0000072903us-gaap:OtherInvestmentsMemberus-gaap:FairValueInputsLevel1Memberus-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember2020-12-31XCEL 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, 20202021 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. ☐
IndicateIndicate 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 30, 2020,2021, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $32,825,311,125.$35,463,594,471.
As of Feb. 11, 2021,17, 2022, there were 537,648,833544,213,730 shares of common stock outstanding, $2.50 par value.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive Proxy Statement for its 20212022 Annual Meeting of Shareholders are incorporated by reference into Part III of this Form 10-K.
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PART I
Item 1 —
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Item 1B —
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PART II
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Item 6 —
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Item 7A —
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Item 8 —
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Item 9 —
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Item 9A —
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Item 9B —
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Item 9C —
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PART III
Item 10 —
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Item 11 —
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Item 12 —
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PART IV
Item 15 —
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Item 16 —
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PART I
ITEM 1 — BUSINESS
Definitions of Abbreviations
Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
Capital 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. CircuitUnited 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 CircuitUnited States Court of Appeals for the Fifth Circuit
IRSInternal Revenue Service
Minnesota District CourtU.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
PHMSAPipeline and Hazardous Materials Safety Administration
PSCWPublic Service Commission of Wisconsin
PUCTPublic Utility Commission of Texas
SDPUCSouth Dakota Public Utilities Commission
SECSecurities and Exchange Commission
TCEQTexas Commission on Environmental Quality
Electric, Purchased Gas and Resource Adjustment Clauses
CEPAColorado Energy Plan Adjustment
CIPConservation improvement program
DCRFDistribution cost recovery factor
DSMDemand side management
DSMCADSM cost adjustment
ECARetail electric commodity adjustment
EECRFEnergy efficiency cost recovery factor
EIREnvironmental improvement rider
FCAFuel clause adjustment
FPPCACFuel and purchased power cost adjustment clause
GCAGas cost adjustment
GUICGas utility infrastructure cost rider
PCCAPurchased capacity cost adjustment
PCRFPower cost recovery factor
PGAPurchased gas adjustment
PSIAPipeline system integrity adjustment
RDFRenewable development fund
RERRenewable energy rider
RESRenewable energy standard
RESARES adjustment
SCASteam cost adjustment
SEPState energy policy rider
TCATransmission cost adjustment
TCRTransmission cost recovery adjustment
TCRFTransmission cost recovery factor
WCAWind cost adjustment
Other
ADITAccumulated deferred income taxes
AFUDCAllowance for funds used during construction
ALLETEALJALLETE, Inc.Administrative Law Judge
AROAsset retirement obligation
ASCFASB Accounting Standards Codification
ASUATMFASB Accounting Standards UpdateAt-the-market
BARTBest available retrofit technology
BoulderCity of Boulder, CO
C&ICommercial and Industrial
CAGRCompoundCorporate annual growth rate
CACJAClean Air Clean Jobs Act
CapX2020Alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort
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
CIGColorado Interstate Gas Company, LLC
COEOColorado Energy Office
CONCertificate of Need
COVID-19Novel coronavirus
CUBCitizens Utility Board
CWAClean Water Act
CWIPConstruction work in progress
D.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
DRIPDividend Reinvestment Program
EEIEdison Electric Institute
EIPEnergy Impact Partners
ELGEffluent limitations guidelines
EMANIEuropean Mutual Association for Nuclear Insurance
EPSEarnings per share
ESGEnvironmental, Social and Governance
ETREffective tax rate
EVsElectric Vehicles
FASBFinancial Accounting Standards Board
Fifth CircuitUnited States Court of Appeals for the Fifth Circuit
FTRFinancial transmission right
GAAPGenerally accepted accounting principles
GEGeneral Electric
GHGGreenhouse gas
HDDHeating degree-days
IMIntegrated market
INPOInstitute of Nuclear Power Operations
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IPCCIntergovernmental Panel on Climate Change
IPPIndependent power producing entity
IRPISOIntegrated Resource PlanIndependent System Operator
ITCInvestment Tax Credit
JOALP&LJoint operating agreement
LSP TransmissionLSP Transmission Holdings, LLC
MDLMulti-district litigationLubbock Power & Light
MECMankato Energy Center
MGPManufactured gas plant
MISOMidcontinent Independent System Operator, Inc.
Moody’sMoody’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.
NOLNet operating loss
NOPRNotice of proposed rulemaking
O&MOperating and maintenance
OAGMinnesota Office of the Attorney General
OATTOpen Access Transmission Tariff
PFASPer- and PolyFluoroAlkyl Substances
PIPrairie Island nuclear generating plant
Post-65Post-Medicare
PPAPurchased power agreement
Pre-65Pre-Medicare
PTCProduction tax credit
RECRenewable energy credit
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ROEReturn on equity
ROFRRight-of-first-refusal
ROURight-of-use
RPSRenewable portfolio standards
RTORegional Transmission Organization
S&PStandard & Poor’s Global Ratings
SERPSupplemental executive retirement plan
SMMPASouthern Minnesota Municipal Power Agency
SO2
Sulfur dioxide
SPPSouthwest Power Pool, Inc.
TCEHTexas 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
TSRTotal shareholder return
VaRValue at Risk
VIEVariable interest entity
WOTUSWaters of the U.S.
Measurements
BcfBillion cubic feet
KVKilovolts
KWhKilowatt hours
MMBtuMillion British thermal units
MWMegawatts
MWhMegawatt hours

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. 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 2021those relating to 2022 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future bad debt expense,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 expectationsintentions 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, 20202021 (including risk factors listed from time to time by Xcel Energy Inc. in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K 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;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; 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 ContentsContents
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). Xcel 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. Xcel Energy’s nonregulated subsidiaries include Eloigne, Capital Services, Venture Holdings and Nicollet Project Holdings.
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 Utility Subsidiaries’ Service Territory
xel-20211231_g3.jpg
Electric customers3.7 million
Natural gas customers2.1 million
Total assets$5457.9 billion
Electric generating capacity20,14020,653 MW
Natural gas storage capacity53.4 Bcf
Electric transmission lines (conductor miles)110,353111,434 miles
Electric distribution lines (conductor miles)208,586210,470 miles
Natural gas transmission lines2,1722,293 miles
Natural gas distribution lines35,93636,510 miles
Vision, Mission and Values
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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:
xel-20201231_g5.jpg
LEAD 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.
We 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.
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Rooted in a culture of compliance and ethical conduct, our decisions and actions are guided by our Code of Conduct and our four values:
ConnectedCommittedSafeTrustworthy
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.
Our values, culture and Code of Conduct serve as the foundation upon which Xcel Energy’s Board of Directors, employees, contractors and suppliers approach their work in delivering on our three strategic priorities.
Lead the Clean Energy Transition
For more than a decade, Xcel Energy has proactively managed the risk of climate change and respondedworked to meet increasing customer demand for renewablecleaner energy.
Xcel Energy was the first major U.S. utility to establish a carbon-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 purchased power. A lead author for the 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 also 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 carbon emissions from generation serving customers by 51% froman estimated 50% (from 2005 to 2020levels) and areremain on track to reach 60% renewable generation by 2030.
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Our recently announced generation transition plans include:
•Adding economic wind and solar resources.
•Limiting coal generation through seasonal dispatch of coal facilities where possible and early retirement of coal plants (e.g., Hayden and Craig), including fully exiting coal in the upper Midwest by 2030 (e.g., Sherco).
•Using natural gas as a means to ensure system reliability.
•Extending the life of our Monticello nuclear plant.
•Converting Harrington, our coal plant in Texas, to natural gas.
•A proposal to close the Hayden coal plant, retiring Unit 2 by the end of 2027 and Unit 1 in 2028.
•Retiring Craig coal plant with Unit 1 closing in 2025 and Unit 2 closing in 2028.
Our March 2021 Colorado resource plan filing will outline a range of options for us to achieve 80% carbon reduction by 2030.
Other notable environmental improvements include:
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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 state, including:next decade, and expects to be coal-free by 2034.
Colorado resource plan — settlement pending CPUC approval
•Proposed plans for our remaining87% carbon reduction by 2030 and full coal units (approximately 1,200 MW), such as early retirements and natural gas conversions.exit by 2034.
•Additional renewables~3,900 MW of wind and solar additions.
•~1,700 MW of flexible resources and storage.
•Transmission expansion.~1,200 MW of distributed solar generation.
We are confident we can achieve our 80% interimMinnesota resource plan — approved by MPUC
•85% carbon reduction goal with today’s technology.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 carbon-freeMexico
•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 plan to limit coal usage through dispatching units seasonally where possible. Natural gas and other dispatchable technologiesresources 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 orderColorado will provide over 560 miles of transmission lines and enable nearly 5,500 MW of new renewables, including access to achievesome of the remaining 20% carbon reduction. Reliability, customer affordability and innovation remain paramount to a successful transition.
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.
Xcel Energy’sOur clean energy leadership extends toencompasses our natural gas distribution systembusiness as well. In 2021, we workcommitted to keep our methanereduce GHG emissions rate below 0.2%. Our plans include the following:by 25% by 2030 from 2020 levels and deliver net-zero natural gas service by 2050, including customer use.
Plans include:
•Working with upstreamInfluencing suppliers on reducing- pursue certified low/no net emissions on their system.supply.
•Reducing methane emissions from our own operations.Operating the cleanest possible system – incorporate clean fuels.
•Designing programs thatOffering customer options – encourage customer conservation and electrification, where beneficial.
Xcel Energy’s leadership also extends beyond our electric and gas businesses to other parts of the economy. In addition to transitioning our own generation fleet, we are 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 avoidance of roughly 5 million tons of CO2 emissions annually.
Enhance the Customer Experience
Xcel Energy is committed to providing programs that customers want and value. We continue to expandhas a comprehensive suite of renewable offerings and promote cost savings and conservation programs in which we have invested over $2 billion in the past decade.
Xcel Energy isthat provide customers with clean energy options and help keep their bills low. We are also transforming and expanding our electric grid to accommodate increased levels of renewablesload growth, renewable energy and distributed energy resourcesresources.
In 2021, Xcel Energy installed over 300,000 smart meters and continuesplans to offer customers directly sourced renewable energy solutions. We areinstall more than one million in 2022. Xcel Energy also working to develop newlaunched 12 EV programs for C&Iresidential and commercial customers, who desire higher than standard service reliability, with the goal beingreceived approval of our New Mexico plan, and continued to make it both easy and affordableprepare for business customers to meet their resiliency needs.
Additionally, we have partnered with policymakers, state agencies and innovative partners to develop nation-leading electric vehicle solutions for our customers. Our electric vehicle plans include residential, fleet and public charging offerings. In 2020, our residential, flat-fee subscription service pilot won Public Utility Fortnightly’s Smartest Transportation Electrification Project award. Xcel Energy has full or pilot electric vehicle programs underway in Minnesota, Colorado and Wisconsin, including our $110 million, three-year Colorado plan which was approved in December 2020.
In 2020, we set an ambitious goal to power 1.5 million electric vehiclesincreased levels of EV adoption across our service territory by 2030,states.
For our local communities, we initiated 20 economic development projects in 2021, which is estimatedare projected to save customerslead to over $1 billion in fueling costscapital investments and cut carbon emissions by nearly 5 million tons annually by 2030.5,000 jobs. Additionally, over 60% of our supply chain spend was local.
Keep Bills Low
AffordabilityCustomer affordability is foundationalcritical to our strategy. Our goal issuccessful strategy execution and we are working 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 residential bills relativelyO&M expenses flat since 2013.2014, 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 states benefit from stronggeographic advantages in wind and solar also enable customer savings, which we call our “Steel for Fuel” strategy. High capacity factors. This geographic advantage,factors, coupled with renewable tax credits and avoided fuel costs, enablesenable Xcel Energy to increase its investment inadd renewables while saving customers money. We call this our “Steel for Fuel” strategy. From 2017 to 2020,To date, we added nearly 3,000 MW ofhave delivered more than $1.8 billion in customer savings by adding owned wind to our system while delivering approximately $430 millionsystem.
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 to our customers.
Xcel Energy continues to control O&M expense without compromising reliability or safety. Since 2014, total O&M has remained flat and we expect annual growth to remain below 1% through 2025 as declines in base O&M offset(equivalent cost per gallon for fueling with electricity vs. gasoline) of approximately $100 million of incremental wind O&M. We are continuing to prudently invest in appropriate areas and remain committed to taking costs out of the business through ongoing improvements in processes and technology.$1 billion by 2030.
Deliver a Competitive Total Return to Investors and Maintain Strong Investment Grade Credit Rating
Successful strategy execution, of our strategy, along with our disciplined approach to growth, investments, operations and management of environmental, social and corporate governance issues, positions Xcel Energyus to continue delivering a competitive TSR.
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We have consistently achieved our financial objectives, meeting or exceeding our initial earnings guidance range for sixteen17 consecutive years and delivering dividend growth for seventeen18 consecutive years.
Over the past five years, GAAP and ongoing earnings have grown 5.6% and 6.1%, respectively,by 6% annually since 2005 and our annual dividend grew 6.3% annually from 2013-2020.growth 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 Leadership
Sustainability is embedded in Xcel Energy’s strategy and our values:
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We are retiring coal plants, adding renewables, exploring new technologies and helping to electrify other sectors, while keeping customer bills low. Xcel Energy has demonstrated leadership in mitigating climate, operational and financial risks, while remaining committed to customers, employees and communities.
EnvironmentalHuman Capital
Xcel Energy wasemployees are the first major U.S. utilitydriving force behind our Company’s success. Our strategic, data-driven approach to establish a carbon-free vision, targeting 100% carbon-free electricity by 2050workforce planning helps ensure we will continue to have the skills and an 80% carbon reduction by 2030 (from 2005 levels). Our planscapabilities required to achieve 80% carbon reductionmeet the evolving needs of our business, customers and communities. We are aligned with targetsalso deeply committed to diversity, equity, human rights and safety.
Safety
Continuously elevating the quality and safety of the Paris Accord, as validated byworkplace is a lead author for the Intergovernmental Panel on Climate Change.
Xcel Energy has provided a voluntary, third-party verified annual GHG disclosure since 2005, longer than any other U.S. utility.top priority. We are considered a founding member of The Climate Registry and a supporter of the Task Force on Climate-Related Financial Disclosures. We have been the number one provider of wind to customersbenchmark company for 12 of the past 15 years. Our wind capacity is expected to reach 11,000 MW by the end of 2021, including nearly 4,500 MW of owned wind.
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As Xcel Energy transitions to cleaner sources, we expect to achieve a 70% reduction in water consumed in electric generation by 2030 (from 2005 levels). Through 2020, we reduced our water consumption 34% (from 2005 levels).
Social
Community
We work to foster economic sustainability and continued affordability by partnering with communities, policymakers and customers to build facilities, foster job growth and attract new businesses. In 2020, Xcel Energy completed 20 economic development projects across our service territory. Additionally, 71% of Xcel Energy’s supply chain spend was local.
In addition to our annual giving, in 2020 Xcel Energy further supported our communities by committing the net gain of nearly $20 million from our Mankato plant sale to short and long-term corporate giving.
We work to mitigate the impacts of early plant retirements on our employees and community, consistent with our Principles for a Responsible Transition. We provide advanced notice, offer retraining and relocation opportunities and have had no layoffs as a result of plant retirements. We also seek to make investments in the communities in which our coal plants are being shut down to offset the economic impact.
Safety
Safety is embedded in our values and governance practices, and Xcel Energy isAlways approach, focused on preventingeliminating life-altering injuries.injuries through a trusted, transparent culture and the use of critical controls. All employees have “stop work authority” and are expected to keep each other, our customers and the public safe. Through our Safety Always approach, employeesEmployees are encouraged to speak up, share experiences and learn from events to help protect themselves, their coworkers and the public.
Human Capital ManagementThe 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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Benefits
Xcel Energy’s success depends onEnergy 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 actively implement programs to attract, hire, developengage and retain skilled employees. Oura talented and diverse workforce, while reinforcing and rewarding strong performance.
Diversity, Equity, Inclusion and Human Rights
We aim to create an inclusive culture where employees are treated equitably, and diversity is not only accepted but celebrated. This starts with our Board of Directors, of which eight members were elected in the past five years.
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The Board of Directors oversees our workforce strategy, is designed to put the best talent in place, create a culture that motivates employees to lead the way in achieving our clean energy goalsincluding diversity and deliver an exceptional customer experience.
inclusion initiatives. In 2021, Xcel Energy has implemented a strategic, data-driven approachadded an incentive-based metric focused on diverse interview panels, executive sponsorship and employee feedback on inclusion in the workplace. A total of 70% of annual incentive pay was tied to workforcesafety, system reliability and succession planning, which includes best practices in learningdiversity, equity and development. Additionally, Xcel Energy partnersinclusion metrics.
In 2021, nearly all offers made had diverse hiring panels and executive sponsors consistently met with their employee counterparts at least monthly. We have also disclosed our Equal Employment Opportunity Employer Information Report (EEO-1).
Our CEO and senior executives lead by example, fostering an open and inclusive work environment through their interactions, communications and personal 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. Also,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 veterans is also a key focus, of our workforce strategy, with approximatelyroughly 10% of employees having served in the military. Xcel Energy offers its employees
To help foster a competitive benefits package which includes: performance-based compensation, healthcare benefits, recognition programs and an employee development program that emphasizes ongoing coaching.
Xcel Energy views diversity, equity and inclusion as an integral partculture of who we are, how we operate and how we see our future. We are committed to an inclusive culture where diversity is celebratedinclusivity, leaders and employees are treated equitably. Our senior leadership team leads by example, fostering an inclusive work environment, which recognizes the need for crucial conversationsreceive training on diversity. Additionally, Xcel Energy supports an inclusive environment by offering company-wide trainings on topics addressing microinequities and unconscious bias. We hold ourselves accountableThe Company hosts 11 business resource groups to support employee interests and measure our progress through corporate scorecard metrics that include, among other things, employee feedback in our engagement survey Inclusion Index.
obtain diverse perspectives when solving challenges and achieving goals.
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In 2020, Xcel Energy received the following recognitions: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.
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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, throughout our operations, consistent with U.S. human rights laws and the general principles set forth in the International Labour Organization Conventions. Xcel Energy requires annual Code of Conduct training is required for all employees annually and members of the Board of Directors. Xcel Energy
The Company does not tolerate discrimination,Code violations of our Code of Conduct or other unacceptable behaviors. We expect and offer employees multiple avenues to raise concerns or report wrong-doing and do not permit any retaliation for doing so.
We respect employees’ freedom of association and their right to collectively organize. As of Dec. 31, 2020, Xcel Energy’s employees were as follows:
Employees Covered by Collective Bargaining AgreementsTotal Full-Time Employees
NSP-Minnesota2,033 3,144 
NSP-Wisconsin394 540 
PSCo1,882 2,378 
SPS769 1,141 
XES— 4,164 
Total5,078 11,367 
Our workforce demographics as of December 2020 were as follows:
FemaleEthnically Diverse
Board of Directors20%20%
CEO direct reports38%13%
Management22%10%
Employees23%16%
New hires33%22%
Interns (hired throughout 2020)33%28%














Governance
For decades, Xcel Energy has fostered a culture of compliance and ethical conduct. Our Code of Conduct serves as the foundation that all employees, contractors and the Board of Directors are expected to follow, along with corporate policies that establish rules and guidelines in areas such as safety, environmental leadership, diversity, community giving and political contributions.retaliation.
Xcel Energy has a diverse and qualified Board of Directors, with eight members elected withinrecently received the past five years.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
Accountability and Incentive
We consistently set aggressive goals and hold ourselves accountable to our customers, communities and investors. Xcel Energy instituted Board of Directors oversight of environmental performance in 2000 and was among the first U.S. utilities to tie carbon reduction directly to executive compensation over fifteen years ago.
In 2020, 60% of annual incentive pay was tied to safety and system reliability. In 2021, we added an incentive-based metric to reinforce our commitment to diversity and inclusion. Xcel Energy has clear Board of Directors committee oversight for safety and our human capital strategy, including diversity and inclusion initiatives.
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Utility Subsidiaries
NSP-Minnesota
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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$21.122.8 billion
Rate Base (estimated)$12.413.7 billion
ROE (net income / average stockholder's equity)9.20%8.45%
Electric generating capacity8,1378,628 MW
Gas storage capacity17.1 Bcf
Electric transmission lines (conductor miles)33,66034,155 miles
Electric distribution lines (conductor miles)80,50881,406 miles
Natural gas transmission lines8085 miles
Natural gas distribution lines10,62910,741 miles
NSP-Wisconsin
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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$2.93.1 billion
Rate Base (estimated)$1.82.0 billion
ROE (net income / average stockholder's equity)10.52%9.92%
Electric generating capacity548 MW
Gas storage capacity3.8 Bcf
Electric transmission lines (conductor miles)12,28812,409 miles
Electric distribution lines (conductor miles)27,61127,701 miles
Natural gas transmission lines3 miles
Natural gas distribution lines2,4922,526 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$20.422.0 billion
Rate Base (estimated)$13.314.0 billion
ROE (net income / average stockholder's equity)8.06%8.23%
Electric generating capacity6,2236,228 MW
Gas storage capacity32.5 Bcf
Electric transmission lines (conductor miles)24,38624,116 miles
Electric distribution lines (conductor miles)78,48378,712 miles
Natural gas transmission lines2,0582,174 miles
Natural gas distribution lines22,81523,243 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$8.99.3 billion
Rate Base (estimated)$5.46.4 billion
ROE (net income / average stockholder's equity)9.54%9.22%
Electric generating capacity5,2325,249 MW
Electric transmission lines (conductor miles)40,01940,754 miles
Electric distribution lines (conductor miles)21,98422,651 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 104,731115,474 (millions of KWh), 3.7 million customers and electric revenues of $9,802$11,205 (millions of dollars) for 2020.2021.
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Retail Sales/Revenue Statistics (a)
2020201920212020
KWh sales per retail customerKWh sales per retail customer23,910 24,712 KWh sales per retail customer23,968 23,910 
Revenue per retail customerRevenue per retail customer$2,199 $2,244 Revenue per retail customer$2,405 $2,199 
Residential revenue per KWhResidential revenue per KWh12.12 ¢11.97 ¢Residential revenue per KWh12.94 ¢12.12 ¢
Large C&I revenue per KWhLarge C&I revenue per KWh5.78 ¢5.96 ¢Large C&I revenue per KWh6.60 ¢5.78 ¢
Small C&I revenue per KWhSmall C&I revenue per KWh9.56 ¢9.43 ¢Small C&I revenue per KWh10.47 ¢9.56 ¢
Total retail revenue per KWhTotal retail revenue per KWh9.20 ¢9.08 ¢Total retail revenue per KWh10.03 ¢9.20 ¢
(a) See Note 6 to the consolidated financial statements for further information.
Owned and Purchased Energy Generation — 20202021
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Electric Energy Sources
Total electric energy generation by source (including energy market purchases) for the year ended Dec. 31, 2020:2021:
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* Distributed generation from the Solar*Rewards® program is not included (approximately 675666 million KWh for 2020)2021).
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Carbon-Free Energy
Xcel Energy’s carbon-free energy portfolio includes wind, nuclear, hydroelectric, biomass and solar power from both owned generation facilities and PPAs. Carbon-free percentages will vary year-over-year based on system additions, commodity costs, weather, system demand and transmission constraints.
See Item 2 — Properties for further information.
Carbon-free energy as a percentage of total energy for 2020:2021:
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* Includes biomass and hydroelectric.
Wind
Owned — Owned and operated wind farms with corresponding capacity:
20202019
Utility SubsidiaryUtility Subsidiary20212020
Utility SubsidiaryWind Farms
Capacity (a)
Wind Farms
Capacity (b)
Wind Farms
Capacity (MW) (a)
Wind Farms
Capacity (MW) (b)
NSP SystemNSP System111,540 MW71,079 MWNSP System142,031111,540
PSCoPSCo21,059 MW1582 MWPSCo21,05921,059
SPSSPS2967 MW1460 MWSPS29842967
TotalTotal153,566 MW92,121 MWTotal184,075153,566
(a) Summer 20202021 net dependable capacity.
(b) Summer 20192020 net dependable capacity.
PPAs — Number of PPAs with capacity range:
Utility SubsidiaryUtility Subsidiary20202019Utility Subsidiary20212020
PPAsRangePPAsRangePPAsRange (MW)PPAsRange (MW)
NSP SystemNSP System1291 MW — 206 MW1311 MW — 206 MWNSP System1281 — 2061291 — 206
PSCoPSCo1723 MW — 301 MW202 MW — 301 MWPSCo1723 — 3011723 — 301
SPSSPS181 MW — 250MW181 MW — 250 MWSPS171 — 250181 — 250
Capacity — Wind capacity:capacity (MW):
Utility SubsidiaryUtility Subsidiary20202019Utility Subsidiary20212020
NSP SystemNSP System3,348 MW2,767 MWNSP System3,9973,348
PSCoPSCo4,085 MW3,145 MWPSCo4,0854,085
SPSSPS2,535 MW2,027 MWSPS2,5482,535
Average Cost (Owned) — Average cost per MWh of wind energy from owned generation:
Utility SubsidiaryUtility Subsidiary20202019Utility Subsidiary20212020
NSP SystemNSP System$23 $35 NSP System$25 $23 
PSCoPSCo35 47 PSCo17 35 
SPSSPS17 — SPS17 17 


Average Cost (PPAs) — Average cost per MWh of wind energy under existing PPAs:
Utility SubsidiaryUtility Subsidiary20202019Utility Subsidiary20212020
NSP SystemNSP System$38 $41 NSP System$37 $38 
PSCoPSCo40 41 PSCo35 40 
SPSSPS26 25 SPS27 26 
Wind Development
Xcel Energy placed approximately 1,450500 MW of owned wind and approximately 700255 MW of PPAs into service during 2020:2021:
ProjectUtility SubsidiaryCapacity (MW)
Blazing Star 12NSP-Minnesota
200 MW (a)(b)
Crowned Ridge 2FreebornNSP-Minnesota
192 MW200 (a)(b)
Community Wind North
NSP-Minnesota
26 MW (a)(b)
JeffersMowerNSP-Minnesota
43 MW (a)(b)
Cheyenne RidgePSCo
477 MW (a)(b)
SagamoreSPS
507 MW91 (a)(b)
Various PPAsVarious
~700 MW255 (c)
(a) Summer 20202021 net dependable capacity.
(b) Values disclosed are the maximum generation levels for these wind units.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 1,4501,050 MW of owned wind under development or construction.being repowered. In addition, Xcel Energy expectswe expect to add approximately 450200 MW of planned PPAs.
Project
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.
Utility SubsidiaryCapacityEstimated Completion
Dakota RangeNSP-Minnesota300 MW2021
FreebornNSP-Minnesota200 MW2021
Blazing Star 2NSP-Minnesota200 MW2021
NoblesNSP-Minnesota200 MW2022
Pleasant ValleyNSP-Minnesota200 MW2024
Border WindsNSP-Minnesota150 MW2024
Grand MeadowNSP-Minnesota100 MW2023
MowerNSP-Minnesota99 MW2021
Various PPAsVarious~450 MW2021
Solar
Solar PPA(s):
TypeUtility SubsidiaryCapacity (MW)
Distributed GenerationNSP System899 MW994
Utility-ScaleNSP System268 MW
Distributed GenerationPSCo643 MW736
Utility-ScalePSCo306 MW562
Distributed GenerationSPS11 MW15
Utility-ScaleSPS190 MW192
Total2,317 MW2,767
Average Cost (PPAs) — Average cost per MWh of solar energy under existing PPAs:
Utility SubsidiaryUtility Subsidiary20202019Utility Subsidiary20212020
NSP SystemNSP System$90 $81 NSP System$90 $90 
PSCoPSCo89 89 PSCo67 89 
SPSSPS59 56 SPS61 59 


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Solar Development
In October 2020, Xcel Energy filed a request withJune 2021, the PSCW approved NSP-Wisconsin’s request to purchase athe 74 MW Western Mustang build-own-transfer solar facility for approximately $100 million solar array in Pierce County, WI. A PSCW decision is expected in the third quarter of 2021.million. Also, as part of the Minnesota Recovery and Relief Recovery docket, NSP-Minnesota proposed the addition ofto add 460 MW of solar facilities at the Sherco site with an expected $550 million incremental investment.investment of approximately $575 million. An MPUC decision is expected inby the second halfthird quarter of 2021.2022.
Additionally, Xcel Energy projectsPSCo placed approximately 3,500260 MW of solar through 2034 in our Minnesota resource plan and will be addressing solar energy within its upcoming Colorado resource plan.PPAs into service during 2021.
Nuclear
Xcel Energy has two nuclear plants with approximately 1,700 MW of total 20202021 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. Xcel Energy secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication to operate its nuclear plants. We use varying contract lengths as well as multiple producers for uranium concentrates, conversion services and enrichment services to minimize potential impacts caused by supply interruptions due to geographical and world political issues.
Nuclear Fuel Cost
Delivered cost per MMBtu of nuclear fuel consumed for owned electric generation and the percentage of total fuel requirements:
Utility SubsidiaryUtility SubsidiaryNuclearUtility SubsidiaryNuclear
NSP SystemNSP SystemCostPercentNSP SystemCostPercent
20212021$0.77 46 %
20202020$0.80 51 %20200.80 51 
20190.81 45 
Other Carbon-Free Energy
Xcel Energy’s other carbon-free energy portfolio includes hydro from owned generating facilities.
See Item 2 — Properties for further information.
Fossil Fuel Energy
Xcel Energy’s fossil fuel energy portfolio includes coal and natural gas power from both owned generating facilities and PPAs.
Coal
Xcel Energy owns and operates coal units with approximately 6,500 MW of total 20202021 net summer dependable capacity.
Approved and proposed early coal plant retirements:
Approved / Authorized
YearUtility SubsidiaryPlant UnitCapacity
2022PSCoComanche 1325 MW
2023NSP-MinnesotaSherco 2682 MW
2024SPS
Harrington(a)
1,018 MW
2025PSCoComanche 2335 MW
2025PSCoCraig 1
42 MW(b)
2026NSP-MinnesotaSherco 1680 MW
2028PSCoCraig 2
40 MW(b)
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)
(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
2027PSCoHayden 2
98 MW(a)
2028PSCoHayden 1
135 MW(b)
2028NSP-MinnesotaA.S. King511 MW
2030NSP-MinnesotaSherco 3
517 MW(c)
2032SPSTolk 1532 MW
2032SPSTolk 2535 MW
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.
(b)(c)Based on PSCo’s ownership of 76% of Unit 1.
(c)(d)Based on Xcel Energy’sPSCo’s ownership interest.of 67%.
Plans for our remaining Colorado coal fleet will be outlined when PSCo submits its 2021 resource plan, which is expected to be filed in March 2021.
Coal Fuel Cost
Delivered cost per MMBtu of coal consumed for owned electric generation and the percentage of fuel requirements:
Coal (a)
Coal (a)
Utility SubsidiaryUtility SubsidiaryCostPercentUtility SubsidiaryCostPercent
NSP SystemNSP SystemNSP System
20212021$1.60 39 %
20202020$1.97 31 %20201.97 31 
20192.02 36 
PSCoPSCoPSCo
202120211.43 62 
202020201.41 51 20201.41 51 
20191.45 55 
SPSSPSSPS
202120212.07 66 
202020202.28 40 20202.28 40 
20192.19 45 
(a)    Includes refuse-derived fuel and wood for the NSP System.
Natural Gas
Xcel Energy has 22 natural gas plants with approximately 7,900 MW of total 20202021 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 GasNatural Gas
Utility SubsidiaryUtility SubsidiaryCostPercentUtility SubsidiaryCostPercent
NSP SystemNSP SystemNSP System
2021 (a)
2021 (a)
$4.98 15 %
20202020$2.67 17 %20202.67 17 
20193.09 19 
PSCoPSCoPSCo
2021 (a)
2021 (a)
8.38 38 
202020203.01 49 20203.01 49 
20193.27 45 
SPSSPSSPS
2021 (a)
2021 (a)
6.72 34 
202020201.43 60 20201.43 60 
20191.14 55 

(a)


Reflective of Winter Storm Uri.
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Capacity and Demand
Uninterrupted system peak demand and occurrence date for the regulated utilities:
System Peak Demand (in MW)System Peak Demand (MW)
2020201920212020
NSP System
NSP System
8,571 July 88,774 July 19
NSP System
8,837 June 98,571 July 8
PSCoPSCo6,899 Aug. 177,111 July 19PSCo6,958 July 286,899 Aug. 17
SPSSPS4,195 July 144,261 Aug. 5SPS4,054 Aug. 94,195 July 14
Transmission
Transmission lines deliver electricity at higher voltagehigh voltages and over longerlong 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 20202021 include:
ProjectUtility SubsidiaryMilesSize
Maple River-Red RiverNSP-Minnesota4 115 KV
Glenwood DouglasNSP-Minnesota20 69 KV
Prentice to StructureNSP-Wisconsin8 115 KV
Lufkin to NaplesNSP-Wisconsin13 69 KV
Belgrade to IronwoodNSP-Wisconsin13 35 KV
Cornucopia to Bayfield Phase 2NSP-Wisconsin5 35 KV
Pawnee-Daniels ParkPSCo113 345 KV
Cheyenne RidgePSCo73 345 KV
TUCO-Yoakum Co.SPS107 345 KV
Eddy Co-KiowaSPS34 345 KV
Mustang-SeminoleSPS20 115 KV
Loving South-PhantomSPS21 115 KV
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 

Notable upcoming projects:
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
ProjectUtility SubsidiaryMilesSizeCompletion Date
Hibbing Taconite RelocationNSP-Minnesota3 500 KV2021
Huntley-WilmarthNSP-Minnesota50 345 KV2021
Helena Scott CountyNSP-Minnesota16 345 KV2021
Baytown to Long LakeNSP-Minnesota9 115 KV2022
Centerville to Lincoln CountyNSP-Minnesota14 69 KV2021
Turtle Lake AlmenaNSP-Wisconsin4 69 KV2021
Bayfield Second CircuitNSP-Wisconsin19 35 KV2022
Roadrunner-China DrawSPS41 345 KV2021
See Item 2 - Properties for further information.
Distribution
Distribution lines allow electricity to travel at lower voltages from substations directly to homes and businesses.customers. Xcel Energy has a vast distribution network, owning and operating approximately 210,000 conductor miles of distribution lines across our eight-state service territory, 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 five yearmulti-year project that started in 2016, Xcel Energy plans to invest approximately $1.8$1.7 billion implementing new network infrastructure, smart meters, advanced software, equipment sensors and related data analytics capabilities. To date, Xcel Energy has spent approximately $568 million on these investments.
These investmentsInvestments of this nature will further improve reliability and reduce outage restoration times for our customers, while at the same time enabling new options and opportunities for increased efficiency savings. The new capabilities will also enable integration of battery storage and other distributed energy resources into the grid, including electric vehicles.
See Item 2 - Properties for further information.


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Natural Gas Operations

Natural gas operations consist of purchase, transportation and distribution of natural gas to end-use residential, C&I and transport customers in NSP-Minnesota, NSP-Wisconsin and PSCo. Xcel Energy had natural gas deliveries of 444,340of 405,895 (thousands of MMBtu), 2.1 million customers and natural gas revenues of $1,636$2,132 (millions of dollars) for 2020.2021.
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Sales/Revenue Statistics (a)
2020201920212020
MMBtu sales per retail customerMMBtu sales per retail customer118.13 129.31 MMBtu sales per retail customer114 118 
Revenue per retail customerRevenue per retail customer$720.42 $851.94 Revenue per retail customer$917 $720 
Residential revenue per MMBtuResidential revenue per MMBtu6.64 7.14 Residential revenue per MMBtu8.61 6.64 
C&I revenue per MMBtuC&I revenue per MMBtu5.22 5.73 C&I revenue per MMBtu7.20 5.22 
Transportation and other revenue per MMBtuTransportation and other revenue per MMBtu0.67 0.57 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:
2020201920212020
Utility SubsidiaryUtility SubsidiaryMMBtuDateMMBtuDateUtility SubsidiaryMMBtu
Date (a)
MMBtuDate
NSP-MinnesotaNSP-Minnesota871,921 Jan. 16897,615 Feb. 25NSP-Minnesota899,133 Feb. 11871,921 Jan. 16
NSP-WisconsinNSP-Wisconsin150,320 Dec. 24166,009 Jan. 30NSP-Wisconsin167,656 Feb. 11150,320 Dec. 24
PSCoPSCo1,931,888 Feb. 42,139,420 March 3PSCo2,316,283 Feb. 141,931,888 Feb. 4
(a)Reflective of Winter Storm Uri.
Natural Gas Supply and Cost
Xcel Energy seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio, which increase flexibility, decrease interruption, and financial risks and economic customer rates. In addition, the utility subsidiaries conduct natural gas price hedging activities approved by their states’ commissions.
Average delivered cost per MMBtu of natural gas for regulated retail distribution:
Utility SubsidiaryUtility Subsidiary20202019Utility Subsidiary
2021 (a)
2020
NSP-MinnesotaNSP-Minnesota$3.32 $3.71 NSP-Minnesota$7.48 $3.32 
NSP-WisconsinNSP-Wisconsin3.08 3.49 NSP-Wisconsin7.11 3.08 
PSCoPSCo2.52 2.95 PSCo6.06 2.52 
(a)Reflective of Winter Storm Uri.
NSP-Minnesota, NSP-Wisconsin and PSCo have natural gas supply transportation and storage agreements that include obligations for purchase and/or delivery of specified volumes or to make payments in lieu of delivery.
General
General Economic Conditions
Economic conditions may have a material impact on Xcel Energy’s operating results. 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 our results of operations, future growth or ability to raise capital resulting from a sustained general slowdown in economic growth or a significant increase in interest rates.rates or inflation.
Seasonality
Demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, Xcel Energy’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.
Competition
Xcel Energy is subject to public policies that promote competition and development of energy markets. Xcel Energy’s industrial and large commercial customers have the ability to generate their own electricity. In addition, customers may have the option of substituting other fuels or relocating their facilities to a lower cost region.
Customers have the opportunity to supply their own power with distributed generation including solar generation and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them.

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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 utility 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 electric 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. Certain Xcel Energy activities require registrations, permits, licenses, inspections and approvals from these agencies.
Xcel Energy has received necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Our facilities strive to operate in compliance with applicable environmental standards and related monitoring and reporting requirements.
However, it is not possible to determine 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.
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Xcel Energy must comply with emission levels in Minnesota, Texas and Wisconsin that may require the purchase of emission allowances. The Denver North Front Range Non-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 environmental regulations to encourage use of clean energy technologies and regulate emissions of GHGs. We have undertaken numerous initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. Future environmental regulations may result in substantial costs.
In July 2019, the EPA adopted the Affordable Clean Energy rule, which requiredrequires states to develop plans by 2022 for GHG reductions from coal-fired power plants. In a Jan. 19,January 2021, decision, the U.S. Court of Appeals for the D.C. Circuit issued a decision vacating and remanding the Affordable Clean Energy rule. That decision if not successfully appealed or reconsidered, would allow the EPA to proceed with alternate regulation of coal-fired power plants, either revivingplants. However, the Clean Power Plan or proposing additional regulation. ItCourt of Appeals decision is too earlynow before the U.S. Supreme Court, where the Court is expected to predict an outcome, butrule on the nature and extent of the EPA’s GHG regulatory authority. If any new rules could require substantial additional investment, even in plants slated for retirement. Xcel Energy believes based on prior state commission practices,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 ensures 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.
Xcel Energy seeks to address climate change and potential climate change regulation through efforts to reduce its GHG emissions in a balanced, cost-effective manner.
In 2020,Emerging Environmental Regulation
New regulations and legislation are being considered to regulate PFAS in drinking water, water discharges, commercial products, wastes, and other areas. PFAS are man-made chemicals found in many consumer products that can persist and accumulate in the environment. These chemicals have received heightened attention from environmental regulators. Increased regulation of PFAS and other emerging contaminants at the federal, state, and local level could have a potential adverse effect on our operations but at this time, it is uncertain what impact, if any, there will be on our operations, financial condition or cash flows. Xcel Energy estimates that it reduced carbon emissions associated with electric generating resources, both ownedwill continue to monitor these regulatory developments and under PPAs, used to servetheir potential impact on its customers by approximately 51% from 2005 levels.operations.
Environmental Costs
Environmental costs include amounts for nuclear plant decommissioning and payments for storage of spent nuclear fuel, disposal of hazardous materials and waste, remediation of contaminated sites, monitoring of discharges to the environment and compliance with laws and permits with respect to emissions.
Costs charged to operating expenses for nuclear decommissioning, spent nuclear fuel disposal, environmental monitoring and remediation and disposal of hazardous materials and waste were approximately:
•$365 million in 2021.
•$400 million in 2020.
•$345 million in 2019.
•$335 million in 2018.19.
Average annual expense of approximately $465$425 million from 20212022 – 20252026 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 2020.
•$30 million in 2019.
•$50 million in 2018.
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.
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Information about our Executive Officers (a)
Name
Age (b)
Current and Recent PositionsTime in Position
Ben FowkeRobert C. Frenzel6251Chairman 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, Xcel Energy Inc.August 2011 — March 2020
Robert C. Frenzel50President and Chief Operating Officer, Xcel Energy Inc.March 2020 — PresentAugust 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)
5455Executive 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
Christopher B. ClarkPatricia Correa5448President and Director, NSP-MinnesotaJanuary 2015 — Present
Darla Figoli58ExecutiveSenior Vice President, Human Resources & Employee Services, Chief Human Resources Officer, Xcel Energy Inc.June 2020February 2022 — Present
Senior Vice President, Human Resources, & Employee Services, Chief Human Resources Officer, Xcel Energy Inc.Eaton Corporation, a power management companyMay 2018July 2019 — June 2020January 2022
Vice President, Human Resources, Eaton CorporationMarch 2016 — July 2019
Senior Vice President, Human Resources and Employee Services, Xcel Energy Inc.Director, Talent & Organization Development, Kellogg Company, a food manufacturing companyMayJuly 2015 — May 2018
David T. Hudson60President and Director, SPSJanuary 2015 — Present
Alice Jackson42President 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 — NovemberMarch 2016
Timothy O’Connor6162Executive Vice President, Chief Operations Officer, Xcel Energy Inc.August 2021 — Present
Executive Vice President, Chief Generation Officer, Xcel Energy Inc.March 2020 — PresentAugust 2021
Senior Vice President, Chief Nuclear Officer, Xcel Energy Services IncFebruary 2013 — March 2020
Frank Prager5859Senior Vice President, Strategy, Planning and External Affairs, Xcel Energy Inc.March 2020 — Present
Vice President, Policy and Federal Affairs, Xcel Energy Services Inc.January 2015 — March 2020
Amanda Rome4041Executive 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)
4950Senior Vice President, Controller, Xcel Energy Inc.January 2015 — Present
Mark E. Stoering60President and Director, NSP-WisconsinJanuary 2015 — Present
Brian J. Van Abel3940Executive Vice President, Chief Financial Officer, Xcel Energy Inc.March 2020 — Present
Senior Vice President, Finance and Corporate Development, Xcel Energy Services Inc.September 2018 — March 2020
Vice President, Treasurer, Xcel Energy Services Inc.July 2015 — September 2018
(a)(a) No family relationships exist between any of the executive officers or directors.
(b)Ages as of Feb. 17, 2021.23, 2022.
(c)In April 2014, Energy Future Holdings Corp., the majority of its subsidiaries, including TCEHTexas Competitive Energy Holdings the parent company of Luminant, filed a voluntary bankruptcy petition under Chapter 11 of the United States Bankruptcy Code. TCEHTexas 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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ITEM 1A — RISK FACTORS
Xcel Energy is subject to a variety of risks, many of which are beyond our control. Risks that may adversely affect the business, financial condition, results of operations or cash flows are described below. Although the risks are organized by heading, and each risk is described separately, many of the risks are interrelated. These risks should be carefully considered together with the other information set forth in this report and future reports that we file with the SEC. You should not interpret the disclosure of any risk factor to imply that the risk has not already materialized.
While we believe we have identified and discussed below the key risk factors affecting our business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant that may adversely affect our business, financial condition, results of operations or cash flows in the future.
Oversight of Risk and Related Processes
The Board of Directors is responsible for the oversight of material risk and maintaining an effective risk monitoring process. Management and the Board of Directors’ committees have responsibility for overseeing the identification and mitigation of key risks and reporting its assessments and activities to the full Board of Directors.
Xcel Energy maintains a robust compliance program and promotes a culture of compliance beginning with the tone at the top. The risk mitigation process includes adherence to our code of conduct and compliance policies, operation of formal risk management structures and overall business management. Xcel Energy further mitigates inherent risks through formal risk committees and corporate functions such as internal audit, and internal controls over financial reporting and legal.
Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Identification and risk analysis occurs formally through risk assessment conducted by senior management, the financial disclosure process, hazard risk procedures, internal audit and compliance with financial and operational controls.
Management also identifies and analyzes risk through the business planning process, development of goals and establishment of key performance indicators, including identification of barriers to implementing Xcel Energy’s strategy. The business planning process also identifies likelihood and mitigating factors to prevent the assumption of inappropriate risk to meet goals.
Management communicates regularly with the Board of Directors and key stakeholders regarding risk. Senior management presents and communicates a periodic risk assessment to the Board of Directors, providing information on the risks that management believes are material, including financial impact, timing, likelihood and mitigating factors. The Board of Directors regularly reviews management’s key risk assessments, which includes areas of existing and future macroeconomic, financial, operational, policy, environmental and security risks.
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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 significant change (e.g., increases in energy efficiency, wider adoption of distributed generation and shifts away from fossil fuel generation to renewable generation). Customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources, downward pressure on sales growth, and potentially stranded costs if we are not able to fully recover costs and investments.
Changing customer expectations and technologies are requiring significant investments in advanced grid infrastructure, which increases exposure to technology obsolescence. Additionally, evolving stakeholder preference for lower emissions from generation sources and end-uses, like heating, may put pressure on our ability to recover capital investments in natural gas generation and delivery.
The magnitude and timing of resource additions and changes in customer demand may not coincide with evolving customer preference for generation resources and end-uses, which introduces further uncertainty into long-term planning. Efforts to electrify the transportation and building sectors to reduce GHG emissions may result in higher electric demand and lower natural gas demand over time. Additionally, multipleHigher 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.
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TableOur products contain components that are globally sourced from suppliers who, in turn, source components from their suppliers. A shortage of Contentskey 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 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 controlsprograms 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. 
SpecializedIn 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. Xcel Energy’s business strategy is dependent on our abilityassets, which may pose additional difficulty for us as we work to recruit, retain and motivate employees. There is competition and a tightening market for skilled employees.employees in this climate. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.
Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.
We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance standards, progress payments, insurance requirements and security for performance. Poor vendor performance or contractor unavailability could impact ongoing operations, restoration operations, our reputation and could introduce financial risk or risks of fines.
Our employees, directors, third-party contractors, or suppliers may violate or be perceived to violate our Codes of Conduct, which could have an adverse effect on our reputation.
We are exposed to risk of employee or third-party contractor fraud or other misconduct. All employees and members of the Board of Directors are subject to comply with our Code of Conduct and are required to participate in annual training. Additionally, suppliers are subject to comply with our supplier Code of Conduct.
Xcel Energy does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. However, it is not always possible to identify and deter misconduct by employees and other third-parties, which may result in governmental investigations, other actions or lawsuits. If such actions are taken against us we may suffer loss of reputation and such actions could have a material effect on our financial condition, results of operations and cash flows.
Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.
NSP-Minnesota has two nuclear generation plants, PI and Monticello. Risks of nuclear generation include:
•Hazards associated with the use of radioactive material in energy production, including management, handling, storage and disposal.
•Limitations on insurance available to cover losses that may arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor.
•Technological and financial uncertainties related to the costs of decommissioning nuclear plants may cause our funding obligations to change.
The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities, including the ability to impose fines and/or shut down a unit until compliance is achieved. NRC safety requirements could necessitate substantial capital expenditures or an increase in operating expenses. In addition, the INPO reviews NSP-Minnesota’s nuclear operations. Compliance with the INPO’s recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.
If a nuclear incident did occur, it could have a material impact on our results of operations, financial condition or cash flows. Furthermore, non-compliance or the occurrence of a serious incident at other nuclear facilities could result in increased industry regulation, which may increase NSP-Minnesota’s compliance costs.
Financial Risks
Our profitability depends on the ability of our utility subsidiaries to recover their costs and changes in regulation may impair the ability of our utility subsidiaries to recover costs from their customers.
We are subject to comprehensive regulation by federal and state utility regulatory agencies, including siting and construction of facilities, customer service and the rates that we can charge customers.
The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services and 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 required by commissions and result in less than full recovery.
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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, use of historic test years, elimination of riders or interim rates, increasing depreciation lives, lower returns on equity, changes to equity ratios and impacts of tax policy may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.
Any credit ratings downgrade could lead to higher borrowing costs 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 if credit ratings fall below investment grade.
We are subject to capital market and interest rate risks.
Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital market disruption and financial market distress could prevent us from issuing short-term commercial paper, issuing new securities or cause us to issue securities with unfavorable terms and conditions, such as higher interest rates.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 economy and unemployment rates.
Credit risk also includes the risk that counterparties that owe us money or product will become insolvent and may breach their obligations. Should the counterparties fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and incur losses.
Xcel Energy may have direct credit exposure in our short-term wholesale and commodity trading activity to financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, (e.g., California Independent System Operator, SPP, PJM Interconnection, LLC, MISO and Electric Reliability Council of Texas), in which any credit losses are socialized to all market participants.
We have additional indirect credit exposure to financial institutions from letters of credit provided as security by power suppliers under various purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below investment grade, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in default under the contract.
Increasing costs of our defined benefit retirement plans and employee benefits may adversely affect our results of operations, financial condition or cash flows.
We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements of these plans. Estimates and assumptions may change. In addition, the Pension Protection Act sets the minimum funding requirements for defined benefit pension plans. Therefore, our funding requirements and contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year, due to high numbers of retirements or employees leaving, would trigger settlement accounting and could require Xcel Energy to recognize incremental pension expense related to unrecognized plan losses in the year liabilities are paid. Changes in industry standards utilized in key assumptions (e.g., mortality tables) could have a significant impact on future obligations and benefit costs.
Increasing costs associated with health care plans may adversely affect our results of operations.
Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our results of operations, financial condition or cash flows. Health care legislation could also significantly impact our benefit programs and costs.
We must rely on cash from our subsidiaries to make dividend payments.
Investments in our subsidiaries are our primary assets. Substantially all 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 estimated federal, state and local tax payments through their regulated rates. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Tax depreciable lives and the valuevalue/availability of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies, such as tax normalization, may impact our ability to economically deliver certain types of resources relative to market prices.
Macroeconomic Risks
Economic conditions impact our business.
Xcel Energy’s operations are affected by local, national and worldwide economic conditions, which correlates to customers/sales growth (decline). Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay their bills, which could lead to additional bad debt expense.
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 is impactingcontinues to impact countries, communities, supply chains and markets. A high degree of uncertainty continues to exist regarding the pandemic,pandemic; the duration and magnitude of business restrictions re-shut downs,(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. While we
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 implementing contingency plans, there are no guarantees these plans will be sufficient to offsetrequesting implementation of a new sales true-up mechanism for 2022 - 2024. These mechanisms mitigate the impact of COVID-19.changes to sales levels as compared to a baseline.
Although the financial impact of the pandemic to the 2020on our financial results washas largely been mitigated, due to management’s actions, we cannot ultimately predict whether it will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact of the virus on the health of our employees, our supply chain or our ability to recover higher costs associated with managing through the pandemic. The impact of COVID-19 may exacerbate other risks discussed herein, which could have a material effect on us. The situation is evolving and additional impacts may arise.
Operations could be impacted by war, terrorism or other events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows.
The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have already incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.
A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility.
We also face the risks of possible loss of business due to significant events such as severe storms, severe temperature extremes, wildfires (particularly in Colorado), widespread pandemic, generator or transmission facility outage, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or a workforce disruption.
In addition, major catastrophic events throughout the world may disrupt our business. Xcel Energy participates in a global supply chain, which includes materials and components that are globally sourced. A prolonged disruption could result in the delay of equipment and materials that may impact our ability to reliably serve our customers.
A major disruption could result in a significant decrease in revenues and additional costs to repair assets, which could have a material impact on our results of operations, financial condition or cash flows.
Xcel Energy participates in GridEx, 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.
Xcel Energy’s generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets as well as information processed in our systems (e.g., information regarding our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error.
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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.
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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 may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.
In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. The
In April 2021, ahead of the United Nations Climate Change Conference in Glasgow, the Biden Administration will establishcommitted the U.S. to a new nationally determined contribution for the United States. The Paris AgreementNationally 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.
The Biden Administration has also announced a one year suspension of new oil and natural gas drilling on federal lands to allow for a review of oil and gas leasing regulations. The form of these regulations is uncertain, but, depending on the requirements imposed in the short and long term, they could impose substantial costs on our oil and gas customers or result in substantial increases to the cost of fuel we use in our electricity and gas businesses.
Many states and localities continue to pursue their own climate policies. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation or retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies.
We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.
If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.
Increased risks of regulatory penalties could negatively impact our business.
The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. The FERC can impose penalties of up to $1.3 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.
In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cyber or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.
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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. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination.
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Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements.
In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.
We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.
Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events. Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues.
Climate change may impact the economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods.
To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
We have committed to a number of long-term climate change goals, which in part are dependent on future technologies not currently in existence. Given the long-term nature of these goals, there is an inherent uncertainty due to internal and external factors regarding our ability to achieve our stated climate change goals. To the extent climate change goals are not met, this could negatively impact our reputation and potentially result in financial risk.
Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers.
To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Periods of extreme temperatures could impact our ability to meet demand. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations. Drought conditions also contribute to the increase in wildfire risk from our electric generation facilities.
While we carry liability insurance, given an extreme event, if Xcel Energy was found to be liable for wildfire damages, amounts that potentially exceed our coverage could negatively impact our results of operations, financial condition or cash flows.
Drought or water depletion could adversely impact our ability to provide electricity to customers, cause early retirement of power plants and increase the cost for energy. Adverse events may result in increased insurance costs and/or decreased insurance availability. We may not recover all costs related to mitigating these physical and financial risks.
ITEM 1B — UNRESOLVED STAFF COMMENTS
None.
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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
FuelInstalled
MW (a)
NSP-Minnesota
Station, Location and Unit at Dec. 31, 2021
NSP-Minnesota
Station, Location and Unit at Dec. 31, 2021
FuelInstalled
MW (a)
Steam:Steam:Steam:
A.S. King-Bayport, MN, 1 Unit (f)
A.S. King-Bayport, MN, 1 Unit (f)
Coal1968511 
A.S. King-Bayport, MN, 1 Unit (f)
Coal1968511 
Sherco-Becker, MN (e)
Sherco-Becker, MN (e)
Sherco-Becker, MN (e)
Unit 1Unit 1Coal1976680 Unit 1Coal1976680 
Unit 2Unit 2Coal1977682 Unit 2Coal1977682 
Unit 3Unit 3Coal1987517 (b)Unit 3Coal1987517 (b)
Monticello, MN, 1 UnitMonticello, MN, 1 UnitNuclear1971617 Monticello, MN, 1 UnitNuclear1971617 
PI-Welch, MNPI-Welch, MNPI-Welch, MN
Unit 1Unit 1Nuclear1973521 Unit 1Nuclear1973521 
Unit 2Unit 2Nuclear1974519 Unit 2Nuclear1974519 
Various locations, 4 UnitsVarious locations, 4 UnitsWood/RefuseVarious36 (c)Various locations, 4 UnitsWood/RefuseVarious36 (c)
Combustion Turbine:Combustion Turbine:Combustion Turbine:
Angus Anson-Sioux Falls, SD, 3 UnitsAngus Anson-Sioux Falls, SD, 3 UnitsNatural Gas1994 - 2005327 Angus Anson-Sioux Falls, SD, 3 UnitsNatural Gas1994 - 2005327 
Black Dog-Burnsville, MN, 3 UnitsBlack Dog-Burnsville, MN, 3 UnitsNatural Gas1987 - 2018494 Black Dog-Burnsville, MN, 3 UnitsNatural Gas1987 - 2018494 
Blue Lake-Shakopee, MN, 6 UnitsBlue Lake-Shakopee, MN, 6 UnitsNatural Gas1974 - 2005447 Blue Lake-Shakopee, MN, 6 UnitsNatural Gas1974 - 2005447 
High Bridge-St. Paul, MN, 3 UnitsHigh Bridge-St. Paul, MN, 3 UnitsNatural Gas2008530 High Bridge-St. Paul, MN, 3 UnitsNatural Gas2008530 
Inver Hills-Inver Grove Heights, MN, 6 UnitsInver Hills-Inver Grove Heights, MN, 6 UnitsNatural Gas1972252 Inver Hills-Inver Grove Heights, MN, 6 UnitsNatural Gas1972252 
Riverside-Minneapolis, MN, 3 UnitsRiverside-Minneapolis, MN, 3 UnitsNatural Gas2009454 Riverside-Minneapolis, MN, 3 UnitsNatural Gas2009454 
Various locations, 7 UnitsVarious locations, 7 UnitsNatural GasVarious10 Various locations, 7 UnitsNatural GasVarious10 
Wind:Wind:Wind:
Blazing Star 1-Lincoln County, MN, 100 UnitsBlazing Star 1-Lincoln County, MN, 100 UnitsWind2020200 (d)
Blazing Star 2-Lincoln County, MN, 100 UnitsBlazing Star 2-Lincoln County, MN, 100 UnitsWind2021200 (d)
Border-Rolette County, ND, 75 UnitsBorder-Rolette County, ND, 75 UnitsWind2015148 (d)Border-Rolette County, ND, 75 UnitsWind2015148 (d)
Community Wind North-Lincoln County, MN, 12 UnitsCommunity Wind North-Lincoln County, MN, 12 UnitsWind202026 (d)
Courtenay Wind-Stutsman County, ND, 100 UnitsCourtenay Wind-Stutsman County, ND, 100 UnitsWind2016190 (d)Courtenay Wind-Stutsman County, ND, 100 UnitsWind2016190 (d)
Crowned Ridge 2-Grant County, SD, 88 UnitsCrowned Ridge 2-Grant County, SD, 88 UnitsWind2020192 (d)
Foxtail-Dickey County, ND, 75 UnitsFoxtail-Dickey County, ND, 75 UnitsWind2019150 (d)Foxtail-Dickey County, ND, 75 UnitsWind2019150 (d)
Freeborn-Freeborn County, MN, 100 UnitsFreeborn-Freeborn County, MN, 100 UnitsWind2021200 (d)
Grand Meadow-Mower County, MN, 67 UnitsGrand Meadow-Mower County, MN, 67 UnitsWind200899 (d)Grand Meadow-Mower County, MN, 67 UnitsWind200899 (d)
Jeffers-Cottonwood County, MN, 20 UnitsJeffers-Cottonwood County, MN, 20 UnitsWind202043 (d)
Lake Benton-Pipestone County, MN, 44 UnitsLake Benton-Pipestone County, MN, 44 UnitsWind201999 (d)Lake Benton-Pipestone County, MN, 44 UnitsWind201999 (d)
Mower-Mower County, MN, 43 UnitsMower-Mower County, MN, 43 UnitsWind202191 (d)
Nobles-Nobles County, MN, 134 UnitsNobles-Nobles County, MN, 134 UnitsWind2010197 (d)Nobles-Nobles County, MN, 134 UnitsWind2010197 (d)
Pleasant Valley-Mower County, MN, 100 UnitsPleasant Valley-Mower County, MN, 100 UnitsWind2015196 (d)Pleasant Valley-Mower County, MN, 100 UnitsWind2015196 (d)
Blazing Star 1-Lincoln County, MN, 100 UnitsWind2020200 (d)
Crowned Ridge 2-Grant County, SD, 88 UnitsWind2020192 (d)
Community Wind North-Lincoln County, MN, 12 UnitsWind202026 (d)
Jeffers-Cottonwood County, MN, 20 UnitsWind202043 (d)
Total8,137 Total8,628 
(a)Summer 20202021 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.
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NSP-Wisconsin
Station, Location and Unit
FuelInstalled
MW (a)
NSP-Wisconsin
Station, Location and Unit at Dec. 31, 2021
NSP-Wisconsin
Station, Location and Unit at Dec. 31, 2021
FuelInstalled
MW (a)
Steam:Steam:Steam:
Bay Front-Ashland, WI, 2 UnitsBay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 Bay Front-Ashland, WI, 2 UnitsWood/Natural Gas1948 - 195641 
French Island-La Crosse, WI, 2 UnitsFrench Island-La Crosse, WI, 2 UnitsWood/Refuse1940 - 194816 (b)French Island-La Crosse, WI, 2 UnitsWood/Refuse1940 - 194816 (b)
Combustion Turbine:Combustion Turbine:Combustion Turbine:
French Island-La Crosse, WI, 2 UnitsFrench Island-La Crosse, WI, 2 UnitsOil1974122 French Island-La Crosse, WI, 2 UnitsOil1974122 
Wheaton-Eau Claire, WI, 5 UnitsWheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973234 Wheaton-Eau Claire, WI, 5 UnitsNatural Gas/Oil1973234 
Hydro:Hydro:Hydro:
Various locations, 63 UnitsVarious locations, 63 UnitsHydroVarious135 Various locations, 63 UnitsHydroVarious135 
Total548 Total548 
(a)Summer 2020 2021 net dependable capacity.
(b)Refuse-derived fuel is made from municipal solid waste.
PSCo
Station, Location and Unit
FuelInstalled
MW (a)
PSCo
Station, Location and Unit at Dec. 31, 2021
PSCo
Station, Location and Unit at Dec. 31, 2021
FuelInstalled
MW (a)
Steam:Steam:Steam:
Comanche-Pueblo, CO (b)
Comanche-Pueblo, CO (b)
Comanche-Pueblo, CO (b)
Unit 1Unit 1Coal1973325 Unit 1Coal1973325 
Unit 2Unit 2Coal1975335 Unit 2Coal1975335 
Unit 3Unit 3Coal2010500 (c)Unit 3Coal2010500 (c)
Craig-Craig, CO, 2 Units (d)
Craig-Craig, CO, 2 Units (d)
Coal1979 - 198082 (e)
Craig-Craig, CO, 2 Units (d)
Coal1979 - 198082 (e)
Hayden-Hayden, CO, 2 Units (h)
Hayden-Hayden, CO, 2 Units (h)
Coal1965 - 1976233 (f)
Hayden-Hayden, CO, 2 Units (h)
Coal1965 - 1976233 (f)
Pawnee-Brush, CO, 1 UnitPawnee-Brush, CO, 1 UnitCoal1981505 Pawnee-Brush, CO, 1 UnitCoal1981505 
Cherokee-Denver, CO, 1 UnitCherokee-Denver, CO, 1 UnitNatural Gas1968310 Cherokee-Denver, CO, 1 UnitNatural Gas1968310 
Combustion Turbine:Combustion Turbine:Combustion Turbine:
Blue Spruce-Aurora, CO, 2 UnitsBlue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 Blue Spruce-Aurora, CO, 2 UnitsNatural Gas2003264 
Cherokee-Denver, CO, 3 UnitsCherokee-Denver, CO, 3 UnitsNatural Gas2015576 Cherokee-Denver, CO, 3 UnitsNatural Gas2015576 
Fort St. Vrain-Platteville, CO, 6 UnitsFort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 2009968 Fort St. Vrain-Platteville, CO, 6 UnitsNatural Gas1972 - 2009973 
Rocky Mountain-Keenesburg, CO, 3 UnitsRocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004580 Rocky Mountain-Keenesburg, CO, 3 UnitsNatural Gas2004580 
Various locations, 8 UnitsVarious locations, 8 UnitsNatural GasVarious251 Various locations, 8 UnitsNatural GasVarious251 
Hydro:Hydro:Hydro:
Cabin Creek-Georgetown, COCabin Creek-Georgetown, COCabin Creek-Georgetown, CO
Pumped Storage, 2 UnitsPumped Storage, 2 UnitsHydro1967210 Pumped Storage, 2 UnitsHydro1967210 
Various locations, 8 UnitsVarious locations, 8 UnitsHydroVarious25 Various locations, 8 UnitsHydroVarious25 
Wind:Wind:Wind:
Rush Creek, CO, 300 unitsRush Creek, CO, 300 unitsWind2018582 (g)Rush Creek, CO, 300 unitsWind2018582 (g)
Cheyenne Ridge, CO, 229 unitsCheyenne Ridge, CO, 229 unitsWind2020477 (g)Cheyenne Ridge, CO, 229 unitsWind2020477 (g)
Total6,223 Total6,228 
(a)    Summer 20202021 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
FuelInstalled
MW (a)
SPS
Station, Location and Unit at Dec. 31, 2021
SPS
Station, Location and Unit at Dec. 31, 2021
FuelInstalled
MW (a)
Steam:Steam:Steam:
Cunningham-Hobbs, NM, 2 UnitsCunningham-Hobbs, NM, 2 UnitsNatural Gas1957 - 1965225 Cunningham-Hobbs, NM, 2 UnitsNatural Gas1957 - 1965225 
Harrington-Amarillo, TX, 3 Units (b)
Harrington-Amarillo, TX, 3 Units (b)
Coal1976 - 19801,018 
Harrington-Amarillo, TX, 3 Units (b)
Coal1976 - 19801,018 
Jones-Lubbock, TX, 2 UnitsJones-Lubbock, TX, 2 UnitsNatural Gas1971 - 1974486 Jones-Lubbock, TX, 2 UnitsNatural Gas1971 - 1974486 
Maddox-Hobbs, NM, 1 UnitMaddox-Hobbs, NM, 1 UnitNatural Gas1967112 Maddox-Hobbs, NM, 1 UnitNatural Gas1967112 
Nichols-Amarillo, TX, 3 UnitsNichols-Amarillo, TX, 3 UnitsNatural Gas1960 - 1968457 Nichols-Amarillo, TX, 3 UnitsNatural Gas1960 - 1968457 
Plant X-Earth, TX, 4 UnitsPlant X-Earth, TX, 4 UnitsNatural Gas1952 - 1964298 Plant X-Earth, TX, 4 UnitsNatural Gas1952 - 1964298 
Tolk-Muleshoe, TX, 2 Units (d)
Tolk-Muleshoe, TX, 2 Units (d)
Coal1982 - 19851,067 
Tolk-Muleshoe, TX, 2 Units (d)
Coal1982 - 19851,067 
Combustion Turbine:Combustion Turbine:Combustion Turbine:
Cunningham-Hobbs, NM, 2 UnitsCunningham-Hobbs, NM, 2 UnitsNatural Gas1997207 Cunningham-Hobbs, NM, 2 UnitsNatural Gas1997207 
Jones-Lubbock, TX, 2 UnitsJones-Lubbock, TX, 2 UnitsNatural Gas2011 - 2013334 Jones-Lubbock, TX, 2 UnitsNatural Gas2011 - 2013334 
Maddox-Hobbs, NM, 1 UnitMaddox-Hobbs, NM, 1 UnitNatural Gas1963 - 197661 Maddox-Hobbs, NM, 1 UnitNatural Gas1963 - 197661 
Wind:Wind:Wind:
Hale-Plainview, TX, 239 UnitsHale-Plainview, TX, 239 UnitsWind2019460 (c)Hale-Plainview, TX, 239 UnitsWind2019477 (c)
Sagamore-Dora, NM, 240 UnitsSagamore-Dora, NM, 240 UnitsWind2020507 (c)Sagamore-Dora, NM, 240 UnitsWind2020507 (c)
Total5,232 Total5,249 
(a)    Summer 20202021 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 expectedproposed to be retired in 2032.2034.
Electric utility overhead and underground transmissiontransmission and distribution lines (measured in conductor miles) at Dec. 31, 2020:2021:
Conductor MilesConductor MilesNSP-MinnesotaNSP-WisconsinPSCoSPSConductor MilesNSP-MinnesotaNSP-WisconsinPSCoSPS
TransmissionTransmissionTransmission
500 KV500 KV2,918 — — — 500 KV2,915 — — — 
345 KV345 KV13,151 3,337 5,389 11,019 345 KV13,570 2,943 4,978 11,688 
230 KV230 KV2,301 — 12,131 9,795 230 KV2,300 — 12,141 9,763 
161 KV161 KV674 1,823 — — 161 KV640 1,778 — — 
138 KV138 KV— — 92 — 138 KV— — 92 — 
115 KV115 KV8,060 1,822 5,092 14,830 115 KV8,086 1,818 5,075 14,880 
Less than 115 KVLess than 115 KV6,556 5,306 1,682 4,375 Less than 115 KV6,644 5,870 1,830 4,423 
Total TransmissionTotal Transmission33,660 12,288 24,386 40,019 Total Transmission34,155 12,409 24,116 40,754 
DistributionDistributionDistribution
Less than 115 KVLess than 115 KV80,508 27,611 78,483 21,984 Less than 115 KV81,406 27,701 78,712 22,651 
TotalTotal114,168 39,899 102,869 62,003 Total115,561 40,110 102,828 63,405 
Electric utility transmission and distribution substations at Dec. 31, 2020:2021:
NSP-MinnesotaNSP-WisconsinPSCoSPS
Quantity352 204 236 457 
NSP-MinnesotaNSP-WisconsinPSCoSPS
Quantity354 204 237 458 
Natural gas utility mains at Dec. 31, 2020:2021:
MilesMilesNSP-MinnesotaNSP-WisconsinPSCoSPSWGIMilesNSP-MinnesotaNSP-WisconsinPSCoSPSWGI
TransmissionTransmission80 3 2,058 20 11 Transmission85 3 2,174 20 11 
DistributionDistribution10,629 2,492 22,815 — — Distribution10,741 2,526 23,243 — — 





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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.Managementestimation.
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 is listed on the Nasdaq Global Select Market (Nasdaq). The trading symbol is XEL. The number of common stockholders of record as of Feb. 12, 202117, 2022 was approximately 52,689.49,137.
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-20201231_g28.jpgxel-20211231_g30.jpg
*    $100 invested on Dec. 31, 20152016 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, 2020,2021, 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)20202019201820172016
Operating revenues$11,526 $11,529 $11,537 $11,404 $11,107 
Operating expenses (a)
9,410 9,425 9,572 9,181 8,867 
Net income1,473 1,372 1,261 1,148 1,123 
Earnings available to common shareholders1,473 1,372 1,261 1,148 1,123 
Diluted earnings per common share2.79 2.64 2.47 2.25 2.21 
Financial information
Dividends declared per common share1.72 1.62 1.52 1.44 1.36 
Total assets53,957 50,448 45,987 43,030 41,155 
Long-term debt (b)
19,645 17,407 15,803 14,520 14,195 
(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 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.

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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, 20202021 and 2019,2020, 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:
2020201920212020
Diluted Earnings (Loss) Per ShareDiluted Earnings (Loss) Per ShareGAAP and Ongoing Diluted EPSGAAP and Ongoing Diluted EPSDiluted Earnings (Loss) Per ShareGAAP and Ongoing Diluted EPSGAAP and Ongoing Diluted EPS
PSCoPSCo$1.22 $1.11 
NSP-MinnesotaNSP-Minnesota$1.12 $1.04 NSP-Minnesota1.12 1.12 
PSCo1.11 1.11 
SPSSPS0.56 0.51 SPS0.59 0.56 
NSP-WisconsinNSP-Wisconsin0.20 0.15 NSP-Wisconsin0.20 0.20 
Equity earnings of unconsolidated subsidiaries0.05 0.05 
Earnings from equity method investments — WYCOEarnings from equity method investments — WYCO0.05 0.05 
Regulated utility (a)
Regulated utility (a)
3.04 2.86 
Regulated utility (a)
3.18 3.04 
Xcel Energy Inc. and OtherXcel Energy Inc. and Other(0.25)(0.22)Xcel Energy Inc. and Other(0.22)(0.25)
Total (a)
Total (a)
$2.79 $2.64 
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.
20202021 Comparison with 20192020
Xcel Energy — GAAP and ongoing earnings increased $0.15 per share, primarily reflecting higher electric margin (largely due to regulatory outcomes which recover capital investment), higher AFUDC and lower O&M expenses, which offset increased depreciation, interest expense and declining sales primarily due to the impacts of COVID-19.
NSP-Minnesota — Earnings increased $0.08$0.17 per share for 2020, reflecting higher electric margin (riders, wholesale transmission revenue2021. The increase was driven by capital investment recovery and a sales true-up mechanism, which recovers lower sales due to COVID-19) and lower O&M expenses,other regulatory outcomes, partially offset by increasedincreases in depreciation and lower AFUDC. Fluctuations in electric and natural gas margin.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 flat for 2020, reflecting higher electric margin (wholesale transmission revenue and regulatory outcomes offset lower sales due to COVID-19), increased AFUDC and higher natural gas margin,partially offset by additionalincreased 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 $0.05$0.03 per share for 2020, reflecting higher electric margin (wholesale transmission revenue and2021, largely related to capital investment recovery, other regulatory outcomes offset lowerand higher sales due to COVID-19) and lower O&M expenses,demand, partially offset by increased depreciation, interest expense and taxes (other than income taxes).decreased AFUDC.
NSP-Wisconsin — Earnings increased $0.05 per sharewere flat for 2020, reflecting higher electric margin (regulatory outcomes offset lower sales due2021 compared to COVID-19) and lower O&M expenses, partially offset by increased depreciation and lower natural gas margin.2020.
Xcel Energy Inc. and Other — Primarily 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:
20202021 vs. 20192020
Diluted Earnings (Loss) Per ShareDec. 31
GAAP and ongoing diluted EPS - 2019— 2020$2.642.79 
Components of change — 20202021 vs. 20192020
Higher electric margins revenues, net of electric fuel and purchased power(a)
0.320.26 
Lower ETR (b)(a)
0.220.17 
Higher AFUDCnatural gas revenues, net of cost of natural gas sold and transported0.080.15 
Changes in O&Mtaxes (other than income taxes)0.02 (0.03)
Lower AFUDC(0.10)
Higher depreciation and amortization(0.26)(0.24)
Higher interest(0.10)
Higher taxes (other than income taxes)(0.06)
Changes in natural gas margins(0.01)
Other (net)(0.06)(0.04)
GAAP and ongoing diluted EPS — 20202021$2.792.96 
(a)    Change in electric margin was negatively impacted by reductions in sales and demand due to COVID-19 and is detailed below. Sales decline excludes weather impact, net of decoupling/sales true-up and reduction in demand revenue is net of sales true-up.
Diluted Earnings (Loss) Per ShareTwelve Months Ended Dec. 31
Electric margin (excluding reductions in sales and demand)$0.41 
Reductions in sales and demand(0.09)
Higher electric margins$0.32 
(b)    Includes PTCs and tax reformplant regulatory amounts, which are primarily offset inas a reduction to electric margin.revenues.
ROE for Xcel Energy and its utility subsidiaries:
2020201920212020
ROEROEGAAP and Ongoing ROEGAAP and Ongoing ROEROEGAAP and Ongoing ROEGAAP and Ongoing ROE
NSP-MinnesotaNSP-Minnesota9.20 %9.31 %NSP-Minnesota8.45 %9.20 %
PSCoPSCo8.06 8.69 PSCo8.23 8.06 
SPSSPS9.54 9.71 SPS9.22 9.54 
NSP-WisconsinNSP-Wisconsin10.52 8.27 NSP-Wisconsin9.92 10.52 
Operating CompaniesOperating Companies8.87 9.06 Operating Companies8.58 8.87 
Xcel EnergyXcel Energy10.59 10.78 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 to the extent there is not a decoupling orperformance. However, sales true-up mechanismand decoupling mechanisms in Minnesota and Colorado predominately mitigate the state.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:
2020 vs.
Normal		2019 vs.
Normal		2020 vs. 20192021 vs.
Normal		2020 vs.
Normal		2021 vs. 2020
HDDHDD(3.1)%10.4 %(12.0)%HDD(6.6)%(3.1)%(4.3)%
CDDCDD22.2 5.4 24.8 CDD12.2 22.2 (9.2)
THITHI6.3 (8.8)18.2 THI26.8 6.3 20.7 
Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:
2020 vs.
Normal		2019 vs.
Normal		2020 vs. 20192021 vs.
Normal		2020 vs.
Normal		2021 vs. 2020
Retail electricRetail electric$0.090 $0.040 $0.050 Retail electric$0.096 $0.090 $0.006 
Decoupling and sales true-upDecoupling and sales true-up(0.041)— (0.041)Decoupling and sales true-up(0.066)(0.041)(0.025)
Total (excluding decoupling)$0.049 $0.040 $0.009 
Electric totalElectric total$0.030 $0.049 $(0.019)
Firm natural gasFirm natural gas(0.011)0.027 (0.038)Firm natural gas(0.025)(0.011)(0.014)
Total (adjusted for recovery from decoupling)$0.038 $0.067 $(0.029)
TotalTotal$0.005 $0.038 $(0.033)
Sales — Sales growth (decline) for actual and weather-normalized sales:
2020 vs. 20192021 vs. 2020
PSCoNSP-MinnesotaSPSNSP-WisconsinXcel EnergyPSCoNSP-MinnesotaSPSNSP-WisconsinXcel Energy
Actual (a)
Actual (a)
Actual (a)
Electric residentialElectric residential5.8 %5.0 %3.6 %2.4 %4.9 %Electric residential— %2.2 %(4.7)%0.5 %0.3 %
Electric C&IElectric C&I(4.1)(7.0)(3.3)(4.6)(5.0)Electric C&I0.4 2.3 2.9 3.6 2.0 
Total retail electric salesTotal retail electric sales(1.1)(3.4)(2.2)(2.6)(2.3)Total retail electric sales0.3 2.2 1.4 2.7 1.4 
Firm natural gas salesFirm natural gas sales(6.8)(8.3)n/a(6.4)(7.2)Firm natural gas sales(1.1)(4.0)N/A(5.0)(2.2)
2020 vs. 20192021 vs. 2020
PSCoNSP-MinnesotaSPSNSP-WisconsinXcel EnergyPSCoNSP-MinnesotaSPSNSP-WisconsinXcel Energy
Weather-normalized (a)
Weather-normalized (a)
Weather-normalized (a)
Electric residentialElectric residential3.8 %3.7 %1.6 %2.6 %3.3 %Electric residential1.5 %0.3 %(1.0)%(0.2)%0.5 %
Electric C&IElectric C&I(4.5)(7.0)(3.4)(4.8)(5.2)Electric C&I0.4 1.7 3.3 3.3 1.9 
Total retail electric salesTotal retail electric sales(1.9)(3.8)(2.6)(2.7)(2.8)Total retail electric sales0.8 1.2 2.5 2.2 1.4 
Firm natural gas salesFirm natural gas sales0.5 1.9 n/a5.1 1.3 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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2020 vs. 2019 (Leap Year Adjusted)
PSCoNSP-MinnesotaSPSNSP-WisconsinXcel Energy
Weather-normalized (a)
Electric residential3.6 %3.4 %1.3 %2.3 %3.1 %
Electric C&I(4.8)(7.3)(3.7)(5.0)(5.4)
Total retail electric sales(2.2)(4.1)(2.9)(2.9)(3.1)
Firm natural gas sales0.1 1.4 n/a4.6 0.7 
(a) Higher residential sales and lower C&I sales were primarily attributable to COVID-19. The increase in residential sales was partially driven by more customers working from home.
Weather-normalized and leap-year adjusted electric sales growth (decline) — year-to-date (excluding leap day)
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 an increased number ofa 1.2% increase in customers, andcombined with higher use per customer. The declinegrowth in C&I sales was primarily due to COVID-19, particularly within the manufacturing and service industries,a 1.2% increase in customers, partially offset by an increaseslightly lower use per customer, primarily in the energyservices sector.
•NSP-Minnesota — Residential sales rose based on an increased number ofgrowth 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. The declinecustomer, primarily in C&I sales was primarily due to COVID-19, particularly within the energy, manufacturing, retail and services sectors.
•SPS — Residential sales rose based on andeclined as lower use per customer offset a 0.9% increase in customers. C&I sales increased number ofdue to a 0.5% increase in customers and higher use per customer. The decline in C&I sales wascustomer, primarily due to COVID-19, particularly withindriven by the energyoil and manufacturinggas and professional services sectors.
•NSP-Wisconsin — Residential sales rose based on an increased number of customers and highergrowth was attributable to a 0.8% increase in customer additions, partially offset by slightly lower use per customer. The declinegrowth in C&I sales was primarily due to COVID-19, particularly withina 1.1% increase in customers, primarily led by increases in the energymanufacturing, health care and manufacturingretail trade sectors.
Weather-normalized and leap-year adjusted natural gas sales growth (decline) — year-to-date (excluding leap day)
•Higher naturalNatural gas sales primarily reflect ana 1.2% increase in the number ofresidential customers combined with higher residential customer use,and a 0.5% increase in C&I customers, partially offset by lower C&I customer use.a decrease in use per customer.
Electric MarginNSP-Minnesota
Electric revenuesStation, Location and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. However, these fluctuations have minimal impact on margin due to fuel recovery mechanisms. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and margin (offset by lower tax expense)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 — — 





Electric
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 margin:
(Millions of Dollars)20202019
Electric revenues$9,802 $9,575 
Electric fuel and purchased power(3,512)(3,510)
Electric margin$6,290 $6,065 
Changes in Electric Margin
(Millions of Dollars)2020 vs. 2019
Regulatory rate outcomes (Colorado, Wisconsin, Texas and New Mexico) ongoing diluted EPS — 2020
$2.79(a)$209 
Non-fuel riders74 
Wholesale transmission revenue (net)59 
MEC purchased capacity costs35 
Conservation incentive13 
2019 tax reform customer credits - Wisconsin (offset in income tax)7 
Estimated impact of weather (net of decoupling / sales true-up)7 
PTCs flowed back to customers (offset by lower ETR)(119)
Sales and demand (b)
(66)
Other (net)6 
Total increase in electric margin$225 
(a)    Includes approximately $70 millionComponents of revenue and margin due to the Texas rate case outcome, which is largely offset by recognition of previously deferred costs.change — 2021 vs. 2020
(b)    Sales excludes weather impact,Higher electric revenues, net of decoupling/sales true-up,electric fuel and demand revenue ispurchased power0.26 
Lower ETR (a)
0.17 
Higher natural gas revenues, net of sales true-up.
Natural Gas Margin
Natural gas expense varies with changing sales and cost of natural gas. However, fluctuations in the cost of natural gas has minimal impact on margin due to cost recovery mechanisms.
Natural gas revenuessold and margin:
(Millions of Dollars)20202019
Natural gas revenues$1,636 $1,868 
Cost of natural gas sold and transported(689)(918)
Natural gas margin$947 $950 
Changes in Natural Gas Margin
(Millions of Dollars)2020 vs. 2019
Estimated impact of weather$(28)
Regulatory rate outcomes (Colorado and Wisconsin)16 
Infrastructure and integrity riders8 
Retail sales growth2 
Other (net)(1)
Total decrease in natural gas margin$(3)transported0.15 
27
Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses decreased $14 million, or 0.6%, for 2020, largely reflecting management actions to reduce costs to offset the impact of lower sales from COVID-19.
Significant changes are as follows:
(Millions of Dollars)2020 vs. 2019
Distribution$(47)
Generation(12)
Transmission(10)
Minnesota payment plan credit program18 
Information technology14 
Employee benefits12 
Texas rate case deferral8 
Other (net)3 
Total decrease in O&M expenses$(14)
•Distribution declined due to cost mitigation/continuous improvement efforts and timing of maintenance, partially offset by increased storm impacts.
•Generation was lower from timing of maintenance and overhauls at power plants and cost mitigation/continuous improvement efforts, partially offset by an increaseChanges in maintenance expenses from wind expansion.
•Transmission declined due to cost mitigation/continuous improvement initiatives.
•Minnesota payment plan credit program represents a commitment to fund customer programs as agreed to in the NSP-Minnesota rate case stay-out.
•Information technology costs increased due to higher spending on network and other infrastructure costs.
•Employee benefits increased due primarily to postretirement costs and other long-term benefits, partially offset by lower deferred compensation expense.
Depreciation and Amortization — Depreciation and amortization increased $183 million, or 10.4%, year-to-date. The increase was primarily driven by the Hale, Cheyenne Ridge, Foxtail, Blazing Star I, Lake Benton, Sagamore, Crowned Ridge, Community Wind North and Jeffers wind facilities going into service, as well as normal system expansion. In addition, new depreciation rates were implemented in Colorado, New Mexico and Texas in 2020, increasing expense.
Taxes (Other than Income Taxes) — Taxestaxes (other than income taxes) increased $43 million, or 7.6%, year-to-date. The increase was primarily due to higher property taxes in Colorado
(0.03)
Lower AFUDC(0.10)
Higher depreciation and Texas (net of deferred amounts).amortization
(0.24)
Other Income (Expense) (net)—(0.04)
Other income (expense) decreased $22 million year-to-date. The decrease was largely due to the performance of rabbi trust investments, primarily offset in O&M expenses.
AFUDC, EquityGAAP and Debt — AFUDC increased $43 million year-to-date. The increase was primarily due to various wind projects under construction.
Interest Charges — Interest charges increased $67 million, or 8.7%, 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.
Income Taxes — Income taxes decreased $134 million for 2020. The decrease was primarily driven by an increase in wind PTCs and an increase in plant-related regulatory differences.
Xcel Energy Inc. and Other Results
Net income andongoing diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:
Contribution (Millions of Dollars)
20202019
Xcel Energy Inc. financing costs$(147)$(128)
MEC (a)
15 — 
Eloigne (b)
1 1 
Xcel Energy Inc. taxes and other results(2)12 
Total Xcel Energy Inc. and other costs$(133)$(115)
— 2021

$
Contribution (Diluted Earnings (Loss) Per Share)
20202019
Xcel Energy Inc. financing costs$(0.28)$(0.21)
MEC (a)
0.03 — 
Eloigne (b)
— — 
Xcel Energy Inc. taxes and other results— (0.01)
Total Xcel Energy Inc. and other costs$(0.25)$(0.22)
(a)MEC was sold in the third quarter of 2020.
(b)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.
2019 Comparison with 2018
A discussion of changes in Xcel Energy’s results of operations, cash flows and liquidity and capital resources from the year ended Dec. 31, 2018 to Dec. 31, 2019 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-K2.96 for the fiscal year 2019, which was filed with the SEC on Feb. 21, 2020. 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
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.
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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.
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
(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
MPUC
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.
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.
ITEM 4 — MINE SAFETY DISCLOSURES
None.
PART II
Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota.
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.
Reviews and approves natural gas supply plans.
ITEM 6 — [RESERVED]
Pipeline safety compliance.
ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NDPSC
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.


Retail rates, services and other aspects of electric and natural gas operations.
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:
Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota.
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
Pipeline safety compliance.
(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 
SDPUC
(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.
DOTPipeline safety compliance.
Minnesota Office of Pipeline SafetyPipeline safety compliance.
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Recovery Mechanisms
Minnesota Office of Pipeline SafetyPipeline safety compliance.
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)
Recovery Mechanisms
MechanismAdditional Information
CIP Rider (a)
Recovers costs of conservation and DSM programs in Minnesota.
EIRRecovers costs of environmental improvement projects in Minnesota.
RDFAllocates money collected from customersMinnesota, 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 support research and development of emerging renewable energy projects and technologies in Minnesota.
RESRecovers cost of renewable generation in Minnesota.
RERRecovers 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 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 2021, NSP-Minnesota filed the 2020 sales true-up compliance report, resulting in a total surcharge of $119 million. An MPUC ruling is anticipated in the second quarter of 2021. The 2021 sales true-up mechanism, extended under the 2020 stay-out petition, will operate similarly to the currently approved sales true-up and apply to all customer classes. Under the stay-out petition, 2021 NSP-Minnesota jurisdictional earnings will be capped at 9.06% ROE. Any excess earnings will 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
Proceeding2022 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.
Amount
(in millions)		Filing
Date		Approval
2020 North Dakota Electric Rate Case$22November 2020Pending
2020 TCR Electric Rider82November 2019Pending
2020 GUIC Natural Gas Rider21November 2019Pending
2021 GUIC Natural Gas Rider27October 2020Pending
2020 RES Electric Rider102November 2019Pending
2021 RES Electric Rider189November 2020Pending

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Additional Information:
2020 Minnesota Electric Rate Case and Stay-Out Alternative — In November 2020, NSP-Minnesota filed an electric rate case seeking a $597 million revenue increase over three years with the MPUC. The rate case is based on a requested ROE of 10.2% and a 52.5% equity ratio. NSP-Minnesota also filed a stay-out alternative in which it would withdraw its rate case filing.
In December 2020, the MPUC verbally approved the stay-out alternative petition, which includes the extension of the sales, capital and property tax true-up mechanisms and delays any increase to the Nuclear Decommissioning Trust annual accrual until Jan. 1, 2022.
Additionally, NSP-Minnesota agreed to not seek recovery of incremental COVID-19 related expenses, including bad debt expense, and committed to fund $18 million in a Residential Payment Plan Credit Program or other similar customer relief programs, as directed by the MPUC. NSP-Minnesota also agreed to an earnings test in which all earnings above an ROE of 9.06% in 2021 would be refunded to customers.
2020 North Dakota Electric Rate Case — In November 2020, NSP-Minnesota filed a request with the NDPSC for an overall increase in annual retail electric revenues of approximately $22 million, or an increase of 10.8%. The rate filing is based on a 2021 forecast test year, a requested ROE of 10.2%, an equity ratio of 52.50% and an electric rate base of approximately $677 million. Interim rates, subject to refund, of approximately $16 million were implemented on Jan. 5, 2021.
2020 TCR Electric Rider — In November 2019, NSP-Minnesota filed the TCR Rider based on an ROE of 9.06%. An MPUC decision is pending.
2020 GUIC Natural Gas Rider — In November 2019, NSP-Minnesota filed the GUIC Rider based on an ROE of 9.04%. An MPUC decision is pending.
2021 GUIC Natural Gas Rider — In October 2020, NSP-Minnesota filed the GUIC Rider based on an ROE of 9.04%. An MPUC decision is pending.
2020 RES Electric Rider — In November 2019, NSP-Minnesota filed the RES Rider. 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%. An MPUC decision is pending.
2021 RES Electric Rider — In November 2020, NSP-Minnesota filed the RES Rider. The requested amount includes a true-up for the 2019 and 2020 rider of $96 million and the 2021 requested amount of $93 million. The filing included an ROE of 9.06%. An MPUC decision is pending.
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 updated preferred resource plan reflects the following:
•Retirement of all coal generation by 2030 with reduced operations at some units prior to retirement, including early retirement of the A.S. King coal plant (511 MW) in 2028 and the Sherco 3 coal plant (517 MW) in 2030.
•Extending the life of the Monticello nuclear plant from 2030 to 2040.
•Continuing to run the PI through current end of life (2033 and 2034).
•Construction of the Sherco combined cycle natural gas plant.
•The addition of 3,500 MW of solar.
•The addition of 2,250 MW of wind.
•2,600 MW of firm peaking (combustion turbine, pumped hydro, battery storage, demand response, etc.).
•Achieving 780 GWh in energy efficiency savings annually through 2034.
•Adding 400 MW of incremental demand response by 2023, and a total of 1,500 MW of demand response by 2034.
Initial comments were submitted Feb. 11, 2021 and reply comments are due April 12, 2021. The MPUC is anticipated to make a final decision during 2021.
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.
NSP-Minnesota’s proposal included the following:
•Repower 651 MW of owned wind projects (capital investment of $750 million) as well as certain wind projects under PPAs.
•Acquire 120 MW repowered wind farm and buy-out of the remaining PPA from ALLETE for $210 million.
•Add solar facilities of 460 MW with an incremental investment of $550 million.
•Accelerate certain grid investment.
•Provide $150 million of incremental electric vehicle rebates.
In December 2020, the MPUC verbally approved the repowering 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. The MPUC is expected to address the solar facilities, ALLETE PPA wind repowering acquisition and the electric vehicle proposal in the second half of 2021.
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.
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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 is estimated to cost approximately $120 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. In June 2018, the Minnesota District Court granted Minnesota state agencies and NSP-Minnesota’s motions to dismiss with prejudice. In February 2020, the Eighth Circuit Court of Appeals upheld the Minnesota District Court decision to dismiss. In June 2020, the Eighth Circuit denied LSP Transmission’s petition for rehearing. In November 2020, LSP Transmission petitioned the U.S. Supreme Court to review its appeal. NSP-Minnesota filed a brief in opposition to this petition on Jan. 25, 2021.
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 JOA.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.
PGAPurchased Gas AdjustmentA retail cost-recovery mechanism to recover the actual cost of natural gas, transportation, and storage services.
Natural Gas Cost-Recovery Factor (MI)NSP-Wisconsin’s natural gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts on an annual basis.
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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 Fuel Cost Recovery Rate Case — In December 2020,January 2022, NSP-Wisconsin reached an electric rate case settlement in principle with the PSCW approvedMPSC 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 NSP-Wisconsin application to update its 2021 fuel cost and decrease retail electric rates for 2021 by approximately $12 million.
Request to Participate in Utility Money Pool— In October 2020, the PSCW approved NSP-Wisconsin’s application to participatesettlement in the Money Pool.
NSP-Wisconsin Solar Proposal — In October 2020, NSP-Wisconsin filed for a 74 MW solar facility build-own-transfer in Wisconsin for approximately $100 million. A PSCW decision is expected in the thirdfirst quarter of 2021.2022.
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 aspects of electric, natural gas and steam operations.
Pipeline safety compliance.
FERC
Wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.
Wholesale electric sales at cost-based prices to customers inside PSCo’s balancing authority area and at market-based prices to customers outside PSCo’s balancing authority area.
PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction.
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
MechanismAdditional Information
ECARecovers fuel and purchased energy costs. Short-term sales margins are shared with customers through the ECA.customers. The ECA is revised quarterly.
PCCAPurchased Capacity Cost AdjustmentRecovers purchased capacity payments.
SCASteam Cost AdjustmentRecovers fuel costs to operate the steam system. The SCASteam Cost Adjustment rate is revised quarterly.
DSMCADSM Cost AdjustmentRecovers electric and gas DSM, interruptible service costs and performance initiatives for achieving energy savings goals.
RESARES AdjustmentRecovers the incremental costs of compliance with the RES with a maximum of 1% of the customer’s bill.
CEPAColorado Energy Plan AdjustmentRecovers the early retirement costs of Comanche units 1 and 2 to a maximum of 1% of the customer’s bill.
WCAWind Cost AdjustmentRecovers costs for customers who choose renewable resources.
TCATransmission Cost AdjustmentRecovers costs for transmission investment between rate cases.
CACJAClean Air Clean Jobs ActRecovers costs associated with the CACJA.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.
PSIARecovers costs for transmission and distribution pipeline integrity management programs.
DecouplingMechanism to true-up revenue to a baseline amount for residential (excluding lighting and demand) and metered non-demand small C&I classes. Represents approximately $51M for differences
Transportation Electrification PlanRecovers costs associated with the investment in sales to the baseline amount. Amounts refunded or surcharged to customers may be limited to a refund cap.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 case:
Plant related investments (a)
$210 
Operations and maintenance, amortization and other expenses11 
Property tax expense11 
Sales growth(17)
Net increase to revenue215
Previously authorized costs:
Transfer of costs previously recovered through the PSIA rider(108)
Total base revenue request$107
ProceedingAmount
(in millions)		Filing DateApproval
2020 Natural Gas Rate CaseProjected 2022 year-end rate base (billions of dollars)$77February 20203.6Received
2019 Electric Rate Case108May 2019Received
2019 Natural Gas Rate Case AppealN/AApril 2019Pending
Wildfire Protection Rider325July 2020Pending
Transportation Electrification Plan Rider110 - 138May 2020Received
Additional Information:
2020 Natural Gas Rate Case — In October 2020,(a)    Includes approximately $28 million as a result of the CPUC approved a settlement resulting in a net increase of $77 million. This increase reflects a $94 million increase in base rate revenue, partially offset by $17 million of costs previously recovered through the Pipeline Integrity rider. Rates will be implemented on April 1, 2021 (retroactiveROE from 9.2% to November 2020)10.25%.
2019Colorado Electric Rate Case Request— In 2019,July 2021, PSCo filed a request with the CPUC seeking a net electric rate increase of approximately $108 million. $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 February 2020,January 2022, PSCo reached an unopposed comprehensive settlement. The CPUC is expected to rule on the CPUC issued an initial decision for asettlement in March 2022 with final rates expected to be effective in April 2022. Key settlement terms include:
•A net electric rate increase of $35$177 million. In July 2020, the CPUC’s final written decision on rehearing was receivedThe 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 resulted in an additional increaseequity ratio of approximately $12 million annually.55.69%.
In December 2020, the CPUC denied PSCo’s request of a $5 million surcharge for changes to the revenue increase from the effective date of rates, based on the CPUC’s decision on rehearing. PSCo has appealed this decision•A current 2021 test year (average rate base) with the District Courttransfer of Denver County.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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2019 Phase I Electric Rate Case Appeal — In August 2020, PSCo filed an appeal with the Denver District Court seeking a review of CPUC decisions on gain on sales and losses of assets, oil and gas royalty revenues and Board of Director’s equity compensation. PSCo plans to seek consolidation of this appeal with the appeal of the surcharge decision in this same proceeding.
2019 Natural Gas Rate Case Appeal — In April 2019, PSCo filed an appeal seeking judicial review of the CPUC’s prior ruling regarding PSCo’s natural gas rate case (filed in June 2017 and approved in December 2018). The appeal requested review of the following: denial of a return on the prepaid pension and retiree medical assets; the use of a capital structure not based on the actual historical test year; and use of an average rate base methodology rather than a year-end rate base methodology.PSIA Rider Extensio
In March 2020, The District Court of Denver County ruled in favor of allowing the prepaid pension assets to be included in rate base; but upheld the CPUC’s treatment of the retiree medical assets and capital structure methodology. In March 2021, PSCo expects to file a motion to implement the District Court’s decision on treatment of the prepaid pension asset for the applicable period of Jan. 1, 2018 through Oct. 31, 2020.
Wildfire Protection Rider —In 2020, PSCo requested to establish a rider to recover incremental costs associated with system investments to reduce wildfire risk. The rider would be effective in June 2021 and continue through 2025. The Office of Consumer Counsel and CPUC Staff are supportive of the wildfire mitigation program as proposed, but oppose rider recovery and instead recommend deferral of certain costs with recovery in a future rate case. A CPUC decision is expected in the second quarter of 2021.
Wildfire Protection capital investment is projected to be approximately $325 million. Forecasted annual revenue requirements from 2021 through 2025:
(Millions of Dollars)20212022202320242025
Forecasted annual revenue requirement$17 $24 $29 $32 $34 
Transportation Electrification Plann — In JanuaryOctober 2021, the CPUC approved PSCo's Transportation Electrification Plan, which authorizesa settlement agreement to allow the rider recoveryto end on Dec. 31, 2021, transfer the investments recovered under the rider to base rates Jan. 1, 2022, and defer $9 million of new electric vehicle utility programsdepreciation 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 residential, commercial, multi-familyPathway 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 charging sectors. The approval establishes utility-owned charging infrastructure and chargers and amortization of rebates for electric vehicles. The Transportation Electrification Plan approval authorizes approximately $110 million in spending with flexibility up to approximately $138 million over three years.interest.
Advanced Grid Rider•Agreed to a cost estimate of $1.7 billion and recovery through the transmission rider.
In 2020, PSCo requested•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 establishconditional CPCN approval for 345 kV extension project subject to the project being included in the final approved Integrated Resource Plan with a rider to recover incremental costs associated with the Advanced Grid Intelligence and Security initiative. The rider would be effective in May 2021 and continue through 2025. In October 2020, an ALJ issued The Recommended Decision granting the Officecost estimate of Consumer Counsel motion to dismiss the Advanced Grid Rider. PSCo has chosen not to appeal the ALJ’s Recommended Decision.$247 million.
The settlement agreement is currently being deliberated by the CPUC.
Resource Plan Settlement— In November 2021, PSCo portionand intervenors filed a partial settlement of the Advanced Grid Intelligenceresource plan, which will result in an expected 87% carbon reduction and Security capital investment is projected to be approximately $850 million. Forecasted annual revenue requirements from 2021 through 2025 are as follows:
(Millions of Dollars)20212022202320242025
Forecasted annual revenue requirement$53 $69 $83 $89 $99 

PSCo KEPCO Filing
In September 2020, PSCo filed with the CPUC for approval to terminate a solar PPA with KEPCO Solar of Alamosa, Inc. and establish a regulatory asset to recover transaction costs of approximately $41 million. By terminating the PPA, customers would save approximately $38 million over an 11-year period. A CPUC decision is expected in the second quarter of 2021.
Natural Gas LDC and Emission Reductions
In October 2020, the CPUC opened a docket to investigate topics related to natural gas emissions in relation to statewide emission reduction goals. The first meeting was held in November 2020, in which subject matter experts discussed greenhouse emission reductions required from the natural gas industry in regard to the statewide goals.
Resource Plan
PSCo is expected to file its next Electric Resource Plan on March 31, 2021. The filing will propose the future of the remaining coal plants in Colorado and PSCo’s plan to achieve it’s 80% carbon emissions reduction targetrenewable 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 plant.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 obtainedincurred replacement power costs of approximately $16 million during the outage.
In October 2020, the CPUC initiated a non-adjudicatory review of Comanche Unit 3’s performance. AIn March 2021, the CPUC Staff issued a report, on performance is expected to be issued in March 2021. At this stagewhich 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 regulatoryfuture of Comanche Unit 3 operations in the next resource plan, performance standards for all company-owned generation and a review the resulting recommendations of the CPUC’s staff cannot be determined.
Boulder Municipalizationoutage and repair costs in upcoming ECA proceedings.
In 2011, Boulder passedOctober 2021, a ballot measure authorizing the formationcomprehensive settlement was reached, which addressed treatment of an electric municipal utility. Subsequently, there have been various legal proceedings in multiple venues.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 September 2020, the City Council voted to approve a settlement between PSCo and Boulder officials to end the city’s municipalization effort. The settlement resulted in a 20-year franchise arrangement (with multiple opt-out conditions), an energy partnership and an undergrounding agreement. It also established the municipalization process if Boulder exercised an opt-out. In DecemberAugust 2020, PSCo filed the franchise agreementan appeal with the Denver District Court seeking a review of CPUC decisions on gains and is currently awaitinglosses on sales of assets, oil and gas royalty revenues, Board of Directors equity compensation and a decision.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.
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Energy Markets — PSCo is working towards joiningplans to join the SPP Western Energy Imbalance Service Market in 2022.April 2023. This market was developed byis an incremental step in the California ISO and allows PSCo access to a real-time energyparticipation in the organized wholesale market. The Western Energy Imbalance Market allowsimbalance markets allow participants to buy and sell power close to the time electricity is consumed and gives system operators real-time visibility across neighboring grids. The result improves balancing supply and demand at a lower cost.
Purchased Transmission Services — In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers.
Wholesale and Commodity Marketing Operations
PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. PSCo uses physical and financial instruments to minimize commodity price and credit risk and hedge sales and purchases. PSCo also engages in trading activity unrelated to hedging. Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved 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 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.
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 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
ProceedingAmount
(in millions)		Filing DateApproval
2019 New Mexico Electric Rate Case$31July 2019Received
2019 Texas Electric Rate Case88August 2019Received
2021 New Mexico Electric Rate Case88January 2021Pending
2021 Texas Electric Rate Case143February 2021Pending
Additional Information:
2019 New Mexico Electric Rate Case — In May 2020, the NMPRC approved a settlement between SPS and intervening parties, which reflects the following terms: a base rate increase of $31 million, an ROE of 9.45% and an equity ratio of 54.77%. New rates and tariffs were effective in May 2020.
2019 Texas Electric Rate Case — In August 2020, the PUCT approved a settlement between SPS and intervening parties, which reflects the following terms: a rate increase of $88 million; ROE of 9.45% and equity ratio of 54.62% for AFUDC purposes. In December 2020, SPS filed to surcharge the final under-recovered amount, estimated to be approximately $72 million, offset by the recognition of previously deferred costs.
2021 New Mexico Electric Rate Case — On Jan. 4,In January 2021, SPS filed an electric rate case with the NMPRC seeking anwith a current requested base rate increase in base rates of approximately $88$84 million. SPS' net
In 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 New Mexico customers is expected to be approximately $48 million, or 10%, as a result of offsetting fuel cost reductions and PTCs attributable to wind energy provided by the Sagamore wind project. PTCs are being credited to customers through the fuel clause.
The request is based on a historic test year ended Sept. 30, 2020, including expected capital additions through Feb. 28, 2021, a ROE of 10.35%,2032, an equity ratio of 54.72% and retailROE 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 basecase 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 approximately $1.9 billion (total company$62 million, but would adjust the class cost allocation such that all rate baseclasses would have a uniform increase of approximately $6.0 billion)4.89%.
Additionally, The NMPRC required the request includes the effect of approximately 400 MW of reduced peak load in 2021 from a wholesale transmission customer and changesparties to depreciation rates to reflect a reductioneither file their acceptance or opposition to the service livesmodified 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’ Tolk power plant (from 2037originally 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 2032)reconsider its order and voted 3-2 to approve the coal handling assets at the Harrington facility (to 2024).
The NMPRC suspended newstipulation without modification. New rates for nine months beyond the 30-day notice period, consistent with historic practice.
The next steps in the procedural schedule are expected to be as follows:
•Staff and intervenor testimony — May 17, 2021.
•Rebuttal testimony — June 9, 2021.
•Deadline to file stipulation — June 23, 2021.
•Public hearing or hearingwill go into effect on stipulation — JulyFeb. 26, - Aug. 6, 2021.
•End of nine month suspension — Nov. 3, 2021.
A NMPRC decision and implementation of final rates is anticipated in the fourth quarter of 2021.2022.
2021 Texas Rate Case — On Feb. 8,In February 2021, SPSfiled an electric rate case with the PUCT and its 81 municipalities, with original rate jurisdiction seeking an increase in base rates of approximately $143$140 million. SPS'SPS’ proposed net rate increase to Texas customers is expected to bewas approximately $74$71 million, or 9.2%, as a result of the offsetting $69 million in fuel cost reductions and PTCs from the Sagamore wind project.
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The request is primarily driven by additional capital investment in new and upgraded electric facilities and equipment since SPS’ previous rate case in 2019, including the 522 MW Sagamore wind project.
The request iswas based on ana ROE of 10.35%, an equity ratio of 54.60% (based on actual capital structure), a Texas retail rate base of approximately $3.3 billion and a historic test year based on the 12-month period ended Dec. 31, 2020 (with the final three months based on estimates). In March 2021, SPS will file to update estimates to actuals through Dec. 31, 2020.
Additionally, the The request includesincluded the effect of losing approximately 400 MW from a wholesale transmission customer and changes to depreciation rates to reflect a reduction to the service lives of SPS’ Tolk power plant (from 2037 to 2032) and the coal handling assets ofat the Harrington facility (to 2024).
SummaryIn January 2022, SPS and intervenors filed a blackbox settlement. Key terms include:
•A base rate increase of SPS’ request:approximately $89 million effective back to March 15, 2021.
Rate Request (Millions of Dollars)•A 9.35% ROE and 7.01% weighted average cost of capital for AFUDC purposes only.
Sagamore wind project$67 
Other capital investments25 
Cost of capital20 
Property taxes8 
Reduced sales, partially offset by changes in O&M8 
Allocator changes4 
Depreciation rate change3 
Other, net8 
Total rate request$143 
Fuel cost reductions and PTCs — Sagamore wind project(69)
Net rate increase$74 
SPS is requesting•The depreciation lives for Tolk moved up to 2034 and Harrington coal assets moved up to 2024.
In February 2022, the PUCT set currentALJ issued an order approving interim rates as temporaryto be effective on March 15, 2021. Once final rates are approved, a surcharge will be requested from March 15, 2021 through the effective date of new base rates.1, 2022. A PUCT decision is expected in the first quarter of 2022.
Texas State ROFR Litigation — In May 2019, the Governor signed a ROFR bill into law, 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. In February 2020, the federal court complaint was dismissed by the district court. In March 2020, the district court ruling was appealed to the Fifth Circuit. A decision is pending.
New Mexico FPPCAC Continuation — In December 2020, the Hearing Examiner recommended the NMPRC approve SPS’ request for the continued use of the FPPCAC and the reconciliation of its fuel costs for the reporting period (September 2015 through June 2019). Additionally, the Hearing Examiner recommended the NMPRC deny the proposed Annual Deferred Fuel Balance True-Up. The proposed true-up is designed to maintain the Deferred Fuel and Purchased Power balance within a bandwidth of plus or minus 5% of annual New Mexico fuel and purchased power costs. A decision is pending.
Resource Plan — SPS is required to file an IRP in New Mexico every three years and will file its next IRP in July 2021.
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.
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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, 20202021 and 2019,2020, Xcel Energy had regulatory assets of $3.8 billion and $3.4 billion, respectively and regulatory liabilities of $5.6$5.7 billion and $5.5$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.
At Dec. 31, 2020,2021, 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. Tax accrual estimates are trued-up to the actual amounts claimed on the tax returns and further adjusted after examinations by taxing authorities, as needed.
In accordance with the interim period reporting guidance, income tax expense for the first three quarters in a year is based on the forecasted annual ETR. The forecasted ETR reflects a number of estimates, including forecasted annual income, permanent tax adjustments and tax credits.
Valuation allowances are applied to deferred tax assets if it is more likely than not that at least a portion may not be realized based on an evaluation of expected future taxable income. Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized. We may adjust our unrecognized tax benefits and interest accruals as disputes with the IRS and state tax authorities are resolved, and as new developments occur. These adjustments may increase or decrease earnings.
See Note 7 to the consolidated financial statements for further information.
Employee Benefits
We sponsor several noncontributory, defined benefit pension plans and other postretirement benefit plans that cover almost all employees and certain retirees. Projected benefit costs are based on historical information and actuarial calculations that include key assumptions (annual return level on pension and postretirement health care investment assets, discount rates, mortality rates and health care cost trend rates, etc.). In addition, the pension cost calculation uses a methodology to reduce the volatility of investment performance over time. Pension assumptions are continually reviewed.
At Dec. 31, 2020,2021, Xcel Energy set the rate of return on assets used to measure pension costs at 6.49%, which represents a 38 basis point decrease fromis consistent with the rate set in 2019.2020. The rate of return used to measure postretirement health care costs is 4.10% at Dec. 31, 2020,2021, which represents a 40 basis point decrease from 2019.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 2.71%3.08% and postretirement health care obligations at 2.65%3.09% at Dec. 31, 2020.2021. This represents a 7837 basis point and 8244 basis point decrease, respectively, from 2019.2020. 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 20202021 pension costs:
Pension CostsPension Costs
(Millions of Dollars)(Millions of Dollars)+1%-1%(Millions of Dollars)+1%-1%
Rate of returnRate of return$(16)$22 Rate of return$(13)$23 
Discount rate (a)
Discount rate (a)
$(5)$13 
Discount rate (a)
$1 $15 
(a)These costcosts include the effects of regulation.
Mortality rates are developed from actual and projected plan experience for pension plan and postretirement benefits. Xcel Energy’s actuary conducts an experience study periodically to determine an estimate of mortality. Xcel Energy considers standard mortality tables, improvement factors and the plans actual experience when selecting a best estimate.
As of Dec. 31, 2020,2021, the initial medical trend cost claim assumptions for Pre-65 was 5.5%5.3% and Post-65 was 5.0%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.
Funding contributions in 2021 were $125$131 million and are expected to decline in the following years. Investment returns exceeded assumed levels in 2021, 2020 and 2019 and were below assumed levels in 2018.2019.
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The pension cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value is determined by adjusting the fair market value of assets at the beginning of the year to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20% per year. As differences between actual and expected investment returns are incorporated into the market-related value, amounts are recognized in pension cost over the expected average remaining years of service for active employees (approximately 13 years in 2020)2021).
Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be $106$77 million in 20212022 and $83$60 million in 2022,2023, while the actual pension costs were $121 million in 2021 and $117 million in 2020 and $115 million in 2019.2020. The expected decrease in 20212022 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 20182019 - 2021:2022:
•$12550 million in January 2022.
•$131 million in 2021.
•$150 million in 2020.
•$154 million in 2019.
•$150 million in 2018.
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 $15 million during 2021, 2020 and $11 million during 2020, 2019, and 2018, respectively, to the postretirement health care plans. Xcel Energy expects to contribute approximately $10$9 million during 2021.2022. 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.
•In 2018,2021, the PSCW approved NSP-Wisconsin’s request for deferred accounting treatment of the 20182021 pension settlement accounting 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.
•PSCo and SPS recognize pension expense in all regulatory jurisdictions based on GAAP. The Texas and Colorado electric retail jurisdictions and the Colorado gas retail jurisdiction, each record the difference between annual recognized pension expense and the annual amount of pension expense approved in their last respective general rate case as a deferral to a regulatory asset.
•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 Xcel Energy revises any assumptions, it adjusts the carrying amount of both the ARO liability and related long-lived asset. ARO liabilities are accreted to reflect the passage of time using the interest method.
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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 2021 and $2.0 billion in 2020 and $2.1 billion in 2019.2020.
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 annual accrual (funding/recovery) set for 2019 and 2020currently approved triennial filing was based on the 2014 nuclear decommissioning filing, approved in 2015. Althoughordered by the MPUC approved an increased accrual from the 2017 triennial filing in January 2019,2019. This approval did not result in a change to the ARO liability. In December 2020, the MPUC subsequently ordered Xcel Energy to maintain the current accrual level (previously established viathrough 2021 to align with the 2014 filing) through 2020.
Inapproved one year stay out of the previously filed multi-year electric rate case. Also, in December 2020, Xcel Energy submitted a 2020 triennial nuclear decommissioning filingfiled an accrual proposal with the MPUC to the MPUC. The filing resultedbe effective in 2022 based on an updated annual accrual of $33 million, or an increase of $19 million compared to the currently approved funding level.independent cost study. In December 2020,2021, Xcel Energy submitted its petition for approval of the 2022-2024 NSP-Minnesota’s Nuclear Decommission Study and Assumptions. Xcel Energy anticipates the MPUC verbally approved NSP-Minnesota to continue using the 2014deliberate on this filing as the basis for 2021. The filing was also used to revise the estimated ARO liability as of Dec. 31, 2020 ($216 million decrease).in 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. Decommissioning activities are expected to begin at the end of the license date and be completed for both facilities by 2095.2091.
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.


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Escalation Rates — Escalation rates represent projected cost increases due to general inflation and increases in the cost of decommissioning activities. NSP-Minnesota appliedused an escalation ratesrate of 3.1% for PI and 3.2% for Monticello in calculating the ARO for nuclear decommissioning AROs,of its nuclear facilities, based on weighted averages of labor and non-labor escalation factors calculated by Goldman Sachs Asset Management.
Discount Rates — Changes in timing or estimated cash flows that result in upward revisions to the ARO are calculated using the then-current credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect when the change occurs is used to discount the revised estimate of the incremental expected cash flows of the retirement activity.
If the change in timing or estimated expected cash flows results in a downward revision of the ARO, the undiscounted revised estimate of expected cash flows is discounted using the credit-adjusted risk-free rate in effect at the date of initial measurement and recognition of the original ARO. Discount rates ranging from approximately 3% to 7% have been used to calculate the net present value of the expected future cash flows over time.
Significant uncertainties exist in estimating future costs including the method to be utilized, ultimate costs to decommission and planned method of disposing spent fuel. If different cost estimates, life assumptions or cost escalation rates were utilized, the AROs could change materially.
However, changes in estimates have minimal impact on results of operations as NSP-Minnesota expects to continue to recover all costs in future rates.
Xcel 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, 2020.2021.
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 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 some 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 our electric and natural gas operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows 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, 2020:2021:
Futures / Forwards MaturityFutures / Forwards Maturity
(Millions of Dollars)(Millions of Dollars)
Less Than
1 Year
1 to 3 Years4 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)
NSP-Minnesota (a)
$(2)$1 $2 $2 $3 
NSP-Minnesota (a)
$(4)$(7)$— $(1)$(12)
NSP-Minnesota (b)
NSP-Minnesota (b)
(3)3 (7)(6)(13)
NSP-Minnesota (b)
(1)3 (9)(8)(15)
PSCo (a)
PSCo (a)
— 1 — — 1 
PSCo (a)
6 6 1 1 14 
PSCo (b)
PSCo (b)
(25)(39)(13)— (77)
PSCo (b)
(37)(48)— — (85)
$(30)$(34)$(18)$(4)$(86)$(36)$(46)$(8)$(8)$(98)
Options MaturityOptions Maturity
(Millions of Dollars)(Millions of Dollars)
Less Than
1 Year
1 to 3 Years4 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 (b)
NSP-Minnesota (b)
$1 $— $— $1 $2 
NSP-Minnesota (b)
$1 $— $— $8 $9 
PSCo (b)
PSCo (b)
13 16 1 — 30 
PSCo (b)
27 29 — — 56 
$14 $16 $1 $1 $32 $28 $29 $— $8 $65 
(a)Prices actively quoted or based on actively quoted prices.
(b)Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:
(Millions of Dollars)(Millions of Dollars)20202019(Millions of Dollars)20212020
Fair value of commodity trading net contracts outstanding at Jan. 1Fair value of commodity trading net contracts outstanding at Jan. 1$(59)$17 Fair value of commodity trading net contracts outstanding at Jan. 1$(54)$(59)
Contracts realized or settled during the periodContracts realized or settled during the period(9)(22)Contracts realized or settled during the period(54)(9)
Commodity trading contract additions and changes during the periodCommodity trading contract additions and changes during the period14 (54)Commodity trading contract additions and changes during the period75 14 
Fair value of commodity trading net contracts outstanding at Dec. 31Fair value of commodity trading net contracts outstanding at Dec. 31$(54)$(59)Fair value of commodity trading net contracts outstanding at Dec. 31$(33)$(54)
At Dec. 31, 2020,2021, 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, 2019,2020, 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. Market price movements can exceed 10% under abnormal circumstances.
The utility subsidiaries’ commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations 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.

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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)(Millions of Dollars)Year Ended
Dec. 31		VaR LimitAverageHighLow(Millions of Dollars)Year Ended
Dec. 31		VaR LimitAverageHighLow
20212021$1 $3 $2 $52 $1 
20202020$1 $3 $1 $2 $1 20201 3 1 2 1 
2019< 13 1 1 < 1
A short-term increase in VaR occurred during the week of Feb. 12, 2021 through Feb. 18, 2021. On Feb. 17, 2021, the portfolio VaR reached a high of $52 million. This increase in VaR was driven by the unprecedented market conditions during Winter Storm Uri. Prior to this widespread weather event, VaR was $1 million and returned to $1 million by Feb. 19, 2021.
Nuclear Fuel Supply — NSP-Minnesota has contracted for approximately 11%78% of its 20212022 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 28%30% of its average enriched nuclear material requirements from these sources. NSP-Minnesota is able to manage nuclear fuel 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 pretax interest expense annually by approximately $11 million and $6 million in 20202021 and 2019,2020, 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. Xcel 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, 2021, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $36 million, while a decrease in prices of 10% would have resulted in a decrease in credit exposure of $26 million. At Dec. 31, 2020, a 10% increase in commodity prices would have resulted in an increase in credit exposure of $11 million, while a decrease in prices of 10% would have resulted in an immaterial increase in credit exposure. At Dec. 31, 2019, a 10% increase in commodity prices would have resulted in an increase in credit exposure
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Table of $19 million, while a decrease in prices of 10% would have resulted in an increase in credit exposure of $14 million.Contents
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 and normal sale contracts, are reported at fair value.
Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting.
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, 2020.2021.
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, 2020.2021.
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)Twelve Months Ended Dec. 31
Cash provided by operating activities — 20192020$3,2632,848 
Components of change — 20202021 vs. 20192020
Higher net income101124 
Non-cash transactions (a)
(49)52 
Changes in working capital (b)
(222)(50)
Changes in net regulatory and other assets and liabilities(245)(785)
Cash provided by operating activities — 20202021$2,8482,189 
(a)    Non-cash transactions applicable to net income (e.g., depreciation, and amortization, nuclear fuel amortization, changes in deferred income taxes, allowance for equity funds used during construction, etc.).
(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 $415$659 million for 20202021 as compared to 2019. Decrease2020. The decrease was primarily due to changes in accounts receivablethe deferral of net natural gas, fuel and purchased energy costs related to increased residential sales, timing of regulatory asset recovery and inventory wind turbine purchases, which were partially offset by an increaseWinter Storm Uri in net income.










the first quarter.
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Investing Cash Flows
(Millions of Dollars)Twelve Months Ended Dec. 31
Cash used in investing activities — 20192020$(4,343)(4,740)
Components of change — 20202021 vs. 20192020
IncreasedDecreased capital expenditures(1,144)1,125 
Sale of MEC in 2020684 (684)
Other investing activities6312 
Cash used in investing activities — 20202021$(4,740)(4,287)
Net cash used in investing activities increaseddecreased by $397$453 million for 20202021 as compared to 2019. 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, including Sagamore, Cheyenne Ridge, Blazing Star 1 and Crowned Ridge 2.projects.





Financing Cash Flows
(Millions of Dollars)Twelve Months Ended Dec. 31
Cash provided by financing activities — 20192020$1,1811,773 
Components of change — 20202021 vs. 20192020
Higher debt issuances452202 
HigherLower repayments of long-term debt(52)584 
HigherLower proceeds from issuance of common stock269 (361)
Higher dividends paid to shareholders(65)(79)
Other financing activities(12)16 
Cash provided by financing activities — 20202021$1,7732,135 
Net cash provided by financing activities increased by $592$362 million for 20202021 as compared to 2019. Increase2020. The increase was primarily attributable to higher proceeds fromthe amount/timing of debt issuances of long-term debt and common stock (duerepayments, changes in capital investment and incremental financing due to forward equity agreements settlingthe lag in November 2020 and August 2019), partially offset by higher repayments of long-term debt and dividends paid.recovery costs associated with Winter Storm Uri.
See Note 5 to the consolidated financial statements for further information.
Capital Requirements
Xcel Energy has contractual obligations and other commitments that will need to be funded in the future. 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 — Xcel Energy has contractual obligations and other commitments that will need to be funded in the future. Contractual obligations and other commercial commitments as of Dec. 31, 2020:
Payments Due by PeriodPayments Due by Period (as of Dec. 31, 2021)
(Millions of Dollars)(Millions of Dollars)TotalLess than 1 Year1 to 3 Years3 to 5 YearsAfter 5 Years(Millions of Dollars)TotalLess than 1 Year1 to 3 Years3 to 5 YearsAfter 5 Years
Long-term debt, principal and interest paymentsLong-term debt, principal and interest payments$34,312 $1,183 $3,249 $3,107 $26,773 Long-term debt, principal and interest payments$37,014 $1,419 $3,323 $3,175 $29,097 
Finance lease obligationsFinance lease obligations257 14 24 22 197 Finance lease obligations242 12 24 19 187 
Operating leases obligations (a)
Operating leases obligations (a)
1,859 273 497 434 655 
Operating leases obligations (a)
1,594 256 478 363 497 
Unconditional purchase obligations (b)
Unconditional purchase obligations (b)
5,005 1,366 1,585 911 1,143 
Unconditional purchase obligations (b)
4,837 1,718 1,538 617 964 
Other long-term obligations, including current portion(c)Other long-term obligations, including current portion(c)637 74 63 60 440 Other long-term obligations, including current portion(c)40 36 4 — — 
Other short-term obligationsOther short-term obligations420 420 — — — Other short-term obligations455 455 — — — 
Short-term debtShort-term debt584 584 — — — Short-term debt1,005 1,005 — — — 
Total contractual cash obligationsTotal contractual cash obligations$43,074 $3,914 $5,418 $4,534 $29,208 Total contractual cash obligations$45,187 $4,901 $5,367 $4,174 $30,745 
(a)Included in operating lease obligations are $247 $229 million, $446$430 million, $398$335 million and $561$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 Inc. and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its fuel (nuclear, natural gas and coal) requirements. Additionally, the utility subsidiaries of Xcel Energy Inc. have entered into non-lease purchase power agreements. Certain contractual purchase obligations are adjusted on indices. Effects of price changes are mitigated through cost of energy adjustment mechanisms.
(c)Primarily consists of contracts for information technology services.
Capital Expenditures — TheBase capital forecasts for Xcel Energy for 2021 through 2025 are detailed in the following tables. The baseexpenditures and incremental capital forecast has been updated to reflect the MPUC’s approval of the $750 million wind repowering proposal. In addition, the base capital forecast reflects a change in the timing of completion of a wind project from 2020 to 2021.forecasts:
ActualBase Capital Forecast (Millions of Dollars)ActualBase Capital Forecast (Millions of Dollars)
By Regulated UtilityBy Regulated Utility2020202120222023202420252021 - 2025 TotalBy Regulated Utility2021202220232024202520262022 - 2026 Total
PSCoPSCo$1,600 $1,700 $1,835 $1,750 $1,695 $1,655 $8,635 PSCo$1,625 $1,930 $1,850 $2,070 $2,220 $1,860 $9,930 
NSP-MinnesotaNSP-Minnesota1,955 1,930 1,785 1,785 1,915 1,890 9,305 NSP-Minnesota1,885 2,250 2,030 1,830 2,130 2,010 10,250 
SPSSPS1,180 505 710 770 735 675 3,395 SPS555 630 660 690 780 790 3,550 
NSP-WisconsinNSP-Wisconsin235 360 430 395 515 470 2,170 NSP-Wisconsin290 480 420 540 460 390 2,290 
Other (a)
Other (a)
(135)(20)(15)10 10 10 (5)
Other (a)
25 (10)— 10 (30)10 (20)
Total base capital expendituresTotal base capital expenditures$4,835 $4,475 $4,745 $4,710 $4,870 $4,700 $23,500 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).
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TableAdditional capital investment in renewable generation and transmission may be needed in the five-year forecast pending approval of Contents
ActualBase Capital Forecast (Millions of Dollars)
By Function2020202120222023202420252021 - 2025 Total
Electric distribution$980 $1,205 $1,440 $1,550 $1,505 $1,475 $7,175 
Electric transmission695 870 1,285 1,285 1,270 1,290 6,000 
Electric generation445 630 575 560 750 975 3,490 
Natural gas580 615 615 665 670 625 3,190 
Other345 545 575 485 405 335 2,345 
Renewables1,790 610 255 165 270 — 1,300 
Total base capital expenditures$4,835 $4,475 $4,745 $4,710 $4,870 $4,700 $23,500 
Incremental Capital Forecast (Millions of Dollars) (a)
NSP-Minnesota Proposal202120222023202420252021 - 2025 Total
Sherco solar$30 $200 $320 $— $— $550 
Wind PPA buyout25 185 — — — 210 
Total incremental capital$55 $385 $320 $— $— $760 
(a)    Reflectsregulatory 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 investment underexpenditures estimated between $1.0 to $1.5 billion (assuming Xcel Energy were to own ~50% of the Minnesota Reliefrenewables). Additionally, the associated $0.5 billion to $1.0 billion of network upgrades, voltage support and Recovery Plan, which will require MPUC approval. The incrementalinterconnection 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 is not included in the base capital forecast.would likely be funded with approximately 50% equity and 50% debt.
Xcel Energy’s capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives (e.g., federal clean energy and tax policy), reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and mergers,merger, acquisition and divestiture opportunities.
Financing for Capital Expenditures through 20252026 — 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. Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies, and other factors.
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Current estimated financing plans of Xcel Energy for 2021 - 2025:
2022 through 2026:
(Millions of Dollars)
Funding Capital Expenditures
Cash from operations (a)
$15,00017,640 
New debt (b)
7,4907,110 
Equity through the DRIP and benefit program410450 
Other equity600800 
Base capital expenditures 2021 - 2025$23,50026,000 
Maturing Debt$3,8203,900 
(a) Net of dividends and pension funding.
(b) Reflects a combination of short and long-term debt; net of refinancing.
The incremental renewable capital expenditures would be financed with approximately 50% debt and 50% equity, if approved by the MPUC.
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 2021, Xcel Energy announced a quarterly dividend of $0.4575 per share, which represents an increase of 6.4%.
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, 2020Dec. 31, 2019
Fair value of pension assets$3,599 $3,184 
Projected pension obligation (a)
3,964 3,701 
Funded status$(365)$(517)
(a)Excludes non-qualified plan of $43 million and $39 million at Dec. 31, 2020 and 2019, respectively.
Pension Assumptions20202019
Discount rate2.71 %3.49 %
Expected long-term rate of return6.49 6.87 
Capital Sources
Short-Term Funding Sources — Xcel Energy generally funds short-term needs, through operating cash flow, 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.
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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.
In addition, in December 2020, Xcel Energy Inc. repaid its $500 million Term Loan Agreement. In September 2020, Xcel Energy Inc. repaid its $700 million Term Loan Agreement.
Xcel Energy’s outstanding short-term debt:
(Amounts in Millions, Except Interest Rates)Three Months Ended Dec. 31, 2020
Borrowing limit$3,100 
Amount outstanding at period end584 
Average amount outstanding415 
Maximum amount outstanding613 
Weighted average interest rate, computed on a daily basis0.60 %
Weighted average interest rate at end of period0.23 
(Amounts in Millions, Except Interest Rates)Year Ended Dec. 31, 2020Year Ended Dec. 31, 2019Year Ended Dec. 31, 2018
Borrowing limit$3,100 $3,600 $3,250 
Amount outstanding at period end584 595 1,038 
Average amount outstanding1,126 1,115 788 
Maximum amount outstanding2,080 1,780 1,349 
Weighted average interest rate, computed on a daily basis1.45 %2.72 %2.34 %
Weighted average interest rate at end of period0.23 2.34 2.97 
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. 16, 2021, 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 $696 $554 $2 $556 
PSCo700 142 558 2 560 
NSP-Minnesota500 129 371 2 373 
SPS500 341 159 1 160 
NSP-Wisconsin150 — 150 5 155 
Total$3,100 $1,308 $1,792 $12 $1,804 
(a)Credit facilities expire in June 2024.
(b)Includes outstanding commercial paper and letters of credit.
Registration Statements — Xcel Energy Inc.’s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2020 and 2019, Xcel Energy had approximately 537 million shares and 525 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 2021 financing plans reflect the following:
•Xcel Energy Inc. — approximately $1.2 billion in debt financing.
•PSCo — approximately $750 million of first mortgage bonds.
•SPS — approximately $250 million of first mortgage bonds.
•NSP-Minnesota — approximately $850 million of first mortgage bonds.
•NSP-Wisconsin — approximately $125 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 Xcel Energy common stock. In August 2019, Xcel Energy settled the forward equity agreements by 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 Xcel Energy common stock. In November 2020, Xcel Energy settled the forward equity agreements by delivering 11.8 million shares of common equity for cash proceeds of $721 million.
Equity through DRIP and Benefits Program — Xcel Energy also plans to issue approximately $75 to $90 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.
Natural Gas Fuel and Electricity Purchases
In February 2021, the United States experienced winter storm Uri and extreme cold temperatures in the central United States. This severe weather event increased the demand for natural gas used in our electric and natural gas businesses. Certain operational assets were impacted by extreme cold temperatures and safety protocols and the cold further impacted the availability of renewable generation across the region (which typically acts as a hedge against commodity prices) contributing to extremely high market prices for natural gas and electricity. As a result, electric and natural gas fuel costs increased approximately $1.2 billion (PSCo - $650 million, NSP-Minnesota - $300 million, SPS - $200 million and NSP-Wisconsin - $45 million). These amounts are preliminary estimates through Feb. 16, 2021 and are subject to final settlement.
Xcel Energy has fuel recovery mechanisms in all of its states to recover the increased cost of natural gas and electricity. However, given the impact of these higher costs to our customers during a pandemic, we expect our regulators to undertake a heightened review and we intend to work with our commissions to recover these costs over time to help mitigate the impacts on customer bills. Xcel Energy is taking action to increase planned debt issuances to ensure adequate liquidity for the timing difference between fuel payments and revenue collection from customers and to address any potential need to post collateral.

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Earnings Guidance
2021 GAAP and ongoing earnings guidance is a range of $2.90 to $3.00 per share. (a)
Key assumptions as compared with 2020 levels unless noted:
•Constructive outcomes in all rate case and regulatory proceedings.
•Modest impacts from COVID-19.
•Normal weather patterns for the remainder of the year.
•Weather-normalized retail electric sales are projected to increase ~1%.
•Weather-normalized retail firm natural gas sales are projected to be relatively flat.
•Capital rider revenue is projected to increase $105 million to $115 million (net of PTCs). The change reflects the deferral of advanced grid costs, which were denied rider recovery. PTCs are credited to customers, through capital riders, fuel clause or base rates and results in a reduction to electric margin.
•O&M expenses are projected to be relatively flat.
•Depreciation expense is projected to increase approximately $195 million to $205 million.
•Property taxes are projected to increase approximately $45 million to $55 million.
•Interest expense (net of AFUDC - debt) is projected to increase $0 million to $10 million.
•AFUDC - equity is projected to decline approximately $45 million to $55 million.
•ETR is projected to be ~(9%). 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.
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:
COVID-19(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 
Although the COVID-19 pandemic has led to numerous challenges,
(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 believesInc., 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 risk management program, including business continuity and disaster recovery planning, will continueutility subsidiaries had the following committed credit facilities available to allow us to proactively manage and successfully navigate challenges, risks and uncertainties.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.
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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.
There
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 continued uncertainty regarding COVID-19,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 durationyear.
•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 magnitudereductions 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 business restrictions, re-shut downsAFUDC - 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 the level and pace of economic recovery. Also, while we may implement contingency plans, there are no guarantees these plans will be sufficient to offset the impact of the pandemic, which couldnot have a material impact on our resultsnet 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 operations, financial condition ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or cash flow.
An overview of certain risk considerations or areas which have or could significantly impact us, is as follows.
Sales —unknown adjustments. Xcel Energy has experiencedis 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 may continue to experience higher residential sales and lower C&I sales as a result of COVID-19. Dividend Growth Rate Objectives —Xcel Energy has decouplingexpects to deliver an attractive total return to our shareholders through a combination of earnings growth and sales true-up mechanismsdividend 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 Minnesota (all electric classes) and Colorado (residential and non-demand small C&I electric classes), which mitigate the impact of changes to sales levels as compared to a baseline.A range.
Bad Debt — Bad debt expense could significantly increase due to pandemic related economic impacts, customer hardship, federal or state legislation and regulatory orders. However, several of our commissions have approved the deferral of incremental COVID-19 related expense, including bad debt expense.
Xcel Energy has received orders in Colorado, Wisconsin, Texas, New Mexico, North Dakota, South Dakota and Michigan, allowing regulatory deferral of incremental COVID-19 costs as a regulatory asset subject to future determination of amount and timing of recovery. As part of NSP-Minnesota’s stay-out alternative, NSP-Minnesota agreed to not seek recovery of incremental COVID-19 related costs.
The majority of wholesale customers are subject to formula transmission and production rates, which true-up rates to actual costs to serve.
Supply Chain and Capital Expenditures — Xcel Energy’s ability to meet customer energy requirements, respond to storm-related disruptions and execute our capital expenditure program are dependent on maintaining an efficient supply chain. During 2020, Xcel Energy did not experience supply chain, contractor or employee disruptions with the exception of delays in certain wind projects.
Liquidity — Xcel Energy took steps to enhance its liquidity in 2020 and believes it has more than adequate liquidity. Xcel Energy will take steps to enhance liquidity in 2021 if needed.
ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See the “Derivatives, Risk Management and Market Risk” section in Item 7, incorporated by reference.
ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See Item 15-1 for an index of financial statements included herein.
See Note 15 to the consolidated financial statements for further information.
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Management Report on Internal Control Over Financial Reporting
The management of Xcel Energy Inc. is responsible for establishing and maintaining adequate internal control over financial reporting. Xcel Energy Inc.’s internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s management and Board of Directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Xcel Energy Inc. management assessed the effectiveness of Xcel Energy Inc.’s internal control over financial reporting as of Dec. 31, 2020.2021. 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, 2020,2021, 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/ BEN FOWKEROBERT C. FRENZEL/s/ BRIAN J. VAN ABEL
Ben FowkeRobert C. FrenzelBrian J. Van Abel
Chairman, President, Chief Executive Officer and DirectorExecutive Vice President, Chief Financial Officer
Feb. 17, 202123, 2022Feb. 17, 202123, 2022

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of Xcel Energy Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Xcel Energy Inc. and subsidiaries (the "Company") as of December 31, 20202021 and 2019,2020, 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, 2020,2021, 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, 2020,2021, 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, 20202021 and 2019,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020,2021, 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, 2020,2021, 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 generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.




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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 precedents of the Commissions’ treatment of similar costs under similar circumstances. We also evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. If the full recovery of project costs is being challenged by intervenors, we evaluated management’s assessment of the probability of a disallowance. We evaluated the external information and compared to the Company’s recorded regulatory assets and liabilities for completeness.
•We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 17, 202123, 2022
We have served as the Company’s auditor since 2002.


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

Year Ended Dec. 31Year Ended Dec. 31
202020192018202120202019
Operating revenuesOperating revenuesOperating revenues
ElectricElectric$9,802 $9,575 $9,719 Electric$11,205 $9,802 $9,575 
Natural gasNatural gas1,636 1,868 1,739 Natural gas2,132 1,636 1,868 
OtherOther88 86 79 Other94 88 86 
Total operating revenuesTotal operating revenues11,526 11,529 11,537 Total operating revenues13,431 11,526 11,529 
Operating expensesOperating expensesOperating expenses
Electric fuel and purchased powerElectric fuel and purchased power3,512 3,510 3,854 Electric fuel and purchased power4,733 3,512 3,510 
Cost of natural gas sold and transportedCost of natural gas sold and transported689 918 843 Cost of natural gas sold and transported1,081 689 918 
Cost of sales — otherCost of sales — other37 40 35 Cost of sales — other38 37 40 
Operating and maintenance expensesOperating and maintenance expenses2,324 2,338 2,352 Operating and maintenance expenses2,321 2,324 2,338 
Conservation and demand side management expensesConservation and demand side management expenses288 285 290 Conservation and demand side management expenses304 288 285 
Depreciation and amortizationDepreciation and amortization1,948 1,765 1,642 Depreciation and amortization2,121 1,948 1,765 
Taxes (other than income taxes)Taxes (other than income taxes)612 569 556 Taxes (other than income taxes)630 612 569 
Total operating expensesTotal operating expenses9,410 9,425 9,572 Total operating expenses11,228 9,410 9,425 
Operating incomeOperating income2,116 2,104 1,965 Operating income2,203 2,116 2,104 
Other (expense) income, net(6)16 (14)
Equity earnings of unconsolidated subsidiaries40 39 35 
Other income (expense), netOther income (expense), net5 (6)16 
Earnings from equity method investmentsEarnings from equity method investments62 40 39 
Allowance for funds used during construction — equityAllowance for funds used during construction — equity115 77 108 Allowance for funds used during construction — equity73 115 77 
Interest charges and financing costsInterest charges and financing costsInterest charges and financing costs
Interest charges — includes other financing costs of $28, $26 and $25, respectively840 773 700 
Interest charges — includes other financing costs of $29, $28 and $26, respectivelyInterest charges — includes other financing costs of $29, $28 and $26, respectively842 840 773 
Allowance for funds used during construction — debtAllowance for funds used during construction — debt(42)(37)(48)Allowance for funds used during construction — debt(26)(42)(37)
Total interest charges and financing costsTotal interest charges and financing costs798 736 652 Total interest charges and financing costs816 798 736 
Income before income taxesIncome before income taxes1,467 1,500 1,442 Income before income taxes1,527 1,467 1,500 
Income tax (benefit) expenseIncome tax (benefit) expense(6)128 181 Income tax (benefit) expense(70)(6)128 
Net incomeNet income$1,473 $1,372 $1,261 Net income$1,597 $1,473 $1,372 
Weighted average common shares outstanding:Weighted average common shares outstanding:Weighted average common shares outstanding:
BasicBasic527 519 511 Basic539 527 519 
DilutedDiluted528 520 511 Diluted540 528 520 
Earnings per average common share:Earnings per average common share:Earnings per average common share:
BasicBasic$2.79 $2.64 $2.47 Basic$2.96 $2.79 $2.64 
DilutedDiluted2.79 2.64 2.47 Diluted2.96 2.79 2.64 
See Notes to Consolidated Financial StatementsSee Notes to Consolidated Financial StatementsSee Notes to Consolidated Financial Statements
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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(amounts in millions)

Year Ended Dec. 31
202020192018
Net income$1,473 $1,372 $1,261 
Other comprehensive (loss) income
Pension and retiree medical benefits:
Net pension and retiree medical losses arising during the period, net of tax of $(2), $0 and $(2), respectively(5)0 (6)
Reclassification of losses to net income, net of tax of $3, $1 and $3, respectively10 3 9 
Derivative instruments:
Net fair value decrease, net of tax of $(3), $(8) and $(2), respectively(10)(23)(5)
Reclassification of losses to net income, net of tax of $2, $1 and $1, respectively5 3 3 
Total other comprehensive (loss) income0 (17)1 
Total comprehensive income$1,473 $1,355 $1,262 
See Notes to Consolidated Financial Statements
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

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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in millions)
Year Ended Dec. 31 Year Ended Dec. 31
202020192018 202120202019
Operating activitiesOperating activities  Operating activities  
Net incomeNet income$1,473 $1,372 $1,261 Net income$1,597 $1,473 $1,372 
Adjustments to reconcile net income to cash provided by operating activities:Adjustments to reconcile net income to cash provided by operating activities:Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortizationDepreciation and amortization1,959 1,785 1,659 Depreciation and amortization2,143 1,959 1,785 
Nuclear fuel amortizationNuclear fuel amortization123 119 122 Nuclear fuel amortization114 123 119 
Deferred income taxesDeferred income taxes(8)143 218 Deferred income taxes(79)(8)143 
Allowance for equity funds used during constructionAllowance for equity funds used during construction(115)(77)(108)Allowance for equity funds used during construction(73)(115)(77)
Equity earnings of unconsolidated subsidiaries(40)(39)(35)
Dividends from unconsolidated subsidiaries42 40 37 
Earnings from equity method investmentsEarnings from equity method investments(62)(40)(39)
Dividends from equity method investmentsDividends from equity method investments42 42 40 
Provision for bad debtsProvision for bad debts60 42 42 Provision for bad debts60 60 42 
Share-based compensation expenseShare-based compensation expense73 58 45 Share-based compensation expense31 73 58 
Net realized and unrealized hedging and derivative transactionsNet realized and unrealized hedging and derivative transactions(27)45 22 Net realized and unrealized hedging and derivative transactions(57)(27)45 
Changes in operating assets and liabilities:Changes in operating assets and liabilities:Changes in operating assets and liabilities:
Accounts receivableAccounts receivable(154)(20)(105)Accounts receivable(164)(154)(20)
Accrued unbilled revenuesAccrued unbilled revenues(3)42 9 Accrued unbilled revenues(149)(3)42 
InventoriesInventories(80)(84)(65)Inventories(126)(80)(84)
Other current assetsOther current assets(45)25 18 Other current assets(34)(45)25 
Accounts payableAccounts payable(33)(12)90 Accounts payable138 (33)(12)
Net regulatory assets and liabilitiesNet regulatory assets and liabilities(144)(66)223 Net regulatory assets and liabilities(973)(144)(66)
Other current liabilitiesOther current liabilities29 (15)(61)Other current liabilities(1)29 (15)
Pension and other employee benefit obligationsPension and other employee benefit obligations(125)(135)(179)Pension and other employee benefit obligations(135)(125)(135)
Other, netOther, net(137)40 (71)Other, net(83)(137)40 
Net cash provided by operating activitiesNet cash provided by operating activities2,848 3,263 3,122 Net cash provided by operating activities2,189 2,848 3,263 
Investing activitiesInvesting activitiesInvesting activities
Capital/construction expendituresCapital/construction expenditures(5,369)(4,225)(3,957)Capital/construction expenditures(4,244)(5,369)(4,225)
Sale of MECSale of MEC684 0 0 Sale of MEC— 684 — 
Purchase of investment securitiesPurchase of investment securities(1,398)(995)(853)Purchase of investment securities(757)(1,398)(995)
Proceeds from the sale of investment securitiesProceeds from the sale of investment securities1,378 975 833 Proceeds from the sale of investment securities743 1,378 975 
Other, netOther, net(35)(98)(9)Other, net(29)(35)(98)
Net cash used in investing activitiesNet cash used in investing activities(4,740)(4,343)(3,986)Net cash used in investing activities(4,287)(4,740)(4,343)
Financing activitiesFinancing activitiesFinancing activities
(Repayments of) proceeds from short-term borrowings, net(11)(443)225 
Proceeds from (repayments of) short-term borrowings, netProceeds from (repayments of) short-term borrowings, net421 (11)(443)
Proceeds from issuances of long-term debtProceeds from issuances of long-term debt2,940 2,920 1,675 Proceeds from issuances of long-term debt2,710 2,940 2,920 
Repayments of long-term debt, including reacquisition premiumsRepayments of long-term debt, including reacquisition premiums(1,001)(949)(452)Repayments of long-term debt, including reacquisition premiums(417)(1,001)(949)
Proceeds from issuance of common stockProceeds from issuance of common stock727 458 230 Proceeds from issuance of common stock366 727 458 
Dividends paidDividends paid(856)(791)(730)Dividends paid(935)(856)(791)
Other, netOther, net(26)(14)(20)Other, net(10)(26)(14)
Net cash provided by financing activitiesNet cash provided by financing activities1,773 1,181 928 Net cash provided by financing activities2,135 1,773 1,181 
Net change in cash and cash equivalentsNet change in cash and cash equivalents(119)101 64 Net change in cash and cash equivalents37 (119)101 
Cash and cash equivalents at beginning of period248 147 83 
Cash and cash equivalents at end of period$129 $248 $147 
Cash, cash equivalents and restricted cash at beginning of periodCash, cash equivalents and restricted cash at beginning of period129 248 147 
Cash, cash equivalents and restricted cash at end of periodCash, cash equivalents and restricted cash at end of period$166 $129 $248 
Supplemental disclosure of cash flow information:Supplemental disclosure of cash flow information:Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)Cash paid for interest (net of amounts capitalized)$(758)$(698)$(633)Cash paid for interest (net of amounts capitalized)$(788)$(758)$(698)
Cash received for income taxes, net12 53 27 
Cash (paid) received for income taxes, netCash (paid) received for income taxes, net(4)12 53 
Supplemental disclosure of non-cash investing and financing transactions:Supplemental disclosure of non-cash investing and financing transactions:Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additionsAccrued property, plant and equipment additions$400 $421 $388 Accrued property, plant and equipment additions$501 $400 $421 
Inventory transfers to property, plant and equipmentInventory transfers to property, plant and equipment275 88 129 Inventory transfers to property, plant and equipment87 275 88 
Operating lease right-of-use assetsOperating lease right-of-use assets369 1,843 0 Operating lease right-of-use assets8 369 1,843 
Allowance for equity funds used during constructionAllowance for equity funds used during construction115 77 108 Allowance for equity funds used during construction73 115 77 
Issuance of common stock for equity awards67 63 67 
Issuance of common stock for reinvested dividends and/or equity awardsIssuance of common stock for reinvested dividends and/or equity awards60 67 63 
See Notes to Consolidated Financial StatementsSee Notes to Consolidated Financial StatementsSee Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in millions, except share and per share)
Dec. 31Dec. 31
2020201920212020
AssetsAssetsAssets
Current assetsCurrent assetsCurrent assets
Cash and cash equivalentsCash and cash equivalents$129 $248 Cash and cash equivalents$166 $129 
Accounts receivable, netAccounts receivable, net916 837 Accounts receivable, net1,018 916 
Accrued unbilled revenuesAccrued unbilled revenues714 713 Accrued unbilled revenues862 714 
InventoriesInventories535 544 Inventories631 535 
Regulatory assetsRegulatory assets640 488 Regulatory assets1,106 640 
Derivative instrumentsDerivative instruments49 55 Derivative instruments123 49 
Prepaid taxesPrepaid taxes42 43 Prepaid taxes44 42 
Prepayments and otherPrepayments and other250 185 Prepayments and other289 250 
Total current assetsTotal current assets3,275 3,113 Total current assets4,239 3,275 
Property, plant and equipment, netProperty, plant and equipment, net42,950 39,483 Property, plant and equipment, net45,457 42,950 
Other assetsOther assetsOther assets
Nuclear decommissioning fund and other investmentsNuclear decommissioning fund and other investments3,096 2,731 Nuclear decommissioning fund and other investments3,628 3,096 
Regulatory assetsRegulatory assets2,737 2,935 Regulatory assets2,738 2,737 
Derivative instrumentsDerivative instruments30 22 Derivative instruments67 30 
Operating lease right-of-use assetsOperating lease right-of-use assets1,490 1,672 Operating lease right-of-use assets1,291 1,490 
OtherOther379 492 Other431 379 
Total other assetsTotal other assets7,732 7,852 Total other assets8,155 7,732 
Total assetsTotal assets$53,957 $50,448 Total assets$57,851 $53,957 
Liabilities and EquityLiabilities and EquityLiabilities and Equity
Current liabilitiesCurrent liabilitiesCurrent liabilities
Current portion of long-term debtCurrent portion of long-term debt$421 $702 Current portion of long-term debt$601 $421 
Short-term debtShort-term debt584 595 Short-term debt1,005 584 
Accounts payableAccounts payable1,237 1,294 Accounts payable1,409 1,237 
Regulatory liabilitiesRegulatory liabilities311 407 Regulatory liabilities271 311 
Taxes accruedTaxes accrued578 466 Taxes accrued569 578 
Accrued interestAccrued interest203 192 Accrued interest209 203 
Dividends payableDividends payable231 212 Dividends payable249 231 
Derivative instrumentsDerivative instruments53 38 Derivative instruments69 53 
Operating lease liabilitiesOperating lease liabilities214 194 Operating lease liabilities205 214 
OtherOther407 468 Other459 407 
Total current liabilitiesTotal current liabilities4,239 4,568 Total current liabilities5,046 4,239 
Deferred credits and other liabilitiesDeferred credits and other liabilitiesDeferred credits and other liabilities
Deferred income taxesDeferred income taxes4,746 4,509 Deferred income taxes4,894 4,746 
Deferred investment tax creditsDeferred investment tax credits45 49 Deferred investment tax credits53 45 
Regulatory liabilitiesRegulatory liabilities5,302 5,077 Regulatory liabilities5,405 5,302 
Asset retirement obligationsAsset retirement obligations2,884 2,701 Asset retirement obligations3,151 2,884 
Derivative instrumentsDerivative instruments131 175 Derivative instruments105 131 
Customer advancesCustomer advances197 203 Customer advances196 197 
Pension and employee benefit obligationsPension and employee benefit obligations666 785 Pension and employee benefit obligations306 666 
Operating lease liabilitiesOperating lease liabilities1,344 1,549 Operating lease liabilities1,146 1,344 
OtherOther183 186 Other158 183 
Total deferred credits and other liabilitiesTotal deferred credits and other liabilities15,498 15,234 Total deferred credits and other liabilities15,414 15,498 
Commitments and contingenciesCommitments and contingencies00Commitments and contingencies00
CapitalizationCapitalizationCapitalization
Long-term debtLong-term debt19,645 17,407 Long-term debt21,779 19,645 
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 537,438,394 and 524,539,000 shares outstanding at Dec. 31, 2020 and Dec. 31, 2019, respectively1,344 1,311 
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, respectivelyCommon 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 capitalAdditional paid in capital7,404 6,656 Additional paid in capital7,803 7,404 
Retained earningsRetained earnings5,968 5,413 Retained earnings6,572 5,968 
Accumulated other comprehensive lossAccumulated other comprehensive loss(141)(141)Accumulated other comprehensive loss(123)(141)
Total common stockholders’ equityTotal common stockholders’ equity14,575 13,239 Total common stockholders’ equity15,612 14,575 
Total liabilities and equityTotal liabilities and equity$53,957 $50,448 Total liabilities and equity$57,851 $53,957 
See Notes to Consolidated Financial StatementsSee Notes to Consolidated Financial StatementsSee Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
(amounts in millions, except per share data; shares in thousands)actual amounts)
Common Stock IssuedRetained Earnings
Accumulated Other
Comprehensive Loss
Total Common Stockholders’ EquityCommon Stock IssuedRetained Earnings
Accumulated Other
Comprehensive Loss
Total Common Stockholders’ Equity
SharesPar ValueAdditional Paid
In Capital		SharesPar ValueAdditional Paid
In Capital
Balance at Dec. 31, 2017507,763 $1,269 $5,898 $4,413 $(125)$11,455 
Balance at Dec. 31, 2018Balance at Dec. 31, 2018514,036,787 $1,285 $6,168 $4,893 $(124)$12,222 
Net incomeNet income1,261 1,261 Net income1,372 1,372 
Other comprehensive incomeOther comprehensive income1 1 Other comprehensive income(17)(17)
Dividends declared on common stock ($1.52 per share)(780)(780)
Dividends declared on common stock ($1.62 per share)Dividends declared on common stock ($1.62 per share)(846)(846)
Issuances of common stockIssuances of common stock6,296 16 254 270 Issuances of common stock10,507,943 26 468 494 
Repurchases of common stockRepurchases of common stock(22)0 (1)(1)Repurchases of common stock(5,730)— — — 
Share-based compensationShare-based compensation17 (1)16 Share-based compensation20 (6)14 
Balance at Dec. 31, 2018514,037 $1,285 $6,168 $4,893 $(124)$12,222 
Balance at Dec. 31, 2019Balance at Dec. 31, 2019524,539,000 $1,311 $6,656 $5,413 $(141)$13,239 
Net IncomeNet Income1,372 1,372 Net Income1,473 1,473 
Other comprehensive loss(17)(17)
Dividends declared on common stock ($1.62 per share)(846)(846)
Issuances of common stock10,508 26 468 494 
Repurchase of common stock(6)0 0 0 
Share-based compensation20 (6)14 
Balance at Dec. 31, 2019524,539 $1,311 $6,656 $5,413 $(141)$13,239 
Net income1,473 1,473 
Dividends declared on common stock ($1.72 per share)Dividends declared on common stock ($1.72 per share)(909)(909)Dividends declared on common stock ($1.72 per share)(909)(909)
Issuances of common stockIssuances of common stock12,954 33 731 764 Issuances of common stock12,953,869 33 731 764 
Repurchase of common stockRepurchase of common stock(55)0 (4)(4)Repurchase of common stock(54,475)— (4)(4)
Share-based compensationShare-based compensation21 (7)14 Share-based compensation21 (7)14 
Adoption of ASC Topic 326Adoption of ASC Topic 326(2)(2)Adoption of ASC Topic 326(2)(2)
Balance at Dec. 31, 2020Balance at Dec. 31, 2020537,438 $1,344 $7,404 $5,968 $(141)$14,575 Balance at Dec. 31, 2020537,438,394 $1,344 $7,404 $5,968 $(141)$14,575 
Net incomeNet income1,597 1,597 
Other comprehensive incomeOther comprehensive income18 18 
Dividends declared on common stock ($1.83 per share)Dividends declared on common stock ($1.83 per share)(989)(989)
Issuances of common stockIssuances of common stock6,586,875 16 387 403 
Share-based compensationShare-based compensation12 (4)8 
Balance at Dec. 31, 2021Balance at Dec. 31, 2021544,025,269 $1,360 $7,803 $6,572 $(123)$15,612 
See Notes to Consolidated Financial StatementsSee Notes to Consolidated Financial StatementsSee Notes to Consolidated Financial Statements
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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 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 consolidated financial statements or notes have been reclassified for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.
Xcel Energy has evaluated events occurring after Dec. 31, 20202021 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.
•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 would be refundable to utility customers over the remaining life of the related assets. Xcel Energy anticipates that a tax rate increase would result in the establishment of a regulatory asset, subject to regulatory approval.an evaluation of whether future recovery is expected.
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Reversal of certain temporary differences are accounted for as current income tax expense due to the effects of past regulatory practices when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize 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 other (expense) income or interest charges in the consolidated statements of income, based on the underlying nature of the transaction.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 areis 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 and 3.1% for 2018.2019.
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.
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.
NSP-Minnesota recovers regulator-approved decommissioning costs of its nuclear power plants over each facility’s expected service life, typically based on the triennial decommissioning studies. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO.
Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning fund and other assets on the consolidated balance sheets.
See Notes 10 and 12 for further information.
Benefit Plans and Other Postretirement Benefits — Xcel Energy maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans requires management to make various assumptions and estimates.
Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms.
See Note 11 for further information.
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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 systematically throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized.
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-term physical wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO are recorded on a net basis in cost of sales.
See Note 6 for further information.
Cash and Cash Equivalents — Xcel Energy considers investments in instruments with a remaining maturity of 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.
As of Dec. 31, 20202021 and 2019,2020, the allowance for bad debts was $79$106 million and $55$79 million, respectively.
Inventory — Inventory is recorded at average cost and consisted of the following:
(Millions of Dollars)(Millions of Dollars)Dec. 31, 2020Dec. 31, 2019(Millions of Dollars)Dec. 31, 2021Dec. 31, 2020
InventoriesInventoriesInventories
Materials and suppliesMaterials and supplies$275 $270 Materials and supplies$289 $275 
FuelFuel176 191 Fuel182 176 
Natural gasNatural gas84 83 Natural gas160 84 
Total inventoriesTotal inventories$535 $544 Total inventories$631 $535 
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 and commodity trading activities, including forward contracts, futures, swaps and options. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.
Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues and interest rate hedging transactions are recorded as a component of interest expense.
Normal Purchases and Normal Sales — 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.
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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.
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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 Adopted
Credit Losses — In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards.
Xcel Energy implemented the guidance using a modified-retrospective approach, recognizing a cumulative effect charge of $2 million (after tax) to retained earnings on Jan. 1, 2020. Other than first-time recognition of an allowance for bad debts on accrued unbilled revenues, the Jan. 1, 2020, adoption of ASC Topic 326 did not have a significant impact on Xcel Energy’s consolidated financial statements.
3. Property, Plant and Equipment
Major classes of property, plant and equipment
(Millions of Dollars)(Millions of Dollars)Dec. 31, 2020Dec. 31, 2019(Millions of Dollars)Dec. 31, 2021Dec. 31, 2020
Property, plant and equipment, netProperty, plant and equipment, netProperty, plant and equipment, net
Electric plantElectric plant$47,104 $44,355 Electric plant$48,680 $47,104 
Natural gas plantNatural gas plant7,135 6,560 Natural gas plant7,758 7,135 
Common and other propertyCommon and other property2,503 2,341 Common and other property2,602 2,503 
Plant to be retired (a)
Plant to be retired (a)
677 259 
Plant to be retired (a)
1,200 677 
CWIPCWIP1,877 2,329 CWIP1,969 1,877 
Total property, plant and equipmentTotal property, plant and equipment59,296 55,844 Total property, plant and equipment62,209 59,296 
Less accumulated depreciationLess accumulated depreciation(16,657)(16,735)Less accumulated depreciation(17,060)(16,657)
Nuclear fuelNuclear fuel2,970 2,909 Nuclear fuel3,081 2,970 
Less accumulated amortizationLess accumulated amortization(2,659)(2,535)Less accumulated amortization(2,773)(2,659)
Property, plant and equipment, netProperty, plant and equipment, net$42,950 $39,483 Property, plant and equipment, net$45,457 $42,950 
(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 23 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.
Joint Ownership of Generation, Transmission and Gas Facilities
The utility subsidiaries’ jointly owned assets as of Dec. 31, 2020:2021:
(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationCWIPPercent Owned
NSP-Minnesota
Electric generation:
Sherco Unit 3$601 $435 $2 59 %
Sherco common facilities149 108 5 80 
Sherco substation5 3 0 59 
Electric transmission:
Grand Meadow11 3 0 50 
CapX2020954 108 33 51 
Total NSP-Minnesota$1,720 $657 $40 
(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationCWIPPercent Owned
NSP-Wisconsin
Electric transmission:
La Crosse, WI to Madison, WI$188 $12 $0 37 %
CapX2020169 23 0 80 
Total NSP-Wisconsin$357 $35 $0 
(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 
(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationCWIPPercent Owned
PSCo
Electric generation:
Hayden Unit 1$153 $92 $0 76 %
Hayden Unit 2150 73 0 37 
Hayden common facilities42 25 0 53 
Craig Units 1 and 281 44 0 10 
Craig common facilities39 24 0 7 
Comanche Unit 3899 137 16 67 
Comanche common facilities25 2 0 82 
Electric transmission:
Transmission and other facilities176 59 2 Various
Gas transmission:
Rifle, CO to Avon, CO22 8 0 60 
Gas transmission compressor8 1 0 50 
Total PSCo$1,595 $465 $18 
(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.
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(Millions of Dollars, Except Percent Owned)Plant in ServiceAccumulated DepreciationPercent Owned
PSCo
Electric generation:
Hayden Unit 1$156 $99 76 %
Hayden Unit 2151 78 37 
Hayden common facilities42 27 53 
Craig Units 1 and 281 48 10 
Craig common facilities39 25 7 
Comanche Unit 3917 154 67 
Comanche common facilities28 2 82 
Electric transmission:
Transmission and other facilities182 63 Various
Gas transmission:
Rifle, CO to Avon, CO22 8 60 
Gas transmission compressor8 2 50 
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.
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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)(Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2020Dec. 31, 2019(Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2021Dec. 31, 2020
Regulatory AssetsRegulatory AssetsCurrentNoncurrentCurrentNoncurrentRegulatory AssetsCurrentNoncurrentCurrentNoncurrent
Pension and retiree medical obligationsPension and retiree medical obligations11Various$82 $1,268 $85 $1,328 Pension and retiree medical obligations11Various$77 $944 $82 $1,268 
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 lives0 283 0 271 Recoverable deferred taxes on AFUDCPlant lives— 289 — 283 
Excess deferred taxes — TCJAExcess deferred taxes — TCJA7Various16 229 39 239 Excess deferred taxes — TCJA7Various14 219 16 229 
Depreciation differencesDepreciation differences
One to 11 years
16 154 15 140 Depreciation differences
One to 10 years
16 173 16 154 
Net AROs (a)
1, 12Various0 139 0 269 
Environmental remediation costsEnvironmental remediation costs1, 12Various16 113 36 131 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 purchaseBenson biomass PPA termination and asset purchase
Nine years
10 65 9 73 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 contract7 54 5 61 Purchased power contract costsTerm of related contract9 45 7 54 
PI extended power uprate14 years3 49 3 53 
Conservation programs (c)(a)
Conservation programs (c)(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)
Contract valuation adjustments (b)
1, 10Term of related contract23 48 20 62 
Contract valuation adjustments (b)
1, 10Term of related contract22 34 23 48 
Losses on reacquired debtTerm of related debt4 38 4 41 
State commission adjustmentsState commission adjustmentsPlant lives1 32 1 32 
Laurentian biomass PPA terminationLaurentian biomass PPA termination
Three years
18 36 19 54 Laurentian biomass PPA termination
Two years
18 18 18 36 
Conservation programs (c)(a)
1
One to two years
26 36 27 26 
State commission adjustmentsPlant lives1 32 1 31 
Sales true-up and revenue decoupling
One to two years
101 28 54 16 
Nuclear refueling outage costsNuclear refueling outage costs1
One to two years
37 16 28 10 
Property taxProperty taxVarious16 21 2 30 Property taxVarious16 16 16 21 
Deferred purchased natural gas and electric energy costs
One to two years
14 18 6 6 
Texas revenue surcharge
One to two years
54 17 2 0 
Renewable resources and environmental initiatives
One to two years
129 12 72 10 
Nuclear refueling outage costs1
One to two years
28 10 43 17 
Gas pipeline inspection and remediation costsGas pipeline inspection and remediation costs
One to two years
26 9 26 8 Gas pipeline inspection and remediation costs
One to two years
33 12 26 9 
Net AROs (c)
Net AROs (c)
1, 12Various— (112)— 139 
OtherOtherVarious50 78 20 69 OtherVarious84 78 50 78 
Total regulatory assetsTotal regulatory assets$640 $2,737 $488 $2,935 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 costsamounts recorded for conservation programs, as well as incentives allowed in certain jurisdictions.future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
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Components of regulatory liabilities:
(Millions of Dollars)(Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2020Dec. 31, 2019(Millions of Dollars)See Note(s)Remaining Amortization PeriodDec. 31, 2021Dec. 31, 2020
Regulatory LiabilitiesRegulatory LiabilitiesCurrentNoncurrentCurrentNoncurrentRegulatory LiabilitiesCurrentNoncurrentCurrentNoncurrent
Deferred income tax adjustments and TCJA refunds (a)
Deferred income tax adjustments and TCJA refunds (a)
7Various$20 $3,368 $75 $3,523 
Deferred income tax adjustments and TCJA refunds (a)
7Various$26 $3,230 $20 $3,368 
Plant removal costsPlant removal costs1, 12Various0 1,520 0 1,217 Plant removal costs1, 12Various— 1,655 — 1,520 
Effects of regulation on employee benefit costs (b)
Effects of regulation on employee benefit costs (b)
Various0 221 0 196 
Effects of regulation on employee benefit costs (b)
Various— 235 — 221 
Renewable resources and environmental initiativesRenewable resources and environmental initiativesVarious5 59 0 45 Renewable resources and environmental initiativesVarious1 101 5 59 
ITC deferralsITC deferrals1Various0 51 0 38 ITC deferrals1Various— 53 — 51 
Revenue decouplingRevenue decoupling
One to two years
10 41 0 0 Revenue decoupling
One to two years
9 41 10 41 
Deferred electric, natural gas and steam production costsLess than one year84 0 138 0 
Conservation programs (c)
1Less than one year49 0 37 0 
Contract valuation adjustments (c)
Contract valuation adjustments (c)
1, 10
One to three years
56 1 19 — 
Deferred natural gas, electric, steam energy/fuel costsDeferred natural gas, electric, steam energy/fuel costsLess than one year50 — 84 — 
Conservation programs (d)
Conservation programs (d)
1Less than one year42 — 49 — 
DOE settlementDOE settlementLess than one year23 0 37 0 DOE settlementLess than one year14 14 23 — 
Contract valuation adjustments (d)
1, 10Less than one year19 0 19 0 
OtherOtherVarious101 42 101 58 OtherVarious73 75 101 42 
Total regulatory liabilities (e)
Total regulatory liabilities (e)
$311 $5,302 $407 $5,077 
Total regulatory liabilities (e)
$271 $5,405 $311 $5,302 
(a)Includes the revaluation of recoverable/regulated plant ADITaccumulated deferred income taxes and revaluation impact of non-plant ADITaccumulated 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 costs for conservation programs, as well as incentives allowed in certain jurisdictions.
(d)Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
(d)Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
(e)Revenue subject to refund of $17 million for both 2021 and $28 million for 2020 and 2019, respectively, is included in other current liabilities.
At Dec. 31, 20202021 and 2019,2020, Xcel Energy’s regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical obligations and net AROs. In addition, regulatory assets included $812$1,718 million and $544$812 million at Dec. 31, 20202021 and 2019,2020, respectively, of past expenditures not earning a return. Amounts are 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.
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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)(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2020Year Ended Dec. 31(Millions of Dollars, Except Interest Rates)Three Months Ended Dec. 31, 2021Year Ended Dec. 31
202020192018202120202019
Borrowing limitBorrowing limit$3,100 $3,100 $3,600 $3,250 Borrowing limit$3,100 $3,100 $3,100 $3,600 
Amount outstanding at period endAmount outstanding at period end584 584 595 1,038 Amount outstanding at period end1,005 1,005 584 595 
Average amount outstandingAverage amount outstanding415 1,126 1,115 788 Average amount outstanding1,200 1,399 1,126 1,115 
Maximum amount outstandingMaximum amount outstanding613 2,080 1,780 1,349 Maximum amount outstanding1,774 2,054 2,080 1,780 
Weighted average interest rate, computed on a daily basisWeighted average interest rate, computed on a daily basis0.60 %1.45 %2.72 %2.34 %Weighted average interest rate, computed on a daily basis0.54 %0.57 %1.45 %2.72 %
Weighted average interest rate at period endWeighted average interest rate at period end0.23 0.23 2.34 2.97 Weighted average interest rate at period end0.31 0.31 0.23 2.34 
Term Loan Agreements — In December 2020,the fourth quarter of 2021, Xcel Energy Inc. repaid its $500 million$1.2 billion 364-Day Term Loan Agreement that was entered into December 2018. In September 2020, Xcel Energy Inc. repaid its $700 million Term Loan Agreement that was entered into March 2020. As of Dec. 31, 2020, Xcel Energy Inc. has 0 open loan agreement.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. In March 2020, NSP-Minnesota renewed its bilateral credit agreement for an additional one-year term.
As of Dec. 31, 2020,2021, NSP-Minnesota had $45 million outstanding letters of credit under the $75 million the Bilateral Credit Agreement were as follows:
(Millions of Dollars)LimitAmount OutstandingAvailable
NSP-Minnesota$75 $49 $26 
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, 20202021 and 2019,2020, there were $19 million and $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.


Terms 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 is $3.1 billion, with a swingline subfacility for Xcel Energy up to $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)
Additional Periods for Which a One-Year Extension May Be Requested (b)
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)
2020201920212020
Xcel Energy Inc. (c)
Xcel Energy Inc. (c)
59 %58 %$200 2 
Xcel Energy Inc. (c)
60 %59 %$250 2 
NSP-WisconsinNSP-Wisconsin46 48 N/A1 NSP-Wisconsin49 46 N/A1 
NSP-MinnesotaNSP-Minnesota47 48 100 2 NSP-Minnesota47 47 100 2 
SPSSPS48 46 50 2 SPS47 48 50 2 
PSCoPSCo44 44 100 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.
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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, 2020,2021, 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, 2020:2021:
(Millions of Dollars)(Millions of Dollars)
Credit Facility (a)
Drawn (b)
Available(Millions of Dollars)
Credit Facility (a)
Drawn (b)
Available
Xcel Energy Inc.Xcel Energy Inc.$1,250 $0 $1,250 Xcel Energy Inc.$1,250 $638 $612 
PSCoPSCo700 144 556 PSCo700 155 545 
NSP-MinnesotaNSP-Minnesota500 189 311 NSP-Minnesota500 9 491 
SPSSPS500 252 248 SPS500 139 361 
NSP-WisconsinNSP-Wisconsin150 19 131 NSP-Wisconsin150 83 67 
TotalTotal$3,100 $604 $2,496 Total$3,100 $1,024 $2,076 
(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 had0 no direct advances on facilities outstanding as of Dec. 31, 20202021 and 2019.2020.
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.
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Long-term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (Millions(in millions of Dollars)dollars):
Xcel Energy Inc.Xcel Energy Inc.Xcel Energy Inc.
Financing InstrumentFinancing InstrumentInterest RateMaturity Date20202019Financing InstrumentInterest RateMaturity Date20212020
Unsecured senior notesUnsecured senior notes2.40 %March 15, 2021$400 $400 Unsecured senior notes2.40 %March 15, 2021$— $400 
Unsecured senior notes (c)(b)
Unsecured senior notes (c)(b)
2.60 March 15, 20220 300 
Unsecured senior notes (c)(b)
0.50 Oct. 15, 2023500 500 
Unsecured senior notesUnsecured senior notes3.30 June 1, 2025250 250 
Unsecured senior notesUnsecured senior notes3.30 June 1, 2025350 350 
Unsecured senior notesUnsecured senior notes3.35 Dec. 1, 2026500 500 
Unsecured senior notes (a)
Unsecured senior notes (a)
0.50 Oct. 15, 2023500 0 
Unsecured senior notes (a)
1.75 March 15,2027500 — 
Unsecured senior notesUnsecured senior notes3.30 June 1, 2025250 250 Unsecured senior notes4.00 June 15, 2028130 130 
Unsecured senior notesUnsecured senior notes3.30 June 1, 2025350 350 Unsecured senior notes4.00 June 15, 2028500 500 
Unsecured senior notesUnsecured senior notes3.35 Dec. 1, 2026500 500 Unsecured senior notes2.60 Dec. 1, 2029500 500 
Unsecured senior notes (b)
4.00 June 15, 2028130 130 
Unsecured senior notes4.00 June 15, 2028500 500 
Unsecured senior notes (b)
2.60 Dec. 1, 2029500 500 
Unsecured senior notes (a)(b)
Unsecured senior notes (a)(b)
3.40 June 1, 2030600 0 
Unsecured senior notes (a)(b)
3.40 June 1, 2030600 600 
Unsecured senior notes (a)
Unsecured senior notes (a)
2.35 Nov. 15, 2031300 — 
Unsecured senior notesUnsecured senior notes6.50 July 1, 2036300 300 Unsecured senior notes6.50 July 1, 2036300 300 
Unsecured senior notesUnsecured senior notes4.80 Sept. 15, 2041250 250 Unsecured senior notes4.80 Sep. 15, 2041250 250 
Unsecured senior notes (b)
3.50 Dec. 1, 2049500 500 
Unsecured senior notesUnsecured senior notes3.50 Dec. 1, 2049500 500 
Unamortized discountUnamortized discount(7)(5)Unamortized discount(8)(7)
Unamortized debt issuance costUnamortized debt issuance cost(32)(28)Unamortized debt issuance cost(33)(32)
Current maturitiesCurrent maturities(400)0 Current maturities— (400)
Total long-term debtTotal long-term debt$4,341 $3,947 Total long-term debt$5,139 $4,341 
(a)2021 financing.
(b)2020 financing.
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 
(b)(a)20192021 financing.
(c)Note was redeemed on Dec. 1, 2020.
NSP-Minnesota
Financing InstrumentInterest RateMaturity Date20202019
First mortgage bonds2.20 %Aug. 15, 2020$0 $300 
First mortgage bonds2.15 Aug. 15, 2022300 300 
First mortgage bonds2.60 May 15, 2023400 400 
First mortgage bonds7.13 July 1, 2025250 250 
First mortgage bonds6.50 March 1, 2028150 150 
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 bonds4.13 May 15, 2044300 300 
First mortgage bonds4.00 Aug. 15, 2045300 300 
First mortgage bonds3.60 May 15, 2046350 350 
First mortgage bonds3.60 Sept. 15, 2047600 600 
First mortgage bonds (b)
2.90 March 1, 2050600 600 
First mortgage bonds (a)
2.60 June 1, 2051700 0 
Unamortized discount(42)(31)
Unamortized debt issuance cost(54)(48)
Current maturities0 (300)
Total long-term debt$5,904 $5,221 
(a)(b)2020 financing.
(b)2019 financing.
NSP-Wisconsin
Financing InstrumentInterest RateMaturity Date20202019
City of La Crosse resource recovery bond6.00 %Nov 1, 2021$19 $19 
First mortgage bonds3.30 June 15, 2024100 100 
First mortgage bonds3.30 June 15, 2024100 100 
First mortgage bonds6.38 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 (a)
3.05 May 1, 2051100 0 
Unamortized discount(4)(3)
Unamortized debt issuance cost(9)(8)
Current maturities(19)0 
Total long-term debt$887 $808 
(a)2020 financing.
PSCo
Financing InstrumentInterest RateMaturity Date20202019
First mortgage bonds3.20 %Nov. 15, 2020$0 $400 
First mortgage bonds2.25 Sept. 15, 2022300 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 (a)
1.90 Jan. 15, 2031375 0 
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 bonds (b)
4.05 Sept. 15, 2049400 400 
First mortgage bonds (b)
3.20 March 1, 2050550 550 
First mortgage bonds (a)
2.70 Jan. 15, 2051375 0 
Unamortized discount(30)(24)
Unamortized debt issuance cost(46)(41)
Current maturities0 (400)
Total long-term debt$5,724 $4,985 
(a)2020 financing.
(b)2019 financing.

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SPS
PSCoPSCo
Financing InstrumentFinancing InstrumentInterest RateMaturity Date20202019Financing InstrumentInterest RateMaturity Date20212020
First mortgage bondsFirst mortgage bonds3.30 %June 15, 2024$150 $150 First mortgage bonds2.25 %Sept. 15, 2022$300 $300 
First mortgage bondsFirst mortgage bonds3.30 June 15, 2024200 200 First mortgage bonds2.50 March 15, 2023250 250 
Unsecured senior notes6.00 Oct. 1, 2033100 100 
Unsecured senior notes6.00 Oct. 1, 2036250 250 
First mortgage bondsFirst mortgage bonds2.90 May 15, 2025250 250 
First mortgage bondsFirst mortgage bonds3.70 June 15, 2028350 350 
First mortgage bonds (b)
First mortgage bonds (b)
1.90 Jan. 15, 2031375 375 
First mortgage bonds (a)
First mortgage bonds (a)
1.875 June 15, 2031750 — 
First mortgage bondsFirst mortgage bonds6.25 Sept. 1, 2037350 350 
First mortgage bondsFirst mortgage bonds6.50 Aug. 1, 2038300 300 
First mortgage bondsFirst mortgage bonds4.75 Aug. 15, 2041250 250 
First mortgage bondsFirst mortgage bonds3.60 Sept. 15, 2042500 500 
First mortgage bondsFirst mortgage bonds3.95 March 15, 2043250 250 
First mortgage bondsFirst mortgage bonds4.50 Aug. 15, 2041200 200 First mortgage bonds4.30 March 15, 2044300 300 
First mortgage bondsFirst mortgage bonds4.50 Aug. 15, 2041100 100 First mortgage bonds3.55 June 15, 2046250 250 
First mortgage bondsFirst mortgage bonds4.50 Aug. 15, 2041100 100 First mortgage bonds3.80 June 15, 2047400 400 
First mortgage bondsFirst mortgage bonds3.40 Aug. 15, 2046300 300 First mortgage bonds4.10 June 15, 2048350 350 
First mortgage bondsFirst mortgage bonds3.70 Aug. 15, 2047450 450 First mortgage bonds4.05 Sept. 15, 2049400 400 
First mortgage bondsFirst mortgage bonds4.40 Nov. 15, 2048300 300 First mortgage bonds3.20 March 1, 2050550 550 
First mortgage bonds (b)
First mortgage bonds (b)
3.75 June 15, 2049300 300 
First mortgage bonds (b)
2.70 Jan. 15, 2051375 375 
First mortgage bonds (a)
3.15 May 1, 2050350 0 
Unamortized discountUnamortized discount(10)(7)Unamortized discount(33)(30)
Unamortized debt issuance costUnamortized debt issuance cost(26)(23)Unamortized debt issuance cost(50)(46)
Current maturitiesCurrent maturities(300)— 
Total long-term debtTotal long-term debt$2,764 $2,420 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.financing re-opened in 2021.
(b)20192020 financing.
Other SubsidiariesOther SubsidiariesOther Subsidiaries
Financing InstrumentFinancing InstrumentInterest RateMaturity Date20202019Financing InstrumentInterest RateMaturity Date20212020
Various Eloigne affordable housing project notesVarious Eloigne affordable housing project notes0.00% - 6.90%2021 — 2054$27 $28 Various Eloigne affordable housing project notes0.00% - 6.50%2022 — 2055$27 $27 
Current maturitiesCurrent maturities(2)(2)Current maturities(1)(2)
Total long-term debtTotal long-term debt$25 $26 Total long-term debt$26 $25 

Maturities of long-term debt:
(Millions of Dollars)(Millions of Dollars)(Millions of Dollars)
2021$421 
20222022601 2022$601 
202320231,151 20231,150 
20242024552 2024552 
202520251,102 20251,102 
20262026501 
Deferred Financing Costs — Deferred financing costs of approximately $167184 millionand $148$167 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 20202021 and 2019,2020, respectively.
ForwardATM Equity AgreementsOffering — In November 2018,2021, Xcel Energy Inc. entered into forward equity agreements forfiled a $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 Dec. 31, 2021, Xcel Energy common stock. In August 2019, Xcel Energy settled the forward equity agreements by delivering 9.4Inc. had issued 5.33 million shares of common equity for cashstock with net proceeds of $453 million.
In November 2019, Xcel Energy Inc. entered into forward equity agreements for a $743$347 million public offering of 11.8 million shares of Xcel Energy common stock. In November 2020, Xcel Energy settled the forward equity agreements by delivering 11.8 million shares of common equity for cash proceeds of $721 million.
Other Equity —Xcel Energy issued $40 million and $39 million of equity annually through the DRIP program during the years ended Dec. 31, 2020 and 2019 respectively. The 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 StockPreferred Stock Outstanding (Shares) 2020 and 2019Preferred Stock Authorized (Shares)Par Value of Preferred StockPreferred Stock Outstanding (Shares) 2021 and 2020
Xcel Energy Inc.Xcel Energy Inc.7,000,000 $100 0 Xcel Energy Inc.7,000,000 $100 — 
PSCoPSCo10,000,000 0.01 0 PSCo10,000,000 0.01 — 
SPSSPS10,000,000 1.00 0 SPS10,000,000 1.00 — 
Xcel Energy Inc. had the following common stock authorized/outstanding:
Common Stock Authorized (Shares)Common Stock Authorized (Shares)Par Value of Common StockCommon Stock Outstanding (Shares) as of Dec. 31, 2020Common Stock Outstanding (Shares) as of Dec. 31, 2019Common 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 1,000,000,000 $2.50 537,438,394 524,539,000 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, 2020:2021:
Equity to Total
Capitalization Ratio
Required Range		Equity to Total Capitalization Ratio ActualEquity to Total
Capitalization Ratio
Required Range		Equity to Total Capitalization Ratio Actual
LowHigh2020LowHigh2021
NSP-MinnesotaNSP-Minnesota47.1 %57.5 %52.7 %NSP-Minnesota47.2 %57.6 %52.9 %
NSP-WisconsinNSP-Wisconsin52.5 N/A52.8 NSP-Wisconsin52.5 N/A52.8 
SPS (a)
SPS (a)
45.0 55.0 54.4 
SPS (a)
45.0 55.0 54.5 
(a)    Excludes short-term debt.
(Amounts in Millions)Unrestricted Retained EarningsTotal CapitalizationLimit on Total Capitalization
NSP-Minnesota$1,356 $12,853 $13,200 
NSP-Wisconsin (a)
7 1,940 N/A
SPS (b)
510 6,062 N/A
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(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)    Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total capitalization ratio falls below the commission authorized level.
(b)    May not pay a dividend that would cause a loss of its investment grade bond rating.
Issuance of securities by Xcel Energy Inc. is not generally subject to regulatory approval. However, utility financings and intra-system financings are subject to the jurisdiction of state regulatory commissions and/or the FERC. Xcel Energy may seek additional authorization as necessary.
Amounts authorized to issue as of Dec. 31, 2020:2021:
(Millions of Dollars)(Millions of Dollars)Long-Term DebtShort-Term Debt(Millions of Dollars)Long-Term DebtShort-Term Debt
NSP-MinnesotaNSP-Minnesota52.93% of total capitalization(a)$1,980 (a)NSP-Minnesota52.8% of total capitalization(a)$2,300 (a)
NSP-WisconsinNSP-Wisconsin$250 150 NSP-Wisconsin$150 150 
SPSSPS0 (b)600 SPS— 600 
PSCoPSCo1,450 800 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)     SPSPSCo filed for additional long-term debt authorization in December 2020.2021.
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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, 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 0 6 131 
Total retail7,787 1,437 75 9,299 
Wholesale759 0 0 759 
Transmission579 0 0 579 
Other73 137 0 210 
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 0 4 134 
Total retail7,851 1,694 74 9,619 
Wholesale737 0 0 737 
Transmission507 0 0 507 
Other49 120 0 169 
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 
Year Ended Dec. 31, 2018Year Ended Dec. 31, 2021
(Millions of Dollars)(Millions of Dollars)ElectricNatural GasAll OtherTotal(Millions of Dollars)ElectricNatural GasAll OtherTotal
Major revenue typesMajor revenue typesMajor revenue types
Revenue from contracts with customers:Revenue from contracts with customers:Revenue from contracts with customers:
ResidentialResidential$2,919 $988 $38 $3,945 Residential$3,194 $1,222 $45 $4,461 
C&IC&I4,874 524 25 5,423 C&I5,050 640 30 5,720 
OtherOther134 0 6 140 Other127 — 7 134 
Total retailTotal retail7,927 1,512 69 9,508 Total retail8,371 1,862 82 10,315 
WholesaleWholesale791 0 0 791 Wholesale1,540 — — 1,540 
TransmissionTransmission523 0 0 523 Transmission604 — — 604 
OtherOther98 100 0 198 Other61 148 — 209 
Total revenue from contracts with customersTotal revenue from contracts with customers9,339 1,612 69 11,020 Total revenue from contracts with customers10,576 2,010 82 12,668 
Alternative revenue and otherAlternative revenue and other380 127 10 517 Alternative revenue and other629 122 12 763 
Total revenuesTotal revenues$9,719 $1,739 $79 $11,537 Total revenues$11,205 $2,132 $94 $13,431 
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 Loss Carryback Claims - In 2020, Xcel Energy identified certain expense related to tax years 2009 - 2011 that qualify for an extended carryback claim. As a result, a tax benefit of approximately $13 million was recognized in 2020.
Federal Audit — Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns:returns expire as follows:
Tax Year(s)Expiration
2014 - 2016July 2021December 2022
2018September 2022
Additionally, the statute of limitations related to the federal tax credit carryforwards will remain open until those credits are utilized in subsequent returns. Further, the statute of limitations related to the additional federal tax loss carryback claim referenced abovefiled in 2020 has been extended. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.
In 2017, the IRS concluded the audit
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Table of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy file a protest with the IRS. In April 2020, Xcel Energy and Appeals reached an agreement and 0 material adjustments were required.Contents
In 2018, the IRS began an audit of tax years 2014 - 2016. In July 2020, Xcel Energy and the IRS reached an agreement and the related benefit was recognized.
State Audits — 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, 2020,2021, 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
Texas20122016
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, 2020,2021, 0 material adjustments have been proposed.
•In July 2020, Minnesota began a reviewan audit of thetax years 2015 - 2018 Research and Experimentation Credits.2018. As of Dec. 31, 2020,2021, 0 material adjustments have been proposed.
•Xcel Energy had 0NaN other state income tax audits in progress for its major operating jurisdictions as of Dec. 31, 2020.2021.
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)(Millions of Dollars)Dec. 31, 2020Dec. 31, 2019(Millions of Dollars)Dec. 31, 2021Dec. 31, 2020
Unrecognized tax benefit — Permanent tax positionsUnrecognized tax benefit — Permanent tax positions$41 $35 Unrecognized tax benefit — Permanent tax positions$47 $41 
Unrecognized tax benefit — Temporary tax positionsUnrecognized tax benefit — Temporary tax positions11 9 Unrecognized tax benefit — Temporary tax positions11 11 
Total unrecognized tax benefitTotal unrecognized tax benefit$52 $44 Total unrecognized tax benefit$58 $52 
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Changes in unrecognized tax benefits:
(Millions of Dollars)(Millions of Dollars)202020192018(Millions of Dollars)202120202019
Balance at Jan. 1Balance at Jan. 1$44 $37 $39 Balance at Jan. 1$52 $44 $37 
Additions based on tax positions related to the current yearAdditions based on tax positions related to the current year9 10 9 Additions based on tax positions related to the current year5 9 10 
Reductions based on tax positions related to the current yearReductions based on tax positions related to the current year(2)(4)(4)Reductions based on tax positions related to the current year— (2)(4)
Additions for tax positions of prior yearsAdditions for tax positions of prior years35 1 2 Additions for tax positions of prior years2 35 1 
Reductions for tax positions of prior yearsReductions for tax positions of prior years(34)0 (4)Reductions for tax positions of prior years(1)(34)— 
Settlements with taxing authorities0 0 (5)
Balance at Dec. 31Balance at Dec. 31$52 $44 $37 Balance at Dec. 31$58 $52 $44 
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
(Millions of Dollars)Dec. 31, 2020Dec. 31, 2019
NOL and tax credit carryforwards$(31)$(40)
Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $19 million and $29 million at Dec. 31, 2020 and Dec. 31, 2019, respectively.
(Millions of Dollars)Dec. 31, 2021Dec. 31, 2020
NOL and tax credit carryforwards$(36)$(31)
As the IRS audit resumesprogresses its review of the tax loss carryback claims and as state audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $27$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.
Interest payable related to unrecognized tax benefits:
(Millions of Dollars)(Millions of Dollars)202020192018(Millions of Dollars)202120202019
Payable for interest related to unrecognized tax benefits at Jan. 1Payable for interest related to unrecognized tax benefits at Jan. 1$0 $0 $0 Payable for interest related to unrecognized tax benefits at Jan. 1$(3)$— $— 
Interest expense related to unrecognized tax benefitsInterest expense related to unrecognized tax benefits(3)0 0 Interest expense related to unrecognized tax benefits— (3)— 
Payable for interest related to unrecognized tax benefits at Dec. 31Payable for interest related to unrecognized tax benefits at Dec. 31$(3)$0 $0 Payable for interest related to unrecognized tax benefits at Dec. 31$(3)$(3)$— 
NaN amountspenalties were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2021, 2020 2019 or 2018.2019.
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)(Millions of Dollars)20202019(Millions of Dollars)20212020
Federal NOL carryforwardFederal NOL carryforward$765 $— 
Federal tax credit carryforwardsFederal tax credit carryforwards$791 $639 Federal tax credit carryforwards1,172 791 
State NOL carryforwardsState NOL carryforwards839 937 State NOL carryforwards1,648 839 
Valuation allowances for state NOL carryforwardsValuation allowances for state NOL carryforwards(4)(19)Valuation allowances for state NOL carryforwards(3)(4)
State tax credit carryforwards, net of federal detriment (a)
State tax credit carryforwards, net of federal detriment (a)
89 89 
State tax credit carryforwards, net of federal detriment (a)
89 89 
Valuation allowances for state credit carryforwards, net of federal benefit (b)
Valuation allowances for state credit carryforwards, net of federal benefit (b)
(64)(66)
Valuation allowances for state credit carryforwards, net of federal benefit (b)
(64)(64)
(a)State tax credit carryforwards are netnet of federal detriment of $24 million as of Dec. 31, 20202021 and 2019.2020.
(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $17 million as of Dec. 31, 20202021 and 2019.2020.
Federal carryforward periods expire between 2031 and 20402041 and state carryforward periods expire starting 2021.2022.
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:
202020192018202120202019
Federal statutory rateFederal statutory rate21.0 %21.0 %21.0 %Federal statutory rate21.0 %21.0 %21.0 %
State income tax on pretax income, net of federal tax effectState income tax on pretax income, net of federal tax effect4.9 4.9 5.0 State income tax on pretax income, net of federal tax effect5.0 4.9 4.9 
Increases (decreases) in tax from:
(Decreases) increases in tax from:(Decreases) increases in tax from:
Wind PTCsWind PTCs(15.7)(9.4)(5.2)Wind PTCs(23.4)(15.7)(9.4)
Plant regulatory differences (a)
Plant regulatory differences (a)
(7.6)(5.8)(6.2)
Plant regulatory differences (a)
(6.2)(7.6)(5.8)
Other tax credits, net NOL & tax credit allowancesOther tax credits, net NOL & tax credit allowances(1.2)(1.7)(1.7)Other tax credits, net NOL & tax credit allowances(1.1)(1.2)(1.7)
NOL CarrybackNOL Carryback(0.9)0 0 NOL Carryback— (0.9)— 
Change in unrecognized tax benefitsChange in unrecognized tax benefits0.5 0.5 0.4 Change in unrecognized tax benefits0.4 0.5 0.5 
Other, netOther, net(1.4)(1.0)(0.7)Other, net(0.3)(1.4)(1.0)
Effective income tax rateEffective income tax rate(0.4)%8.5 %12.6 %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.
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Components of income tax expense for years ended Dec. 31:
(Millions of Dollars)(Millions of Dollars)202020192018(Millions of Dollars)202120202019
Current federal tax benefit$(13)$(16)$(34)
Current state tax expense2 4 8 
Current change in unrecognized tax expense (benefit)18 2 (6)
Current federal tax expense (benefit)Current federal tax expense (benefit)$15 $(13)$(16)
Current state tax (benefit) expenseCurrent state tax (benefit) expense(2)2 4 
Current change in unrecognized tax expenseCurrent change in unrecognized tax expense1 18 2 
Deferred federal tax (benefit) expenseDeferred federal tax (benefit) expense(89)55 122 Deferred federal tax (benefit) expense(183)(89)55 
Deferred state tax expenseDeferred state tax expense91 83 85 Deferred state tax expense99 91 83 
Deferred change in unrecognized tax (benefit) expense(10)5 11 
Deferred change in unrecognized tax expense (benefit)Deferred change in unrecognized tax expense (benefit)5 (10)5 
Deferred ITCsDeferred ITCs(5)(5)(5)Deferred ITCs(5)(5)(5)
Total income tax (benefit) expenseTotal income tax (benefit) expense$(6)$128 $181 Total income tax (benefit) expense$(70)$(6)$128 
Components of deferred income tax expense as of Dec. 31:
(Millions of Dollars)(Millions of Dollars)202020192018(Millions of Dollars)202120202019
Deferred tax expense excluding items belowDeferred tax expense excluding items below$237 $344 $320 Deferred tax expense excluding items below$148 $237 $344 
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilitiesAmortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities(247)(206)(102)Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities(221)(247)(206)
Tax expense allocated to other comprehensive income, adoption of ASC Topic 326, adoption of ASU No. 2018-02, and other2 5 0 
Tax (benefit) expense allocated to other comprehensive income, adoption of ASC Topic 326, and otherTax (benefit) expense allocated to other comprehensive income, adoption of ASC Topic 326, and other(6)2 5 
Deferred tax (benefit) expenseDeferred tax (benefit) expense$(8)$143 $218 Deferred tax (benefit) expense$(79)$(8)$143 

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Components of net deferred tax liability as of Dec. 31:
(Millions of Dollars)(Millions of Dollars)20202019(Millions of Dollars)2021
2020 (a)
Deferred tax liabilities:Deferred tax liabilities:Deferred tax liabilities:
Differences between book and tax bases of propertyDifferences between book and tax bases of property$5,810 $5,474 Differences between book and tax bases of property$6,231 $5,810 
Operating lease assetsOperating lease assets400 449 Operating lease assets351 400 
Regulatory assetsRegulatory assets603 598 Regulatory assets598 603 
Deferred fuel costsDeferred fuel costs262 (6)
Pension expensePension expense176 173 Pension expense175 176 
OtherOther74 70 Other93 74 
Total deferred tax liabilitiesTotal deferred tax liabilities$7,063 $6,764 Total deferred tax liabilities$7,710 $7,057 
Deferred tax assets:Deferred tax assets:Deferred tax assets:
Regulatory liabilitiesRegulatory liabilities$806 $847 Regulatory liabilities$780 $806 
Operating lease liabilitiesOperating lease liabilities400 449 Operating lease liabilities351 400 
Tax credit carryforwardTax credit carryforward880 727 Tax credit carryforward1,261 880 
NOL carryforwardNOL carryforward37 38 NOL carryforward247 37 
NOL and tax credit valuation allowancesNOL and tax credit valuation allowances(64)(67)NOL and tax credit valuation allowances(64)(64)
Other employee benefitsOther employee benefits141 128 Other employee benefits119 141 
Deferred ITCsDeferred ITCs13 14 Deferred ITCs15 13 
Rate refund16 26 
OtherOther88 93 Other107 98 
Total deferred tax assetsTotal deferred tax assets$2,317 $2,255 Total deferred tax assets$2,816 $2,311 
Net deferred tax liabilityNet deferred tax liability$4,746 $4,509 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 Plan Including Share-Based Compensation — Xcel Energy has an incentive plan which includes share-based payment elements, the Amended and Restated 2015 Omnibus Incentive Plan with 7.0 million equity shares authorized.
Restricted Stock — The Amended and Restated 2015 Omnibus Incentive Plan allows 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-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)(Shares in Thousands)202020192018(Shares in Thousands)202120202019
Granted sharesGranted shares1 13 18 Granted shares2 1 13 
Grant date fair valueGrant date fair value$70.26 $53.46 $44.68 Grant date fair value$61.54 $70.26 $53.46 
Changes in nonvested restricted stock:
(Shares in Thousands)(Shares in Thousands)SharesWeighted Average
Grant Date Fair Value		(Shares in Thousands)SharesWeighted Average
Grant Date Fair Value
Nonvested restricted stock at Jan. 1, 202031 $50.15 
Nonvested restricted stock at Jan. 1, 2021Nonvested restricted stock at Jan. 1, 202115 $56.68 
GrantedGranted1 70.26 Granted2 61.54 
ForfeitedForfeited(3)44.68 Forfeited— 70.26 
VestedVested(15)46.41 Vested(9)49.71 
Dividend equivalentsDividend equivalents1 66.96 Dividend equivalents— 66.73 
Nonvested restricted stock at Dec. 31, 202015 56.68 
Nonvested restricted stock at Dec. 31, 2021Nonvested 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, 0.30.2 million, and 0.3 million time-based equity shares subject only to service conditions were granted annually in 2021, 2020 and 2019, and 2018, respectively.
The performance conditions for a portion of the awards granted from 20182019 to 20202021 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)(Units in Thousands)202020192018(Units in Thousands)202120202019
Granted unitsGranted units411 483 500 Granted units421 411 483 
Weighted average grant date fair valueWeighted average grant date fair value$62.92 $49.67 $47.60 Weighted average grant date fair value$66.03 $62.92 $49.67 
Equity awards vested:
(Units in Thousands, Fair Value in Millions)(Units in Thousands, Fair Value in Millions)202020192018(Units in Thousands, Fair Value in Millions)202120202019
Vested UnitsVested Units442 464 475 Vested Units392 442 464 
Total Fair ValueTotal Fair Value$29 $29 $23 Total Fair Value$27 $29 $29 
Changes in the nonvested portion of equity award units:
(Units in Thousands)(Units in Thousands)UnitsWeighted Average
Grant Date Fair Value		(Units in Thousands)UnitsWeighted Average
Grant Date Fair Value
Nonvested Units at Jan. 1, 2020880 $48.20 
Nonvested Units at Jan. 1, 2021Nonvested Units at Jan. 1, 2021780 $55.68 
GrantedGranted411 62.92 Granted421 66.03 
ForfeitedForfeited(101)53.87 Forfeited(146)61.76 
VestedVested(442)47.63 Vested(392)48.91 
Dividend equivalentsDividend equivalents32 51.56 Dividend equivalents32 58.00 
Nonvested Units at Dec. 31, 2020780 55.68 
Nonvested Units at Dec. 31, 2021Nonvested Units at Dec. 31, 2021695 64.59 
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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)(Units in Thousands)202020192018(Units in Thousands)202120202019
Granted unitsGranted units33 29 36 Granted units31 33 29 
Weighted average grant date fair valueWeighted average grant date fair value$61.61 $58.44 $45.44 Weighted average grant date fair value$68.15 $61.61 $58.44 
Changes in stock equivalent units:
(Units in Thousands)(Units in Thousands)UnitsWeighted Average
Grant Date Fair Value		(Units in Thousands)UnitsWeighted Average
Grant Date Fair Value
Stock equivalent units at Jan. 1, 2020725 $32.72 
Stock equivalent units at Jan. 1, 2021Stock equivalent units at Jan. 1, 2021630 $36.28 
GrantedGranted33 61.61 Granted31 68.15 
Units distributedUnits distributed(146)28.16 Units distributed(73)31.47 
Dividend equivalentsDividend equivalents18 67.44 Dividend equivalents16 66.98 
Stock equivalent units at Dec. 31, 2020630 36.28 
Stock equivalent units at Dec. 31, 2021Stock 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-year period. Xcel Energy Inc.’s TSR is compared to a peer group of other utility companies. Potential payouts of the awards range from 0zero to 200%.

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TSR liability awards granted:
(In Thousands)(In Thousands)202020192018(In Thousands)202120202019
Awards grantedAwards granted212 225 239 Awards granted221 212 225 
TSR liability awards settled:
(Units In Thousands, Settlement Amount in Millions)(Units In Thousands, Settlement Amount in Millions)202020192018(Units In Thousands, Settlement Amount in Millions)202120202019
Awards settledAwards settled476 466 482 Awards settled446 476 466 
Settlement amount (cash, common stock and deferred amounts)Settlement amount (cash, common stock and deferred amounts)$33 $25 $22 Settlement amount (cash, common stock and deferred amounts)$27 $33 $25 
TSR liability awards of $27$22 million were settled in cash in 2020.2021.
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, 0.30.2 million, and 0.3 million of equity award units were granted in 2021, 2020, 2019, and 2018,2019, 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)(Millions of Dollars)202020192018(Millions of Dollars)202120202019
Compensation cost for share-based awards (a)
Compensation cost for share-based awards (a)
$73 $58 $45 
Compensation cost for share-based awards (a)
$31 $73 $58 
Tax benefit recognized in incomeTax benefit recognized in income19 15 12 Tax benefit recognized in income8 19 15 
(a)Compensation costs for share-based payments are included in O&M expense.
There was approximately $28 million in 2021 and $51 million in 2020 and $40 million in 2019 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 1.71.6 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.
•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 0.3 million, 1.1 million 1.3 million and 0.51.3 million shares for 2021, 2020 and 2019, and 2018, respectively.
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10. Fair Value of Financial Assets and Liabilities
Fair Value Measurements
Accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance.
•Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.
•Level 2 — Pricing inputs are other than quoted prices in active markets but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs.
•Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.
Specific valuation methods include:
Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAV.
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 fund investments may be redeemed with proper notice, however, withdrawals may be delayed or discounted as a result of fund illiquidity.
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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 investment targets by asset class for the qualified trust.
NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset.
Unrealized gains for the nuclear decommissioning fund were $981 million$1.3 billion and $706$981 million as of Dec. 31, 20202021 and 2019,2020, respectively, and unrealized losses were $5$7 million and $6$5 million as of Dec. 31, 20202021 and 2019,2020, respectively.
Non-derivative instruments with recurring fair value measurements:
Dec. 31, 2020Dec. 31, 2021
Fair ValueFair Value
(Millions of Dollars)(Millions of Dollars)CostLevel 1Level 2Level 3NAVTotal(Millions of Dollars)CostLevel 1Level 2Level 3NAVTotal
Nuclear decommissioning fund (a)
Nuclear decommissioning fund (a)
Nuclear decommissioning fund (a)
Cash equivalentsCash equivalents$40 $40 $0 $0 $0 $40 Cash equivalents$64 $64 $— $— $— $64 
Commingled fundsCommingled funds787 0 0 0 1,041 1,041 Commingled funds856 — — — 1,294 1,294 
Debt securitiesDebt securities528 0 572 13 0 585 Debt securities631 — 666 9 — 675 
Equity securitiesEquity securities446 1,109 2 0 0 1,111 Equity securities411 1,222 1 — — 1,223 
TotalTotal$1,801 $1,149 $574 $13 $1,041 $2,777 Total$1,962 $1,286 $667 $9 $1,294 $3,256 
(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.
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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.
Dec. 31, 2019
Fair Value
(Millions of Dollars)CostLevel 1Level 2Level 3NAVTotal
Nuclear decommissioning fund (a)
Cash equivalents$33 $33 $0 $0 $0 $33 
Commingled funds733 0 0 0 935 935 
Debt securities489 0 495 13 0 508 
Equity securities485 962 2 0 0 964 
Total$1,740 $995 $497 $13 $935 $2,440 
(a)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.
For the years ended Dec. 31, 20202021 and 2019,2020, 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, 2020:2021:
Final Contractual MaturityFinal Contractual Maturity
(Millions of Dollars)(Millions of Dollars)Due in 1 year or LessDue in 1 to 5 YearsDue in 5 to 10 YearsDue after 10 yearsTotal(Millions of Dollars)Due in 1 year or LessDue in 1 to 5 YearsDue in 5 to 10 YearsDue after 10 yearsTotal
Debt securitiesDebt securities$1 $116 $211 $257 $585 Debt securities$4 $149 $208 $314 $675 







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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, 2020Dec. 31, 2021
Fair ValueFair Value
(Millions of Dollars)(Millions of Dollars)CostLevel 1Level 2Level 3Total(Millions of Dollars)CostLevel 1Level 2Level 3Total
Rabbi Trusts (a)
Rabbi Trusts (a)
Rabbi Trusts (a)
Cash equivalentsCash equivalents$32 $32 $0 $0 $32 Cash equivalents$20 $20 $— $— $20 
Mutual fundsMutual funds60 70 0 0 70 Mutual funds75 89 — — 89 
TotalTotal$92 $102 $0 $0 $102 Total$95 $109 $— $— $109 
(a)    Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
Dec. 31, 2019Dec. 31, 2020
Fair ValueFair Value
(Millions of Dollars)(Millions of Dollars)CostLevel 1Level 2Level 3Total(Millions of Dollars)CostLevel 1Level 2Level 3Total
Rabbi Trusts (a)
Rabbi Trusts (a)
Rabbi Trusts (a)
Cash equivalentsCash equivalents$17 $17 $0 $0 $17 Cash equivalents$32 $32 $— $— $32 
Mutual fundsMutual funds57 65 0 0 65 Mutual funds60 70 — — 70 
TotalTotal$74 $82 $0 $0 $82 Total$92 $102 $— $— $102 
(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 yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes, with changes in fair value prior to settlement recorded as other comprehensive income.
As of Dec. 31, 2020,2021, accumulated other comprehensive loss related to settled interest rate derivatives included $6$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, 2020,2021, Xcel Energy had 0no unsettled interest rate 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.
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. The classification of unrealized losses or gains on these instruments as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms.
As of Dec. 31, 2020,2021, Xcel Energy had 0no commodity contracts designated as cash flow 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 amounts of commodity forwards, options and FTRs:
(Amounts in Millions) (a)(b)
(Amounts in Millions) (a)(b)
Dec. 31, 2020Dec. 31, 2019
(Amounts in Millions) (a)(b)
Dec. 31, 2021Dec. 31, 2020
MWh of electricityMWh of electricity87 95 MWh of electricity80 87 
MMBtu of natural gasMMBtu of natural gas175 110 MMBtu of natural gas156 175 
(a)Not reflective of net positions in the underlying commodities.
(b)Notional amounts for options included on a gross basis but weighted for the probability of exercise.
Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented on the consolidated balance sheets.
Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities.
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As of Dec. 31, 2020,2021, 6 of Xcel Energy’s 10 most significant counterparties for these activities, comprising $130$83 million or 54%38% of this credit exposure, had investment grade credit ratings from S&P, Moody’s Investor Services or Fitch Ratings. NaN of the 10 most significant counterparties, comprising $32$44 million or 13%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 $17$38 million or 7%18% of this credit exposure, had credit quality less than investment grade, based on internal analysis. NaN of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.
Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate cash flow hedges on Xcel Energy’s accumulated other comprehensive loss, included in the consolidated statements of common stockholders’ equity and in the consolidated statements of comprehensive income:
(Millions of Dollars)(Millions of Dollars)202020192018(Millions of Dollars)202120202019
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1Accumulated other comprehensive loss related to cash flow hedges at Jan. 1$(80)$(60)$(58)Accumulated other comprehensive loss related to cash flow hedges at Jan. 1$(85)$(80)$(60)
After-tax net unrealized losses related to derivatives accounted for as hedges(10)(23)(5)
After-tax net unrealized gains (losses) related to derivatives accounted for as hedgesAfter-tax net unrealized gains (losses) related to derivatives accounted for as hedges4 (10)(23)
After-tax net realized losses on derivative transactions reclassified into earningsAfter-tax net realized losses on derivative transactions reclassified into earnings5 3 3 After-tax net realized losses on derivative transactions reclassified into earnings6 5 3 
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31Accumulated other comprehensive loss related to cash flow hedges at Dec. 31$(85)$(80)$(60)Accumulated other comprehensive loss related to cash flow hedges at Dec. 31$(75)$(85)$(80)
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Impact of derivative activity:
Pre-Tax Fair Value
Gains (Losses) Recognized
During the Period in:
(Millions of Dollars)Accumulated
Other
Comprehensive Loss		Regulatory
(Assets) and Liabilities
Year Ended Dec. 31, 2020
Derivatives designated as cash flow hedges
Interest rate$(13)$0 
Total$(13)$0 
Other derivative instruments
Electric commodity$0 $(5)
Natural gas commodity0 (13)
Total$0 $(18)
Year Ended Dec. 31, 2019
Interest rate$(30)$0 
Total$(30)$0 
Other derivative instruments
Electric commodity$0 $8 
Natural gas commodity0 (9)
Total$0 $(1)
Year Ended Dec. 31, 2018
Interest rate$(7)$0 
Total$(7)$0 
Other derivative instruments
Electric commodity$0 $1 
Natural gas commodity0 10 
Total$0 $11 
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
Derivatives designated as cash flow hedges
Interest rate$5 $— 
Total$5 $— 
Other derivative instruments
Electric commodity$— $32 
Natural gas commodity— (4)
Total$— $28 
Year Ended Dec. 31, 2020
Interest rate$(13)$— 
Total$(13)$— 
Other derivative instruments
Electric commodity$— $(5)
Natural gas commodity— (13)
Total$— $(18)
Year Ended Dec. 31, 2019
Interest rate$(30)$— 
Total$(30)$— 
Other derivative instruments
Electric commodity$— $8 
Natural gas commodity— (9)
Total$— $(1)
Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from:
Pre-Tax Gains
(Losses) Recognized
During the Period in Income
Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from:
Pre-Tax Gains
(Losses) Recognized
During the Period in Income
(Millions of Dollars)(Millions of Dollars)Accumulated
Other
Comprehensive Loss		Regulatory
Assets and (Liabilities)		(Millions of Dollars)Accumulated
Other
Comprehensive Loss		Regulatory
Assets and (Liabilities)
Year Ended Dec. 31, 2021Year Ended Dec. 31, 2021
Derivatives designated as cash flow hedgesDerivatives designated as cash flow hedges
Interest rateInterest rate$8 (a)$— $— 
TotalTotal$8 $— $— 
Other derivative instrumentsOther derivative instruments
Commodity tradingCommodity trading$— $— $63 (b)
Electric commodityElectric commodity— (23)(c)— 
Natural gas commodityNatural gas commodity— 5 (d)(22)(d)
TotalTotal$— $(18)$41 
Year Ended Dec. 31, 2020Year Ended Dec. 31, 2020Year Ended Dec. 31, 2020
Derivatives designated as cash flow hedgesDerivatives designated as cash flow hedgesDerivatives designated as cash flow hedges
Interest rateInterest rate$7 (a)$0 $0 Interest rate$7 (a)$— $— 
TotalTotal$7 $0 $0 Total$7 $— $— 
Other derivative instrumentsOther derivative instrumentsOther derivative instruments
Commodity tradingCommodity trading$0 $0 $(1)(b)Commodity trading$— $— $(1)(b)
Electric commodityElectric commodity0 (3)(c)0 Electric commodity— (3)(c)— 
Natural gas commodityNatural gas commodity0 10 (d)(13)(d)Natural gas commodity— 10 (d)(13)(d)
TotalTotal$0 $7 $(14)Total$— $7 $(14)
Year Ended Dec. 31, 2019Year Ended Dec. 31, 2019Year Ended Dec. 31, 2019
Derivatives designated as cash flow hedgesDerivatives designated as cash flow hedgesDerivatives designated as cash flow hedges
Interest rateInterest rate$4 (a)$0 $0 Interest rate$4 (a)$— $— 
TotalTotal$4 $0 $0 Total$4 $— $— 
Other derivative instrumentsOther derivative instrumentsOther derivative instruments
Commodity tradingCommodity trading$0 $0 $2 (b)Commodity trading$— $— $2 (b)
Electric commodityElectric commodity0 (5)(c)0 Electric commodity— (5)(c)— 
Natural gas commodityNatural gas commodity0 2 (d)(7)(d)Natural gas commodity— 2 (d)(7)(d)
TotalTotal$0 $(3)$(5)Total$— $(3)$(5)
Year Ended Dec. 31, 2018
Derivatives designated as cash flow hedges
Interest rate$4 (a)$0 $0 
Total$4 $0 $0 
Other derivative instruments
Commodity trading$0 $0 $14 (b)
Electric commodity0 (1)(c)0 
Natural gas commodity0 (6)(d)(4)(d)
Total$0 $(7)$10 
(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)Amounts for the years ended Dec. 31, 2020 and 2019 included 0 settlementSettlement losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Such losses for the year ended Dec. 31, 2018, was $1 million. Remaining settlement losses for the years ended Dec. 31, 2020, 2019 and 2018 related to natural gas operations and wereare 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, 2021, 2020 2019 and 2018.2019.
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Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal purchase and normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies. As of Dec. 31, 20202021 and 2019,2020, there were $4$3 million and $7$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 approximately $64 million and $60 million of derivative instruments in a liability position with such underlying contract provisions.provisions, respectively.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. Provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. Xcel Energy had 0no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 20202021 and 2019.2020.

Recurring Fair Value Measurements — Derivative assets and liabilities measured at fair value on a recurring basis were as follows:
Dec. 31, 2020Dec. 31, 2019Dec. 31, 2021Dec. 31, 2020
Fair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
Total
(Millions of Dollars)(Millions of Dollars)Level 1Level 2Level 3Level 1Level 2Level 3(Millions of Dollars)Level 1Level 2Level 3Level 1Level 2Level 3
Current derivative assetsCurrent derivative assetsCurrent derivative assets
Other derivative instruments:Other derivative instruments:Other derivative instruments:
Commodity tradingCommodity trading$2 $67 $1 $70 $(52)$18 $3 $51 $24 $78 $(52)$26 Commodity trading$22 $137 $21 $180 $(134)$46 $2 $67 $1 $70 $(52)$18 
Electric commodityElectric commodity0 0 20 20 (1)19 0 0 21 21 (1)20 Electric commodity— — 57 57 (1)56 — — 20 20 (1)19 
Natural gas commodityNatural gas commodity0 9 0 9 0 9 0 6 0 6 0 6 Natural gas commodity— 18 — 18 — 18 — 9 — 9 — 9 
Total current derivative assetsTotal current derivative assets$2 $76 $21 $99 $(53)46 $3 $57 $45 $105 $(53)52 Total current derivative assets$22 $155 $78 $255 $(135)120 $2 $76 $21 $99 $(53)46 
PPAs (b)
PPAs (b)
3 3 
PPAs (b)
3 3 
Current derivative instrumentsCurrent derivative instruments$49 $55 Current derivative instruments$123 $49 
Noncurrent derivative assetsNoncurrent derivative assetsNoncurrent derivative assets
Other derivative instruments:Other derivative instruments:Other derivative instruments:
Commodity tradingCommodity trading$8 $66 $8 $82 $(62)$20 $9 $38 $7 $54 $(45)$9 Commodity trading$16 $63 $89 $168 $(107)$61 $8 $66 $8 $82 $(62)$20 
Total noncurrent derivative assetsTotal noncurrent derivative assets$8 $66 $8 $82 $(62)20 $9 $38 $7 $54 $(45)9 Total noncurrent derivative assets$16 $63 $89 $168 $(107)61 $8 $66 $8 $82 $(62)20 
PPAs (b)
PPAs (b)
10 13 
PPAs (b)
6 10 
Noncurrent derivative instrumentsNoncurrent derivative instruments$30 $22 Noncurrent derivative instruments$67 $30 
Dec. 31, 2020Dec. 31, 2019Dec. 31, 2021Dec. 31, 2020
Fair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
TotalFair ValueFair Value Total
Netting (a)
Total
(Millions of Dollars)(Millions of Dollars)Level 1Level 2Level 3Level 1Level 2Level 3(Millions of Dollars)Level 1Level 2Level 3Level 1Level 2Level 3
Current derivative liabilitiesCurrent derivative liabilitiesCurrent derivative liabilities
Other derivative instruments:Other derivative instruments:Other derivative instruments:
Commodity tradingCommodity trading$4 $64 $17 $85 $(58)$27 $4 $59 $15 $78 $(63)$15 Commodity trading$19 $148 $20 $187 $(143)$44 $4 $64 $17 $85 $(58)$27 
Electric commodityElectric commodity0 0 1 1 (1)0 0 0 1 1 (1)0 Electric commodity— — 1 1 (1)— — — 1 1 (1)— 
Natural gas commodityNatural gas commodity0 9 0 9 0 9 0 5 0 5 0 5 Natural gas commodity— 8 — 8 — 8 — 9 — 9 — 9 
Total current derivative liabilitiesTotal current derivative liabilities$4 $73 $18 $95 $(59)36 $4 $64 $16 $84 $(64)20 Total current derivative liabilities$19 $156 $21 $196 $(144)52 $4 $73 $18 $95 $(59)36 
PPAs (b)
PPAs (b)
17 18 
PPAs (b)
17 17 
Current derivative instrumentsCurrent derivative instruments$53 $38 Current derivative instruments$69 $53 
Noncurrent derivative liabilitiesNoncurrent derivative liabilitiesNoncurrent derivative liabilities
Other derivative instruments:Other derivative instruments:Other derivative instruments:
Commodity tradingCommodity trading$3 $58 $60 $121 $(47)$74 $2 $79 $32 $113 $(13)$100 Commodity trading$18 $48 $127 $193 $(128)$65 $3 $58 $60 $121 $(47)$74 
Total noncurrent derivative liabilitiesTotal noncurrent derivative liabilities$3 $58 $60 $121 $(47)74 $2 $79 $32 $113 $(13)100 Total noncurrent derivative liabilities$18 $48 $127 $193 $(128)65 $3 $58 $60 $121 $(47)74 
PPAs (b)
PPAs (b)
57 75 
PPAs (b)
40 57 
Noncurrent derivative instrumentsNoncurrent derivative instruments$131 $175 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, 20202021 and 2019.2020. At Dec. 31, 20202021, derivative assets and 2019,liabilities include 0 obligations to return cash collateral. At Dec. 31, 2020, derivative assets and liabilities include $15 million and $32 million of obligations to return cash collateral, respectively.collateral. At Dec. 31, 20202021 and 2019,2020, derivative assets and liabilities include rights to reclaim cash collateral of $6$30 million and $11$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.
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Changes in Level 3 commodity derivatives:
Year Ended Dec. 31Year Ended Dec. 31
(Millions of Dollars)(Millions of Dollars)202020192018(Millions of Dollars)202120202019
Balance at Jan. 1Balance at Jan. 1$4 $29 $35 Balance at Jan. 1$(49)$4 $29 
PurchasesPurchases51 44 59 Purchases65 51 44 
SettlementsSettlements(73)(64)(59)Settlements(158)(73)(64)
Net transactions recorded during the period:Net transactions recorded during the period:Net transactions recorded during the period:
Losses recognized in earnings (a)
(39)(8)(1)
Net gains (losses) recognized as regulatory assets and liabilities8 3 (5)
Gains (losses) recognized in earnings (a)
Gains (losses) recognized in earnings (a)
49 (39)(8)
Net gains recognized as regulatory assets and liabilitiesNet gains recognized as regulatory assets and liabilities112 8 3 
Balance at Dec. 31Balance at Dec. 31$(49)$4 $29 Balance at Dec. 31$19 $(49)$4 
(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.
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 Dec. 31, 2021, 2020 2019 and 2018.2019.
Fair Value of Long-Term Debt
As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:
2020201920212020
(Millions of Dollars)(Millions of Dollars)Carrying AmountFair ValueCarrying AmountFair Value(Millions of Dollars)Carrying AmountFair ValueCarrying AmountFair Value
Long-term debt, including current portionLong-term debt, including current portion$20,066 $24,412 $18,109 $20,227 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, 20202021 and 2019,2020, 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. All newly hired or rehired employees participate under the Cash Balance formula, which is based on pay credits using a percentage of annual eligible pay and annual interest credits. The average annual interest crediting rates for these plans was 2.03, 1.89 2.82 and 3.62 percent2.82% in 2021, 2020, 2019, and 2018,2019, 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 who participated in the plan in 2008, when the SERP was closed to new participants.
The nonqualified pension plan provides benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows.
Obligations of the SERP and nonqualified plan as of Dec. 31, 20202021 and 20192020 were $43 million and $39$43 million, respectively. Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $4 million in 2021 and $6 million in 2020 and $4 million in 2019.2020.
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%.
•In 2021,2022, expected investment-return assumption is 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.

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Plan Assets
For each of the fair value hierarchy levels, Xcel Energy’s pension plan assets measured at fair value:
Dec. 31, 2020 (a)
Dec. 31, 2019 (a)
Dec. 31, 2021 (a)
Dec. 31, 2020 (a)
(Millions of Dollars)(Millions of Dollars)Level 1Level 2Level 3Measured at NAVTotalLevel 1Level 2Level 3Measured at NAVTotal(Millions of Dollars)Level 1Level 2Level 3Measured at NAVTotalLevel 1Level 2Level 3Measured at NAVTotal
Cash equivalentsCash equivalents$209 $0 $0 $0 $209 $145 $0 $0 $0 $145 Cash equivalents$133 $— $— $— $133 $209 $— $— $— $209 
Commingled fundsCommingled funds1,462 0 0 1,115 2,577 1,408 0 0 1,031 2,439 Commingled funds1,324 — — 1,143 2,467 1,462 — — 1,115 2,577 
Debt securitiesDebt securities0 714 4 0 718 0 645 4 0 649 Debt securities— 959 5 — 964 — 714 4 — 718 
Equity securitiesEquity securities77 0 0 0 77 86 0 0 0 86 Equity securities67 — — — 67 77 — — — 77 
OtherOther13 5 0 0 18 (120)5 0 (20)(135)Other— 7 — 32 39 13 5 — — 18 
TotalTotal$1,761 $719 $4 $1,115 $3,599 $1,519 $650 $4 $1,011 $3,184 Total$1,524 $966 $5 $1,175 $3,670 $1,761 $719 $4 $1,115 $3,599 
(a)See Note 10 for further information regarding fair value measurement inputs and methods.
For each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that were measured at fair value:
Dec. 31, 2020 (a)
Dec. 31, 2019 (a)
Dec. 31, 2021 (a)
Dec. 31, 2020 (a)
(Millions of Dollars)(Millions of Dollars)Level 1Level 2Level 3Measured at NAVTotalLevel 1Level 2Level 3Measured at NAVTotal(Millions of Dollars)Level 1Level 2Level 3Measured at NAVTotalLevel 1Level 2Level 3Measured at NAVTotal
Cash equivalentsCash equivalents$27 $0 $0 $0 $27 $23 $0 $0 $0 $23 Cash equivalents$28 $— $— $— $28 $27 $— $— $— $27 
Insurance contractsInsurance contracts0 50 0 0 50 0 51 0 0 51 Insurance contracts— 52 — — 52 — 50 — — 50 
Commingled fundsCommingled funds72 0 0 69 141 69 0 0 76 145 Commingled funds64 — — 77 141 72 — — 69 141 
Debt securitiesDebt securities0 232 0 0 232 0 228 1 0 229 Debt securities— 218 1 — 219 — 232 — — 232 
OtherOther0 2 0 0 2 0 1 0 0 1 Other— 2 — — 2 — 2 — — 2 
TotalTotal$99 $284 $0 $69 $452 $92 $280 $1 $76 $449 Total$92 $272 $1 $77 $442 $99 $284 $— $69 $452 
(a)See Note 10 for further information on fair value measurement inputs and methods.
NoNaN assets were transferred in or out of Level 3 for 2020. Immaterial assets were transferred in2021 or out of Level 3 for 2019.2020.
Funded Status — Benefit obligations for both pension and postretirement plans increaseddecreased from Dec. 31, 20192020 to Dec. 31, 2020,2021, due primarily to decreasesbenefit 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 BenefitsPension BenefitsPostretirement Benefits
(Millions of Dollars)(Millions of Dollars)2020201920202019(Millions of Dollars)2021202020212020
Change in Benefit Obligation:Change in Benefit Obligation:Change in Benefit Obligation:
Obligation at Jan. 1Obligation at Jan. 1$3,701 $3,477 $547 $542 Obligation at Jan. 1$3,964 $3,701 $574 $547 
Service costService cost95 86 1 2 Service cost104 95 2 1 
Interest costInterest cost125 145 18 22 Interest cost104 125 15 18 
Plan amendmentsPlan amendments0 1 0 0 Plan amendments5 — — — 
Actuarial loss328 273 50 19 
Actuarial (gain) lossActuarial (gain) loss(94)328 (41)50 
Plan participants’ contributionsPlan participants’ contributions0 0 8 8 Plan participants’ contributions— — 8 8 
Medicare subsidy reimbursementsMedicare subsidy reimbursements0 0 1 1 Medicare subsidy reimbursements— — 2 1 
Benefit payments (a)
Benefit payments (a)
(285)(281)(51)(47)
Benefit payments (a)
(365)(285)(49)(51)
Obligation at Dec. 31Obligation at Dec. 31$3,964 $3,701 $574 $547 Obligation at Dec. 31$3,718 $3,964 $511 $574 
Change in Fair Value of Plan Assets:Change in Fair Value of Plan Assets:Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1Fair value of plan assets at Jan. 1$3,184 $2,742 $449 $417 Fair value of plan assets at Jan. 1$3,599 $3,184 $452 $449 
Actual return on plan assetsActual return on plan assets550 568 35 56 Actual return on plan assets305 550 16 35 
Employer contributionsEmployer contributions150 155 11 15 Employer contributions131 150 15 11 
Plan participants’ contributionsPlan participants’ contributions0 0 8 8 Plan participants’ contributions— — 8 8 
Benefit paymentsBenefit payments(285)(281)(51)(47)Benefit payments(365)(285)(49)(51)
Fair value of plan assets at Dec. 31Fair value of plan assets at Dec. 31$3,599 $3,184 $452 $449 Fair value of plan assets at Dec. 31$3,670 $3,599 $442 $452 
Funded status of plans at Dec. 31Funded status of plans at Dec. 31$(365)$(517)$(122)$(98)Funded status of plans at Dec. 31$(48)$(365)$(69)$(122)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:Amounts recognized in the Consolidated Balance Sheet at Dec. 31:Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Noncurrent assetsNoncurrent assets$0 $0 $6 $21 Noncurrent assets$19 $— $33 $6 
Current liabilitiesCurrent liabilities0 0 (7)(6)Current liabilities— — (4)(7)
Noncurrent liabilitiesNoncurrent liabilities(365)(517)(121)(113)Noncurrent liabilities(67)(365)(98)(121)
Net amounts recognizedNet amounts recognized$(365)$(517)$(122)$(98)Net amounts recognized$(48)$(365)$(69)$(122)
(a)Includes approximately $197 million in 2021 and $0 million in 2020 and $20 million in 2019 of lump-sum benefit payments used in the determination of a settlement charge.
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Pension BenefitsPostretirement BenefitsPension BenefitsPostretirement Benefits
Significant Assumptions Used to Measure Benefit Obligations:Significant Assumptions Used to Measure Benefit Obligations:2020201920202019Significant Assumptions Used to Measure Benefit Obligations:2021202020212020
Discount rate for year-end valuationDiscount rate for year-end valuation2.71 %3.49 %2.65 %3.47 %Discount rate for year-end valuation3.08 %2.71 %3.09 %2.65 %
Expected average long-term increase in compensation levelExpected average long-term increase in compensation level3.75 3.75 N/AN/AExpected average long-term increase in compensation level3.75 3.75 N/AN/A
Mortality tableMortality tablePRI-2012PRI-2012PRI-2012PRI-2012Mortality tablePRI-2012PRI-2012PRI-2012PRI-2012
Health care costs trend rate — initial: Pre-65Health care costs trend rate — initial: Pre-65N/AN/A5.50 %6.00 %Health care costs trend rate — initial: Pre-65N/AN/A5.30 %5.50 %
Health care costs trend rate — initial: Post-65Health care costs trend rate — initial: Post-65N/AN/A5.00 %5.10 %Health care costs trend rate — initial: Post-65N/AN/A4.90 %5.00 %
Ultimate trend assumption — initial: Pre-65Ultimate trend assumption — initial: Pre-65N/AN/A4.50 %4.50 %Ultimate trend assumption — initial: Pre-65N/AN/A4.50 %4.50 %
Ultimate trend assumption — initial: Post-65Ultimate trend assumption — initial: Post-65N/AN/A4.50 %4.50 %Ultimate trend assumption — initial: Post-65N/AN/A4.50 %4.50 %
Years until ultimate trend is reachedYears until ultimate trend is reachedN/AN/A53Years until ultimate trend is reachedN/AN/A45
Accumulated benefit obligation for the pension plan was $3,693$3,469 million and $3,465$3,693 million as of Dec. 31, 20202021 and 2019,2020, 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 BenefitsPension BenefitsPostretirement Benefits
(Millions of Dollars)(Millions of Dollars)202020192018202020192018(Millions of Dollars)202120202019202120202019
Service costService cost$95 $86 $94 $1 $2 $2 Service cost$104 $95 $86 $2 $1 $2 
Interest costInterest cost125 145 133 18 22 22 Interest cost104 125 145 15 18 22 
Expected return on plan assetsExpected return on plan assets(208)(203)(209)(19)(21)(26)Expected return on plan assets(206)(208)(203)(18)(19)(21)
Amortization of prior service creditAmortization of prior service credit(4)(5)(5)(8)(10)(11)Amortization of prior service credit(1)(4)(5)(8)(8)(10)
Amortization of net lossAmortization of net loss100 87 111 4 5 8 Amortization of net loss107 100 87 5 4 5 
Settlement charge (a)
Settlement charge (a)
0 6 91 0 0 0 
Settlement charge (a)
59 — 6 — — — 
Net periodic pension cost (credit)Net periodic pension cost (credit)108 116 215 (4)(2)(5)Net periodic pension cost (credit)167 108 116 (4)(4)(2)
Effects of regulationEffects of regulation9 (1)(75)3 1 2 Effects of regulation(46)9 (1)2 3 1 
Net benefit cost (credit) recognized for financial reportingNet benefit cost (credit) recognized for financial reporting$117 $115 $140 $(1)$(1)$(3)Net benefit cost (credit) recognized for financial reporting$121 $117 $115 $(2)$(1)$(1)
Significant Assumptions Used to Measure Costs:Significant Assumptions Used to Measure Costs:Significant Assumptions Used to Measure Costs:
Discount rateDiscount rate3.49 %4.31 %3.63 %3.47 %4.32 %3.62 %Discount rate2.71 %3.49 %4.31 %2.65 %3.47 %4.32 %
Expected average long-term increase in compensation levelExpected average long-term increase in compensation level3.75 3.75 3.75 0 0 0 Expected average long-term increase in compensation level3.75 3.75 3.75 — — — 
Expected average long-term rate of return on assetsExpected average long-term rate of return on assets6.87 6.87 6.87 4.50 4.50 5.30 Expected average long-term rate of return on assets6.49 6.87 6.87 4.10 4.50 4.50 
(a)A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 20192021 and 2018,2019, as a result of lump-sum distributions during each plan year, Xcel Energy recorded a total pension settlement charge of $6$59 million and $91$6 million, respectively, the majority of which was not recognized due to the effects of regulation. A total of $1$7 million and $11$1 million was recorded in the consolidated statements of income in 20192021 and 2018,2019, respectively. There were no0 settlement charges recorded for the qualified pension plans in 2020.
Pension BenefitsPostretirement BenefitsPension BenefitsPostretirement Benefits
(Millions of Dollars)(Millions of Dollars)2020201920202019(Millions of Dollars)2021202020212020
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net lossNet loss$1,333 $1,447 $126 $95 Net loss$978 $1,333 $81 $126 
Prior service creditPrior service credit(11)(15)(15)(23)Prior service credit(9)(11)(7)(15)
TotalTotal$1,322 $1,432 $111 $72 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:Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assetsCurrent regulatory assets$82 $78 $0 $0 Current regulatory assets$74 $82 $— $— 
Noncurrent regulatory assetsNoncurrent regulatory assets1,181 1,285 125 80 Noncurrent regulatory assets846 1,181 90 125 
Current regulatory liabilitiesCurrent regulatory liabilities0 0 (1)(1)Current regulatory liabilities— — (1)(1)
Noncurrent regulatory liabilitiesNoncurrent regulatory liabilities0 0 (18)(12)Noncurrent regulatory liabilities— — (19)(18)
Deferred income taxesDeferred income taxes15 18 1 1 Deferred income taxes13 15 1 1 
Net-of-tax accumulated other comprehensive incomeNet-of-tax accumulated other comprehensive income44 51 4 4 Net-of-tax accumulated other comprehensive income36 44 3 4 
TotalTotal$1,322 $1,432 $111 $72 Total$969 $1,322 $74 $111 
Measurement dateDec. 31, 2020Dec. 31, 20192021Dec. 31, 2020Dec. 31, 20192021Dec. 31, 2020



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Cash Flows — Funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the requirements of income tax and other pension-related regulations. Required contributions were made in 20182019 —- 20212022 to meet minimum funding requirements.
Voluntary and required pension funding contributions:
•$12550 million in January 2022.
•$131 million in 2021.
•$150 million in 2020.
•$154 million in 2019.
•$150 million in 2018.
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:
•Expects to contribute approximately $10$9 million during 2022.
•$15 million during 2021.
•$11 million during 2020.
•$15 million during 2019.
•$11 million during 2018.
Targeted asset allocations:
Pension BenefitsPostretirement BenefitsPension BenefitsPostretirement Benefits
20202019202020192021202020212020
Domestic and international equity securitiesDomestic and international equity securities35 %37 %15 %15 %Domestic and international equity securities33 %35 %15 %15 %
Long-duration fixed income securitiesLong-duration fixed income securities35 30 0 0 Long-duration fixed income securities37 35 — — 
Short-to-intermediate fixed income securitiesShort-to-intermediate fixed income securities13 14 72 72 Short-to-intermediate fixed income securities11 13 71 72 
Alternative investmentsAlternative investments15 17 9 9 Alternative investments17 15 8 9 
CashCash2 2 4 4 Cash2 2 6 4 
TotalTotal100 %100 %100 %100 %Total100 %100 %100 %100 %
The asset allocations above reflect target allocations approved in the calendar year to take effect in the subsequent year.
Plan Amendments —In 2018, the PSCo postretirement plan was amended to add the 5% cash balance formula.
In 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 2020 which affected the postretirement benefit obligation.
In 2021, Xcel Energy amended the Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) to reduce supplemental benefits for non-bargaining participants as well as to allow the transfer of a portion of non-qualified pension obligations into the qualified plans.
Projected Benefit Payments
Xcel Energy’s projected benefit payments:
(Millions of Dollars)(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
2021$304 $44 $2 $42 
20222022282 43 2 41 2022$323 $42 $2 $40 
20232023274 42 2 40 2023257 41 2 39 
20242024265 41 2 39 2024253 40 2 38 
20252025259 39 2 37 2025251 38 2 36 
2026-20301,193 175 12 163 
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 and $38 million in 2018.2019.
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 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.
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. In December 2020, a settlement in principleColorado. Settlement of approximately $3 million was reached for approximately $3 million. The parties have sought and are awaiting court approval of settlement.
Arandell Corp. —in February 2021. In February 2019,July 2021, the casesettlement was remanded back to the U.S. District Court in Wisconsin.
Xcel Energy has concluded that a loss is remote for the remaining lawsuit.approved.
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Rate Matters and Other
MEC AcquisitionXcel Energy’s operating subsidiaries are involved in various regulatory proceedings arising in the ordinary course of business. Until resolution, typically in the form of a rate order, uncertainties may exist regarding the ultimate rate treatment for certain activities and Dispositiontransactions. Amounts have been recognized for probable and reasonably estimable losses that may result. Unless otherwise disclosed, any reasonably possible range of loss in excess of any recognized amount is not expected to have a material effect on the consolidated financial statements.
Minnesota Winter Storm Uri Costs — In January 2020, Xcel Energy, Inc. purchased MEC,its Minnesota jurisdiction, NSP-Minnesota is participating in a 760 MWcontested case regarding the prudency of incremental natural gas combined cycle facility,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 approximately $650 million from Southern Power Company.the best interest of its customers and stakeholders.
In July 2020, Xcel Energy sold MEC to Southwest Generation for $684 million. The gain on saleNSP-Minnesota filed rebuttal testimony in January 2022 detailing its position that the disallowances recommended by other parties lack any merit in the prudency review given the pertinent facts regarding NSP-Minnesota’s actions before, during and after the storm event. An MPUC decision is expected in the summer of approximately $20 million, which was offset by charitable giving, including COVID-19 relief efforts, had no material impact on earnings.2022.
Sherco — In 2018, NSP-Minnesota and SMMPASouthern Minnesota Municipal Power Agency (Co-owner of Sherco Unit 3) reached a settlement with GE related to a 2011 incident, which damaged the turbine at Sherco Unit 3 and resulted in an extended outage for repair. NSP-Minnesota notified the MPUC of its proposal to refund settlement proceeds to customers through the FCA.
In March 2019, the MPUC approved NSP-Minnesota’s settlement refund proposal. Additionally, the MPUC decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of an appeal pending between GE and NSP-Minnesota’s insurers. In February 2020, the Minnesota Court of Appeals affirmed the district court’s judgment in favor of GE. In March 2020, NSP-Minnesota’s insurers filed a petition seeking additional review by the Minnesota Supreme Court.
In April 2020, the Minnesota Supreme Court denied the insurers’ petition for further review, ending the litigation. In accordance with a prior MPUC order, NSP-Minnesota made a compliance filing in August 2020 detailing all costs that resulted from the outage and all insurance recoveries received by NSP-Minnesota in connection with the outage.
In January 2021, the Minnesota Office of the Attorney GeneralOAG and DOC filed comments recommendingrecommended that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the FCA. On Jan. 27, 2021, 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 forof the Westmoreland Coal Company filed an arbitration demand against NSP-Minnesota, SMMPASouthern 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. Westmoreland’s insurers quantified their losses as approximately $36 million.
Arbitration was delayed pending resolution of a separate lawsuit brought by NSP-Minnesota, SMMPA, and their insurers against various GE entities based on the inspection and maintenance advice GE provided for Sherco Unit 3. In July 2020, following the conclusion of the appeal that fully resolved the GE litigation, Westmoreland’s insurers served notice, which triggered the arbitration to resume.
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. It is uncertain when aprovision. A final resolution will occur, but it is unlikely an arbitration hearing will take place beforehas been scheduled for October 2022. The parties are also required to participate in mediation, which has been scheduled for the fourthfirst quarter 2021.of 2022. At this stage of the proceeding, before any discovery has been conducted/completed, a reasonable estimate of damages or range of damages cannot be determined.
MISO ROE Complaints — In November 2013 and February 2015, customer groups filed two ROE complaints against MISO TOs, which includes NSP-Minnesota and NSP-Wisconsin. The first complaint requested a reduction in base ROE transmission formula rates from 12.38% to 9.15% for the time period of Nov. 12, 2013 to Feb. 11, 2015, and removal of ROE adders (including those for RTO membership). The second complaint requested, for a subsequent time period, a base ROE reduction from 12.38% to 8.67%.
In September 2016, the FERC issued an order (Opinion No. 551) granting a 10.32% base ROE 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 Circuit subsequently vacated and remanded the FERC Opinion.Opinion No. 551.
In November 2019, the FERC issued an order (Opinion No. 569), which set the MISO base ROE at 9.88%, effective Sept. 28, 2016 and for the first complaint period. The FERC also dismissed the second complaint. In December 2019, MISO TOs filed a request for 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.
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 June 2020, various parties filed requests for rehearing of Opinion 569-A with the FERC. In November 2020, the FERC issued an order (Opinion No. 569-B) in response to the 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. Each 10 basis point reduction in the allowed base ROE for the first complaint andperiod, second complaint period and subsequent period relative to amounts accrued would reduce Xcel Energy’s net income by $1 million, $1 million and $2 million, respectively.
The MISO TOs and $1 million, respectively.
Variousvarious parties have filed petitions for review of Opinion Nos. 569, 569-A and 569-B at the D.C. Circuit. These appeals remain pending.Oral arguments were held in late 2021 and a decision is expected by the end of 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 March 2020, SPP and Oklahoma Gas & Electric separately filed petitions for review of the FERC’s orders at the D.C. Circuit. SPS has intervened in bothIn August 2021, the D.C Circuit issued a decision denying these appeals in support ofand upholding the FERC. Any refundsFERC’s orders. Refunds received by SPS are expected to be given back to SPS customers through future rates.
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Table The timing of Contentsthese refunds is uncertain.
In October 2017, SPS filed a separate related complaint 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 issued a tolling order granting a rehearing for further consideration in May 2018. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the amount 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. ThisFERC 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 stayed pendingexpected in the outcomefirst quarter of the separate2022. The D.C. Circuit appeal initiated in 2020 by Oklahoma Gas & Electric and SPP.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, 2020, SPS does not expect refunds to be probable under either of these commitments.2021, the full-year net capacity factor was 48.4%, resulting in no refund liability for 2021.
Contract Termination — SPS and Lubbock Power & LightLP&L are parties to a 25-year, 170 MW partial requirements contract. In October 2020, Lubbock Power & Light initiated discussions concerningMay 2021, SPS and LP&L finalized a settlement which would terminate the interpretationcontract upon LP&L’s move from the SPP to the Electric Reliability Council of contractual termsTexas (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 early terminationComanche Unit 3's operation and default. If the parties are unable to reach resolution, the contract calls for the matter to proceed to arbitration. Theavailability.
In September 2021, CORE Electric Cooperative filed a lawsuit in Colorado state court seeking an unspecified amount of anydamages. 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 depends on multiple factorsfor replacement power costs, claims for unjust enrichment and is currently unknown.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 were completed in 2020. Groundwater treatment activities will continue for many years.
The cost estimate for remediation and restoration of the entire site is approximately $199 million. At Dec. 31, 2020 and 2019, NSP-Wisconsin had a total liability of $19 million and $23 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 and application of a 3% carrying charge to the regulatory asset.
In January 2021, the EPA confirmed that NSP-Wisconsin completed its work on the soils and sediments at the Site and all that remains is the long-term groundwater pump and treat program.
Xcel Energy is currently investigating, remediating or performing post-closure actions at 12 other16 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 regulations that impose requirements for handling, storage, treatment and disposal of solid waste. Under the CCR Rule, utilities are required to complete groundwater sampling around their CCR landfills and surface impoundments. Currently, Xcel Energy has 98 regulated ash units in operation.
Xcel Energy is conducting groundwater sampling and monitoring and implementing assessment of corrective measures at certain CCR landfills and surface impoundments. In NSP-Minnesota, 0no results above the groundwater protection standards in the rule were identified. In PSCo, statistically significant increases above background concentrations were detected at 4 locations. Subsequently, assessment monitoring samples were collected at these locations and, basedBased on the results,further assessments, PSCo is evaluating options for corrective action at 2 locations, 1 of which indicates potential offsite impacts to groundwater. Until PSCo completes its assessments, itThe 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 a cease receipt and initiate a closure date ofby April 2021 for all CCR impoundments affected by the August 2018 D.C. Circuit ruling. The D.C. Circuit concluded that the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the storage or disposal of coal ash. This final rule required Xcel Energy to expedite closure plans for 2 impoundments.
In October 2020, NSP-Minnesota completed construction and placed in service a new impoundment to replace the clay lined impoundment at a cost of $9 million.impoundment. With the new ash pond in service, NSP-Minnesota has initiated closure activities for the existing ash pond at an estimated cost of $4 million. NSP-Minnesota has five years to complete closure activities.
PSCo is pursuing options to buildalso built an alternative collection and treatment system to remove the Comanche Station bottom ash collectionpond from service. The total cost of the alternate treatment system that will be constructed and in service in advance ofis approximately $25 million. PSCo worked expeditiously to meet the April 11, 2021 deadline. Oncedeadline, but was not able to remove the alternative bottom ash system is operational,pond from service until June 18, 2021. PSCo expects to negotiate a compliance order with the existing impoundmentEPA addressing the closure deadline as well as other potential issues. PSCo will initiatealso now proceed with closure perof the CCR Rule.pond, at an estimated cost of $3 million.
Closure costs for existing impoundments are included in the calculation of the ARO.
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Federal CWA WOTUSWaters of the U.S. Rule — In April 2020, the EPA and U.S. Army Corps of Engineers (“Agencies”) replaced the 2015 WOTUS rule and narrowedXcel Energy is monitoring ongoing changes to the definition of WOTUS (“2020 WOTUS Rule”). The new definition simplifies the process whether waters are subject to CWA jurisdiction and streamlines the permitting process. In June 2020,Waters of the U.S. District Court forunder the District of Colorado stayed the effective date of the 2020 WOTUS Rule in Colorado, where the pre-2015 definition of WOTUS is now in effect.CWA. Regardless of which definition is applicable in the states in which we operate, Xcel Energy does not anticipate that compliance costs will be material.
Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to surface waters as well as utility-owned landfills that receive CCRs. In October 2020, the EPA published a final rule revising the regulations.
The retirement of units affected by the final ELG rule is subject to regulatory approval.The exact total cost of ELG compliance is therefore uncertain but Xcel Energydoes not anticipate that compliance costs will be material.
Federal CWA Section 316(b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing impingement and entrainment of aquatic species. Xcel Energy estimates the likely future cost for complying with impingement and entrainment requirements is approximately $41$39 million, to be incurred between 20212022 and 2028. Xcel Energy believes 6 NSP-Minnesota plants and 2 NSP-Wisconsin plants could be required 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 $191$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 regional haze first planning period requirements developed by Minnesota and Colorado were approved by the EPA in 2012 and implemented by 2014 and 2016, respectively. Texas’ first regional haze plan has undergone federal 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. 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. The EPA reaffirmed the rule in August 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 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. As states are now proceeding with the second regional haze planning period, the EPA may choose not to 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 was monitored for the three years ending in 2019 and the monitoring showed the area to be exceeding the standard.
To address this issue, SPS negotiated an order with the TCEQ providing for the end of coal combustion and the conversion of the Harrington plant to a natural gas fueled facility by Jan. 1, 2025.
Xcel Energy believes 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 $3.3 billion and $2.8 billion for 2021 and $2.4 billion for 2020, and 2019, respectively.
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Xcel Energy’s AROs were as follows:
(Millions
of Dollars)		(Millions
of Dollars)		Jan. 1, 2020
Amounts
Incurred
(a)
Amounts Settled (b)
Accretion
Cash Flow
 Revisions (c)
Dec. 31, 2020(Millions
of Dollars)		Jan. 1, 2021
Amounts Incurred (a)
Accretion
Cash Flow Revisions (b)
Dec. 31, 2021 (c)
ElectricElectricElectric
NuclearNuclear$2,068 $0 $0 $105 $(216)$1,957 Nuclear$1,957 $— $99 $— $2,056 
WindWind360 101 17 — 478 
Steam, hydro and other productionSteam, hydro and other production202 0 (5)9 58 264 Steam, hydro and other production264 6 10 8 288 
Wind146 149 (3)8 60 360 
DistributionDistribution44 0 0 2 0 46 Distribution46 — 1 — 47 
Natural gasNatural gasNatural gas
Transmission and distributionTransmission and distribution236 0 0 10 6 252 Transmission and distribution252 — 10 9 271 
MiscellaneousMiscellaneous3 0 0 0 0 3 Miscellaneous3 — — 5 8 
CommonCommonCommon
MiscellaneousMiscellaneous1 0 0 0 0 1 Miscellaneous1 — — — 1 
Non-utilityNon-utilityNon-utility
MiscellaneousMiscellaneous1 0 0 0 0 1 Miscellaneous1 — 1 — 2 
Total liabilityTotal liability$2,701 $149 $(8)$134 $(92)$2,884 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 $0 $0 $100 $0 $2,068 
Steam, hydro and other production177 0 (5)8 22 202 
Wind119 26 0 7 (6)146 
Distribution42 0 0 2 0 44 
Miscellaneous7 0 0 0 (7)0 
Natural gas
Transmission and distribution249 0 0 11 (24)236 
Miscellaneous4 0 0 0 (1)3 
Common
Miscellaneous1 0 0 0 0 1 
Non-utility
Miscellaneous1 0 0 0 0 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. Revisions 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 changes in cost estimates to remediate ponds at production facilities. Revisions in wind AROs were driven by new dismantling studies.
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, 2020.2021. Therefore, an ARO was not recorded for these facilities.
Nuclear Related
Nuclear Insurance — NSP-Minnesota’s public liability for claims from any nuclear incident is limited to $13.8$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 $13.3$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 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.
NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and EMANI. The coverage limits are $2.8 billion for each of NSP-Minnesota’s 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 $11 million for business interruption insurance and $34$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 47 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 2095.2091. 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.
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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 $2.8$3.3 billion of assets held in external decommissioning trusts at Dec. 31, 2020.2021. 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 BasisRegulatory Basis
(Millions of Dollars)(Millions of Dollars)20202019(Millions of Dollars)20212020
Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars)Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars)$3,012 $3,012 Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars)$3,012 $3,012 
Effect of escalating costsEffect of escalating costs844 688 Effect of escalating costs1,006 844 
Estimated decommissioning cost obligation (in current dollars)Estimated decommissioning cost obligation (in current dollars)3,856 3,700 Estimated decommissioning cost obligation (in current dollars)4,018 3,856 
Effect of escalating costs to payment dateEffect of escalating costs to payment date7,349 7,505 Effect of escalating costs to payment date7,187 7,349 
Estimated future decommissioning costs (undiscounted)Estimated future decommissioning costs (undiscounted)11,205 11,205 Estimated future decommissioning costs (undiscounted)11,205 11,205 
Effect of discounting obligation (using average risk-free interest rate of 1.64% and 2.39% for 2020 and 2019, respectively)(4,181)(5,562)
Effect of discounting obligation (using average risk-free interest rate of 1.96% and 1.64% for 2021 and 2020, respectively)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 obligationDiscounted decommissioning cost obligation$7,024 $5,643 Discounted decommissioning cost obligation$6,554 $7,024 
Assets held in external decommissioning trustAssets held in external decommissioning trust$2,777 $2,440 Assets held in external decommissioning trust$3,256 $2,777 
Underfunding of external decommissioning fund compared to the discounted decommissioning obligationUnderfunding of external decommissioning fund compared to the discounted decommissioning obligation4,247 3,203 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)(Millions of Dollars)20202019(Millions of Dollars)20212020
Discounted decommissioning cost obligation - regulated basisDiscounted decommissioning cost obligation - regulated basis$7,024 $5,643 Discounted decommissioning cost obligation - regulated basis$6,554 $7,024 
Differences in discount rate and market risk premiumDifferences in discount rate and market risk premium(2,628)(2,295)Differences in discount rate and market risk premium(2,209)(2,628)
O&M costs not included for GAAPO&M costs not included for GAAP(1,734)(1,280)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)0 ARO differences between 2020 and 2014 cost studies(705)(705)
Nuclear production decommissioning ARO - GAAPNuclear production decommissioning ARO - GAAP$1,957 $2,068 Nuclear production decommissioning ARO - GAAP$2,056 $1,957 
Decommissioning expenses recognized as a result of regulation:
(Millions of Dollars)(Millions of Dollars)202020192018(Millions of Dollars)202120202019
Annual decommissioning recorded as depreciation expense: (a) (b)
Annual decommissioning recorded as depreciation expense: (a) (b)
$20 $20 $20 
Annual decommissioning recorded as depreciation expense: (a) (b)
$22 $20 $20 
(a)Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.
(b)Decommissioning expenses in 2021, 2020 2019 and 20182019 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million.
The 20142017 nuclear decommissioning filing, effective Jan. 1, 2019, has been approved in 2015, was used for regulatory presentation inby the MPUC. In March 2020, 2019 and 2018. Although there was a nuclear triennial filing in 2017, the MPUC continuedapproved for NSP-Minnesota to approvedelay any increase to the 2014 triennial filing as the regulatory basis in 2020, 2019 and 2018.annual funding requirement until 2021. In December 2020, the MPUC verbally approved for NSP-Minnesota to continue usingdelay any increase to the 2014annual funding requirement until 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, aswas the basis for 2021.10-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. A contract contains a lease if it conveys the exclusive right to control the use of a specific asset. A contract determined to contain a lease is evaluated further to determine if the arrangement is a finance lease.
ROU assets represent Xcel Energy's rights to use leased assets. The present value of future operating lease payments 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 4.0%). 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, 2020 (a)
Dec. 31, 2019
PPAs$1,650 $1,642 
Other212 201 
Gross operating lease ROU assets1,862 1,843 
Accumulated amortization(372)(171)
Net operating lease ROU assets$1,490 $1,672 
(a)In 2020, Xcel Energy purchased MEC, which was subsequently sold. During the period of ownership, the MEC PPA was not accounted for as an operating lease. Xcel Energy reestablished the operating lease ROU asset of approximately $350 million upon the sale of MEC to a third party.
(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 
ROU assets for finance leases are included in other noncurrent assets, and the present value of future finance lease payments is included in other current liabilities and other noncurrent liabilities.
Xcel Energy’s most significant finance lease activities are related to WYCO, a joint venture with CIG, to develop and lease natural gas pipeline, storage and compression facilities. Xcel Energy Inc. has a 50% ownership interest in WYCO. WYCO leases its facilities to CIG, and CIG operates the facilities, providing natural gas storage and transportation services to PSCo under separate service agreements.
PSCo accounts for its Totem natural gas storage service and Front Range pipeline arrangements with CIG and WYCO, respectively, as finance leases. Xcel Energy Inc. eliminates 50% of the finance lease obligation related to WYCO in the consolidated balance sheet along with an equal amount of Xcel Energy Inc.’s equity investment in WYCO.
Finance lease ROU assets:
(Millions of Dollars)Dec. 31, 2020Dec. 31, 2019
Gas storage facilities$201 $201 
Gas pipeline21 21 
Gross finance lease ROU assets222 222 
Accumulated amortization(90)(83)
Net finance lease ROU assets$132 $139 
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Finance lease ROU assets:
(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)(Millions of Dollars)202020192018(Millions of Dollars)202120202019
Operating leasesOperating leasesOperating leases
PPA capacity paymentsPPA capacity payments$238 $221 $210 PPA capacity payments$251 $238 $221 
Other operating leases (a)
Other operating leases (a)
26 34 38 
Other operating leases (a)
36 26 34 
Total operating lease expense (b)
Total operating lease expense (b)
$264 $255 $248 
Total operating lease expense (b)
$287 $264 $255 
Finance leasesFinance leasesFinance leases
Amortization of ROU assetsAmortization of ROU assets$7 $6 $6 Amortization of ROU assets$7 $7 $6 
Interest expense on lease liabilityInterest expense on lease liability18 19 19 Interest expense on lease liability17 18 19 
Total finance lease expenseTotal finance lease expense$25 $25 $25 Total finance lease expense$24 $25 $25 
(a)Includes short-term lease expense of $5 million for 2021, 2020 2019 and 2018.2019.
(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.
Commitments under operating and finance leases as of Dec. 31, 2020:2021:
(Millions of Dollars)(Millions of Dollars)
PPA (a) (b)
Operating
Leases
Other Operating
Leases
Total
Operating
Leases
Finance
 Leases (c)
(Millions of Dollars)
PPA (a) (b)
Operating
Leases
Other Operating
Leases
Total
Operating
Leases
Finance
 Leases (c)
2021$247 $26 $273 $14 
20222022228 30 258 12 2022$229 $27 $256 $12 
20232023218 21 239 12 2023221 26 247 12 
20242024209 21 230 12 2024209 22 231 12 
20252025189 15 204 10 2025189 16 205 10 
20262026146 12 158 9 
ThereafterThereafter561 94 655 197 Thereafter416 81 497 187 
Total minimum obligationTotal minimum obligation1,652 207 1,859 257 Total minimum obligation1,410 184 1,594 242 
Interest component of obligationInterest component of obligation(262)(39)(301)(180)Interest component of obligation(209)(34)(243)(170)
Present value of minimum obligationPresent value of minimum obligation$1,390 168 1,558 77 Present value of minimum obligation$1,201 150 1,351 72 
Less current portionLess current portion(214)(4)Less current portion(205)(3)
Noncurrent operating and finance lease liabilitiesNoncurrent operating and finance lease liabilities$1,344 $73 Noncurrent operating and finance lease liabilities$1,146 $69 
Weighted-average remaining lease term in yearsWeighted-average remaining lease term in years8.536.5Weighted-average remaining lease term in years8.936.1
(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 2033.2039.
(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 2033 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 in 2021, 2020 and $105 million in 2020, 2019, and 2018, 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 in 2021, 2020 and $131 million in 2020, 2019, and 2018, 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, 2020,2021, 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)(Millions of Dollars)Capacity
Energy (a)
(Millions of Dollars)Capacity
Energy (a)
2021$71 $156 
2022202275 172 2022$75 $165 
2023202377 176 202377 169 
2024202472 181 202472 174 
2025202529 60 202529 53 
2026202612 10 
ThereafterThereafter24 85 Thereafter12 38 
TotalTotal$348 $830 Total$277 $609 
(a)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 20212022 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, 2020:2021:
(Millions of Dollars)(Millions of Dollars)CoalNuclear fuelNatural gas supplyNatural gas supply and transportation(Millions of Dollars)CoalNuclear fuelNatural gas supplyNatural gas supply and transportation
2021$298 $101 $453 $287 
20222022165 87 120 280 2022$620 $89 $477 $292 
2023202358 103 55 217 2023233 109 75 224 
2024202424 83 3 165 2024147 82 4 172 
2025202524 121 0 149 202529 119 — 156 
2026202631 29 — 149 
ThereafterThereafter52 274 0 708 Thereafter34 309 — 571 
TotalTotal$621 $769 $631 $1,806 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.
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The utility subsidiaries had approximately 4,062 MW and 3,986 MW of capacity under long-term PPAs at both Dec. 31, 20202021 and 2019, respectively,2020 with entities that have been determined to be VIEs. AgreementsThese agreements have expiration dates through 2041.
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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)(Millions of Dollars)Dec. 31, 2020Dec. 31, 2019(Millions of Dollars)Dec. 31, 2021Dec. 31, 2020
Current assetsCurrent assets$7 $7 Current assets$7 $7 
Property, plant and equipment, netProperty, plant and equipment, net38 41 Property, plant and equipment, net37 38 
Other noncurrent assetsOther noncurrent assets1 1 Other noncurrent assets1 1 
Total assetsTotal assets$46 $49 Total assets$45 $46 
Current liabilitiesCurrent liabilities$8 $8 Current liabilities$7 $8 
Mortgages and other long-term debt payableMortgages and other long-term debt payable25 26 Mortgages and other long-term debt payable27 25 
Other noncurrent liabilitiesOther noncurrent liabilities1 0 Other noncurrent liabilities1 1 
Total liabilitiesTotal liabilities$34 $34 Total liabilities$35 $34 

Other
Technology Agreements — Xcel Energy has several contracts for information technology services that extend through 2022. The contracts are cancelable, although there are financial penalties for early termination. Xcel Energy capitalized or expensed $103 million, $110 million $101 million and $127$101 million associated with these contracts in 2021, 2020 2019 and 2018,2019, respectively.
Committed minimum payments under these obligations are $33 million in 2021 and $15 million in 2022.
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, 20202021 and 2019,2020, 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 $62 million at both Dec. 31, 2021 and 2020 and 2019.respectively.
Other Indemnification Agreements — Xcel Energy Inc. and its subsidiaries provide indemnifications through various contracts. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold. Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.
13. Other Comprehensive Income
Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31:
20202021
(Millions of Dollars)(Millions of Dollars)Gains and Losses on Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotal(Millions of Dollars)Gains and Losses on Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotal
Accumulated other comprehensive loss at Jan. 1Accumulated other comprehensive loss at Jan. 1$(80)$(61)$(141)Accumulated other comprehensive loss at Jan. 1$(85)$(56)$(141)
Other comprehensive loss before reclassifications (net of taxes of $(3) and $(2), respectively)(10)(5)(15)
Other comprehensive loss before reclassifications (net of taxes of $1 and $—, respectively)Other comprehensive loss before reclassifications (net of taxes of $1 and $—, respectively)4 — 4 
Losses reclassified from net accumulated other comprehensive loss:Losses reclassified from net accumulated other comprehensive loss:Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $2 and $0, respectively)5 (a)0 5 
Amortization of net actuarial loss (net of taxes of $0 and $3, respectively)0 10 (b)10 
Net current period other comprehensive (loss) income(5)5 0 
Interest rate derivatives (net of taxes of $2 and $—, respectively)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)Amortization of net actuarial loss (net of taxes of $— and $3, respectively)— 8 (b)8 
Net current period other comprehensive incomeNet current period other comprehensive income10 8 18 
Accumulated other comprehensive loss at Dec. 31Accumulated other comprehensive loss at Dec. 31$(85)$(56)$(141)Accumulated other comprehensive loss at Dec. 31$(75)$(48)$(123)
(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.
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20192020
(Millions of Dollars)(Millions of Dollars)Gains and Losses on Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotal(Millions of Dollars)Gains and Losses on Cash Flow HedgesDefined Benefit Pension and Postretirement ItemsTotal
Accumulated other comprehensive loss at Jan. 1Accumulated other comprehensive loss at Jan. 1$(60)$(64)$(124)Accumulated other comprehensive loss at Jan. 1$(80)$(61)$(141)
Other comprehensive loss before reclassifications (net of taxes of $(8) and $0, respectively)(23)0 (23)
Other comprehensive loss before reclassifications (net of taxes of $(3) and $(2), respectively)Other comprehensive loss before reclassifications (net of taxes of $(3) and $(2), respectively)(10)(5)(15)
Losses reclassified from net accumulated other comprehensive loss:Losses reclassified from net accumulated other comprehensive loss:Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $1 and $0, respectively)3 (a)0 3 
Amortization of net actuarial loss (net of taxes of $0 and $1, respectively)0 3 (b)3 
Interest rate derivatives (net of taxes of $2 and $—, respectively)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)Amortization of net actuarial loss (net of taxes of $— and $3, respectively)— 10 (b)10 
Net current period other comprehensive (loss) incomeNet current period other comprehensive (loss) income(20)3 (17)Net current period other comprehensive (loss) income(5)5 — 
Accumulated other comprehensive loss at Dec. 31Accumulated other comprehensive loss at Dec. 31$(80)$(61)$(141)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.
14. Segment Information
Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided, including the regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.
Xcel Energy has the following reportable segments:
•Regulated Electric — The regulated electric utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes wholesale commodity and trading operations.
•Regulated Natural Gas — The regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado.
Xcel Energy also presents All Other, which includes operating segments with revenues below the necessary quantitative thresholds. Those operating segments primarily include steam revenue, appliance repair services, non-utility real estate activities, revenues associated with processing solid waste into refuse-derived fuel, investments in rental housing projects that qualify for low-income housing tax credits and the operations of MEC until July 2020.
Xcel Energy had equity method investments in unconsolidated subsidiaries of $165$208 million and $155$165 million as of Dec. 31, 20202021 and 2019,2020, 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)202020192018
Regulated Electric
Operating revenues - external$9,802 $9,575 $9,719 
Intersegment revenue2 1 1 
Total revenues$9,804 $9,576 $9,720 
Depreciation and amortization1,673 1,535 1,421 
Interest charges and financing costs534 500 449 
Income tax expense1 125 187 
Net income1,407 1,288 1,177 
Regulated Natural Gas
Operating revenues - external$1,636 $1,868 $1,739 
Intersegment revenue1 2 2 
Total revenues$1,637 $1,870 $1,741 
Depreciation and amortization252 219 212 
Interest charges and financing costs71 69 61 
Income tax expense17 48 28 
Net income190 195 187 
All Other
Total revenues$88 $86 $79 
Depreciation and amortization23 11 9 
Interest charges and financing costs193 167 142 
Income tax benefit(24)(45)(34)
Net loss(124)(111)(103)
Consolidated Total
Total revenues$11,529 $11,532 $11,540 
Reconciling eliminations(3)(3)(3)
Total operating revenues$11,526 $11,529 $11,537 
Depreciation and amortization1,948 1,765 1,642 
Interest charges and financing costs798 736 652 
Income tax (benefit) expense(6)128 181 
Net income1,473 1,372 1,261 
15. Summarized Quarterly Financial Data (Unaudited)
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
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Quarter Ended
(Amounts in millions, except per share data)March 31, 2019June 30, 2019Sept. 30, 2019Dec. 31, 2019
Operating revenues$3,141 $2,577 $3,013 $2,798 
Operating income486 410 758 450 
Net income315 238 527 292 
EPS total — basic$0.61 $0.46 $1.02 $0.56 
EPS total — diluted0.610.461.010.56
Cash dividends declared per common share0.4050.4050.4050.405
(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 
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.
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As of Dec. 31, 20202021, 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, 20202021 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, Xcel Energy conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, Xcel Energy did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board, as approved by the SEC and as indicated in Xcel Energy’s Management Report on Internal Controls over Financial Reporting, which is contained in Item 8 herein.
ITEM 9B — OTHER INFORMATION
None.
ITEM 9C — DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.

PART III
ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information required under this Item with respect to Directors and Corporate Governance is set forth in Xcel Energy Inc.’s Proxy Statement for its 20212022 Annual Meeting of Shareholders, which is expected to occur on April 6, 2021,5, 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 20212022 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 20212022 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 20212022 Annual Meeting of Shareholders, which is incorporated by reference.
ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information required under this Item (aggregate fees billed to us by our principal accountant, Deloitte & Touche LLP (PCAOB ID No. 34)) is contained in Xcel Energy Inc.’s Proxy Statement for its 20212022 Annual Meeting of Shareholders, which is incorporated by reference.


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PART IV
ITEM 15 — EXHIBIT AND FINANCIAL STATEMENT SCHEDULES
1Consolidated Financial Statements
Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2020.2021.
Report of Independent Registered Public Accounting Firm — Financial Statements and Internal Controls Over Financial Reporting
Consolidated Statements of Income — For each of the three years ended Dec. 31, 2021, 2020, 2019, and 2018.2019.
Consolidated Statements of Comprehensive Income — For each of the three years ended Dec. 31, 2021, 2020, 2019, and 2018.2019.
Consolidated Statements of Cash Flows — For each of the three years ended Dec. 31, 2021, 2020, 2019, and 2018.2019.
Consolidated Balance Sheets — As of Dec. 31, 20202021 and 2019.2020.
Consolidated Statements of Common Stockholders’ Equity — For each of the three years ended Dec. 31, 2021, 2020, 2019, and 2018.2019.
2Schedule I — Condensed Financial Information of Registrant.
Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2021, 2020, 2019 and 2018.2019.
3Exhibits
*Indicates incorporation by reference
+Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
Xcel Energy Inc.
Exhibit NumberDescriptionReport or Registration StatementExhibit Reference
Xcel Energy Inc. Form 8-K dated May 16, 20123.01
Xcel Energy Inc. Form 8-K dated April 3, 20203.01
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 20194.01
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Xcel Energy Inc. Form 8-K dated Dec. 14, 20004.01
Xcel Energy Inc. Form 8-K dated June 6, 20064.01
Xcel Energy Inc. Form 8-K dated Jan. 16, 20084.01
Xcel Energy Inc. Form 8-K dated Jan. 16, 20084.03
Xcel Energy Inc. Form 8-K dated Sept. 12, 20114.01
Xcel Energy Inc. Form 8-K dated June 1, 20154.01
Xcel Energy Inc. Form 8-K dated March 8 20164.02
Xcel Energy Inc. Form 8-K dated Dec. 1, 20164.01
Xcel Energy Inc. Form 8-K dated June 25, 20184.01
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. 3, 20214.01
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 200810.02
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 200810.05
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 201110.18
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 201610.01
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, 200810.17
Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010Appendix A
Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 201310.01
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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, 2011Appendix A
Xcel Energy Inc. Form 8-K dated May 20, 201510.02
Xcel Energy Inc. Form 10-Q for the quarter ended September 30, 202110.01
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 201810.36
Xcel Energy Inc. Form U5B dated Nov. 16, 2000H-1
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Xcel Energy Inc. Form 8-K dated June 7, 2019
99.01
Xcel Energy Inc. Form 8-K dated February 18, 202110.01
Xcel Energy Inc. Form 8-K dated December 10, 202110.01
NSP-Minnesota
Xcel Energy Inc. Form S-3 dated April 18, 20184(b)(3)
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 20174.11
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 20174.12
NSP-Minnesota Form 10-12G dated Oct. 5, 20004.51
Xcel Energy Inc. Form S-3 dated April 18, 20184(b)(7)
NSP-Minnesota Form 10-12G dated Oct. 5, 20004.63
NSP-Minnesota Form 8-K dated July 14, 20054.01
NSP-Minnesota Form 8-K dated May 18, 20064.01
NSP-Minnesota Form 8-K dated June 19, 20074.01
NSP-Minnesota Form 8-K dated Nov. 16, 20094.01
NSP-Minnesota Form 8-K dated Aug. 4, 20104.01
NSP-Minnesota Form 8-K dated Aug. 13, 20124.01
NSP-Minnesota Form 8-K dated May 20, 20134.01
NSP-Minnesota Form 8-K dated May 13, 20144.01
NSP-Minnesota Form 8-K dated Aug. 11, 20154.01
NSP-Minnesota Form 8-K dated May 31, 20164.01
NSP-Minnesota Form 8-K dated Sept. 13, 20174.01
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NSP-Minnesota Form 8-K dated Sept. 10, 20194.01
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, 200410.01
Xcel Energy Inc. Form 8-K dated June 7, 201999.02
NSP-Wisconsin
Xcel Energy Inc. Form S-3 dated April 18, 20184(c)(3)
NSP-Wisconsin Form 8-K dated Sept. 25, 20004.01
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NSP-Wisconsin Form 8-K dated Sept. 3, 20084.01
NSP-Wisconsin Form 8-K dated Oct. 10, 20124.01
NSP-Wisconsin Form 8-K dated June 23, 20144.01
NSP-Wisconsin Form 8-K dated Dec. 4, 20174.01
NSP-Wisconsin Form 8-K dated Sept. 12, 20184.01
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, 200410.01
Xcel Energy Inc. Form 8-K dated June 7, 201999.05
NSP-Wisconsin Form 8-K dated July 20, 20211.01
PSCo
Xcel Energy Inc. Form S-3 dated April 18, 20184(d)(3)
PSCo Form 8-K dated Aug. 8, 20074.01
PSCo Form 8-K dated Aug. 6, 20084.01
PSCo Form 8-K dated Aug. 9, 20114.01
PSCo Form 8-K dated Sept. 11, 20124.01
PSCo Form 8-K dated March 26, 20134.01
PSCo Form 8-K dated March 10, 20144.01
PSCo Form 8-K dated May 12, 20154.01
PSCo Form 8-K dated June 13, 20164.01
PSCo Form 8-K dated June 19, 20174.01
PSCo Form 8-K dated June 21, 20184.01
PSCo Form 8-K dated March 13, 20194.01
PSCo Form 8-K dated August 13, 20194.01
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, 200499.02
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Xcel Energy Inc. Form 8-K dated June 7, 201999.03
SPS
SPS Form 8-K dated Feb. 25, 199999.2
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 20034.04
SPS Form 8-K dated Oct. 3, 20064.01
SPS Form 8-K dated Aug. 10, 20114.01
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SPS Form 8-K dated Aug. 10, 20114.02
SPS Form 8-K dated June 9, 20144.02
SPS Form 8-K dated Aug. 12, 20164.02
SPS Form 8-K dated Aug 9. 20174.02
SPS Form 8-K dated Nov. 5, 20184.02
SPS Form 8-K dated June 18, 20194.02
SPS Form 8-K dated May 18, 20204.02
Xcel Energy Inc. Form 8-K dated June 7, 201999.04
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)
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SCHEDULE I
XCEL ENERGY INC.
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(amounts in millions, except per share data)
Year Ended Dec. 31Year Ended Dec. 31
202020192018202120202019
IncomeIncomeIncome
Equity earnings of subsidiariesEquity earnings of subsidiaries$1,646 $1,505 $1,393 Equity earnings of subsidiaries$1,744 $1,646 $1,505 
Total incomeTotal income1,646 1,505 1,393 Total income1,744 1,646 1,505 
Expenses and other deductionsExpenses and other deductionsExpenses and other deductions
Operating expensesOperating expenses43 23 24 Operating expenses21 43 23 
Other incomeOther income(4)(9)(1)Other income3 (4)(9)
Interest charges and financing costsInterest charges and financing costs198 173 149 Interest charges and financing costs173 198 173 
Total expenses and other deductionsTotal expenses and other deductions237 187 172 Total expenses and other deductions197 237 187 
Income before income taxesIncome before income taxes1,409 1,318 1,221 Income before income taxes1,547 1,409 1,318 
Income tax benefitIncome tax benefit(64)(54)(40)Income tax benefit(50)(64)(54)
Net incomeNet income$1,473 $1,372 $1,261 Net income$1,597 $1,473 $1,372 
Other Comprehensive IncomeOther Comprehensive IncomeOther Comprehensive Income
Pension and retiree medical benefits, net of tax of $ 1, $1 and $1, respectivelyPension and retiree medical benefits, net of tax of $ 1, $1 and $1, respectively$5 $3 $3 Pension and retiree medical benefits, net of tax of $ 1, $1 and $1, respectively$8 $5 $3 
Derivative instruments, net of tax of $(1), $(7) and $(1), respectively(5)(20)(2)
Derivative instruments, net of tax of $3, $(1) and $(7), respectivelyDerivative instruments, net of tax of $3, $(1) and $(7), respectively10 (5)(20)
Other comprehensive income (loss)Other comprehensive income (loss)0 (17)1 Other comprehensive income (loss)18 — (17)
Comprehensive incomeComprehensive income$1,473 $1,355 $1,262 Comprehensive income$1,615 $1,473 $1,355 
Weighted average common shares outstanding:Weighted average common shares outstanding:Weighted average common shares outstanding:
BasicBasic527 519 511 Basic539 527 519 
DilutedDiluted528 520 511 Diluted540 528 520 
Earnings per average common share:Earnings per average common share:Earnings per average common share:
BasicBasic$2.79 $2.64 $2.47 Basic$2.96 $2.79 $2.64 
DilutedDiluted2.79 2.64 2.47 Diluted2.96 2.79 2.64 
See Notes to Condensed Financial StatementsSee Notes to Condensed Financial StatementsSee Notes to Condensed Financial Statements

XCEL ENERGY INC.
CONDENSED STATEMENTS OF CASH FLOWS
(amounts in millions)
Year Ended Dec. 31
202020192018
Operating activities
Net cash provided by operating activities$2,377 $1,389 $1,210 
Investing activities
Capital contributions to subsidiaries(2,553)(1,594)(809)
Net (investments) return in the utility money pool(18)39 (85)
Other, net(1)0 0 
Net cash used in investing activities(2,572)(1,555)(894)
Financing activities
(Repayment of) proceeds from short-term borrowings, net(500)12 (295)
Proceeds from issuance of long-term debt1,089 1,120 492 
Repayment of long-term debt(300)(550)0 
Proceeds from issuance of common stock727 458 230 
Repurchase of common stock(4)0 (1)
Dividends paid(856)(791)(730)
Other(17)(14)(12)
Net cash provided by (used in) financing activities139 235 (316)
Net change in cash and cash equivalents(56)69 0 
Cash and cash equivalents at beginning of period70 1 1 
Cash and cash equivalents at end of period$14 $70 $1 
See Notes to Condensed Financial Statements

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 BALANCE SHEETS
(amounts in millions)
Dec. 31Dec. 31
2020201920212020
AssetsAssetsAssets
Cash and cash equivalentsCash and cash equivalents$14 $70 Cash and cash equivalents$1 $14 
Accounts receivable from subsidiariesAccounts receivable from subsidiaries424 370 Accounts receivable from subsidiaries430 424 
Other current assetsOther current assets6 12 Other current assets6 6 
Total current assetsTotal current assets444 452 Total current assets437 444 
Investment in subsidiariesInvestment in subsidiaries19,102 17,443 Investment in subsidiaries21,167 19,102 
Other assetsOther assets40 60 Other assets71 40 
Total other assetsTotal other assets19,142 17,503 Total other assets21,238 19,142 
Total assetsTotal assets$19,586 $17,955 Total assets$21,675 $19,586 
Liabilities and EquityLiabilities and EquityLiabilities and Equity
Current portion of long-term debtCurrent portion of long-term debt400 0 Current portion of long-term debt— 400 
Dividends payableDividends payable231 212 Dividends payable249 231 
Short-term debtShort-term debt0 500 Short-term debt638 — 
Other current liabilitiesOther current liabilities21 33 Other current liabilities29 21 
Total current liabilitiesTotal current liabilities652 745 Total current liabilities916 652 
Other liabilitiesOther liabilities17 23 Other liabilities10 17 
Total other liabilitiesTotal other liabilities17 23 Total other liabilities10 17 
Commitments and contingenciesCommitments and contingenciesCommitments and contingencies
CapitalizationCapitalizationCapitalization
Long-term debtLong-term debt4,342 3,948 Long-term debt5,137 4,342 
Common stockholders' equityCommon stockholders' equity14,575 13,239 Common stockholders' equity15,612 14,575 
Total capitalizationTotal capitalization18,917 17,187 Total capitalization20,749 18,917 
Total liabilities and equityTotal liabilities and equity$19,586 $17,955 Total liabilities and equity$21,675 $19,586 
See Notes to Condensed Financial StatementsSee Notes to Condensed Financial StatementsSee 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, 20202021 and 2019,2020, 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, 2020:2021:
(Millions of Dollars)GuarantorGuarantee
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 (e)(d)
(Millions of Dollars)GuarantorGuarantee
Amount		Current
Exposure		Triggering
Event
Guarantee of loan for Hiawatha Collegiate High School(a)
Xcel Energy Inc.$1 — (c)
Guarantee performance and payment of surety bonds for Xcel Energy Inc.’s utility subsidiaries(b)
Xcel Energy Inc.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 net of payables with affiliates at Dec. 31:
(Millions of Dollars)(Millions of Dollars)20202019(Millions of Dollars)20212020
NSP-MinnesotaNSP-Minnesota$81 $60 NSP-Minnesota$104 $81 
NSP-WisconsinNSP-Wisconsin9 17 NSP-Wisconsin25 9 
PSCoPSCo98 78 PSCo91 98 
SPSSPS55 47 SPS58 55 
Xcel Energy Services Inc.Xcel Energy Services Inc.159 112 Xcel Energy Services Inc.125 159 
Xcel Energy Ventures Inc.0 25 
Other subsidiaries of Xcel Energy Inc.Other subsidiaries of Xcel Energy Inc.22 31 Other subsidiaries of Xcel Energy Inc.27 22 
$424 $370 $430 $424 
Dividends — Cash dividends paid to Xcel Energy Inc. by its subsidiaries were $1,344 million, $2,527 million $2,987 million and $1,097$2,987 million for the years ended Dec. 31, 2021, 2020 2019 and 2018,2019, 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, 20202021
Loan outstanding at period end$57— 
Average loan outstanding185— 
Maximum loan outstanding318— 
Weighted average interest rate, computed on a daily basis0.08 %N/A
Weighted average interest rate at end of period0.07 %N/A
Money pool interest income$0— 
(Amounts in Millions, Except Interest Rates)(Amounts in Millions, Except Interest Rates)Year Ended Dec. 31, 2020Year Ended Dec. 31, 2019Year Ended Dec. 31, 2018(Amounts in Millions, Except Interest Rates)Year Ended Dec. 31, 2021Year Ended Dec. 31, 2020Year Ended Dec. 31, 2019
Loan outstanding at period endLoan outstanding at period end$57 $39 $0 Loan outstanding at period end$— $57 $39 
Average loan outstandingAverage loan outstanding104 47 71 Average loan outstanding16 104 47 
Maximum loan outstandingMaximum loan outstanding350 250 243 Maximum loan outstanding439 350 250 
Weighted average interest rate, computed on a daily basisWeighted average interest rate, computed on a daily basis0.60 %2.15 %1.95 %Weighted average interest rate, computed on a daily basis0.08 %0.60 %2.15 %
Weighted average interest rate at end of periodWeighted average interest rate at end of period0.07 %1.63 %N/AWeighted average interest rate at end of periodN/A0.07 %1.63 
Money pool interest incomeMoney pool interest income$1 $1 $1 Money pool interest income$— $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 allowancesAllowance for bad debtsNOL and tax credit valuation allowances
(Millions of Dollars)(Millions of Dollars)202020192018202020192018(Millions of Dollars)202120202019202120202019
Balance at Jan. 1Balance at Jan. 1$55 $55 $52 $67 $79 $77 Balance at Jan. 1$79 $55 $55 $64 $67 $79 
Additions charged to costs and expensesAdditions charged to costs and expenses60 42 42 6 9 7 Additions charged to costs and expenses60 60 42 5 6 9 
Additions charged to other accountsAdditions charged to other accounts12 (a)16 (a)11 (a)0 0 0 Additions charged to other accounts14 (a)12 (a)16 (a)— — — 
Deductions from reservesDeductions from reserves(48)(b)(58)(b)(50)(b)(9)(c)(21)(d)(5)(d)Deductions from reserves(47)(b)(48)(b)(58)(b)(5)(d)(9)(c)(21)(d)
Balance at Dec. 31Balance at Dec. 31$79 $55 $55 $64 $67 $79 Balance at Dec. 31$106 $79 $55 $64 $64 $67 
(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.
ITEM 16 — FORM 10-K SUMMARY
None.
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Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned thereunto duly authorized.
XCEL ENERGY INC.
Feb. 17, 202123, 2022By:/s/ BRIAN J. VAN ABEL
Brian J. Van Abel
Executive Vice President, Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities on the date indicated above.
/s/ BEN FOWKEROBERT C. FRENZELChairman, President, Chief Executive Officer and Director
Ben FowkeRobert 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
*Director
Netha N. Johnson
*Director
Patricia L. Kampling
*Director
George J. Kehl
*Director
Richard T. O’Brien
*Director
David K. Owens
*Director
Charles Pardee
*Director
Christopher J. Policinski
*Director
James Prokopanko
*Director
James J. Sheppard
*Director
David A. Westerlund
*Director
Kim Williams
*Director
Timothy V. Wolf
*Director
Daniel Yohannes
*By:/s/ BRIAN J. VAN ABELAttorney-in-Fact
Brian J. Van Abel

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