.20 0.20 
Earnings from equity method investments — WYCO0.05 0.05 
Regulated utility (a)
3.18 3.04 
Xcel Energy Inc. and Other(0.22)(0.25)
Total (a)
$2.96 $2.79 
(a)    Amounts may not add due to rounding.
Xcel Energy’s management believes that ongoing earnings reflects management’s performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy’s core business. In addition, Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors.
2021 Comparison with 2020
Xcel Energy — GAAP and ongoing earnings increased $0.17 per share for 2021. The increase was driven by capital investment recovery and other regulatory outcomes, partially offset by increases in depreciation and lower AFUDC. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in revenues are offset by the related variation in costs).
PSCo — Earnings increased $0.11 per share for 2021, 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).
NSP-Minnesota — Earnings were flat for 2021 compared to 2020, reflecting capital investment recovery offset by additional depreciation and interest charges.
SPS — Earnings increased $0.03 per share for 2021, largely related to capital investment recovery, other regulatory outcomes and higher sales and demand, partially offset by decreased AFUDC.
NSP-Wisconsin — Earnings were flat for 2021 compared to 2020.
Xcel Energy Inc. and Other — Primarily includes financing costs at the holding company, offset by earnings from EIP investments.
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Changes in Diluted EPS
Components significantly contributing to changes in EPS:
2021 vs. 2020
Diluted Earnings (Loss) Per ShareDec. 31
GAAP and ongoing diluted EPS — 2020$2.79
Components of change — 2021 vs. 2020
Higher electric revenues, andnet of electric fuel and purchased power expenses are impacted by fluctuations in the price of0.26 
Lower ETR (a)
0.17 
Higher natural gas coal and uranium used in the generationrevenues, net of electricity. However, these price fluctuations have minimal impact on electric margin due to fuel recovery mechanisms that recover fuel expenses. In addition, electric customers receive a credit for PTCs generated in a particular period.
Electric Margin
(Millions of Dollars) 2019 vs. 2018
Non-fuel riders (a)
 $107
Regulatory rate outcomes (Minnesota, New Mexico, North and South Dakota) 95
Implementation of lease accounting standard (offset in interest expense and amortization) 22
Purchased capacity costs 22
Demand revenue 20
Wholesale transmission revenue (net) 11
Timing of tax reform regulatory decisions (offset in income tax and amortization) (37)
Estimated impact of weather (net of Minnesota decoupling) (25)
Firm wholesale generation (20)
Sales declines (excluding weather impact) (18)
Other (net) 23
Total increase in electric margin $200
(a)
Includes approximately $60 million of additional PTC benefit (grossed-up for tax) as compared to 2018, which are credited to customers through various regulatory mechanisms.

Natural Gas Margin
Total natural gas expense varies with changing sales requirements and the cost of natural gas. However, fluctuations in the cost of natural gas has minimal impact on natural gas margin due to cost recovery mechanisms.
Natural Gas Margin
(Millions of Dollars) 2019 vs. 2018
Infrastructure and integrity riders $19
Estimated impact of weather 14
Transport sales 7
Retail sales growth 7
Other (net) 7
Total increase in natural gas margin $54
Non-Fuel Operating Expensessold and Other Items
transported
O&M Expenses0.15 
— O&M expenses decreased $14 million, or 0.6%, for 2019. Significant changes are summarized below:
(Millions of Dollars) 2019 vs. 2018
Plant generation $(20)
Nuclear plant operations and amortization (8)
Transmission (7)
Distribution 16
Other (net) 5
Total decrease in O&M expenses $(14)
Plant generation, transmission and distribution costs were lower due to timing of maintenance activities;
Nuclear plant operations and amortization were lower largely reflecting improved operating efficiencies and reduced refueling outage costs; and
Distribution expensesChanges in 2019 were higher than 2018 due to storms, labor and overtime incurred primarily in the first six months of 2019.
Depreciation and Amortization — Depreciation and amortization increased $123 million, or 7%, for 2019. The increase was primarily driven by the Rush Creek, Hale, Foxtail and Lake Benton wind farms going into service, natural gas and distribution/transmission replacements, and various software solutions. These increases were partially offset by higher levels of accelerated amortization of PSCo’s prepaid pension asset in 2018.
Taxes (Other than Income Taxes) — Taxestaxes (other than income taxes) increased $13 million, or 2.3%, for 2019. The increase was primarily due to higher property taxes in Colorado
(0.03)
Lower AFUDC(0.10)
Higher depreciation and Minnesota (net of deferred amounts).amortization
AFUDC, Equity(0.24)
Other (net)(0.04)
GAAP and Debt — AFUDC decreased $42 million for 2019. The decrease was primarily due to the Rush Creek wind project being placed in-service in 2018, partially offset by the Hale wind project, which went into service in June 2019, and other capital investments.
Interest Charges — Interest charges increased $73 million, or 10.4%, for 2019. The increase was primarily due to higher debt levels to fund capital investments, changes in short-term interest rates and implementation of lease accounting standard (offset in electric margin).
Income Taxes — Income taxes decreased $53 million for 2019, 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 2019 and ITCs in 2018. The ETR was 8.5% for 2019 compared with 12.6% for the same period in 2018, largely due to the adjustments above.
Xcel Energy Inc. and Other Results
Net income andongoing diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:
  Contribution (Millions of Dollars)
  2019 2018
Xcel Energy Inc. financing costs $(128) $(110)
Eloigne (a)
 1
 —
Xcel Energy Inc. taxes and other results 12
 (5)
Total Xcel Energy Inc. and other costs $(115) $(115)
   Contribution (Diluted Earnings (Loss) Per Share)
  2019 2018
Xcel Energy Inc. financing costs $(0.21) $(0.21)
Eloigne (a)
 —
 —
Xcel Energy Inc. taxes and other results (0.01) (0.01)
Total Xcel Energy Inc. and other costs $(0.22) $(0.22)
— 2021
$2.96
(a)
Amounts include gains or losses associated with sales of properties held by Eloigne.
Xcel Energy Inc.’s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries.
2018 Comparison with 2017
A discussion of changes in Xcel Energy’s results of operations and liquidity and capital resources from the year ended Dec. 31, 2017 to Dec. 31, 2018 can be found in Part II, “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year 2018, which was filed with the SEC on Feb. 22, 2019. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.
(a)Includes PTCs and plant regulatory amounts, which are primarily offset as a reduction to electric revenues.
ROE for Xcel Energy and its utility subsidiaries:
20212020
ROEGAAP and Ongoing ROEGAAP and Ongoing ROE
NSP-Minnesota8.45 %9.20 %
PSCo8.23 8.06 
SPS9.22 9.54 
NSP-Wisconsin9.92 10.52 
Operating Companies8.58 8.87 
Xcel Energy10.58 10.59 
Statement of Income Analysis
The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.
Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. However, sales true-up and decoupling mechanisms in Minnesota and Colorado predominately mitigate the positive and adverse impacts of weather.
Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather.
Public Utility Regulation
Normal weather conditions are defined as either the 10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates.
Percentage (decrease) increase in normal and actual HDD, CDD and THI:
2021 vs.
Normal		2020 vs.
Normal		2021 vs. 2020
HDD(6.6)%(3.1)%(4.3)%
CDD12.2 22.2 (9.2)
THI26.8 6.3 20.7 
Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:
2021 vs.
Normal		2020 vs.
Normal		2021 vs. 2020
Retail electric$0.096 $0.090 $0.006 
Decoupling and sales true-up(0.066)(0.041)(0.025)
Electric total$0.030 $0.049 $(0.019)
Firm natural gas(0.025)(0.011)(0.014)
Total$0.005 $0.038 $(0.033)
Sales — Sales growth (decline) for actual and weather-normalized sales:
2021 vs. 2020
PSCoNSP-MinnesotaSPSNSP-WisconsinXcel Energy
Actual
Electric residential— %2.2 %(4.7)%0.5 %0.3 %
Electric C&I0.4 2.3 2.9 3.6 2.0 
Total retail electric sales0.3 2.2 1.4 2.7 1.4 
Firm natural gas sales(1.1)(4.0)N/A(5.0)(2.2)
2021 vs. 2020
PSCoNSP-MinnesotaSPSNSP-WisconsinXcel Energy
Weather-normalized
Electric residential1.5 %0.3 %(1.0)%(0.2)%0.5 %
Electric C&I0.4 1.7 3.3 3.3 1.9 
Total retail electric sales0.8 1.2 2.5 2.2 1.4 
Firm natural gas sales1.3 (2.2)N/A(4.1)(0.1)
2021 vs. 2020 (2020 Leap Year Adjusted)
PSCoNSP-MinnesotaSPSNSP-WisconsinXcel Energy
Weather-normalized
Electric residential1.7 %0.6 %(0.7)%0.1 %0.8 %
Electric C&I0.7 1.9 3.6 3.6 2.1 
Total retail electric sales1.1 1.5 2.7 2.5 1.7 
Firm natural gas sales1.8 (1.7)N/A(3.6)0.4 

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Weather-normalized and leap-year adjusted electric sales growth (decline) — year-to-date
Weather-adjusted sales results for each of our utility subsidiaries in 2021 reflect improving economies as the adverse effects of COVID-19 lessen. The recovery reflects increased sales in the C&I sector as businesses return to a more normal level. Residential sales remain elevated from pre-pandemic levels due to continuance of individuals working from home.
•PSCo — Residential sales rose based on a 1.2% increase in customers, combined with higher use per customer. The growth in C&I sales was due to a 1.2% increase in customers, partially offset by slightly lower use per customer, primarily in the services sector.
•NSP-Minnesota — Residential sales growth reflects a 1.2% increase in customers, partially offset by a lower use per customer. The growth in C&I sales was due to a 0.9% increase in customers and higher use per customer, primarily in the manufacturing, retail and services sectors.
•SPS — Residential sales declined as lower use per customer offset a 0.9% increase in customers. C&I sales increased due to a 0.5% increase in customers and higher use per customer, primarily driven by the oil and gas and professional services sectors.
•NSP-Wisconsin — Residential sales growth was attributable to a 0.8% increase in customer additions, partially offset by slightly lower use per customer. The growth in C&I sales was due to a 1.1% increase in customers, primarily led by increases in the manufacturing, health care and retail trade sectors.
Weather-normalized and leap-year adjusted natural gas sales growth (decline) — year-to-date
•Natural gas sales primarily reflect a 1.2% increase in residential customers and a 0.5% increase in C&I customers, partially offset by a decrease in use per customer.
The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and WGI. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico, and Texas.
Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in rates for utility services through filings with governing commissions. Changes in operating costs can affect Xcel Energy’s financial results, depending on the timing of rate case filings and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital.
In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy’s results of operations.
See Rate Matters within Note 12 to the consolidated financial statements for further information.




NSP-Minnesota
Summary of Regulatory Agencies / RTOStation, Location and Areas of JurisdictionUnit at Dec. 31, 2021
FuelInstalled
MW (a)
Steam:
A.S. King-Bayport, MN, 1 Unit(f)
Coal1968511 
Sherco-Becker, MN(e)
Unit 1Coal1976680 
Unit 2Coal1977682 
Unit 3Coal1987517 (b)
Monticello, MN, 1 UnitNuclear1971617 
PI-Welch, MN
Unit 1Nuclear1973521 
Unit 2Nuclear1974519 
Various locations, 4 UnitsWood/RefuseVarious36 (c)
Combustion Turbine:
Angus Anson-Sioux Falls, SD, 3 UnitsNatural Gas1994 - 2005327 
Black Dog-Burnsville, MN, 3 UnitsNatural Gas1987 - 2018494 
Blue Lake-Shakopee, MN, 6 UnitsNatural Gas1974 - 2005447 
High Bridge-St. Paul, MN, 3 UnitsNatural Gas2008530 
Inver Hills-Inver Grove Heights, MN, 6 UnitsNatural Gas1972252 
Riverside-Minneapolis, MN, 3 UnitsNatural Gas2009454 
Various locations, 7 UnitsNatural GasVarious10 
Wind:
Blazing Star 1-Lincoln County, MN, 100 UnitsWind2020200 (d)
Blazing Star 2-Lincoln County, MN, 100 UnitsWind2021200 (d)
Border-Rolette County, ND, 75 UnitsWind2015148 (d)
Community Wind North-Lincoln County, MN, 12 UnitsWind202026 (d)
Courtenay Wind-Stutsman County, ND, 100 UnitsWind2016190 (d)
Crowned Ridge 2-Grant County, SD, 88 UnitsWind2020192 (d)
Foxtail-Dickey County, ND, 75 UnitsWind2019150 (d)
Freeborn-Freeborn County, MN, 100 UnitsWind2021200 (d)
Grand Meadow-Mower County, MN, 67 UnitsWind200899 (d)
Jeffers-Cottonwood County, MN, 20 UnitsWind202043 (d)
Lake Benton-Pipestone County, MN, 44 UnitsWind201999 (d)
Mower-Mower County, MN, 43 UnitsWind202191 (d)
Nobles-Nobles County, MN, 134 UnitsWind2010197 (d)
Pleasant Valley-Mower County, MN, 100 UnitsWind2015196 (d)
Total8,628 
Regulatory Body / RTOAdditional Information
MPUC (a)
Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations.
Reviews and approves IRPs for meeting future energy needs.
Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota.
Reviews and approves natural gas supply plans.
Pipeline safety compliance.
NDPSC (a)
Retail rates, services and other aspects of electric and natural gas operations.
Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota.
Pipeline safety compliance.
SDPUC
Retail rates, services and other aspects of electric operations.
Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota.
Pipeline safety compliance.
FERCWholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce.
MISONSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC.
DOTPipeline safety compliance.
Minnesota Office of Pipeline SafetyPipeline safety compliance.
(a)
(a)Summer 2021 net dependable capacity.
(b)Based on NSP-Minnesota’s ownership of 59%.
(c)Refuse-derived fuel is made from municipal solid waste.
(d)Values disclosed are the generation levels at the point-of-interconnection for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
(e)A.S. King is expected to be retired early in 2028.
(f)Sherco Unit 1, 2, and 3 are expected to be retired early in 2026, 2023 and 2030, respectively.
Jurisdictional Cost Recovery Allocation — In December 2016, NSP-Minnesota filed a resource treatment framework with the NDPSC and MPUC to allow NSP-Minnesota’s operations in North Dakota and Minnesota to gradually become more independent of one another. The filing identified two options: a legal separation, creating a separate North Dakota operating company; or a pseudo-separation, which maintains the current corporate structure but directly assigns costs and benefits of each resource to the jurisdiction that supports it. Docket remains under consideration by the NDPSC.
Recovery Mechanisms
MechanismAdditional Information
CIP Rider (a)
Recovers costs of conservation and DSM programs.
EIRRecovers costs of environmental improvement projects.
RDFAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies.
RESRecovers cost of renewable generation in Minnesota.
RERRecovers the cost of renewable generation in North Dakota.
SEPRecovers costs related to various energy policies approved by the Minnesota legislature.
TCRRecovers costs for investments in electric transmission and distribution grid modernization.
Infrastructure RiderRecovers costs for investments in generation and incremental property taxes in South Dakota.
FCA (b)
Minnesota, North Dakota and South Dakota include a FCA for monthly billing adjustments to recover changes in prudently incurred costs of fuel related items and purchased energy. Capacity costs are recovered through base rates and are not recovered through the FCA. MISO costs are generally recovered through either the FCA or base rates.
PGAProvides for prospective monthly rate adjustments for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actuals costs.
GUIC RiderRecovers costs for transmission and distribution pipeline integrity management programs, including: funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs.
(a)
Minnesota state law requires NSP-Minnesota to invest 2% of its state electric revenues and 0.5% of its state gas revenues in CIP. These costs are recovered through an annual cost-recovery mechanism.
(b)
In 2017, the MPUC changed the FCA process in Minnesota, which will implemented in 2020. Under the new process, each month utilities would collect amounts equal to the baseline cost of energy set at the start of the plan year (base would be reset annually). Monthly variations to the baseline costs would be tracked and netted over a 12-month period. Utilities would issue refunds above the baseline costs and could seek recovery of any overage.

Pending and Recently Concluded Regulatory Proceedings
MechanismUtility ServiceAmount Requested (in millions)
Filing
Date
ApprovalAdditional Information
MPUC
2018 TCRElectric$98November 2017ReceivedIn November 2019, the MPUC issued an order setting an ROE of 9.06% and recovery of 2017-2018 expenses related to advanced grid investments.
2020 TCRElectric$82November 2019PendingIn November 2019, NSP-Minnesota filed the 2020 TCR Rider. The filing included an ROE of 9.06%. Timing of an MPUC ruling is uncertain.
2019 GUICNatural Gas$29November 2018PendingIn November 2018, NSP-Minnesota filed the 2019 GUIC Rider with the MPUC. The filing included an ROE of 10.25%. Timing of an MPUC ruling is uncertain.
2020 GUICNatural Gas$21November 2019PendingIn November 2019, NSP-Minnesota filed the 2020 GUIC Rider with the MPUC. The filing included an ROE of 9.04%. Timing of an MPUC ruling is uncertain.
2018 RESElectric$23November 2017ReceivedIn November 2019, the MPUC approved an order setting an ROE of 9.06%.
2020 RESElectric$102November 2019PendingIn November 2019, NSP-Minnesota filed the 2020 RES Rider with the MPUC. The requested amount includes a true up for the 2019 rider of $38 million and the 2020 requested amount of $64 million. The filing included an ROE of 9.06%. Timing of an MPUC ruling is uncertain.
Minnesota Electric Rate Case and Alternative Petition —In November 2019, NSP-Minnesota filed a three-year electric rate case with the MPUC. The proposed electric rates reflect a three-year increase in revenues of approximately $201.4 million (6.5%) in 2020, with subsequent incremental increases of $146.4 million (4.8%) in 2021 and $118.3 million (3.9%) in 2022. The rate case is based on a requested ROE of 10.2%, a 52.5% equity ratio, an average electric rate base of $9.0 billion for 2020, $9.3 billion for 2021 and $9.8 billion for 2022.
In addition, NSP-Minnesota requested interim rates, subject to refund, of $122.0 million to be implemented in January 2020 and an incremental $144.0 million to be implemented in January 2021.
NSP-Minnesota also filed a stay-out petition, in which NSP-Minnesota would withdraw its electric rate case and refrain from filing another rate case for one year if the MPUC were to approve an extension of true-up mechanisms for sales, capital and property taxes. NSP-Minnesota also requested that the MPUC delay any increase to the Nuclear Decommissioning Trust annual accrual until 2021.
In December 2019, the MPUC verbally approved the stay-out petition including extension of the sales, capital and property tax true-up mechanisms and the delay of any increase to the Nuclear Decommissioning Trust annual accrual until Jan. 1, 2021.
MEC Acquisition — In November 2018, NSP-Minnesota reached an agreement with Southern Power Company (a subsidiary of Southern Company) to purchase MEC, a 760 MW natural gas combined cycle facility, for approximately $650 million.
In September 2019, the MPUC denied NSP-Minnesota's request to purchase MEC as a rate base asset. In January 2020, the MPUC approved Xcel Energy’s plan to acquire MEC as a non-regulated investment and step into the terms of the existing PPAs with NSP-Minnesota. A newly formed non-regulated subsidiary of Xcel Energy completed the transaction to purchase MEC on Jan. 17, 2020.
Minnesota Resource Plan —In July 2019, NSP-Minnesota filed its Minnesota resource plan, which runs through 2034. The plan would result in an 80% carbon reduction by 2030 (from 2005) and puts NSP-Minnesota on a path to achieving its vision of being 100% carbon-free by 2050. The preferred plan includes the following:
Extends the life of the Monticello nuclear plant from 2030 to 2040;
Continues to run PI through current end of life (2033 and 2034);
Includes the MEC acquisition and construction of the Sherco combined cycle natural gas plant;
Includes the early retirement of the King coal plant (511 MW) in 2028 and the Sherco 3 coal plant (517 MW) in 2030;
Adds approximately 1,700 MW of firm peaking (combustion turbine, pumped hydro, battery storage, demand response, etc.);
Adds approximately 1,200 MW of wind replacement; and
Adds approximately 4,000 MW of solar.
Intervening parties will provide recommendations and comments on the resource plan. Following the MPUC’s denial of its request to purchase MEC, NSP-Minnesota will provide updates to remove its ownership of MEC from the preferred plan. The MPUC required NSP-Minnesota to update its filing to address issues related to its decision on MEC, including certain new modeling scenarios. An updated filing is required by April 1, 2020. The MPUC is anticipated to make a final decision on the resource plan in the first half of 2021.
Jeffers Wind and Community Wind North Repowering Acquisition — In October 2019, the MPUC approved NSP-Minnesota’s request to acquire the Jeffers and Community Wind North wind facilities in western Minnesota from Longroad Energy. The wind farms will have approximately 70 MW of capacity after being repowered. The repowering is expected to be completed by December 2020 and qualify for the full PTC. The $135 million asset acquisition is projected to provide customer savings of approximately $7 million over the life of the facilities.

Mower Wind Facility —In August 2019, NSP-Minnesota filed a petition with the MPUC to acquire the Mower wind facility from affiliates of NextEra Energy, Inc. for an undisclosed amount. The Mower facility is located in southeastern Minnesota and is currently contracted under a PPA with NSP-Minnesota through 2026. Mower is expected to continue to have approximately 99 MW of capacity following a planned repowering. The acquisition would occur after repowering, which is expected to be complete in 2020 and qualify for the full PTC. NSP-Minnesota will need approval from both the MPUC and FERC to complete the transaction. NSP-Minnesota filed reply comments addressing the DOC’s concerns with the transaction in February 2020.Timing of MPUC and FERC decisions are uncertain.
Purchased Power Arrangements and Transmission Service Provider
NSP-Minnesota expects to use power plants, power purchases, CIP/DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements.
Purchased Power — NSP-Minnesota has contracts to purchase power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require a capacity and an energy charge. NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost.
PPA Terminations and Amendments — In June 2018, NSP-Minnesota terminated the Benson and Laurentian PPAs, and purchased the Benson biomass facility. As a result, a $103 million regulatory asset was recognized for the costs of the Benson transaction. For Laurentian, a regulatory asset of $109 million was recognized for annual termination payments/obligations. Regulatory approvals provide for recovery of the Benson regulatory asset over 10 years and Laurentian termination payments as they occur (over six years). Termination of the PPAs is expected to save customers over $600 million throughout the next 10 years.
Purchased Transmission Services — NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers.
Minnesota State ROFR Statute Complaint — In September 2017, LSP Transmission filed a complaint in the Minnesota District Court against the Minnesota Attorney General, MPUC and DOC. The complaint was in response to MISO assigning NSP-Minnesota and ITC Midwest, LLC to jointly own a new 345 KV transmission line from Mankato to Winnebago, Minnesota.
The project was estimated to cost $108 million and projected to be in-service by the end of 2021. It was assigned to NSP-Minnesota and ITC Midwest as the incumbent utilities, consistent with a Minnesota state ROFR statute. The complaint challenged the constitutionality of the statute and is seeking declaratory judgment that the statute violates the Commerce Clause of the U.S. Constitution and should not be enforced. The Minnesota state agencies and NSP-Minnesota filed motions to dismiss.
In June 2018, the Minnesota District Court granted the defendants’ motions to dismiss with prejudice. LSP Transmission filed an appeal in July 2018. In September 2019, the estimate was updated to approximately $140 million, due to various changes in build plans. In October 2019, oral arguments were held with the Eighth Circuit Court of Appeals. A decision is expected in the first or second quarter of 2020.
Nuclear Power Operations and Waste Disposal
Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.
NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.
Low-Level Waste Disposal — Low level waste disposal from Monticello and PI is disposed at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if of-site low-level waste disposal facilities become unavailable.
High-Level Radioactive Waste Disposal — The federal government has responsibility to permanently dispose domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. The federal government has been evaluating a nuclear geologic repository at Yucca Mountain, Nevada for many years. Currently, there are no definitive plans for a permanent federal storage facility site.
Nuclear Spent Fuel Storage —NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2. Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.
Wholesale and Commodity Marketing Operations
NSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price and credit risk and hedge sales and purchases.
NSP-Minnesota also engages in trading activity unrelated to hedging. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved JOA. NSP-Minnesota does not serve any wholesale requirements customers at cost-based regulated rates.

NSP-Wisconsin
Summary of Regulatory Agencies / RTOStation, Location and Areas of JurisdictionUnit at Dec. 31, 2021
FuelInstalled
MW(a)
Steam:
Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 
French Island-La Crosse, WI, 2 UnitsWood/Refuse1940 - 194816 (b)
Combustion Turbine:
French Island-La Crosse, WI, 2 UnitsOil1974122 
Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973234 
Hydro:
Various locations, 63 UnitsHydroVarious135 
Total548 
(a)Summer 2021 net dependable capacity.
(b)Refuse-derived fuel is made from municipal solid waste.
PSCo
Station, Location and Unit at Dec. 31, 2021
FuelInstalled
MW (a)
Steam:
Comanche-Pueblo, CO (b)
Unit 1Coal1973325 
Unit 2Coal1975335 
Unit 3Coal2010500 (c)
Craig-Craig, CO, 2 Units (d)
Coal1979 - 198082 (e)
Hayden-Hayden, CO, 2 Units
Coal1965 - 1976233 (f)
Pawnee-Brush, CO, 1 UnitCoal1981505 
Cherokee-Denver, CO, 1 UnitNatural Gas1968310 
Combustion Turbine:
Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 
Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 
Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 2009973 
Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004580 
Various locations, 8 UnitsNatural GasVarious251 
Hydro:
Cabin Creek-Georgetown, CO
Pumped Storage, 2 UnitsHydro1967210 
Various locations, 8 UnitsHydroVarious25 
Wind:
Rush Creek, CO, 300 unitsWind2018582 (g)
Cheyenne Ridge, CO, 229 unitsWind2020477 (g)
Total6,228 
(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).
24
SPS
Station, Location and Unit at Dec. 31, 2021
FuelInstalled
MW (a)
Steam:
Cunningham-Hobbs, NM, 2 UnitsNatural Gas1957 - 1965225 
Harrington-Amarillo, TX, 3 Units (b)
Coal1976 - 19801,018 
Jones-Lubbock, TX, 2 UnitsNatural Gas1971 - 1974486 
Maddox-Hobbs, NM, 1 UnitNatural Gas1967112 
Nichols-Amarillo, TX, 3 UnitsNatural Gas1960 - 1968457 
Plant X-Earth, TX, 4 UnitsNatural Gas1952 - 1964298 
Tolk-Muleshoe, TX, 2 Units (d)
Coal1982 - 19851,067 
Combustion Turbine:
Cunningham-Hobbs, NM, 2 UnitsNatural Gas1997207 
Jones-Lubbock, TX, 2 UnitsNatural Gas2011 - 2013334 
Maddox-Hobbs, NM, 1 UnitNatural Gas1963 - 197661 
Wind:
Hale-Plainview, TX, 239 UnitsWind2019477 (c)
Sagamore-Dora, NM, 240 UnitsWind2020507 (c)
Total5,249 
(a)    Summer 2021 net dependable capacity.
(b)    Harrington is expected to be converted to natural gas by the end of 2024.
(c)     Values disclosed are the generation levels at the point-of-interconnection for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
(d)    Tolk Unit 1 and 2 are proposed to be retired in 2034.
Electric utility overhead and underground transmission and distribution lines at Dec. 31, 2021:
Conductor MilesNSP-MinnesotaNSP-WisconsinPSCoSPS
Transmission
500 KV2,915 — — — 
345 KV13,570 2,943 4,978 11,688 
230 KV2,300 — 12,141 9,763 
161 KV640 1,778 — — 
138 KV— — 92 — 
115 KV8,086 1,818 5,075 14,880 
Less than 115 KV6,644 5,870 1,830 4,423 
Total Transmission34,155 12,409 24,116 40,754 
Distribution
Less than 115 KV81,406 27,701 78,712 22,651 
Total115,561 40,110 102,828 63,405 
Electric utility transmission and distribution substations at Dec. 31, 2021:
NSP-MinnesotaNSP-WisconsinPSCoSPS
Quantity354 204 237 458 
Natural gas utility mains at Dec. 31, 2021:
MilesNSP-MinnesotaNSP-WisconsinPSCoSPSWGI
Transmission85 3 2,174 20 11 
Distribution10,741 2,526 23,243 — — 





ITEM 3 — LEGAL PROCEEDINGS
Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation.
Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s consolidated financial statements. Legal fees are generally expensed as incurred.
See Note 12 to the consolidated financial statements, Item 1 and Item 7 for further information.
ITEM 4 — MINE SAFETY DISCLOSURES
None.
PART II
ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Stock Data
Xcel Energy Inc.’s common stock is listed on the Nasdaq Global Select Market (Nasdaq). The trading symbol is XEL. The number of common stockholders of record as of Feb. 17, 2022 was approximately 49,137.
The following compares our cumulative TSR on common stock with the cumulative TSR of the EEI Investor-Owned Electrics Index and the S&P 500 Composite Stock Price Index over the last five years.
The EEI Investor-Owned Electrics Index (market capitalization-weighted) included 39 companies at year-end and is a broad measure of industry performance.
Comparison of Five Year Cumulative Total Return*
xel-20211231_g30.jpg
*    $100 invested on Dec. 31, 2016 in stock or index — including reinvestment of dividends. Fiscal years ended Dec. 31.
25
Purchases of Equity Securities by Issuer and Affiliated Purchasers
For the quarter ended Dec. 31, 2021, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers.
ITEM 6 — [RESERVED]
ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as ongoing ROE, ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from measures calculated and presented in accordance with GAAP.
Xcel Energy’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.
Ongoing ROE
Ongoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity’s average stockholder’s equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results.
Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)
GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS is calculated by dividing the net income or loss of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss of such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.
We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. For the years ended Dec. 31, 2021 and 2020, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings.


Results of Operations
Diluted EPS for Xcel Energy at Dec. 31:
20212020
Diluted Earnings (Loss) Per ShareGAAP and Ongoing Diluted EPSGAAP and Ongoing Diluted EPS
PSCo$1.22 $1.11 
NSP-Minnesota1.12 1.12 
SPS0.59 0.56 
NSP-Wisconsin0.20 0.20 
Earnings from equity method investments — WYCO0.05 0.05 
Regulated utility (a)
3.18 3.04 
Xcel Energy Inc. and Other(0.22)(0.25)
Total (a)
$2.96 $2.79 
(a)    Amounts may not add due to rounding.
Xcel Energy’s management believes that ongoing earnings reflects management’s performance in operating Xcel Energy and provides a meaningful representation of the performance of Xcel Energy’s core business. In addition, Xcel Energy’s management uses ongoing earnings internally for financial planning and analysis, reporting results to the Board of Directors and when communicating its earnings outlook to analysts and investors.
2021 Comparison with 2020
Xcel Energy — GAAP and ongoing earnings increased $0.17 per share for 2021. The increase was driven by capital investment recovery and other regulatory outcomes, partially offset by increases in depreciation and lower AFUDC. Fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in revenues are offset by the related variation in costs).
PSCo — Earnings increased $0.11 per share for 2021, 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).
NSP-Minnesota — Earnings were flat for 2021 compared to 2020, reflecting capital investment recovery offset by additional depreciation and interest charges.
SPS — Earnings increased $0.03 per share for 2021, largely related to capital investment recovery, other regulatory outcomes and higher sales and demand, partially offset by decreased AFUDC.
NSP-Wisconsin — Earnings were flat for 2021 compared to 2020.
Xcel Energy Inc. and Other — Primarily includes financing costs at the holding company, offset by earnings from EIP investments.
26
Changes in Diluted EPS
Components significantly contributing to changes in EPS:
2021 vs. 2020
Diluted Earnings (Loss) Per ShareDec. 31
GAAP and ongoing diluted EPS — 2020$2.79
Components of change — 2021 vs. 2020
Higher electric revenues, net of electric fuel and purchased power0.26 
Lower ETR (a)
0.17 
Higher natural gas revenues, net of cost of natural gas sold and transported0.15 
Changes in taxes (other than income taxes)(0.03)
Lower AFUDC(0.10)
Higher depreciation and amortization(0.24)
Other (net)(0.04)
GAAP and ongoing diluted EPS — 2021$2.96
(a)Includes PTCs and plant regulatory amounts, which are primarily offset as a reduction to electric revenues.
ROE for Xcel Energy and its utility subsidiaries:
20212020
ROEGAAP and Ongoing ROEGAAP and Ongoing ROE
NSP-Minnesota8.45 %9.20 %
PSCo8.23 8.06 
SPS9.22 9.54 
NSP-Wisconsin9.92 10.52 
Operating Companies8.58 8.87 
Xcel Energy10.58 10.59 
Statement of Income Analysis
The following summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.
Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. However, sales true-up and decoupling mechanisms in Minnesota and Colorado predominately mitigate the positive and adverse impacts of weather.
Degree-day or THI data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. HDD is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. CDD is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather.
Normal weather conditions are defined as either the 10, 20 or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales. Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized estimates.
Percentage (decrease) increase in normal and actual HDD, CDD and THI:
2021 vs.
Normal		2020 vs.
Normal		2021 vs. 2020
HDD(6.6)%(3.1)%(4.3)%
CDD12.2 22.2 (9.2)
THI26.8 6.3 20.7 
Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:
2021 vs.
Normal		2020 vs.
Normal		2021 vs. 2020
Retail electric$0.096 $0.090 $0.006 
Decoupling and sales true-up(0.066)(0.041)(0.025)
Electric total$0.030 $0.049 $(0.019)
Firm natural gas(0.025)(0.011)(0.014)
Total$0.005 $0.038 $(0.033)
Sales — Sales growth (decline) for actual and weather-normalized sales:
2021 vs. 2020
PSCoNSP-MinnesotaSPSNSP-WisconsinXcel Energy
Actual
Electric residential— %2.2 %(4.7)%0.5 %0.3 %
Electric C&I0.4 2.3 2.9 3.6 2.0 
Total retail electric sales0.3 2.2 1.4 2.7 1.4 
Firm natural gas sales(1.1)(4.0)N/A(5.0)(2.2)
2021 vs. 2020
PSCoNSP-MinnesotaSPSNSP-WisconsinXcel Energy
Weather-normalized
Electric residential1.5 %0.3 %(1.0)%(0.2)%0.5 %
Electric C&I0.4 1.7 3.3 3.3 1.9 
Total retail electric sales0.8 1.2 2.5 2.2 1.4 
Firm natural gas sales1.3 (2.2)N/A(4.1)(0.1)
2021 vs. 2020 (2020 Leap Year Adjusted)
PSCoNSP-MinnesotaSPSNSP-WisconsinXcel Energy
Weather-normalized
Electric residential1.7 %0.6 %(0.7)%0.1 %0.8 %
Electric C&I0.7 1.9 3.6 3.6 2.1 
Total retail electric sales1.1 1.5 2.7 2.5 1.7 
Firm natural gas sales1.8 (1.7)N/A(3.6)0.4 

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Weather-normalized and leap-year adjusted electric sales growth (decline) — year-to-date
Weather-adjusted sales results for each of our utility subsidiaries in 2021 reflect improving economies as the adverse effects of COVID-19 lessen. The recovery reflects increased sales in the C&I sector as businesses return to a more normal level. Residential sales remain elevated from pre-pandemic levels due to continuance of individuals working from home.
•PSCo — Residential sales rose based on a 1.2% increase in customers, combined with higher use per customer. The growth in C&I sales was due to a 1.2% increase in customers, partially offset by slightly lower use per customer, primarily in the services sector.
•NSP-Minnesota — Residential sales growth reflects a 1.2% increase in customers, partially offset by a lower use per customer. The growth in C&I sales was due to a 0.9% increase in customers and higher use per customer, primarily in the manufacturing, retail and services sectors.
•SPS — Residential sales declined as lower use per customer offset a 0.9% increase in customers. C&I sales increased due to a 0.5% increase in customers and higher use per customer, primarily driven by the oil and gas and professional services sectors.
•NSP-Wisconsin — Residential sales growth was attributable to a 0.8% increase in customer additions, partially offset by slightly lower use per customer. The growth in C&I sales was due to a 1.1% increase in customers, primarily led by increases in the manufacturing, health care and retail trade sectors.
Weather-normalized and leap-year adjusted natural gas sales growth (decline) — year-to-date
•Natural gas sales primarily reflect a 1.2% increase in residential customers and a 0.5% increase in C&I customers, partially offset by a decrease in use per customer.
Electric Margin
Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. However, these price fluctuations generally have minimal impact on earnings impact due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes.
Electric Revenues, Fuel and Purchased Power and Electric Margin
(Millions of Dollars)20212020
Electric revenues$11,205 $9,802 
Electric fuel and purchased power(4,733)(3,512)
Electric margin$6,472 $6,290 
Changes in Electric Margin
(Millions of Dollars)2021 vs. 2020
Non-fuel riders$221 
Regulatory rate outcomes (Texas, Wisconsin, Colorado, New Mexico and North Dakota)114 
Proprietary commodity trading, net of sharing (a)
40 
Sales and demand (b)
29 
PTCs flowed back to customers (offset by lower ETR)(149)
Texas 2019 rate case surcharge (c)
(70)
Estimated impact of weather (net of decoupling/sales true-up)(12)
Other (net)9 
Increase in electric margin$182 
(a)Includes $27 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.
(b)Sales excludes weather impact, net of decoupling/sales true-up, and demand is net of sales true-up.
(c)Impact is due to the Texas rate case outcome, which resulted in a revenue increase that was recognized in the third quarter of 2020 (largely offset by recognition of previously deferred costs).
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)20212020
Natural gas revenues$2,132 $1,636 
Cost of natural gas sold and transported(1,081)(689)
Natural gas margin$1,051 $947 
Changes in Natural Gas Margin
(Millions of Dollars)2021 vs. 2020
Regulatory rate outcomes (Colorado and North Dakota)$90 
Infrastructure and integrity riders12 
Conservation incentive3 
Estimated impact of weather(10)
Other (net)9 
Increase in natural gas margin$104 
Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses decreased $3 million year-to-date. Increases for distribution, wind farm maintenance and technology costs were offset by a decrease in employee benefits expense (e.g., long term incentives), additional Texas 2021 rate case deferrals and the year-over-year impact of amounts associated with the Texas 2019 rate case surcharge.
Depreciation and Amortization — Depreciation and amortization increased $173 million year-to-date. The increase was primarily driven by several wind farms going into service, normal system expansion and the implementation of new depreciation rates in various states.
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Other Income (Expense) — Other income (expense) increased $11 million year-to-date. The change was largely related to gains associated with rabbi trust performance (offset in O&M expenses).
AFUDC, Equity and Debt — AFUDC decreased $58 million year-to-date. The decrease was driven by completion of various wind projects throughout 2020 and 2021.
Interest Charges — Interest charges increased $2 million year-to-date. The increase was largely due to higher debt levels to fund capital investments, partially offset by lower long-term and short-term interest rates.
Earnings from Equity Method Investments — Earnings from equity method investments increased $22 million year-to-date. The year-to-date change was largely attributable to the performance of the EIP funds, which invest in energy technology companies.
Income Taxes — Income tax benefit increased $64 million year-to-date. The change was driven by an increase in wind PTCs due to additional wind facilities going into service. Impact of PTCs was partially offset by an increase in pretax earnings, lower plant regulatory differences and lower non-plant accumulated deferred income tax amortization.
Xcel Energy Inc. and Other Results
Net income and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:
Contribution (Millions of Dollars)
20212020
Xcel Energy Inc. financing costs$(129)$(147)
MEC (a)
— 15 
Venture Holdings (b)
21 4 
Xcel Energy Inc. taxes and other results(12)(5)
Total Xcel Energy Inc. and other costs$(120)$(133)

Contribution (Diluted Earnings (Loss) Per Share)
20212020
Xcel Energy Inc. financing costs$(0.24)$(0.28)
MEC (a)
— 0.03 
Venture Holdings (b)
0.04 0.01 
Xcel Energy Inc. taxes and other results(0.02)(0.01)
Total Xcel Energy Inc. and other costs$(0.22)$(0.25)
(a)MEC was sold in the third quarter of 2020.
(b)Amounts include gains or losses associated with EIP investments.
Xcel Energy Inc.’s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries.
2020 Comparison with 2019
A discussion of changes in Xcel Energy’s results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2019 to Dec. 31, 2020 can be found in Part II, “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year 2020, which was filed with the SEC on Feb. 17, 2021. However, such discussion is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.
Public Utility Regulation
The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility subsidiaries and West Gas Interstate. Xcel Energy is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico and Texas.
Rates are designed to recover plant investment, operating costs and an allowed return on investment. Our utility subsidiaries request changes in utility rates through commission filings. Changes in operating costs can affect Xcel Energy’s financial results, depending on the timing of rate cases and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital.
In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impact Xcel Energy’s results of operations.
See Rate Matters within Note 12 to the consolidated financial statements for further information.
NSP-Minnesota
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Regulatory Body / RTOAdditional Information
MPUC
Retail rates, services, security issuances, property transfers, mergers, disposition of assets, affiliate transactions, and other aspects of electric and natural gas operations.
Reviews and approves Integrated Resource Plans for meeting future energy needs.
Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota.
Reviews and approves natural gas supply plans.
Pipeline safety compliance.
NDPSC
Retail rates, services and other aspects of electric and natural gas operations.
Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota.
Pipeline safety compliance.
South Dakota Public Utilities Commission
Retail rates, services and other aspects of electric operations.
Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota.
Pipeline safety compliance.
FERCWholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce.
MISONSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers outside of their balancing authority as jointly authorized by the FERC.
DOTAdditional Information
PSCW
Retail rates, services and other aspects of electric and natural gas operations.
Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.
The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.
Pipeline safety compliance.
MPSC
Retail rates, services and other aspects of electric and natural gas operations.
Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.
Pipeline safety compliance.
FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.
MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.
DOTPipeline safety compliance.
Minnesota Office of Pipeline SafetyPipeline safety compliance.
Recovery Mechanisms
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Recovery Mechanisms
MechanismAdditional Information
CIP Rider (a)
Recovers costs of conservation and DSM programs in Minnesota.
Environmental Improvement RiderRecovers costs of environmental improvement projects in Minnesota.
Renewable Development FundAllocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.
RESRecovers cost of renewable generation in Minnesota.
Renewable Energy RiderRecovers cost of renewable generation in North Dakota.
State Energy Policy RiderRecovers costs related to various energy policies approved by the Minnesota legislature.
TCRRecovers costs for investments in electric transmission and distribution grid modernization.
Infrastructure RiderRecovers costs for investments in generation and incremental property taxes in South Dakota.
FCA (b)
Minnesota, North Dakota and South Dakota include a FCA for monthly billing adjustments to recover changes in prudently incurred costs of fuel related items and purchased energy. Capacity costs are recovered through base rates and are not recovered through the FCA. MISO costs are generally recovered through either the FCA or base rates.
Purchased Gas AdjustmentProvides for prospective monthly rate adjustments for costs of purchased natural gas, transportation and storage service. Includes a true-up process for difference between projected and actual costs.
GUIC RiderRecovers costs for transmission and distribution pipeline integrity management programs, including funding for pipeline assessments, deferred costs for sewer separation and pipeline integrity management programs in Minnesota.
Sales True-upIn February 2022, NSP-Minnesota filed the 2021 sales true-up compliance report, resulting in a total surcharge of $59 million. An MPUC ruling is anticipated in the second quarter of 2022. In their current rate case, NSP-Minnesota has proposed a sales true-up mechanism for 2022 and beyond that would operate similarly to the 2021 sales true-up. Under the stay-out petition, 2021 NSP-Minnesota jurisdictional earnings was capped at a 9.06% ROE. Any excess earnings are required to be refunded to customers.
(a)Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues and 0.5% of its state natural gas revenues on CIP. These costs are recovered through an annual cost-recovery mechanism.
(b)The MPUC changed the FCA process in Minnesota (effective in 2020). Each month, utilities collect amounts equal to baseline cost of energy set at the start of the plan year (base would be reset annually). Monthly variations to baseline costs are tracked and netted over a 12-month period. Utilities issue refunds above the baseline costs and can seek recovery of any overage.
Pending and Recently Concluded Regulatory Proceedings
2022 Minnesota Natural Gas Rate Case—In November 2021, NSP-Minnesota filed a request with the MPUC for an annual natural gas rate increase of $36 million, or 6.6%. The filing is based on a 2022 forecast test year and includes a requested ROE of 10.5%, rate base of $934 million and an equity ratio of 52.50%.
In December 2021, the MPUC approved the requested interim rates of $25 million, subject to refund, beginning on Jan. 1, 2022.
The next steps in the procedural schedule are expected to be as follows:
•Intervenor testimony: Aug. 30, 2022.
•Rebuttal testimony: Oct. 4, 2022.
•Public hearing: Nov. 1-4, 2022.
•ALJ Report: Feb. 6, 2023.
•MPUC Order: April 26, 2023.
2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. The rate case is based on a requested ROE of 10.2%, a 52.50% equity ratio and forward test years.
The request is detailed as follows:
(Amounts in Millions, Except Percentages)202220232024Total
Rate request$396 $150 $131 $677 
Increase percentage12.2 %4.8 %4.2 %21.2 %
Rate base$10,931 $11,446 $11,918 N/A
In addition, NSP-Minnesota requested interim rates, subject to refund, of $288 million to be implemented in January 2022 and an incremental $135 million to be implemented in January 2023. In December 2021, the MPUC approved rates of $247 million to begin on Jan. 1, 2022. The adjusted level reflects exigent circumstances from the COVID-19 pandemic.
The next steps in the procedural schedule are expected to be as follows:
•Intervenor testimony: Oct. 3, 2022.
•Rebuttal testimony: Nov. 8, 2022.
•Public hearing: Dec. 13-16, 2022.
•ALJ Report: March 31, 2023.
•MPUC Order: June 30, 2023.
2021 North Dakota Natural Gas Rate Case — In September 2021, NSP-Minnesota filed a request with the NDPSC for a natural gas rate increase of $7 million, or 10.49%. The filing is based on a requested ROE of 10.5%, an equity ratio of 52.54%, a 2022 forecast test year and a rate base of approximately $140 million. Interim rates of $7 million, subject to refund, were implemented on Nov. 1, 2021. An NDPSC decision is expected in early fall 2022.
The next steps in the procedural schedule are expected to be as follows:
•Intervenor testimony: March 1, 2022
•Rebuttal testimony: April 1, 2022
•Hearings: June 1-3, 2022
2020 North Dakota Electric Rate Case — In November 2020, NSP-Minnesota filed a rate case with the NDPSC seeking a rate increase of $19 million based on a ROE of 10.2%, an equity ratio of 52.5% and rate base of $677 million.
In August 2021, the NDPSC approved a settlement between NSP-Minnesota and various parties, which includes the following, effective Jan. 1, 2021:
•Base revenue increase of $7 million.
•ROE of 9.5%.
•Equity ratio of 52.5%.
•Deferral of advanced grid intelligence and security initiative capital and O&M expenses.
•An earnings cap mechanism, which would return to customers 100% of earnings equal to or in excess of 9.75% ROE, effective until the next rate case.
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Minnesota Relief and Recovery— In 2020, the MPUC opened a docket and invited utilities in the state to submit potential projects that would create jobs and help jump start the economy to offset the impacts of COVID-19.
The status of the various proposals is listed below:
•In January 2021, the MPUC approved NSP-Minnesota’s request for the repowering of 651 MW of owned wind projects and 20 MW of wind projects under PPAs. These projects are estimated to save customers approximately $160 million over the next 25 years.
•In April 2021, NSP-Minnesota proposed to add 460 MW of solar facilities at the Sherco site with an incremental investment of approximately $575 million. An MPUC decision is expected by the third quarter of 2022.
•In June 2021, the MPUC approved NSP-Minnesota’s proposal to acquire a repowered wind farm from ALLETE, Inc.
•The MPUC is also considering NSP-Minnesota’s revised proposal to provide $40 million of incremental electric vehicle rebates.
Minnesota Resource Plan—In July 2019, NSP-Minnesota filed its Minnesota resource plan, which runs through 2034.
On Feb. 8, 2022, the MPUC approved the following:
•10-year extension for the Monticello nuclear facility.
•Retirement of the A.S. King plant in 2028 and Sherco 3 in 2030.
•NSP-Minnesota ownership of Sherco and A.S. King gen-tie lines plus additional renewable resources on the lines up to its current interconnection rights (2,000 MW for Sherco and 600 MW for A.S. King).
•The need for 2,150 MW of new wind and 2,500 MW of new solar by 2032, as well as additional renewable generation of 1,100 MW beyond 2032.
•Recognition of the need for 800 MW of additional firm dispatchable resources between 2027 and 2029. The dispatchable generation will need to be approved through a CON process.
The next Minnesota resource plan is due on Feb. 1, 2024.
2022 RES Electric Rider — In November 2021, NSP-Minnesota filed the RES Rider. The requested amount of $264 million includes a true-up (2020 and 2021 riders) of $154 million and the 2022 requested amount of $110 million. The filing included a ROE of 9.06%. An MPUC decision is pending.
2021 RES Electric Rider — In November 2020, NSP-Minnesota filed the RES Rider. The requested amount of $189 million includes a true-up (2019 and 2020 riders) of $96 million and the 2021 requested amount of $93 million. The filing included a ROE of 9.06%. An MPUC decision is pending.
2022 GUIC Natural Gas Rider — In October 2021, NSP-Minnesota filed the GUIC Rider for an amount of $27 million based on a ROE of 9.04%. An MPUC decision is pending.
2021 GUIC Natural Gas Rider — In October 2020, NSP-Minnesota filed the GUIC Rider for an amount of $27 million based on a ROE of 9.04%. An MPUC decision is pending.
2022 TCR Electric Rider — In November 2021, NSP-Minnesota filed the TCR Rider for an amount of $105 million based on a ROE of 9.06%. An MPUC decision is pending.
2020 TCR Electric Rider — In November 2019, NSP-Minnesota filed the TCR Rider for an amount of $82 million based on a ROE of 9.06%, which was approved by the MPUC in December 2021.
FERC NOPR on ROE Incentive Adders — In April 2021, the FERC issued a NOPR proposing to limit collection of ROE incentive adders for RTO membership to the first three years after an entity begins participation in an RTO. If adopted as a final rule, NSP-Minnesota (as well as NSP-Wisconsin and SPS) would prospectively discontinue charging their current 50 basis point ROE incentive adders. Amounts related to a discontinuance of the adder would ultimately be offset by an increase in retail rates, subject to future rate cases.
Purchased Power Arrangements and Transmission Service Provider
NSP-Minnesota expects to use power plants, power purchases, CIP/DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements.
Purchased Power — NSP-Minnesota has contracts to purchase power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require a capacity and an energy charge.
NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost.
Purchased Transmission Services — NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers.
Nuclear Power Operations
Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes, which are covered by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. Low-level waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment contaminated through use.
NRC Regulation — The NRC regulates nuclear operations. Costs of complying with NRC requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs and expects to recover future compliance costs.
Low-Level Waste Disposal — Low level waste disposal from Monticello and PI is disposed at the Clive facility located in Utah and the Waste Control Specialists facility in Texas. NSP-Minnesota has storage capacity available on-site at PI and Monticello which would allow both plants to continue to operate until the end of their current licensed lives if off-site low-level waste disposal facilities become unavailable.
High-Level Radioactive Waste Disposal — The federal government has responsibility to permanently dispose domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. Currently, there are no definitive plans for a permanent federal storage facility site.
Nuclear Spent Fuel Storage — NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. Authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2. Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not commence storage operations.
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Monticello CON — In September 2021, NSP-Minnesota filed an application for a CON for additional spent fuel storage (existing independent spent fuel storage installation) at the Monticello Nuclear Power Generating Plant. The CON requests sufficient additional spent fuel storage at the existing independent spent fuel storage installation to allow continued operation of the Monticello Plant until 2040. The filing passed completeness review and has been referred to an ALJ. A decision is expected in late 2023.
Wholesale and Commodity Marketing Operations
NSP-Minnesota conducts wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price and credit risk and to hedge sales and purchases.
NSP-Minnesota also engages in trading activity unrelated to hedging. Sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota does not serve any wholesale requirements customers at cost-based regulated rates.
NSP-Wisconsin
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Regulatory Body / RTOAdditional Information
PSCW
Retail rates, services and other aspects of electric and natural gas operations.
Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.
The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January.
Pipeline safety compliance.
MPSC
Retail rates, services and other aspects of electric and natural gas operations.
Certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built.
Pipeline safety compliance.
FERCWholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.
MISONSP-Wisconsin is a transmission owning member of the MISO RTO that operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.
DOTPipeline safety compliance.
Recovery Mechanisms
MechanismAdditional Information
Annual Fuel Cost PlanNSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.
Power Supply Cost Recovery FactorsNSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-recoveries are refunded and any under-recoveries are collected from customers.
Wisconsin Energy Efficiency ProgramThe primary energy efficiency program is funded by the utilities, but operated by independent contractors subject to oversight by the PSCW and utilities. NSP-Wisconsin recovers these costs from customers.
Purchased Gas AdjustmentA retail cost-recovery mechanism to recover the actual cost of natural gas, transportation, and storage services.
Natural Gas Cost-Recovery Factor (MI)
MechanismAdditional Information
Annual Fuel Cost Plan (a)
NSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.
Power Supply Cost Recovery FactorsNSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-recoveries are refunded and any under-recoveries are collected from customers.
Wisconsin Energy Efficiency ProgramThe primary energy efficiency program is funded by the utilities, but operated by independent contractors subject to oversight by the PSCW and utilities. NSP-Wisconsin recovers these costs from customers.
PGANSP-Wisconsin has a retail PGA cost-recovery mechanism for Wisconsin to recover the actual cost of natural gas and transportation and storage services.
Natural Gas Cost-Recovery Factor (MI)NSP-Wisconsin’s natural gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts on an annual basis.
(a)
Pending and Recently Concluded Regulatory Proceedings
Wisconsin Electric and Natural Gas Settlement — In December 2021, the PSCW approved a rate case settlement agreement and 2022 fuel cost plan without modification. New rates and tariffs were effective Jan. 1, 2022. Key elements of the settlement:
•An increase in electric rates of $35 million (4.9%) for 2022 and an incremental $18 million increase (2.5%) for 2023.
•An increase in natural gas rates of $10 million (8.4%) for 2022 and an incremental $3 million (2.3%) for 2023.
•ROE of 9.80% for 2022 and 10.00% for 2023.
•Equity ratio of 52.5% for both 2022 and 2023.
•Returning $9 million in various net regulatory liabilities to offset customer impacts in 2023.
•Deferring certain pension and other post-employment benefit expense in 2021 through 2023.
•Incorporating an earnings sharing mechanism for 2022 and 2023.
Michigan Electric Rate Case —In January 2022, NSP-Wisconsin reached an electric rate case settlement in principle with the MPSC staff and others. The settlement grants NSP-Wisconsin an electric revenue increase of $1.6 million in 2022, based on a ROE of 9.7% and an equity ratio of 52.5%. The MPSC is expected to rule on the settlement in the first quarter of 2022.
NSP-Wisconsin’s electric fuel costs were lower than authorized in rates and outside the 2% annual tolerance band in 2019. Under the fuel cost recovery rules, NSP-Wisconsin retained the $3.3 million of over-recovered fuel costs (amounts within annual tolerance band) and deferred $9.7 million (amounts in excess of annual tolerance band) as a regulatory liability. NSP-Wisconsin plans to file a reconciliation of 2019 fuel costs with the PSCW by March 2020. 
Pending and Recently Concluded Regulatory Proceedings
MechanismUtility ServiceAmount Requested (in millions)
Filing
Date
ApprovalAdditional Information
PSCW
Rate CaseElectric & Natural GasN/AMay 2019ReceivedIn May 2019, NSP-Wisconsin filed an application with the PSCW seeking no change to base electric rates through Dec. 31, 2021; and a $3.2 million (4.6%) decrease to base natural gas rates, effective Jan. 1, 2020, and no additional changes to base natural gas rates through Dec. 31, 2021. The settlement is based on an ROE of 10.0% and an equity ratio of 52.5%. In September 2019, the PSCW issued an interim order approving the settlement agreement as filed with one minor modification, to remove the deferral of pension settlement accounting costs for 2021. A final order was received in December 2019.
Purchased Power and Transmission Services
The NSP System expects to use power plants, power purchases, conservation and DSM options, new generation facilities and expansion of power plants to meet its system capacity requirements.
Purchased Power — Through the Interchange Agreement, NSP-Wisconsin receives power purchased by NSP-Minnesota from other utilities and independent power producers. Long-term purchased power contracts for dispatchable resources typically require a capacity charge and an energy charge. NSP-Minnesota makes short-term purchases to meet system requirements, replace company owned generation, meet operating reserve obligations or obtain energy at a lower cost.
Purchased Transmission Services — NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers.
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Wholesale and Commodity Marketing Operations
NSP-Wisconsin does not serve any wholesale requirements customers at cost-based regulated rates.
PSCo
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Regulatory Body / RTOAdditional Information on Regulatory Authority
CPUC
Retail rates, accounts, services, issuance of securities and other regionalaspects of electric, natural gas and steam operations.
Pipeline safety compliance.
FERC
Wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission service providersof 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 deliver powercustomers inside PSCo’s balancing authority area and energyat market-based prices to their customers.
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.
Wholesale
RTOPSCo is not presently a member of an RTO and Commodity Marketing Operations
NSP-Wisconsin does not serve any wholesale requirements customers at cost-based regulated rates.

PSCo
Summary of Regulatory Agencies /operate within an RTO energy market. However, PSCo does make certain sales to other RTO’s, including SPP and Areas of Jurisdiction
participates in a joint dispatch agreement with neighboring utilities.
DOT
Regulatory Body / RTOAdditional Information
CPUC
Retail rates, accounts, services, issuance of securities and other aspects of electric and natural gas 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.
RTOPSCo 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.
DOTPipeline safety compliance.
SPP Western Energy Imbalance Service MarketBalances generation and load regionally and in real time for participants in the Western Interconnection
Recovery Mechanisms
Recovery Mechanisms
MechanismAdditional Information
ECARecovers fuel and purchased energy costs. Short-term sales margins are shared with customers. The ECA is revised quarterly.
Purchased Capacity Cost AdjustmentRecovers purchased capacity payments.
Steam Cost AdjustmentRecovers fuel costs to operate the steam system. The Steam Cost Adjustment rate is revised quarterly.
DSM Cost AdjustmentRecovers electric and gas DSM, interruptible service costs and performance initiatives for achieving energy savings goals.
RES AdjustmentRecovers the incremental costs of compliance with the RES with a maximum of 1% of the customer’s bill.
Colorado Energy Plan AdjustmentRecovers the early retirement costs of Comanche units 1 and 2 to a maximum of 1% of the customer’s bill.
Wind Cost AdjustmentRecovers costs for customers who choose renewable resources.
Transmission Cost AdjustmentRecovers costs for transmission investment between rate cases.
Clean Air Clean Jobs ActRecovers costs associated with the Clean Air Clean Jobs Act.
FCAPSCo 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.
GCARecovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates.
PSIA
MechanismAdditional Information
ECARecovers fuel and purchased energy costs. Short-term sales margins are shared with customers through the ECA. The ECA is revised quarterly.
PCCARecovers purchased capacity payments.
SCARecovers difference between actual fuel costs and costs recovered under steam service rates. The SCA rate is revised quarterly.
DSMCARecovers DSM, interruptible service costs and performance initiatives for achieving energy savings goals.
RESARecovers the incremental costs of compliance with the RES with a maximum of 2% of the customer’s bill.
WCARecovers costs for customers who choose renewable resources.
TCARecovers costs for transmission investment outside of rate cases.
CACJARecovers costs associated with the CACJA.
FCAPSCo 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.
GCARecovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates.
PSIARecovers costs for transmission and distribution pipeline integrity management programs.
Pending
DecouplingMechanism to true-up revenue to a baseline amount for residential (excluding lighting and Recently Concluded Regulatory Proceedings
MechanismUtility ServiceAmount Requested (in millions)
Filing
Date
ApprovalAdditional Information
CPUC
Rate CaseSteam$7January 2019ReceivedIn September 2019, the CPUC approved PSCo’s Settlement Agreement with CPUC Staff and the City of Denver. The settlement reflects an ROE of 9.67% for AFUDC purposes, an equity ratio of 56.04% and utilization of tax reform benefits. The first stepped increase went into effect Oct. 1, 2019, with full rates effective Oct. 1, 2020.
Rate Case AppealNatural GasN/AApril 2019PendingIn April 2019, PSCo filed an appeal seeking judicial review of the CPUC’s prior ruling regarding PSCo’s last natural gas rate case (approved in December 2018). Appeal requests review of the following: denial of a return on the prepaid pension and retiree medical assets; the use of a capital structure that is not based on the actual historical test year level; and the use of an average rate base methodology rather than a year-end rate base methodology. Timeline on a final ruling is unknown.
DSM IncentiveElectric & Natural Gas$12April 2019ReceivedPSCo earned an electric and natural gas DSM incentive of $9 million and $3 million, respectively, for achieving its 2018 savings goals.demand) and metered non-demand small C&I classes.

PSCo — Electric Rate Case —Transportation Electrification Plan In October 2019, PSCo filed rebuttal testimonyRecovers costs associated with the CPUC requestinginvestment in and adoption of transportation electrification infrastructure.
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 increase of $108 million. This is based on a $353 million increase offset by $245 million of previously authorized costs currently recovered through various rider mechanisms. The request was based on a ROE of 10.20%, an equity ratio of 55.61%case:
Plant related investments (a)
$210 
Operations and a current test year, which includes certain forecasted plant additions through December 2019.
In December 2019, the CPUC held deliberations and on Feb. 11, 2020 issued a written decision approving a current test year ended Aug. 31, 2019, a 9.3% ROE, an equity ratio of 55.61%, implementation of decoupling in 2020maintenance, amortization and other items. This resulted in an estimated $35 million net base rate revenue increase.
Revenue Request (Millions of Dollars) 2020
Company filed rebuttal $353
ROE (55)
Impact of change in test year (17)
Property tax expense 15
Rate base adjustments (11)
Capital structure (5)
     Total proposed revenue change 280
Estimated impact of previously authorized costs (existing riders) 245
Net revenue change $35

Final rates are expected to be implemented in February 2020. PSCo currently intends to file an application for rehearing/reconsideration in the first quarter of 2020.
expenses
PSCo — Gas Rate Case —11 
On Feb. 5, 2020, PSCo filed a request with the CPUC seeking a netProperty tax expense11 
Sales growth(17)
Net increase to retail gas ratesrevenue215
Previously authorized costs:
Transfer of $127 million, reflecting a $145 million increase in base rate revenue, which is partially offset by $18 millioncosts previously authorizedrecovered through the PSIA rider mechanism. The(108)
Total base revenue request is based on a test year that incorporates actual capital and expenses as of Sept. 30, 2019, adjusted for known and measurable differences for the 12-month period ended Sept. 30, 2020, a 9.95% ROE and an equity ratio of 55.81%. Proposed effective date is Nov. 1, 2020.
Revenue Request (Millions of Dollars) 2020
Capital additions (through Sept. 30, 2019) $62
Forecasted capital additions (through Sept. 30, 2020) 33
Sales growth (includes amounts forecasted through Sept. 30, 2020) (29)
Operations and maintenance, amortization and other expenses 29
Property tax expense 19
Cost of capital 8
Updated depreciation rates 5
Net increase to revenue 127
Previously authorized costs:  
Transfer PSIA rider costs to base rates 18
Total base request $145
   
Expected year-end rate base $2,236
The request reflects $1.3 billion of capital additions since the 2016 test year used to set current rates. Capital investments are made to maintain the safety and reliability of the natural gas system, along with investments to connect new customers and perform mandated infrastructure relocation work.
Timing of a CPUC ruling is expected in the second half of 2020.
Resource Plan
CEP $107— In September 2018, the CPUC approved PSCo’s CEP portfolio, which included the retirement of two coal-fired generation units, Comanche Unit 1 (in 2022) and Comanche Unit 2 (in 2025), and the following additions:
Projected 2022 year-end rate base (billions of dollars)$3.6
Total CapacityPSCo's Ownership
Wind generation1,100 MW500 MW
Solar generation700 MW—
Battery storage275 MW—
Natural gas generation380 MW380 MW
PSCo’s investment is expected to be approximately $1 billion, including transmission to support the increase in renewable generation.
CPCNs were granted by the CPUC for the Shortgrass Substation in February 2019, and for the 500 MW Cheyenne Ridge wind farm and 345 KV generation tie line in April 2019.
A CPCN for the acquisitions of the Valmont and Manchief natural gas generation facilities was filed in July 2019, and a settlement on those acquisitions was reached with CPUC Staff and the Colorado Office of Consumer Counsel in January 2020, pending a CPUC decision expected in approximately the second quarter of 2020.
A CPCN for voltage control facilities was also filed with the CPUC in December 2019, with another expected to follow in approximately the first quarter of 2020 for network transmission upgrades required for the CEP portfolio.
(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.
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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.
•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.
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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 onthe 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.
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.
Boulder Municipalization
In 2011, Boulder passed a ballot measure authorizing the formation of an electric municipal utility, subject to certain conditions. Subsequently, there have been various legal proceedings in multiple venues with jurisdiction over Boulder’s plan. In 2014, the Boulder City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility and the Colorado Court of Appeals ruled in PSCo’s favor, vacating a lower court decision. In June 2018, the Colorado Supreme Court rejected Boulder’s request to dismiss the case and remanded it to the Boulder District Court. The case was then settled in June 2019 after Boulder agreed to repeal the ordinance establishing the utility.
Boulder has filed multiple separation applications with the CPUC, which have been challenged by PSCo and other intervenors. In September 2017, the CPUC issued a written decision, agreeing with several key aspects of PSCo’s position. The CPUC has approved the designation of some electrical distribution assets for transfer, subject to Boulder completing certain filings.
In the fourth quarter of 2018, the Boulder City Council also adopted an Ordinance authorizing Boulder to begin negotiations for the acquisition of certain property or to otherwise condemn that property after Feb. 1, 2019. In the first quarter of 2019, Boulder sent PSCo a notice of intent to acquire certain electric distribution assets. In the third quarter of 2019, Boulder filed its condemnation litigation, which was later dismissed by the Boulder District Court in September 2019 on the grounds that Boulder had not completed the pre-requisite CPUC process and filings. Boulder is currently appealing this order. In October 2019, the CPUC approved the subsequent filings regarding asset transfers outside of substations, reaffirmed its 2017 decision on assets outside of substations and closed the CPUC proceeding.
In December 2019, Boulder filed a new condemnation action despite its ongoing appeal of the last condemnation case. PSCo subsequently filed a motion to dismiss or stay the new condemnation action. In February 2020, Boulder filed an application under section 210 of the Federal Power Act asking FERC to order PSCo to interconnect its facilities with a future Boulder municipal utility under Boulder’s preferred terms and conditions.
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 JOA.
joint operating agreement.

SPS
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Regulatory Body / RTOAdditional Information
PUCT
Retail electric operations, rates, services, construction of transmission or generation and other aspects of SPS’ electric operations.
The municipalities in which SPS operates in Texas have original jurisdiction over rates in those communities. The municipalities’ rate setting decisions are subject to PUCT review.
NMPRCRetail electric operations, retail rates and services and the construction of transmission or generation.
FERCWholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce.
SPP RTO and SPP IMIntegrated and Wholesale MarketMarketsSPS is a transmission-owningtransmission owning member of the SPP RTO and operates within the SPP RTO and SPP IMintegrated and wholesale market.markets. SPS is authorized to make wholesale electric sales at market-based prices.
Recovery Mechanisms
MechanismAdditional Information
DCRFDistribution Cost Recovery FactorRecovers distribution costs not included in rates in Texas.
EECRFEnergy Efficiency Cost Recovery FactorRecovers costs for energy efficiency programs in Texas.
Energy Efficiency RiderRecovers costs for energy efficiency programs in New Mexico.
FPPCACFuel and Purchased Power Cost Adjustment Clause
Adjusts monthly to recover actual fuel and purchased power costs in New Mexico. In October 2019, SPS filed an application to the NMPRC to approve SPS’ continued use of its FPPCAC and for reconciliation of fuel costs for the period Sept. 1, 2015, through June 30, 2019, which will determine whether all fuel costs incurred are eligible for recovery. No procedural schedule has yet been established for this matter.
PCRFPower Cost Recovery FactorAllows recovery of purchased power costs not included in Texas rates.
RPSRenewable Portfolio StandardsRecovers deferred costs for renewable energy programs in New Mexico.
TCRFTCR FactorRecovers certain transmission infrastructure improvement costs and changes in wholesale transmission charges not included in Texas base rates.
Fixed Fuel and Purchased Recovery FactorProvides for the over- or under-recovery of energy expenses.expenses in Texas. Regulations require refunding or surcharging over- or under- recovery amounts, including interest, when they exceed 4% of the utility’s annual fuel and purchased energy costs on a rolling 12-month basis if this condition is expected to continue.
Wholesale Fuel and Purchased Energy Cost AdjustmentSPS recovers fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased energy cost adjustment clause accepted by the FERC. Wholesale customers also pay the jurisdictional allocation of production costs.
Pending and Recently Concluded Regulatory Proceedings
MechanismUtility ServiceAmount Requested (in millions)
Filing
Date
ApprovalAdditional Information
SPS (NMPRC)
Rate CaseElectric$51July 2019Pending
In July 2019, SPS filed an electric rate case with the NMPRC seeking an increase in retail electric base rates of approximately $51 million. The rate request is based on an ROE of 10.35%, an equity ratio of 54.77%, a rate base of approximately $1.3 billion and a historic test year with rate base additions through Aug. 31, 2019. In December 2019, SPS revised its base rate increase request to approximately $47 million, based on an ROE of 10.10% and updated information. The request also included an increase of $14.6 million for accelerated depreciation including the early retirement of the Tolk Coal Plant in 2032.
On Jan. 13, 2020, SPS and various parties filed an uncontested comprehensive stipulation. The stipulation includes a base rate revenue increase of $31 million, based on an ROE of 9.45% and an equity ratio of 54.77%. The stipulation also includes an acceleration of depreciation on the Tolk Coal Plant to reflect early retirement in 2037, which results in a total increase in depreciation expense of $8 million. The Signatories will not oppose the full application of depreciation rates associated with the 2032 retirement date in SPS’ next base rate case. SPS anticipates final rates will go into effect in the second or third quarter of 2020.

SPS — Texas2021 New Mexico Electric Rate Case — In January 2021, SPS filed an electric rate case with the NMPRC with a current requested base rate increase of approximately $84 million.
In August 2019,June 2021, SPS and various parties filed an uncontested stipulation with the NMPRC, which reflected a $62 million rate increase, a change in the depreciation life of the Tolk coal plant to 2032, an equity ratio of 54.72% and ROE of 9.35% for reconciliation statements and determining the revenue requirements for the Sagamore and Hale wind projects. In December 2021, the Hearing Examiner issued a recommendation that the NMPRC approve the rate case settlement agreement without modification.
On Feb. 2, 2022, the NMPRC voted 3-2 to reject the uncontested stipulation as filed. The NMPRC then approved a modified settlement, which would maintain the proposed revenue requirement increase of $62 million, but would adjust the class cost allocation such that all rate classes would have a uniform increase of 4.89%. The NMPRC required the parties to either file their acceptance or opposition to the modified settlement.
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On Feb. 9, 2022, the signatories informed the NMPRC they did not unanimously support the modifications. Accordingly, the Hearing Examiner will issue a procedural order for further proceedings on SPS’ originally filed application.
On Feb. 10, 2022, SPS filed a motion requesting the NMPRC either approve the original settlement or approve the modified settlement.
On Feb. 16, 2022, the NMPRC voted to reconsider its order and voted 3-2 to approve the stipulation without modification. New rates will go into effect on Feb. 26, 2022.
2021 Texas Rate Case — In February 2021, SPS filed an electric rate case with the PUCT and its municipalities, seeking an increase in retail electric base rates of approximately $141$140 million. SPS’ proposed net rate increase to Texas customers was approximately $71 million, or 9.2%, as a result of the offsetting $69 million in fuel cost reductions and PTCs from the Sagamore wind project.
The filing requests anrequest was based on a ROE of 10.35%, a 54.65%an equity ratio of 54.60%, a rate base of approximately $2.6$3.3 billion and is builta historic test year based on the 12-month period ended Dec. 31, 2020. The request included the effect of losing approximately 400 MW from a 12 month period that ended June 30, 2019. wholesale transmission customer and changes to depreciation lives of SPS’ Tolk power plant (from 2037 to 2032) and coal handling assets at the Harrington facility (to 2024).
In September 2019,January 2022, SPS and intervenors filed a blackbox settlement. Key terms include:
•A base rate increase of approximately $89 million effective back to March 15, 2021.
•A 9.35% ROE and 7.01% weighted average cost of capital for AFUDC purposes only.
•The depreciation lives for Tolk moved up to 2034 and Harrington coal assets moved up to 2024.
In February 2022, the ALJ issued an update to the electric rate case and revised its requested increase to approximately $137 million.
On Feb. 10, 2020, the Alliance of Xcel Municipalities (AXM), Texas Industrial Energy Consumers (TIEC), Office of Public Utility Counsel (OPUC) and Department of Energy (DOE) filed testimony along with several other parties.
On Feb. 18, 2020, the PUCT Staff filed testimony that included certain adjustments and various ring-fencing measures.
Proposed modifications to SPS’ request:
(Millions of Dollars) Staff AXM OPUC TIEC DOE
SPS Direct Testimony $137
 $137
 $137
 $137
 $137
           
Recommended base rate adjustments:        
ROE (22) (24) (15) (21) (24)
Capital structure (7) (10) —
 (7) (3)
Tolk/Harrington O&M disallowance —
 (7) —
 —
 —
Distribution and Transmission Capital Disallowances (a)
 (7) —
 —
 —
 —
Depreciation expense (8) (15) (8) (20) —
Excess ADIT unprotected plant —
 —
 (7) —
 —
Income Tax Expense Differences (12) —
 —
 —
 —
Other, net (6) (6) (1) (1) —
Total Adjustments (62) (62) (31) (49) (27)
Total proposed revenue change $75
 $75
 $106
 $88
 $110

Recommended Position Staff AXM 
OPUC (b)
 TIEC DOE
ROE 9.1% 9.0% —% 9.2% 9.0%
Equity Ratio 51.00% 50.00% —% 51.00% 53.00%
(a)
Staff recommends exclusion of approximately $134 million in transmission, distribution, and general plant in service in this rate case resulting in an approximate $7 million decrease to the revenue requirement.
(b)
OPUC did not provide a recommendation for an ROE or equity ratio. For illustrative purposes an ROE of 9.5% was used.
The next steps in the procedural schedule are expectedorder approving interim rates to be as follows:
Rebuttal testimony —effective on March 11, 2020; and
Public hearing begins — March 30, 2020
1, 2022. A PUCT decision and implementation of final rates is anticipated in the third quarter of 2020.
Resource Plan
In December 2018, the NMPRC issued a final order accepting SPS’ IRP.
SPS is forecasting a surplus capacity of 382 MW in 2028, but a capacity deficit of approximately 2,896 MW in 2038. SPS’ optimal resource plan for the planning period incorporates the addition of wind, simple cycle combustion turbine generation, combined cycle energy and entering PPAs. Various factors may impact this IRP, which could potentially require updates to the action plan and will be the subject of future IRPs, including:
New and revised environmental regulations;
Impacts of variability due to participation in the SPP;
Customer expectations;
Technological advances;
Groundwater aquifer depletion at SPS’s Tolk Station;
Aging generation fleet;
Load growth and gas price variability;
Changes to tax credits and incentives; and
Changes to renewable portfolio standard acquisitions.
SPS is required to file an IRP in New Mexico every three years and will file its next IRP in July 2021.
Texas State ROFR
In May 2019, the Governor signed into law Senate Bill 1938, which grants incumbent utilities a ROFR to build transmission infrastructure when it directly interconnects to the utility’s existing facility. In June 2019, a complaint was filed in the United States District Court for the Western District of Texas claiming the new ROFR law to be unconstitutional. The Texas Attorney General has made a motion to dismiss the federal court complaint. A ruling on the dismissal motion is expected in the first quarter of 2020.2022.
Purchased Power Arrangements and Transmission Service Providers
SPS expects to use electric generating stations, power purchases, DSM and new generation options to meet its system capacity requirements.
Purchased Power — SPS purchases power from other utilities and IPPs. Long-term purchased power contracts typically require periodic capacity and energy charges. SPS also makes short-term purchases to meet system load and energy requirements to replace owned generation, meet operating reserve obligations or obtain energy at a lower cost.
Purchased Transmission Services — SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers.
Natural Gas
SPS does not provide retail natural gas service, but purchases and transports natural gas for its generation facilities and operates limited natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines. SPS is subject to the jurisdiction of the FERC with respect to natural gas transactions in interstate commerce and the PHMSA and PUCT for pipeline safety compliance.
Wholesale and Commodity Marketing Operations
SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. SPS uses physical and financial instruments to minimize commodity price and credit risk and to hedge sales and purchases.
Other Public Utility Matters
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, Xcel Energy incurred net natural gas, fuel and purchased energy costs of approximately $1 billion (largely deferred as regulatory assets).
Regulatory Overview —Xcel Energy 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 63 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.
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Proceedings initiated:
Utility SubsidiaryJurisdictionRegulatory Status
NSP-MinnesotaMinnesotaNSP-Minnesota filed with the MPUC seeking recovery of $215 million in incremental costs from natural gas customers. In August 2021, the MPUC allowed recovery of $179 million of costs deemed to be extraordinary beginning in September 2021 over 27 months (no financing charge) and $36 million of ordinary costs over 12 months through the monthly Purchased Gas Adjustment. The $179 million in extraordinary cost recovery is subject to refund pending the outcome of a contested case before an ALJ.

In December 2021, the MPUC approved extending recovery of Winter Storm Uri costs for the residential class (approximately $97 million) from a 27-month recovery period to a 63-month recovery period. New residential Winter Storm Uri rates were effective Jan. 1, 2022.

In December 2021, direct testimony was received from intervenors. The DOC recommended a $127 million disallowance based on allegations including peaking plant usage, load forecasting, natural gas supply/storage and related purchases. Alternatively, the DOC recommended a $42 million disallowance if NSP-Minnesota proves it prudently managed its peaking plants. The OAG recommended a disallowance of $179 million based on allegations that NSP-Minnesota could have fully hedged its exposure to spot market prices. Alternatively, the OAG recommended a $25 million disallowance based on allegations related to specific hedges allegedly available in the market during February 2021. The CUB recommended a $69 million disallowance based on allegations related to the unavailability of NSP-Minnesota’s peaking plants, inaccuracy of load forecasting and inadequate curtailment of interruptible customers.

Xcel Energy strongly disagrees with the recommendations of the DOC, OAG and CUB and believes that it acted prudently and according to MPUC approved procedures for the best interest of its customers and stakeholders. NSP-Minnesota filed rebuttal testimony in January 2022. A hearing before the ALJs assigned to the matter is scheduled for Feb. 17-23, 2022. An MPUC decision is expected in the summer of 2022.

See Rate Matters and Other within Note 12 to the consolidated financial statements for further information.
South DakotaWinter Storm Uri had no impact on South Dakota electric costs as NSP-Minnesota was a net seller in the electric market.
North DakotaIn June, the NDPSC approved recovery of $32 million in natural gas costs over 15 months (starting July 2021) with no financing charge.
NSP-WisconsinWisconsinIn March, the PSCW approved NSP-Wisconsin’s proposal to recover $45 million of Winter Storm Uri natural gas costs over nine months through December 2021 with no financing charge.
MichiganIn May, the MPSC approved recovery of $2 million in natural gas costs over 10 months with no financing charge.
PSCoColoradoIn 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.
SPSTexas
As part of the Texas fuel surcharge filing, SPS filed for recovery of $76 million, over 24 months, in under-collected purchased power and fuel costs through March 2021, subject to revision due to re-settlements. Of this amount, $62 million was attributed to Winter Storm Uri.

In the third quarter, SPS filed a supplemental application and testimony to recover an additional $26 million in under-collected purchased power and fuel costs through June 2021 resulting primarily from SPP resettlements and continued increases in natural gas prices.

In November 2021, the ALJ abated the hearing schedule to allow the parties to continue settlement negotiations.

In December 2021, SPS filed its triennial Fuel Reconciliation, under which the PUCT will consider prudence of SPS’ fuel costs for the period July 2018 - June 2021, including Winter Storm Uri.

In January 2022, SPS and other parties filed a stipulation/motion for interim rates. The filing covers all fuel under-collections occurring between January 2020 and August 2021, totaling $121 million. The settlement does not address the prudence of Winter Storm Uri costs nor the retention of $11 million related to market sales during the event. These items will be reviewed through the triennial Fuel Reconciliation proceeding and are subject to a final PUCT decision. Interim rates, designed to collect up to $110 million over a period of 30 months, will begin on Feb. 1, 2022.
New MexicoIn March 2021, the NMPRC approved SPS' request to recover $26 million of fuel costs over 24 months with no financing charge, subject to NMPRC review.

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Potential Tax Reform
The U.S. Congress is currently discussing potential proposals that may impact federal tax law. At this time, it is unknown what, if any, changes may ultimately occur. Based on provisions passed by the U.S. House of Representatives in November 2021, known as the Build Back Better Act, if any of such provisions were to be enacted into law, we would not expect the impact of such changes to have a material impact on our earnings.
Critical Accounting Policies and Estimates
Preparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported.
Accounting policies and estimates that are most significant to Xcel Energy’s results of operations, financial condition or cash flows, and require management’s most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.’s Board of Directors on a quarterly basis.
Regulatory Accounting
Xcel Energy is subject to the accounting for Regulated Operations, which provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows.
Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income.
Each reporting period we assess the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital, and may materially impact our results of operations, financial condition or cash flows.
As of Dec. 31, 20192021 and 2018,2020, Xcel Energy recordedhad regulatory assets of $3.4$3.8 billion and $3.8$3.4 billion, respectively and regulatory liabilities of $5.5$5.7 billion and $5.6 billion, respectively. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If future recovery of costs in any such jurisdiction is no longer probable, Xcel Energy would be required to charge these assets to current net income or other comprehensive income. In
At Dec. 31, 2021, in assessing the probability of recovery of recognized regulatory assets, unless otherwise disclosed, Xcel Energy noted no current or anticipated proposals or changes in the regulatory environment that it expects will materially impact the probability of recovery of the assets.
See NoteNotes 4 and 12 to the consolidated financial statements for further information.

Income Tax Accruals
Judgment, uncertainty and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of the ETR.
Changes in tax laws and rates may affect recorded deferred tax assets and liabilities and our future ETR. ETR calculations are revised every quarter based on best available year-end tax assumptions, adjusted in the following year after returns are filed. The taxTax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.
In accordance with the interim period reporting guidance, income tax expense for the first three quarters in a year is based on the forecasted annual ETR. The forecasted ETR reflects a number of estimates, including forecasted annual income, permanent tax adjustments and tax credits.
Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized based on an evaluation of expected future taxable income. Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized. We may adjust our unrecognized tax benefits and interest accruals as disputes with the IRS and state tax authorities are resolved, and as new developments occur. These adjustments may increase or decrease earnings.
See Note 7 to the consolidated financial statements for further information.
Employee Benefits
We sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed.
At Dec. 31, 2019,2021, Xcel Energy set the rate of return on assets used to measure pension costs at 6.87%6.49%, which is consistent with the rate set in 2018.2020. The rate of return used to measure postretirement health care costs is 4.50%4.10% at Dec. 31, 2019,2021, which represents a 80 basis point decrease from 2018. is consistent with the rate set in 2020.
Xcel Energy’s pension investment strategy is based on plan-specific investments that seek to minimize investment and interest rate risk as a plan’s funded status increases over time. This strategy results in a greater percentage of interest rate sensitive securities being allocated to plans with a higher funded status ratios and a greater percentage of growth assets being allocated to plans having a lower funded status ratios.
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Xcel Energy set the discount rates used to value the pension obligations at 3.49%3.08% and postretirement health care obligations at 3.47%3.09% at Dec. 31, 2019.2021. This represents a 8237 basis point and 8544 basis point decrease, respectively, from 2018.2020. Xcel Energy uses a bond matching study as its primary basis for determining the discount rate used to value pension and postretirement health care obligations. The bond matching study utilizes a portfolio of high grade (Aa or higher) bonds that matches the expected cash flows of Xcel Energy’s benefit plans in amount and duration.
The effective yield on this cash flow matched bond portfolio determines the discount rate for the individual plans. The bond matching study is validated for reasonableness against the Merrill Lynch Corporate 15+ Bond Index. In addition, Xcel Energy reviews general actuarial survey data to assess the reasonableness of the discount rate selected.
If Xcel Energy were to use alternative assumptions, a 1% change would result in the following impact on 20192021 pension costs:
 Pension CostsPension Costs
(Millions of Dollars) +1% -1%(Millions of Dollars)+1%-1%
Rate of return $(16) $18
Rate of return$(13)$23 
Discount rate (a)
 (5) 9
Discount rate (a)
$1 $15 
(a)
(a)These costs include the effects of regulation.
These costs include the effects of regulation.
Mortality rates are developed from actual and projected plan experience for pension plan and postretirement benefits. Xcel Energy’s actuary conducts an experience study periodically as part of the process to determine an estimate of mortality. Xcel Energy considers standard mortality tables, improvement factors and the plans actual experience when selecting a best estimate.
As of Dec. 31, 2019,2021, the initial medical trend cost claim assumptions for Pre-65 was 6.0%5.3% and Post-65 was 5.1%4.9%. The ultimate trend assumption remained at 4.5% for both Pre-65 and Post-65 claims costs. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost experienced by Xcel Energy’s retiree medical plan.
A 1% changeFunding contributions in the assumed health care cost trend rate would have the following effects on Xcel Energy:
  Accumulated Postretirement Benefit Obligation Service and Interest Components
(Millions of Dollars) +1% -1% +1% -1%
Health care cost trend $51 $(43) $2 $(2)
Funding requirements in 20202021 were $150$131 million and are expected to decline in the following years. Investment returns exceeded assumed levels in 20172021, 2020 and 2019 and were below assumed levels in 2018.2019.
The pension cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value is determined by adjusting the fair market value of assets at the beginning of the year to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20% per year. As differences between actual and expected investment returns are incorporated into the market-related value, amounts are recognized in pension cost over the expected average remaining years of service for active employees (approximately 1213 years in 2019)2021).
Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be $104$77 million in 20202022 and $90$60 million in 2021,2023, while the actual pension costs were $115$121 million in 20192021 and $141$117 million in 2018.2020. The expected decrease in 20202022 and future year costs is primarily due to the reductions in loss amortizations.

Pension funding contributions across all four of Xcel Energy’s pension plans, both voluntary and required, for 20172019 - 2020:2022:
•$50 million in January 2022.
•$131 million in 2021.
•$150 million in January 2020;2020.
•$154 million in 2019;
$150 million in 2018; and
$162 million in 2017.2019.
Future amounts may change based on actual market performance, changes in interest rates and any changes in governmental regulations. Therefore, additional contributions could be required in the future.
Xcel Energy contributed $15 million, $11 million and $20$15 million during 2019, 20182021, 2020 and 2017,2019, respectively, to the postretirement health care plans. Xcel Energy expects to contribute approximately $10$9 million during 2020.2022. Xcel Energy recovers employee benefits costs in its utility operations consistent with accounting guidance with the exception of the areas noted below.
•NSP-Minnesota recognizes pension expense in all regulatory jurisdictions using the aggregate normal cost actuarial method. Differences between aggregate normal cost and expense as calculated by pension accounting standards are deferred as a regulatory liability;liability.
•In 2018,2021, the PSCW approved NSP-Wisconsin’s request for deferred accounting treatment of the 20182021 pension settlement accounting expense;expense. In addition, the Commission order approved escrow accounting treatment for pension and other post-employment benefit expenses.
•Regulatory Commissions in Colorado, Texas, New Mexico and FERC jurisdictions allow the recovery of other postretirement benefit costs only to the extent that recognized expense is matched by cash contributions to an irrevocable trust. Xcel Energy has consistently funded at a level to allow full recovery of costs in these jurisdictions;jurisdictions.
•PSCo and SPS recognize pension expense in all regulatory jurisdictions based on expense consistent with accounting guidance.GAAP. The Texas and Colorado electric retail jurisdictions and the Colorado gas retail jurisdiction, each record the difference between annual recognized pension expense and the annual amount of pension expense approved in their last respective general rate case as a deferral to a regulatory asset; andasset.
•In 2018, PSCo was required to create a regulatory liability to adjust postretirement health care costs to zero in order to match the amounts collected in rates in the Colorado Gas retail jurisdiction. In 2020, this requirement was extended to the Colorado Electric retail jurisdiction.
See Note 11 to the consolidated financial statements for further information.
Nuclear Decommissioning
Xcel Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Xcel Energy estimates the fair value of its AROs using present value techniques, in which it makes assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. When the CompanyXcel Energy revises any assumptions, it adjusts the carrying amount of both the ARO liability and related long-lived asset. ARO liabilities are accreted to reflect the passage of time using the interest method.
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A significant portion of Xcel Energy’s AROs relates to the future decommissioning of NSP-Minnesota’s nuclear facilities. The nuclear decommissioning obligation is funded by the external decommissioning trust fund. Difference between regulatory funding (including depreciation expense less returns from the external trust fund) and expense recognized is deferred as a regulatory asset. The amounts recorded for AROs related to future nuclear decommissioning were $2.1 billion in 20192021 and $2.0 billion in 2018.2020.
NSP-Minnesota obtains periodic independent cost studies in order to estimate the cost and timing of planned nuclear decommissioning activities. Estimates of future cash flows are highly uncertain and may vary significantly from actual results. NSP-Minnesota is required to file a nuclear decommissioning filing every three years. The filing covers all expenses for the decommissioning of the nuclear plants, including decontamination and removal of radioactive material.
The most recentcurrently approved triennial filing was approvedordered by the MPUC in January 2019. This approval did not result in a change to the ARO liability. In December 2019,2020, the MPUC ordered Xcel Energy to maintain the current accrual through 20202021 to align with the approved one year stay out of the previously filed three-yearmulti-year electric rate case. Also, in December 2020, Xcel Energy will evaluatefiled an accrual proposal with the scenarios and potentially propose a new accrual startingMPUC to be effective in 2022 when it submitsbased on an updated independent cost study. In December 2021, Xcel Energy submitted its petition for approval of the next triennial2022-2024 NSP-Minnesota’s Nuclear Decommission Study and Assumptions. Xcel Energy anticipates the MPUC to deliberate on this filing in December 2020.February 2022.
The following assumptions have a significant effect on the estimated nuclear obligation:
Timing — Decommissioning cost estimates are impacted by each facility’s retirement date and timing of the actual decommissioning activities. Estimated retirement dates coincide with the expiration of each unit’s operating license with the NRC (i.e., 2030 for Monticello and 2033 and 2034 for PI’s Unit 1 and 2, respectively). The estimated timing of the decommissioning activities is based upon the DECON method (required by the MPUC), which assumes prompt removal and dismantlement. The use of the DECON method is required by the MPUC. Decommissioning activities are expected to begin at the end of the license date and be completed for both facilities by 2091.
Technology and Regulation — There is limited experience with actual decommissioning of large nuclear facilities. Changes in technology, experience and regulations could cause cost estimates to change significantly.
Escalation Rates — Escalation rates represent projected cost increases due to general inflation and increases in the cost of decommissioning activities. NSP-Minnesota used an escalation rate of 3.4%3.2% in calculating the ARO for nuclear decommissioning of its nuclear facilities, based on the weighted averages of labor and non-labor escalation factors calculated by Goldman Sachs Asset Management.
Discount Rates — Changes in timing or estimated cash flows that result in upward revisions to the ARO are calculated using the then-current credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect when the change occurs is used to discount the revised estimate of the incremental expected cash flows of the retirement activity.
If the change in timing or estimated expected cash flows results in a downward revision of the ARO, the undiscounted revised estimate of expected cash flows is discounted using the credit-adjusted risk-free rate in effect at the date of initial measurement and recognition of the original ARO. Discount rates ranging from approximately 4%3% to 7% have been used to calculate the net present value of the expected future cash flows over time.
Significant uncertainties exist in estimating future costs including the method to be utilized, ultimate costs to decommission and planned method of disposing spent fuel. If different cost estimates, life assumptions or cost escalation rates were utilized, the AROs could change materially.
However, changes in estimates have minimal impact on results of operations as NSP-Minnesota expects to continue to recover all costs in future rates.

The CompanyXcel Energy continually makes judgments and estimates related to these critical accounting policy areas, based on an evaluation of the assumptions and uncertainties for each area. The information and assumptions of these judgments and estimates will be affected by events beyond the control of Xcel Energy, or otherwise change over time. This may require adjustments to recorded results to better reflect updated information that becomes available. The accompanying financial statements reflect management’s best estimates and judgments of the impact of these factors as of Dec. 31, 2019.2021.
See Note 12 to the consolidated financial statements for further information.
Derivatives, Risk Management and Market Risk
We are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk.
Xcel Energy is also exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform under the contracts underlying its derivatives, the contracts expose us to certainsome credit and non-performance risk.
Distress in the financial markets may impact counterparty risk, the fair value of the securities in the nuclear decommissioning fund and pension fund and Xcel Energy’s ability to earn a return on short-term investments.
Commodity Price Risk — We are exposed to commodity price risk in theirour electric and natural gas operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows itus to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.
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Wholesale and Commodity Trading Risk — Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by itsour risk management committee.
Fair value of net commodity trading contracts as of Dec. 31, 2019:2021:
Futures / Forwards Maturity
(Millions of Dollars)
Less Than
1 Year
1 to 3 Years4 to 5 Years
Greater Than
5 Years
Total
Fair Value
NSP-Minnesota (a)
$(4)$(7)$— $(1)$(12)
NSP-Minnesota (b)
(1)3 (9)(8)(15)
PSCo (a)
6 6 1 1 14 
PSCo (b)
(37)(48)— — (85)
$(36)$(46)$(8)$(8)$(98)
Futures / Forwards MaturityOptions Maturity
(Millions of Dollars) 
Less Than
1 Year
 1 to 3 Years 4 to 5 Years 
Greater Than
5 Years
 
Total
Fair Value
(Millions of Dollars)
Less Than
1 Year
1 to 3 Years4 to 5 Years
Greater Than
5 Years
Total Fair Value
NSP-Minnesota (a)
 $(1) $2
 $2
 $3
 $6
NSP-Minnesota (b)
 2
 (3) (2) (10) (13)
NSP-Minnesota (b)
$1 $— $— $8 $9 
PSCo (b)
 (4) (22) (31) —
 (57)
PSCo (b)
27 29 — — 56 
 $(3) $(23) $(31) $(7) $(64)$28 $29 $— $8 $65 
(a)
(a)Prices actively quoted or based on actively quoted prices.
(b)Prices based on models and other valuation methods.
Prices actively quoted or based on actively quoted prices.
(b)
Prices based on models and other valuation methods.
 Options Maturity
(Millions of Dollars) 
Less Than
1 Year
 1 to 3 Years 4 to 5 Years 
Greater Than
5 Years
 Total Fair Value
NSP-Minnesota (a)
 $4
 $1
 $—
 $—
 $5
(a)
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) 2019 2018(Millions of Dollars)20212020
Fair value of commodity trading net contract assets outstanding at Jan. 1 $17
 $16
Fair value of commodity trading net contracts outstanding at Jan. 1Fair value of commodity trading net contracts outstanding at Jan. 1$(54)$(59)
Contracts realized or settled during the period (22) (10)Contracts realized or settled during the period(54)(9)
Commodity trading contract additions and changes during the period (54) 11
Commodity trading contract additions and changes during the period75 14 
Fair value of commodity trading net contract assets outstanding at Dec. 31 $(59) $17
Fair value of commodity trading net contracts outstanding at Dec. 31Fair value of commodity trading net contracts outstanding at Dec. 31$(33)$(54)
At Dec. 31, 2019,2021, a 10% increase in market prices for commodity trading contracts through the forward curve would increase pretax income from continuing operations by approximately $13 million, whereas a 10% decrease would decrease pretax income from continuing operations by approximately $13 million. At Dec. 31, 2020, a 10% increase in market prices for commodity trading contracts would increase pretax income from continuing operations by approximately $10$13 million, whereas a 10% decrease would decrease pretax income from continuing operations by approximately $10$13 million. At Dec. 31, 2018, aMarket price movements can exceed 10% increase in market prices for commodity trading contracts would increase pretax income by approximately $16 million, whereas a 10% decrease would decrease pretax income by approximately $16 million.under abnormal circumstances.
The utility subsidiaries’ 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 and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:
(Millions of Dollars)Year Ended
Dec. 31		VaR LimitAverageHighLow
2021$1 $3 $2 $52 $1 
20201 3 1 2 1 
(Millions of Dollars) 
Year Ended
Dec. 31
 VaR Limit Average High Low
2019 $0.4
 $3.0
 $0.6
 $0.8
 $0.3
2018 4.8
 6.0
 0.6
 5.6
 0.1
In November 2018, management temporarily increasedA short-term increase in VaR occurred during the week of Feb. 12, 2021 through Feb. 18, 2021. On Feb. 17, 2021, the portfolio VaR limitreached a high of $52 million. This increase in VaR was driven by the unprecedented market conditions during Winter Storm Uri. Prior to accommodate a 10-year transaction. NSP-Minnesota systematically hedging the transactionthis widespread weather event, VaR was $1 million and the consolidated VaR returned below $3to $1 million in early January 2019.by Feb. 19, 2021.
Nuclear Fuel Supply — NSP-Minnesota has received all enriched nuclear material for 2019 and has contracted for approximately 51%78% of its 20202022 enriched nuclear material requirements from sources that could be impacted by sanctions against entities doing business with Iran. Those sanctions may impact the supply of enriched nuclear material supplied from Russia. Long-term, through 2030, NSP-Minnesota is scheduled to take delivery of approximately 29%30% of its average enriched nuclear material requirements from these sources. Alternate potential sources provide the flexibilityNSP-Minnesota is able to manage NSP-Minnesota’s nuclear fuel supply.supply with alternate potential sources. NSP-Minnesota periodically assesses if further actions are required to assure a secure supply of enriched nuclear material.
Interest Rate Risk — Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.

A 100 basis point change in the benchmark rate on Xcel Energy’s variable rate debt would impact annual pretax interest expense annually by approximately $11 million and $6 million in 20192021 and $10 million in 2018.2020, respectively.
NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate risk and equity price risk. The fund is invested in a diversified portfolio of cash equivalents, debt securities, equity securities and other investments. These investments may be used only for the purpose of decommissioning NSP-Minnesota’s nuclear generating plants.
Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting.
Changes in discount rates and expected return on plan assets impact the value of pension and postretirement plan assets and/or benefit costs.
Credit Risk — Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. The CompanyXcel Energy maintains credit policies intended to minimize overall credit risk and actively monitormonitors these policies to reflect changes and scope of operations.
At Dec. 31, 2019,2021, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $19$36 million, while a decrease in prices of 10% would have resulted in an increasea decrease in credit exposure of $14$26 million. At Dec. 31, 2018,2020, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $14$11 million, while a decrease in prices of 10% would have resulted in an immaterial increase in credit exposureexposure.
41
Xcel Energy 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 our credit risk.
Fair Value Measurements
Xcel Energy 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-normalpurchase and normal sale contracts, are reported at fair value. The Company’s
Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting.
Commodity Derivatives — Xcel Energy 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, 2019.2021.
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, 2019.2021.
See Notes 10 and 11 to the consolidated financial statements for further information.
Liquidity and Capital Resources
Cash Flows
Operating Cash Flows
(Millions of Dollars) 2019 2018 2017
Net cash provided by operating activities $3,263
 $3,122
 $3,126
(Millions of Dollars)Twelve Months Ended Dec. 31
Cash provided by operating activities — 2020$2,848 
Components of change — 2021 vs. 2020
Higher net income124 
Non-cash transactions (a)
52 
Changes in working capital (b)
(50)
Changes in net regulatory and other assets and liabilities(785)
Cash provided by operating activities — 2021$2,189 
Net cash provided by operating activities increased by(a)    $141 million for 2019 as comparedNon-cash transactions applicable to 2018. Increase was primarily due to additional net income (excluding amounts related to non-cash operating activities (e.g., depreciation, andnuclear fuel amortization, andchanges in deferred tax expenses)income taxes, allowance for equity funds used during construction, etc.), partially offset by increased refunds associated with TCJA..
(b)     Working capital includes accounts receivable, accrued unbilled revenues, inventories, accounts payable, other current assets and other current liabilities.
Net cash provided by operating activities decreased by$4 $659 million for 20182021 as compared to 2017. Change2020. The decrease was primarily due to refunds associated with the TCJA and timingdeferral of certain electric andnet natural gas, recovery mechanisms, partially offset byfuel and purchased energy costs related to Winter Storm Uri in the change in net income.first quarter.
Investing Cash Flows
(Millions of Dollars) 2019 2018 2017
Net cash used in investing activities $(4,343) $(3,986) $(3,296)
(Millions of Dollars)Twelve Months Ended Dec. 31
Cash used in investing activities — 2020$(4,740)
Components of change — 2021 vs. 2020
Decreased capital expenditures1,125 
Sale of MEC in 2020(684)
Other investing activities12 
Cash used in investing activities — 2021$(4,287)
Net cash used in investing activities increaseddecreased by $357$453 million for 20192021 as compared to 2018. Increase was primarily attributable to additional2020. The decrease in capital expenditures primarily forwas largely due to the purchase of MEC in January 2020, which was subsequently sold in July 2020, as well as the completion of various wind projects.
Net cash used in investing activities increased by $690 million for 2018 as compared to 2017. Increase was largely related to higher capital expenditures for the Rush Creek, Foxtail and Hale wind generation facilities.Financing Cash Flows
(Millions of Dollars) 2019 2018 2017
Net cash provided by financing activities $1,181
 $928
 $168
(Millions of Dollars)Twelve Months Ended Dec. 31
Cash provided by financing activities — 2020$1,773 
Components of change — 2021 vs. 2020
Higher debt issuances202 
Lower repayments of long-term debt584 
Lower proceeds from issuance of common stock(361)
Higher dividends paid to shareholders(79)
Other financing activities16 
Cash provided by financing activities — 2021$2,135 
Net cash provided by financing activities increased by $253$362 million for 20192021 as compared to 2018. Increase2020. The increase was primarily attributable to higher proceeds fromthe amount/timing of debt issuances of long-term debt and common stock (primarilyrepayments, changes in capital investment and incremental financing due to the forward equity agreement settlinglag in August 2019), partially offset by higher repayments of long-term debt and dividends paid.recovery costs associated with Winter Storm Uri.
Net cash provided by financing activities increased by $760 millionSee Note 5 to the consolidated financial statements for 2018 as compared to 2017. Increase was primarily due to lower repayments of long-term debt, proceeds from the issuances of common stock and additional debt financings, partially offset by lower short-term debt proceeds as compared to 2017.further information.


Capital Requirements
Xcel Energy has contractual obligations and other commitments that will need to be funded in the future. The Company expects to have adequate amounts of cash from operating and/or financing activities to meet both its short-term and long-term cash requirements. Xcel Energy’s financing requirements are dependent on both existing contractual obligations and other commitments, as well as projected capital forecasts. Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios. Projected future financing requirements can be impacted by various factors including constraints to supply chain and labor, as well as inflation.
Recovery of the effects of inflation through higher customer rates is dependent upon receiving adequate and timely rate increases. Rate increases may not be retroactive and often lag increases in costs caused by inflation. On occasion, the Company may enter into rate settlement agreements, which require us to wait for a period of time to file the next base rate increase request. These agreements may result in regulatory lag whereby the impact of inflation may not yet be reflected in rates, or a delay may occur between capital project completion and the start of rate recovery. Xcel Energy attempts to mitigate the potential impact of inflation through the use of fuel, energy and other cost adjustment clauses and bill riders, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances.
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Contractual Obligations and Other Commitments —
Payments Due by Period (as of Dec. 31, 2021)
(Millions of Dollars)TotalLess than 1 Year1 to 3 Years3 to 5 YearsAfter 5 Years
Long-term debt, principal and interest payments$37,014 $1,419 $3,323 $3,175 $29,097 
Finance lease obligations242 12 24 19 187 
Operating leases obligations (a)
1,594 256 478 363 497 
Unconditional purchase obligations (b)
4,837 1,718 1,538 617 964 
Other long-term obligations, including current portion (c)
40 36 4 — — 
Other short-term obligations455 455 — — — 
Short-term debt1,005 1,005 — — — 
Total contractual cash obligations$45,187 $4,901 $5,367 $4,174 $30,745 
(a)Included in operating lease obligations are $229 million, $430 million, $335 million and $416 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively, pertaining to PPAs that were accounted for as operating leases.
(b)Xcel Energy hasInc. and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its fuel (nuclear, natural gas and coal) requirements. Additionally, the utility subsidiaries of Xcel Energy Inc. have entered into non-lease purchase power agreements. Certain contractual purchase obligations and other commitments that will need to be funded in the future.are adjusted on indices. Effects of price changes are mitigated through cost of energy adjustment mechanisms.
Contractual obligations and other commercial commitments as(c)Primarily consists of Dec. 31, 2019:contracts for information technology services.
  Payments Due by Period
(Millions of Dollars) Total Less than 1 Year 1 to 3 Years 3 to 5 Years After 5 Years
Long-term debt, principal and interest payments$31,433
 $1,422
 $2,702
 $2,514
 $24,795
Finance lease obligations271
 14
 26
 24
 207
Operating leases obligations (a)
2,116
 262
 520
 469
 865
Unconditional purchase obligations (b)
5,831
 1,302
 1,940
 1,178
 1,411
Other long-term obligations, including current portion680
 64
 89
 59
 468
Other short-term obligations442
 442
 —
 —
 —
Short-term debt595
 595
 —
 —
 —
Total contractual cash obligations$41,368
 $4,101
 $5,277
 $4,244
 $27,746
(a)
Included in operating lease obligations are $236 million, $463 million, $422 million and $750 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively, pertaining to PPAs that were accounted for as operating leases.
(b)
Xcel Energy Inc. and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its fuel (nuclear, natural gas and coal) requirements. Additionally, the utility subsidiaries of Xcel Energy Inc. have entered into non-lease purchase power agreements. Certain contractual purchase obligations are adjusted on indices. Effects of price changes are mitigated through cost of energy adjustment mechanisms.
Capital Expenditures — Current estimated baseBase capital expenditures:expenditures and incremental capital forecasts:
ActualBase Capital Forecast (Millions of Dollars)
By Regulated Utility2021202220232024202520262022 - 2026 Total
PSCo$1,625 $1,930 $1,850 $2,070 $2,220 $1,860 $9,930 
NSP-Minnesota1,885 2,250 2,030 1,830 2,130 2,010 10,250 
SPS555 630 660 690 780 790 3,550 
NSP-Wisconsin290 480 420 540 460 390 2,290 
Other (a)
25 (10)— 10 (30)10 (20)
Total base capital expenditures$4,380 $5,280 $4,960 $5,140 $5,560 $5,060 $26,000 
ActualBase Capital Forecast (Millions of Dollars)
By Function2021202220232024202520262022 - 2026 Total
Electric distribution$1,110 $1,485 $1,600 $1,520 $1,605 $1,720 $7,930 
Electric transmission830 1,105 1,220 1,575 1,965 1,555 7,420 
Electric generation575 645 580 670 650 650 3,195 
Natural gas655 655 670 695 660 660 3,340 
Other610 725 545 450 340 450 2,510 
Renewables600 665 345 230 340 25 1,605 
Total base capital expenditures$4,380 $5,280 $4,960 $5,140 $5,560 $5,060 $26,000 
(a) Other category includes intercompany transfers for safe harbor wind turbines.
The five-year capital forecast includes the proposed Colorado Pathway transmission expansion (approximately $1.7 billion) and the proposed 460 MW Sherco solar facility (approximately $600 million).
Additional capital investment in renewable generation and transmission may be needed in the five-year forecast pending approval of regulatory filings in Minnesota and Colorado. The approval of the proposed resource plans could result in up to 2,000 MW of renewable generation being needed between 2024 - 2026, resulting in potential capital expenditures estimated between $1.0 to $1.5 billion (assuming Xcel Energy were to own ~50% of the renewables). Additionally, the associated $0.5 billion to $1.0 billion of network upgrades, voltage support and interconnection work related to the Colorado Power Pathway could also be needed during this five-year forecast depending on resource mix, location and timing. Any additional capital investment would likely be funded with approximately 50% equity and 50% debt.
  Capital Forecast
(Millions of Dollars) 2020 2021 2022 2023 2024 2020 - 2024 Total
By Subsidiary            
NSP-Minnesota $2,025
 $1,580
 $1,670
 $1,800
 $1,845
 $8,920
PSCo 1,415
 1,445
 1,720
 1,565
 1,530
 7,675
SPS 1,025
 530
 700
 750
 800
 3,805
NSP-Wisconsin 250
 320
 345
 350
 425
 1,690
Other (a)
 (85) (65) 10
 10
 10
 (120)
Total capital expenditures $4,630
 $3,810
 $4,445
 $4,475
 $4,610
 $21,970
(a)
Other category includes intercompany transfers for safe harbor wind turbines. The $650M non-regulated acquisition of MEC in 2020 is not included above.

  Capital Forecast
(Millions of Dollars) 2020 2021 2022 2023 2024 2020 - 2024 Total
By Function            
Renewables $1,760
 $315
 $—
 $—
 $—
 $2,075
Electric generation 480
 595
 580
 780
 1,000
 3,435
Electric transmission 625
 835
 1,295
 1,270
 1,260
 5,285
Electric distribution 885
 1,140
 1,415
 1,470
 1,350
 6,260
Natural gas 520
 450
 600
 560
 640
 2,770
Other 360
 475
 555
 395
 360
 2,145
Total capital expenditures $4,630
 $3,810
 $4,445
 $4,475
 $4,610
 $21,970
Xcel Energy’s capital expenditure programforecast is subject to continuouscontinuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives (e.g., federal clean energy and tax policy), reserve margin requirements, availability of purchased power, alternative plans for meeting long-term energy needs, compliance with environmental requirements, RPSinitiatives and mergers,regulation, and merger, acquisition and divestiture opportunities.
The Company issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions andFinancing for other general corporate purposes.

Financing Capital Expenditures through 20242026 — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes.
43
Current estimated financing plans of Xcel Energy for 2020 - 2024:
(Millions of Dollars)  
Funding Capital Expenditures  
Cash from operations (a)
 $13,905
New debt (b)
 6,665
Equity through the DRIP and benefit program 400
Equity through the at-the-market program 250
Equity through forward equity agreements (c)
 750
Base capital expenditures 2020 - 2024 $21,970
   
Maturing Debt $3,245
2022 through 2026:
(Millions of Dollars)
Funding Capital Expenditures
Cash from operations(a)
$17,640 
New debt (b)
7,110 
Equity through the DRIP and benefit program450 
Other equity800 
Base capital expenditures 2021 - 2025$26,000 
Maturing Debt$3,900 
(a) Net of dividends and pension funding.
(b) Reflects a combination of short and long-term debt; net of refinancing.
(c) Equity forward issued in 2019, but has not yet settled; settlement expected by Dec. 31, 2020
Common Stock Dividends — Future dividend levels will be dependent on Xcel Energy’s results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2020, Xcel Energy announced a quarterly dividend of $0.43 per share, which represents an increase of 6.2%.
Xcel Energy’s dividend policy balances the following:
Projected cash generation;
Projected capital investment;
A reasonable rate of return on shareholder investment; and
The impact on Xcel Energy’s capital structure and credit ratings.
In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company system to declare dividends. Specifically, under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries’ dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants.
See Note 5 to the consolidated financial statements for further information.
Pension Fund— Xcel Energy’s pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds.

Funded status and pension assumptions:
(Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018
Fair value of pension assets $3,184
 $2,742
Projected pension obligation (a)
 3,701
 3,477
Funded status $(517) $(735)
(a)
Excludes non-qualified plan of $39 million and $33 million at Dec. 31, 2019 and 2018, respectively.
Pension Assumptions 2019 2018
Discount rate 3.49% 4.31%
Expected long-term rate of return 6.87
 6.87
Capital Sources
Short-Term Funding Sources — Xcel Energy uses a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on financing needs for construction expenditures, working capital and dividend payments.
Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash operating and short-term investment accounts.
Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are:
$1.25 billion for Xcel Energy Inc.;
$700 million for PSCo;
$500 million for NSP-Minnesota;
$500 million for SPS; and
$150 million for NSP-Wisconsin.
In addition, Xcel Energy Inc. borrowed $500 million under a 364-day term loan agreement that expires Dec. 1, 2020. Xcel Energy has an option to request an extension through Nov. 30, 2021.
Xcel Energy’s outstanding short-term debt:
(Amounts in Millions, Except Interest Rates) Three Months Ended Dec. 31, 2019
Borrowing limit $3,600
Amount outstanding at period end 595
Average amount outstanding 663
Maximum amount outstanding 945
Weighted average interest rate, computed on a daily basis 2.40%
Weighted average interest rate at end of period 2.34
(Amounts in Millions, Except Interest Rates) Year Ended Dec. 31, 2019 Year Ended Dec. 31, 2018 Year Ended Dec. 31, 2017
Borrowing limit $3,600
 $3,250
 $3,250
Amount outstanding at period end 595
 1,038
 814
Average amount outstanding 1,115
 788
 644
Maximum amount outstanding 1,780
 1,349
 1,247
Weighted average interest rate, computed on a daily basis 2.72% 2.34% 1.35%
Weighted average interest rate at end of period 2.34
 2.97
 1.90
Credit Facility Agreements— Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods beyond the June 2024 termination date. NSP-Wisconsin has the right to request an extension of the revolving credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.

As of Feb. 18, 2020, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:
(Millions of Dollars) Facility 
Drawn (a)
 Available Cash Liquidity
Xcel Energy Inc. $1,250
 $759
 $491
 $—
 $491
PSCo 700
 49
 651
 1
 652
NSP-Minnesota 500
 10
 490
 1
 491
SPS 500
 123
 377
 1
 378
NSP-Wisconsin 150
 62
 88
 —
 88
Total $3,100
 $1,003
 $2,097
 $3
 $2,100
(a)
Includes outstanding commercial paper, term loan borrowings and letters of credit.
Registration Statements — Xcel Energy Inc.’s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2019 and 2018, the Company had approximately 525 million shares and 514 million shares of common stock outstanding, respectively.
Xcel Energy Inc. and its utility subsidiaries have registration statements on file with the SEC pursuant to which they may sell securities from time to time. These registration statements, which are uncapped, permit Xcel Energy Inc. and its utility subsidiaries to issue debt and other securities in the future at amounts, prices and with terms to be determined at the time of future offerings, and in the case of our utility subsidiaries, subject to commission approval.
Planned Financing Activity— Xcel Energy’s 2020 financing plans reflect the following:
Xcel Energy Inc. — approximately $700 million of senior unsecured bonds and approximately $75 to $80 million of equity through the DRIP and benefit programs;
NSP-Minnesota — approximately $550 million of first mortgage bonds;
NSP-Wisconsin — approximately $100 million of first mortgage bonds
PSCo — approximately $750 million of first mortgage bonds; and
SPS — approximately $300 million of first mortgage bonds.
Forward Equity Agreements —In November 2018, Xcel Energy Inc. entered into forward equity agreements in connection with a completed $459 million public offering of 9.4 million shares of common stock. In August 2019, we settled the forward equity agreements by physically delivering 9.4 million shares of common equity for cash proceeds of $453 million.
In November 2019, Xcel Energy Inc. entered into forward equity agreements for a $743 million public offering of 11.8 million shares of common stock.
Other Equity — Xcel Energy also plans to issue approximately $75 to $80 million of equity annually through the DRIP and benefit programs during the five-year forecast time period.
Long-Term Borrowings and Other Financing Instruments— See Note 5 to the consolidated financial statements for further information.
Earnings Guidance
2020 GAAP and ongoing earnings guidance is a range of $2.73 to $2.83 per share.(a)
Key assumptions:
Constructive outcomes in all rate case and regulatory proceedings.
Normal weather patterns.
Weather-normalized retail electric sales are projected to increase ~1%, including impact of leap year.
Weather-normalized retail firm natural gas sales are projected to increase ~1%, including impact of leap year.
Capital rider revenue is projected to increase $45 million to $55 million (net of PTCs). PTCs are credited to customers, through capital riders and reductions to electric margin.
O&M expenses are projected to increase approximately 1% to 2%.
Depreciation expense is projected to increase approximately $160 million to $170 million.
Property taxes are projected to increase approximately $35 million to $45 million.
•
Interest expense (net of AFUDC — debt) is projected to increase $50 million to $60 million.
•
AFUDC — equity is projected to increase approximately $10 million to $20 million.
•
The ETR is projected to be approximately 0%. The ETR reflects benefits of PTCs which are credited to customers through electric margin and will not impact net income.
(a)
Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. Xcel Energy is unable to forecast if any of these items will occur or provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.
Off-Balance Sheet Arrangements
Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
Common Stock Dividends — Future dividend levels will be dependent on Xcel Energy’s results of operations, financial condition, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February 2022, Xcel Energy announced an increase in the annual dividend of 12 cents per share, which represents an increase of 6.6%.
Xcel Energy’s dividend policy balances the following:
•Projected cash generation.
•Projected capital investment.
•A reasonable rate of return on shareholder investment.
•The impact on Xcel Energy’s capital structure and credit ratings.
In addition, there are certain statutory limitations that could affect dividend levels. Federal law places limits on the ability of public utilities within a holding company to declare dividends. Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries’ dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants.
See Note 5 to the consolidated financial statements for further information.
Pension Fund— Xcel Energy’s pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities and alternative investments, including private equity, real estate and hedge funds.
Funded status and pension assumptions:
(Millions of Dollars)Dec. 31, 2021Dec. 31, 2020
Fair value of pension assets$3,670 $3,599 
Projected pension obligation (a)
3,718 3,964 
Funded status$(48)$(365)
(a)Excludes non-qualified plan of $43 million and $43 million at Dec. 31, 2021 and 2020, respectively.
Pension Assumptions20212020
Discount rate3.08 %2.71 %
Expected long-term rate of return6.49 6.49 
Capital Sources
Short-Term Funding Sources — Xcel Energy generally funds short-term needs, through operating cash flows, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on construction expenditures, working capital and dividend payments.
Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash and short-term investment accounts.
Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. Authorized levels for these commercial paper programs are:
•$1.25 billion for Xcel Energy Inc.
•$700 million for PSCo.
•$500 million for NSP-Minnesota.
•$500 million for SPS.
•$150 million for NSP-Wisconsin.
Xcel Energy Inc. repaid its $1.2 billion 364-Day Term Loan Agreement in the fourth quarter.
Xcel Energy’s outstanding short-term debt:
(Amounts in Millions, Except Interest Rates)Three Months Ended Dec. 31, 2021
Borrowing limit$3,100 
Amount outstanding at period end1,005 
Average amount outstanding1,200 
Maximum amount outstanding1,774 
Weighted average interest rate, computed on a daily basis0.54 %
Weighted average interest rate at end of period0.31 
(Amounts in Millions, Except Interest Rates)Year Ended Dec. 31, 2021Year Ended Dec. 31, 2020
Borrowing limit$3,100 $3,100 
Amount outstanding at period end1,005 584 
Average amount outstanding1,399 1,126 
Maximum amount outstanding2,054 2,080 
Weighted average interest rate, computed on a daily basis0.57 %1.45 %
Weighted average interest rate at end of period0.31 0.23 
Credit Facility Agreements— Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods beyond the June 2024 termination date. NSP-Wisconsin has the right to request an extension of the revolving credit facility for an additional year. All extension requests are subject to majority bank group approval.
As of Feb. 18, 2022, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:
(Millions of Dollars)
Facility (a)
Drawn (b)
AvailableCashLiquidity
Xcel Energy Inc.$1,250 $757 $493 $2 $495 
PSCo700 26 674 22 696 
NSP-Minnesota500 11 489 13 502 
SPS500 235 265 3 268 
NSP-Wisconsin150 — 150 3 153 
Total$3,100 $1,029 $2,071 $43 $2,114 
(a)Credit facilities expire in June 2024.
(b)Includes outstanding commercial paper and letters of credit.
44
Registration Statements — Xcel Energy Inc.’s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2021 and 2020, Xcel Energy had approximately 544 million shares and 537 million shares of common stock outstanding, respectively.
Xcel Energy Inc. and its utility subsidiaries have registration statements on file with the SEC pursuant to which they may sell securities from time to time. These registration statements, which are uncapped, permit Xcel Energy Inc. and its utility subsidiaries to issue debt and other securities in the future at amounts, prices and with terms to be determined at the time of future offerings, and in the case of our utility subsidiaries, subject to commission approval.
Planned Financing Activity— Xcel Energy’s 2022 financing plans reflect the following:
•Xcel Energy Inc. — approximately $600 million in unsecured bonds during Q2.
•PSCo — approximately $650 million of first mortgage bonds during Q2.
•SPS — approximately $150 million of first mortgage bonds during Q2.
•NSP-Minnesota — approximately $500 million of first mortgage bonds during Q2.
•NSP-Wisconsin — approximately $100 million of first mortgage bonds during Q3.
Equity through DRIP and Benefits Program — Xcel Energy also plans to issue approximately $90 million of equity annually through the DRIP and benefit programs during the five-year forecast time period.
ATM Equity Offering — In November 2021, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $800 million of its common stock through an ATM program. As of Dec. 31, 2021, Xcel Energy Inc. issued 5.33 million shares of common stock with net proceeds of $347 million through the ATM program.
Long-Term Borrowings and Other Financing Instruments— See Note 5 to the consolidated financial statements for further information.
Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives
Xcel Energy 2022 Earnings Guidance — Xcel Energy’s 2022 GAAP and ongoing earnings guidance is a range of $3.10 to $3.20 per share.(a)
Key assumptions as compared with 2021 levels unless noted:
•Constructive outcomes in all rate case and regulatory proceedings.
•Normal weather patterns for the year.
•Weather-normalized retail electric sales are projected to increase ~1%.
•Weather-normalized retail firm natural gas sales are projected to be 0% to 1%.
•Capital rider revenue is projected to increase $35 million to $45 million (net of PTCs). PTCs are credited to customers, through capital riders and reductions to other regulatory mechanisms.
•O&M expenses are projected to increase approximately 1% to 2%.
•Depreciation expense is projected to increase approximately $255 million to $265 million.
•Property taxes are projected to increase approximately $40 million to $50 million.
•Interest expense (net of AFUDC - debt) is projected to increase $55 million to $65 million.
•AFUDC - equity is projected to be relatively flat.
•ETR is projected to be ~(3%) to (5%). The ETR reflects benefits of PTCs which are credited to customers through electric margin and will not have a material impact on net income.
(a)     Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. Xcel Energy is unable to forecast if any of these items will occur or provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.
Long-Term EPS and Dividend Growth Rate Objectives —Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:
•     Deliver long-term annual EPS growth of 5% to 7% based off of a 2021 base of $2.96 per share, which represents the mid-point of the revised 2021 guidance range of $2.94 to $2.98 per share.
•    Deliver annual dividend increases of 5% to 7%.
•     Target a dividend payout ratio of 60% to 70%.
•     Maintain senior secured debt credit ratings in the A range.

ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See the “Derivatives, Risk Management and Market Risk” section in Item 7, incorporated by reference.
ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See Item 15-1 for an index of financial statements included herein.
See Note 15 to the consolidated financial statements for further information.
45


Management Report on Internal Control Over Financial Reporting
The management of Xcel Energy Inc. is responsible for establishing and maintaining adequate internal control over financial reporting. Xcel Energy Inc.’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s management and boardBoard of directorsDirectors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Xcel Energy Inc. management assessed the effectiveness of Xcel Energy Inc.’s internal control over financial reporting as of Dec. 31, 2019.2021. 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, 2019,2021, Xcel Energy Inc.’s internal control over financial reporting is effective at the reasonable assurance level based on those criteria.
Xcel Energy Inc.’s independent registered public accounting firm has issued an auditattestation report on Xcel Energy Inc.’s internal control over financial reporting. Its report appears herein.
/s/ ROBERT C. FRENZEL/s/ BRIAN J. VAN ABEL
Robert C. FrenzelBrian J. Van Abel
Chairman, President, Chief Executive Officer and DirectorExecutive Vice President, Chief Financial Officer
Feb. 23, 2022Feb. 23, 2022
/s/ BEN FOWKE/s/ ROBERT C. FRENZEL
Ben FowkeRobert C. Frenzel
Chairman, President, Chief Executive Officer and DirectorExecutive Vice President, Chief Financial Officer
Feb. 21, 2020Feb. 21, 2020


46
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of Xcel Energy Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Xcel Energy Inc. and subsidiaries (the "Company") as of December 31, 20192021 and 2018,2020, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows, for each of the three years in the period ended December 31, 2019,2021, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the "financial statements"). We also have audited the Company’s internal control over financial reporting as of December 31, 2019,2021, based on criteria established in Internal Control -— Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20192021 and 2018,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2021, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019,2021, based on criteria established in Internal Control -— Integrated Framework (2013) issued by COSO.
Basis for Opinions
The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Controls over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

47
Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements -— Refer to Notes 4 and 12 to the consolidated financial statements.
Critical Audit Matter Description
The Company is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico, and Texas. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission for its wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with North American Electric Reliability Corporation standards, asset transactions and mergers and natural gas transactions in interstate commerce, (collectively with state utility regulatory agencies, the “Commissions”). Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation affects multiple financial statement line items and disclosures, including property, plant and equipment, regulatory assets and liabilities, operating revenues and expenses, and income taxes.
The Company is subject to regulatory rate setting processes. Rates are determined and approved in regulatory proceedings based on an analysis of the Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in assets required to deliver services to customers. Accounting for the Company’s regulated operations provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. The Commissions’ regulation of rates is premised on the full recovery of incurred costs and a reasonable rate of return on invested capital. Decisions by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. In the rate setting process, the Company’s rates result in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant, and 3) a refund due to customers. Given that management’s accounting judgementsjudgments 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 precedenceprecedents 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 21, 202023, 2022
We have served as the Company’s auditor since 2002.


48
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(amounts in millions, except per share data)

Year Ended Dec. 31
202120202019
Operating revenues
Electric$11,205 $9,802 $9,575 
Natural gas2,132 1,636 1,868 
Other94 88 86 
Total operating revenues13,431 11,526 11,529 
Operating expenses
Electric fuel and purchased power4,733 3,512 3,510 
Cost of natural gas sold and transported1,081 689 918 
Cost of sales — other38 37 40 
Operating and maintenance expenses2,321 2,324 2,338 
Conservation and demand side management expenses304 288 285 
Depreciation and amortization2,121 1,948 1,765 
Taxes (other than income taxes)630 612 569 
Total operating expenses11,228 9,410 9,425 
Operating income2,203 2,116 2,104 
Other income (expense), net5 (6)16 
Earnings from equity method investments62 40 39 
Allowance for funds used during construction — equity73 115 77 
Interest charges and financing costs
Interest charges — includes other financing costs of $29, $28 and $26, respectively842 840 773 
Allowance for funds used during construction — debt(26)(42)(37)
Total interest charges and financing costs816 798 736 
Income before income taxes1,527 1,467 1,500 
Income tax (benefit) expense(70)(6)128 
Net income$1,597 $1,473 $1,372 
Weighted average common shares outstanding:
Basic539 527 519 
Diluted540 528 520 
Earnings per average common share:
Basic$2.96 $2.79 $2.64 
Diluted2.96 2.79 2.64 
See Notes to Consolidated Financial Statements
49
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(amounts in millions, except per share data)

  Year Ended Dec. 31
  2019 2018 2017
Operating revenues      
Electric $9,575
 $9,719
 $9,676
Natural gas 1,868
 1,739
 1,650
Other 86
 79
 78
Total operating revenues 11,529
 11,537
 11,404
       
Operating expenses      
Electric fuel and purchased power 3,510
 3,854
 3,757
Cost of natural gas sold and transported 918
 843
 823
Cost of sales — other 40
 35
 34
Operating and maintenance expenses 2,338
 2,352
 2,270
Conservation and demand side management program expenses 285
 290
 273
Depreciation and amortization 1,765
 1,642
 1,479
Taxes (other than income taxes) 569
 556
 545
Total operating expenses 9,425
 9,572
 9,181
       
Operating income 2,104
 1,965
 2,223
       
Other income (expense), net 16
 (14) (10)
Equity earnings of unconsolidated subsidiaries 39
 35
 30
Allowance for funds used during construction — equity 77
 108
 75
       
Interest charges and financing costs      
Interest charges — includes other financing costs of $26, $25 and $24, respectively 773
 700
 663
Allowance for funds used during construction — debt (37) (48) (35)
Total interest charges and financing costs 736
 652
 628
       
Income before income taxes 1,500
 1,442
 1,690
Income taxes 128
 181
 542
Net income $1,372
 $1,261
 $1,148
       
Weighted average common shares outstanding:      
Basic 519
 511
 509
Diluted 520
 511
 509
       
Earnings per average common share:      
Basic $2.64
 $2.47
 $2.26
Diluted 2.64
 2.47
 2.25
       
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(amounts in millions)

Year Ended Dec. 31
202120202019
Net income$1,597 $1,473 $1,372 
Other comprehensive income (loss)
Pension and retiree medical benefits:
Net pension and retiree medical losses arising during the period, net of tax of $—, $(2) and $—, respectively— (5)— 
Reclassification of losses to net income, net of tax of $3, $3 and $1, respectively8 10 3 
Derivative instruments:
Net fair value increase (decrease), net of tax of $1, $(3) and $(8), respectively4 (10)(23)
Reclassification of losses to net income, net of tax of $2, $2 and $1, respectively6 5 3 
Total other comprehensive income (loss)18 — (17)
Total comprehensive income$1,615 $1,473 $1,355 
See Notes to Consolidated Financial Statements

50
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(amounts in millions)

  Year Ended Dec. 31
  2019 2018 2017
       
Net income $1,372
 $1,261
 $1,148
Other comprehensive (loss) income      
Defined pension and other postretirement benefits:      
Net pension and retiree medical loss arising during the period, net of tax of $0, $(2) and $(2), respectively —
 (6) (3)
Reclassification of loss to net income, net of tax of $1, $3 and $5, respectively 3
 9
 7
Derivative instruments:      
Net fair value decrease, net of tax of $(8), $(2) and $0, respectively (23) (5) —
Reclassification of loss to net income, net of tax of $1, $1 and $2, respectively 3
 3
 3
       
Total other comprehensive (loss) income (17) 1
 7
Total comprehensive income $1,355
 $1,262
 $1,155
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in millions)
 Year Ended Dec. 31
 202120202019
Operating activities  
Net income$1,597 $1,473 $1,372 
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization2,143 1,959 1,785 
Nuclear fuel amortization114 123 119 
Deferred income taxes(79)(8)143 
Allowance for equity funds used during construction(73)(115)(77)
Earnings from equity method investments(62)(40)(39)
Dividends from equity method investments42 42 40 
Provision for bad debts60 60 42 
Share-based compensation expense31 73 58 
Net realized and unrealized hedging and derivative transactions(57)(27)45 
Changes in operating assets and liabilities:
Accounts receivable(164)(154)(20)
Accrued unbilled revenues(149)(3)42 
Inventories(126)(80)(84)
Other current assets(34)(45)25 
Accounts payable138 (33)(12)
Net regulatory assets and liabilities(973)(144)(66)
Other current liabilities(1)29 (15)
Pension and other employee benefit obligations(135)(125)(135)
Other, net(83)(137)40 
Net cash provided by operating activities2,189 2,848 3,263 
Investing activities
Capital/construction expenditures(4,244)(5,369)(4,225)
Sale of MEC— 684 — 
Purchase of investment securities(757)(1,398)(995)
Proceeds from the sale of investment securities743 1,378 975 
Other, net(29)(35)(98)
Net cash used in investing activities(4,287)(4,740)(4,343)
Financing activities
Proceeds from (repayments of) short-term borrowings, net421 (11)(443)
Proceeds from issuances of long-term debt2,710 2,940 2,920 
Repayments of long-term debt, including reacquisition premiums(417)(1,001)(949)
Proceeds from issuance of common stock366 727 458 
Dividends paid(935)(856)(791)
Other, net(10)(26)(14)
Net cash provided by financing activities2,135 1,773 1,181 
Net change in cash and cash equivalents37 (119)101 
Cash, cash equivalents and restricted cash at beginning of period129 248 147 
Cash, cash equivalents and restricted cash at end of period$166 $129 $248 
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)$(788)$(758)$(698)
Cash (paid) received for income taxes, net(4)12 53 
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions$501 $400 $421 
Inventory transfers to property, plant and equipment87 275 88 
Operating lease right-of-use assets8 369 1,843 
Allowance for equity funds used during construction73 115 77 
Issuance of common stock for reinvested dividends and/or equity awards60 67 63 
See Notes to Consolidated Financial Statements

51
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in millions)
 Year Ended Dec. 31
 2019 2018 2017
Operating activities   
  
Net income$1,372
 $1,261
 $1,148
Adjustments to reconcile net income to cash provided by operating activities:     
Depreciation and amortization1,785
 1,659
 1,495
Nuclear fuel amortization119
 122
 114
Deferred income taxes143
 218
 640
Allowance for equity funds used during construction(77) (108) (75)
Equity earnings of unconsolidated subsidiaries(39) (35) (30)
Dividends from unconsolidated subsidiaries40
 37
 41
Provision for bad debts42
 42
 39
Share-based compensation expense58
 45
 57
Net realized and unrealized hedging and derivative transactions45
 22
 2
Changes in operating assets and liabilities:     
Accounts receivable(20) (105) (60)
Accrued unbilled revenues42
 9
 (34)
Inventories(84) (65) (3)
Other current assets25
 18
 9
Accounts payable(12) 90
 43
Net regulatory assets and liabilities(66) 223
 (16)
Other current liabilities(15) (61) (38)
Pension and other employee benefit obligations(135) (179) (133)
Other, net40
 (71) (73)
Net cash provided by operating activities3,263
 3,122
 3,126
      
Investing activities 
  
  
Utility capital/construction expenditures(4,225) (3,957) (3,244)
Purchases of investment securities(995) (853) (1,697)
Proceeds from the sale of investment securities975
 833
 1,669
Other, net(98) (9) (24)
Net cash used in investing activities(4,343) (3,986) (3,296)
      
Financing activities     
(Repayments of) proceeds from short-term borrowings, net(443) 225
 422
Proceeds from issuance of long-term debt2,920
 1,675
 1,518
Repayments of long-term debt, including reacquisition premiums(949) (452) (1,030)
Proceeds from issuance of common stock458
 230
 —
Dividends paid(791) (730) (721)
Other, net(14) (20) (21)
Net cash provided by financing activities1,181
 928
 168
      
Net change in cash, cash equivalents and restricted cash101
 64
 (2)
Cash, cash equivalents and restricted cash at beginning of period147
 83
 85
Cash, cash equivalents and restricted cash at end of period$248
 $147
 $83
      
Supplemental disclosure of cash flow information: 
  
  
Cash paid for interest (net of amounts capitalized)$(698) $(633) $(616)
Cash received for income taxes, net53
 27
 44
Supplemental disclosure of non-cash investing and financing transactions:   
  
Accrued property, plant and equipment additions$421
 $388
 $464
Inventory and other asset transfers to property, plant and equipment88
 129
 63
Operating lease right-of-use assets1,843
 —
 —
Allowance for equity funds used during construction77
 108
 75
Issuance of common stock for reinvested dividends and equity awards63
 67
 31
      
See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in millions, except share and per share)
Dec. 31
20212020
Assets
Current assets
Cash and cash equivalents$166 $129 
Accounts receivable, net1,018 916 
Accrued unbilled revenues862 714 
Inventories631 535 
Regulatory assets1,106 640 
Derivative instruments123 49 
Prepaid taxes44 42 
Prepayments and other289 250 
Total current assets4,239 3,275 
Property, plant and equipment, net45,457 42,950 
Other assets
Nuclear decommissioning fund and other investments3,628 3,096 
Regulatory assets2,738 2,737 
Derivative instruments67 30 
Operating lease right-of-use assets1,291 1,490 
Other431 379 
Total other assets8,155 7,732 
Total assets$57,851 $53,957 
Liabilities and Equity
Current liabilities
Current portion of long-term debt$601 $421 
Short-term debt1,005 584 
Accounts payable1,409 1,237 
Regulatory liabilities271 311 
Taxes accrued569 578 
Accrued interest209 203 
Dividends payable249 231 
Derivative instruments69 53 
Operating lease liabilities205 214 
Other459 407 
Total current liabilities5,046 4,239 
Deferred credits and other liabilities
Deferred income taxes4,894 4,746 
Deferred investment tax credits53 45 
Regulatory liabilities5,405 5,302 
Asset retirement obligations3,151 2,884 
Derivative instruments105 131 
Customer advances196 197 
Pension and employee benefit obligations306 666 
Operating lease liabilities1,146 1,344 
Other158 183 
Total deferred credits and other liabilities15,414 15,498 
Commitments and contingencies00
Capitalization
Long-term debt21,779 19,645 
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 544,025,269 and 537,438,394 shares outstanding at Dec. 31, 2021 and Dec. 31, 2020, respectively1,360 1,344 
Additional paid in capital7,803 7,404 
Retained earnings6,572 5,968 
Accumulated other comprehensive loss(123)(141)
Total common stockholders’ equity15,612 14,575 
Total liabilities and equity$57,851 $53,957 
See Notes to Consolidated Financial Statements

52
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in millions, except share and per share)
  Dec. 31
  2019 2018
Assets    
Current assets    
Cash and cash equivalents $248
 $147
Accounts receivable, net 837
 860
Accrued unbilled revenues 713
 755
Inventories 544
 548
Regulatory assets 488
 464
Derivative instruments 55
 87
Prepaid taxes 43
 79
Prepayments and other 185
 154
Total current assets 3,113
 3,094
     
Property, plant and equipment, net 39,483
 36,944
     
Other assets    
Nuclear decommissioning fund and other investments 2,731
 2,317
Regulatory assets 2,935
 3,326
Derivative instruments 22
 34
Operating lease right-of-use assets 1,672
 —
Other 492
 272
Total other assets 7,852
 5,949
Total assets $50,448
 $45,987
     
Liabilities and Equity    
Current liabilities    
Current portion of long-term debt $702
 $406
Short-term debt 595
 1,038
Accounts payable 1,294
 1,237
Regulatory liabilities 407
 436
Taxes accrued 466
 450
Accrued interest 192
 174
Dividends payable 212
 195
Derivative instruments 38
 61
Other 662
 463
Total current liabilities 4,568
 4,460
     
Deferred credits and other liabilities    
Deferred income taxes 4,509
 4,165
Deferred investment tax credits 49
 54
Regulatory liabilities 5,077
 5,187
Asset retirement obligations 2,701
 2,568
Derivative instruments 175
 129
Customer advances 203
 199
Pension and employee benefit obligations 785
 994
Operating lease liabilities 1,549
 —
Other 186
 206
Total deferred credits and other liabilities 15,234
 13,502
     
Commitments and contingencies 


 


Capitalization    
Long-term debt 17,407
 15,803
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 524,539,000 and 514,036,787 shares outstanding at Dec. 31, 2019 and 2018, respectively 1,311
 1,285
Additional paid in capital 6,656
 6,168
Retained earnings 5,413
 4,893
Accumulated other comprehensive loss (141) (124)
Total common stockholders’ equity 13,239
 12,222
Total liabilities and equity $50,448
 $45,987
     
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
(amounts in millions, except per share data; shares in actual amounts)
Common Stock IssuedRetained Earnings
Accumulated Other
Comprehensive Loss
Total Common Stockholders’ Equity
SharesPar ValueAdditional Paid
In Capital
Balance at Dec. 31, 2018514,036,787 $1,285 $6,168 $4,893 $(124)$12,222 
Net income1,372 1,372 
Other comprehensive income(17)(17)
Dividends declared on common stock ($1.62 per share)(846)(846)
Issuances of common stock10,507,943 26 468 494 
Repurchases of common stock(5,730)— — — 
Share-based compensation20 (6)14 
Balance at Dec. 31, 2019524,539,000 $1,311 $6,656 $5,413 $(141)$13,239 
Net Income1,473 1,473 
Dividends declared on common stock ($1.72 per share)(909)(909)
Issuances of common stock12,953,869 33 731 764 
Repurchase of common stock(54,475)— (4)(4)
Share-based compensation21 (7)14 
Adoption of ASC Topic 326(2)(2)
Balance at Dec. 31, 2020537,438,394 $1,344 $7,404 $5,968 $(141)$14,575 
Net income1,597 1,597 
Other comprehensive income18 18 
Dividends declared on common stock ($1.83 per share)(989)(989)
Issuances of common stock6,586,875 16 387 403 
Share-based compensation12 (4)8 
Balance at Dec. 31, 2021544,025,269 $1,360 $7,803 $6,572 $(123)$15,612 
See Notes to Consolidated Financial Statements
53
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
(amounts in millions, shares in thousands)
 Common Stock Issued   
Accumulated Other
Comprehensive Loss
 Total Common Stockholders’ Equity
 Shares Par Value 
Additional
Paid In
Capital
 
Retained
Earnings
  
            
Balance at Dec. 31, 2016507,223
 $1,268
 $5,881
 $3,982
 $(110) $11,021
            
Net income      1,148
   1,148
Other comprehensive loss        7
 7
Dividends declared on common stock ($1.44 per share)      (736)   (736)
Issuances of common stock611
 1
 4
     5
Repurchases of common stock(71) —
 (3)     (3)
Share-based compensation 
  
 16
 (3)   13
Adoption of ASU No. 2018-02      22
 (22) —
Balance at Dec. 31, 2017507,763
 $1,269
 $5,898
 $4,413
 $(125) $11,455
            
Net income      1,261
   1,261
Other comprehensive income        1
 1
Dividends declared on common stock ($1.52 per share)      (780)   (780)
Issuances of common stock6,296
 16
 254
     270
Repurchases of common stock(22) —
 (1)     (1)
Share-based compensation    17
 (1)   16
Balance at Dec. 31, 2018514,037
 $1,285
 $6,168
 $4,893
 $(124) $12,222
            
Net income      1,372
   1,372
Other comprehensive income        (17) (17)
Dividends declared on common stock ($1.62 per share)      (846)   (846)
Issuances of common stock10,508
 26
 468
     494
Repurchases of common stock(6) —
 —
     —
Share-based compensation    20
 (6)   14
Balance at Dec. 31, 2019524,539
 $1,311
 $6,656
 $5,413
 $(141) $13,239
            
See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
General — Xcel Energy Inc.’s utility subsidiaries are engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas.
Xcel Energy’s regulated operations include the activities of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utility subsidiaries serve electric and natural gas customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Also included in regulated operations are WGI, an interstate natural gas pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipeline, storage and compression facilities.
Xcel Energy Inc.’s nonregulated subsidiaries include Eloigne, Capital Services, Venture Holdings and the newly formed MEC Holdings LLC.Nicollet Project Holdings. Eloigne invests in rental housing projects that qualify for low-income housing tax credits. Capital Services procures equipment for construction of renewable generation facilities at other subsidiaries. Venture Holdings invests in limited partnerships, including EIP funds with portfolios of investments in energy technology companies. Nicollet Project Holdings invests in nonregulated assets such as the MEC generating facility (through July 2020) and Minnesota community solar gardens. Xcel Energy Inc. owns the following additional direct subsidiaries, some of which are intermediate holding companies with additional subsidiaries: Xcel Energy Wholesale Group Inc., Xcel Energy Markets Holdings Inc., Xcel Energy Ventures Inc., Xcel Energy Retail Holdings Inc., Xcel Energy Communications Group, Inc., Xcel Energy International Inc., Xcel Energy Transmission Holding Company, LLC, Nicollet Holdings Company, LLC, Nicollet ProjectXcel Energy Nuclear Services Holdings, LLC Xcel Energy Venture Holdings Inc. and Xcel Energy Services Inc. Xcel Energy Inc. and its subsidiaries collectively are referred to as Xcel Energy.
Xcel Energy’s consolidated financial statements include its wholly-owned subsidiaries and VIEs for which it is the primary beneficiary. All intercompany transactions and balances are eliminated unless a different treatment is appropriate for rate regulated transactions.
Xcel Energy uses the equity method of accounting for its investmentinvestments in EIP funds and WYCO. Xcel Energy’s equity earnings in WYCO are included on the consolidated statements of income as equity earnings of unconsolidated subsidiaries.
Xcel Energy has investments in certain plants and transmission facilities jointly owned with nonaffiliated utilities. Xcel Energy’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and Xcel Energy’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income.
Xcel Energy’s consolidated financial statements are presented in accordance with GAAP. All of the utility subsidiaries’ underlying accounting records also conform to the FERC uniform system of accounts. Certain amounts in the 2018 and 2017 consolidated financial statements or notes have been reclassified to conform to the 2019 presentation for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.
Xcel Energy has evaluated events occurring after Dec. 31, 20192021 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.
Use of Estimates — Xcel Energy uses estimates based on the best information available in recording transactions and balances resulting from business operations.
Estimates are used onfor 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 — Xcel Energy Inc.’s regulated utility subsidiaries account for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:
•Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; andrates.
•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, the utility subsidiaries may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities from their balance sheets. Such changes could have a material effect on Xcel Energy’s results of operations, financial condition and cash flows.
See Note 4 for further information.
Income Taxes — Xcel Energy accounts for income taxes using the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Xcel Energy defers income taxes for all temporary differences between pretax financial and taxable income and between the book and tax bases of assets and liabilities.
Xcel Energy uses rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.
The effects of tax rate changes that are attributable to the utility subsidiaries are generally subject to a normalization method of accounting. Therefore, the revaluation of most of the utility subsidiaries’ net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, which willwould be refundable to utility customers over the remaining life of the related assets. AXcel Energy anticipates that a tax rate increase would result in the establishment of a similar regulatory asset.asset, subject to an evaluation of whether future recovery is expected.
54
Reversal of certain temporary differences are accounted for as current income tax expense due to the effects of past regulatory practices when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize 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.

Xcel Energy 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. Xcel Energy 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.
Xcel Energy reports interest and penalties related to income taxes within the other (expense) income andor interest charges in the consolidated statements of income.
Xcel Energy Inc. and its subsidiaries file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries.
See Note 7 for further information.
Property, Plant and Equipment and Depreciation in Regulated Operations — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. 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.
Xcel Energy 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 of Xcel Energy’s utility subsidiaries 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. Accumulated removal costs are reflected in the consolidated balance sheet as a regulatory liability. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.5% for 2021, 3.4% for 2020 and 3.3% for 2019, 3.1% for 2018 and 2017.2019.
See Note 3 for further information.
AROs — Xcel Energy 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. The utility subsidiaries also recover through rates certain future plant removal costs in addition to AROs.
The accumulated removal costs for these obligations are reflected in the consolidated balance sheets as a regulatory liability.
See Note 12 for further information.
Nuclear Decommissioning — Nuclear decommissioning studies that estimate NSP-Minnesota’s costs of decommissioning its nuclear power plants are performed at least every three3 years and submitted to the state commissions for approval.
For ratemaking purposes, NSP-Minnesota recovers regulator-approved decommissioning costs of its nuclear power plants over each facility’s expected service life, typically based on the triennial decommissioning studies. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO.
Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets.
See NoteNotes 10 and 12 for further information.
Benefit Plans and Other Postretirement Benefits — Xcel Energy maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.
Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.
See Note 11 for further information.
55
Environmental Costs — Environmental costs are recorded when it is probable Xcel Energy is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If anFor certain environmental expense iscosts 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 Xcel Energy’s expected share of the cost.
Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.
See Note 12 for further information.
Revenue from Contracts with Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. Xcel Energy recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basissystematically 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.

Xcel Energy does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. Xcel Energy presents its revenues net of any excise or sales taxes or fees. The utility subsidiaries recognize physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. Revenues and charges for short termshort-term physical wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other RTO revenues and charges settled/facilitated through an RTO are recorded on a net basis in cost of sales.
See Note 6 for further information.
Cash and Cash Equivalents — Xcel Energy considers investments in instruments with a remaining maturity of three3 months or less at the time of purchase to be cash equivalents.
Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. Xcel Energy establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.
At bothAs of Dec. 31, 20192021 and 2018,2020, the allowance for bad debts was $55 million.$106 million and $79 million, respectively.
Inventory — Inventory is recorded at average cost and consisted of the following:
(Millions of Dollars)Dec. 31, 2021Dec. 31, 2020
Inventories
Materials and supplies$289 $275 
Fuel182 176 
Natural gas160 84 
Total inventories$631 $535 
(Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018
Inventories    
Materials and supplies $270
 $271
Fuel 191
 170
Natural gas 83
 107
Total inventories $544
 $548

Equity Method Investments —The equity method of accounting is used for investments in WYCO and EIP funds, which results in Xcel Energy’s recognition of its share of these investees’ GAAP pretax earnings, based on Xcel Energy’s proportional ownership interest. For investments in EIP funds, this includes Xcel Energy’s share of fund expenses and realized gains and losses, as well as unrealized gains and losses resulting from valuations of the funds’ investments in emerging energy technology companies.
Fair Value Measurements — Xcel Energy presents cash equivalents, interest rate derivatives, commodity derivatives and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements.
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, Xcel Energy may use quoted prices for similar contracts or internally prepared valuation models to determine fair value.
For the pension and postretirement plan assets and nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security.
See Notes 10 and 11 for further information.
Derivative Instruments — Xcel Energy uses derivative instruments in connection with its interest rate, utility commodity price vehicle fuel 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; hedging transactions for vehicle fuel costs are recorded as a component of capital projects and O&M costs;revenues and interest rate hedging transactions are recorded as a component of interest expense.
Normal Purchases and Normal Sales — Xcel Energy enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether 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 10 for further information.
Commodity Trading Operations — All applicable gains and losses related to commodity trading activities are shown on a net basis in electric operating revenues in the consolidated statements of income.
Commodity trading activities are not associated with energy produced from Xcel Energy’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 10 for further information.
56
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 Xcel Energy’s rate base for establishing utility rates.
Alternative Revenue — Certain rate rider mechanisms (including decouplingdecoupling/sales true up and CIP/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.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 — Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.
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.
Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and amortization method for nuclear refueling costs. This method amortizes costs over the period between refueling outages consistent with rate recovery.

RECs — Cost of RECs that are utilized for compliance is recorded as electric fuel and purchased power expense. In certain jurisdictions, Xcel Energy reduces recoverable fuel and purchased power costs for the cost of RECs and records that costreceived. An inventory accounting model is used to account for RECs recognized on the consolidated balance sheets, however these assets are classified as a regulatory asset when the amount isassets if amounts are recoverable in future rates.
Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.
Cost of RECs that are utilized to support commodity trading activities are recorded in a similar manner as the associated commodities and are shown on a net basis in electric operating revenues in the consolidated statements of income.

2. Accounting Pronouncements
Recently IssuedAdopted
Credit Losses — In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 326326 (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. ASC Topic 326 is effective for interim and annual periods beginning on or after Dec. 15, 2019 and will be applied
Xcel Energy implemented the guidance using a modified-retrospective approach, withrecognizing a cumulative-effect adjustmentcumulative effect charge of $2 million (after tax) to retained earnings as ofon Jan. 1, 2020.
Xcel Energy expects the impact of adoption of the new standard to include first-time recognition of expected credit losses (i.e., bad debt expense) on unbilled revenues, with the initial allowance established at Jan. 1, 2020 charged to retained earnings. Recognition of this allowance and other impacts of adoption are expected to be immaterial to the consolidated financial statements.
Recently Adopted
Leases — In 2016, the FASB issued Leases, Topic 842(ASC Topic 842), which provides new accounting and disclosure guidance for leasing activities, most significantly requiring that operating leases be recognized on the balance sheet. Xcel Energy adopted the guidance on Jan. 1, 2019 utilizing the package of transition practical expedients provided by the new standard, including carrying forward prior conclusions on whether agreements existing before the adoption date contain leases and whether existing leases are operating or finance leases; ASC Topic 842 refers to capital leases as finance leases.
Specifically, for land easement contracts, Xcel Energy has elected the practical expedient provided by ASU No. 2018-01 Leases: Land Easement Practical Expedient for Transition to Topic 842, and as a result, only those easement contracts entered on or after Jan. 1, 2019 will be evaluated to determine if lease treatment is appropriate.
Xcel Energy also utilized the transition practical expedient offered by ASU No. 2018-11 Leases: Targeted Improvements to implement the standard on a prospective basis. As a result, reporting periods in the consolidated financial statements beginning Jan. 1, 2019 reflect the implementation of ASC Topic 842, while prior periods continue to be reported in accordance with Leases, Topic 840 (ASC Topic 840). Other than first-time recognition of operating leasesan allowance for bad debts on its consolidated balance sheet,accrued unbilled revenues, the implementationJan. 1, 2020, adoption of ASC Topic 842326 did not have a significant impact on Xcel Energy’s consolidated financial statements. Adoption resulted in recognition of approximately $1.7 billion of operating lease ROU assets and current/noncurrent operating lease liabilities.
See Note 12 for leasing disclosures.
3. Property, Plant and Equipment

Major classes of property, plant and equipment
(Millions of Dollars)Dec. 31, 2021Dec. 31, 2020
Property, plant and equipment, net
Electric plant$48,680 $47,104 
Natural gas plant7,758 7,135 
Common and other property2,602 2,503 
Plant to be retired (a)
1,200 677 
CWIP1,969 1,877 
Total property, plant and equipment62,209 59,296 
Less accumulated depreciation(17,060)(16,657)
Nuclear fuel3,081 2,970 
Less accumulated amortization(2,773)(2,659)
Property, plant and equipment, net$45,457 $42,950 
(Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018
Property, plant and equipment    
Electric plant $44,355
 $41,472
Natural gas plant 6,560
 6,210
Common and other property 2,341
 2,154
Plant to be retired (a)
 259
 322
CWIP 2,329
 2,091
Total property, plant and equipment 55,844
 52,249
Less accumulated depreciation (16,735) (15,659)
Nuclear fuel 2,909
 2,771
Less accumulated amortization (2,535) (2,417)
Property, plant and equipment, net $39,483
 $36,944
(a)(a)Includes regulator-approved retirements of Comanche Units 1 and 2 and jointly owned Craig Unit 1 for PSCo, and Sherco Units 1, 2 and 3 and A.S. King for NSP-Minnesota. Also includes SPS’ expected retirement of Tolk and conversion of Harrington to natural gas, and PSCo’s planned retirement of jointly owned Craig Unit 2.
In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in approximately 2022 and 2025, respectively. PSCo also expects Craig Unit 1 to be retired early in 2025.  Amounts are presented net of accumulated depreciation.
Joint Ownership of Generation, Transmission and Gas Facilities
The utility subsidiaries’ jointly owned assets as of Dec. 31, 2019:2021:
(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent Owned
NSP-Minnesota
Electric generation:
Sherco Unit 3$620 $451 59 %
Sherco common facilities178 108 80 
Sherco substation5 4 59 
Electric transmission:
Grand Meadow11 3 50 
Huntley Wilmarth48 1 50 
CapX2020952 127 51 
Total NSP-Minnesota (a)
$1,814 $694 
(a)Projects additionally include $7 million in CWIP.
(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent Owned
NSP-Wisconsin
Electric transmission:
La Crosse, WI to Madison, WI$177 $15 37 %
CapX2020169 28 80 
Total NSP-Wisconsin (a)
$346 $43 
(a)Projects additionally include $2 million in CWIP.
(Millions of Dollars) Plant in Service Accumulated Depreciation CWIP Percent Owned
NSP-Minnesota        
Electric generation:        
Sherco Unit 3 $603
 $426
 $4
 59%
Sherco common facilities 145
 103
 2
 80
Sherco substation 5
 3
 —
 59
Electric transmission:        
CapX2020 972
 92
 2
 51
Grand Meadow 11
 3
 —
 50
Total NSP-Minnesota $1,736
 $627
 $8
  
57
(Millions of Dollars) Plant in Service Accumulated Depreciation CWIP Percent Owned
NSP-Wisconsin        
Electric transmission:        
La Crosse, WI to Madison, WI $187
 $7
 $—
 37%
CapX2020 169
 19
 —
 80
Total NSP-Wisconsin $356
 $26
 $—
  

(Millions of Dollars) Plant in Service Accumulated Depreciation CWIP Percent Owned
(Millions of Dollars, Except Percent Owned)(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent Owned
PSCo        PSCo
Electric generation:        Electric generation:
Hayden Unit 1 $152
 $81
 $—
 76%Hayden Unit 1$156 $99 76 %
Hayden Unit 2 149
 71
 —
 37
Hayden Unit 2151 78 37 
Hayden common facilities 41
 22
 —
 53
Hayden common facilities42 27 53 
Craig Units 1 and 2 81
 41
 —
 10
Craig Units 1 and 281 48 10 
Craig common facilities 39
 22
 —
 7
Craig common facilities39 25 7 
Comanche Unit 3 887
 149
 1
 67
Comanche Unit 3917 154 67 
Comanche common facilities 29
 3
 —
 82
Comanche common facilities28 2 82 
Electric transmission:        Electric transmission:
Transmission and other facilities 174
 62
 1
 Various
Transmission and other facilities182 63 Various
Gas transmission:        Gas transmission:
Rifle, CO to Avon, CO 22
 7
 —
 60
Rifle, CO to Avon, CO22 8 60 
Gas transmission compressor 9
 1
 —
 50
Gas transmission compressor8 2 50 
Total PSCo $1,583
 $459
 $2
  
Total PSCo (a)
Total PSCo (a)
$1,626 $506 

(a)Projects additionally include $4 million in CWIP.
Each company’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing.

4. Regulatory Assets and Liabilities
Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP.
Components of regulatory assets:
(Millions of Dollars) See Note(s) Remaining
Amortization Period		 Dec. 31, 2019 Dec. 31, 2018(Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2021Dec. 31, 2020
Regulatory Assets   Current Noncurrent Current NoncurrentRegulatory AssetsCurrentNoncurrentCurrentNoncurrent
Pension and retiree medical obligations 11
 Various $85
 $1,328
 $87
 $1,500
Pension and retiree medical obligations11Various$77 $944 $82 $1,268 
Recoverable deferred taxes on AFUDC recorded in plant   Plant lives —
 271
 —
 264
Net AROs (a)
 1, 12
 Plant lives —
 269
 —
 452
Deferred natural gas, electric, steam energy/fuel costsDeferred natural gas, electric, steam energy/fuel costs
One to five years
504 543 14 18 
Recoverable deferred taxes on AFUDCRecoverable deferred taxes on AFUDCPlant lives— 289 — 283 
Excess deferred taxes — TCJA 7
 Various 39
 239
 —
 296
Excess deferred taxes — TCJA7Various14 219 16 229 
Depreciation differences   One to twelve years 15
 140
 18
 107
Depreciation differences
One to 10 years
16 173 16 154 
Environmental remediation costs 1, 12
 Various 36
 131
 17
 155
Environmental remediation costs1, 12Various14 92 16 113 
Texas revenue surchargesTexas revenue surcharges
One to two years
20 64 54 17 
Sales true-up and revenue decouplingSales true-up and revenue decoupling
One to two years
33 56 101 28 
Benson biomass PPA termination and asset purchase   Ten years 9
 73
 10
 86
Benson biomass PPA termination and asset purchase
Eight years
10 55 10 65 
Renewable resources and environmental initiativesRenewable resources and environmental initiatives
One to two years
170 48 129 12 
PI extended power upratePI extended power uprate13 years4 46 3 49 
Purchased power contract costsPurchased power contract costsTerm of related contract9 45 7 54 
Conservation programs (a)
Conservation programs (a)
1
One to two years
21 35 26 36 
Losses on reacquired debtLosses on reacquired debtTerm of related debt3 35 4 38 
Contract valuation adjustments (b)
 1, 10
 Term of related contract 20
 62
 17
 77
Contract valuation adjustments (b)
1, 10Term of related contract22 34 23 48 
Purchased power contract costs   Term of related contract 5
 61
 4
 63
State commission adjustmentsState commission adjustmentsPlant lives1 32 1 32 
Laurentian biomass PPA termination   Five years 19
 54
 18
 73
Laurentian biomass PPA termination
Two years
18 18 18 36 
PI extended power uprate   Sixteen years 3
 53
 3
 56
Losses on reacquired debt   Term of related debt 4
 41
 4
 44
State commission adjustments   Plant lives 1
 31
 1
 29
Nuclear refueling outage costsNuclear refueling outage costs1
One to two years
37 16 28 10 
Property tax   Various 2
 30
 14
 10
Property taxVarious16 16 16 21 
Conservation programs (c)
 1
 One to two years 27
 26
 42
 28
Nuclear refueling outage costs 1
 One to two years 43
 17
 37
 14
Sales true-up and revenue decoupling   One to two years 54
 16
 38
 7
Renewable resources and environmental initiatives   One to two years 72
 10
 39
 9
Gas pipeline inspection and remediation costs   One to two years 26
 8
 28
 3
Gas pipeline inspection and remediation costs
One to two years
33 12 26 9 
Deferred purchased natural gas and electric energy costs   One to three years 6
 6
 57
 13
Net AROs (c)
Net AROs (c)
1, 12Various— (112)— 139 
Other   Various 22
 69
 30
 40
OtherVarious84 78 50 78 
Total regulatory assets   $488
 $2,935
 $464
 $3,326
Total regulatory assets$1,106 $2,738 $640 $2,737 
(a)Includes amounts recordedcosts for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.conservation programs, as well as incentives allowed in certain jurisdictions.
(b)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
(c)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
58
Components of regulatory liabilities:
(Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2021Dec. 31, 2020
Regulatory LiabilitiesCurrentNoncurrentCurrentNoncurrent
Deferred income tax adjustments and TCJA refunds (a)
7Various$26 $3,230 $20 $3,368 
Plant removal costs1, 12Various— 1,655 — 1,520 
Effects of regulation on employee benefit costs (b)
Various— 235 — 221 
Renewable resources and environmental initiativesVarious1 101 5 59 
ITC deferrals1Various— 53 — 51 
Revenue decoupling
One to two years
9 41 10 41 
Contract valuation adjustments (c)
1, 10
One to three years
56 1 19 — 
Deferred natural gas, electric, steam energy/fuel costsLess than one year50 — 84 — 
Conservation programs (d)
1Less than one year42 — 49 — 
DOE settlementLess than one year14 14 23 — 
OtherVarious73 75 101 42 
Total regulatory liabilities (e)
$271 $5,405 $311 $5,302 
(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 PSCo prepaid pension asset.
(c)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
(d)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
Components(e)Revenue subject to refund of regulatory liabilities:
(Millions of Dollars) See Note(s) Remaining
Amortization Period		 Dec. 31, 2019 Dec. 31, 2018
Regulatory Liabilities     Current Noncurrent Current Noncurrent
Deferred income tax adjustments and TCJA refunds (a)
 7 Various $75
 $3,523
 $157
 $3,715
Plant removal costs 1, 12 Plant lives —
 1,217
 —
 1,175
Effects of regulation on employee benefit costs (b)
   Various —
 196
 —
 137
Renewable resources and environmental initiatives   Various —
 45
 9
 54
ITC deferrals (c)
 1 Various —
 38
 —
 40
Deferred electric, natural gas and steam production costs   Less than one year 138
 —
 102
 —
Contract valuation adjustments (d)
 1, 10 Less than one year 19
 —
 26
 —
Conservation programs (e)
 1 Less than one year 37
 —
 36
 —
DOE settlement   Less than one year 37
 —
 19
 —
Other   Various 101
 58
 87
 66
Total regulatory liabilities (f)
     $407
 $5,077
 $436
 $5,187
(a)$17 million for both 2021 and 2020 is included in other current liabilities.
Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.
(b)
Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset.
(c)
Includes impact of lower federal tax rate due to the TCJA.
(d)
Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
(e)
Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
(f)
Revenue subject to refund of $28 million and $29 million for 2019 and 2018, respectively, is included in other current liabilities.
At Dec. 31, 20192021 and 2018,2020, Xcel Energy’s regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical obligations and net AROs and Laurentian biomass PPA termination costs/obligations.AROs. In addition, regulatory assets included $544$1,718 million and $512$812 million at Dec. 31, 20192021 and 2018,2020, respectively, of past expenditures not earning a return. Amounts primarilyare related to funded pension obligations, sales true-up and revenue decoupling, purchased natural gas and electric energy costs (including those related to Winter Storm Uri), various renewable resources and certain environmental initiatives.

5. Borrowings and Other Financing Instruments
Short-Term Borrowings
Short-Term Debt — Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements.
Commercial paper and term loan borrowings outstanding:
(Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2019 Year Ended Dec. 31
  2019 2018 2017
Borrowing limit $3,600
 $3,600
 $3,250
 $3,250
Amount outstanding at period end 595
 595
 1,038
 814
Average amount outstanding 663
 1,115
 788
 644
Maximum amount outstanding 945
 1,780
 1,349
 1,247
Weighted average interest rate, computed on a daily basis 2.40% 2.72% 2.34% 1.35%
Weighted average interest rate at end of period 2.34
 2.34
 2.97
 1.90

(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2021Year Ended Dec. 31
202120202019
Borrowing limit$3,100 $3,100 $3,100 $3,600 
Amount outstanding at period end1,005 1,005 584 595 
Average amount outstanding1,200 1,399 1,126 1,115 
Maximum amount outstanding1,774 2,054 2,080 1,780 
Weighted average interest rate, computed on a daily basis0.54 %0.57 %1.45 %2.72 %
Weighted average interest rate at period end0.31 0.31 0.23 2.34 
Term Loan AgreementAgreements — In December 2019,the fourth quarter of 2021, Xcel Energy Inc. entered into a $500 millionrepaid its $1.2 billion 364-Day Term Loan Agreement to pay down borrowings and terminate the expiring $500 million term loan made to Xcel Energy under the 364-Day Term Loan Agreement dated as of Dec. 4, 2018. The loan is unsecured and matures Dec. 1, 2020. Xcel Energy has an option to request an extension through Nov. 30, 2021. Term loan includes one financial covenant, requiring Xcel Energy’s consolidated funded debt to total capitalization ratio to be less than or equal to 65 percent. Interest is at a rate equal to either the Eurodollar rate, plus 50.0 basis points, or an alternate base rate.
Term loan borrowings as of Dec. 31, 2019:
(Millions of Dollars) Limit Amount Used Available
Xcel Energy Inc. $500
 $500
 $—

Agreement.
Bilateral Credit Agreement — In March 2019, NSP-Minnesota entered into a one-yearApril 2021, NSP-Minnesota’s uncommitted bilateral credit agreement.agreement was renewed for an additional one-year term. The credit agreement is limited in use to support letters of credit.
As of Dec. 31, 2019,2021, NSP-Minnesota had $45 million outstanding letters of credit under the $75 million the Bilateral Credit Agreement were as follows:
(Millions of Dollars) Limit Amount Used Available
NSP-Minnesota $75
 $22
 $53

Agreement.
Letters of Credit — Xcel Energy uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. As of Dec. 31, 20192021 and 2018,2020, there were $20$19 million and $49$20 million of letters of credit outstanding under the credit facilities.facilities, respectively. Amounts approximate their fair value.
Credit Facilities — In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
AmendedTerms of Credit Agreements — In June 2019, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS entered into amended five-year credit agreements with a syndicate of banks. The total borrowing limit under the amended credit agreements was increased tois $3.1 billion, with the following changes:
Maturity extended from June 2021 to June 2024;
Borrowing limita swingline subfacility for Xcel Energy was increased from $1.0 billionup to $1.25 billion;
Borrowing limit for SPS was increased from $400 million to $500 million; and
•
Added swingline subfacility for Xcel Energy up to $75 million$75 million. The amended credit agreements mature in June 2024.
Features of the credit facilities:
Debt-to-Total Capitalization Ratio (a)
Amount Facility May Be Increased (millions of dollars)
Additional Periods for Which a One-Year Extension May Be Requested (b)
20212020
Xcel Energy Inc. (c)
60 %59 %$250 2 
NSP-Wisconsin49 46 N/A1 
NSP-Minnesota47 47 100 2 
SPS47 48 50 2 
PSCo44 44 100 2 
(a)    Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.
(b)    All extension requests are subject to majority bank group approval.
(c)The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. would be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy’s consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.
  
Debt-to-Total Capitalization Ratio(a)
 Amount Facility May Be Increased (millions) 
Additional Periods for Which a One-Year Extension May Be Requested (b)
  2019 2018    
Xcel Energy Inc. (c)
 58% 58% $200
 2
NSP-Wisconsin 48
 48
 N/A
 1
NSP-Minnesota 48
 48
 100
 2
SPS 46
 46
 50
 2
PSCo 44
 46
 100
 2
59
(a)
Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.
(b)
All extension requests are subject to majority bank group approval.
(c)
The Xcel Energy Inc. credit facility has a cross-default provision that Xcel Energy Inc. will be in default on its borrowings under the facility if it or any of its subsidiaries (except NSP-Wisconsin as long as its total assets do not comprise more than 15% of Xcel Energy’s consolidated total assets) default on indebtedness in an aggregate principal amount exceeding $75 million.
If Xcel Energy Inc. or its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender. As of Dec. 31, 2019,2021, Xcel Energy Inc. and its subsidiaries were in compliance with all financial covenants.
Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available as of Dec. 31, 2019:2021:
(Millions of Dollars)
Credit Facility (a)
Drawn (b)
Available
Xcel Energy Inc.$1,250 $638 $612 
PSCo700 155 545 
NSP-Minnesota500 9 491 
SPS500 139 361 
NSP-Wisconsin150 83 67 
Total$3,100 $1,024 $2,076 
(Millions of Dollars) 
Credit Facility (a)
 
Drawn (b)
 Available
Xcel Energy Inc. $1,250
 $—
 $1,250
PSCo 700
 9
 691
NSP-Minnesota 500
 2
 498
SPS 500
 40
 460
NSP-Wisconsin 150
 65
 85
Total $3,100
 $116
 $2,984
(a)These credit facilities mature in June 2024.
(b)Includes outstanding commercial paper and letters of credit.
(a)
These credit facilities mature in June 2024.
(b)
Includes outstanding commercial paper and letters of credit.
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had 0 no direct advances on facilities outstanding as of Dec. 31, 20192021 and 2018.2020.
Long-Term Borrowings and Other Financing Instruments
Generally, all property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are subject to the liens of their first mortgage indentures. 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 termLong-term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (Millions(in millions of Dollars)dollars):
Xcel Energy Inc.
Financing InstrumentInterest RateMaturity Date20212020
Unsecured senior notes2.40 %March 15, 2021$— $400 
Unsecured senior notes (b)
0.50 Oct. 15, 2023500 500 
Unsecured senior notes3.30 June 1, 2025250 250 
Unsecured senior notes3.30 June 1, 2025350 350 
Unsecured senior notes3.35 Dec. 1, 2026500 500 
Unsecured senior notes (a)
1.75 March 15,2027500 — 
Unsecured senior notes4.00 June 15, 2028130 130 
Unsecured senior notes4.00 June 15, 2028500 500 
Unsecured senior notes2.60 Dec. 1, 2029500 500 
Unsecured senior notes (b)
3.40 June 1, 2030600 600 
Unsecured senior notes (a)
2.35 Nov. 15, 2031300 — 
Unsecured senior notes6.50 July 1, 2036300 300 
Unsecured senior notes4.80 Sep. 15, 2041250 250 
Unsecured senior notes3.50 Dec. 1, 2049500 500 
Unamortized discount(8)(7)
Unamortized debt issuance cost(33)(32)
Current maturities— (400)
Total long-term debt$5,139 $4,341 
(a)2021 financing.
(b)2020 financing.
Xcel Energy Inc.
Financing Instrument Interest Rate Maturity Date 2019 2018
Unsecured senior notes (d)
 4.70% May 15, 2020 $—
 $550
Unsecured senior notes 2.40
 March 15, 2021 400
 400
Unsecured senior notes 2.60
 March 15, 2022 300
 300
Unsecured senior notes 3.30
 June 1, 2025 250
 250
Unsecured senior notes 3.30
 June 1, 2025 350
 350
Unsecured senior notes 3.35
 Dec. 1, 2026 500
 500
Unsecured senior notes (a)
 4.00
 June 15, 2028 130
 —
Unsecured senior notes (b)
 4.00
 June 15, 2028 500
 500
Unsecured senior notes (a)
 2.60
 Dec. 1, 2029 500
 —
Unsecured senior notes 6.50
 July 1, 2036 300
 300
Unsecured senior notes 4.80
 Sept. 15, 2041 250
 250
Unsecured senior notes (a)
 3.50
 Dec. 1, 2049 500
 —
Elimination of PSCo capital lease obligation with affiliates (c)
     —
 (60)
Unamortized discount     (5) (5)
Unamortized debt issuance cost     (28) (21)
Current maturities (capital lease obligation) (c)
     —
 2
Total long-term debt     $3,947
 $3,316
(a)
2019 financing.
(b)
2018 financing.
(c)
Xcel Energy adopted ASC 842 on Jan. 1, 2019, which refers to capital leases as finance leases. Under ASC 842, the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities rather than debt.
(d)
Note was redeemed on Dec. 23, 2019.
NSP-Minnesota
Financing InstrumentInterest RateMaturity Date20212020
First mortgage bonds2.15 %Aug. 15, 2022$300 $300 
First mortgage bonds2.60 May 15, 2023400 400 
First mortgage bonds7.125 July 1, 2025250 250 
First mortgage bonds6.50 March 1, 2028150 150 
First mortgage bonds (a)
2.25 April 1, 2031425 — 
First mortgage bonds5.25 July 15, 2035250 250 
First mortgage bonds6.25 June 1, 2036400 400 
First mortgage bonds6.20 July 1, 2037350 350 
First mortgage bonds5.35 Nov. 1, 2039300 300 
First mortgage bonds4.85 Aug. 15, 2040250 250 
First mortgage bonds3.40 Aug. 15, 2042500 500 
First mortgage bonds4.125 May 15, 2044300 300 
First mortgage bonds4.00 Aug. 15, 2045300 300 
First mortgage bonds3.60 May 15, 2046350 350 
First mortgage bonds3.60 Sep. 15, 2047600 600 
First mortgage bonds2.90 March 1, 2050600 600 
First mortgage bonds (b)
2.60 June 1, 2051700 700 
First mortgage bonds (a)
3.20 April 1,2052425 — 
Other long-term debt3 — 
Unamortized discount(44)(42)
Unamortized debt issuance cost(62)(54)
Current maturities(300)— 
Total long-term debt$6,447 $5,904 
(a)2021 financing.
(b)2020 financing.
NSP-Wisconsin
Financing InstrumentInterest RateMaturity Date20212020
City of La Crosse resource recovery bond6.00 %Nov. 1, 2021$— $19 
First mortgage bonds3.30 June 15, 2024100 100 
First mortgage bonds3.30 June 15, 2024100 100 
First mortgage bonds6.375 Sept. 1, 2038200 200 
First mortgage bonds3.70 Oct. 1, 2042100 100 
First mortgage bonds3.75 Dec. 1, 2047100 100 
First mortgage bonds4.20 Sept. 1, 2048200 200 
First mortgage bonds (b)
3.05 May 1, 2051100 100 
First mortgage bonds (a)
2.82 May 1, 2051100 — 
Other long-term debt1 — 
Unamortized discount(4)(4)
Unamortized debt issuance cost(10)(9)
Current maturities— (19)
Total long-term debt$987 $887 
(a)2021 financing.
(b)2020 financing.
NSP-Minnesota
Financing Instrument Interest Rate Maturity Date 2019 2018
First mortgage bonds 2.20% Aug. 15, 2020 $300
 $300
First mortgage bonds 2.15
 Aug. 15, 2022 300
 300
First mortgage bonds 2.60
 May 15, 2023 400
 400
First mortgage bonds 7.13
 July 1, 2025 250
 250
First mortgage bonds 6.50
 March 1, 2028 150
 150
First mortgage bonds 5.25
 July 15, 2035 250
 250
First mortgage bonds 6.25
 June 1, 2036 400
 400
First mortgage bonds 6.20
 July 1, 2037 350
 350
First mortgage bonds 5.35
 Nov. 1, 2039 300
 300
First mortgage bonds 4.85
 Aug. 15, 2040 250
 250
First mortgage bonds 3.40
 Aug. 15, 2042 500
 500
First mortgage bonds 4.13
 May 15, 2044 300
 300
First mortgage bonds 4.00
 Aug. 15, 2045 300
 300
First mortgage bonds 3.60
 May 15, 2046 350
 350
First mortgage bonds 3.60
 Sept. 15, 2047 600
 600
First mortgage bonds (a)
 2.90
 March 1, 2050 600
 —
Unamortized discount     (31) (21)
Unamortized debt issuance cost     (48) (42)
Current maturities     (300) —
Total long-term debt     $5,221
 $4,937
(a)
2019 financing.
NSP-Wisconsin
Financing Instrument Interest Rate Maturity Date 2019 2018
City of La Crosse resource recovery bond 6.00% Nov 1, 2021 $19
 $19
First mortgage bonds 3.30
 June 15, 2024 100
 100
First mortgage bonds 3.30
 June 15, 2024 100
 100
First mortgage bonds 6.38
 Sept. 1, 2038 200
 200
First mortgage bonds 3.70
 Oct. 1, 2042 100
 100
First mortgage bonds 3.75
 Dec. 1, 2047 100
 100
First mortgage bonds (a)
 4.20
 Sept. 1, 2048 200
 200
Unamortized discount     (3) (3)
Unamortized debt issuance cost     (8) (9)
Total long-term debt     $808
 $807
60
(a)
2018 financing.
PSCo
Financing Instrument Interest Rate Maturity Date 2019 2018
First mortgage bonds (d)
 5.13% June 1, 2019 $—
 $400
First mortgage bonds 3.20
 Nov. 15, 2020 400
 400
First mortgage bonds 2.25
 Sept. 15, 2022 300
 300
First mortgage bonds 2.50
 March 15, 2023 250
 250
First mortgage bonds 2.90
 May 15, 2025 250
 250
First mortgage bonds (b)
 3.70
 June 15, 2028 350
 350
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 (b)
 4.10
 June 15, 2048 350
 350
First mortgage bonds (a)
 4.05
 Sept. 15, 2049 400
 —
First mortgage bonds (a)
 3.20
 March 1, 2050 550
 —
Capital lease obligations (c)
 11.20 - 14.30
 2025 - 2060 —
 145
Unamortized discount     (24) (14)
Unamortized debt issuance cost     (41) (33)
Current maturities     (400) (406)
Total long-term debt     $4,985
 $4,592
Table of Contents
PSCo
Financing InstrumentInterest RateMaturity Date20212020
First mortgage bonds2.25 %Sept. 15, 2022$300 $300 
First mortgage bonds2.50 March 15, 2023250 250 
First mortgage bonds2.90 May 15, 2025250 250 
First mortgage bonds3.70 June 15, 2028350 350 
First mortgage bonds (b)
1.90 Jan. 15, 2031375 375 
First mortgage bonds (a)
1.875 June 15, 2031750 — 
First mortgage bonds6.25 Sept. 1, 2037350 350 
First mortgage bonds6.50 Aug. 1, 2038300 300 
First mortgage bonds4.75 Aug. 15, 2041250 250 
First mortgage bonds3.60 Sept. 15, 2042500 500 
First mortgage bonds3.95 March 15, 2043250 250 
First mortgage bonds4.30 March 15, 2044300 300 
First mortgage bonds3.55 June 15, 2046250 250 
First mortgage bonds3.80 June 15, 2047400 400 
First mortgage bonds4.10 June 15, 2048350 350 
First mortgage bonds4.05 Sept. 15, 2049400 400 
First mortgage bonds3.20 March 1, 2050550 550 
First mortgage bonds (b)
2.70 Jan. 15, 2051375 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.
SPS
Financing InstrumentInterest RateMaturity Date20212020
First mortgage bonds3.30 %June 15, 2024$150 $150 
First mortgage bonds3.30 June 15, 2024200 200 
Unsecured senior notes6.00 Oct. 1, 2033100 100 
Unsecured senior notes6.00 Oct. 1, 2036250 250 
First mortgage bonds4.50 Aug. 15, 2041200 200 
First mortgage bonds4.50 Aug. 15, 2041100 100 
First mortgage bonds4.50 Aug. 15, 2041100 100 
First mortgage bonds3.40 Aug. 15, 2046300 300 
First mortgage bonds3.70 Aug. 15, 2047450 450 
First mortgage bonds4.40 Nov. 15, 2048300 300 
First mortgage bonds3.75 June 15, 2049300 300 
First mortgage bonds (b)
3.15 May 1, 2050350 350 
First mortgage bonds (a)
3.15 May 1, 2050250 — 
Unamortized discount(9)(10)
Unamortized debt issuance cost(28)(26)
Total long-term debt$3,013 $2,764 
(a)2020 financing re-opened in 2021.
(b)2020 financing.
Other Subsidiaries
Financing InstrumentInterest RateMaturity Date20212020
Various Eloigne affordable housing project notes0.00% - 6.50%2022 — 2055$27 $27 
Current maturities(1)(2)
Total long-term debt$26 $25 

(a)
2019 financing.
(b)
2018 financing.
(c)
PSCo adopted ASC 842 on Jan. 1, 2019, which refers to capital leases as finance leases. Under ASC 842, the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities rather than debt.
(d)
Bond was redeemed on March 29, 2019.

SPS
Financing Instrument Interest Rate Maturity Date 2019 2018
First mortgage bonds 3.30% June 15, 2024 $150
 $150
First mortgage bonds 3.30
 June 15, 2024 200
 200
Unsecured senior notes 6.00
 Oct. 1, 2033 100
 100
Unsecured senior notes 6.00
 Oct. 1, 2036 250
 250
First mortgage bonds 4.50
 Aug. 15, 2041 200
 200
First mortgage bonds 4.50
 Aug. 15, 2041 100
 100
First mortgage bonds 4.50
 Aug. 15, 2041 100
 100
First mortgage bonds 3.40
 Aug. 15, 2046 300
 300
First mortgage bonds 3.70
 Aug. 15, 2047 450
 450
First mortgage bonds (b)
 4.40
 Nov. 15, 2048 300
 300
First mortgage bonds (a)
 3.75
 June 15, 2049 300
 —
Unamortized discount     (7) (4)
Unamortized debt issuance cost     (23) (20)
Total long-term debt     $2,420
 $2,126
(a)
2019 financing.
(b)
2018 financing.
Other Subsidiaries
Financing Instrument Interest Rate Maturity Date 2019 2018
Various Eloigne affordable housing project notes 0.00% - 6.90% 2020 — 2052 $28
 $26
Current maturities     (2) (1)
Total long-term debt     $26
 $25
Maturities of long-term debt:
(Millions of Dollars)  
2020 $702
2021 421
2022 900
2023 650
2024 552

(Millions of Dollars)
2022$601 
20231,150 
2024552 
20251,102 
2026501 
Deferred Financing Costs — Deferred financing costs of approximately $148$184 million and $126$167 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 20192021 and 2018,2020, respectively.
ForwardATM Equity AgreementsOffering — In November 2018,2021, Xcel Energy Inc. entered into forward equity agreements in connection withfiled a completed $459prospectus supplement under which it may sell up to $800 million public offering of 9.4 million sharesits common stock through an ATM program. As of Xcel Energy common stock. In August 2019, Xcel Energy settled the forward equity agreements by physically delivering 9.4 million shares of common equity for cash proceeds of $453 million.
In November 2019,Dec. 31, 2021, Xcel Energy Inc. entered into forward equity agreements in connection with a completed $743 million public offering of 11.8 million shares of Xcel Energy common stock. The initial forward agreement was for 10.3 million shares with an additional agreement for 1.5 million shares exercised at the option of the banking counterparty.
At Dec. 31, 2019, the forward agreements could have been settled with physical delivery of 11.8 million common shares to the banking counterparty in exchange for cash of $739 million. The forward instruments could also have been settled at Dec. 31, 2019 with delivery of approximately $6 million of cash or approximately 0.1had issued 5.33 million shares of common stock to the counterparty, if Xcel Energy unilaterally electedwith net cash or net share settlement, respectively.
The forward price used to determine amounts due at settlement is calculated based on the November 2019 public offering price for Xcel Energy’s common stockproceeds of $62.69, increased for the overnight bank funding rate, less a spread of 0.75% and less expected dividends on Xcel Energy’s common stock during the period the instruments are outstanding.
Xcel Energy may settle the agreements at any time up to the maturity date of Dec. 31, 2020. Depending on settlement timing, cash proceeds are expected to be approximately $730$347 million to $740 million.
Forward equity instruments were recognized within stockholders’ equity at fair value at execution of the agreements and will not be subsequently adjusted until settlement.
Other Equity —Xcel Energy issued $39 million of equity annually through the DRIP program during the years ended Dec. 31, 2019 and 2018, respectively. Program allows stockholders to elect dividend reinvestment in Xcel Energy common stock through a non-cash transaction. See Note 8 for equity items related to share based compensation.ATM program.
Capital Stock — Preferred stock authorized/outstanding:
 Preferred Stock Authorized (Shares) Par Value of Preferred Stock Preferred Stock Outstanding (Shares) 2019 and 2018Preferred Stock Authorized (Shares)Par Value of Preferred StockPreferred Stock Outstanding (Shares) 2021 and 2020
Xcel Energy Inc. 7,000,000
 $100
 —
Xcel Energy Inc.7,000,000 $100 — 
PSCo 10,000,000
 0.01
 —
PSCo10,000,000 0.01 — 
SPS 10,000,000
 1.00
 —
SPS10,000,000 1.00 — 
Xcel Energy Inc. had the following common stock authorized/outstanding:
Common Stock Authorized (Shares) Par Value of Common Stock Common Stock Outstanding (Shares) as of Dec. 31, 2019 Common Stock Outstanding (Shares) as of Dec. 31, 2018
1,000,000,000
 $2.50
 524,539,000
 514,036,787

Common Stock Authorized (Shares)Par Value of Common StockCommon Stock Outstanding (Shares) as of Dec. 31, 2021Common Stock Outstanding (Shares) as of Dec. 31, 2020
1,000,000,000 $2.50 544,025,269 537,438,394 
Dividend and Other Capital-Related Restrictions — Xcel Energy depends on its utility subsidiaries to pay dividends. Xcel Energy Inc.’s utility subsidiaries’ dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts. Dividends are solely to be paid from retained earnings. Certain covenants also require Xcel Energy Inc. to be current on interest payments prior to dividend disbursements.
State regulatory commissions impose dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those imposed by the FERC. Requirements and actuals as of Dec. 31, 2019:2021:
Equity to Total
Capitalization Ratio
Required Range		Equity to Total Capitalization Ratio Actual
LowHigh2021
NSP-Minnesota47.2 %57.6 %52.9 %
NSP-Wisconsin52.5 N/A52.8 
SPS (a)
45.0 55.0 54.5 
(a)    Excludes short-term debt.
  
Equity to Total
Capitalization Ratio
Required Range
 Equity to Total Capitalization Ratio Actual
  Low High 2019
NSP-Minnesota 47.1% 57.5% 52.3%
NSP-Wisconsin 51.5
 N/A
 51.8
SPS (a)
 45.0
 55.0
 54.4
61

(a)
Excludes short-term debt.
(Amounts in Millions) Unrestricted Retained Earnings Total Capitalization Limit on Total Capitalization
NSP-Minnesota $1,147
 $11,634
 $12,700
NSP-Wisconsin (a)
 12
 1,827
 N/A
SPS (b)
 535
 5,304
 N/A
(Amounts in Millions)Unrestricted Retained EarningsTotal CapitalizationLimit on Total Capitalization
NSP-Minnesota$1,558 $14,321 $15,332 
NSP-Wisconsin (a)
11 2,091 N/A
SPS (b)
513 6,615 N/A
(a)
(a)Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level.
(b)May not pay a dividend that would cause a loss of its investment grade bond rating.
Cannot pay annual dividends in excess of approximately $55 million if its average equity-to-total capitalization ratio falls below the commission authorized level.
(b)
May not pay a dividend that would cause a loss of its investment grade bond rating.

Issuance of securities by Xcel Energy Inc. generally is not generally subject to regulatory approval. However, utility financings and intra-system financings are subject to the jurisdiction of state regulatory commissions and/or the FERC. Xcel Energy may seek additional authorization as necessary.
Amounts authorized to issue as of Dec. 31, 2019:2021:
(Millions of Dollars)Long-Term DebtShort-Term Debt
NSP-Minnesota52.8% of total capitalization(a)$2,300 (a)
NSP-Wisconsin$150 150 
SPS— 600 
PSCo700 (b)800 
(a)    NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization.
(b)     PSCo filed for additional long-term debt authorization in December 2021.
(Millions of Dollars) Long-Term Debt Short-Term Debt 
NSP-Minnesota 52.93% of total capitalization
(a) 
$1,905
(a) 
NSP-Wisconsin $—
(b) 
150
 
SPS —
(c) 
600
 
PSCo 150
 800
 
(a)
NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization remains within the required range, and to issue short-term debt provided it does not exceed 15% of total capitalization.
(b)
NSP-Wisconsin filed for additional long-term debt authorization in December 2019.
(c)
SPS filed for additional long-term debt authorization in February 2020.
6. Revenues
Revenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy’s operating revenues consisted of the following:
Year Ended Dec. 31, 2021
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$3,194 $1,222 $45 $4,461 
C&I5,050 640 30 5,720 
Other127 — 7 134 
Total retail8,371 1,862 82 10,315 
Wholesale1,540 — — 1,540 
Transmission604 — — 604 
Other61 148 — 209 
Total revenue from contracts with customers10,576 2,010 82 12,668 
Alternative revenue and other629 122 12 763 
Total revenues$11,205 $2,132 $94 $13,431 
  Year Ended Dec. 31, 2019
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types        
Revenue from contracts with customers:
Residential $2,877
 $1,127
 $41
 $4,045
C&I 4,844
 567
 29
 5,440
Other 130
 —
 4
 134
Total retail 7,851
 1,694
 74
 9,619
Wholesale 737
 —
 —
 737
Transmission 507
 —
 —
 507
Other 49
 120
 —
 169
Total revenue from contracts with customers 9,144
 1,814
 74
 11,032
Alternative revenue and other 431
 54
 12
 497
Total revenues $9,575
 $1,868
 $86
 $11,529
  Year Ended Dec. 31, 2018
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types        
Revenue from contracts with customers:
Residential $2,919
 $988
 $38
 $3,945
C&I 4,874
 524
 25
 5,423
Other 134
 —
 6
 140
Total retail 7,927
 1,512
 69
 9,508
Wholesale 791
 —
 —
 791
Transmission 523
 —
 —
 523
Other 98
 100
 —
 198
Total revenue from contracts with customers 9,339
 1,612
 69
 11,020
Alternative revenue and other 380
 127
 10
 517
Total revenues $9,719
 $1,739
 $79
 $11,537

Year Ended Dec. 31, 2020
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$3,066 $975 $42 $4,083 
C&I4,596 462 27 5,085 
Other125 — 6 131 
Total retail7,787 1,437 75 9,299 
Wholesale759 — — 759 
Transmission579 — — 579 
Other73 137 — 210 
Total revenue from contracts with customers9,198 1,574 75 10,847 
Alternative revenue and other604 62 13 679 
Total revenues$9,802 $1,636 $88 $11,526 
Year Ended Dec. 31, 2019
(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue types
Revenue from contracts with customers:
Residential$2,877 $1,127 $41 $4,045 
C&I4,844 567 29 5,440 
Other130 — 4 134 
Total retail7,851 1,694 74 9,619 
Wholesale737 — — 737 
Transmission507 — — 507 
Other49 120 — 169 
Total revenue from contracts with customers9,144 1,814 74 11,032 
Alternative revenue and other431 54 12 497 
Total revenues$9,575 $1,868 $86 $11,529 
7. Income Taxes
Federal Tax Reform —Loss Carryback Claims - In 2017, the TCJA was signed into law. The key provisions impacting2020, Xcel Energy generally beginning in 2018, included:
Corporate federal tax rate reduction from 35% to 21%;
Normalization of resulting plant-related excess deferred taxes;
Elimination of the corporate alternative minimum tax;
Continued interest expense deductibility and discontinued bonus depreciation for regulated public utilities;
Limitations onidentified certain executive compensation deductions;
Limitations on certain deductions for NOLs arising after Dec. 31, 2017 (limited to 80% of taxable income);
Repeal of the section 199 manufacturing deduction; and
Reduced deductions for meals and entertainment as well as state and local lobbying.
Reductions in deferred tax assets and liabilities due to a decrease in corporate federal tax rates typically result in a net tax benefit. However, the impacts are primarily recognized as regulatory liabilities refundable to utility customers as a result of IRS requirements and past regulatory treatment.
Estimated impacts of the new tax law in December 2017 included:
$2.7 billion ($3.8 billion grossed-up for tax) of reclassifications of plant-related excess deferred taxes to regulatory liabilities upon valuation at the new 21% federal rate. The regulatory liabilities will be amortized consistent with IRS normalization requirements, resulting in customer refunds over an estimated weighted average period of approximately 30 years;
$254 million and $174 million of reclassifications (grossed-up for tax) of excess deferred taxes for non-plant related deferred tax assets and liabilities, respectively, to regulatory assets and liabilities; and
$23 million of total estimated income tax expense related to the tax rate change on certain non-plant deferred taxes and all other 2017 income statement impactsyears 2009 - 2011 that qualify for an extended carryback claim. As a result, a tax benefit of the federal tax reform.
Xcel Energy accounted for the state tax impacts of federal tax reform based on enacted state tax laws. Any future state tax law changes related to the TCJA will be accounted forapproximately $13 million was recognized in the periods state laws are enacted.2020.
Federal Audit — Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns:returns expire as follows:
Tax Year(s)Expiration
2009 - 2013June 2020
2014 - 2016December 2022
2018September 20202022

In 2015,Additionally, the IRS commenced an examinationstatute of limitations related to the federal tax years 2012 and 2013. In 2017,credit carryforwards will remain open until those credits are utilized in subsequent returns. Further, the IRS concludedstatute of limitations related to the audit ofadditional federal tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energyloss carryback claim filed a protest with the IRS. As of Dec. 31, 2019, the casein 2020 has been forwarded to the Office of Appeals andextended. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.
In 2018, the IRS began an audit
62

State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions and various other state income-based tax returns.
As of Dec. 31, 2019,2021, Xcel Energy’s earliest open tax years (subject to examination by state taxing authorities in its major operating jurisdictions) were as follows:
StateYear
Colorado20092014
Minnesota20092014
Texas20092016
Wisconsin20142016
•In 2018,April 2021, Texas began an audit of tax years 2016-2019. As of Dec. 31, 2021, 0 material adjustments have been proposed.
•In March 2021, Wisconsin began an audit of tax years 20142016 - 2016.2019. As of Dec. 31, 2019, no2021, 0 material adjustments have been proposed.
Xcel Energy had no•In July 2020, Minnesota began an audit of tax years 2015 - 2018. As of Dec. 31, 2021, 0 material adjustments have been proposed.
•NaN other state income tax audits in progress for its major operating jurisdictions as of Dec. 31, 2019.2021.
Unrecognized Tax Benefits — Unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain, but for which there is uncertainty about the timing of such deductibility.timing. A change in the period of deductibility would not affect the ETR but would accelerate the payment to the taxing authority to an earlier period.authority.
Unrecognized tax benefits - permanent vs. temporary:
(Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018(Millions of Dollars)Dec. 31, 2021Dec. 31, 2020
Unrecognized tax benefit — Permanent tax positions $35
 $28
Unrecognized tax benefit — Permanent tax positions$47 $41 
Unrecognized tax benefit — Temporary tax positions 9
 9
Unrecognized tax benefit — Temporary tax positions11 11 
Total unrecognized tax benefit $44
 $37
Total unrecognized tax benefit$58 $52 
Changes in unrecognized tax benefits:
(Millions of Dollars) 2019 2018 2017
Balance at Jan. 1 $37
 $39
 $134
Additions based on tax positions related to the current year 10
 9
 6
Reductions based on tax positions related to the current year (4) (4) (4)
Additions for tax positions of prior years 1
 2
 15
Reductions for tax positions of prior years —
 (4) (105)
Settlements with taxing authorities —
 (5) (7)
Balance at Dec. 31 $44
 $37
 $39

(Millions of Dollars)202120202019
Balance at Jan. 1$52 $44 $37 
Additions based on tax positions related to the current year5 9 10 
Reductions based on tax positions related to the current year— (2)(4)
Additions for tax positions of prior years2 35 1 
Reductions for tax positions of prior years(1)(34)— 
Balance at Dec. 31$58 $52 $44 
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
(Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018
NOL and tax credit carryforwards $(40) $(35)

Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $29 million and $24 million at Dec. 31, 2019 and Dec. 31, 2018, respectively.
(Millions of Dollars)Dec. 31, 2021Dec. 31, 2020
NOL and tax credit carryforwards$(36)$(31)
As the IRS Appealsprogresses its review of the tax loss carryback claims and federal andas state audits progress, and other state audits resume, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $28 million in the next 12 months.
Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.
No amounts
Interest payable related to unrecognized tax benefits:
(Millions of Dollars)202120202019
Payable for interest related to unrecognized tax benefits at Jan. 1$(3)$— $— 
Interest expense related to unrecognized tax benefits— (3)— 
Payable for interest related to unrecognized tax benefits at Dec. 31$(3)$(3)$— 
NaN penalties were payable for interestaccrued related to unrecognized tax benefits as of Dec. 31, 2019, 20182021, 2020 or 2017. No interest income related to unrecognized tax benefits was recorded in 2019 or 2018, and $3 million was recorded in 2017.
No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2019, 2018 or 2017.2019.
Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31:
(Millions of Dollars)20212020
Federal NOL carryforward$765 $— 
Federal tax credit carryforwards1,172 791 
State NOL carryforwards1,648 839 
Valuation allowances for state NOL carryforwards(3)(4)
State tax credit carryforwards, net of federal detriment (a)
89 89 
Valuation allowances for state credit carryforwards, net of federal benefit (b)
(64)(64)
(Millions of Dollars) 2019 2018
Federal tax credit carryforwards $639
 $553
Valuation allowances for federal credit carryforwards —
 (5)
State NOL carryforwards 937
 1,104
Valuation allowances for state NOL carryforwards (19) (50)
State tax credit carryforwards, net of federal detriment (a)
 89
 89
Valuation allowances for state credit carryforwards, net of federal benefit (b)
 (66) (69)
(a)State tax credit carryforwards are net of federal detriment of $24 million as of Dec. 31, 2021 and 2020.
(a)
(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $17 million as of Dec. 31, 2021 and 2020.
State tax credit carryforwards are net of federal detriment of $24 million as of Dec. 31, 2019 and 2018.
(b)
Valuation allowances for state tax credit carryforwards were net of federal benefit of $17 million and $18 million as of Dec. 31, 2019 and 2018, respectively.
Federal carryforward periods expire between 20232031 and 20392041 and state carryforward periods expire between 2020 and 2036.starting 2022.
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:
202120202019
Federal statutory rate21.0 %21.0 %21.0 %
State income tax on pretax income, net of federal tax effect5.0 4.9 4.9 
(Decreases) increases in tax from:
Wind PTCs(23.4)(15.7)(9.4)
Plant regulatory differences (a)
(6.2)(7.6)(5.8)
Other tax credits, net NOL & tax credit allowances(1.1)(1.2)(1.7)
NOL Carryback— (0.9)— 
Change in unrecognized tax benefits0.4 0.5 0.5 
Other, net(0.3)(1.4)(1.0)
Effective income tax rate(4.6)%(0.4)%8.5 %
(a)Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions and additional prepaid pension asset amortization.
 2019 
2018 (a)
 
2017 (a)
Federal statutory rate21.0 % 21.0 % 35.0 %
State income tax on pretax income, net of federal tax effect4.9
 5.0
 4.1
Increases (decreases) in tax from:     
Wind PTCs(9.4) (5.2) (4.7)
Plant regulatory differences (b)
(5.8) (6.2) (0.8)
Other tax credits, net of NOL & tax credit allowances(1.7) (1.7) (1.0)
Change in unrecognized tax benefits0.5
 0.4
 (0.6)
Tax reform—
 —
 1.4
Other, net(1.0) (0.7) (1.3)
Effective income tax rate8.5 % 12.6 % 32.1 %
63
(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 years ended Dec. 31:
(Millions of Dollars) 2019 2018 2017
Current federal tax (benefit) expense $(16) $(34) $1
Current state tax expense (benefit) 4
 8
 (11)
Current change in unrecognized tax expense (benefit) 2
 (6) (83)
Deferred federal tax expense 55
 122
 460
Deferred state tax expense 83
 85
 107
Deferred change in unrecognized tax expense 5
 11
 73
Deferred ITCs (5) (5) (5)
Total income tax expense $128
 $181
 $542

(Millions of Dollars)202120202019
Current federal tax expense (benefit)$15 $(13)$(16)
Current state tax (benefit) expense(2)2 4 
Current change in unrecognized tax expense1 18 2 
Deferred federal tax (benefit) expense(183)(89)55 
Deferred state tax expense99 91 83 
Deferred change in unrecognized tax expense (benefit)5 (10)5 
Deferred ITCs(5)(5)(5)
Total income tax (benefit) expense$(70)$(6)$128 
Components of deferred income tax expense as of Dec. 31:
(Millions of Dollars) 2019 2018 2017
Deferred tax expense (benefit) excluding items below $344
 $320
 $(2,939)
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (206) (102) 3,583
Tax benefit (expense) allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other 5
 —
 (4)
Deferred tax expense $143
 $218
 $640

(Millions of Dollars)202120202019
Deferred tax expense excluding items below$148 $237 $344 
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities(221)(247)(206)
Tax (benefit) expense allocated to other comprehensive income, adoption of ASC Topic 326, and other(6)2 5 
Deferred tax (benefit) expense$(79)$(8)$143 
Components of net deferred tax liability as of Dec. 31:
(Millions of Dollars) 2019 
2018 (a)
(Millions of Dollars)2021
2020 (a)
Deferred tax liabilities:  
  
Deferred tax liabilities:
Differences between book and tax bases of property $5,474
 $5,082
Differences between book and tax bases of property$6,231 $5,810 
Operating lease assets 449
 —
Operating lease assets351 400 
Regulatory assets 598
 599
Regulatory assets598 603 
Deferred fuel costsDeferred fuel costs262 (6)
Pension expense 173
 178
Pension expense175 176 
Other 70
 60
Other93 74 
Total deferred tax liabilities $6,764
 $5,919
Total deferred tax liabilities$7,710 $7,057 
    
Deferred tax assets:  
  
Deferred tax assets:
Regulatory liabilities $847
 $879
Regulatory liabilities$780 $806 
Operating lease liabilities 449
 —
Operating lease liabilities351 400 
Tax credit carryforward 727
 642
Tax credit carryforward1,261 880 
NOL carryforward 38
 51
NOL carryforward247 37 
NOL and tax credit valuation allowances (67) (79)NOL and tax credit valuation allowances(64)(64)
Other employee benefits 128
 124
Other employee benefits119 141 
Deferred ITCs 14
 16
Deferred ITCs15 13 
Rate refund 26
 60
Other 93
 61
Other107 98 
Total deferred tax assets $2,255
 $1,754
Total deferred tax assets$2,816 $2,311 
Net deferred tax liability $4,509
 $4,165
Net deferred tax liability$4,894 $4,746 
(a)Prior periods have been reclassified to conform to current year presentation.

8. Share-Based Compensation
Incentive PlansPlan Including Share-Based Compensation — Xcel Energy has twoan incentive plansplan which includeincludes share-based payment elements. Planselements, the Amended and authorized equity shares for awards:
Restated 2015 Omnibus Incentive Plan -with 7.0 million shares; and
Executive Annual Incentive Award Plan - 1.2 million shares.equity shares authorized.
Restricted Stock — The Executive Annual Incentive Award PlanAmended and Restated 2015 Omnibus Incentive Plan allowallows certain employees to elect to receive shares of common or restricted stock. Restricted stock is treated as an equity award and vests and settles in equal annual installments over a three-yearthree-year period. Restricted stock has a fair value equal to the market trading price of Xcel Energy stock at the grant date.
Shares of restricted stock granted at Dec. 31:
(Shares in Thousands) 2019 2018 2017(Shares in Thousands)202120202019
Granted shares 13
 18
 15
Granted shares2 1 13 
Grant date fair value $53.46
 $44.68
 $42.00
Grant date fair value$61.54 $70.26 $53.46 
Changes in nonvested restricted stock:
(Shares in Thousands) Shares Weighted Average
Grant Date Fair Value
Nonvested restricted stock at Jan. 1, 2019 36
 $44.29
Granted 13
 53.46
Forfeited —
 —
Vested (19) 41.60
Dividend equivalents 1
 57.09
Nonvested restricted stock at Dec. 31, 2019 31
 50.15

(Shares in Thousands)SharesWeighted Average
Grant Date Fair Value
Nonvested restricted stock at Jan. 1, 202115 $56.68 
Granted2 61.54 
Forfeited— 70.26 
Vested(9)49.71 
Dividend equivalents— 66.73 
Nonvested restricted stock at Dec. 31, 20218 67.26 
Other Equity Awards — Xcel Energy‘s Board of Directors has granted equity awards under the Amended and Restated 2015 Omnibus Incentive Plan, which includes various vesting conditions and performance goals. At the end of the restricted period, such grants will be awarded if vesting conditions and/or performance goals are met.
Certain employees are granted equity awards with a portion subject only to service conditions, and the other portion subject to performance conditions. A total of 0.2 million, 0.2 million, and 0.3 million time-based equity shares subject only to service conditions were granted annually in 2019, 20182021, 2020 and 2017,2019, respectively.
The performance conditions for a portion of the awards granted from 20172019 to 20192021 are based on relative TSR and environmental goals. Equity awards with performance conditions will be settled or forfeited after three years, with payouts ranging from 0zero to 200 percent200% depending on achievement.
Equity award units granted to employees (excluding restricted stock):
(Units in Thousands) 2019 2018 2017(Units in Thousands)202120202019
Granted units 483
 500
 503
Granted units421 411 483 
Weighted average grant date fair value $49.67
 $47.60
 $41.02
Weighted average grant date fair value$66.03 $62.92 $49.67 
Equity awards vested:
(Units in Thousands) 2019 2018 2017
(Units in Thousands, Fair Value in Millions)(Units in Thousands, Fair Value in Millions)202120202019
Vested Units 464
 475
 467
Vested Units392 442 464 
Total Fair Value $29,432
 $23,393
 $22,459
Total Fair Value$27 $29 $29 
Changes in the nonvested portion of equity award units:
(Units in Thousands)UnitsWeighted Average
Grant Date Fair Value
Nonvested Units at Jan. 1, 2021780 $55.68 
Granted421 66.03 
Forfeited(146)61.76 
Vested(392)48.91 
Dividend equivalents32 58.00 
Nonvested Units at Dec. 31, 2021695 64.59 
(Units in Thousands) Units Weighted Average
Grant Date Fair Value
Nonvested Units at Jan. 1, 2019 939
 $44.30
Granted 483
 49.67
Forfeited (116) 50.19
Vested (464) 41.09
Dividend equivalents 38
 45.22
Nonvested Units at Dec. 31, 2019 880
 48.20
64

Table of Contents
Stock Equivalent Units — Non-employee members of Xcel Energy‘s Board of Directors may elect to receive their annual equity grant as stock equivalent units in lieu of common stock. Each unit’s value is equal to 1 share of common stock. The annual equity grant is vested as of the date of each member’s election to the Board of Directors; there is no further service or other condition. Directors may also elect to receive their cash fees as stock equivalent units in lieu of cash. Stock equivalent units are payable as a distribution of common stock upon a director’s termination of service.
Stock equivalent units granted:
(Units in Thousands) 2019 2018 2017(Units in Thousands)202120202019
Granted units 29
 36
 51
Granted units31 33 29 
Weighted average grant date fair value $58.44
 $45.44
 $46.05
Weighted average grant date fair value$68.15 $61.61 $58.44 

Changes in stock equivalent units:
(Units in Thousands) Units Weighted Average
Grant Date Fair Value
Stock equivalent units at Jan. 1, 2019 688
 $30.93
Granted 29
 58.44
Units distributed (11) 32.56
Dividend equivalents 19
 57.28
Stock equivalent units at Dec. 31, 2019 725
 32.72

(Units in Thousands)UnitsWeighted Average
Grant Date Fair Value
Stock equivalent units at Jan. 1, 2021630 $36.28 
Granted31 68.15 
Units distributed(73)31.47 
Dividend equivalents16 66.98 
Stock equivalent units at Dec. 31, 2021604 39.27 
TSR Liability Awards — Xcel Energy Inc.’s Board of Directors has granted TSR liability awards under the Amended and Restated 2015 Omnibus Incentive Plan. This plan allows Xcel Energy to attach various performance goals to the awards granted. The liability awards have been historically dependent on relative TSR measured over a three-yearthree-year period. Xcel Energy Inc.’s TSR is compared to a peer group of 20 other utility members.companies. Potential payouts of the awards range from 0zero to 200%.
TSR liability awards granted:
(In Thousands) 2019 2018 2017(In Thousands)202120202019
Awards granted 225
 239
 240
Awards granted221 212 225 
TSR liability awards settled:
(In Thousands) 2019 2018 2017
Awards settled 466
 482
 454
Settlement amount (cash, common stock and deferred amounts) $24,930
 $21,534
 $19,083

(Units In Thousands, Settlement Amount in Millions)202120202019
Awards settled446 476 466 
Settlement amount (cash, common stock and deferred amounts)$27 $33 $25 
TSR liability awards of $21$22 million were settled in cash in 2019.2021.
Share-Based Compensation Expense — Other than for restricted stock, vesting of employee equity awards is typically predicated on the achievement of a TSR or environmental measures target. Additionally, approximately 0.2 million, 0.2 million, and 0.3 million of equity award units were granted annually in 2017 -2021, 2020, and 2019, respectively, with vesting subject only to service conditions of three years.
Generally, these instruments are considered to be equity awards as the award settlement determination (shares or cash) is made by Xcel Energy, not the participants. In addition, these awards have not been previously settled in cash and Xcel Energy plans to continue electing share settlement.
Grant date fair value of equity awards is expensed over the service period. TSR liability awards have been historically settled partially in cash, and do not qualify as equity awards, but rather are accounted for as liabilities. As liability awards, the fair value on which ratable expense is based, as employees vest in their rights to those awards, is remeasured each period based on the current stock price and performance achievement, and final expense is based on the market value of the shares on the date the award is settled.
Compensation costs related to share-based awards:
(Millions of Dollars)202120202019
Compensation cost for share-based awards (a)
$31 $73 $58 
Tax benefit recognized in income8 19 15 
(Millions of Dollars) 2019 2018 2017
Compensation cost for share-based awards (a)
 $58
 $45
 $57
Tax benefit recognized in income 15
 12
 22
(a)(a)Compensation costs for share-based payments are included in O&M expense.
Compensation costs for share-based payment are included in O&M expense.
There was approximately $40$28 million in 20192021 and $38$51 million in 20182020 of total unrecognized compensation cost related to nonvested share-based compensation awards. Xcel Energy expects to recognize the unrecognized amount over a weighted average period of 1.6 years.
9. Earnings Per Share

Basic EPS was computed by dividing the earnings available to common shareholders by the weighted average number of common shares outstanding during the period.outstanding. Diluted EPS was computed by dividing the earnings available to common shareholders by the diluted weighted average number of common shares outstanding during the period. outstanding.
Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate diluted EPS is calculated using the treasury stock method.
Common Stock Equivalents — Xcel Energy Inc. has common stock equivalents related to forward equity agreements and certain equity awards in share-based compensation arrangements. Common stock equivalents include commitments to issue common stock related to time-based equity compensation awards.
Stock equivalent units granted to Xcel Energy’s Board of Directors are included in common shares outstanding upon grant date as there is no further service, performance or market condition associated with these. Restricted stock issued to employees under the Executive Annual Incentive Award Plan is included in common shares outstanding when granted.
Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following:
•Equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions for settlement have been satisfied by the end of the reporting period; andperiod.
•Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement.
Common shares outstanding used in the basic and diluted EPS computation:
(Shares in Millions)202120202019
Basic539527519
Diluted (a)
540 528 520 
(a)Diluted common shares outstanding included common stock equivalents of 1.30.3 million, 0.51.1 million and 0.61.3 million shares for 2021, 2020 and 2019, 2018 and 2017.respectively.
65
10. 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.
•— 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; and
•
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.

Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs. The investments in commingled funds may be redeemed for NAV with proper notice. Private equity commingled fund investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate commingled fundsfund investments may be redeemed with proper notice, however, withdrawals may be delayed or discounted as a result of fund illiquidity.
Investments in debt securities — Fair values for debt securities are determined by a third-party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.
Interest rate derivatives — Fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Commodity derivatives — Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When 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.
Electric commodity derivatives held by NSP-Minnesota and SPS include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from aan RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path.
The value of an FTR is derived from, and designed to offset, the cost of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR.
If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of certain inputs to the value of FTRs between auction processes, including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3.
Non-trading monthly FTR settlements are included in fuel and purchased energy cost recovery mechanisms as applicable in each jurisdiction, and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of NSP-Minnesota and SPS, the numerous unobservable quantitative inputs pertinent to the value of FTRs are immaterial to the consolidated financial statements.
Non-Derivative Fair Value Measurements
Nuclear Decommissioning Fund
The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust.
NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset.
Unrealized gains for the nuclear decommissioning fund were $706 million$1.3 billion and $450$981 million as of Dec. 31, 20192021 and 2018,2020, respectively, and unrealized losses were $6$7 million and $45$5 million as of Dec. 31, 20192021 and 2018,2020, respectively.
Non-derivative instruments with recurring fair value measurements:
 Dec. 31, 2019Dec. 31, 2021
   Fair ValueFair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total(Millions of Dollars)CostLevel 1Level 2Level 3NAVTotal
Nuclear decommissioning fund (a)
            
Nuclear decommissioning fund (a)
Cash equivalents $33
 $33
 $—
 $—
 $—
 $33
Cash equivalents$64 $64 $— $— $— $64 
Commingled funds 733
 —
 —
 —
 935
 935
Commingled funds856 — — — 1,294 1,294 
Debt securities 489
 —
 495
 13
 —
 508
Debt securities631 — 666 9 — 675 
Equity securities 485
 962
 2
 —
 —
 964
Equity securities411 1,222 1 — — 1,223 
Total $1,740
 $995
 $497
 $13
 $935
 $2,440
Total$1,962 $1,286 $667 $9 $1,294 $3,256 
(a)
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $208 million of equity investments in unconsolidated subsidiaries and $164 million of rabbi trust assets and miscellaneous investments.
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $155 million of equity investments in unconsolidated subsidiaries and $136 million of rabbi trust assets and miscellaneous investments.
  Dec. 31, 2018
    Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total
Nuclear decommissioning fund (a)
            
Cash equivalents $24
 $24
 $—
 $—
 $—
 $24
Commingled funds 758
 79
 —
 —
 819
 898
Debt securities 466
 —
 436
 —
 —
 436
Equity securities 401
 697
 —
 —
 —
 697
Total $1,649
 $800
 $436
 $—
 $819
 $2,055
66
(a)
Dec. 31, 2020
Fair Value
(Millions of Dollars)CostLevel 1Level 2Level 3NAVTotal
Nuclear decommissioning fund (a)
Cash equivalents$40 $40 $— $— $— $40 
Commingled funds787 — — — 1,041 1,041 
Debt securities528 — 572 13 — 585 
Equity securities446 1,109 2 — — 1,111 
Total$1,801 $1,149 $574 $13 $1,041 $2,777 
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $165 million of equity investments in unconsolidated subsidiaries and $154 million of rabbi trust assets and miscellaneous investments.
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $141 million of equity investments in unconsolidated subsidiaries and $121 million of rabbi trust assets and miscellaneous investments.
For the years ended Dec. 31, 20192021 and 2018,2020, there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.

Contractual maturity dates of debt securities in the nuclear decommissioning fund as of Dec. 31, 2019:2021:
  Final Contractual Maturity
(Millions of Dollars) 
Due in 1 Year
or Less
 
Due in 1 to 5
Years
 
Due in 5 to 10
Years
 
Due after 10
Years
 Total
Debt securities $(7) $111
 $246
 $158
 $508

Final Contractual Maturity
(Millions of Dollars)Due in 1 year or LessDue in 1 to 5 YearsDue in 5 to 10 YearsDue after 10 yearsTotal
Debt securities$4 $149 $208 $314 $675 
Rabbi Trusts
Xcel Energy has established rabbi trusts to provide partial funding for future distributions of its SERP and deferred compensation plan.
Cost and fair value of assets held in rabbi trusts:
Dec. 31, 2021
Fair Value
(Millions of Dollars)CostLevel 1Level 2Level 3Total
Rabbi Trusts (a)
Cash equivalents$20 $20 $— $— $20 
Mutual funds75 89 — — 89 
Total$95 $109 $— $— $109 
  Dec. 31, 2019
    Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 Total
Rabbi Trusts (a)
          
Cash equivalents $17
 $17
 $—
 $—
 $17
Mutual funds 57
 65
 —
 —
 65
Total $74
 $82
 $—
 $—
 $82
(a)(a)    Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
 Dec. 31, 2018Dec. 31, 2020
   Fair ValueFair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 Total(Millions of Dollars)CostLevel 1Level 2Level 3Total
Rabbi Trusts (a)
          
Rabbi Trusts (a)
Cash equivalents $16
 $16
 $—
 $—
 $16
Cash equivalents$32 $32 $— $— $32 
Mutual funds 52
 51
 —
 —
 51
Mutual funds60 70 — — 70 
Total $68
 $67
 $—
 $—
 $67
Total$92 $102 $— $— $102 
(a)    Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
(a)
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
Derivative Instruments Fair Value Measurements
Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.
Interest Rate Derivatives — Xcel Energy enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or 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.purposes, with changes in fair value prior to settlement recorded as other comprehensive income.
As of Dec. 31, 2019,2021, accumulated other comprehensive lossesloss related to settled interest rate derivatives included $5 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, 2019,2021, Xcel Energy had 0no unsettled interest rate swaps outstanding. These interest rate derivatives were designated as hedges, and as such, changes in fair value are recorded to other comprehensive income.derivatives.
Wholesale and Commodity Trading Risk — Xcel Energy Inc.’s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Xcel Energy is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in activities governed by this policy.
Commodity Derivatives — Xcel Energy enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, 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, FTRs, vehicle fuel and weather derivatives.
As of Dec. 31, 2019, Xcel Energy had 0 commodity derivative contracts designated as cash flow hedges. Xcel Energy may enter 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. Changes in the fair valueThe classification of non-trading commodity derivativeunrealized losses or gains on these instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability, if applicable, is based on commission approved regulatory recovery mechanisms. Immaterial amounts to income related to the ineffectiveness of cash flow hedges were recorded for the years ended Dec. 31, 2019 and 2018.
As of Dec. 31, 2019, there were 0 net gains related to2021, Xcel Energy had no commodity derivativecontracts designated as cash flow hedges recorded as a component of accumulated other comprehensive losses or related amounts expected to be reclassified into earnings during the next 12 months.hedges.
Xcel Energy 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 amountamounts of commodity forwards, options and FTRs at Dec. 31:FTRs:
(Amounts in Millions) (a)(b)
Dec. 31, 2021Dec. 31, 2020
MWh of electricity80 87 
MMBtu of natural gas156 175 
(Millions of Dollars) (a) (b)
 2019 2018
MWh of electricity 95
 87
MMBtu of natural gas 110
 92
(a)Not reflective of net positions in the underlying commodities.
(a)
(b)Notional amounts for options included on a gross basis but weighted for the probability of exercise.
Amounts are not reflective of net positions in the underlying commodities.
(b)
Notional amounts for options are included on a gross basis but weighted for the probability of exercise.
Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented inon the consolidated balance sheets.
Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities.
67
As of Dec. 31, 2019,2021, 6 of Xcel Energy’s 10 most significant counterparties for these activities, comprising $154$83 million or 60%38% of this credit exposure, had investment grade credit ratings from Standard & Poor’s,S&P, Moody’s Investor Services or Fitch Ratings. NaN of the 10 most significant counterparties, comprising $37$44 million or 14%20% of this credit exposure, were not rated by these external agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade. NaN of these significant counterparties, comprising $38 million or 18% of this credit exposure, had credit quality less than investment grade, based on internal analysis. NaN of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.

Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate and vehicle fuel cash flow hedges on Xcel Energy’s accumulated other comprehensive loss, included in the consolidated statements of common stockholders’ equity and in the consolidated statements of comprehensive income:
(Millions of Dollars)202120202019
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1$(85)$(80)$(60)
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges4 (10)(23)
After-tax net realized losses on derivative transactions reclassified into earnings6 5 3 
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31$(75)$(85)$(80)
(Millions of Dollars) 2019 2018 2017
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $(60) $(58) $(51)
After-tax net unrealized losses related to derivatives accounted for as hedges (23) (5) —
After-tax net realized losses on derivative transactions reclassified into earnings 3
 3
 3
Adoption of ASU. 2018-02 (a)
 —
 —
 (10)
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $(80) $(60) $(58)
(a)
In 2017, Xcel Energy implemented ASU No 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings.
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, 2019    
Derivatives designated as cash flow hedges    
Interest rate $(30) $—
Total (30) —
Other derivative instruments    
Electric commodity —
 8
Natural gas commodity —
 (9)
Total —
 (1)
     
Year Ended Dec. 31, 2018    
Interest rate (7) —
Total (7) —
Other derivative instruments    
Electric commodity —
 1
Natural gas commodity —
 10
Total —
 11
     
Year Ended Dec. 31, 2017    
Other derivative instruments    
Electric commodity —
 10
Natural gas commodity —
 (13)
Total $—
 $(3)

 
Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from:
 
Pre-Tax Gains
(Losses) Recognized
During the Period in Income
 
(Millions of Dollars)Accumulated
Other
Comprehensive Loss		 Regulatory
Assets and (Liabilities)		  
Year Ended Dec. 31, 2019      
Derivatives designated as cash flow hedges      
Interest rate$4
(a) 
$—
 $—
 
Total4
 —
 —
 
Other derivative instruments      
Commodity trading—
 —
 2
(b) 
Electric commodity—
 (5)
(c) 
—
 
Natural gas commodity—
 2
(d) 
(7)
(d) 
Total—
 (3) (5) 
       
Year Ended Dec. 31, 2018      
Derivatives designated as cash flow hedges      
Interest rate4
(a) 
—
 —
 
Total4
 —
 —
 
Other derivative instruments      
Commodity trading—
 —
 14
(b) 
Electric commodity—
 (1)
(c) 
—
 
Natural gas commodity—
 (6)
(d) 
(4)
(d) 
Total—
 (7) 10
 
       
Year Ended Dec. 31, 2017      
Derivatives designated as cash flow hedges      
Interest rate5
(a) 
—
 —
 
Total5
 —
 —
 
Other derivative instruments      
Commodity trading—
 —
 10
(b) 
Electric commodity—
 (15)
(c) 
—
 
Natural gas commodity—
 3
(d) 
(6)
(d) 
Total$—
 $(12) $4
 
(a)
Amounts recorded to interest charges.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
(b)Derivatives designated as cash flow hedges
Amounts 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)Interest rate
Amounts recorded to electric fuel and purchased power. These$5 $— 
Total$5 $— 
Other derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms and reclassified out of income as regulatory assets or liabilities, as appropriate.instruments
(d)Electric commodity
Amounts for the year ended$— $32 
Natural gas commodity— (4)
Total$— $28 
Year Ended Dec. 31, 2019 included 0 settlement losses on derivatives entered to mitigate natural2020
Interest rate$(13)$— 
Total$(13)$— 
Other derivative instruments
Electric commodity$— $(5)
Natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Such losses and gains for the years endedcommodity— (13)
Total$— $(18)
Year Ended Dec. 31, 2018 and 2017 were $1 million and immaterial, respectively. Remaining settlement losses for the years ended Dec. 31, 2019 2018 and 2017 related to natural
Interest rate$(30)$— 
Total$(30)$— 
Other derivative instruments
Electric commodity$— $8 
Natural gas operations and were recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.commodity— (9)
Total$— $(1)
Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from:
Pre-Tax Gains
(Losses) Recognized
During the Period in Income
(Millions of Dollars)Accumulated
Other
Comprehensive Loss		Regulatory
Assets and (Liabilities)
Year Ended Dec. 31, 2021
Derivatives designated as cash flow hedges
Interest rate$8 (a)$— $— 
Total$8 $— $— 
Other derivative instruments
Commodity trading$— $— $63 (b)
Electric commodity— (23)(c)— 
Natural gas commodity— 5 (d)(22)(d)
Total$— $(18)$41 
Year Ended Dec. 31, 2020
Derivatives designated as cash flow hedges
Interest rate$7 (a)$— $— 
Total$7 $— $— 
Other derivative instruments
Commodity trading$— $— $(1)(b)
Electric commodity— (3)(c)— 
Natural gas commodity— 10 (d)(13)(d)
Total$— $7 $(14)
Year Ended Dec. 31, 2019
Derivatives designated as cash flow hedges
Interest rate$4 (a)$— $— 
Total$4 $— $— 
Other derivative instruments
Commodity trading$— $— $2 (b)
Electric commodity— (5)(c)— 
Natural gas commodity— 2 (d)(7)(d)
Total$— $(3)$(5)
(a)Recorded to interest charges.
(b)Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.
(c)Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms and reclassified out of income as regulatory assets or liabilities, as appropriate.
(d)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.
Xcel Energy had 0no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2019, 20182021, 2020 and 2017.2019.

68
Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal purchase-normalpurchase and normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies, or for cross default contractual provisions if there was a failure under other financing arrangements related to payment terms or other covenants.agencies. As of Dec. 31, 20192021 and 2018, the amounts for2020, there were $3 million and $4 million of derivative instruments in a liability position with such underlying contract provisions, respectively. Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under the other financing arrangements related to payment terms or other covenants.
As of Dec. 31, 2021 and 2020, there were $7approximately $64 million and NaN,$60 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 provisionsProvisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. Xcel Energy had 0no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 20192021 and 2018.2020.

Recurring Fair Value Measurements — Xcel Energy’s derivativeDerivative assets and liabilities measured at fair value on a recurring basis:basis were as follows:
Dec. 31, 2021Dec. 31, 2020
Fair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
Total
(Millions of Dollars)Level 1Level 2Level 3Level 1Level 2Level 3
Current derivative assets
Other derivative instruments:
Commodity trading$22 $137 $21 $180 $(134)$46 $2 $67 $1 $70 $(52)$18 
Electric commodity— — 57 57 (1)56 — — 20 20 (1)19 
Natural gas commodity— 18 — 18 — 18 — 9 — 9 — 9 
Total current derivative assets$22 $155 $78 $255 $(135)120 $2 $76 $21 $99 $(53)46 
PPAs (b)
3 3 
Current derivative instruments$123 $49 
Noncurrent derivative assets
Other derivative instruments:
Commodity trading$16 $63 $89 $168 $(107)$61 $8 $66 $8 $82 $(62)$20 
Total noncurrent derivative assets$16 $63 $89 $168 $(107)61 $8 $66 $8 $82 $(62)20 
PPAs (b)
6 10 
Noncurrent derivative instruments$67 $30 
Dec. 31, 2021Dec. 31, 2020
Fair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
Total
(Millions of Dollars)Level 1Level 2Level 3Level 1Level 2Level 3
Current derivative liabilities
Other derivative instruments:
Commodity trading$19 $148 $20 $187 $(143)$44 $4 $64 $17 $85 $(58)$27 
Electric commodity— — 1 1 (1)— — — 1 1 (1)— 
Natural gas commodity— 8 — 8 — 8 — 9 — 9 — 9 
Total current derivative liabilities$19 $156 $21 $196 $(144)52 $4 $73 $18 $95 $(59)36 
PPAs (b)
17 17 
Current derivative instruments$69 $53 
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading$18 $48 $127 $193 $(128)$65 $3 $58 $60 $121 $(47)$74 
Total noncurrent derivative liabilities$18 $48 $127 $193 $(128)65 $3 $58 $60 $121 $(47)74 
PPAs (b)
40 57 
Noncurrent derivative instruments$105 $131 
(a)Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement and all derivative instruments and related collateral amounts were subject to master netting agreements as of Dec. 31, 2021 and 2020. At Dec. 31, 2021, derivative assets and liabilities include 0 obligations to return cash collateral. At Dec. 31, 2020, derivative assets and liabilities include $15 million of obligations to return cash collateral. At Dec. 31, 2021 and 2020, derivative assets and liabilities include rights to reclaim cash collateral of $30 million and $6 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
(b)During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, contracts are no longer adjusted to fair value and the previous carrying value of these contracts is being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
  Dec. 31, 2019 Dec. 31, 2018
  Fair Value Fair Value Total 

Netting (a)
   Fair Value Fair Value Total 

Netting (a)
  
(Millions of Dollars) Level 1 Level 2 Level 3   Total Level 1 Level 2 Level 3   Total
Current derivative assets                        
Commodity trading $3
 $51
 $24
 $78
 $(52) $26
 $4
 $92
 $2
 $98
 $(44) $54
Electric commodity —
 —
 21
 21
 (1) 20
 —
 —
 25
 25
 —
 25
Natural gas commodity —
 6
 —
 6
 —
 6
 —
 4
 —
 4
 —
 4
Total current derivative assets $3
 $57
 $45
 $105
 $(53) 52
 $4
 $96
 $27
 $127
 $(44) 83
PPAs (b)
           3
           4
Current derivative instruments           $55
           $87
Noncurrent derivative assets                        
Other derivative instruments:                        
Commodity trading $9
 $38
 $7
 $54
 $(45) $9
 $—
 $27
 $5
 $32
 $(14) $18
Total noncurrent derivative assets $9
 $38
 $7
 $54
 $(45) 9
 $—
 $27
 $5
 $32
 $(14) 18
PPAs (b)
           13
           16
Noncurrent derivative instruments           $22
           $34
  Dec. 31, 2019 Dec. 31, 2018
  Fair Value Fair Value Total 
Netting (a)
   Fair Value Fair Value Total 
Netting (a)
  
(Millions of Dollars) Level 1 Level 2 Level 3   Total Level 1 Level 2 Level 3   Total
Current derivative liabilities                        
Derivatives designated as cash flow hedges:                        
Interest rate $—
 $—
 $—
 $—
 $—
 $—
 $—
 $7
 $—
 $7
 $—
 $7
Other derivative instruments:                        
Commodity trading 4
 59
 15
 78
 (63) 15
 4
 88
 2
 94
 (60) 34
Electric commodity —
 —
 1
 1
 (1) —
 —
 —
 —
 —
 —
 —
Natural gas commodity —
 5
 —
 5
 —
 5
 —
 —
 —
 —
 —
 —
Total current derivative liabilities $4
 $64
 $16
 $84
 $(64) 20
 $4
 $95
 $2
 $101
 $(60) 41
PPAs (b)
           18
           20
Current derivative instruments           $38
           $61
Noncurrent derivative liabilities                        
Other derivative instruments:                        
Commodity trading $2
 $79
 $32
 $113
 $(13) $100
 $—
 $18
 $1
 $19
 $17
 $36
Total noncurrent derivative liabilities $2
 $79
 $32
 $113
 $(13) 100
 $—
 $18
 $1
 $19
 $17
 36
PPAs (b)
           75
           93
Noncurrent derivative instruments           $175
           $129
69
(a)
Xcel Energy nets derivative instruments and related collateral in 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 as of Dec. 31, 2019 and 2018. At both Dec. 31, 2019 and 2018, derivative assets and liabilities included $32 million of obligations to return cash collateral. At Dec. 31, 2019 and 2018, derivative assets and liabilities included rights to reclaim cash collateral of $11 million and $15 million, respectively. Counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
(b)
During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

Changes in Level 3 commodity derivatives:
Year Ended Dec. 31
(Millions of Dollars)202120202019
Balance at Jan. 1$(49)$4 $29 
Purchases65 51 44 
Settlements(158)(73)(64)
Net transactions recorded during the period:
Gains (losses) recognized in earnings (a)
49 (39)(8)
Net gains recognized as regulatory assets and liabilities112 8 3 
Balance at Dec. 31$19 $(49)$4 
  Year Ended Dec. 31
(Millions of Dollars) 2019 2018 2017
Balance at Jan. 1 $29
 $35
 $17
Purchases 44
 59
 82
Settlements (64) (59) (97)
Net transactions recorded during the period:      
(Losses) gains recognized in earnings (a)
 (8) (1) 5
Net gains (losses) recognized as regulatory assets and liabilities 3
 (5) 28
Balance at Dec. 31 $4
 $29
 $35
(a)(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.
Amounts relate to commodity derivatives held at the end of the period.
Xcel Energy recognizes transfers between levels as of the beginning of each period. There were 0no transfers of amounts between levels for derivative instruments for 2017 -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:
  2019 2018
(Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value
Long-term debt, including current portion $18,109
 $20,227
 $16,209
 $16,755

20212020
(Millions of Dollars)Carrying AmountFair ValueCarrying AmountFair Value
Long-term debt, including current portion$22,380 $25,232 $20,066 $24,412 
Fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of Dec. 31, 20192021 and 2018,2020, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.
11. Benefit Plans and Other Postretirement Benefits
Pension and Postretirement Health Care Benefits
Xcel Energy has several noncontributory, qualified, defined benefit pension plans that cover almost all employees. Generally, benefits areAll newly hired or rehired employees participate under the Cash Balance formula, which is based on pay credits using a combinationpercentage of years of serviceannual eligible pay and annual interest credits. The average pay.annual interest crediting rates for these plans was 2.03, 1.89 and 2.82% 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 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 that were participantswho 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, 20192021 and 20182020 were $39$43 million and $33$43 million, respectively. Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $4 million in 20192021 and $6 million in 2018.2020.
Xcel Energy bases theEnergy’s investment-return assumption onconsiders the expected long-term performance for each of the asset classes in its pension and postretirement health care portfolios. For pension assets,portfolio. Xcel Energy considers the historical returns achieved by its asset portfolioportfolios over the past 20 years or longer period,long time periods, as well as long-term projected return levels.
Pension cost determination assumes a forecasted mix of investment types over the long-term.
•Investment returns in 2021 were above the assumed level of 6.49%.
•Investment returns in 2020 were above the assumed level of 6.87%.
•Investment returns in 2019 were above the assumed level of 6.87%;.
Investment returns in 2018 were below the assumed level of 6.87%;
Investment returns in 2017 were above the assumed level of 6.87%; and
•In 2020,2022, expected investment-return assumption is 6.87%6.49%.
Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class.
There were no significant concentrations of risk in any industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by the assets in any year.
State agencies also have issued guidelines to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico amounts collected in rates. PSCo is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. These assets are invested in a manner consistent with the investment strategy for the pension plan.
Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations consider many factors and generally result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.

70
Plan Assets
For each of the fair value hierarchy levels, Xcel Energy’s pension plan assets measured at fair value:
Dec. 31, 2021 (a)
Dec. 31, 2020 (a)
(Millions of Dollars)Level 1Level 2Level 3Measured at NAVTotalLevel 1Level 2Level 3Measured at NAVTotal
Cash equivalents$133 $— $— $— $133 $209 $— $— $— $209 
Commingled funds1,324 — — 1,143 2,467 1,462 — — 1,115 2,577 
Debt securities— 959 5 — 964 — 714 4 — 718 
Equity securities67 — — — 67 77 — — — 77 
Other— 7 — 32 39 13 5 — — 18 
Total$1,524 $966 $5 $1,175 $3,670 $1,761 $719 $4 $1,115 $3,599 
  
Dec. 31, 2019 (a)
 
Dec. 31, 2018 (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 $145
 $—
 $—
 $—
 $145
 $137
 $—
 $—
 $—
 $137
Commingled funds 1,408
 —
 —
 1,031
 2,439
 914
 —
 —
 987
 1,901
Debt securities —
 645
 4
 —
 649
 —
 621
 —
 —
 621
Equity securities 86
 —
 —
 —
 86
 106
 —
 —
 —
 106
Other (120) 5
 —
 (20) (135) 2
 5
 —
 (30) (23)
Total $1,519
 $650
 $4
 $1,011
 $3,184
 $1,159
 $626
 $—
 $957
 $2,742

(a)
(a)See Note 10 for further information regarding fair value measurement inputs and methods.
See Note 10 for further information regarding fair value measurement inputs and methods.

For each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that were measured at fair value:
Dec. 31, 2021 (a)
Dec. 31, 2020 (a)
(Millions of Dollars)Level 1Level 2Level 3Measured at NAVTotalLevel 1Level 2Level 3Measured at NAVTotal
Cash equivalents$28 $— $— $— $28 $27 $— $— $— $27 
Insurance contracts— 52 — — 52 — 50 — — 50 
Commingled funds64 — — 77 141 72 — — 69 141 
Debt securities— 218 1 — 219 — 232 — — 232 
Other— 2 — — 2 — 2 — — 2 
Total$92 $272 $1 $77 $442 $99 $284 $— $69 $452 
  
Dec. 31, 2019 (a)
 
Dec. 31, 2018 (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 $23
 $—
 $—
 $—
 $23
 $19
 $—
 $—
 $—
 $19
Insurance contracts —
 51
 —
 —
 51
 —
 45
 —
 —
 45
Commingled funds 69
 —
 —
 76
 145
 133
 —
 —
 40
 173
Debt securities —
 228
 1
 —
 229
 —
 179
 —
 —
 179
Other —
 1
 —
 —
 1
 —
 1
 —
 —
 1
Total $92
 $280
 $1
 $76
 $449
 $152
 $225
 $—
 $40
 $417
(a)See Note 10 for further information on fair value measurement inputs and methods.
(a)
See Note 10 for further information on fair value measurement inputs and methods.
ImmaterialNaN assets were transferred in or out of Level 3 for 2019. No assets were transferred in2021 or out of Level 3 for 2018.2020.
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 Xcel Energy are as follows:
Pension BenefitsPostretirement Benefits
(Millions of Dollars)2021202020212020
Change in Benefit Obligation:
Obligation at Jan. 1$3,964 $3,701 $574 $547 
Service cost104 95 2 1 
Interest cost104 125 15 18 
Plan amendments5 — — — 
Actuarial (gain) loss(94)328 (41)50 
Plan participants’ contributions— — 8 8 
Medicare subsidy reimbursements— — 2 1 
Benefit payments (a)
(365)(285)(49)(51)
Obligation at Dec. 31$3,718 $3,964 $511 $574 
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1$3,599 $3,184 $452 $449 
Actual return on plan assets305 550 16 35 
Employer contributions131 150 15 11 
Plan participants’ contributions— — 8 8 
Benefit payments(365)(285)(49)(51)
Fair value of plan assets at Dec. 31$3,670 $3,599 $442 $452 
Funded status of plans at Dec. 31$(48)$(365)$(69)$(122)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Noncurrent assets$19 $— $33 $6 
Current liabilities— — (4)(7)
Noncurrent liabilities(67)(365)(98)(121)
Net amounts recognized$(48)$(365)$(69)$(122)
(a)Includes approximately $197 million in 2021 and $0 million in 2020 of lump-sum benefit payments used in the determination of a settlement charge.
71
  Pension Benefits Postretirement Benefits
(Millions of Dollars) 2019 2018 2019 2018
Change in Benefit Obligation:        
Obligation at Jan. 1 $3,477
 $3,828
 $542
 $621
Service cost 86
 94
 2
 2
Interest cost 145
 133
 22
 22
Plan amendments 1
 —
 —
 —
Actuarial loss (gain) 273
 (224) 19
 (62)
Plan participants’ contributions —
 —
 8
 8
Medicare subsidy reimbursements —
 —
 1
 1
Benefit payments (a)
 (281) (354) (47) (50)
Obligation at Dec. 31 $3,701
 $3,477
 $547
 $542
Change in Fair Value of Plan Assets:        
Fair value of plan assets at Jan. 1 $2,742
 $3,088
 $417
 $461
Actual return on plan assets 568
 (142) 56
 (13)
Employer contributions 155
 150
 15
 11
Plan participants’ contributions —
 —
 8
 8
Benefit payments (281) (354) (47) (50)
Fair value of plan assets at Dec. 31 $3,184
 $2,742
 $449
 $417
Funded status of plans at Dec. 31 $(517) $(735) $(98) $(125)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:        
Noncurrent assets $—
 $—
 $21
 $—
Current liabilities —
 —
 (6) (7)
Noncurrent liabilities (517) (735) (113) (118)
Net amounts recognized $(517) $(735) $(98) $(125)
(a)
Includes approximately $20 million in 2019 and $198 million in 2018 of lump-sum benefit payments used in the determination of a settlement charge.
Pension BenefitsPostretirement Benefits
 Pension Benefits Postretirement Benefits
(Millions of Dollars) 2019 2018 2019 2018
Significant Assumptions Used to Measure Benefit Obligations:        Significant Assumptions Used to Measure Benefit Obligations:2021202020212020
Discount rate for year-end valuation 3.49% 4.31% 3.47% 4.32%Discount rate for year-end valuation3.08 %2.71 %3.09 %2.65 %
Expected average long-term increase in compensation level 3.75
 3.75
 N/A
 N/A
Expected average long-term increase in compensation level3.75 3.75 N/AN/A
Mortality table PRI-2012
 RP-2014
 PRI-2012
 RP-2014
Mortality tablePRI-2012PRI-2012PRI-2012PRI-2012
Health care costs trend rate — initial: Pre-65
 N/A
 N/A
 6.00% 6.50%Health care costs trend rate — initial: Pre-65N/AN/A5.30 %5.50 %
Health care costs trend rate — initial: Post-65
 N/A
 N/A
 5.10% 5.30%Health care costs trend rate — initial: Post-65N/AN/A4.90 %5.00 %
Ultimate trend assumption — initial: Pre-65
 N/A
 N/A
 4.50% 4.50%Ultimate trend assumption — initial: Pre-65N/AN/A4.50 %4.50 %
Ultimate trend assumption — initial: Post-65
 N/A
 N/A
 4.50% 4.50%Ultimate trend assumption — initial: Post-65N/AN/A4.50 %4.50 %
Years until ultimate trend is reached N/A
 N/A
 3
 4
Years until ultimate trend is reachedN/AN/A45
Accumulated benefit obligation for the pension plan was $3,465$3,469 million and $3,275$3,693 million as of Dec. 31, 20192021 and 2018,2020, respectively.

Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other income (expense) in the consolidated statements of income.
Components of net periodic benefit cost (credit) and amounts recognized in other comprehensive income and regulatory assets and liabilities:
Pension BenefitsPostretirement Benefits
(Millions of Dollars)202120202019202120202019
Service cost$104 $95 $86 $2 $1 $2 
Interest cost104 125 145 15 18 22 
Expected return on plan assets(206)(208)(203)(18)(19)(21)
Amortization of prior service credit(1)(4)(5)(8)(8)(10)
Amortization of net loss107 100 87 5 4 5 
Settlement charge (a)
59 — 6 — — — 
Net periodic pension cost (credit)167 108 116 (4)(4)(2)
Effects of regulation(46)9 (1)2 3 1 
Net benefit cost (credit) recognized for financial reporting$121 $117 $115 $(2)$(1)$(1)
Significant Assumptions Used to Measure Costs:
Discount rate2.71 %3.49 %4.31 %2.65 %3.47 %4.32 %
Expected average long-term increase in compensation level3.75 3.75 3.75 — — — 
Expected average long-term rate of return on assets6.49 6.87 6.87 4.10 4.50 4.50 
  Pension Benefits Postretirement Benefits
(Millions of Dollars) 2019 2018 2017 2019 2018 2017
Service cost $86
 $94
 $94
 $2
 $2
 $2
Interest cost 145
 133
 147
 22
 22
 24
Expected return on plan assets (203) (209) (209) (21) (26) (25)
Amortization of prior service credit (5) (5) (2) (10) (11) (11)
Amortization of net loss 87
 111
 107
 5
 8
 7
Settlement charge (a)
 6
 91
 81
 —
 —
 —
Net periodic pension cost (credit) 116
 215
 218
 (2) (5) (3)
Costs not recognized due to effects of regulation (1) (75) (79) 1
 2
 —
Net benefit cost (credit) recognized for financial reporting $115
 $140
 $139
 $(1) $(3) $(3)
Significant Assumptions Used to Measure Costs:            
Discount rate 4.31% 3.63% 4.13% 4.32% 3.62% 4.13%
Expected average long-term increase in compensation level 3.75
 3.75
 3.75
 —
 —
 —
Expected average long-term rate of return on assets 6.87
 6.87
 6.87
 4.50
 5.30
 5.80
(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 2021 and 2019, as a result of lump-sum distributions during each plan year, Xcel Energy recorded a total pension settlement charge of $59 million and $6 million, respectively, the majority of which was not recognized due to the effects of regulation. A total of $7 million and $1 million was recorded in the consolidated statements of income in 2021 and 2019, respectively. There were 0 settlement charges recorded for the qualified pension plans in 2020.
Pension BenefitsPostretirement Benefits
(Millions of Dollars)2021202020212020
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss$978 $1,333 $81 $126 
Prior service credit(9)(11)(7)(15)
Total$969 $1,322 $74 $111 
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$74 $82 $— $— 
Noncurrent regulatory assets846 1,181 90 125 
Current regulatory liabilities— — (1)(1)
Noncurrent regulatory liabilities— — (19)(18)
Deferred income taxes13 15 1 1 
Net-of-tax accumulated other comprehensive income36 44 3 4 
Total$969 $1,322 $74 $111 
(a)
A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2019 and 2018, as a result of lump-sum distributions during the 2019 and 2018 plan years, Xcel Energy recorded a total pension settlement charge of $6 million in 2019 and $91 million in 2018, the majority of which was not recognized due to the effects of regulation. A total of $1 million and $11 million was recorded in the consolidated statements of income in 2019 and 2018, respectively.
  Pension Benefits Postretirement Benefits
(Millions of Dollars) 2019 2018 2019 2018
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:        
Net loss $1,447
 $1,633
 $95
 $116
Prior service credit (15) (20) (23) (33)
Total $1,432
 $1,613
 $72
 $83
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 $78
 $94
 $—
 $—
Noncurrent regulatory assets 1,285
 1,446
 80
 89
Current regulatory liabilities —
 —
 (1) (1)
Noncurrent regulatory liabilities —
 —
 (12) (10)
Deferred income taxes 18
 19
 1
 1
Net-of-tax accumulated other comprehensive income 51
 54
 4
 4
Total $1,432
 $1,613
 $72
 $83

Measurement dateDec. 31, 20192021Dec. 31, 20182020Dec. 31, 20192021Dec. 31, 20182020


72
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 20172019 —- 20202022 to meet minimum funding requirements.
Voluntary and required pension funding contributions:
•$50 million in January 2022.
•$131 million in 2021.
•$150 million in January 2020;2020.
•$154 million in 2019;
$150 million in 2018; and
$162 million in 2017.

2019.
The postretirement health care plans have no funding requirements other than fulfilling benefit payment obligations when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities.
Voluntary postretirement funding contributions:
$10•Expects to contribute approximately $9 million during 2020;2022.
•$15 million during 2019;2021.
•$11 million during 2018; and2020.
•$2015 million during 2017.2019.

Targeted asset allocations:
Pension BenefitsPostretirement Benefits
2021202020212020
Domestic and international equity securities33 %35 %15 %15 %
Long-duration fixed income securities37 35 — — 
Short-to-intermediate fixed income securities11 13 71 72 
Alternative investments17 15 8 9 
Cash2 2 6 4 
Total100 %100 %100 %100 %
  Pension Benefits Postretirement Benefits
  2019 2018 2019 2018
Domestic and international equity securities 37% 36% 15% 18%
Long-duration fixed income securities 30
 30
 —
 —
Short-to-intermediate fixed income securities 14
 17
 72
 70
Alternative investments 17
 15
 9
 8
Cash 2
 2
 4
 4
Total 100% 100% 100% 100%

The asset allocations above reflect target allocations approved in the calendar year to take effect in the subsequent year.
Plan Amendments —The Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) were amended in 2017 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.
In 2018, the PSCo postretirement plan was amended to add the 5% cash balance formula.
In 2019, the Pension Protection Act measurement concept was extended beyond 2019 for NSP bargaining terminations and retirements to Dec. 31, 2022.
There were no0 significant plan amendments made in 20192020 which affected the postretirement benefit obligation.
In 2021, Xcel Energy amended the Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans.
Projected Benefit Payments
Xcel Energy’s projected benefit payments:
(Millions of Dollars) Projected
Pension Benefit
Payments		 Gross Projected
Postretirement
Health Care
Benefit Payments		 Expected
Medicare Part D
Subsidies		 Net Projected
Postretirement
Health Care
Benefit Payments		(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
2020 $278
 $44
 $2
 $42
2021 263
 43
 2
 41
2022 262
 42
 2
 40
2022$323 $42 $2 $40 
2023 260
 41
 2
 39
2023257 41 2 39 
2024 255
 40
 2
 38
2024253 40 2 38 
2025-2029 1,205
 181
 13
 168
20252025251 38 2 36 
20262026245 37 2 35 
2027-20312027-20311,156 165 13 152 

Defined Contribution Plans
Xcel Energy maintains 401(k) and other defined contribution plans that cover most employees. Total expense to these plans was approximately $43 million in 2021, $42 million in 2020 and $39 million in 2019, $38 million in 2018 and $37 million in 2017.2019.
Multiemployer Plans
NSP-Minnesota and NSP-Wisconsin each contribute to several union multiemployer pension and other postretirement benefit plans, none of which are individually significant. These plans provide pension and postretirement health care benefits to certain union employees who may perform services for multiple employers and do not participate in the NSP-Minnesota and NSP-Wisconsin sponsored pension and postretirement health care plans.
Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota and NSP-Wisconsin sponsored plans, in that if another participating employer ceases to contribute to a multiemployer plan, additional unfunded obligations may need to be funded over time by remaining participating employers.

12. Commitments and Contingencies
Legal
Xcel Energy is involved in various litigation matters that are being defended and handled in the ordinary course of business. AssessingThe 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 regardingabout future events. Management maintains accruals for losses that are probable of being incurred and subject to reasonable estimation.
Management may beis 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, arising from such current proceedings would have a material effect on Xcel Energy’s consolidated financial statements. Unless otherwise required by GAAP, legalLegal 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.
NaN cases remaincase remains active which include an MDLincludes a multi-district litigation matter consisting of a Colorado purported class (Breckenridge) and 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.
73
Arandell Corp.Table of Contents — In February 2019, the case was remanded back to the U.S. District Court in Wisconsin.
Rate Matters and Other
Xcel Energy has concludedEnergy’s operating subsidiaries are involved in various regulatory proceedings arising in the ordinary course of business. Until resolution, typically in the form of a rate order, uncertainties may exist regarding the ultimate rate treatment for certain activities and transactions. Amounts have been recognized for probable and reasonably estimable losses that may result. Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a loss is remote for both remaining lawsuits.material effect on the consolidated financial statements.
Line Extension DisputesMinnesota Winter Storm Uri Costs — In December 2015,its Minnesota jurisdiction, NSP-Minnesota is participating in a contested case regarding the DRCprudency of incremental natural gas costs incurred during Winter Storm Uri. Other parties to the case have recommended significant cost disallowances, and while ultimate resolution of the matter is uncertain, it is reasonably possible that the MPUC could disallow certain deferred costs, resulting in earnings losses. The OAG recommended the MPUC deny recovery of up to $179 million, the largest recommendation among the intervenor positions.
NSP-Minnesota strongly disagrees with the recommendations of the DOC, OAG and CUB, and believes that it acted prudently and according to MPUC approved procedures for the best interest of its customers and stakeholders.
NSP-Minnesota filed a lawsuit seeking monetary damagesrebuttal testimony in January 2022 detailing its position that the disallowances recommended by other parties lack any merit in the Denver District Court, stating PSCo failed to award proper allowancesprudency review given the pertinent facts regarding NSP-Minnesota’s actions before, during and refunds for line extensions to new developments pursuant toafter the termsstorm event. An MPUC decision is expected in the summer of electric and gas service agreements. The dispute involves claims by over 50 developers. In February 2018, the Colorado Supreme Court denied DRC’s petition to appeal the Denver District Court’s dismissal of the lawsuit, effectively terminating this litigation. However, in January 2018, DRC filed a new lawsuit in Boulder County District Court, asserting a single claim that PSCo was required to file its line extension agreements with the CPUC but failed to do so.
This claim is similar to the arguments previously raised by the DRC. PSCo filed a motion to dismiss this claim, which was granted in May 2018. The DRC subsequently filed an appeal to the Colorado Court of Appeals. In November 2019, the Colorado Court of Appeals issued an opinion affirming dismissal of the lawsuit based upon lack of subject matter jurisdiction. The Colorado Court of Appeals did not address the second issue based upon issue preclusion. Finally, the Colorado Court of Appeals remanded the case to the Boulder District Court to consider PSCo’s request for an award of costs, which it concluded does not include attorneys’ fees. The DRC did not file a petition for a Writ of Certiorari to the Colorado Supreme Court by the Dec. 26, 2019 deadline, effectively terminating this litigation.

Rate Matters
MEC Acquisition — In November 2018, NSP-Minnesota reached an agreement with Southern Power Company (a subsidiary of Southern Company) to purchase MEC, a 760 MW natural gas combined cycle facility, with capacity and energy historically sold to NSP-Minnesota under PPAs expiring in 2026 and 2039, for approximately $650 million.
In September 2019, the MPUC denied NSP-Minnesota's request to purchase MEC as a rate base asset. In January 2020, the MPUC approved Xcel Energy’s plan to acquire MEC as a non-regulated investment and step into the terms of the existing PPAs with NSP-Minnesota. A newly formed non-regulated subsidiary of Xcel Energy completed the transaction to purchase MEC on Jan. 17, 2020.2022.
Sherco — In NSP-Minnesota’s 2013 fuel reconciliation filing, the MPUC made recovery of replacement power costs associated with the 2011 incident at its Sherco Unit 3 plant provisional2018, NSP-Minnesota and subject to further review following conclusion of litigation commenced by NSP-Minnesota, SMMPASouthern Minnesota Municipal Power Agency (Co-owner of Sherco Unit 3) and insurance companies against GE.
In 2018, NSP-Minnesota and SMMPA reached a settlement with GE.GE related to a 2011 incident, which damaged the turbine at Sherco Unit 3 and resulted in an extended outage for repair. NSP-Minnesota notified the MPUC of its proposal to refund the GE settlement proceeds back to customers through the FCA. The insurance providers continued their litigation against GE and the case went to trial.
In 2018, GE prevailed in the lawsuit with the insurance companies, however, the jury found comparable fault, finding that GE was 52% and NSP-Minnesota was 48% at fault. At that point in the litigation, NSP-Minnesota was no longer involved in the case and was not present to make arguments about its role in the event. The specific issue leading to the fault apportionment was also not before the jury and not relevant to the outcome of the trial.
In January 2019, the DOC recommended that NSP-Minnesota refund $20 million of previously recovered purchased power costs to its customers, based on the jury’s apportionment of fault. The OAG recommended the MPUC withhold any decision until the underlying litigation by the insurance providers (currently under appeal) is concluded. The DOC subsequently filed comments agreeing with the OAG’s recommendation to withhold a decision pending the outcome of any appeals. NSP-Minnesota filed reply comments arguing that the DOC recommendations are without merit and that it acted prudently in operating the plant and its settlement with GE was reasonable.
In March 2019, the MPUC approved NSP-Minnesota’s proposal tosettlement refund proposal. Additionally, the GE settlement proceeds back to customers through the FCA. It alsoMPUC decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of thean appeal pending litigation between GE and NSP-Minnesota’s insurers. In February 2020, the Minnesota Court of Appeals affirmed the district court’s judgment in favor of GE. In March 2020, NSP-Minnesota’s insurers filed a petition seeking additional review by the Minnesota Supreme Court.
In April 2020, the Minnesota Supreme Court denied the insurers’ petition for further review, ending the litigation.
In January 2021, the OAG and DOC recommended that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the FCA. NSP-Minnesota subsequently filed its response, asserting that it acted prudently in connection with the Sherco Unit 3 outage, the MPUC has previously disallowed $22 million of related costs and no additional refund or disallowance is appropriate. A final decision by the MPUC is pending. A loss related to this matter is deemed remote.
Westmoreland Arbitration —In November 2014, insurers of the Westmoreland Coal Company filed an arbitration demand against NSP-Minnesota, Southern Minnesota Municipal Power Agency and Western Fuels Association, seeking recovery of alleged $36 million of business losses due to a turbine failure at Sherco Unit 3. The Westmoreland insurers claim NSP-Minnesota’s invocation of the force majeure clause to stop the supply of coal was improper because the incident was allegedly caused by NSP-Minnesota’s failure to conform to industry maintenance standards.
NSP-Minnesota denies the claims asserted by the Westmoreland insurers and believes it properly stopped the supply of coal based upon the force majeure provision. A final hearing has been scheduled for October 2022. The parties are also required to participate in mediation, which has been scheduled for the first quarter of 2022. At this stage of the proceeding, a reasonable estimate of damages or range of damages cannot be determined.
MISO ROE Complaints — In November 2013 and February 2015, customerscustomer groups filed two ROE complaints against MISO TOs, includingwhich includes NSP-Minnesota and NSP-Wisconsin.
The first complaint argued forrequested a reduction in the base ROE in MISO transmission formula rates from 12.38% to 9.15%, for the time period of Nov. 12, 2013 to Feb. 11, 2015, and removal of ROE adders (including those for RTO membership). The second complaint sought to reducerequested, for a subsequent time period, a base ROE reduction from 12.38% to 8.67%.
In September 2016, the FERC issued an order (Opinion No. 551) granting a 10.32% base ROE (10.82% with the RTO adder) effective for the first complaint period of Nov. 12, 2013 to Feb. 11, 2015 and subsequent to the date of the order. The D.C.D.C Circuit subsequently vacated and remanded FERC Opinion No. 531, which had established the ROE methodology on which the September 2016 FERC order was based.
551.
On March 21, 2019, FERC announced a NOI seeking public comments on whether, and if so how, to revise ROE policies in light of the D.C. Circuit Court decision. FERC also initiated a NOI on whether to revise its policies on incentives for electric transmission investments, including the RTO membership incentive. In November 2019, the FERC issued an order adopting a new ROE methodology and settling(Opinion No. 569), which set the MISO base ROE at 9.88% (10.38% with the RTO adder), effective Sept. 28, 2016 and for the Nov. 12, 2013 to Feb. 11, 2015 refundfirst complaint period. The FERC also dismissed the second complaint.
In December 2019, MISO TOs filed a request for rehearing.rehearing regarding the new ROE methodology announced in Opinion No. 569. Customers also filed requests for rehearing claiming, among other points, that the FERC erred by dismissing the second complaint without refunds. Xcel Energy
In May 2020, the FERC issued an order (Opinion No. 569-A) which granted rehearing in part to Opinion 569 and further refined the FERC’s ROE methodology, most significantly to incorporate the risk premium model (in addition to the discounted cash flow and capital asset pricing models), resulting in a new base ROE of 10.02%, effective Sept. 28, 2016 and for the first complaint period. The FERC also affirmed its decision in Opinion No. 569 to dismiss the second complaint.
In November 2020, the FERC issued an order (Opinion No. 569-B) in response to rehearing requests. The FERC corrected certain inputs to its ROE calculation model, did not change the ROE effective Sept. 28, 2016, and for the first MISO complaint period and upheld its decision to deny refunds for the second complaint period. NSP-Minnesota has recognized a liability for its best estimate of final refunds to customers. It is uncertain when the FERC will act on the requests for rehearing or any other pending matters related to the 2019 NOIs.
Texas Fuel Reconciliation —In December 2018,SPS filed an application with the PUCT for reconciliation of fuel costsEach 10 basis point reduction in ROE for the first complaint period, Jan. 1, 2016, through June 30, 2018,second complaint period and subsequent period relative to determine whether all fuel costs incurredamounts accrued would reduce Xcel Energy’s net income by $1 million, $1 million and $2 million, respectively.
The MISO TOs and various parties have filed petitions for review of Opinion Nos. 569, 569-A and 569-B at the D.C. Circuit. Oral arguments were eligible for recovery. In December 2019, the PUCT issued an order disallowing recovery of costs for Texas customers related to two specific solar PPAs. These PPAs were previously approvedheld in late 2021 and a decision is expected by the NMPRC as reasonable, necessary and economic. SPS recorded a total disallowanceend of approximately $6 million in December 2019.the third quarter of 2022.
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SPP OATT Upgrade Costs — Under the SPP OATT, costsCosts of transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade.upgrade under the SPP OATT. SPP had not been charging its customers for these upgrades, even though the SPP OATT had allowed SPP to do so since 2008. In 2016, the FERC granted SPP’s request to recover these previously unbilled charges and SPP subsequently billed SPS approximately $13 million.
In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover previously unbilled charges was remanded to the FERC. In February 2019, the FERC reversed its 2016 decision and ordered SPP to refund charges retroactively collected from its transmission customers, including SPS, related to periods before September 2015.
In April 2019, several parties, includingMarch 2020, SPP and Oklahoma Gas & Electric separately filed requestspetitions for review of the FERC’s orders at the D.C. Circuit. In August 2021, the D.C Circuit issued a rehearing. Timing of a FERC response to rehearing requests is uncertain. Any refundsdecision denying these appeals and upholding the FERC’s orders. Refunds received by SPS are expected to be given back to SPS customers through future rates. The timing of these refunds is uncertain.
In October 2017, SPS filed a separate related complaint against SPP asserting SPP assessed upgrade charges to SPS in violation of the SPP OATT. In March 2018, the FERC issued an order denying the SPS complaint. SPS filed a request for rehearing in April 2018. The FERC grantedissued a tolling order granting a rehearing for further consideration in May 2018. Timing of FERC action on the SPS rehearing is uncertain. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the amountsamount through future SPS customer rates. In October 2020, SPS filed a petition for review of the FERC’s March 2018 order and May 2018 tolling order at the D.C. Circuit. FERC has asked that this appeal be stayed until early 2022, in order to provide FERC with time to issue an order on SPS’ April 2018 rehearing request. FERC’s order is expected in the first quarter of 2022. The D.C. Circuit appeal may resume after that FERC order is issued.
Wind Operating Commitments — PUCT and NMPRC orders related to the Hale and Sagamore wind projects included certain operating and savings minimums. In general, annual generation must exceed a net capacity factor of 48%. If annual generation is below the guaranteed level, SPS would be obligated to refund an amount equal to foregone PTCs and fuel savings. Additionally, retail customer savings must exceed project costs included in base rates over the first ten years of operations. SPS would be required to refund excess costs, if any, after ten years of operations. As of Dec. 31, 2021, the full-year net capacity factor was 48.4%, resulting in no refund liability for 2021.
Contract Termination —SPS and LP&L are parties to a 25-year, 170 MW partial requirements contract. In May 2021, SPS and LP&L finalized a settlement which would terminate the contract upon LP&L’s move from the SPP to the Electric Reliability Council of Texas (expected in 2023). The settlement agreement requires LP&L to pay SPS $78 million (lump sum or annual installments), to the benefit of SPS’ remaining customers. LP&L would remain obligated to pay for SPP transmission charges associated with LP&L’s load in SPP. The settlement agreement is subject to approval by the PUCT and FERC.
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 Xcel Energy, which are normally recovered through the regulated rate process.
Site Remediation —
Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. Xcel Energy Inc.’s subsidiaries may sometimes pay all or a portion of the cost to remediate sites where past activities of their predecessors or other parties have caused environmental contamination.
Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which one or more of Xcel Energy Inc.’s subsidiaries are alleged to have sent wastes to that site.

Historical MGP, Landfill and Disposal Sites
Ashland MGP Site — NSP-Wisconsin was named a responsible party for contamination at the Ashland/Northern States Power Lakefront Superfund Site (the Site) in Ashland, Wisconsin. Remediation was completed in 2019 and restoration activities are anticipated to be completed in 2020. Groundwater treatment activities will continue for many years.
The current cost estimate for remediation and restoration of the entire site is approximately $199 million. At Dec. 31, 2019 and 2018, NSP-Wisconsin had a total liability of $23 million and $27 million, respectively, for the entire site.
NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation and restoration costs as a regulatory asset. The PSCW has authorized NSP-Wisconsin rate recovery for all remediation and restoration costs incurred at the Site. In its final December 2019 order approving 2020 and 2021 natural gas base rates, the PSCW authorized continued amortization of costs and application of a 3% carrying charge to the regulatory asset.
MGP, Landfill or Disposal Sites — PSCo is cooperating with the City of Denver on an environmental investigation of the Rice Yards Site in Denver, Colorado, which had various historic industrial uses by multiple parties, including railroad, maintenance shop, scrap metal yard, and MGP operations.
The area is being redeveloped into residential and commercial mixed uses, and PSCo is in discussions with the current property owner regarding legal claims related to the Rice Yards Site.
In addition, Xcel Energy is currently investigating, remediating or remediating 12 otherperforming post-closure actions at 16 historical MGP, landfill or other disposal sites across its service territories.territories, excluding sites that are being addressed under current coal ash regulations (see below).
Xcel Energy has recognized its best estimate of costs/liabilities that will result from final resolution of these issues,issues; however, the outcome and timing isare unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.
Environmental Requirements — Water and Waste
Coal Ash Regulation — Xcel Energy’s operations are subject to federal and state lawsregulations 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, Xcel Energy has 98 regulated ash units in operation.
Xcel Energy is conducting groundwater sampling and where appropriate, initiating themonitoring and implementing assessment of corrective measures and evaluating whether corrective action is required at anycertain CCR landfills orand surface impoundments. In 2019, groundwater monitoring consistent with the CCR Rule was conducted. In NSP-Minnesota, 0no results above the groundwater protection standards in the rule were identified. In PSCo, statistically significant increaseincreases above background concentration wasconcentrations were detected at 4 locations. Subsequently, assessment monitoring samples were collected, andBased on further assessments, PSCo is evaluating the results to determine whetheroptions for corrective action is required. Until PSCo completes its assessment, itat 2 locations, 1 of which indicates potential offsite impacts to groundwater. The total cost is uncertain, what impact, if any, there willbut could be onup to $35 million. PSCo is continuing to assess the operations, financial condition or cash flows.and regulatory impacts.
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In August 2020, the EPA published its final rule to implement closure by April 2021 for all CCR impoundments affected by the August 2018 the D.C. Circuit ruled that the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the storage or disposal of coal ash. In November 2019, the EPA proposed rules in response to this decision.
If finalized in their current form, these rules would require NSP-Minnesotaruling. This final rule required Xcel Energy to expedite closure plans for 1 impoundment at an estimated cost of $2 million2 impoundments.
In October 2020, NSP-Minnesota completed construction and the construction ofplaced in service a new impoundment atto replace the cost of $9 million.
In 2019, Xcel Energy initiated the construction of this new impoundment, an ash pond, expected to be in service in 2020. Upon placingclay lined impoundment. With the new ash pond in service, NSP-Minnesota has initiated closure activities for the existing ash pond will be taken outat an estimated cost of $4 million. NSP-Minnesota has five years to complete closure activities.
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 and closure activities as prescribed by the CCR Rule and the facility’s National Pollutant Discharge Elimination System permit will be initiated. In addition, the rules proposed byuntil June 18, 2021. PSCo expects to negotiate a compliance order with the EPA may require PSCo to expediteaddressing the closure deadline as well as other potential issues. PSCo will also now proceed with closure of 1 coal ash impoundment.the pond, at an estimated cost of $3 million.
Closure costs for existing impoundments are included in the calculation of the ARO liability. See Note 12 for further information.ARO.
Federal CWA WOTUSWaters of the U.S. Rule — In 2015,Xcel Energy is monitoring ongoing changes to the EPA anddefinition of Waters of the U.S. Army Corps of Engineers published a final rule that significantly broadened the scope of waters under the CWA that are subject to federal jurisdiction, referred to as “WOTUS”. In 2019,CWA. Regardless of which definition is applicable in the EPA repealed the 2015 rule and published a draft replacement rule. Until a final rule is issued,states in which we operate, Xcel Energy cannot estimate potential impacts, but anticipatesdoes not anticipate that compliance costs will be recoverable through regulatory mechanisms.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 2017,October 2020, the EPA delayedpublished 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 date for flue gas desulfurization wastewater and bottom ash transport until November 2020. After 2020,is therefore uncertain but Xcel Energy estimatesdoes not anticipate that ELG compliance will cost approximately $12 million to complete. The EPA, however, is conducting a rulemaking process to revise certain effluent limitations and pretreatment standards, which may impact compliance costs. Xcel Energy anticipates these costs will be fully recoverable through regulatory mechanisms.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. Xcel Energy estimates the likely future cost for complying with impingement and entrainment requirements is approximately $40$39 million, to be incurred between 20202022 and 2028. Xcel Energy believes 6 NSP-Minnesota plants and 2 NSP-Wisconsin plants could be required by state regulators to make improvements to reduce impingement and entrainment. The exact total cost of the impingement and entrainment improvements is uncertain, but could be up to approximately $198$192 million. Xcel Energy anticipates these costs will be fully recoverable through regulatory mechanisms.
Environmental Requirements — Air
Regional Haze Rules — The regional haze program requires SO2, nitrogen oxide and particulate matter emission controls at power plants to reduce visibility impairment in national parks and wilderness areas. The program includes BART and reasonable further progress. The requirements of the first regional haze plansfirst planning period requirements developed by Minnesota and Colorado have beenwere approved by the EPA in 2012 and implemented.implemented by 2014 and 2016, respectively. Texas’ first regional haze plan has undergone federal review as described below.review.
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 Xcel Energy facilities are expected to be minimal.
BART Determination for Texas: The EPA has issued a revised final rule adopting a BART alternative Texas only SO2 trading program that applies to all Harrington and Tolk units. Under the trading program, SPS expects the allowance allocations to be sufficient for SO2 emissions. The anticipated costs of compliance are not expected to have a material impact; and SPS believes that compliance costs would be recoverable through regulatory mechanisms.
Several parties have challenged whether the final rule issued by the EPA should be considered to have met the requirements imposed in a Consent Decree entered by the United States District Court for the District of ColumbiaD.C. Circuit that established deadlines for the EPA to take final action on state regional haze plan submissions. The court has required status reports from the parties while the EPA works on the reconsideration rulemaking.

In December 2017, the National Parks Conservation Association, Sierra Club, and Environmental Defense Fund appealed the EPA’s 2017 final BART rule to the Fifth Circuit and filed a petition for administrative reconsideration. In January 2018, the court granted SPS’ motion to intervene in the Fifth Circuit litigation in support of the EPA’s final rule. The court has held the litigation in abeyance while the EPA decided whether to reconsider the rule. In August 2018, the EPA started a reconsideration rulemaking, which was supplemented by an additional agency noticerulemaking. The EPA reaffirmed the rule in November 2019. ItAugust 2020 with minor changes.
The 2020 EPA Action has been challenged. All pending actions could be consolidated and may proceed in the Fifth Circuit or the D.C. Circuit, where a parallel challenge has been filed. The timing of final decisions is not known when the EPA will make a final decision on this proposal.unclear.
Reasonable Progress Rule: In 2016, the EPA adopted a final rule establishing a federal implementation plan for reasonable further progress under the regional haze program for the state of Texas. The rule imposes SO2 emission limitations that would require the installation of dry scrubbers on Tolk Units 1 and 2, with2; compliance would have been required by February 2021. Investment costs associated with dry scrubbers could be $600 million. SPS appealed the EPA’s decision and obtained a stay of the final rule.
In March 2017, the Fifth Circuit remanded the rule to the EPA for reconsideration, leaving the stay in effect. In a future rulemaking, the EPA will address whether SO2 emission reductions beyond those required in the BART alternative rule referenced above are needed at Tolk under the “reasonable progress” requirements. TheAs states are now proceeding with the second regional haze planning period, the EPA hasmay choose not announced a schedule for actingto act on the remanded rule.
Implementation of the NAAQS for SO2 — The EPA has designated all areas near SPS’ generating plants as attaining the SO2 NAAQS with an1 exception. The EPA issued final designations, which found the area near the SPS Harrington plant as “unclassifiable.” The area near the Harrington plant iswas monitored for the three years ending in 2019 and the monitoring showed the area to be monitoredexceeding the standard.
To address this issue, SPS negotiated an order with the TCEQ providing for three yearsthe end of coal combustion and a final designation is expected to be made by December 2020.
If the area nearconversion of the Harrington plant is designated nonattainment in 2020, the TCEQ will need to develop an implementation plan, designed to achieve the NAAQSa natural gas fueled facility by Jan. 1, 2025. The TCEQ could require additional SO2 controls at Harrington as part of such a plan. Xcel Energy cannot evaluate the impacts until the final designation is made and any required state plans are developed.
Xcel Energy believes that should SO2 control systems be required for a plant, compliance costs or the costs of alternative cost-effective generation will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial condition or cash flows.
AROs — AROs have been recorded for Xcel Energy’s assets. For nuclear assets, the ARO is associated with the decommissioning of NSP-Minnesota nuclear generating plants.
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Aggregate fair value of NSP-Minnesota’s legally restricted assets, for funding future nuclear decommissioning was $2.4$3.3 billion and $2.1$2.8 billion for 20192021 and 2018,2020, respectively.
Xcel Energy’s AROs were as follows:
(Millions 
of Dollars)		Jan. 1, 2021
Amounts Incurred (a)
Accretion
Cash Flow Revisions (b)
Dec. 31, 2021 (c)
Electric
Nuclear$1,957 $— $99 $— $2,056 
Wind360 101 17 — 478 
Steam, hydro and other production264 6 10 8 288 
Distribution46 — 1 — 47 
Natural gas
Transmission and distribution252 — 10 9 271 
Miscellaneous3 — — 5 8 
Common
Miscellaneous1 — — — 1 
Non-utility
Miscellaneous1 — 1 — 2 
Total liability$2,884 $107 $138 $22 $3,151 
(a)Amounts incurred related to the wind farms placed in service in 2021 for NSP-Minnesota (Blazing Star 2, Mower and Freeborn) and removal of a utility scale battery asset in NSP-Minnesota.
(b)In 2021, AROs were revised for changes in timing and estimates of cash flows. Revisions in steam, hydro and other production AROs were primarily related to changes in cost estimates for remediation of ash containment facilities. Changes in gas transmission and distribution AROs were primarily related to changes in labor rates coupled with increased gas line mileage and number of services.
(c)There were no ARO amounts settled in 2021.
(Millions 
of Dollars)		Jan. 1, 2020
Amounts Incurred (a)
Amounts
Settled
(b)
Accretion
Cash Flow Revisions (c)
Dec. 31, 2020
Electric
Nuclear$2,068 $— $— $105 $(216)$1,957 
Steam, hydro and other production202 — (5)9 58 264 
Wind146 149 (3)8 60 360 
Distribution44 — — 2 — 46 
Natural gas
Transmission and distribution236 — — 10 6 252 
Miscellaneous3 — — — — 3 
Common
Miscellaneous1 — — — — 1 
Non-utility
Miscellaneous1 — — — — 1 
Total liability$2,701 $149 $(8)$134 $(92)$2,884 
(a)Amounts incurred related to the wind farms placed in service in 2020 for NSP-Minnesota (Blazing Star 1, Crowned Ridge 2, Jeffers and Community Wind North), PSCo (Cheyenne Ridge) and SPS (Sagamore).
(b)Amounts settled primarily related to closure of certain ash containment facilities, removal of wind facilities and asbestos abatement projects.
(c)In 2020, AROs were revised for changes in timing and estimates of cash flows. Revisions in the nuclear AROs were driven by reductions in spent fuel cooling time requirements in the nuclear triennial filing coupled with decreasing interest rates. Changes in wind AROs were driven by new dismantling studies. Revisions in steam, hydro and other production AROs were primarily related to changes in cost estimates for remediation of ash containment facilities.
(Millions 
of Dollars)
 Jan. 1, 2019 
Amounts
Incurred
(a)
 
Amounts
Settled
(b)
 Accretion 
Cash Flow Revisions (c)
 Dec. 31, 2019
Electric            
Nuclear $1,968
 $—
 $—
 $100
 $—
 $2,068
Steam, hydro and other production 177
 —
 (5) 8
 22
 202
Wind 119
 26
 —
 7
 (6) 146
Distribution 42
 —
 —
 2
 —
 44
Miscellaneous 7
 —
 —
 —
 (7) —
Natural gas            
Transmission and distribution 249
 —
 —
 11
 (24) 236
Miscellaneous 4
 —
 —
 —
 (1) 3
Common            
Miscellaneous 1
 —
 —
 —
 —
 1
Non-utility            
Miscellaneous 1
 —
 —
 —
 —
 1
Total liability $2,568
 $26
 $(5) $128
 $(16) $2,701
(a)
Amounts incurred related to the wind farms placed in service in 2019 for NSP-Minnesota (Lake Benton and Foxtail) and SPS (Hale).
(b)
Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities.
(c)
In 2019, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by decreased inflation rates. Changes in steam, hydro and other production AROs primarily related to the cost estimates to remediate ponds at production facilities. Changes in wind AROs were driven by new dismantling studies.
(Millions 
of Dollars)
 Jan. 1, 2018 
Amounts
Incurred
(a)
 
Amounts
Settled
(b)
 Accretion 
Cash Flow Revisions (c)
 Dec. 31, 2018
Electric            
Nuclear $1,874
 $—
 $—
 $94
 $—
 $1,968
Steam, hydro and other production 192
 —
 (14) 8
 (9) 177
Wind 96
 12
 —
 4
 7
 119
Distribution 21
 —
 —
 1
 20
 42
Miscellaneous 5
 —
 —
 —
 2
 7
Natural gas            
Transmission and distribution 282
 —
 —
 13
 (46) 249
Miscellaneous 4
 —
 —
 —
 —
 4
Common            
Miscellaneous 1
 —
 —
 —
 —
 1
Non-utility            
Miscellaneous —
 1
 —
 —
 —
 1
Total liability $2,475
 $13
 $(14) $120
 $(26) $2,568

(a)
Amounts incurred related to the PSCo Rush Creek wind farm and Nicollet Projects community solar gardens, which were placed in service in 2018.
(b)
Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities.
(c)
In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were primarily related to increased gas line mileage and number of services, which were more than offset by increased discount rates. Changes in electric distribution AROs primarily related to increased labor costs.

Indeterminate AROs — Other plants or buildings may contain asbestos due to the age of many of Xcel Energy’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2019.2021. Therefore, an ARO was not recorded for these facilities.
Removal Costs — Xcel Energy records a regulatory liability for the plant removal costs of its utility subsidiaries that are recovered currently in rates. Removal costs have accumulated based on varying rates as authorized by the appropriate regulatory entities. The utility subsidiaries have estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates.
Accumulated balances by entity at Dec. 31:
(Millions of Dollars) 2019 2018
NSP-Minnesota $520
 $485
PSCo 351
 344
SPS 175
 188
NSP-Wisconsin 171
 158
Total Xcel Energy $1,217
 $1,175

Nuclear Related
Nuclear Insurance — NSP-Minnesota’s public liability for claims from any nuclear incident is limited to $13.9$13.5 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has secured $450 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.5$13.0 billion of exposure is funded by the Secondary Financial Protection Program available from assessments by the federal government.
NSP-Minnesota is subject to assessments of up to $138 million per reactor-incident for each of its 3 licensed reactors, for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $21 million per reactor-incident during any one year. Maximum assessments are subject to inflation adjustments by the NRC and state premium taxes. The NRC’s last adjustment was effective November 2018.adjustments.
NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI. The coverage limits are $2.7$2.8 billion for each of NSP-Minnesota’s 2 nuclear plant sites. NEIL also provides business interruption insurance coverage up to $350 million, including the cost of replacement power during prolonged accidental outages of nuclear generating units. Premiums are expensed over the policy term.
All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds. Capital has been accumulated in the reserve funds of NEIL and EMANI to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage.
NSP-Minnesota could be subject to annual maximum assessments of approximately $12$11 million for business interruption insurance and $35$33 million for property damage insurance if losses exceed accumulated reserve funds.
Nuclear Fuel Disposal — NSP-Minnesota is responsible for temporarily storing spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from U.S. nuclear plants, but no such facility is yet available.
NSP-Minnesota owns temporary on-site storage facilities for spent fuel at its Monticello and PI nuclear plants, which consist of storage pools and dry cask facilities. The Monticello dry-cask storage facility currently stores all 30 of the authorized canisters. The PI dry-cask storage facility currently stores 4447 of the 64 authorized casks. Monticello’s future spent fuel will continue to be placed in its spent fuel pool. The decommissioning plan addresses the disposition of spent fuel at the end of the licensed life. A CON for additional storage at the Monticello site has been filed with the MPUC, to support possible life extension.NSP-Minnesota expects a decision by year-end 2023.
Regulatory Plant Decommissioning Recovery — Decommissioning activities for NSP-Minnesota’s nuclear facilities are planned to begin at the end of each unit’s operating license and be completed by 2091. NSP-Minnesota’s current operating licenses allow continued use of its Monticello nuclear plant until 2030 and its PI nuclear plant until 2033 for Unit 1 and 2034 for Unit 2.
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Future decommissioning costs of nuclear facilities are estimated through triennial periodic studies that assess the costs and timing of planned nuclear decommissioning activities for each unit.
Obligations for decommissioning are expected to be funded 100% by the external decommissioning trust fund. The cost study assumes the external decommissioning fund will earn an after-tax return between 5.23% and 6.30%.
Realized and unrealized gains on fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Decommissioning costs are quantified in 2014 dollars. Escalation rates are 4.36% for plant removal activities and 3.36% for fuel management and site restoration activities.
NSP-Minnesota had $2.4$3.3 billion of assets held in external decommissioning trusts at Dec. 31, 2019.2021. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation. Xcel Energy believes future decommissioning costs will continue to be recovered in customer rates. The following amounts were prepared on a regulatory basis and not directly recorded in the financial statements as an ARO.
  Regulatory Basis
(Millions of Dollars) 2019 2018
Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars) $3,012
 $3,012
Effect of escalating costs 688
 539
Estimated decommissioning cost obligation (in current dollars) 3,700
 3,551
Effect of escalating costs to payment date 7,505
 7,654
Estimated future decommissioning costs (undiscounted) 11,205
 11,205
Effect of discounting obligation (using average risk-free interest rate of 2.39% and 3.33% for 2019 and 2018, respectively) (5,562) (6,911)
Discounted decommissioning cost obligation $5,643
 $4,294
Assets held in external decommissioning trust $2,440
 $2,055
Underfunding of external decommissioning fund compared to the discounted decommissioning obligation 3,203
 2,239

Regulatory Basis
(Millions of Dollars)20212020
Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars)$3,012 $3,012 
Effect of escalating costs1,006 844 
Estimated decommissioning cost obligation (in current dollars)4,018 3,856 
Effect of escalating costs to payment date7,187 7,349 
Estimated future decommissioning costs (undiscounted)11,205 11,205 
Effect of discounting obligation (using average risk-free interest rate of 1.96% and 1.64% for 2021 and 2020, respectively)(4,651)(4,181)
Discounted decommissioning cost obligation$6,554 $7,024 
Assets held in external decommissioning trust$3,256 $2,777 
Underfunding of external decommissioning fund compared to the discounted decommissioning obligation3,298 4,247 
Calculations and data used by the regulator in approving NSP-Minnesota’s rates are useful in assessing future cash flows. Regulatory basis information is a means to reconcile amounts previously provided to the MPUC and utilized for regulatory purposes to amounts used for financial reporting.
Reconciliation of the discounted decommissioning cost obligation - regulated basis to the ARO recorded in accordance with GAAP:
(Millions of Dollars) 2019 2018(Millions of Dollars)20212020
Discounted decommissioning cost obligation - regulated basis $5,643
 $4,294
Discounted decommissioning cost obligation - regulated basis$6,554 $7,024 
Differences in discount rate and market risk premium (2,295) (1,447)Differences in discount rate and market risk premium(2,209)(2,628)
O&M costs not included for GAAP (1,280) (879)O&M costs not included for GAAP(1,584)(1,734)
ARO differences between 2020 and 2014 cost studiesARO differences between 2020 and 2014 cost studies(705)(705)
Nuclear production decommissioning ARO - GAAP $2,068
 $1,968
Nuclear production decommissioning ARO - GAAP$2,056 $1,957 


Decommissioning expenses recognized as a result of regulation:
(Millions of Dollars)202120202019
Annual decommissioning recorded as depreciation expense: (a) (b)
$22 $20 $20 
(Millions of Dollars) 2019 2018 2017
Annual decommissioning recorded as depreciation expense: (a) (b)
 $20
 $20
 $20

(a)Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.
(a)
Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.
(b)
Decommissioning expenses in 2019, 2018
(b)Decommissioning expenses in 2021, 2020 and 2019 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million.
The 2017 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million.
The 2014 nuclear decommissioning filing, approved in 2015, was used for regulatory presentation in 2019, 2018 and 2017. The 2017 filing, effective Jan. 1, 2019, has been approved by the MPUC. In March 2020, the MPUC approved for NSP-Minnesota to delay any increase to the annual funding requirement until 2021. In December 2019,2020, the MPUC verbally approved for NSP-Minnesota to delay any increase to the annual funding requirement until 2021.2022. In December 2021, NSP-Minnesota submitted a Petition for approval of the 2022 - 2024 Nuclear Decommissioning Study and Assumptions. Contemplated but not proposed in this filing, was the 10-year extension of the license to operate the Monticello Plant, moving the planned retirement date from 2030 to 2040. The 2019 Preferred Integrated Resource Plan Supplement does include a 10-year extension of the license.On Feb. 8, 2022, the MPUC approved the 10-year extension.
Leases
Xcel Energy evaluates contracts that may contain leases, including PPAs and arrangements for the use of office space and other facilities, vehicles and equipment. Under ASC Topic 842, adopted by Xcel Energy on Jan. 1, 2019, aA contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease.
ROU assets represent Xcel Energy's rights to use leased assets. Starting in 2019, theThe present value of future operating lease payments areis recognized in other current liabilities and noncurrent operating lease liabilities. These amounts, adjusted for any prepayments or incentives, are recognized as operating lease ROU assets.
Most of Xcel Energy’s leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using the applicable Xcel Energy subsidiary’s estimated incremental borrowing rate (weighted-average(weighted average of 4.1%4.0%). Xcel Energy has elected the practical expedient under which non-lease components, such as asset maintenance costs included in payments, are not deducted from minimum lease payments for the purposes of lease accounting and disclosure.
Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the consolidated balance sheet.
Operating lease ROU assets:
(Millions of Dollars) Dec. 31, 2019
PPAs $1,642
Other 201
Gross operating lease ROU assets 1,843
Accumulated amortization (171)
Net operating lease ROU assets $1,672

(Millions of Dollars)Dec. 31, 2021Dec. 31, 2020
PPAs$1,656 $1,650 
Other225 212 
Gross operating lease ROU assets1,881 1,862 
Accumulated amortization(590)(372)
Net operating lease ROU assets$1,291 $1,490 

In 2019, 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. Prior to 2019, finance leases were included in property, plant and equipment, the current portion of long-term debt and long-term debt.
Xcel Energy’s most significant finance lease activities are related to WYCO, a joint venture with CIG, to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc. has a 50% ownership interest in WYCO. WYCO leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage and transportation services to PSCo under separate service agreements.
PSCo accounts for its Totem natural gas storage service and Front Range pipeline arrangements with CIG and WYCO, respectively, as finance leases. Xcel Energy Inc. eliminates 50% of the finance lease obligation related to WYCO in the consolidated balance sheet along with an equal amount of Xcel Energy Inc.’s equity investment in WYCO.
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Finance lease ROU assets:
(Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018
Gas storage facilities $201
 $201
Gas pipeline 21
 21
Gross finance lease ROU assets 222
 222
Accumulated amortization (83) (77)
Net finance lease ROU assets $139
 $145

(Millions of Dollars)Dec. 31, 2021Dec. 31, 2020
Gas storage facilities$201 $201 
Gas pipeline21 21 
Gross finance lease ROU assets222 222 
Accumulated amortization(97)(90)
Net finance lease ROU assets$125 $132 
Components of lease expense:
(Millions of Dollars)202120202019
Operating leases
PPA capacity payments$251 $238 $221 
Other operating leases (a)
36 26 34 
Total operating lease expense (b)
$287 $264 $255 
Finance leases
Amortization of ROU assets$7 $7 $6 
Interest expense on lease liability17 18 19 
Total finance lease expense$24 $25 $25 
(Millions of Dollars) 2019 2018 2017
Operating leases      
PPA capacity payments $221
 $210
 $210
Other operating leases (a)
 34
 38
 36
Total operating lease expense (b)
 $255
 $248
 $246
Finance leases      
Amortization of ROU assets $6
 $6
 $5
Interest expense on lease liability 19
 19
 20
Total finance lease expense $25
 $25
 $25
(a)Includes short-term lease expense of $5 million for 2021, 2020 and 2019.
(a)
(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.
Includes short-term lease expense of $5 million for 2019, 2018 and 2017.
(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, 2019:2021:
(Millions of Dollars)
PPA (a) (b)
Operating
Leases
Other Operating
Leases
Total
Operating
Leases
Finance
 Leases (c)
2022$229 $27 $256 $12 
2023221 26 247 12 
2024209 22 231 12 
2025189 16 205 10 
2026146 12 158 9 
Thereafter416 81 497 187 
Total minimum obligation1,410 184 1,594 242 
Interest component of obligation(209)(34)(243)(170)
Present value of minimum obligation$1,201 150 1,351 72 
Less current portion(205)(3)
Noncurrent operating and finance lease liabilities$1,146 $69 
Weighted-average remaining lease term in years8.936.1
(Millions of Dollars) 
PPA (a) (b)
Operating
Leases
 
Other Operating
Leases
 
Total
Operating
Leases
 
Finance
 Leases (c)
2020 $236
 $26
 $262
 $14
2021 238
 29
 267
 14
2022 225
 28
 253
 12
2023 214
 25
 239
 12
2024 208
 22
 230
 12
Thereafter 750
 115
 865
 207
Total minimum obligation 1,871
 245
 2,116
 271
Interest component of obligation (321) (52) (373) (190)
Present value of minimum obligation $1,550
 193
 1,743
 81
Less current portion     (194) (4)
Noncurrent operating and finance lease liabilities     $1,549
 $77
         
Weighted-average remaining lease term in years     9.3
 37.0
(a)Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.
(b)PPA operating leases contractually expire at various dates through 2039.
(c)(a)
Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.
(b)
PPA operating leases contractually expire at various dates through 2033.
(c)
Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.
Operating lease liabilities at Dec. 31, 2019 include a present value of approximately $400 million for MEC PPA capacity payments. In 2020, these operating lease liabilities and related ROU assets will be eliminated from Xcel Energy’s consolidated balance sheet following the completed January 2020 purchase of MEC by a newly formed non-regulated subsidiary of Xcel Energy.
50% ownership interest in WYCO.

Commitments under operating and finance leases as of Dec. 31, 2018:
(Millions of Dollars) 
PPA (a) (b)
Operating
Leases
 
Other Operating
Leases
 
Total
Operating
Leases
 
Finance Leases (c)
2019 $207
 $32
 $239
 $14
2020 208
 26
 234
 14
2021 210
 25
 235
 14
2022 197
 24
 221
 12
2023 186
 22
 208
 12
Thereafter 883
 154
 1,037
 220
Total minimum obligation 

 

 

 286
Interest component of obligation       (201)
Present value of minimum obligation     $85
(a)
Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.
(b)
PPA operating leases contractually expire at various dates through 2033.
(c)
Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.
PPAs and Fuel Contracts
Non-Lease PPAs — NSP Minnesota,NSP-Minnesota, PSCo and SPS have entered into PPAs with other utilities and energy suppliers with various expiration dates through 2034 for purchased power to meet system load and energy requirements, operating reserve obligations and as part of wholesale and commodity trading activities. In general, these agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs, accounted for as executory contracts with various expiration dates through 2033, contain minimum energy purchase commitments, and totalcommitments. Total energy payments on those contracts were $149 million, $112 million and $102 million $105 millionin 2021, 2020 and $100 million in 2019, 2018 and 2017, respectively.
Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $69 million, $75 million and $86 million $131 millionin 2021, 2020 and $168 million in 2019, 2018 and 2017, respectively.
Capacity and energy payments are contingent on the IPPs meeting contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices. The effects of price adjustments on financial results are mitigated through purchased energy cost recovery mechanisms.
At Dec. 31, 2019,2021, the estimated future payments for capacity and energy that the utility subsidiaries of Xcel Energy are obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:
(Millions of Dollars)Capacity
Energy (a)
2022$75 $165 
202377 169 
202472 174 
202529 53 
202612 10 
Thereafter12 38 
Total$277 $609 
(Millions of Dollars) Capacity 
Energy (a)
2020 $70
 $110
2021 78
 157
2022 77
 173
2023 79
 177
2024 74
 182
Thereafter 56
 146
Total $434
 $945
(a)(a)Excludes contingent energy payments for renewable energy PPAs.
Excludes contingent energy payments for renewable energy PPAs.
Fuel Contracts — Xcel Energy has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal, nuclear fuel and natural gas requirements. These contracts expire between 20202022 and 2060. Xcel Energy is required to pay additional amounts depending on actual quantities shipped under these agreements.
Estimated minimum purchases under these contracts as of Dec. 31, 2019:2021:
(Millions of Dollars) Coal Nuclear fuel Natural gas supply Natural gas supply and transportation
2020 $430
 $54
 $343
 $295
2021 222
 103
 254
 283
2022 135
 85
 104
 269
2023 58
 103
 53
 198
2024 24
 74
 3
 153
Thereafter 74
 275
 —
 860
Total $943
 $694
 $757
 $2,058

(Millions of Dollars)CoalNuclear fuelNatural gas supplyNatural gas supply and transportation
2022$620 $89 $477 $292 
2023233 109 75 224 
2024147 82 4 172 
202529 119 — 156 
202631 29 — 149 
Thereafter34 309 — 571 
Total$1,094 $737 $556 $1,564 
VIEs 
PPAs — Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from IPPs for which the utility subsidiaries are required to reimburse fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. Xcel Energy has determined that certain IPPs are VIEs. Xcel Energy is not subject to risk of loss from the operations of these entities, and no significant financial support is required other than contractual payments for energy and capacity.
In addition, certain solar PPAs provide an option to purchase emission allowances or sharing provisions related to production credits generated by the solar facility under contract. These specific PPAs create a variable interest in the IPP.
Xcel Energy evaluated each of these VIEs for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. Xcel Energy concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.
79
The utility subsidiaries had approximately 3,986 MW and 3,7704,062 MW of capacity under long-term PPAs at both Dec. 31, 20192021 and 2018, respectively,2020 with entities that have been determined to be VIEs. AgreementsThese agreements have expiration dates through 2041.
Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk plants from TUCO Inc. under contracts that will expire in December 2022. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.
SPS has not provided any significant financial support to TUCO, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of fuel procurement costs.
SPS has determined that TUCO is a VIE, however it has concluded that SPS is not the primary beneficiary of TUCO because it does not have the power to direct the activities that most significantly impact TUCO’s economic performance.

Low-Income Housing Limited Partnerships — Eloigne and NSP-Wisconsin have entered into limited partnerships for the construction and operation of affordable rental housing developments which qualify for low-income housing tax credits. Xcel Energy Inc. has determined Eloigne and NSP-Wisconsin’s low-income housing partnerships to be VIEs primarily due to contractual arrangements within each limited partnership that establish sharing of ongoing voting control and profits and losses that does not align with the partners’ proportional equity ownership.
Eloigne and NSP-Wisconsin have the power to direct the activities that most significantly impact these entities’ economic performance. Therefore, Xcel Energy Inc. consolidates these limited partnerships in its consolidated financial statements. Xcel Energy’s risk of loss for these partnerships is limited to its capital contributions, adjusted for any distributions and its share of undistributed profits and losses; no significant additional financial support has been, or is required to be, provided to the limited partnerships by Eloigne or NSP-Wisconsin.
Amounts reflected in Xcel Energy’s consolidated balance sheets for the Eloigne and NSP-Wisconsin low-income housing limited partnerships:
(Millions of Dollars)Dec. 31, 2021Dec. 31, 2020
Current assets$7 $7 
Property, plant and equipment, net37 38 
Other noncurrent assets1 1 
Total assets$45 $46 
Current liabilities$7 $8 
Mortgages and other long-term debt payable27 25 
Other noncurrent liabilities1 1 
Total liabilities$35 $34 
(Millions of Dollars) Dec. 31, 2019 Dec. 31, 2018
Current assets $7
 $5
Property, plant and equipment, net 41
 42
Other noncurrent assets 1
 1
Total assets $49
 $48
     
Current liabilities $8
 $7
Mortgages and other long-term debt payable 26
 26
Other noncurrent liabilities —
 —
Total liabilities $34
 $33

Other
Technology Agreements — Xcel Energy has a contract that extends through December 2022 with IBM for information technology services. The contract is cancelable at Xcel Energy’s option, although Xcel Energy would be obligated to pay 50% of the contract value for early termination. Xcel Energy capitalized or expensed $46 million, $81 million and $98 million associated with the IBM contract in 2019, 2018 and 2017, respectively.
Xcel Energy’s contract with Accentureseveral contracts for information technology services extendsthat extend through December 2020.2022. The contract iscontracts are cancelable, at Xcel Energy’s option, although there are financial penalties for early termination. Xcel Energy capitalized or expensed $52$103 million, $46$110 million and $16$101 million associated with the Accenture contractthese contracts in 2021, 2020 and 2019, 2018 and 2017, respectively.
During 2019, Xcel Energy executed a contract with Cognizant for information technology services which extends through 2022. The contract is cancelable at Xcel Energy’s option, although there are financial penalties for early termination. Xcel Energy capitalized or expensed $3 million associated with the Cognizant contract in 2019.
Committed minimum payments under these obligations:obligations are $15 million in 2022.
(Millions of Dollars) IBM Agreement Accenture Agreement Cognizant Agreement
2020 $15
 $11
 $9
2021 15
 —
 7
2022 6
 —
 3
2023 —
 —
 —
2024 —
 —
 —
Thereafter —
 —
 —

Guarantees and Bond Indemnifications — Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum amount.
As of Dec. 31, 20192021 and 2018,2020, Xcel Energy Inc. and its subsidiaries had 0no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements.
Guarantees and bond indemnities issued and outstanding for Xcel Energy were $60 million and $62 million and $69 million as ofat Dec. 31, 20192021 and 2018.2020 respectively.
Other Indemnification Agreements — Xcel Energy Inc. and its subsidiaries provide indemnifications through various contracts. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold. Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.
13. Other Comprehensive Income
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:
2021
(Millions of Dollars)Gains and Losses on Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotal
Accumulated other comprehensive loss at Jan. 1$(85)$(56)$(141)
Other comprehensive loss before reclassifications (net of taxes of $1 and $—, respectively)4 — 4 
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $2 and $—, respectively)6 (a)— 6 
Amortization of net actuarial loss (net of taxes of $— and $3, respectively)— 8 (b)8 
Net current period other comprehensive income10 8 18 
Accumulated other comprehensive loss at Dec. 31$(75)$(48)$(123)
  2019
(Millions of Dollars) Gains and
Losses on Cash Flow Hedges		 Defined Benefit
Pension and
Postretirement
Items		 Total
Accumulated other comprehensive loss at Jan. 1 $(60) $(64) $(124)
Other comprehensive loss before reclassifications (net of taxes of $(8) and $0, respectively) (23) —
 (23)
Losses reclassified from net accumulated other comprehensive loss:      
Interest rate derivatives (net of taxes of $1 and $0, respectively) 3
(a) 
—
 3
Amortization of net actuarial loss (net of taxes of $0 and $1, respectively) —
 3
(b) 
3
Net current period other comprehensive (loss) income (20) 3
 (17)
Accumulated other comprehensive loss at Dec. 31 $(80) $(61) $(141)

(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.
80
2020
(Millions of Dollars)Gains and Losses on Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotal
Accumulated other comprehensive loss at Jan. 1$(80)$(61)$(141)
Other comprehensive loss before reclassifications (net of taxes of $(3) and $(2), respectively)(10)(5)(15)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $2 and $—, respectively)5 (a)— 5 
Amortization of net actuarial loss (net of taxes of $— and $3, respectively)— 10 (b)10 
Net current period other comprehensive (loss) income(5)5 — 
Accumulated other comprehensive loss at Dec. 31$(85)$(56)$(141)
(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.
(a)
Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.
  2018
(Millions of Dollars) 
Gains and
Losses on Cash Flow Hedges
 
Defined Benefit
Pension and
Postretirement
Items
 Total
Accumulated other comprehensive loss at Jan. 1 $(58) $(67) $(125)
Other comprehensive loss before reclassifications (net of taxes of $(2) and $(2), respectively) (5) (6) (11)
Losses reclassified from net accumulated other comprehensive loss:      
Interest rate derivatives (net of taxes of $1 and $0, respectively) 3
(a) 
—
 3
Amortization of net actuarial loss (net of taxes of $0 and $3, respectively) —
 9
(b) 
9
Net current period other comprehensive (loss) income (2) 3
 1
Accumulated other comprehensive loss at Dec. 31 $(60) $(64) $(124)
(a)
Included in interest charges.
(b)
Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.

14. Segments and RelatedSegment Information
Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided, including the regulated
electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and
SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.
Xcel Energy has the following reportable segments:
•
Regulated Electric - The regulated electric utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes wholesale commodity and trading operations; and
•
Regulated Natural Gas -
•Regulated Electric — The regulated electric utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes wholesale commodity and trading operations.
•Regulated Natural Gas — The regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado.
Xcel Energy also presents All Other, which includes operating segments with revenues below the necessary quantitative thresholds. Those operating segments primarily include steam revenue, appliance repair services, non-utility real estate activities, revenues associated with processing solid waste into refuse-derived fuel, and investments in rental housing projects that qualify for low-income housing tax credits.credits and the operations of MEC until July 2020.
Xcel Energy had equity method investments in unconsolidated subsidiaries of $155$208 million and $141$165 million as of Dec. 31, 20192021 and 2018,2020, respectively, included in the natural gas utility and all other segments.
Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments. As an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment. Reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations, which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.
Certain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.
Xcel Energy’s segment information:
(Millions of Dollars) 2019 2018 2017
Regulated Electric      
Operating revenues from external customers $9,575
 $9,719
 $9,676
Intersegment revenue 1
 1
 2
Total revenues $9,576
 $9,720
 $9,678
Depreciation and amortization 1,535
 1,421
 1,298
Interest charges and financing costs 500
 449
 449
Income tax expense 125
 187
 528
Net income 1,288
 1,177
 1,066
Regulated Natural Gas      
Operating revenues from external customers $1,868
 $1,739
 $1,650
Intersegment revenue 2
 2
 1
Total revenues $1,870
 $1,741
 $1,651
Depreciation and amortization 219
 212
 174
Interest charges and financing costs 69
 61
 57
Income tax expense 48
 28
 23
Net income 195
 187
 182
Other      
Total operating revenue $86
 $79
 $78
Depreciation and amortization 11
 9
 7
Interest charges and financing costs 167
 142
 122
Income tax (benefit) (45) (34) (9)
Net (loss) (111) (103) (100)
       
Consolidated Total      
Total revenue $11,532
 $11,540
 $11,407
Reconciling eliminations (3) (3) (3)
Consolidated total revenue $11,529
 $11,537
 $11,404
Depreciation and amortization 1,765
 1,642
 1,479
Interest charges and financing costs 736
 652
 628
Income tax expense 128
 181
 542
Net income 1,372
 1,261
 1,148

(Millions of Dollars)202120202019
Regulated Electric
Operating revenues — external$11,205 $9,802 $9,575 
Intersegment revenue2 2 1 
Total revenues$11,207 $9,804 $9,576 
Depreciation and amortization1,855 1,673 1,535 
Interest charges and financing costs568 534 500 
Income tax (benefit) expense(96)1 125 
Net income1,478 1,407 1,288 
Regulated Natural Gas
Operating revenues — external$2,132 $1,636 $1,868 
Intersegment revenue2 1 2 
Total revenues$2,134 $1,637 $1,870 
Depreciation and amortization254 252 219 
Interest charges and financing costs75 71 69 
Income tax expense54 17 48 
Net income231 190 195 
All Other
Total revenues$94 $88 $86 
Depreciation and amortization12 23 11 
Interest charges and financing costs173 193 167 
Income tax benefit(28)(24)(45)
Net loss(112)(124)(111)
Consolidated Total
Total revenues$13,435 $11,529 $11,532 
Reconciling eliminations(4)(3)(3)
Total operating revenues$13,431 $11,526 $11,529 
Depreciation and amortization2,121 1,948 1,765 
Interest charges and financing costs816 798 736 
Income tax (benefit) expense(70)(6)128 
Net income1,597 1,473 1,372 
15. Summarized Quarterly Financial Data (Unaudited)
  Quarter Ended
(Amounts in millions, except per share data) March 31, 2019 June 30, 2019 Sept. 30, 2019 Dec. 31, 2019
Operating revenues $3,141
 $2,577
 $3,013
 $2,798
Operating income 486
 410
 758
 450
Net income 315
 238
 527
 292
EPS total — basic $0.61
 $0.46
 $1.02
 $0.56
EPS total — diluted 0.61
 0.46
 1.01
 0.56
Cash dividends declared per common share 0.405
 0.405
 0.405
 0.405
  Quarter Ended
(Amounts in millions, except per share data) March 31, 2018 June 30, 2018 Sept. 30, 2018 Dec. 31, 2018
Operating revenues $2,951
 $2,658
 $3,048
 $2,880
Operating income (a)
 480
 450
 696
 339
Net income 291
 265
 491
 214
EPS total — basic $0.57
 $0.52
 $0.96
 $0.42
EPS total — diluted 0.57
 0.52
 0.96
 0.42
Cash dividends declared per common share 0.380
 0.380
 0.380
 0.380

(a)
In 2018, Xcel Energy implemented ASU No. 2017-07 related to net periodic benefit cost, which resulted in retrospective reclassification of pension costs from O&M expense to other income.

ITEM 9 — CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A — CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the CEO and CFO, allowing timely decisions regarding required disclosure.
81
As of Dec. 31, 2019,2021, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
No changes in Xcel Energy’s internal control over financial reporting occurred during the most recent fiscal quarter ended Dec. 31, 2021 that materially affected, or are reasonably likely to materially affect, Xcel Energy’s internal control over financial reporting. Xcel Energy maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. Xcel Energy has evaluated and documented its controls in process activities, general computer activities, and on an entity-wide level.
During the year and in preparation for issuing its report for the year ended Dec. 31, 20192021 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, Xcel Energy conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, Xcel Energy did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board, as approved by the SEC and as indicated in Xcel Energy’s Management Report on Internal Controls over Financial Reporting, which is contained in Item 8 herein.













ITEM 9B — OTHER INFORMATION
None.
PART III
ITEM 9C — DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.

PART III
ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information required under this Item with respect to Directors and Corporate Governance is set forth in Xcel Energy Inc.’s Proxy Statement for its 20202022 Annual Meeting of Shareholders, which is expected to occur on April 6, 2020,5, 2022, incorporated by reference. Information with respect to Executive Officers is included in Item 1 to this report.
ITEM 11 — EXECUTIVE COMPENSATION
Information required under this Item is set forth in Xcel Energy Inc.’s Proxy Statement for its 20202022 Annual Meeting of Shareholders, which is incorporated by reference.
ITEM 12 — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 20202022 Annual Meeting of Shareholders, which is incorporated by reference.
ITEM 13 — CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 20202022 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 definitive Proxy Statement for its 20202022 Annual Meeting of Shareholders, which is incorporated by reference.


PART IV
ITEM 15 — EXHIBITS,EXHIBIT AND FINANCIAL STATEMENT SCHEDULES
1Consolidated Financial Statements
Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2019.2021.
Report of Independent Registered Public Accounting Firm — Financial Statements
Report of Independent Registered Public Accounting Firm — and Internal Controls Over Financial Reporting
Consolidated Statements of Income — For each of the three years ended Dec. 31, 2019, 2018,2021, 2020, and 2017.2019.
Consolidated Statements of Comprehensive Income — For each of the three years ended Dec. 31, 2019, 2018,2021, 2020, and 2017.2019.
Consolidated Statements of Cash Flows — For each of the three years ended Dec. 31, 2019, 2018,2021, 2020, and 2017.2019.
Consolidated Balance Sheets — As of Dec. 31, 20192021 and 2018.2020.
Consolidated Statements of Common Stockholders’ Equity — For each of the three years ended Dec. 31, 2019, 2018,2021, 2020, and 2017.2019.
2Schedule I — Condensed Financial Information of Registrant.
Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2019, 20182021, 2020, and 2017.2019.
3Exhibits
*Indicates incorporation by reference
+Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
Xcel Energy Inc.
Exhibit NumberDescriptionReport or Registration StatementSEC File or Registration NumberExhibit Reference
Xcel Energy IncInc. Form 8-K dated May 16, 2012001-030343.01
Xcel Energy IncInc. Form 8-K dated Feb. 17, 2016April 3, 2020001-030343.01
Description of Securities
4.02*
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 20194.01
82
Table of Contents
Xcel Energy Inc. Form 8-K dated Dec. 14, 2000001-030344.01
Xcel Energy Inc. Form 8-K dated June 6, 2006001-030344.01
Xcel Energy Inc. Form 8-K dated Jan. 16, 2008001-030344.01
Xcel Energy Inc. Form 8-K dated Jan. 16, 2008001-030344.03
Supplemental Indenture dated as of May 1, 2010 between Xcel Energy Inc. and Wells Fargo Bank, National Association, as Trustee
Xcel Energy Inc. Form 8-K dated May 10, 2010001-030344.01
4.07*
Xcel Energy Inc. Form 8-K dated Sept. 12, 2011001-030344.01
Xcel Energy Inc. Form 8-K dated June 1, 2015001-030344.01
Xcel Energy Inc. Form 8-K dated March 8, 2016001-030344.02
4.10*
Supplemental Indenture No. 10, dated as of Dec. 1, 2016, by and between Xcel Energy Inc. and Wells Fargo Bank, National Association, as Trustee
Xcel Energy Inc. Form 8-K dated Dec. 1, 2016001-030344.01
Xcel Energy Inc. Form 8-K dated June 25, 2018001-030344.01
Xcel Energy Inc. Form 8-K dated Nov. 7, 20194.01
Xcel Energy Inc. Form 8-K dated April 1, 20204.01
Xcel Energy Inc. Form 8-K dated Sept. 25, 20204.01
Xcel Energy Inc. Form 8-K dated Nov. 7, 20193, 2021001-030344.01
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008001-0303410.02
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008001-0303410.05
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 20082011001-0303410.0810.18
Xcel Energy Inc. Form U5B dated Nov. 16, 200010-Q for the quarter ended June 30, 2016001-03034H-110.01
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 201810.01
Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 202010.02
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 202010.01
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008001-0303410.17
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009001-0303410.06

10.07*+
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, 2009001-0303410.08
10.08*+
Xcel Energy Inc. Executive Annual Incentive Plan (as amended and restated effective Feb. 17, 2010)
Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010001-03034Appendix A
Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 201310.01
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 200910.08
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 200810.07
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 201110.17
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 201310.22
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 201610.01
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 201710.1
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 201810.34
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 201810.35
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 201910.32
Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011001-03034Appendix A
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008001-0303410.07
10.11*+
First Amendment to Exhibit 10.10 effective Nov. 29, 2011
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011001-0303410.17
10.12*+
Second Amendment to Exhibit 10.02 dated Oct. 26, 2011
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011001-0303410.18
10.13*+
First Amendment to Exhibit 10.08 dated Feb. 20, 2013
Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013001-0303410.01
10.14*+
Fourth Amendment to Exhibit 10.02 dated Feb. 20, 2013
Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013001-0303410.02
10.15*+
Second Amendment to Exhibit 10.10 dated May 21, 2013
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013001-0303410.22
10.16*+
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, 2015001-0303410.02
Xcel Energy Inc. Form 10-Q for the quarter ended JuneSeptember 30, 20162021001-0303410.01
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016001-0303410.01
10.19*+
Fourth Amendment to Exhibit 10.10 dated Oct. 23, 2017
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017001-0303410.1
10.20*+
Sixth Amendment to Exhibit 10.02 dated Feb. 22, 2018
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017001-0303410.30
10.21*+
Seventh Amendment to Exhibit 10.02 dated May 7, 2018
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018001-0303410.01
10.22*
Forward Sale Agreement, dated Nov. 7, 2018, between Xcel Energy Inc. and Morgan Stanley &Co., LLC
Xcel Energy Inc. Form 8-K dated Nov. 7, 2018001-0303410.01
10.23*
Amended and Restated 364-Day Term Loan Agreement dated as of Dec. 4, 2018 among Xcel Energy Inc., as Borrower, the several lenders from time to time parties thereto, and MUFG Bank, Ltd. as Administrative Agent.
Xcel Energy Inc. Form 8-K dated Dec. 4, 2018001-0303499.01
10.24*+
Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018001-0303410.34
10.25*+
Form of Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement Terms and Conditions under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018001-0303410.35
10.26*+
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, 2018001-0303410.36
Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2019U5B dated Nov. 16, 2000001-03034H-1
83
Table of Contents
10.01
Xcel Energy Inc. Form 8-K dated June 7, 2019

001-0303499.01
Xcel Energy Inc. Form 8-K dated Oct. 30, 2019001-0303410.01
10.30*
Additional Forward Sale Agreement, dated Nov. 1, 2019 between Xcel Energy Inc. and Citibank, N.A.
Xcel Energy Inc. Form 8-K dated Oct. 30, 2019001-0303410.02
10.31*
364-Day Term Loan Agreement dated Dec. 3, 2019as of February 18, 2021 among Xcel Energy Inc., as Borrower, the several lenders from time to time parties thereto, and Canadian ImperialU.S. Bank of Commerce, New York Branch,National Association, as Administrative AgentAgent.
Xcel Energy Inc. Form 8-K dated Dec. 3, 2019February 18, 2021001-0303410.01
10.2710.32*+
Xcel Energy Inc. Form 8-K dated December 10, 202110.01
NSP-Minnesota
Xcel Energy Inc. Form S-3 dated April 18, 2018001-030344(b)(3)
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017001-030344.11
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017001-030344.12
NSP-Minnesota Form 10-12G dated Oct. 5, 2000000-317094.51
Xcel Energy Inc. Form S-3 dated April 18, 2018001-030344(b)(7)

NSP-Minnesota Form 10-12G dated Oct. 5, 2000000-317094.63
NSP-Minnesota Form 8-K dated July 14, 2005001-313874.01
NSP-Minnesota Form 8-K dated May 18, 2006001-313874.01
NSP-Minnesota Form 8-K dated June 19, 2007001-313874.01
NSP-Minnesota Form 8-K dated Nov. 16, 2009001-313874.01
NSP-Minnesota Form 8-K dated Aug. 4, 2010001-313874.01
NSP-Minnesota Form 8-K dated Aug. 13, 2012001-313874.01
NSP-Minnesota Form 8-K dated May 20, 2013001-313874.01
NSP-Minnesota Form 8-K dated May 13, 2014001-313874.01
NSP-Minnesota Form 8-K dated Aug. 11, 2015001-313874.01
NSP-Minnesota Form 8-K dated May 31, 2016001-313874.01
NSP-Minnesota Form 8-K dated Sept. 13, 2017001-313874.01
NSP-Minnesota Form 8-K dated Sept. 10, 2019001-313874.01
NSP-Minnesota 8-K dated June 15, 20204.01
NSP-Minnesota 8-K dated March 30, 20214.01
NSP-Wisconsin Form S-4 dated Jan. 21, 2004333-11203310.01
Xcel Energy Inc. Form 8-K dated June 7, 2019001-0303499.02
NSP-Wisconsin
Xcel Energy Inc. Form S-3 dated April 18, 2018001-030344(c)(3)
NSP-Wisconsin Form 8-K dated Sept. 25, 2000001-031404.01
84
Table of Contents
4.01
Xcel Energy Inc Form 10-Q for the quarter ended Sept. 30, 2003001-030344.05
4.34*
Supplemental Trust Indenture dated as of Sept. 1, 2008 between NSP-Wisconsin and U.S. Bank National Association, as successor Trustee, creating $200 million principal amount of 6.375% First Mortgage Bonds, Series duedue Sept. 1, 2038
NSP-Wisconsin Form 8-K dated Sept. 3, 2008001-031404.01
NSP-Wisconsin Form 8-K dated Oct. 10, 2012001-031404.01
NSP-Wisconsin Form 8-K dated June 23, 2014001-031404.01
NSP-Wisconsin Form 8-K dated Dec. 4, 2017001-031404.01
NSP-Wisconsin to Form 8-K dated Sept. 12, 2018001-030344.01
NSP-Wisconsin Form 8-K dated May 26, 20204.01
NSP-Wisconsin Form 8-K dated July 20, 20214.01
NSP-Wisconsin Form S-4 dated Jan. 21, 2004333-11203310.01

Xcel Energy Inc. Form 8-K dated June 7, 2019001-0303499.05
PSCo
NSP-Wisconsin Form 8-K dated July 20, 20211.01
PSCo
Xcel Energy Inc. Form S-3 dated April 18, 2018001-030344(d)(3)
PSCo Form 8-K dated July 13, 1999001-03280
4.1
4.2
4.41*
Supplemental Indenture, dated Aug. 1, 2007 between PSCo and U.S. Bank Trust National Association, as successor Trustee
PSCo Form 8-K dated Aug. 8, 2007001-032804.01
PSCo Form 8-K dated Aug. 6, 2008001-032804.01
PSCo Form 8-K dated May 28, 2009001-032804.01
4.44*
Supplemental Indenture dated as of Nov. 1, 2010 between PSCo and U.S. Bank National Association, as successor Trustee, creating $400 million principal amount of 3.20% First Mortgage Bonds, Series due 2020
PSCo Form 8-K dated Nov. 8, 2010001-032804.01
4.45*
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, 2011001-032804.01
PSCo Form 8-K dated Sept. 11, 2012001-032804.01
PSCo Form 8-K dated March 26, 2013001-032804.01
PSCo Form 8-K dated March 10, 2014001-032804.01
PSCo Form 8-K dated May 12, 2015001-032804.01
PSCo Form 8-K dated June 13, 2016001-032804.01
PSCo Form 8-K dated June 19, 2017001-032804.01
PSCo Form 8-K dated June 21, 2018001-032804.01
PSCo Form 8-K dated March 13, 2019001-032804.01
PSCo Form 8-K dated August 13, 2019001-032804.01
PSCo Form 8-K dated May 15, 20204.01
PSCo Form 8-K dated March 1, 20214.01
Xcel Energy Inc. Form 8-K dated Dec. 3, 2004001-0303499.02
Xcel Energy Inc. Form 8-K dated June 7, 2019001-0303499.03
SPS
SPS Form 8-K dated Feb. 25, 1999001-0378999.2
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2003001-030344.04
SPS Form 8-K dated Oct. 3, 2006001-037894.01
SPS Form 8-K dated Aug. 10, 2011001-037894.01
85
Table of Contents
4.01
SPS Form 8-K dated Aug. 10, 2011001-037894.02
SPS Form 8-K dated June 9, 2014001-037894.02
SPS Form 8-K dated Aug. 12, 2016001-037894.02
SPS Form 8-K dated Aug 9. 2017001-037894.02
SPS Form 8-K dated Nov. 5, 2018001-037894.02

SPS Form 8-K dated June 18, 2019001-037894.02
SPS Form 8-K dated May 18, 20204.02
Xcel Energy Inc. Form 8-K dated June 7, 2019001-0303499.04
Xcel Energy Inc.
101.INSInline 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.SCHInline XBRL Schema
101.CALInline XBRL Calculation
101.DEFInline XBRL Definition
101.LABInline XBRL Label
101.PREInline XBRL Presentation
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

86
SCHEDULE I
XCEL ENERGY INC.
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(amounts in millions, except per share data)
Year Ended Dec. 31
202120202019
Income
Equity earnings of subsidiaries$1,744 $1,646 $1,505 
Total income1,744 1,646 1,505 
Expenses and other deductions
Operating expenses21 43 23 
Other income3 (4)(9)
Interest charges and financing costs173 198 173 
Total expenses and other deductions197 237 187 
Income before income taxes1,547 1,409 1,318 
Income tax benefit(50)(64)(54)
Net income$1,597 $1,473 $1,372 
Other Comprehensive Income
Pension and retiree medical benefits, net of tax of $ 1, $1 and $1, respectively$8 $5 $3 
Derivative instruments, net of tax of $3, $(1) and $(7), respectively10 (5)(20)
Other comprehensive income (loss)18 — (17)
Comprehensive income$1,615 $1,473 $1,355 
Weighted average common shares outstanding:
Basic539 527 519 
Diluted540 528 520 
Earnings per average common share:
Basic$2.96 $2.79 $2.64 
Diluted2.96 2.79 2.64 
See Notes to Condensed Financial Statements
XCEL ENERGY INC.
CONDENSED STATEMENTS OF CASH FLOWS
(amounts in millions)
Year Ended Dec. 31
202120202019
Operating activities
Net cash provided by operating activities$1,147 $2,377 $1,389 
Investing activities
Capital contributions to subsidiaries(1,661)(2,553)(1,594)
Net return (investments) in the utility money pool57 (18)39 
Other, net— (1)— 
Net cash used in investing activities(1,604)(2,572)(1,555)
Financing activities
Proceeds (repayment of) from short-term borrowings, net638 (500)12 
Proceeds from issuance of long-term debt791 1,089 1,120 
Repayment of long-term debt(400)(300)(550)
Proceeds from issuance of common stock366 727 458 
Repurchase of common stock— (4)— 
Dividends paid(935)(856)(791)
Other(16)(17)(14)
Net cash provided by financing activities444 139 235 
Net change in cash, cash equivalents, and restricted cash(13)(56)69 
Cash, cash equivalents and restricted cash at beginning of period14 70 1 
Cash, cash equivalents and restricted cash at end of period$1 $14 $70 
See Notes to Condensed Financial Statements
XCEL ENERGY INC.
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(amounts in millions, except per share data)
 Year Ended Dec. 31
 2019 2018 2017
Income     
Equity earnings of subsidiaries$1,505
 $1,393
 $1,263
Total income1,505
 1,393
 1,263
Expenses and other deductions     
Operating expenses23
 24
 30
Other income(9) (1) (6)
Interest charges and financing costs173
 149
 128
Total expenses and other deductions187
 172
 152
Income before income taxes1,318
 1,221
 1,111
Income tax benefit(54) (40) (37)
Net income$1,372
 $1,261
 $1,148
      
Other Comprehensive Income     
Pension and retiree medical benefits, net of tax of $1, $1 and $3, respectively$3
 $3
 $4
Derivative instruments, net of tax of $(7), $(1) and $2, respectively(20) (2) 3
Other comprehensive income (loss)(17) 1
 7
Comprehensive income$1,355
 $1,262
 $1,155
      
Weighted average common shares outstanding:     
Basic519
 511
 509
Diluted520
 511
 509
Earnings per average common share:     
Basic$2.64
 $2.47
 $2.26
Diluted2.64
 2.47
 2.25
See Notes to Condensed Financial Statements

XCEL ENERGY INC.
XCEL ENERGY INC.
CONDENSED STATEMENTS OF CASH FLOWS
(amounts in millions)
 Year Ended Dec. 31
 2019 2018 2017
Operating activities     
Net cash provided by operating activities$1,389
 $1,210
 $1,208
Investing activities     
Capital contributions to subsidiaries(1,594) (809) (849)
Investments in the utility money pool(1,054) (2,578) (1,258)
Return of investments in the utility money pool1,093
 2,493
 1,173
Net cash used in investing activities(1,555) (894) (934)
Financing activities     
Proceeds from (repayment of) short-term borrowings, net12
 (295) 715
Proceeds from issuance of long-term debt1,120
 492
 —
Repayment of long-term debt(550) —
 (250)
Proceeds from issuance of common stock458
 230
 —
Repurchase of common stock—
 (1) (3)
Dividends paid(791) (730) (721)
Other(14) (12) (14)
Net cash (used in) provided by financing activities235
 (316) (273)
Net change in cash and cash equivalents69
 —
 1
Cash and cash equivalents at beginning of period1
 1
 —
Cash and cash equivalents at end of period$70
 $1
 $1
See Notes to Condensed Financial Statements

CONDENSED BALANCE SHEETS
(amounts in millions)
Dec. 31
20212020
Assets
Cash and cash equivalents$1 $14 
Accounts receivable from subsidiaries430 424 
Other current assets6 6 
Total current assets437 444 
Investment in subsidiaries21,167 19,102 
Other assets71 40 
Total other assets21,238 19,142 
Total assets$21,675 $19,586 
Liabilities and Equity
Current portion of long-term debt— 400 
Dividends payable249 231 
Short-term debt638 — 
Other current liabilities29 21 
Total current liabilities916 652 
Other liabilities10 17 
Total other liabilities10 17 
Commitments and contingencies
Capitalization
Long-term debt5,137 4,342 
Common stockholders' equity15,612 14,575 
Total capitalization20,749 18,917 
Total liabilities and equity$21,675 $19,586 
See Notes to Condensed Financial Statements

XCEL ENERGY INC.
CONDENSED BALANCE SHEETS
(amounts in millions)
 Dec. 31
 2019 2018
Assets   
Cash and cash equivalents$70
 $1
Accounts receivable from subsidiaries370
 309
Other current assets12
 1
Total current assets452
 311
Investment in subsidiaries17,443
 15,965
Other assets60
 44
Total other assets17,503
 16,009
Total assets$17,955
 $16,320
Liabilities and Equity   
Dividends payable212
 195
Short-term debt500
 488
Other current liabilities33
 10
Total current liabilities745
 693
Other liabilities23
 32
Total other liabilities23
 32
Commitments and contingencies

 

Capitalization   
Long-term debt3,948
 3,373
Common stockholders’ equity13,239
 12,222
Total capitalization17,187
 15,595
Total liabilities and equity$17,955
 $16,320
See Notes to Condensed Financial Statements

Notes to Condensed Financial Statements
Incorporated by reference are Xcel Energy’s consolidated statements of common stockholders’ equity and other comprehensive income in Part II, Item 8.
Basis of Presentation — The condensed financial information of Xcel Energy Inc. is presented to comply with Rule 12-04 of Regulation S-X. Xcel Energy Inc.’s investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded in the balance sheets. The income from operations of the subsidiaries is reported on a net basis as equity in income of subsidiaries.
As a holding company with no business operations, Xcel Energy Inc.’s assets consist primarily of investments in its utility subsidiaries. Xcel Energy Inc.’s material cash inflows are only from dividends and other payments received from its utility subsidiaries and the proceeds raised from the sale of debt and equity securities. The ability of its utility subsidiaries to make dividend and other payments is subject to the availability of funds after taking into account their respective funding requirements, the terms of their respective indebtedness, the regulations of the FERC under the Federal Power Act, and applicable state laws. Management does not expect maintaining these requirements to have an impact on Xcel Energy Inc.’s ability to pay dividends at the current level in the foreseeable future. Each of its utility subsidiaries, however, is legally distinct and has no obligation, contingent or otherwise, to make funds available to Xcel Energy Inc.

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Guarantees and Indemnifications
Xcel Energy Inc. provides guarantees and bond indemnities under specified agreements or transactions, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. limit the exposure to a maximum stated amount. As of Dec. 31, 20192021 and 2018,2020, Xcel Energy Inc. had no assets held as collateral related to guarantees, bond indemnities and indemnification agreements.
Guarantees and bond indemnities issued and outstanding as of Dec. 31, 2019:2021:
(Millions of Dollars) Guarantor 
Guarantee
Amount
 
Current
Exposure
 
Triggering
Event
Guarantee of loan for Hiawatha Collegiate High School (a)
 Xcel Energy Inc. $1.0
 —
 
(c) 
Guarantee performance and payment of surety bonds for Xcel Energy Inc.’s utility subsidiaries (b)
 Xcel Energy Inc. 60.4
 
(e) 
 
(d) 

(a)
The term(Millions of this guarantee expires the earlier of 2024 or full repayment of the loan.Dollars)
GuarantorGuarantee
Amount		Current
Exposure		Triggering
Event
(b)Guarantee of loan for Hiawatha Collegiate High School(a)
The surety bonds primarily relate to workers compensation benefits and utility projects. The workers compensation bonds are renewed annually and the project based bonds expire in conjunction with the completion of the related projects.
Xcel Energy Inc.$1 — (c)
(c)
Nonperformance and/or nonpayment.
(d)
Per the indemnity agreement betweenGuarantee performance and payment of surety bonds for Xcel Energy Inc. and the various surety companies, surety companies have the discretion to demand that collateral be posted.
’s utility subsidiaries(e)(b)
Due to the magnitude of projects associated with the surety bonds, the total current exposure of this indemnification cannot be determined. Xcel Energy Inc. believes the exposure to be significantly less than the total amount of the outstanding bonds.59 (e)(d)
(a)The term of this guarantee expires the earlier of 2024 or full repayment of the loan.
(b)The surety bonds primarily relate to workers compensation benefits and utility projects. The workers compensation bonds are renewed annually and the project based bonds expire in conjunction with the completion of the related projects.
(c)Nonperformance and/or nonpayment.
(d)Per the indemnity agreement between Xcel Energy Inc. and the various surety companies, surety companies have the discretion to demand that collateral be posted.
(e)Due to the magnitude of projects associated with the surety bonds, the total current exposure of this indemnification cannot be determined. Xcel Energy Inc. believes the exposure to be significantly less than the total amount of the outstanding bonds.
Indemnification Agreements
Xcel Energy Inc. provides indemnifications through contracts entered into in the normal course of business. Indemnifications are primarily against adverse litigation outcomes in connection with underwriting agreements, breaches of representations and warranties, including corporate existence, transaction authorization and certain income tax matters. Obligations under these agreements may be limited in terms of duration or amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.
Related Party Transactions — Xcel Energy Inc. presents related party receivables net of payables. Accounts receivable and payablenet of payables with affiliates at Dec. 31:
  2019 2018
(Millions of Dollars) Accounts Receivable Accounts Payable Accounts Receivable Accounts Payable
NSP-Minnesota $60
 $—
 $117
 $—
NSP-Wisconsin 17
 —
 3
 —
PSCo 78
 —
 29
 —
SPS 47
 —
 39
 —
Xcel Energy Services Inc. 112
 —
 96
 —
Xcel Energy Ventures Inc. 25
 —
 13
 —
Other subsidiaries of Xcel Energy Inc. 31
 —
 12
 —
  $370
 $—
 $309
 $—

(Millions of Dollars)20212020
NSP-Minnesota$104 $81 
NSP-Wisconsin25 9 
PSCo91 98 
SPS58 55 
Xcel Energy Services Inc.125 159 
Other subsidiaries of Xcel Energy Inc.27 22 
$430 $424 
Dividends — Cash dividends paid to Xcel Energy Inc. by its subsidiaries were $2,987$1,344 million, $1,097$2,527 million and $1,063$2,987 million for the years ended Dec. 31, 2019, 20182021, 2020 and 2017,2019, respectively. These cash receipts are included in operating cash flows of the condensed statements of cash flows.
Money Pool — FERC approval was received to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc.
Money pool lending for Xcel Energy Inc.:
(Amounts in Millions, Except Interest Rates)Three Months Ended Dec. 31, 2021
Loan outstanding at period end$— 
Average loan outstanding— 
Maximum loan outstanding— 
Weighted average interest rate, computed on a daily basisN/A
Weighted average interest rate at end of periodN/A
Money pool interest income$— 
(Amounts in Millions, Except Interest Rates) Three Months Ended Dec. 31, 2019
Loan outstanding at period end $39
Average loan outstanding 35
Maximum loan outstanding 125
Weighted average interest rate, computed on a daily basis 1.67%
Weighted average interest rate at end of period 1.63%
Money pool interest income 1.47%
(Amounts in Millions, Except Interest Rates) 
Year Ended
Dec. 31, 2019
 
Year Ended
Dec. 31, 2018
 Year Ended
Dec. 31, 2017
Loan outstanding at period end $39
 $—
 $85
Average loan outstanding 47
 71
 38
Maximum loan outstanding 250
 243
 226
Weighted average interest rate, computed on a daily basis 2.15% 1.95% 1.13%
Weighted average interest rate at end of period 1.63% N/A
 1.18
Money pool interest income $1.0
 $1.4
 $0.4

(Amounts in Millions, Except Interest Rates)Year Ended Dec. 31, 2021Year Ended Dec. 31, 2020Year Ended Dec. 31, 2019
Loan outstanding at period end$— $57 $39 
Average loan outstanding16 104 47 
Maximum loan outstanding439 350 250 
Weighted average interest rate, computed on a daily basis0.08 %0.60 %2.15 %
Weighted average interest rate at end of periodN/A0.07 %1.63 
Money pool interest income$— $1 $1 
See notes to the consolidated financial statements in Part II, Item 8.
SCHEDULE II
Xcel Energy Inc. and Subsidiaries Valuation and Qualifying Accounts Years Ended Dec. 31
Allowance for bad debtsNOL and tax credit valuation allowances
(Millions of Dollars)202120202019202120202019
Balance at Jan. 1$79 $55 $55 $64 $67 $79 
Additions charged to costs and expenses60 60 42 5 6 9 
Additions charged to other accounts14 (a)12 (a)16 (a)— — — 
Deductions from reserves(47)(b)(48)(b)(58)(b)(5)(d)(9)(c)(21)(d)
Balance at Dec. 31$106 $79 $55 $64 $64 $67 
  Allowance for bad debts NOL and tax credit valuation allowances
(Millions of Dollars) 2019 2018 2017 2019 2018 2017 
Balance at Jan. 1 $55
 $52
 $51
 $79
 $77
 $58
 
Additions charged to costs and expenses 42
 42
 39
 9
 7
 9
 
Additions charged to other accounts 16
(a) 
11
(a) 
10
(a) 
—

—

22
(c) 
Deductions from reserves (58)
(b) 
(50)
(b) 
(48)
(b) 
(21)
(e) 
(5)
(e) 
(12)
(d) 
Balance at Dec. 31 $55
 $55
 $52
 $67
 $79
 $77
 

(a)Recovery of amounts previously written-off.
(b)Deductions related primarily to bad debt write-offs.
(c)Primarily the reduction of valuation allowances for North Dakota ITC, net of federal income tax benefit, that is offset to a regulatory liability forecasted to be used prior to expiration along with valuation allowances that expired.
(d)Primarily reductions to valuation allowances due to additional NOLs and tax credits forecasted to be used prior to expiration.
(a)
Recovery of amounts previously written off.
(b)
Deductions related primarily to bad debt write-offs.
(c)
Accrual of valuation allowances for North Dakota ITC, net of federal income tax benefit, that is offset to a regulatory liability and includes $14 million expense related to the revaluation of federal benefit as a result of the TCJA.
(d)
Primarily the reductions to valuation allowances for North Dakota ITC carryforwards, net of federal benefit, primarily due to a consolidated adjustment to the regulatory liability accrual referenced above; the change includes $4 million of reduced expense related to the revaluation of federal benefit as a result of TCJA.
(e)
Primarily the reductions to valuation allowances due to additional NOLs and tax credits now forecasted to be used prior to expiration.
ITEM 16 — FORM 10-K SUMMARY
None.
88

Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned thereunto duly authorized.
XCEL ENERGY INC.
Feb. 23, 2022By:XCEL ENERGY INC./s/ BRIAN J. VAN ABEL
Brian J. Van Abel
Feb. 21, 2020By:/s/ ROBERT C. FRENZEL
Robert C. Frenzel
Executive Vice President, Chief Financial Officer
(Principal Financial Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the date indicated above.
/s/ ROBERT C. FRENZELChairman, President, Chief Executive Officer and Director
Robert C. Frenzel(Principal Executive Officer)
/s/ BRIAN J. VAN ABELExecutive Vice President, Chief Financial Officer
Brian J. Van Abel(Principal Financial Officer)
/s/ JEFFREY S. SAVAGESenior Vice President, Controller
Jeffrey S. Savage(Principal Accounting Officer)
*Director
Lynn Casey
*/s/ BEN FOWKEChairman, President, Chief Executive Officer and Director
Ben FowkeNetha N. Johnson(Principal Executive Officer)
*/s/ ROBERT C. FRENZELExecutive Vice President, Chief Financial OfficerDirector
Robert C. FrenzelPatricia L. Kampling(Principal Financial Officer)
*/s/ JEFFREY S. SAVAGESenior Vice President, ControllerDirector
Jeffrey S. SavageGeorge J. Kehl(Principal Accounting Officer)
*Director
Lynn Casey
*Director
Richard K. Davis
*Director
Richard T. O’Brien
*Director
David K. OwensCharles Pardee
*Director
Christopher J. Policinski
*Director
James Prokopanko
*Director
A. Patricia Sampson
*Director
James J. Sheppard
*Director
David A. Westerlund
*Director
Kim Williams
*Director
Timothy V. Wolf
*Director
Daniel Yohannes
*By:/s/ ROBERT C. FRENZELBRIAN J. VAN ABELAttorney-in-Fact
Robert C. FrenzelBrian J. Van Abel

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