EDGAR 10-K Filing

Company CIK: 72903
Filing Year: 2021
Filename: 72903_10-K_2021_0000072903-21-000012.json

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ITEM 1. BUSINESS
ITEM 1 - BUSINESS
Definitions of Abbreviations
Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
Capital Services Capital Services, LLC
Eloigne Eloigne Company
e prime e prime inc.
NSP-Minnesota Northern States Power Company, a Minnesota corporation
NSP System The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota
NSP-Wisconsin Northern States Power Company, a Wisconsin corporation
Operating companies NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
PSCo Public Service Company of Colorado
SPS Southwestern Public Service Co.
Utility subsidiaries NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
WGI WestGas InterState, Inc.
WYCO WYCO Development, LLC
Xcel Energy Xcel Energy Inc. and its subsidiaries
Federal and State Regulatory Agencies
CPUC Colorado Public Utilities Commission
D.C. Circuit United States Court of Appeals for the District of Columbia Circuit
DOC Minnesota Department of Commerce
DOE United States Department of Energy
DOT United States Department of Transportation
EPA United States Environmental Protection Agency
FERC Federal Energy Regulatory Commission
Fifth Circuit United States Court of Appeals for the Fifth Circuit
IRS Internal Revenue Service
Minnesota District Court U.S. District Court for the District of Minnesota
MPSC Michigan Public Service Commission
MPUC Minnesota Public Utilities Commission
NDPSC North Dakota Public Service Commission
NERC North American Electric Reliability Corporation
NMPRC New Mexico Public Regulation Commission
NRC Nuclear Regulatory Commission
PHMSA Pipeline and Hazardous Materials Safety Administration
PSCW Public Service Commission of Wisconsin
PUCT Public Utility Commission of Texas
SDPUC South Dakota Public Utilities Commission
SEC Securities and Exchange Commission
TCEQ Texas Commission on Environmental Quality
Electric, Purchased Gas and Resource Adjustment Clauses
CEPA Colorado Energy Plan Adjustment
CIP Conservation improvement program
DCRF Distribution cost recovery factor
DSM Demand side management
DSMCA DSM cost adjustment
ECA Retail electric commodity adjustment
EECRF Energy efficiency cost recovery factor
EIR Environmental improvement rider
FCA Fuel clause adjustment
FPPCAC Fuel and purchased power cost adjustment clause
GCA Gas cost adjustment
GUIC Gas utility infrastructure cost rider
PCCA Purchased capacity cost adjustment
PCRF Power cost recovery factor
PGA Purchased gas adjustment
PSIA Pipeline system integrity adjustment
RDF Renewable development fund
RER Renewable energy rider
RES Renewable energy standard
RESA RES adjustment
SCA Steam cost adjustment
SEP State energy policy rider
TCA Transmission cost adjustment
TCR Transmission cost recovery adjustment
TCRF Transmission cost recovery factor
WCA Wind cost adjustment
Other
ADIT Accumulated deferred income taxes
AFUDC Allowance for funds used during construction
ALLETE ALLETE, Inc.
ARO Asset retirement obligation
ASC FASB Accounting Standards Codification
ASU FASB Accounting Standards Update
BART Best available retrofit technology
Boulder City of Boulder, CO
C&I Commercial and Industrial
CAGR Compound annual growth rate
CACJA Clean Air Clean Jobs Act
CapX2020 Alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort
CCR Coal combustion residuals
CCR Rule Final rule (40 CFR 257.50 - 257.107) published by the EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste
CDD Cooling degree-days
CEO Chief executive officer
CFO Chief financial officer
CIG Colorado Interstate Gas Company, LLC
COVID-19 Novel coronavirus
CWA Clean Water Act
CWIP Construction work in progress
DECON Decommissioning method where radioactive contamination is removed and safely disposed of at a requisite facility or decontaminated to a permitted level
DRIP Dividend Reinvestment Program
EEI Edison Electric Institute
ELG Effluent limitations guidelines
EMANI European Mutual Association for Nuclear Insurance
EPS Earnings per share
ETR Effective tax rate
FASB Financial Accounting Standards Board
FTR Financial transmission right
GAAP Generally accepted accounting principles
GE General Electric
GHG Greenhouse gas
HDD Heating degree-days
IM Integrated market
INPO Institute of Nuclear Power Operations
IPP Independent power producing entity
IRP Integrated Resource Plan
ITC Investment Tax Credit
JOA Joint operating agreement
LSP Transmission LSP Transmission Holdings, LLC
MDL Multi-district litigation
MEC Mankato Energy Center
MGP Manufactured gas plant
MISO Midcontinent Independent System Operator, Inc.
Moody’s Moody’s Investor Services
NAAQS National Ambient Air Quality Standard
Native load Demand of retail and wholesale customers that a utility has an obligation to serve under statute or contract
NAV Net asset value
NEIL Nuclear Electric Insurance Ltd.
NOL Net operating loss
O&M Operating and maintenance
OATT Open Access Transmission Tariff
PI Prairie Island nuclear generating plant
Post-65 Post-Medicare
PPA Purchased power agreement
Pre-65 Pre-Medicare
PTC Production tax credit
REC Renewable energy credit
ROE Return on equity
ROFR Right-of-first-refusal
ROU Right-of-use
RPS Renewable portfolio standards
RTO Regional Transmission Organization
S&P Standard & Poor’s Global Ratings
SERP Supplemental executive retirement plan
SMMPA Southern Minnesota Municipal Power Agency
SO2
Sulfur dioxide
SPP Southwest Power Pool, Inc.
TCEH Texas Competitive Energy Holdings
TCJA 2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act
THI Temperature-humidity index
TOs Transmission owners
TSR Total shareholder return
VaR Value at Risk
VIE Variable interest entity
WOTUS Waters of the U.S.
Measurements
Bcf Billion cubic feet
KV Kilovolts
KWh Kilowatt hours
MMBtu Million British thermal units
MW Megawatts
MWh Megawatt hours
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 2021 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future bad debt expense, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, and expectations regarding regulatory proceedings, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information.
The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2020 (including risk factors listed from time to time by 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; operational safety, including our nuclear generation facilities; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; ability to recover costs; changes in regulation 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 and their impact on capital expenditures and 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.
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 and Nicollet Project Holdings.
Utility Subsidiaries’ Service Territory
Electric customers 3.7 million
Natural gas customers 2.1 million
Total assets $54 billion
Electric generating capacity 20,140 MW
Natural gas storage capacity 53.4 Bcf
Electric transmission lines (conductor miles) 110,353 miles
Electric distribution lines (conductor miles) 208,586 miles
Natural gas transmission lines 2,172 miles
Natural gas distribution lines 35,936 miles
Vision, Mission and Values
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:
Lead the Clean Energy Transition
For more than a decade, Xcel Energy has proactively managed the risk of climate change and responded to increasing customer demand for renewable energy. We reduced carbon emissions from generation serving customers by 51% from 2005 to 2020 and are on track to reach 60% renewable generation by 2030.
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 in the state, including:
•Proposed plans for our remaining coal units (approximately 1,200 MW), such as early retirements and natural gas conversions.
•Additional renewables and storage.
•Transmission expansion.
We are confident we can achieve our 80% interim carbon reduction goal with today’s technology. New carbon-free dispatchable technologies will be required in order to achieve the remaining 20% carbon reduction. Reliability, customer affordability and innovation remain paramount to a successful transition.
Xcel Energy’s clean energy leadership extends to our natural gas distribution system as we work to keep our methane emissions rate below 0.2%. Our plans include the following:
•Working with upstream suppliers on reducing emissions on their system.
•Reducing methane emissions from our own operations.
•Designing programs that encourage customer conservation and electrification where beneficial.
Enhance the Customer Experience
Xcel Energy is committed to providing programs that customers want and value. We continue to expand renewable offerings and promote cost savings and conservation programs, in which we have invested over $2 billion in the past decade.
Xcel Energy is transforming our electric grid to accommodate increased levels of renewables and distributed energy resources and continues to offer customers directly sourced renewable energy solutions. We are also working to develop new programs for C&I customers who desire higher than standard service reliability, with the goal being to make it both easy and affordable 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 vehicles across our service territory by 2030, which is estimated to save customers $1 billion in fueling costs and cut carbon emissions by nearly 5 million tons annually by 2030.
Keep Bills Low
Affordability is foundational to our strategy. Our goal is to keep bill increases at or below the rate of inflation. Xcel Energy has kept residential bills relatively flat since 2013.
Our states benefit from strong wind and solar capacity factors. This geographic advantage, coupled with renewable tax credits and avoided fuel costs, enables Xcel Energy to increase its investment in renewables while saving customers money. We call this our “Steel for Fuel” strategy. From 2017 to 2020, we added nearly 3,000 MW of wind to our system while delivering approximately $430 million in 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 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.
Deliver a Competitive Total Return to Investors and Maintain Strong Investment Grade Credit Rating
Successful execution of our strategy, along with our disciplined approach to growth, investments, operations and management of environmental, social and corporate governance issues, positions Xcel Energy to continue delivering a competitive TSR.
We have consistently achieved our financial objectives, meeting or exceeding our initial earnings guidance range for sixteen consecutive years and delivering dividend growth for seventeen consecutive years.
GAAP and ongoing earnings have grown 5.6% and 6.1%, respectively, annually since 2005 and our dividend grew 6.3% annually from 2013-2020. 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 current ratings are consistent with this objective.
Environmental, Social and Governance Leadership
Sustainability is embedded in Xcel Energy’s strategy and our values:
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.
Environmental
Xcel Energy was the first major U.S. utility to establish a carbon-free vision, targeting 100% carbon-free electricity by 2050 and an 80% carbon reduction by 2030 (from 2005 levels). Our plans to achieve 80% carbon reduction are aligned with targets of the Paris Accord, as validated by 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. We are 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 customers 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.
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 is focused on preventing life-altering injuries. All employees have “stop work authority” to keep each other, our customers and the public safe. Through our Safety Always approach, employees are encouraged to share experiences and learn from events to help protect themselves, their coworkers and the public.
Human Capital Management
Xcel Energy’s success depends on our ability to actively implement programs to attract, hire, develop and retain skilled employees. 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 goals and deliver an exceptional customer experience.
Xcel Energy has implemented a strategic, data-driven approach to workforce and succession planning, which includes best practices in learning and development. Additionally, Xcel Energy partners with educational and community organizations to attract and hire diverse employees who reflect the communities we serve. Also, hiring veterans is a key focus of our workforce strategy, with approximately 10% of employees having served in the military. Xcel Energy offers its employees 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 part of who we are, how we operate and how we see our future. We are committed to an inclusive culture where diversity is celebrated and employees are treated equitably. Our senior leadership team leads by example, fostering an inclusive work environment, which recognizes the need for crucial conversations on diversity. Additionally, Xcel Energy supports an inclusive environment by offering company-wide trainings on topics addressing microinequities and unconscious bias. We hold ourselves accountable and measure our progress through corporate scorecard metrics that include, among other things, employee feedback in our engagement survey Inclusion Index.
In 2020, Xcel Energy received the following recognitions:
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 for all employees and members of the Board of Directors. Xcel Energy does not tolerate discrimination, violations of our Code of Conduct or other unacceptable behaviors. We 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 Agreements Total Full-Time Employees
NSP-Minnesota 2,033 3,144
NSP-Wisconsin 394 540
PSCo 1,882 2,378
SPS 769 1,141
XES - 4,164
Total 5,078 11,367
Our workforce demographics as of December 2020 were as follows:
Female Ethnically Diverse
Board of Directors 20% 20%
CEO direct reports 38% 13%
Management 22% 10%
Employees 23% 16%
New hires 33% 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.
Xcel Energy has a diverse and qualified Board of Directors, with eight members elected within the past five years.
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.
Utility Subsidiaries
NSP-Minnesota
Electric customers 1.5 million NSP-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 customers 0.6 million
Consolidated earnings contribution 35% to 45%
Total assets $21.1 billion
Rate Base (estimated) $12.4 billion
ROE (net income / average stockholder's equity) 9.20%
Electric generating capacity 8,137 MW
Gas storage capacity 17.1 Bcf
Electric transmission lines (conductor miles) 33,660 miles
Electric distribution lines (conductor miles) 80,508 miles
Natural gas transmission lines 80 miles
Natural gas distribution lines 10,629 miles
NSP-Wisconsin
Electric customers 0.3 million NSP-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 customers 0.1 million
Consolidated earnings contribution 5% to 10%
Total assets $2.9 billion
Rate Base (estimated) $1.8 billion
ROE (net income / average stockholder's equity) 10.52%
Electric generating capacity 548 MW
Gas storage capacity 3.8 Bcf
Electric transmission lines (conductor miles) 12,288 miles
Electric distribution lines (conductor miles) 27,611 miles
Natural gas transmission lines 3 miles
Natural gas distribution lines 2,492 miles
PSCo
Electric customers 1.5 million PSCo 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 customers 1.4 million
Consolidated earnings contribution 35% to 45%
Total assets $20.4 billion
Rate Base (estimated) $13.3 billion
ROE (net income / average stockholder's equity) 8.06%
Electric generating capacity 6,223 MW
Gas storage capacity 32.5 Bcf
Electric transmission lines (conductor miles) 24,386 miles
Electric distribution lines (conductor miles) 78,483 miles
Natural gas transmission lines 2,058 miles
Natural gas distribution lines 22,815 miles
SPS
Electric customers 0.4 million SPS conducts business in Texas and New Mexico and generates, purchases, transmits, distributes and sells electricity.
Consolidated earnings contribution 15% to 20%
Total assets $8.9 billion
Rate Base (estimated) $5.4 billion
ROE (net income / average stockholder's equity) 9.54%
Electric generating capacity 5,232 MW
Electric transmission lines (conductor miles) 40,019 miles
Electric distribution lines (conductor miles) 21,984 miles
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 104,731 (millions of KWh), 3.7 million customers and electric revenues of $9,802 (millions of dollars) for 2020.
Sales/Revenue Statistics (a)
2020 2019
KWh sales per retail customer 23,910 24,712
Revenue per retail customer $ 2,199 $ 2,244
Residential revenue per KWh 12.12 ¢ 11.97 ¢
Large C&I revenue per KWh 5.78 ¢ 5.96 ¢
Small C&I revenue per KWh 9.56 ¢ 9.43 ¢
Total retail revenue per KWh 9.20 ¢ 9.08 ¢
(a) See Note 6 to the consolidated financial statements for further information.
Owned and Purchased Energy Generation - 2020
Electric Energy Sources
Total electric generation by source (including energy market purchases) for the year ended Dec. 31, 2020:
* Distributed generation from the Solar*Rewards® program is not included (approximately 675 million KWh for 2020).
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, weather, system demand and transmission constraints.
See Item 2 - Properties for further information.
Carbon-free energy as a percentage of total energy for 2020:
* Includes biomass and hydroelectric.
Wind
Owned - Owned and operated wind farms with corresponding capacity:
2020 2019
Utility Subsidiary Wind Farms Capacity (a)
Wind Farms Capacity (b)
NSP System 11 1,540 MW 7 1,079 MW
PSCo 2 1,059 MW 1 582 MW
SPS 2 967 MW 1 460 MW
Total 15 3,566 MW 9 2,121 MW
(a) Summer 2020 net dependable capacity.
(b) Summer 2019 net dependable capacity.
PPAs - Number of PPAs with capacity range:
Utility Subsidiary 2020 2019
PPAs Range PPAs Range
NSP System 129 1 MW - 206 MW 131 1 MW - 206 MW
PSCo 17 23 MW - 301 MW 20 2 MW - 301 MW
SPS 18 1 MW - 250MW 18 1 MW - 250 MW
Capacity - Wind capacity:
Utility Subsidiary 2020 2019
NSP System 3,348 MW 2,767 MW
PSCo 4,085 MW 3,145 MW
SPS 2,535 MW 2,027 MW
Average Cost (Owned) - Average cost per MWh of wind energy from owned generation:
Utility Subsidiary 2020 2019
NSP System $ 23 $ 35
PSCo 35 47
SPS 17 -
Average Cost (PPAs) - Average cost per MWh of wind energy under existing PPAs:
Utility Subsidiary 2020 2019
NSP System $ 38 $ 41
PSCo 40 41
SPS 26 25
Wind Development
Xcel Energy placed approximately 1,450 MW of owned wind and approximately 700 MW of PPAs into service during 2020:
Project Utility Subsidiary Capacity
Blazing Star 1 NSP-Minnesota 200 MW (a)(b)
Crowned Ridge 2 NSP-Minnesota 192 MW (a)(b)
Community Wind North
NSP-Minnesota 26 MW (a)(b)
Jeffers NSP-Minnesota 43 MW (a)(b)
Cheyenne Ridge PSCo 477 MW (a)(b)
Sagamore SPS 507 MW (a)(b)
Various PPAs Various ~700 MW (c)
(a) Summer 2020 net dependable capacity.
(b) Values disclosed are the maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
(c) Based on contracted capacity.
Xcel Energy currently has approximately 1,450 MW of owned wind under development or construction. In addition, Xcel Energy expects to add approximately 450 MW of planned PPAs.
Project Utility Subsidiary Capacity Estimated Completion
Dakota Range NSP-Minnesota 300 MW 2021
Freeborn NSP-Minnesota 200 MW 2021
Blazing Star 2 NSP-Minnesota 200 MW 2021
Nobles NSP-Minnesota 200 MW 2022
Pleasant Valley NSP-Minnesota 200 MW 2024
Border Winds NSP-Minnesota 150 MW 2024
Grand Meadow NSP-Minnesota 100 MW 2023
Mower NSP-Minnesota 99 MW 2021
Various PPAs Various ~450 MW 2021
Solar
Solar PPA(s):
Type Utility Subsidiary Capacity
Distributed Generation NSP System 899 MW
Utility-Scale NSP System 268 MW
Distributed Generation PSCo 643 MW
Utility-Scale PSCo 306 MW
Distributed Generation SPS 11 MW
Utility-Scale SPS 190 MW
Total 2,317 MW
Average Cost (PPAs) - Average cost per MWh of solar energy under existing PPAs:
Utility Subsidiary 2020 2019
NSP System $ 90 $ 81
PSCo 89 89
SPS 59 56
Solar Development
In October 2020, Xcel Energy filed a request with the PSCW to purchase a 74 MW, $100 million solar array in Pierce County, WI. A PSCW decision is expected in the third quarter of 2021. Also, as part of the Minnesota Recovery and Relief Recovery docket, NSP-Minnesota, proposed the addition of 460 MW of solar facilities with an expected $550 million incremental investment. An MPUC decision is expected in the second half of 2021.
Additionally, Xcel Energy projects approximately 3,500 MW of solar through 2034 in our Minnesota resource plan and will be addressing solar energy within its upcoming Colorado resource plan.
Nuclear
Xcel Energy has two nuclear plants with approximately 1,700 MW of total 2020 net summer dependable capacity that serves the NSP-System. Our nuclear fleet has become one of the safest and well-run 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 Subsidiary Nuclear
NSP System Cost Percent
2020 $ 0.80 51 %
2019 0.81 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 2020 net summer dependable capacity.
Approved and proposed early coal plant retirements:
Approved / Authorized
Year Utility Subsidiary Plant Unit Capacity
2022 PSCo Comanche 1 325 MW
2023 NSP-Minnesota Sherco 2 682 MW
2024 SPS Harrington (a)
1,018 MW
2025 PSCo Comanche 2 335 MW
2025 PSCo Craig 1 42 MW (b)
2026 NSP-Minnesota Sherco 1 680 MW
2028 PSCo Craig 2 40 MW (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
Year Utility Subsidiary Plant Unit Capacity
2027 PSCo Hayden 2 98 MW (a)
2028 PSCo Hayden 1 135 MW (b)
2028 NSP-Minnesota A.S. King 511 MW
2030 NSP-Minnesota Sherco 3 517 MW (c)
2032 SPS Tolk 1 532 MW
2032 SPS Tolk 2 535 MW
(a)Based on PSCo’s ownership of 37% of Unit 2.
(b)Based on PSCo’s ownership of 76% of Unit 1.
(c)Based on Xcel Energy’s ownership interest.
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 percentage of fuel requirements:
Coal (a)
Utility Subsidiary Cost Percent
NSP System
2020 $ 1.97 31 %
2019 2.02 36
PSCo
2020 1.41 51
2019 1.45 55
SPS
2020 2.28 40
2019 2.19 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 2020 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 percentage of total fuel requirements:
Natural Gas
Utility Subsidiary Cost Percent
NSP System
2020 $ 2.67 17 %
2019 3.09 19
PSCo
2020 3.01 49
2019 3.27 45
SPS
2020 1.43 60
2019 1.14 55
Capacity and Demand
Uninterrupted system peak demand and occurrence date for the regulated utilities:
System Peak Demand (in MW)
2020 2019
NSP System
8,571 July 8 8,774 July 19
PSCo 6,899 Aug. 17 7,111 July 19
SPS 4,195 July 14 4,261 Aug. 5
Transmission
Transmission lines deliver electricity at higher voltage and over longer distances from power sources to transmission substations closer to homes and businesses. A strong transmission system ensures continued reliable and affordable service, ability to meet state and regional energy policy goals, and support for a diverse generation mix, including renewable energy. Xcel Energy owns more than 20,000 miles of transmission lines, serving 22,000 MW of customer load.
Transmission projects completed in 2020 include:
Project Utility Subsidiary Miles Size
Maple River-Red River NSP-Minnesota 4 115 KV
Glenwood Douglas NSP-Minnesota 20 69 KV
Prentice to Structure NSP-Wisconsin 8 115 KV
Lufkin to Naples NSP-Wisconsin 13 69 KV
Belgrade to Ironwood NSP-Wisconsin 13 35 KV
Cornucopia to Bayfield Phase 2 NSP-Wisconsin 5 35 KV
Pawnee-Daniels Park PSCo 113 345 KV
Cheyenne Ridge PSCo 73 345 KV
TUCO-Yoakum Co. SPS 107 345 KV
Eddy Co-Kiowa SPS 34 345 KV
Mustang-Seminole SPS 20 115 KV
Loving South-Phantom SPS 21 115 KV
Notable upcoming projects:
Project Utility Subsidiary Miles Size Completion Date
Hibbing Taconite Relocation NSP-Minnesota 3 500 KV 2021
Huntley-Wilmarth NSP-Minnesota 50 345 KV 2021
Helena Scott County NSP-Minnesota 16 345 KV 2021
Baytown to Long Lake NSP-Minnesota 9 115 KV 2022
Centerville to Lincoln County NSP-Minnesota 14 69 KV 2021
Turtle Lake Almena NSP-Wisconsin 4 69 KV 2021
Bayfield Second Circuit NSP-Wisconsin 19 35 KV 2022
Roadrunner-China Draw SPS 41 345 KV 2021
See Item 2 - Properties for further information.
Distribution
Distribution lines allow electricity to travel at lower voltages from substations directly to homes and businesses. 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.
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 year project, Xcel Energy plans to invest approximately $1.8 billion implementing new network infrastructure, smart meters, advanced software, equipment sensors and related data analytics capabilities.
These investments 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.
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 444,340 (thousands of MMBtu), 2.1 million customers and natural gas revenues of $1,636 (millions of dollars) for 2020.
Sales/Revenue Statistics (a)
2020 2019
MMBtu sales per retail customer 118.13 129.31
Revenue per retail customer $ 720.42 $ 851.94
Residential revenue per MMBtu 6.64 7.14
C&I revenue per MMBtu 5.22 5.73
Transportation and other revenue per MMBtu 0.67 0.57
(a) See Note 6 to the consolidated financial statements for further information.
Capability and Demand
Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply).
Maximum daily output (firm and interruptible) and occurrence date:
2020 2019
Utility Subsidiary MMBtu Date MMBtu Date
NSP-Minnesota 871,921 Jan. 16 897,615 Feb. 25
NSP-Wisconsin 150,320 Dec. 24 166,009 Jan. 30
PSCo 1,931,888 Feb. 4 2,139,420 March 3
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 Subsidiary 2020 2019
NSP-Minnesota $ 3.32 $ 3.71
NSP-Wisconsin 3.08 3.49
PSCo 2.52 2.95
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 management cannot predict the impact of fluctuating energy prices, 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.
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.
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 operation of certain new electric transmission facilities. State utility commissions have also created resource planning programs that promote competition for electric generation resources used to provide service to retail customers.
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.
Public Utility Regulation
See Item 7 for discussion of public utility regulation.
Environmental
Environmental Regulation
Our facilities are regulated by federal and state agencies that have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Certain 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 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.
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. 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 required states to develop plans by 2022 for GHG reductions from coal-fired power plants. In a Jan. 19, 2021 decision, the U.S. Court of Appeals for the D.C. Circuit issued a decision vacating and remanding the Affordable Clean Energy rule. That decision, if not successfully appealed or reconsidered, would allow the EPA to proceed with alternate regulation of coal-fired power plants, either reviving the Clean Power Plan or proposing additional regulation. It is too early to predict an outcome, but new rules could require substantial additional investment, even in plants slated for retirement. Xcel Energy believes, based on prior state commission practices, the cost of these initiatives or replacement generation would be recoverable through rates.
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, Xcel Energy estimates that it reduced carbon emissions associated with electric generating resources, both owned and under PPAs, used to serve its customers by approximately 51% from 2005 levels.
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:
•$400 million in 2020.
•$345 million in 2019.
•$335 million in 2018.
Average annual expense of approximately $465 million from 2021 - 2025 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.
Capital expenditures for environmental improvements were approximately:
•$30 million in 2020.
•$30 million in 2019.
•$50 million in 2018.
Capital Spending and Financing
See Item 7 for discussion of capital expenditures and funding sources.
Information about our Executive Officers (a)
Name Age (b)
Current and Recent Positions Time in Position
Ben Fowke 62 Chairman of the Board of Directors, Chief Executive Officer and Director, Xcel Energy Inc. August 2011 - Present
Chief Executive Officer, NSP-Minnesota, NSP-Wisconsin, PSCo, and SPS January 2015 - Present
President, Xcel Energy Inc. August 2011 - March 2020
Robert C. Frenzel 50 President and Chief Operating Officer, Xcel Energy Inc. March 2020 - Present
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 54 Executive 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 company October 2015 - May 2018
Christopher B. Clark 54 President and Director, NSP-Minnesota January 2015 - Present
Darla Figoli 58 Executive Vice President, Human Resources & Employee Services, Chief Human Resources Officer, Xcel Energy Inc. June 2020 - Present
Senior Vice President, Human Resources & Employee Services, Chief Human Resources Officer, Xcel Energy Inc. May 2018 - June 2020
Senior Vice President, Human Resources and Employee Services, Xcel Energy Inc. May 2015 - May 2018
David T. Hudson 60 President and Director, SPS January 2015 - Present
Alice Jackson 42 President and Director, PSCo May 2018 - Present
Area Vice President, Strategic Revenue Initiatives, Xcel Energy Services Inc. November 2016 - May 2018
Regional Vice President, Rates and Regulatory Affairs, PSCo November 2013 - November 2016
Timothy O’Connor 61 Executive Vice President, Chief Generation Officer, Xcel Energy Inc. March 2020 - Present
Senior Vice President, Chief Nuclear Officer, Xcel Energy Services Inc February 2013 - March 2020
Frank Prager 58 Senior 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 Rome 40 Executive 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 49 Senior Vice President, Controller, Xcel Energy Inc. January 2015 - Present
Mark E. Stoering 60 President and Director, NSP-Wisconsin January 2015 - Present
Brian J. Van Abel 39 Executive 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) No family relationships exist between any of the executive officers or directors.
(b) Ages as of Feb. 17, 2021.
(c) In April 2014, Energy Future Holdings Corp., the majority of its subsidiaries, including TCEH the parent company of Luminant, filed a voluntary bankruptcy petition under Chapter 11 of the United States Bankruptcy Code. TCEH emerged from Chapter 11 in October 2016.

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ITEM 1A. RISK FACTORS
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. 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.
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.
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 transmission and distribution operations involve numerous risks that may result in accidents and other operating risks and costs.
Our natural gas transmission and distribution activities include inherent hazards and operating risks, such as leaks, explosions, outages and mechanical problems. Our electric generation, transmission and distribution activities include inherent hazards and operating risks such as contact, fire and outages. These risks could result in loss of life, significant property damage, environmental pollution, impairment of our operations and substantial financial losses. We maintain insurance against most, but not all, of these risks and losses. The occurrence of these events, if not fully covered by insurance, could have a material effect on our financial condition, results of operations and cash flows.
Other uncertainties and risks inherent in operating and maintaining 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.
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, multiple states may not agree as to the appropriate resource mix, which may lead to costs to comply with one jurisdiction that are not recoverable across all jurisdictions served by the same assets.
We are subject to longer-term availability of inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.
We are subject to commodity risks and other risks associated with energy markets and energy production.
In the event fuel costs increase, customer demand could decline and bad debt expense may rise, which may have a material impact on our results of operations. Despite existing fuel recovery mechanisms 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 controls are not effective, Xcel Energy’s results of operations, financial condition or cash flows could be materially impacted.
Failure to attract and retain a qualified workforce could have an adverse effect on operations.
Specialized knowledge is required of our technical employees for construction and operation of transmission, generation and distribution assets. Xcel Energy’s business strategy is dependent on our ability to recruit, retain and motivate employees. There is competition and a tightening market for skilled employees. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees or future availability and cost of contract labor may adversely affect the ability to manage and operate our business. Inability to attract and retain these employees could adversely impact our results of operations, financial condition or cash flows.
Our operations use third-party contractors in addition to employees to perform periodic and ongoing work.
We rely on third-party contractors to perform operations, maintenance and construction work. Our contractual arrangements with these contractors typically include performance standards, progress payments, insurance requirements and security for performance. Poor vendor performance could impact ongoing operations, restoration operations, our reputation and could introduce financial risk or risks of fines.
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.
Changes in the long-term cost-effectiveness or to the operating conditions of our assets may result in early retirements of utility facilities. While regulation typically provides cost recovery relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
In a continued low interest rate environment, there has been increased downward pressure on allowed ROE. Conversely, higher than expected inflation or tariffs may increase costs of construction and operations. Also, rising fuel costs could increase the risk that 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.
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, lower returns on equity, changes to equity ratios and impacts of tax policy may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.
Any credit ratings downgrade could lead to higher borrowing costs and could impact our ability to access capital markets. Also, 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. 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.
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 value of various tax credits or the timeliness of their utilization may impact the economics or selection of resources. If tax rates are increased, there could be timing delays before regulated rates provide for recovery of such tax increases in revenues. In addition, certain IRS tax policies, such as tax normalization, may impact our ability to economically deliver certain types of resources relative to market prices.
Macroeconomic Risks
Economic conditions impact our business.
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 intensive industry and federal trade policy could significantly impact the cost of materials we use. There may be delays before these additional material costs can be recovered in rates.
We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.
The global outbreak of COVID-19 is impacting countries, communities, supply chains and markets. A high degree of uncertainty continues to exist regarding the pandemic, the duration and magnitude of business restrictions, re-shut downs, if any, and the level and pace of economic recovery. While we are implementing contingency plans, there are no guarantees these plans will be sufficient to offset the impact of COVID-19.
Although the impact of the pandemic to the 2020 results was largely mitigated due to management’s actions, we cannot ultimately predict whether it will have a material impact on our future liquidity, financial condition or results of operations. Nor can we predict the impact of the virus on the health of our employees, our supply chain or our ability to recover higher costs associated with managing through the pandemic. The impact of COVID-19 may exacerbate other risks discussed herein, which could have a material effect on us. The situation is evolving and additional impacts may arise.
Operations could be impacted by war, terrorism or other events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition, results of operations or cash flows.
The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have already incurred increased costs for security and capital expenditures in response to these risks. The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, insurance may have higher deductibles, higher premiums and more restrictive policy terms.
A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, brand and reputation. Because our facilities are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility.
We also face the risks of possible loss of business due to significant events such as severe storms, severe temperature extremes, wildfires (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 grid security and emergency response exercises (GridEx). These efforts, led by the NERC, test and further develop the coordination, threat sharing and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid.
A cyber incident or security breach could have a material effect on our business.
We operate in an industry that requires the continued operation of sophisticated information technology, control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors, 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. 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.
Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or causing the release of customer information, all of which would likely receive state and federal regulatory scrutiny and could expose us to liability.
Xcel Energy’s generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third-party service providers’ operations, could also negatively impact our business.
Our supply chain for procurement of digital equipment and services may expose software or hardware to these risks and could result in a breach or significant costs of remediation. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. Cyber security incidents and regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third-party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.
We maintain security measures to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including asset failure or unauthorized access to assets or information.
A failure or breach of our technology systems or those of our third-party service providers could disrupt critical business functions and may negatively impact our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network protection may not be effective given the constant changes to threat vulnerability.
Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.
Our electric and natural gas utility businesses are seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns. A significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations or cash flows.
Public Policy Risks
We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.
Legislative and regulatory responses related to climate change may create financial risk as our facilities may be subject to additional regulation at either the state or federal level in the future. International agreements could additionally lead to future federal or state regulations.
In 2015, the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries, with a goal of holding the increase in global average temperature to below 2º Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5º Celsius. The Biden Administration will establish a new nationally determined contribution for the United States. The Paris Agreement could result in future additional GHG reductions in the United States. In addition, the Biden Administration has announced plans to implement new climate change programs, including potential regulation of GHG emissions targeting the utility industry.
The Biden Administration has also announced a one year suspension of new oil and natural gas drilling on federal lands to allow for a review of oil and gas leasing regulations. The form of these regulations is uncertain, but, depending on the requirements imposed in the short and long term, they could impose substantial costs on our oil and gas customers or result in substantial increases to the cost of fuel we use in our electricity and gas businesses.
Many states and localities continue to pursue their own climate policies. The steps Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation or retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies.
We may be subject to climate change lawsuits. An adverse outcome could require substantial capital expenditures and possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant and could affect results of operations, financial condition or cash flows if such costs are not recovered through regulated rates.
If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations, financial condition or cash flows.
Increased risks of regulatory penalties could negatively impact our business.
The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. The FERC can impose penalties of up to $1.3 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties. Also, the PHMSA, Occupational Safety and Health Administration and other federal agencies have the authority to assess penalties.
In the event of serious incidents, these agencies may pursue penalties. In addition, certain states have the authority to impose substantial penalties. If a serious reliability, cyber or safety incident did occur, it could have a material effect on our results of operations, financial condition or cash flows.
Environmental Risks
We are subject to environmental laws and regulations, with which compliance could be difficult and costly.
We are subject to environmental laws and regulations that affect many aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. Laws and regulations require us to obtain permits, licenses, and approvals and to comply with a variety of environmental requirements.
Environmental laws and regulations can also require us to restrict or limit the output of facilities or the use of certain fuels, shift generation to lower-emitting facilities, install pollution control equipment, clean up spills and other contamination and correct environmental hazards. Failure to meet requirements of environmental mandates may result in fines or penalties. We may be required to pay all or a portion of the cost to remediate sites where our past activities, or the activities of other parties, caused environmental contamination.
Changes in environmental policies and regulations or regulatory decisions may result in early retirements of our generation facilities. While regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs.
We are subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. It could have a material effect on our results of operations, financial condition or cash flows if our regulators do not allow us to recover the cost of capital investment or O&M costs incurred to comply with the requirements.
In addition, existing environmental laws or regulations may be revised and new laws or regulations may be adopted. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.
We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.
Climate change can create physical and financial risk. Physical risks include changes in weather conditions and extreme weather events. Our customers’ energy needs vary with weather. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in generating assets, transmission and infrastructure. Decreased energy use due to weather changes may result in decreased revenues.
Climate change may impact the economy, which could impact our sales and revenues. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG, could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
Severe weather impacts our service territories, primarily when thunderstorms, flooding, tornadoes, wildfires and snow or ice storms occur. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Extreme weather conditions creating high energy demand may raise electricity prices, increasing the cost of energy we provide to our customers.
To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Periods of extreme temperatures could impact our ability to meet demand. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations. Drought conditions also contribute to the increase in wildfire risk from our electric generation facilities.
While we carry liability insurance, given an extreme event, if 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. We may not recover all costs related to mitigating these physical and financial risks.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B - UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES
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
Fuel Installed MW (a)
Steam:
A.S. King-Bayport, MN, 1 Unit (f)
Coal 1968 511
Sherco-Becker, MN (e)
Unit 1 Coal 1976 680
Unit 2 Coal 1977 682
Unit 3 Coal 1987 517 (b)
Monticello, MN, 1 Unit Nuclear 1971 617
PI-Welch, MN
Unit 1 Nuclear 1973 521
Unit 2 Nuclear 1974 519
Various locations, 4 Units Wood/Refuse Various 36 (c)
Combustion Turbine:
Angus Anson-Sioux Falls, SD, 3 Units Natural Gas 1994 - 2005 327
Black Dog-Burnsville, MN, 3 Units Natural Gas 1987 - 2018 494
Blue Lake-Shakopee, MN, 6 Units Natural Gas 1974 - 2005 447
High Bridge-St. Paul, MN, 3 Units Natural Gas 2008 530
Inver Hills-Inver Grove Heights, MN, 6 Units Natural Gas 1972 252
Riverside-Minneapolis, MN, 3 Units Natural Gas 2009 454
Various locations, 7 Units Natural Gas Various 10
Wind:
Border-Rolette County, ND, 75 Units Wind 2015 148 (d)
Courtenay Wind-Stutsman County, ND, 100 Units Wind 2016 190 (d)
Foxtail-Dickey County, ND, 75 Units Wind 2019 150 (d)
Grand Meadow-Mower County, MN, 67 Units Wind 2008 99 (d)
Lake Benton-Pipestone County, MN, 44 Units Wind 2019 99 (d)
Nobles-Nobles County, MN, 134 Units Wind 2010 197 (d)
Pleasant Valley-Mower County, MN, 100 Units Wind 2015 196 (d)
Blazing Star 1-Lincoln County, MN, 100 Units Wind 2020 200 (d)
Crowned Ridge 2-Grant County, SD, 88 Units Wind 2020 192 (d)
Community Wind North-Lincoln County, MN, 12 Units Wind 2020 26 (d)
Jeffers-Cottonwood County, MN, 20 Units Wind 2020 43 (d)
Total 8,137
(a)Summer 2020 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
Fuel Installed MW (a)
Steam:
Bay Front-Ashland, WI, 2 Units Wood/Natural Gas 1948 - 1956 41
French Island-La Crosse, WI, 2 Units Wood/Refuse 1940 - 1948 16 (b)
Combustion Turbine:
French Island-La Crosse, WI, 2 Units Oil 1974 122
Wheaton-Eau Claire, WI, 5 Units Natural Gas/Oil 1973 234
Hydro:
Various locations, 63 Units Hydro Various 135
Total 548
(a)Summer 2020 net dependable capacity.
(b)Refuse-derived fuel is made from municipal solid waste.
PSCo
Station, Location and Unit
Fuel Installed MW (a)
Steam:
Comanche-Pueblo, CO (b)
Unit 1 Coal 1973 325
Unit 2 Coal 1975 335
Unit 3 Coal 2010 500 (c)
Craig-Craig, CO, 2 Units (d)
Coal 1979 - 1980 82 (e)
Hayden-Hayden, CO, 2 Units (h)
Coal 1965 - 1976 233 (f)
Pawnee-Brush, CO, 1 Unit Coal 1981 505
Cherokee-Denver, CO, 1 Unit Natural Gas 1968 310
Combustion Turbine:
Blue Spruce-Aurora, CO, 2 Units Natural Gas 2003 264
Cherokee-Denver, CO, 3 Units Natural Gas 2015 576
Fort St. Vrain-Platteville, CO, 6 Units Natural Gas 1972 - 2009 968
Rocky Mountain-Keenesburg, CO, 3 Units Natural Gas 2004 580
Various locations, 8 Units Natural Gas Various 251
Hydro:
Cabin Creek-Georgetown, CO
Pumped Storage, 2 Units Hydro 1967 210
Various locations, 8 Units Hydro Various 25
Wind:
Rush Creek, CO, 300 units Wind 2018 582 (g)
Cheyenne Ridge, CO, 229 units Wind 2020 477 (g)
Total 6,223
(a) Summer 2020 net dependable capacity.
(b) In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in 2022 and 2025, respectively.
(c) Based on PSCo’s ownership of 67%.
(d) Craig Unit 1 and 2 are expected to be retired early in 2025 and 2028, respectively.
(e) Based on PSCo’s ownership of 10%.
(f) Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2.
(g) Values disclosed are the generation levels at the point-of-interconnection. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
(h) Hayden Unit 1 and 2 are expected to be retired in 2028 and 2027, respectively.
SPS
Station, Location and Unit
Fuel Installed MW (a)
Steam:
Cunningham-Hobbs, NM, 2 Units Natural Gas 1957 - 1965 225
Harrington-Amarillo, TX, 3 Units (b)
Coal 1976 - 1980 1,018
Jones-Lubbock, TX, 2 Units Natural Gas 1971 - 1974 486
Maddox-Hobbs, NM, 1 Unit Natural Gas 1967 112
Nichols-Amarillo, TX, 3 Units Natural Gas 1960 - 1968 457
Plant X-Earth, TX, 4 Units Natural Gas 1952 - 1964 298
Tolk-Muleshoe, TX, 2 Units (d)
Coal 1982 - 1985 1,067
Combustion Turbine:
Cunningham-Hobbs, NM, 2 Units Natural Gas 1997 207
Jones-Lubbock, TX, 2 Units Natural Gas 2011 - 2013 334
Maddox-Hobbs, NM, 1 Unit Natural Gas 1963 - 1976 61
Wind:
Hale-Plainview, TX, 239 Units Wind 2019 460 (c)
Sagamore-Dora, NM, 240 Units Wind 2020 507 (c)
Total 5,232
(a) Summer 2020 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 expected to be retired in 2032.
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2020:
Conductor Miles NSP-Minnesota NSP-Wisconsin PSCo SPS
Transmission
500 KV 2,918 - - -
345 KV 13,151 3,337 5,389 11,019
230 KV 2,301 - 12,131 9,795
161 KV 674 1,823 - -
138 KV - - 92 -
115 KV 8,060 1,822 5,092 14,830
Less than 115 KV 6,556 5,306 1,682 4,375
Total Transmission 33,660 12,288 24,386 40,019
Distribution
Less than 115 KV 80,508 27,611 78,483 21,984
Total 114,168 39,899 102,869 62,003
Electric utility transmission and distribution substations at Dec. 31, 2020:
NSP-Minnesota NSP-Wisconsin PSCo SPS
Quantity 352 204 236 457
Natural gas utility mains at Dec. 31, 2020:
Miles NSP-Minnesota NSP-Wisconsin PSCo SPS WGI
Transmission 80 3 2,058 20 11
Distribution 10,629 2,492 22,815 - -

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ITEM 3. LEGAL PROCEEDINGS
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 financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.
See Note 12 to the consolidated financial statements, Item 1 and Item 7 for further information.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4 - MINE SAFETY DISCLOSURES
None.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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, 2021 was approximately 52,689.
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*
* $100 invested on Dec. 31, 2015 in stock or index - including reinvestment of dividends. Fiscal years ended Dec. 31.
Purchases of Equity Securities by Issuer and Affiliated Purchasers
For the quarter ended Dec. 31, 2020, 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.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6 - SELECTED FINANCIAL DATA
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) 2020 2019 2018 2017 2016
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 income 1,473 1,372 1,261 1,148 1,123
Earnings available to common shareholders 1,473 1,372 1,261 1,148 1,123
Diluted earnings per common share 2.79 2.64 2.47 2.25 2.21
Financial information
Dividends declared per common share 1.72 1.62 1.52 1.44 1.36
Total assets 53,957 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
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, 2020 and 2019, 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:
2020 2019
Diluted Earnings (Loss) Per Share GAAP and Ongoing Diluted EPS GAAP and Ongoing Diluted EPS
NSP-Minnesota $ 1.12 $ 1.04
PSCo 1.11 1.11
SPS 0.56 0.51
NSP-Wisconsin 0.20 0.15
Equity earnings of unconsolidated subsidiaries 0.05 0.05
Regulated utility (a)
3.04 2.86
Xcel Energy Inc. and Other (0.25) (0.22)
Total (a)
$ 2.79 $ 2.64
(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.
2020 Comparison with 2019
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 per share for 2020, reflecting higher electric margin (riders, wholesale transmission revenue and a sales true-up mechanism, which recovers lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation and lower natural gas margin.
PSCo - Earnings 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, offset by additional depreciation and taxes (other than income taxes).
SPS - Earnings increased $0.05 per share for 2020, reflecting higher electric margin (wholesale transmission revenue and regulatory outcomes offset lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation, interest expense and taxes (other than income taxes).
NSP-Wisconsin - Earnings increased $0.05 per share for 2020, reflecting higher electric margin (regulatory outcomes offset lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation and lower natural gas margin.
Xcel Energy Inc. and Other - Primarily includes financing costs at the holding company.
Changes in Diluted EPS
Components significantly contributing to changes in EPS:
2020 vs. 2019
Diluted Earnings (Loss) Per Share Dec. 31
GAAP and ongoing diluted EPS - 2019 $ 2.64
Components of change - 2020 vs. 2019
Higher electric margins (a)
0.32
Lower ETR (b)
0.22
Higher AFUDC 0.08
Changes in O&M 0.02
Higher depreciation and amortization (0.26)
Higher interest (0.10)
Higher taxes (other than income taxes) (0.06)
Changes in natural gas margins (0.01)
Other (net) (0.06)
GAAP and ongoing diluted EPS - 2020 $ 2.79
(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 Share Twelve 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 reform regulatory amounts, which are primarily offset in electric margin.
ROE for Xcel Energy and its utility subsidiaries:
2020 2019
ROE GAAP and Ongoing ROE GAAP and Ongoing ROE
NSP-Minnesota 9.20 % 9.31 %
PSCo 8.06 8.69
SPS 9.54 9.71
NSP-Wisconsin 10.52 8.27
Operating Companies 8.87 9.06
Xcel Energy 10.59 10.78
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 or sales true-up mechanism in the state.
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. 2019
HDD (3.1) % 10.4 % (12.0) %
CDD 22.2 5.4 24.8
THI 6.3 (8.8) 18.2
Weather - Estimated impact of temperature variations on EPS compared with normal weather conditions:
2020 vs.
Normal 2019 vs.
Normal 2020 vs. 2019
Retail electric $ 0.090 $ 0.040 $ 0.050
Decoupling and sales true-up (0.041) - (0.041)
Total (excluding decoupling) $ 0.049 $ 0.040 $ 0.009
Firm natural gas (0.011) 0.027 (0.038)
Total (adjusted for recovery from decoupling) $ 0.038 $ 0.067 $ (0.029)
Sales - Sales growth (decline) for actual and weather-normalized sales:
2020 vs. 2019
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Actual (a)
Electric residential 5.8 % 5.0 % 3.6 % 2.4 % 4.9 %
Electric C&I (4.1) (7.0) (3.3) (4.6) (5.0)
Total retail electric sales (1.1) (3.4) (2.2) (2.6) (2.3)
Firm natural gas sales (6.8) (8.3) n/a (6.4) (7.2)
2020 vs. 2019
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-normalized (a)
Electric residential 3.8 % 3.7 % 1.6 % 2.6 % 3.3 %
Electric C&I (4.5) (7.0) (3.4) (4.8) (5.2)
Total retail electric sales (1.9) (3.8) (2.6) (2.7) (2.8)
Firm natural gas sales 0.5 1.9 n/a 5.1 1.3
2020 vs. 2019 (Leap Year Adjusted)
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-normalized (a)
Electric residential 3.6 % 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 sales 0.1 1.4 n/a 4.6 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)
•PSCo - Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the manufacturing and service industries, partially offset by an increase in the energy sector.
•NSP-Minnesota - Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the energy, manufacturing and services sectors.
•SPS - Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the energy and manufacturing sectors.
•NSP-Wisconsin - Residential sales rose based on an increased number of customers and higher use per customer. The decline in C&I sales was primarily due to COVID-19, particularly within the energy and manufacturing sectors.
Weather-normalized and leap-year adjusted natural gas sales growth (decline) - year-to-date (excluding leap day)
•Higher natural gas sales reflect an increase in the number of customers combined with higher residential customer use, partially offset by lower C&I customer use.
Electric Margin
Electric revenues 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).
Electric revenues and margin:
(Millions of Dollars) 2020 2019
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) (a)
$ 209
Non-fuel riders 74
Wholesale transmission revenue (net) 59
MEC purchased capacity costs 35
Conservation incentive 13
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 million of revenue and margin due to the Texas rate case outcome, which is largely offset by recognition of previously deferred costs.
(b) Sales excludes weather impact, net of decoupling/sales true-up, and demand revenue is 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 revenues and margin:
(Millions of Dollars) 2020 2019
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 riders 8
Retail sales growth 2
Other (net) (1)
Total decrease in natural gas margin $ (3)
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 program 18
Information technology 14
Employee benefits 12
Texas rate case deferral 8
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 increase 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) - Taxes (other than income taxes) increased $43 million, or 7.6%, year-to-date. The increase was primarily due to higher property taxes in Colorado and Texas (net of deferred amounts).
Other Income (Expense) - 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, Equity 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 and diluted EPS contributions of Xcel Energy Inc. and its nonregulated businesses:
Contribution (Millions of Dollars)
2020 2019
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)
Contribution (Diluted Earnings (Loss) Per Share)
2020 2019
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-K 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.
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.
NSP-Minnesota
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Regulatory Body / RTO Additional 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 IRPs for meeting future energy needs.
Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota.
Reviews and approves natural gas supply plans.
Pipeline safety compliance.
NDPSC Retail rates, services and other aspects of electric and natural gas operations.
Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota.
Pipeline safety compliance.
SDPUC Retail rates, services and other aspects of electric operations.
Regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in South Dakota.
Pipeline safety compliance.
FERC Wholesale 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.
MISO NSP-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.
DOT Pipeline safety compliance.
Minnesota Office of Pipeline Safety Pipeline safety compliance.
Recovery Mechanisms
Mechanism Additional Information
CIP Rider (a)
Recovers costs of conservation and DSM programs in Minnesota.
EIR Recovers costs of environmental improvement projects in Minnesota.
RDF Allocates money collected from customers to support research and development of emerging renewable energy projects and technologies in Minnesota.
RES Recovers cost of renewable generation in Minnesota.
RER Recovers cost of renewable generation in North Dakota.
SEP Recovers costs related to various energy policies approved by the Minnesota legislature.
TCR Recovers costs for investments in electric transmission and distribution grid modernization.
Infrastructure Rider Recovers 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.
PGA Provides 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 Rider Recovers 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-up In 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
Proceeding Amount
(in millions) Filing
Date Approval
2020 North Dakota Electric Rate Case $22 November 2020 Pending
2020 TCR Electric Rider 82 November 2019 Pending
2020 GUIC Natural Gas Rider 21 November 2019 Pending
2021 GUIC Natural Gas Rider 27 October 2020 Pending
2020 RES Electric Rider
102 November 2019
Pending
2021 RES Electric Rider 189 November 2020 Pending
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.
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.
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. 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 / RTO Additional 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.
FERC Wholesale 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.
MISO NSP-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.
DOT Pipeline safety compliance.
Recovery Mechanisms
Mechanism Additional Information
Annual Fuel Cost Plan NSP-Wisconsin does not have an automatic electric fuel adjustment clause. Under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW. Once the PSCW approves the plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a 2% annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the most recently authorized ROE. Under-collections that exceed the 2% annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.
Power Supply Cost Recovery Factors NSP-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 Program The 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.
PGA A 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.
Pending and Recently Concluded Regulatory Proceedings
2021 Electric Fuel Cost Recovery - In December 2020, the PSCW approved 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 participate 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 third quarter of 2021.
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.
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 / RTO Additional Information on Regulatory Authority
CPUC Retail rates, accounts, services, issuance of securities and other aspects of electric, natural gas and steam operations.
Pipeline safety compliance.
FERC Wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.
Wholesale electric sales at cost-based prices to customers inside PSCo’s balancing authority area and at market-based prices to customers outside PSCo’s balancing authority area.
PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction.
RTO PSCo is not presently a member of an RTO and does not operate within an RTO energy market. However, PSCo does make certain sales to other RTO’s, including SPP and participates in a joint dispatch agreement with neighboring utilities.
DOT Pipeline safety compliance.
Recovery Mechanisms
Mechanism Additional Information
ECA Recovers fuel and purchased energy costs. Short-term sales margins are shared with customers through the ECA. The ECA is revised quarterly.
PCCA Recovers purchased capacity payments.
SCA Recovers fuel costs to operate the steam system. The SCA rate is revised quarterly.
DSMCA Recovers electric and gas DSM, interruptible service costs and performance initiatives for achieving energy savings goals.
RESA Recovers the incremental costs of compliance with the RES with a maximum of 1% of the customer’s bill.
CEPA Recovers the early retirement costs of Comanche units 1 and 2 to a maximum of 1% of the customer’s bill.
WCA Recovers costs for customers who choose renewable resources.
TCA Recovers costs for transmission investment between rate cases.
CACJA Recovers costs associated with the CACJA.
FCA PSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale customers pay production costs through a forecasted formula rate subject to true-up.
GCA Recovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates.
PSIA Recovers costs for transmission and distribution pipeline integrity management programs.
Decoupling Mechanism to true-up revenue to a baseline amount for residential (excluding lighting and demand) and metered non-demand small C&I classes. Represents approximately $51M for differences in sales to the baseline amount. Amounts refunded or surcharged to customers may be limited to a refund cap.
Pending and Recently Concluded Regulatory Proceedings
Proceeding Amount
(in millions) Filing Date Approval
2020 Natural Gas Rate Case $77 February 2020 Received
2019 Electric Rate Case 108 May 2019 Received
2019 Natural Gas Rate Case Appeal N/A April 2019 Pending
Wildfire Protection Rider 325 July 2020 Pending
Transportation Electrification Plan Rider 110 - 138 May 2020 Received
Additional Information:
2020 Natural Gas Rate Case - In October 2020, the CPUC approved a settlement resulting in a net increase of $77 million. This increase reflects a $94 million increase in base rate revenue, partially offset by $17 million of costs previously recovered through the Pipeline Integrity rider. Rates will be implemented on April 1, 2021 (retroactive to November 2020).
2019 Electric Rate Case - In 2019, PSCo filed a request with the CPUC seeking a net rate increase of approximately $108 million. In February 2020, the CPUC issued an initial decision for a net rate increase of $35 million. In July 2020, the CPUC’s final written decision on rehearing was received and resulted in an additional increase of approximately $12 million annually.
In December 2020, the CPUC denied PSCo’s request of a $5 million surcharge for changes to the revenue increase from the effective date of rates, based on the CPUC’s decision on rehearing. PSCo has appealed this decision with the District Court of Denver County.
2019 Phase I Electric Rate Case Appeal - In August 2020, PSCo filed an appeal with the Denver District Court seeking a review of CPUC decisions on gain on sales and losses of assets, oil and gas royalty revenues and Board of Director’s equity compensation. PSCo plans to seek consolidation of this appeal with the appeal of the surcharge decision in this same proceeding.
2019 Natural Gas Rate Case Appeal - In April 2019, PSCo filed an appeal seeking judicial review of the CPUC’s prior ruling regarding PSCo’s natural gas rate case (filed in June 2017 and approved in December 2018). The appeal requested review of the following: denial of a return on the prepaid pension and retiree medical assets; the use of a capital structure not based on the actual historical test year; and use of an average rate base methodology rather than a year-end rate base methodology.
In March 2020, The District Court of Denver County ruled in favor of allowing the prepaid pension assets to be included in rate base; but upheld the CPUC’s treatment of the retiree medical assets and capital structure methodology. In March 2021, PSCo expects to file a motion to implement the District Court’s decision on treatment of the prepaid pension asset for the applicable period of Jan. 1, 2018 through Oct. 31, 2020.
Wildfire Protection Rider - In 2020, PSCo requested to establish a rider to recover incremental costs associated with system investments to reduce wildfire risk. The rider would be effective in June 2021 and continue through 2025. The Office of Consumer Counsel and CPUC Staff are supportive of the wildfire mitigation program as proposed, but oppose rider recovery and instead recommend deferral of certain costs with recovery in a future rate case. A CPUC decision is expected in the second quarter of 2021.
Wildfire Protection capital investment is projected to be approximately $325 million. Forecasted annual revenue requirements from 2021 through 2025:
(Millions of Dollars) 2021 2022 2023 2024 2025
Forecasted annual revenue requirement $ 17 $ 24 $ 29 $ 32 $ 34
Transportation Electrification Plan - In January 2021, the CPUC approved PSCo's Transportation Electrification Plan, which authorizes rider recovery of new electric vehicle utility programs for the residential, commercial, multi-family and public charging sectors. The approval establishes utility-owned charging infrastructure and chargers and amortization of rebates for electric vehicles. The Transportation Electrification Plan approval authorizes approximately $110 million in spending with flexibility up to approximately $138 million over three years.
Advanced Grid Rider
In 2020, PSCo requested to establish a rider to recover incremental costs associated with the Advanced Grid Intelligence and Security initiative. The rider would be effective in May 2021 and continue through 2025. In October 2020, an ALJ issued The Recommended Decision granting the Office of Consumer Counsel motion to dismiss the Advanced Grid Rider. PSCo has chosen not to appeal the ALJ’s Recommended Decision.
The PSCo portion of the Advanced Grid Intelligence and Security capital investment is projected to be approximately $850 million. Forecasted annual revenue requirements from 2021 through 2025 are as follows:
(Millions of Dollars) 2021 2022 2023 2024 2025
Forecasted annual revenue requirement $ 53 $ 69 $ 83 $ 89 $ 99
PSCo KEPCO Filing
In September 2020, PSCo filed with the CPUC for approval to terminate a solar PPA with KEPCO Solar of Alamosa, Inc. and establish a regulatory asset to recover transaction costs of approximately $41 million. By terminating the PPA, customers would save approximately $38 million over an 11-year period. A CPUC decision is expected in the second quarter of 2021.
Natural Gas LDC and Emission Reductions
In October 2020, the CPUC opened a docket to investigate topics related to natural gas emissions in relation to statewide emission reduction goals. The first meeting was held in November 2020, in which subject matter experts discussed greenhouse emission reductions required from the natural gas industry in regard to the statewide goals.
Resource Plan
PSCo is expected to file its next Electric Resource Plan on March 31, 2021. The filing will propose the future of the remaining coal plants in Colorado and PSCo’s plan to achieve it’s 80% carbon emissions reduction target by 2030. A CPUC decision is expected in 2022.
PSCo - Comanche Unit 3
PSCo is part owner and operator of Comanche Unit 3, a 750 MW, coal-fueled electric generating unit. In January 2020, the unit experienced a turbine failure causing the unit to be taken offline for repairs, which were completed in June 2020. During start-up the unit experienced a loss of turbine oil, which damaged the plant. Comanche Unit 3 recommenced operations in January 2021. Replacement and repair of damaged systems in excess of a $2 million deductible are expected to be recovered through insurance policies. PSCo obtained replacement power costs of approximately $16 million during the outage. In October 2020, the CPUC initiated a non-adjudicatory review of Comanche Unit 3’s performance. A report on performance is expected to be issued in March 2021. At this stage of the regulatory review, the resulting recommendations of the CPUC’s staff cannot be determined.
Boulder Municipalization
In 2011, Boulder passed a ballot measure authorizing the formation of an electric municipal utility. Subsequently, there have been various legal proceedings in multiple venues.
In September 2020, the City Council voted to approve a settlement between PSCo and Boulder officials to end the city’s municipalization effort. The settlement resulted in a 20-year franchise arrangement (with multiple opt-out conditions), an energy partnership and an undergrounding agreement. It also established the municipalization process if Boulder exercised an opt-out. In December 2020, PSCo filed the franchise agreement with the CPUC and is currently awaiting a decision.
Purchased Power and Transmission Service Providers
PSCo expects to meet its system capacity requirements through electric generating stations, power purchases, new generation facilities, DSM options and expansion of generation plants.
Purchased Power - PSCo purchases power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require capacity and energy charges. It also contracts to purchase power for both wind and solar resources. PSCo makes short-term purchases to meet system load and energy requirements, replace owned generation, meet operating reserve obligations, or obtain energy at a lower cost.
Energy Markets - PSCo is working towards joining the Western Energy Imbalance Market in 2022. This market was developed by the California ISO and allows PSCo access to a real-time energy market. The Western Energy Imbalance Market allows participants to buy and sell power close to the time electricity is consumed and gives system operators real-time visibility across neighboring grids. The result improves balancing supply and demand at a lower cost.
Purchased Transmission Services - In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to its customers.
Wholesale and Commodity Marketing Operations
PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. PSCo uses physical and financial instruments to minimize commodity price and credit risk and hedge sales and purchases. PSCo also engages in trading activity unrelated to hedging. Sharing of any margin is determined through state regulatory proceedings as well as the operation of the FERC approved JOA.
SPS
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Regulatory Body / RTO Additional 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.
NMPRC Retail electric operations, retail rates and services and the construction of transmission or generation.
FERC Wholesale 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 IM Wholesale Market SPS is a transmission owning member of the SPP RTO and operates within the SPP RTO and SPP IM wholesale market. SPS is authorized to make wholesale electric sales at market-based prices.
Recovery Mechanisms
Mechanism Additional Information
DCRF Recovers distribution costs not included in rates in Texas.
EECRF Recovers costs for energy efficiency programs in Texas.
Energy Efficiency Rider Recovers costs for energy efficiency programs in New Mexico.
FPPCAC Adjusts monthly to recover actual fuel and purchased power costs in New Mexico.
PCRF Allows recovery of purchased power costs not included in Texas rates.
RPS Recovers deferred costs for renewable energy programs in New Mexico.
TCRF Recovers certain transmission infrastructure improvement costs and changes in wholesale transmission charges not included in Texas base rates.
Fixed Fuel and Purchased Recovery Factor Provides 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 Adjustment SPS 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
Proceeding Amount
(in millions) Filing Date Approval
2019 New Mexico Electric Rate Case $31 July 2019 Received
2019 Texas Electric Rate Case 88 August 2019 Received
2021 New Mexico Electric Rate Case 88 January 2021 Pending
2021 Texas Electric Rate Case 143 February 2021 Pending
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, 2021, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $88 million. SPS' net rate increase 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%, an equity ratio of 54.72% and retail rate base of approximately $1.9 billion (total company rate base of approximately $6.0 billion).
Additionally, the request includes the effect of approximately 400 MW of reduced peak load in 2021 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 at the Harrington facility (to 2024).
The NMPRC suspended 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 hearing on stipulation - July 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.
2021 Texas Rate Case - On Feb. 8, 2021, SPS filed an electric rate case with the PUCT and its 81 municipalities with original rate jurisdiction seeking an increase in base rates of approximately $143 million. SPS' net rate increase to Texas customers is expected to be approximately $74 million, or 9.2%, as a result of offsetting $69 million in fuel cost reductions and PTCs from the Sagamore wind project.
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 is based on an 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 request includes the effect of 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 of the Harrington facility (to 2024).
Summary of SPS’ request:
Rate Request (Millions of Dollars)
Sagamore wind project $ 67
Other capital investments 25
Cost of capital 20
Property taxes 8
Reduced sales, partially offset by changes in O&M 8
Allocator changes 4
Depreciation rate change 3
Other, net 8
Total rate request $ 143
Fuel cost reductions and PTCs - Sagamore wind project (69)
Net rate increase $ 74
SPS is requesting the PUCT set current rates as temporary 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. 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 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.
Critical Accounting Policies and Estimates
Preparation of the consolidated financial statements requires the application of accounting rules and guidance, as well as the use of estimates. Application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and results reported.
Accounting policies and estimates that are most significant to Xcel Energy’s results of operations, financial condition or cash flows, and require management’s most difficult, subjective or complex judgments are outlined below. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.’s Board of Directors on a quarterly basis.
Regulatory Accounting
Xcel Energy is subject to the accounting for Regulated Operations, which provides that rate-regulated entities report assets and liabilities consistent with the recovery of those incurred costs in rates, if it is probable that such rates will be charged and collected. Our rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or other comprehensive income.
Each reporting period we assess the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital, and may materially impact our results of operations, financial condition or cash flows.
As of Dec. 31, 2020 and 2019, Xcel Energy had regulatory assets of $3.4 billion and regulatory liabilities of $5.6 billion and $5.5 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, in assessing the probability of recovery of recognized regulatory assets, 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 Note 4 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, Xcel Energy set the rate of return on assets used to measure pension costs at 6.49%, which represents a 38 basis point decrease from the rate set in 2019. The rate of return used to measure postretirement health care costs is 4.10% at Dec. 31, 2020, which represents a 40 basis point decrease from 2019.
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 and a greater percentage of growth assets being allocated to plans having a lower funded status ratios.
Xcel Energy set the discount rates used to value the pension obligations at 2.71% and postretirement health care obligations at 2.65% at Dec. 31, 2020. This represents a 78 basis point and 82 basis point decrease, respectively, from 2019. 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 2020 pension costs:
Pension Costs
(Millions of Dollars) +1% -1%
Rate of return $ (16) $ 22
Discount rate (a)
$ (5) $ 13
(a)These cost 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, the initial medical trend cost claim assumptions for Pre-65 was 5.5% and Post-65 was 5.0%. 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 million and are expected to decline in the following years. Investment returns exceeded assumed levels in 2020 and 2019 and were below assumed levels in 2018.
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).
Xcel Energy currently projects the pension costs recognized for financial reporting purposes will be $106 million in 2021 and $83 million in 2022, while the actual pension costs were $117 million in 2020 and $115 million in 2019. The expected decrease in 2021 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 2018 - 2021:
•$125 million in January 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 $11 million, $15 million and $11 million during 2020, 2019 and 2018, respectively, to the postretirement health care plans. Xcel Energy expects to contribute approximately $10 million during 2021. 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, the PSCW approved NSP-Wisconsin’s request for deferred accounting treatment of the 2018 pension settlement accounting expense.
•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.
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 $2.0 billion in 2020 and $2.1 billion in 2019.
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 2020 was based on the 2014 nuclear decommissioning filing, approved in 2015. Although the MPUC approved an increased accrual from the 2017 triennial filing in January 2019, the MPUC subsequently ordered Xcel Energy to maintain the accrual level (previously established via the 2014 filing) through 2020.
In December 2020, Xcel Energy submitted a 2020 triennial nuclear decommissioning filing to the MPUC. The filing resulted in an updated annual accrual of $33 million, or an increase of $19 million compared to the currently approved funding level. In December 2020, the MPUC verbally approved NSP-Minnesota to continue using the 2014 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).
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.
Technology and Regulation - There is limited experience with actual decommissioning of large nuclear facilities. Changes in technology, experience and regulations could cause cost estimates to change significantly.
Escalation Rates - Escalation rates represent projected cost increases due to general inflation and increases in the cost of decommissioning activities. NSP-Minnesota applied escalation rates of 3.1% for PI and 3.2% for Monticello in calculating the nuclear decommissioning AROs, 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.
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 it to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.
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 its risk management committee.
Fair value of net commodity trading contracts as of Dec. 31, 2020:
Futures / Forwards Maturity
(Millions of Dollars) Less Than
1 Year
1 to 3 Years 4 to 5 Years Greater Than
5 Years
Total
Fair Value
NSP-Minnesota (a)
$ (2) $ 1 $ 2 $ 2 $ 3
NSP-Minnesota (b)
(3) 3 (7) (6) (13)
PSCo (a)
- 1 - - 1
PSCo (b)
(25) (39) (13) - (77)
$ (30) $ (34) $ (18) $ (4) $ (86)
Options Maturity
(Millions of Dollars) Less Than
1 Year
1 to 3 Years 4 to 5 Years Greater Than
5 Years
Total Fair Value
NSP-Minnesota (b)
$ 1 $ - $ - $ 1 $ 2
PSCo (b)
13 16 1 - 30
$ 14 $ 16 $ 1 $ 1 $ 32
(a)Prices actively quoted or based on actively quoted prices.
(b)Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing for the years ended Dec. 31:
(Millions of Dollars) 2020 2019
Fair value of commodity trading net contracts outstanding at Jan. 1 $ (59) $ 17
Contracts realized or settled during the period (9) (22)
Commodity trading contract additions and changes during the period 14 (54)
Fair value of commodity trading net contracts outstanding at Dec. 31 $ (54) $ (59)
At Dec. 31, 2020, a 10% increase in market prices for commodity trading contracts through the forward curve would increase pretax income from continuing operations by approximately $13 million, whereas a 10% decrease would decrease pretax income from continuing operations by approximately $13 million. At Dec. 31, 2019, a 10% increase in market prices for commodity trading contracts would increase pretax income from continuing operations by approximately $10 million, whereas a 10% decrease would decrease pretax income from continuing operations by approximately $10 million. 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.
The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchase and normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows:
(Millions of Dollars) Year Ended
Dec. 31 VaR Limit Average High Low
2020 $ 1 $ 3 $ 1 $ 2 $ 1
2019 < 1 3 1 1 < 1
Nuclear Fuel Supply - NSP-Minnesota has contracted for approximately 11% of its 2021 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% 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 $6 million in 2020 and 2019, 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 monitor these policies to reflect changes and scope of operations.
At Dec. 31, 2020, a 10% increase in commodity prices would have resulted in an 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 of $19 million, while a decrease in prices of 10% would have resulted in an increase in credit exposure of $14 million.
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.
Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are recorded as other comprehensive income or deferred as regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. The impact of discounting commodity derivative liabilities for credit risk was immaterial at Dec. 31, 2020.
See Notes 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 - 2019 $ 3,263
Components of change - 2020 vs. 2019
Higher net income 101
Non-cash transactions (a)
(49)
Changes in working capital (b)
(222)
Changes in net regulatory and other assets and liabilities (245)
Cash provided by operating activities - 2020 $ 2,848
(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 million for 2020 as compared to 2019. Decrease was primarily due to changes in accounts receivable related to increased residential sales, timing of regulatory asset recovery and inventory wind turbine purchases, which were partially offset by an increase in net income.
Investing Cash Flows
(Millions of Dollars) Twelve Months Ended Dec. 31
Cash used in investing activities - 2019 $ (4,343)
Components of change - 2020 vs. 2019
Increased capital expenditures (1,144)
Sale of MEC 684
Other investing activities 63
Cash used in investing activities - 2020 $ (4,740)
Net cash used in investing activities increased by $397 million for 2020 as compared to 2019. Increase was primarily attributable to additional capital expenditures, primarily for wind projects, including Sagamore, Cheyenne Ridge, Blazing Star 1 and Crowned Ridge 2.
Financing Cash Flows
(Millions of Dollars) Twelve Months Ended Dec. 31
Cash provided by financing activities - 2019 $ 1,181
Components of change - 2020 vs. 2019
Higher debt issuances 452
Higher repayments of long-term debt (52)
Higher proceeds from issuance of common stock 269
Higher dividends paid to shareholders (65)
Other financing activities (12)
Cash provided by financing activities - 2020 $ 1,773
Net cash provided by financing activities increased by $592 million for 2020 as compared to 2019. Increase was primarily attributable to higher proceeds from issuances of long-term debt and common stock (due to forward equity agreements settling in November 2020 and August 2019), partially offset by higher repayments of long-term debt and dividends paid.
See Note 5 to the consolidated financial statements for further information.
Capital Requirements
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.
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 Period
(Millions of Dollars) Total Less than 1 Year 1 to 3 Years 3 to 5 Years After 5 Years
Long-term debt, principal and interest payments $ 34,312 $ 1,183 $ 3,249 $ 3,107 $ 26,773
Finance lease obligations 257 14 24 22 197
Operating leases obligations (a)
1,859 273 497 434 655
Unconditional purchase obligations (b)
5,005 1,366 1,585 911 1,143
Other long-term obligations, including current portion 637 74 63 60 440
Other short-term obligations 420 420 - - -
Short-term debt 584 584 - - -
Total contractual cash obligations $ 43,074 $ 3,914 $ 5,418 $ 4,534 $ 29,208
(a)Included in operating lease obligations are $247 million, $446 million, $398 million and $561 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively, pertaining to PPAs that were accounted for as operating leases.
(b)Xcel Energy Inc. and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its fuel (nuclear, natural gas and coal) requirements. Additionally, the utility subsidiaries of Xcel Energy Inc. have entered into non-lease purchase power agreements. Certain contractual purchase obligations are adjusted on indices. Effects of price changes are mitigated through cost of energy adjustment mechanisms.
Capital Expenditures - The capital forecasts for Xcel Energy for 2021 through 2025 are detailed in the following tables. The base 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.
Actual Base Capital Forecast (Millions of Dollars)
By Regulated Utility 2020 2021 2022 2023 2024 2025 2021 - 2025 Total
PSCo $ 1,600 $ 1,700 $ 1,835 $ 1,750 $ 1,695 $ 1,655 $ 8,635
NSP-Minnesota 1,955 1,930 1,785 1,785 1,915 1,890 9,305
SPS 1,180 505 710 770 735 675 3,395
NSP-Wisconsin 235 360 430 395 515 470 2,170
Other (a)
(135) (20) (15) 10 10 10 (5)
Total base capital expenditures $ 4,835 $ 4,475 $ 4,745 $ 4,710 $ 4,870 $ 4,700 $ 23,500
(a) Other category includes intercompany transfers for safe harbor wind turbines.
Actual Base Capital Forecast (Millions of Dollars)
By Function 2020 2021 2022 2023 2024 2025 2021 - 2025 Total
Electric distribution $ 980 $ 1,205 $ 1,440 $ 1,550 $ 1,505 $ 1,475 $ 7,175
Electric transmission 695 870 1,285 1,285 1,270 1,290 6,000
Electric generation 445 630 575 560 750 975 3,490
Natural gas 580 615 615 665 670 625 3,190
Other 345 545 575 485 405 335 2,345
Renewables 1,790 610 255 165 270 - 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 Proposal 2021 2022 2023 2024 2025 2021 - 2025 Total
Sherco solar $ 30 $ 200 $ 320 $ - $ - $ 550
Wind PPA buyout 25 185 - - - 210
Total incremental capital $ 55 $ 385 $ 320 $ - $ - $ 760
(a) Reflects potential capital investment under the Minnesota Relief and Recovery Plan, which will require MPUC approval. The incremental capital investment is not included in the base capital forecast.
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, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and mergers, acquisition and divestiture opportunities.
Financing Capital Expenditures through 2025 - 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.
Current estimated financing plans for 2021 - 2025:
(Millions of Dollars)
Funding Capital Expenditures
Cash from operations (a)
$ 15,000
New debt (b)
7,490
Equity through the DRIP and benefit program 410
Other equity 600
Base capital expenditures 2021 - 2025 $ 23,500
Maturing Debt $ 3,820
(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, 2020 Dec. 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 Assumptions 2020 2019
Discount rate 2.71 % 3.49 %
Expected long-term rate of return 6.49 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.
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 end 584
Average amount outstanding 415
Maximum amount outstanding 613
Weighted average interest rate, computed on a daily basis 0.60 %
Weighted average interest rate at end of period 0.23
(Amounts in Millions, Except Interest Rates) Year Ended Dec. 31, 2020 Year Ended Dec. 31, 2019 Year Ended Dec. 31, 2018
Borrowing limit $ 3,100 $ 3,600 $ 3,250
Amount outstanding at period end 584 595 1,038
Average amount outstanding 1,126 1,115 788
Maximum amount outstanding 2,080 1,780 1,349
Weighted average interest rate, computed on a daily basis 1.45 % 2.72 % 2.34 %
Weighted average interest rate at end of period 0.23 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)
Available Cash Liquidity
Xcel Energy Inc. $ 1,250 $ 696 $ 554 $ 2 $ 556
PSCo 700 142 558 2 560
NSP-Minnesota 500 129 371 2 373
SPS 500 341 159 1 160
NSP-Wisconsin 150 - 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.
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.
COVID-19
Although the COVID-19 pandemic has led to numerous challenges, Xcel Energy believes its risk management program, including business continuity and disaster recovery planning, will continue to allow us to proactively manage and successfully navigate challenges, risks and uncertainties.
There is continued uncertainty regarding COVID-19, the duration and magnitude of business restrictions, re-shut downs 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 could have a material impact on our results of operations, financial condition or cash flow.
An overview of certain risk considerations or areas which have or could significantly impact us, is as follows.
Sales - Xcel Energy has experienced and may continue to experience higher residential sales and lower C&I sales as a result of COVID-19. Xcel Energy has decoupling and sales true-up mechanisms 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.
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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See Item 7, incorporated by reference.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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.
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. 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, 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 audit report on Xcel Energy Inc.’s internal control over financial reporting. Its report appears herein.
/s/ BEN FOWKE /s/ BRIAN J. VAN ABEL
Ben Fowke Brian J. Van Abel
Chairman, Chief Executive Officer and Director Executive Vice President, Chief Financial Officer
Feb. 17, 2021 Feb. 17, 2021
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, 2020 and 2019, 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, 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, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, 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.
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 judgements are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant regulatory orders issued by the Commissions for the Company, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We also evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. If the full recovery of project costs is being challenged by intervenors, we evaluated management’s assessment of the probability of a disallowance. We evaluated the external information and compared to the Company’s recorded regulatory assets and liabilities for completeness.
•We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 17, 2021
We have served as the Company’s auditor since 2002.
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(amounts in millions, except per share data)
Year Ended Dec. 31
2020 2019 2018
Operating revenues
Electric $ 9,802 $ 9,575 $ 9,719
Natural gas 1,636 1,868 1,739
Other 88 86 79
Total operating revenues 11,526 11,529 11,537
Operating expenses
Electric fuel and purchased power 3,512 3,510 3,854
Cost of natural gas sold and transported 689 918 843
Cost of sales - other 37 40 35
Operating and maintenance expenses 2,324 2,338 2,352
Conservation and demand side management expenses 288 285 290
Depreciation and amortization 1,948 1,765 1,642
Taxes (other than income taxes) 612 569 556
Total operating expenses 9,410 9,425 9,572
Operating income 2,116 2,104 1,965
Other (expense) income, net (6) 16 (14)
Equity earnings of unconsolidated subsidiaries 40 39 35
Allowance for funds used during construction - equity 115 77 108
Interest charges and financing costs
Interest charges - includes other financing costs of $28, $26 and $25, respectively
840 773 700
Allowance for funds used during construction - debt (42) (37) (48)
Total interest charges and financing costs 798 736 652
Income before income taxes 1,467 1,500 1,442
Income tax (benefit) expense (6) 128 181
Net income $ 1,473 $ 1,372 $ 1,261
Weighted average common shares outstanding:
Basic 527 519 511
Diluted 528 520 511
Earnings per average common share:
Basic $ 2.79 $ 2.64 $ 2.47
Diluted 2.79 2.64 2.47
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(amounts in millions)
Year Ended Dec. 31
2020 2019 2018
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), $- and $(2), respectively
(5) - (6)
Reclassification of losses to net income, net of tax of $3, $1 and $3, respectively
10 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, respectively
5 3 3
Total other comprehensive (loss) income - (17) 1
Total comprehensive income $ 1,473 $ 1,355 $ 1,262
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in millions)
Year Ended Dec. 31
2020 2019 2018
Operating activities
Net income $ 1,473 $ 1,372 $ 1,261
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization 1,959 1,785 1,659
Nuclear fuel amortization 123 119 122
Deferred income taxes (8) 143 218
Allowance for equity funds used during construction (115) (77) (108)
Equity earnings of unconsolidated subsidiaries (40) (39) (35)
Dividends from unconsolidated subsidiaries 42 40 37
Provision for bad debts 60 42 42
Share-based compensation expense 73 58 45
Net realized and unrealized hedging and derivative transactions (27) 45 22
Changes in operating assets and liabilities:
Accounts receivable (154) (20) (105)
Accrued unbilled revenues (3) 42 9
Inventories (80) (84) (65)
Other current assets (45) 25 18
Accounts payable (33) (12) 90
Net regulatory assets and liabilities (144) (66) 223
Other current liabilities 29 (15) (61)
Pension and other employee benefit obligations (125) (135) (179)
Other, net (137) 40 (71)
Net cash provided by operating activities 2,848 3,263 3,122
Investing activities
Capital/construction expenditures (5,369) (4,225) (3,957)
Sale of MEC 684 - -
Purchase of investment securities (1,398) (995) (853)
Proceeds from the sale of investment securities 1,378 975 833
Other, net (35) (98) (9)
Net cash used in investing activities (4,740) (4,343) (3,986)
Financing activities
(Repayments of) proceeds from short-term borrowings, net (11) (443) 225
Proceeds from issuances of long-term debt 2,940 2,920 1,675
Repayments of long-term debt, including reacquisition premiums (1,001) (949) (452)
Proceeds from issuance of common stock 727 458 230
Dividends paid (856) (791) (730)
Other, net (26) (14) (20)
Net cash provided by financing activities 1,773 1,181 928
Net change in cash and cash equivalents (119) 101 64
Cash and cash equivalents at beginning of period 248 147 83
Cash and cash equivalents at end of period $ 129 $ 248 $ 147
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized) $ (758) $ (698) $ (633)
Cash received for income taxes, net 12 53 27
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions $ 400 $ 421 $ 388
Inventory transfers to property, plant and equipment 275 88 129
Operating lease right-of-use assets 369 1,843 -
Allowance for equity funds used during construction 115 77 108
Issuance of common stock for equity awards 67 63 67
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in millions, except share and per share)
Dec. 31
2020 2019
Assets
Current assets
Cash and cash equivalents $ 129 $ 248
Accounts receivable, net 916 837
Accrued unbilled revenues 714 713
Inventories 535 544
Regulatory assets 640 488
Derivative instruments 49 55
Prepaid taxes 42 43
Prepayments and other 250 185
Total current assets 3,275 3,113
Property, plant and equipment, net 42,950 39,483
Other assets
Nuclear decommissioning fund and other investments 3,096 2,731
Regulatory assets 2,737 2,935
Derivative instruments 30 22
Operating lease right-of-use assets 1,490 1,672
Other 379 492
Total other assets 7,732 7,852
Total assets $ 53,957 $ 50,448
Liabilities and Equity
Current liabilities
Current portion of long-term debt $ 421 $ 702
Short-term debt 584 595
Accounts payable 1,237 1,294
Regulatory liabilities 311 407
Taxes accrued 578 466
Accrued interest 203 192
Dividends payable 231 212
Derivative instruments 53 38
Operating lease liabilities 214 194
Other 407 468
Total current liabilities 4,239 4,568
Deferred credits and other liabilities
Deferred income taxes 4,746 4,509
Deferred investment tax credits 45 49
Regulatory liabilities 5,302 5,077
Asset retirement obligations 2,884 2,701
Derivative instruments 131 175
Customer advances 197 203
Pension and employee benefit obligations 666 785
Operating lease liabilities 1,344 1,549
Other 183 186
Total deferred credits and other liabilities 15,498 15,234
Commitments and contingencies
Capitalization
Long-term debt 19,645 17,407
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, respectively
1,344 1,311
Additional paid in capital 7,404 6,656
Retained earnings 5,968 5,413
Accumulated other comprehensive loss (141) (141)
Total common stockholders’ equity 14,575 13,239
Total liabilities and equity $ 53,957 $ 50,448
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
(amounts in millions, shares in thousands)
Common Stock Issued Retained Earnings Accumulated Other
Comprehensive Loss
Total Common Stockholders’ Equity
Shares Par Value Additional Paid
In Capital
Balance at Dec. 31, 2017 507,763 $ 1,269 $ 5,898 $ 4,413 $ (125) $ 11,455
Net income 1,261 1,261
Other comprehensive income 1 1
Dividends declared on common stock ($1.52 per share)
(780) (780)
Issuances of common stock 6,296 16 254 270
Repurchases of common stock (22) - (1) (1)
Share-based compensation 17 (1) 16
Balance at Dec. 31, 2018 514,037 $ 1,285 $ 6,168 $ 4,893 $ (124) $ 12,222
Net Income 1,372 1,372
Other comprehensive loss (17) (17)
Dividends declared on common stock ($1.62 per share)
(846) (846)
Issuances of common stock 10,508 26 468 494
Repurchase of common stock (6) - - -
Share-based compensation 20 (6) 14
Balance at Dec. 31, 2019 524,539 $ 1,311 $ 6,656 $ 5,413 $ (141) $ 13,239
Net income 1,473 1,473
Dividends declared on common stock ($1.72 per share)
(909) (909)
Issuances of common stock 12,954 33 731 764
Repurchase of common stock (55) - (4) (4)
Share-based compensation 21 (7) 14
Adoption of ASC Topic 326 (2) (2)
Balance at Dec. 31, 2020 537,438 $ 1,344 $ 7,404 $ 5,968 $ (141) $ 14,575
See Notes to Consolidated Financial Statements
XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
General - Xcel Energy Inc.’s utility subsidiaries are engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas.
Xcel Energy’s regulated operations include the activities of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utility subsidiaries serve electric and natural gas customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Also included in regulated operations are WGI, an interstate natural gas pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipeline, storage and compression facilities.
Xcel Energy Inc.’s nonregulated subsidiaries include Eloigne, Capital Services 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. 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 Project 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 investment in 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, 2020 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.
Use of Estimates - Xcel Energy uses estimates based on the best information available in recording transactions and balances resulting from business operations.
Estimates are used on items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or actual amounts can be determined. Revisions can affect operating results.
Regulatory Accounting - 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.
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.
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 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 are 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 3.4% for 2020, 3.3% for 2019 and 3.1% for 2018.
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 three 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.
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 an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.
Estimated remediation costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for 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 three months or less at the time of purchase to be cash equivalents.
Accounts Receivable and Allowance for Bad Debts - Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. 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, 2020 and 2019, the allowance for bad debts was $79 million and $55 million, respectively.
Inventory - Inventory is recorded at average cost and consisted of the following:
(Millions of Dollars) Dec. 31, 2020 Dec. 31, 2019
Inventories
Materials and supplies $ 275 $ 270
Fuel 176 191
Natural gas 84 83
Total inventories $ 535 $ 544
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.
Other Utility Items
AFUDC - AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in Xcel Energy’s rate base for establishing utility rates.
Alternative Revenue - Certain rate rider mechanisms (including decoupling 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. 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 costs for the cost of RECs and records that cost as a regulatory asset when the amount is recoverable in future rates.
Sales of RECs are recorded in electric revenues on a gross basis. 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) Dec. 31, 2020 Dec. 31, 2019
Property, plant and equipment, net
Electric plant $ 47,104 $ 44,355
Natural gas plant 7,135 6,560
Common and other property 2,503 2,341
Plant to be retired (a)
677 259
CWIP 1,877 2,329
Total property, plant and equipment 59,296 55,844
Less accumulated depreciation (16,657) (16,735)
Nuclear fuel 2,970 2,909
Less accumulated amortization (2,659) (2,535)
Property, plant and equipment, net $ 42,950 $ 39,483
(a)Includes regulator-approved retirements of Comanche Units 1 and 2 and jointly owned Craig Unit 1 for PSCo, and Sherco Units 1 and 2 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:
(Millions of Dollars, Except Percent Owned) Plant in Service Accumulated Depreciation CWIP Percent Owned
NSP-Minnesota
Electric generation:
Sherco Unit 3 $ 601 $ 435 $ 2 59 %
Sherco common facilities 149 108 5 80
Sherco substation 5 3 - 59
Electric transmission:
Grand Meadow 11 3 - 50
CapX2020 954 108 33 51
Total NSP-Minnesota $ 1,720 $ 657 $ 40
(Millions of Dollars, Except Percent Owned) Plant in Service Accumulated Depreciation CWIP Percent Owned
NSP-Wisconsin
Electric transmission:
La Crosse, WI to Madison, WI $ 188 $ 12 $ - 37 %
CapX2020 169 23 - 80
Total NSP-Wisconsin $ 357 $ 35 $ -
(Millions of Dollars, Except Percent Owned) Plant in Service Accumulated Depreciation CWIP Percent Owned
PSCo
Electric generation:
Hayden Unit 1 $ 153 $ 92 $ - 76 %
Hayden Unit 2 150 73 - 37
Hayden common facilities 42 25 - 53
Craig Units 1 and 2 81 44 - 10
Craig common facilities 39 24 - 7
Comanche Unit 3 899 137 16 67
Comanche common facilities 25 2 - 82
Electric transmission:
Transmission and other facilities 176 59 2 Various
Gas transmission:
Rifle, CO to Avon, CO 22 8 - 60
Gas transmission compressor 8 1 - 50
Total PSCo $ 1,595 $ 465 $ 18
Each company’s share of operating expenses and construction expenditures is included in the applicable utility accounts. Respective owners are responsible for providing their own financing.
4. Regulatory Assets and Liabilities
Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric and natural gas rates. Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP.
Components of regulatory assets:
(Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2020 Dec. 31, 2019
Regulatory Assets Current Noncurrent Current Noncurrent
Pension and retiree medical obligations 11 Various $ 82 $ 1,268 $ 85 $ 1,328
Recoverable deferred taxes on AFUDC Plant lives - 283 - 271
Excess deferred taxes - TCJA
7 Various 16 229 39 239
Depreciation differences One to 11 years
16 154 15 140
Net AROs (a)
1, 12 Various - 139 - 269
Environmental remediation costs 1, 12 Various 16 113 36 131
Benson biomass PPA termination and asset purchase Nine years
10 65 9 73
Purchased power contract costs Term of related contract 7 54 5 61
PI extended power uprate 14 years
3 49 3 53
Contract valuation adjustments (b)
1, 10 Term of related contract 23 48 20 62
Losses on reacquired debt Term of related debt 4 38 4 41
Laurentian biomass PPA termination Three years
18 36 19 54
Conservation programs (c)
1 One to two years
26 36 27 26
State commission adjustments Plant lives 1 32 1 31
Sales true-up and revenue decoupling One to two years
101 28 54 16
Property tax Various 16 21 2 30
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 -
Renewable resources and environmental initiatives One to two years
129 12 72 10
Nuclear refueling outage costs 1 One to two years
28 10 43 17
Gas pipeline inspection and remediation costs One to two years
26 9 26 8
Other Various 50 78 20 69
Total regulatory assets $ 640 $ 2,737 $ 488 $ 2,935
(a) Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
(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 costs for conservation programs, as well as incentives allowed in certain jurisdictions.
Components of regulatory liabilities:
(Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2020 Dec. 31, 2019
Regulatory Liabilities Current Noncurrent Current Noncurrent
Deferred income tax adjustments and TCJA refunds (a)
7 Various $ 20 $ 3,368 $ 75 $ 3,523
Plant removal costs 1, 12 Various - 1,520 - 1,217
Effects of regulation on employee benefit costs (b)
Various - 221 - 196
Renewable resources and environmental initiatives Various 5 59 - 45
ITC deferrals
1 Various - 51 - 38
Revenue decoupling One to two years
10 41 - -
Deferred electric, natural gas and steam production costs Less than one year 84 - 138 -
Conservation programs (c)
1 Less than one year 49 - 37 -
DOE settlement Less than one year 23 - 37 -
Contract valuation adjustments (d)
1, 10 Less than one year 19 - 19 -
Other Various 101 42 101 58
Total regulatory liabilities (e)
$ 311 $ 5,302 $ 407 $ 5,077
(a)Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.
(b)Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the 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.
(e)Revenue subject to refund of $17 million and $28 million for 2020 and 2019, respectively, is included in other current liabilities.
At Dec. 31, 2020 and 2019, 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 million and $544 million at Dec. 31, 2020 and 2019, 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, various renewable resources and certain environmental initiatives.
5. Borrowings and Other Financing Instruments
Short-Term Borrowings
Short-Term Debt - Xcel Energy meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements.
Commercial paper and term loan borrowings outstanding:
(Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2020 Year Ended Dec. 31
2020 2019 2018
Borrowing limit $ 3,100 $ 3,100 $ 3,600 $ 3,250
Amount outstanding at period end 584 584 595 1,038
Average amount outstanding 415 1,126 1,115 788
Maximum amount outstanding 613 2,080 1,780 1,349
Weighted average interest rate, computed on a daily basis 0.60 % 1.45 % 2.72 % 2.34 %
Weighted average interest rate at period end 0.23 0.23 2.34 2.97
Term Loan Agreements - In December 2020, Xcel Energy Inc. repaid its $500 million 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 no open loan agreement.
Bilateral Credit Agreement - In March 2019, NSP-Minnesota entered into a one-year uncommitted bilateral credit agreement. The 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, outstanding letters of credit under the Bilateral Credit Agreement were as follows:
(Millions of Dollars) Limit Amount Outstanding Available
NSP-Minnesota $ 75 $ 49 $ 26
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, 2020 and 2019, there were $20 million of letters of credit outstanding under the credit facilities. 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)
2020 2019
Xcel Energy Inc. (c)
59 % 58 % $ 200 2
NSP-Wisconsin 46 48 N/A 1
NSP-Minnesota 47 48 100 2
SPS 48 46 50 2
PSCo 44 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.
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, 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:
(Millions of Dollars) Credit Facility (a)
Drawn (b)
Available
Xcel Energy Inc. $ 1,250 $ - $ 1,250
PSCo 700 144 556
NSP-Minnesota 500 189 311
SPS 500 252 248
NSP-Wisconsin 150 19 131
Total $ 3,100 $ 604 $ 2,496
(a)These credit facilities mature in June 2024.
(b)Includes outstanding commercial paper and letters of credit.
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facilities. Xcel Energy Inc. and its utility subsidiaries had no direct advances on facilities outstanding as of Dec. 31, 2020 and 2019.
Long-Term Borrowings and Other Financing Instruments
Generally, all property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are subject to the liens of their first mortgage indentures. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses for refinanced debt are deferred and amortized over the life of the new issuance.
Long-term debt obligations for Xcel Energy Inc. and its utility subsidiaries as of Dec. 31 (Millions of Dollars):
Xcel Energy Inc.
Financing Instrument Interest Rate Maturity Date 2020 2019
Unsecured senior notes 2.40 % March 15, 2021 $ 400 $ 400
Unsecured senior notes (c)
2.60 March 15, 2022 - 300
Unsecured senior notes (a)
0.50 Oct. 15, 2023 500 -
Unsecured senior notes 3.30 June 1, 2025 250 250
Unsecured senior notes 3.30 June 1, 2025 350 350
Unsecured senior notes 3.35 Dec. 1, 2026 500 500
Unsecured senior notes (b)
4.00 June 15, 2028 130 130
Unsecured senior notes 4.00 June 15, 2028 500 500
Unsecured senior notes (b)
2.60 Dec. 1, 2029 500 500
Unsecured senior notes (a)
3.40 June 1, 2030 600 -
Unsecured senior notes 6.50 July 1, 2036 300 300
Unsecured senior notes 4.80 Sept. 15, 2041 250 250
Unsecured senior notes (b)
3.50 Dec. 1, 2049 500 500
Unamortized discount (7) (5)
Unamortized debt issuance cost (32) (28)
Current maturities (400) -
Total long-term debt $ 4,341 $ 3,947
(a)2020 financing.
(b)2019 financing.
(c)Note was redeemed on Dec. 1, 2020.
NSP-Minnesota
Financing Instrument Interest Rate Maturity Date 2020 2019
First mortgage bonds 2.20 % Aug. 15, 2020 $ - $ 300
First mortgage bonds 2.15 Aug. 15, 2022 300 300
First mortgage bonds 2.60 May 15, 2023 400 400
First mortgage bonds 7.13 July 1, 2025 250 250
First mortgage bonds 6.50 March 1, 2028 150 150
First mortgage bonds 5.25 July 15, 2035 250 250
First mortgage bonds 6.25 June 1, 2036 400 400
First mortgage bonds 6.20 July 1, 2037 350 350
First mortgage bonds 5.35 Nov. 1, 2039 300 300
First mortgage bonds 4.85 Aug. 15, 2040 250 250
First mortgage bonds 3.40 Aug. 15, 2042 500 500
First mortgage bonds 4.13 May 15, 2044 300 300
First mortgage bonds 4.00 Aug. 15, 2045 300 300
First mortgage bonds 3.60 May 15, 2046 350 350
First mortgage bonds 3.60 Sept. 15, 2047 600 600
First mortgage bonds (b)
2.90 March 1, 2050 600 600
First mortgage bonds (a)
2.60 June 1, 2051 700 -
Unamortized discount (42) (31)
Unamortized debt issuance cost (54) (48)
Current maturities - (300)
Total long-term debt $ 5,904 $ 5,221
(a)2020 financing.
(b)2019 financing.
NSP-Wisconsin
Financing Instrument Interest Rate Maturity Date 2020 2019
City of La Crosse resource recovery bond 6.00 % Nov 1, 2021 $ 19 $ 19
First mortgage bonds 3.30 June 15, 2024 100 100
First mortgage bonds 3.30 June 15, 2024 100 100
First mortgage bonds 6.38 Sept. 1, 2038 200 200
First mortgage bonds 3.70 Oct. 1, 2042 100 100
First mortgage bonds 3.75 Dec. 1, 2047 100 100
First mortgage bonds 4.20 Sept. 1, 2048 200 200
First mortgage bonds (a)
3.05 May 1, 2051 100 -
Unamortized discount (4) (3)
Unamortized debt issuance cost (9) (8)
Current maturities (19) -
Total long-term debt $ 887 $ 808
(a)2020 financing.
PSCo
Financing Instrument Interest Rate Maturity Date 2020 2019
First mortgage bonds 3.20 % Nov. 15, 2020 $ - $ 400
First mortgage bonds 2.25 Sept. 15, 2022 300 300
First mortgage bonds 2.50 March 15, 2023 250 250
First mortgage bonds 2.90 May 15, 2025 250 250
First mortgage bonds 3.70 June 15, 2028 350 350
First mortgage bonds (a)
1.90 Jan. 15, 2031 375 -
First mortgage bonds 6.25 Sept. 1, 2037 350 350
First mortgage bonds 6.50 Aug. 1, 2038 300 300
First mortgage bonds 4.75 Aug. 15, 2041 250 250
First mortgage bonds 3.60 Sept. 15, 2042 500 500
First mortgage bonds 3.95 March 15, 2043 250 250
First mortgage bonds 4.30 March 15, 2044 300 300
First mortgage bonds 3.55 June 15, 2046 250 250
First mortgage bonds 3.80 June 15, 2047 400 400
First mortgage bonds 4.10 June 15, 2048 350 350
First mortgage bonds (b)
4.05 Sept. 15, 2049 400 400
First mortgage bonds (b)
3.20 March 1, 2050 550 550
First mortgage bonds (a)
2.70 Jan. 15, 2051 375 -
Unamortized discount (30) (24)
Unamortized debt issuance cost (46) (41)
Current maturities - (400)
Total long-term debt $ 5,724 $ 4,985
(a)2020 financing.
(b)2019 financing.
SPS
Financing Instrument Interest Rate Maturity Date 2020 2019
First mortgage bonds 3.30 % June 15, 2024 $ 150 $ 150
First mortgage bonds 3.30 June 15, 2024 200 200
Unsecured senior notes 6.00 Oct. 1, 2033 100 100
Unsecured senior notes 6.00 Oct. 1, 2036 250 250
First mortgage bonds 4.50 Aug. 15, 2041 200 200
First mortgage bonds 4.50 Aug. 15, 2041 100 100
First mortgage bonds 4.50 Aug. 15, 2041 100 100
First mortgage bonds 3.40 Aug. 15, 2046 300 300
First mortgage bonds 3.70 Aug. 15, 2047 450 450
First mortgage bonds 4.40 Nov. 15, 2048 300 300
First mortgage bonds (b)
3.75 June 15, 2049 300 300
First mortgage bonds (a)
3.15 May 1, 2050 350 -
Unamortized discount (10) (7)
Unamortized debt issuance cost (26) (23)
Total long-term debt $ 2,764 $ 2,420
(a)2020 financing.
(b)2019 financing.
Other Subsidiaries
Financing Instrument Interest Rate Maturity Date 2020 2019
Various Eloigne affordable housing project notes 0.00% - 6.90% 2021 - 2054 $ 27 $ 28
Current maturities (2) (2)
Total long-term debt $ 25 $ 26
Maturities of long-term debt:
(Millions of Dollars)
2021 $ 421
2022 601
2023 1,151
2024 552
2025 1,102
Deferred Financing Costs - Deferred financing costs of approximately $167 million and $148 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt as of Dec. 31, 2020 and 2019, respectively.
Forward Equity Agreements - In November 2018, Xcel Energy Inc. entered into forward equity agreements for a $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.
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.
Capital Stock - Preferred stock authorized/outstanding:
Preferred Stock Authorized (Shares) Par Value of Preferred Stock Preferred Stock Outstanding (Shares) 2020 and 2019
Xcel Energy Inc. 7,000,000 $ 100 -
PSCo 10,000,000 0.01 -
SPS 10,000,000 1.00 -
Xcel Energy Inc. had the following common stock authorized/outstanding:
Common Stock Authorized (Shares) Par Value of Common Stock Common Stock Outstanding (Shares) as of Dec. 31, 2020 Common Stock Outstanding (Shares) as of Dec. 31, 2019
1,000,000,000 $ 2.50 537,438,394 524,539,000
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:
Equity to Total
Capitalization Ratio
Required Range Equity to Total Capitalization Ratio Actual
Low High 2020
NSP-Minnesota 47.1 % 57.5 % 52.7 %
NSP-Wisconsin 52.5 N/A 52.8
SPS (a)
45.0 55.0 54.4
(a) Excludes short-term debt.
(Amounts in Millions) Unrestricted Retained Earnings Total Capitalization Limit 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
(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:
(Millions of Dollars) Long-Term Debt Short-Term Debt
NSP-Minnesota 52.93% of total capitalization (a)
$ 1,980 (a)
NSP-Wisconsin $ 250 150
SPS - (b)
PSCo 1,450 800
(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) SPS filed for additional long-term debt authorization in December 2020.
6. Revenues
Revenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy’s operating revenues consisted of the following:
Year Ended Dec. 31, 2020
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 3,066 $ 975 $ 42 $ 4,083
C&I 4,596 462 27 5,085
Other 125 - 6 131
Total retail 7,787 1,437 75 9,299
Wholesale 759 - - 759
Transmission 579 - - 579
Other 73 137 - 210
Total revenue from contracts with customers 9,198 1,574 75 10,847
Alternative revenue and other 604 62 13 679
Total revenues $ 9,802 $ 1,636 $ 88 $ 11,526
Year Ended Dec. 31, 2019
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 2,877 $ 1,127 $ 41 $ 4,045
C&I 4,844 567 29 5,440
Other 130 - 4 134
Total retail 7,851 1,694 74 9,619
Wholesale 737 - - 737
Transmission 507 - - 507
Other 49 120 - 169
Total revenue from contracts with customers 9,144 1,814 74 11,032
Alternative revenue and other 431 54 12 497
Total revenues $ 9,575 $ 1,868 $ 86 $ 11,529
Year Ended Dec. 31, 2018
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 2,919 $ 988 $ 38 $ 3,945
C&I 4,874 524 25 5,423
Other 134 - 6 140
Total retail 7,927 1,512 69 9,508
Wholesale 791 - - 791
Transmission 523 - - 523
Other 98 100 - 198
Total revenue from contracts with customers 9,339 1,612 69 11,020
Alternative revenue and other 380 127 10 517
Total revenues $ 9,719 $ 1,739 $ 79 $ 11,537
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:
Tax Year(s) Expiration
2014 - 2016 July 2021
Additionally, the statute of limitations related to the federal tax loss carryback claim referenced above has been extended. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.
In 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy file a protest with the IRS. In April 2020, Xcel Energy and Appeals reached an agreement and no material adjustments were required.
In 2018, the IRS began an audit of tax years 2014 - 2016. In July 2020, Xcel Energy and the IRS reached an agreement and the related benefit was recognized.
State Audits - 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, Xcel Energy’s earliest open tax years (subject to examination by state taxing authorities in its major operating jurisdictions) were as follows:
State Year
Colorado 2009
Minnesota 2009
Texas 2012
Wisconsin 2014
•In 2018, Wisconsin began an audit of tax years 2014 - 2016. As of Dec. 31, 2020, no material adjustments have been proposed.
•In July 2020, Minnesota began a review of the 2015 - 2018 Research and Experimentation Credits. As of Dec. 31, 2020, no material adjustments have been proposed.
•Xcel Energy had no other state income tax audits in progress for its major operating jurisdictions as of Dec. 31, 2020.
Unrecognized Tax Benefits - Unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain, but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment to the taxing authority to an earlier period.
Unrecognized tax benefits - permanent vs. temporary:
(Millions of Dollars) Dec. 31, 2020 Dec. 31, 2019
Unrecognized tax benefit - Permanent tax positions $ 41 $ 35
Unrecognized tax benefit - Temporary tax positions 11 9
Total unrecognized tax benefit $ 52 $ 44
Changes in unrecognized tax benefits:
(Millions of Dollars) 2020 2019 2018
Balance at Jan. 1 $ 44 $ 37 $ 39
Additions based on tax positions related to the current year 9 10 9
Reductions based on tax positions related to the current year (2) (4) (4)
Additions for tax positions of prior years 35 1 2
Reductions for tax positions of prior years (34) - (4)
Settlements with taxing authorities - - (5)
Balance at Dec. 31 $ 52 $ 44 $ 37
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
(Millions of Dollars) Dec. 31, 2020 Dec. 31, 2019
NOL and tax credit carryforwards $ (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.
As the IRS audit resumes and state audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $27 million in the next 12 months.
Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.
Interest payable related to unrecognized tax benefits:
(Millions of Dollars) 2020 2019 2018
Payable for interest related to unrecognized tax benefits at Jan. 1 $ - $ - $ -
Interest expense related to unrecognized tax benefits (3) - -
Payable for interest related to unrecognized tax benefits at Dec. 31 $ (3) $ - $ -
No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2020, 2019 or 2018.
Other Income Tax Matters - NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31:
(Millions of Dollars) 2020 2019
Federal tax credit carryforwards $ 791 $ 639
State NOL carryforwards 839 937
Valuation allowances for state NOL carryforwards (4) (19)
State tax credit carryforwards, net of federal detriment (a)
89 89
Valuation allowances for state credit carryforwards, net of federal benefit (b)
(64) (66)
(a)State tax credit carryforwards are net of federal detriment of $24 million as of Dec. 31, 2020 and 2019.
(b)Valuation allowances for state tax credit carryforwards were net of federal benefit of $17 million as of Dec. 31, 2020 and 2019.
Federal carryforward periods expire between 2031 and 2040 and state carryforward periods expire starting 2021.
Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.
Effective income tax rate for years ended Dec. 31:
2020 2019 2018
Federal statutory rate 21.0 % 21.0 % 21.0 %
State income tax on pretax income, net of federal tax effect 4.9 4.9 5.0
Increases (decreases) in tax from:
Wind PTCs (15.7) (9.4) (5.2)
Plant regulatory differences (a)
(7.6) (5.8) (6.2)
Other tax credits, net NOL & tax credit allowances (1.2) (1.7) (1.7)
NOL Carryback (0.9) - -
Change in unrecognized tax benefits 0.5 0.5 0.4
Other, net (1.4) (1.0) (0.7)
Effective income tax rate (0.4) % 8.5 % 12.6 %
(a)Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions and additional prepaid pension asset amortization.
Components of income tax expense for years ended Dec. 31:
(Millions of Dollars) 2020 2019 2018
Current federal tax benefit $ (13) $ (16) $ (34)
Current state tax expense 2 4 8
Current change in unrecognized tax expense (benefit) 18 2 (6)
Deferred federal tax (benefit) expense (89) 55 122
Deferred state tax expense 91 83 85
Deferred change in unrecognized tax (benefit) expense (10) 5 11
Deferred ITCs (5) (5) (5)
Total income tax (benefit) expense $ (6) $ 128 $ 181
Components of deferred income tax expense as of Dec. 31:
(Millions of Dollars) 2020 2019 2018
Deferred tax expense excluding items below $ 237 $ 344 $ 320
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (247) (206) (102)
Tax expense allocated to other comprehensive income, adoption of ASC Topic 326, adoption of ASU No. 2018-02, and other 2 5 -
Deferred tax (benefit) expense $ (8) $ 143 $ 218
Components of net deferred tax liability as of Dec. 31:
(Millions of Dollars) 2020 2019
Deferred tax liabilities:
Differences between book and tax bases of property $ 5,810 $ 5,474
Operating lease assets 400 449
Regulatory assets 603 598
Pension expense 176 173
Other 74 70
Total deferred tax liabilities $ 7,063 $ 6,764
Deferred tax assets:
Regulatory liabilities $ 806 $ 847
Operating lease liabilities 400 449
Tax credit carryforward 880 727
NOL carryforward 37 38
NOL and tax credit valuation allowances (64) (67)
Other employee benefits 141 128
Deferred ITCs 13 14
Rate refund 16 26
Other 88 93
Total deferred tax assets $ 2,317 $ 2,255
Net deferred tax liability $ 4,746 $ 4,509
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) 2020 2019 2018
Granted shares 1 13 18
Grant date fair value $ 70.26 $ 53.46 $ 44.68
Changes in nonvested restricted stock:
(Shares in Thousands) Shares Weighted Average
Grant Date Fair Value
Nonvested restricted stock at Jan. 1, 2020 31 $ 50.15
Granted 1 70.26
Forfeited (3) 44.68
Vested (15) 46.41
Dividend equivalents 1 66.96
Nonvested restricted stock at Dec. 31, 2020 15 56.68
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, 0.3 million, and 0.3 million time-based equity shares subject only to service conditions were granted annually in 2020, 2019 and 2018, respectively.
The performance conditions for a portion of the awards granted from 2018 to 2020 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 zero to 200 percent depending on achievement.
Equity award units granted to employees (excluding restricted stock):
(Units in Thousands) 2020 2019 2018
Granted units 411 483 500
Weighted average grant date fair value $ 62.92 $ 49.67 $ 47.60
Equity awards vested:
(Units in Thousands, Fair Value in Millions) 2020 2019 2018
Vested Units 442 464 475
Total Fair Value $ 29 $ 29 $ 23
Changes in the nonvested portion of equity award units:
(Units in Thousands) Units Weighted Average
Grant Date Fair Value
Nonvested Units at Jan. 1, 2020 880 $ 48.20
Granted 411 62.92
Forfeited (101) 53.87
Vested (442) 47.63
Dividend equivalents 32 51.56
Nonvested Units at Dec. 31, 2020 780 55.68
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 one 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) 2020 2019 2018
Granted units 33 29 36
Weighted average grant date fair value $ 61.61 $ 58.44 $ 45.44
Changes in stock equivalent units:
(Units in Thousands) Units Weighted Average
Grant Date Fair Value
Stock equivalent units at Jan. 1, 2020 725 $ 32.72
Granted 33 61.61
Units distributed (146) 28.16
Dividend equivalents 18 67.44
Stock equivalent units at Dec. 31, 2020 630 36.28
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 zero to 200%.
TSR liability awards granted:
(In Thousands) 2020 2019 2018
Awards granted 212 225 239
TSR liability awards settled:
(Units In Thousands, Settlement Amount in Millions) 2020 2019 2018
Awards settled 476 466 482
Settlement amount (cash, common stock and deferred amounts) $ 33 $ 25 $ 22
TSR liability awards of $27 million were settled in cash in 2020.
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, 0.3 million, and 0.3 million of equity award units were granted in 2020, 2019, and 2018, 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) 2020 2019 2018
Compensation cost for share-based awards (a)
$ 73 $ 58 $ 45
Tax benefit recognized in income 19 15 12
(a)Compensation costs for share-based payments are included in O&M expense.
There was approximately $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 1.7 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. 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. 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.
Diluted common shares outstanding included common stock equivalents of 1.1 million, 1.3 million and 0.5 million shares for 2020, 2019 and 2018, respectively.
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.
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 a 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 and $706 million as of Dec. 31, 2020 and 2019, respectively, and unrealized losses were $5 million and $6 million as of Dec. 31, 2020 and 2019, respectively.
Non-derivative instruments with recurring fair value measurements:
Dec. 31, 2020
Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total
Nuclear decommissioning fund (a)
Cash equivalents $ 40 $ 40 $ - $ - $ - $ 40
Commingled funds 787 - - - 1,041 1,041
Debt securities 528 - 572 13 - 585
Equity securities 446 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) Cost Level 1 Level 2 Level 3 NAV Total
Nuclear decommissioning fund (a)
Cash equivalents $ 33 $ 33 $ - $ - $ - $ 33
Commingled funds 733 - - - 935 935
Debt securities 489 - 495 13 - 508
Equity securities 485 962 2 - - 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, 2020 and 2019, 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:
Final Contractual Maturity
(Millions of Dollars) Due in 1 year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 years Total
Debt securities $ 1 $ 116 $ 211 $ 257 $ 585
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, 2020
Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 Total
Rabbi Trusts (a)
Cash equivalents $ 32 $ 32 $ - $ - $ 32
Mutual funds 60 70 - - 70
Total $ 92 $ 102 $ - $ - $ 102
(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
Dec. 31, 2019
Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 Total
Rabbi Trusts (a)
Cash equivalents $ 17 $ 17 $ - $ - $ 17
Mutual funds 57 65 - - 65
Total $ 74 $ 82 $ - $ - $ 82
(a) 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, accumulated other comprehensive loss related to settled interest rate derivatives included $6 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, Xcel Energy had no 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 as a regulatory asset or liability, if applicable, is based on approved regulatory recovery mechanisms.
As of Dec. 31, 2020, Xcel Energy had no 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)
Dec. 31, 2020 Dec. 31, 2019
MWh of electricity 87 95
MMBtu of natural gas 175 110
(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.
As of Dec. 31, 2020, six of Xcel Energy’s 10 most significant counterparties for these activities, comprising $130 million or 54% of this credit exposure, had investment grade credit ratings from S&P, Moody’s or Fitch Ratings. Three of the 10 most significant counterparties, comprising $32 million or 13% 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. One of these significant counterparties, comprising $17 million or 7% of this credit exposure, had credit quality less than investment grade, based on internal analysis. Eight 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) 2020 2019 2018
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (80) $ (60) $ (58)
After-tax net unrealized losses related to derivatives accounted for as hedges (10) (23) (5)
After-tax net realized losses on derivative transactions reclassified into earnings 5 3 3
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (85) $ (80) $ (60)
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) $ -
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)
Year Ended Dec. 31, 2018
Interest rate $ (7) $ -
Total $ (7) $ -
Other derivative instruments
Electric commodity $ - $ 1
Natural gas commodity - 10
Total $ - $ 11
Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from:
Pre-Tax Gains
(Losses) Recognized
During the Period in Income
(Millions of Dollars) Accumulated
Other
Comprehensive Loss Regulatory
Assets and (Liabilities)
Year Ended Dec. 31, 2020
Derivatives designated as cash flow hedges
Interest rate $ 7 (a)
$ - $ -
Total $ 7 $ - $ -
Other derivative instruments
Commodity trading $ - $ - $ (1) (b)
Electric commodity - (3) (c)
-
Natural gas commodity - 10 (d)
(13) (d)
Total $ - $ 7 $ (14)
Year Ended Dec. 31, 2019
Derivatives designated as cash flow hedges
Interest rate $ 4 (a)
$ - $ -
Total $ 4 $ - $ -
Other derivative instruments
Commodity trading $ - $ - $ 2 (b)
Electric commodity - (5) (c)
-
Natural gas commodity - 2 (d)
(7) (d)
Total $ - $ (3) $ (5)
Year Ended Dec. 31, 2018
Derivatives designated as cash flow hedges
Interest rate $ 4 (a)
$ - $ -
Total $ 4 $ - $ -
Other derivative instruments
Commodity trading $ - $ - $ 14 (b)
Electric commodity - (1) (c)
-
Natural gas commodity - (6) (d)
(4) (d)
Total $ - $ (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 no settlement losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, 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 were recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.
Xcel Energy had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2020, 2019 and 2018.
Credit Related Contingent Features - Contract provisions for derivative instruments that 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, 2020 and 2019, there were $4 million and $7 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, 2020, there were approximately $60 million of derivative instruments in a liability position with such underlying contract provisions.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. 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 no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2020 and 2019.
Recurring Fair Value Measurements - Derivative assets and liabilities measured at fair value on a recurring basis were as follows:
Dec. 31, 2020 Dec. 31, 2019
Fair Value Fair Value Total Netting (a)
Total Fair Value Fair Value Total Netting (a)
Total
(Millions of Dollars) Level 1 Level 2 Level 3 Level 1 Level 2 Level 3
Current derivative assets
Other derivative instruments:
Commodity trading $ 2 $ 67 $ 1 $ 70 $ (52) $ 18 $ 3 $ 51 $ 24 $ 78 $ (52) $ 26
Electric commodity - - 20 20 (1) 19 - - 21 21 (1) 20
Natural gas commodity - 9 - 9 - 9 - 6 - 6 - 6
Total current derivative assets $ 2 $ 76 $ 21 $ 99 $ (53) 46 $ 3 $ 57 $ 45 $ 105 $ (53) 52
PPAs (b)
3 3
Current derivative instruments $ 49 $ 55
Noncurrent derivative assets
Other derivative instruments:
Commodity trading $ 8 $ 66 $ 8 $ 82 $ (62) $ 20 $ 9 $ 38 $ 7 $ 54 $ (45) $ 9
Total noncurrent derivative assets $ 8 $ 66 $ 8 $ 82 $ (62) 20 $ 9 $ 38 $ 7 $ 54 $ (45) 9
PPAs (b)
10 13
Noncurrent derivative instruments $ 30 $ 22
Dec. 31, 2020 Dec. 31, 2019
Fair Value Fair Value Total Netting (a)
Total Fair Value Fair Value Total Netting (a)
Total
(Millions of Dollars) Level 1 Level 2 Level 3 Level 1 Level 2 Level 3
Current derivative liabilities
Other derivative instruments:
Commodity trading $ 4 $ 64 $ 17 $ 85 $ (58) $ 27 $ 4 $ 59 $ 15 $ 78 $ (63) $ 15
Electric commodity - - 1 1 (1) - - - 1 1 (1) -
Natural gas commodity - 9 - 9 - 9 - 5 - 5 - 5
Total current derivative liabilities $ 4 $ 73 $ 18 $ 95 $ (59) 36 $ 4 $ 64 $ 16 $ 84 $ (64) 20
PPAs (b)
17 18
Current derivative instruments $ 53 $ 38
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading $ 3 $ 58 $ 60 $ 121 $ (47) $ 74 $ 2 $ 79 $ 32 $ 113 $ (13) $ 100
Total noncurrent derivative liabilities $ 3 $ 58 $ 60 $ 121 $ (47) 74 $ 2 $ 79 $ 32 $ 113 $ (13) 100
PPAs (b)
57 75
Noncurrent derivative instruments $ 131 $ 175
(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, 2020 and 2019. At Dec. 31, 2020 and 2019, derivative assets and liabilities include $15 million and $32 million of obligations to return cash collateral, respectively. At Dec. 31, 2020 and 2019, derivative assets and liabilities include rights to reclaim cash collateral of $6 million and $11 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.
Changes in Level 3 commodity derivatives:
Year Ended Dec. 31
(Millions of Dollars) 2020 2019 2018
Balance at Jan. 1 $ 4 $ 29 $ 35
Purchases 51 44 59
Settlements (73) (64) (59)
Net transactions recorded during the period:
Losses recognized in earnings (a)
(39) (8) (1)
Net gains (losses) recognized as regulatory assets and liabilities 8 3 (5)
Balance at Dec. 31 $ (49) $ 4 $ 29
(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 no transfers of amounts between levels for derivative instruments for Dec. 31, 2020, 2019 and 2018.
Fair Value of Long-Term Debt
As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value:
2020 2019
(Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value
Long-term debt, including current portion $ 20,066 $ 24,412 $ 18,109 $ 20,227
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, 2020 and 2019, 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 1.89, 2.82 and 3.62 percent in 2020, 2019, and 2018, respectively. Some employees may participate under legacy formulas such as the traditional final average pay or pension equity. Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs subject to the limitations of applicable employee benefit and tax laws.
In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives who participated in the plan in 2008, when the SERP was closed to new participants.
The nonqualified pension plan provides benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows.
Obligations of the SERP and nonqualified plan as of Dec. 31, 2020 and 2019 were $43 million and $39 million, respectively. Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $6 million in 2020 and $4 million in 2019.
Xcel Energy bases the investment-return assumption on expected long-term performance for each of the asset classes in its pension and postretirement health care portfolios. For pension assets, Xcel Energy considers the historical returns achieved by its asset portfolio over the past 20 years or longer period, as well as long-term projected return levels.
Pension cost determination assumes a forecasted mix of investment types over the long-term.
•Investment returns in 2020 were above the assumed level of 6.87%.
•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, 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 result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios.
Plan Assets
For each of the fair value hierarchy levels, Xcel Energy’s pension plan assets measured at fair value:
Dec. 31, 2020 (a)
Dec. 31, 2019 (a)
(Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total
Cash equivalents $ 209 $ - $ - $ - $ 209 $ 145 $ - $ - $ - $ 145
Commingled funds 1,462 - - 1,115 2,577 1,408 - - 1,031 2,439
Debt securities - 714 4 - 718 - 645 4 - 649
Equity securities 77 - - - 77 86 - - - 86
Other 13 5 - - 18 (120) 5 - (20) (135)
Total $ 1,761 $ 719 $ 4 $ 1,115 $ 3,599 $ 1,519 $ 650 $ 4 $ 1,011 $ 3,184
(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)
(Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total
Cash equivalents $ 27 $ - $ - $ - $ 27 $ 23 $ - $ - $ - $ 23
Insurance contracts - 50 - - 50 - 51 - - 51
Commingled funds 72 - - 69 141 69 - - 76 145
Debt securities - 232 - - 232 - 228 1 - 229
Other - 2 - - 2 - 1 - - 1
Total $ 99 $ 284 $ - $ 69 $ 452 $ 92 $ 280 $ 1 $ 76 $ 449
(a)See Note 10 for further information on fair value measurement inputs and methods.
No assets were transferred in or out of Level 3 for 2020. Immaterial assets were transferred in or out of Level 3 for 2019.
Funded Status - Benefit obligations for both pension and postretirement plans increased from Dec. 31, 2019 to Dec. 31, 2020, due primarily to decreases in discount rates used in actuarial valuations. Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for Xcel Energy are as follows:
Pension Benefits Postretirement Benefits
(Millions of Dollars) 2020 2019 2020 2019
Change in Benefit Obligation:
Obligation at Jan. 1 $ 3,701 $ 3,477 $ 547 $ 542
Service cost 95 86 1 2
Interest cost 125 145 18 22
Plan amendments - 1 - -
Actuarial loss 328 273 50 19
Plan participants’ contributions - - 8 8
Medicare subsidy reimbursements - - 1 1
Benefit payments (a)
(285) (281) (51) (47)
Obligation at Dec. 31 $ 3,964 $ 3,701 $ 574 $ 547
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1 $ 3,184 $ 2,742 $ 449 $ 417
Actual return on plan assets 550 568 35 56
Employer contributions 150 155 11 15
Plan participants’ contributions - - 8 8
Benefit payments (285) (281) (51) (47)
Fair value of plan assets at Dec. 31 $ 3,599 $ 3,184 $ 452 $ 449
Funded status of plans at Dec. 31 $ (365) $ (517) $ (122) $ (98)
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Noncurrent assets $ - $ - $ 6 $ 21
Current liabilities - - (7) (6)
Noncurrent liabilities (365) (517) (121) (113)
Net amounts recognized $ (365) $ (517) $ (122) $ (98)
(a)Includes approximately $0 million in 2020 and $20 million in 2019 of lump-sum benefit payments used in the determination of a settlement charge.
Pension Benefits Postretirement Benefits
Significant Assumptions Used to Measure Benefit Obligations: 2020 2019 2020 2019
Discount rate for year-end valuation 2.71 % 3.49 % 2.65 % 3.47 %
Expected average long-term increase in compensation level 3.75 3.75 N/A N/A
Mortality table PRI-2012 PRI-2012 PRI-2012 PRI-2012
Health care costs trend rate - initial: Pre-65 N/A N/A 5.50 % 6.00 %
Health care costs trend rate - initial: Post-65 N/A N/A 5.00 % 5.10 %
Ultimate trend assumption - initial: Pre-65 N/A N/A 4.50 % 4.50 %
Ultimate trend assumption - initial: Post-65 N/A N/A 4.50 % 4.50 %
Years until ultimate trend is reached N/A N/A 5 3
Accumulated benefit obligation for the pension plan was $3,693 million and $3,465 million as of Dec. 31, 2020 and 2019, respectively.
Net Periodic Benefit Cost (Credit) - Net periodic benefit cost (credit), other than the service cost component, is included in other income 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 Benefits Postretirement Benefits
(Millions of Dollars) 2020 2019 2018 2020 2019 2018
Service cost $ 95 $ 86 $ 94 $ 1 $ 2 $ 2
Interest cost 125 145 133 18 22 22
Expected return on plan assets (208) (203) (209) (19) (21) (26)
Amortization of prior service credit (4) (5) (5) (8) (10) (11)
Amortization of net loss 100 87 111 4 5 8
Settlement charge (a)
- 6 91 - - -
Net periodic pension cost (credit) 108 116 215 (4) (2) (5)
Effects of regulation 9 (1) (75) 3 1 2
Net benefit cost (credit) recognized for financial reporting $ 117 $ 115 $ 140 $ (1) $ (1) $ (3)
Significant Assumptions Used to Measure Costs:
Discount rate 3.49 % 4.31 % 3.63 % 3.47 % 4.32 % 3.62 %
Expected average long-term increase in compensation level 3.75 3.75 3.75 - - -
Expected average long-term rate of return on assets 6.87 6.87 6.87 4.50 4.50 5.30
(a)A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2019 and 2018, as a result of lump-sum distributions during each plan year, Xcel Energy recorded a total pension settlement charge of $6 million and $91 million, respectively, the majority of which was not recognized due to the effects of regulation. A total of $1 million and $11 million was recorded in the consolidated statements of income in 2019 and 2018, respectively. There were no settlement charges recorded for the qualified pension plans in 2020.
Pension Benefits Postretirement Benefits
(Millions of Dollars) 2020 2019 2020 2019
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss $ 1,333 $ 1,447 $ 126 $ 95
Prior service credit (11) (15) (15) (23)
Total $ 1,322 $ 1,432 $ 111 $ 72
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets $ 82 $ 78 $ - $ -
Noncurrent regulatory assets 1,181 1,285 125 80
Current regulatory liabilities - - (1) (1)
Noncurrent regulatory liabilities - - (18) (12)
Deferred income taxes 15 18 1 1
Net-of-tax accumulated other comprehensive income 44 51 4 4
Total $ 1,322 $ 1,432 $ 111 $ 72
Measurement date Dec. 31, 2020 Dec. 31, 2019 Dec. 31, 2020 Dec. 31, 2019
Cash Flows - Funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the requirements of income tax and other pension-related regulations. Required contributions were made in 2018 - 2021 to meet minimum funding requirements.
Voluntary and required pension funding contributions:
•$125 million in January 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 million during 2021.
•$11 million during 2020.
•$15 million during 2019.
•$11 million during 2018.
Targeted asset allocations:
Pension Benefits Postretirement Benefits
2020 2019 2020 2019
Domestic and international equity securities 35 % 37 % 15 % 15 %
Long-duration fixed income securities 35 30 - -
Short-to-intermediate fixed income securities 13 14 72 72
Alternative investments 15 17 9 9
Cash 2 2 4 4
Total 100 % 100 % 100 % 100 %
The asset allocations above reflect target allocations approved in the calendar year to take effect in the subsequent year.
Plan Amendments - In 2018, the PSCo postretirement plan was amended to add the 5% cash balance formula.
In 2019, the Pension Protection Act measurement concept was extended beyond 2019 for NSP bargaining terminations and retirements to Dec. 31, 2022.
There were no significant plan amendments made in 2020 which affected the postretirement benefit obligation.
Projected Benefit Payments
Xcel Energy’s projected benefit payments:
(Millions of Dollars) Projected
Pension Benefit
Payments Gross Projected
Postretirement
Health Care
Benefit Payments Expected
Medicare Part D
Subsidies Net Projected
Postretirement
Health Care
Benefit Payments
2021 $ 304 $ 44 $ 2 $ 42
2022 282 43 2 41
2023 274 42 2 40
2024 265 41 2 39
2025 259 39 2 37
2026-2030 1,193 175 12 163
Defined Contribution Plans
Xcel Energy maintains 401(k) and other defined contribution plans that cover most employees. Total expense to these plans was approximately $42 million in 2020, $39 million in 2019 and $38 million in 2018.
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, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.
Gas Trading Litigation - e prime is a wholly owned subsidiary of Xcel Energy. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Multiple lawsuits involving multiple plaintiffs seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada.
Two cases remain active which include an MDL matter consisting of a Colorado purported class (Breckenridge) and a Wisconsin purported class (Arandell Corp.).
Breckenridge/Colorado - In February 2019, the MDL panel remanded Breckenridge back to the U.S. District Court in Colorado. In December 2020, a settlement in principle was reached for approximately $3 million. The parties have sought and are awaiting court approval of settlement.
Arandell Corp. - In February 2019, the case was remanded back to the U.S. District Court in Wisconsin.
Xcel Energy has concluded that a loss is remote for the remaining lawsuit.
Rate Matters and Other
MEC Acquisition and Disposition - In January 2020, Xcel Energy, Inc. purchased MEC, a 760 MW natural gas combined cycle facility, for approximately $650 million from Southern Power Company.
In July 2020, Xcel Energy sold MEC to Southwest Generation for $684 million. The gain on sale of approximately $20 million, which was offset by charitable giving, including COVID-19 relief efforts, had no material impact on earnings.
Sherco - In 2018, NSP-Minnesota and SMMPA (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 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 General and DOC filed comments recommending that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the FCA. On Jan. 27, 2021, NSP-Minnesota 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 for Westmoreland Coal Company filed an arbitration demand against NSP-Minnesota, SMMPA and Western Fuels Association, seeking recovery of alleged 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 a final resolution will occur, but it is unlikely an arbitration hearing will take place before the fourth quarter 2021. 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.
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 for the first MISO complaint period and upheld its decision to deny refunds for the second complaint period. Each 10 basis point reduction in the allowed base ROE for the first complaint and second complaint would reduce net income by $2 million and $1 million, respectively.
Various parties have filed petitions for review of Opinion Nos. 569, 569-A and 569-B at the D.C. Circuit. These appeals remain pending.
SPP OATT Upgrade Costs - Under the SPP OATT, costs of transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. 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 both appeals in support of the FERC. Any refunds received by SPS are expected to be given back to SPS customers through future rates.
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. This appeal is stayed pending the outcome of the separate appeal initiated in 2020 by Oklahoma Gas & Electric and SPP.
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.
Contract Termination - SPS and Lubbock Power & Light are parties to a 25-year, 170 MW partial requirements contract. In October 2020, Lubbock Power & Light initiated discussions concerning the interpretation of contractual terms related to early termination and default. If the parties are unable to reach resolution, the contract calls for the matter to proceed to arbitration. The amount of any damages depends on multiple factors and is currently unknown.
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.
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 other MGP, landfill or other disposal sites across its service territories.
Xcel Energy has recognized its best estimate of costs/liabilities that will result from final resolution of these issues, however, the outcome and timing is unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.
Environmental Requirements - Water and Waste
Coal Ash Regulation - 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 nine 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, no results above the groundwater protection standards in the rule were identified. In PSCo, statistically significant increases above background concentrations were detected at four locations. Subsequently, assessment monitoring samples were collected at these locations and, based on the results, PSCo is evaluating options for corrective action at two locations, one of which indicates potential offsite impacts to groundwater. Until PSCo completes its assessments, it is uncertain what impact, if any, there will be on the operations, financial condition or cash flows.
In August 2020, the EPA published its final rule to implement a cease receipt and initiate a closure date of April 2021 for all CCR impoundments affected by the August 2018 D.C. Circuit ruling. The D.C. Circuit concluded that the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the storage or disposal of coal ash. This final rule required Xcel Energy to expedite closure plans for two 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. 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 build an alternative bottom ash collection system that will be constructed and in service in advance of the April 11, 2021 deadline. Once the alternative bottom ash system is operational, the existing impoundment will initiate closure per the CCR Rule.
Closure costs for existing impoundments are included in the calculation of the ARO.
Federal CWA WOTUS Rule - In April 2020, the EPA and U.S. Army Corps of Engineers (“Agencies”) replaced the 2015 WOTUS rule and narrowed the definition of WOTUS (“2020 WOTUS Rule”). The new definition simplifies the process whether waters are subject to CWA jurisdiction and streamlines the permitting process. In June 2020, the U.S. District Court for the District of Colorado stayed the effective date of the 2020 WOTUS Rule in Colorado, where the pre-2015 definition of WOTUS is now in effect. Regardless of which definition is applicable in the states in which we operate, 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 Energy does not anticipate that compliance costs will be material.
Federal CWA Section 316(b) - The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing impingement and entrainment of aquatic species. Xcel Energy estimates the likely cost for complying with impingement and entrainment requirements is approximately $41 million, to be incurred between 2021 and 2028. Xcel Energy believes six NSP-Minnesota plants and two 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 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 Columbia 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, with compliance 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 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 an 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.
Aggregate fair value of NSP-Minnesota’s legally restricted assets, for funding future nuclear decommissioning was $2.8 billion and $2.4 billion for 2020 and 2019, respectively.
Xcel Energy’s AROs were as follows:
(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 production 202 - (5) 9 58 264
Wind 146 149 (3) 8 60 360
Distribution 44 - - 2 - 46
Natural gas
Transmission and distribution 236 - - 10 6 252
Miscellaneous 3 - - - - 3
Common
Miscellaneous 1 - - - - 1
Non-utility
Miscellaneous 1 - - - - 1
Total liability $ 2,701 $ 149 $ (8) $ 134 $ (92) $ 2,884
(a)Amounts incurred related to the wind farms placed in service in 2020 for NSP-Minnesota (Blazing Star 1, Crowned Ridge 2, Jeffers and Community Wind North), PSCo (Cheyenne Ridge) and SPS (Sagamore).
(b)Amounts settled primarily related to closure of certain ash containment facilities, removal of wind facilities and asbestos abatement projects.
(c)In 2020, AROs were revised for changes in timing and estimates of cash flows. Revisions in the nuclear AROs were driven by reductions in spent fuel cooling time requirements in the nuclear triennial filing coupled with decreasing interest rates. Changes in wind AROs were driven by new dismantling studies. Revisions in steam, hydro and other production AROs were primarily related to changes in cost estimates for remediation of ash containment facilities.
(Millions
of Dollars) Jan. 1, 2019 Amounts Incurred (a)
Amounts
Settled
(b)
Accretion Cash Flow Revisions (c)
Dec. 31, 2019
Electric
Nuclear $ 1,968 $ - $ - $ 100 $ - $ 2,068
Steam, hydro and other production 177 - (5) 8 22 202
Wind 119 26 - 7 (6) 146
Distribution 42 - - 2 - 44
Miscellaneous 7 - - - (7) -
Natural gas
Transmission and distribution 249 - - 11 (24) 236
Miscellaneous 4 - - - (1) 3
Common
Miscellaneous 1 - - - - 1
Non-utility
Miscellaneous 1 - - - - 1
Total liability $ 2,568 $ 26 $ (5) $ 128 $ (16) $ 2,701
(a)Amounts incurred related to the wind farms placed in service in 2019 for NSP-Minnesota (Lake Benton and Foxtail) and SPS (Hale).
(b)Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities.
(c)In 2019, AROs were revised for changes in timing and estimates of cash flows. 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. 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 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 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 three 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 two 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 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.
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. 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.
Future decommissioning costs of nuclear facilities are estimated through triennial periodic studies that assess the costs and timing of planned nuclear decommissioning activities for each unit.
Obligations for decommissioning are expected to be funded 100% by the external decommissioning trust fund. The cost study assumes the external decommissioning fund will earn an after-tax return between 5.23% and 6.30%. Realized and unrealized gains on fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Decommissioning costs are quantified in 2014 dollars. Escalation rates are 4.36% for plant removal activities and 3.36% for fuel management and site restoration activities.
NSP-Minnesota had $2.8 billion of assets held in external decommissioning trusts at Dec. 31, 2020. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation. Xcel Energy believes future decommissioning costs will continue to be recovered in customer rates. The following amounts were prepared on a regulatory basis and not directly recorded in the financial statements as an ARO.
Regulatory Basis
(Millions of Dollars) 2020 2019
Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars) $ 3,012 $ 3,012
Effect of escalating costs 844 688
Estimated decommissioning cost obligation (in current dollars) 3,856 3,700
Effect of escalating costs to payment date 7,349 7,505
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)
Discounted decommissioning cost obligation $ 7,024 $ 5,643
Assets held in external decommissioning trust $ 2,777 $ 2,440
Underfunding of external decommissioning fund compared to the discounted decommissioning obligation 4,247 3,203
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) 2020 2019
Discounted decommissioning cost obligation - regulated basis $ 7,024 $ 5,643
Differences in discount rate and market risk premium (2,628) (2,295)
O&M costs not included for GAAP (1,734) (1,280)
ARO differences between 2020 and 2014 cost studies (705) -
Nuclear production decommissioning ARO - GAAP $ 1,957 $ 2,068
Decommissioning expenses recognized as a result of regulation:
(Millions of Dollars) 2020 2019 2018
Annual decommissioning recorded as depreciation expense: (a) (b)
$ 20 $ 20 $ 20
(a)Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.
(b)Decommissioning expenses in 2020, 2019 and 2018 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million.
The 2014 nuclear decommissioning filing, approved in 2015, was used for regulatory presentation in 2020, 2019 and 2018. Although there was a nuclear triennial filing in 2017, the MPUC continued to approve the 2014 triennial filing as the regulatory basis in 2020, 2019 and 2018. In December 2020, the MPUC verbally approved NSP-Minnesota to continue using the 2014 filing as the basis for 2021.
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 are 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 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
Other 212 201
Gross operating lease ROU assets 1,862 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.
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, 2020 Dec. 31, 2019
Gas storage facilities $ 201 $ 201
Gas pipeline 21 21
Gross finance lease ROU assets 222 222
Accumulated amortization (90) (83)
Net finance lease ROU assets $ 132 $ 139
Components of lease expense:
(Millions of Dollars) 2020 2019 2018
Operating leases
PPA capacity payments $ 238 $ 221 $ 210
Other operating leases (a)
26 34 38
Total operating lease expense (b)
$ 264 $ 255 $ 248
Finance leases
Amortization of ROU assets $ 7 $ 6 $ 6
Interest expense on lease liability 18 19 19
Total finance lease expense $ 25 $ 25 $ 25
(a)Includes short-term lease expense of $5 million for 2020, 2019 and 2018.
(b)PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.
Commitments under operating and finance leases as of Dec. 31, 2020:
(Millions of Dollars) PPA (a) (b)
Operating
Leases
Other Operating
Leases
Total
Operating
Leases
Finance
Leases (c)
2021 $ 247 $ 26 $ 273 $ 14
2022 228 30 258 12
2023 218 21 239 12
2024 209 21 230 12
2025 189 15 204 10
Thereafter 561 94 655 197
Total minimum obligation 1,652 207 1,859 257
Interest component of obligation (262) (39) (301) (180)
Present value of minimum obligation $ 1,390 168 1,558 77
Less current portion (214) (4)
Noncurrent operating and finance lease liabilities $ 1,344 $ 73
Weighted-average remaining lease term in years 8.5 36.5
(a)Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.
(b)PPA operating leases contractually expire at various dates through 2033.
(c)Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.
PPAs and Fuel Contracts
Non-Lease PPAs - NSP Minnesota, 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 contain minimum energy purchase commitments, and total energy payments on those contracts were $112 million, $102 million 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 $75 million, $86 million 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, the estimated future payments for capacity and energy that the utility subsidiaries of Xcel Energy are obligated to purchase pursuant to these executory contracts, subject to availability, were as follows:
(Millions of Dollars) Capacity Energy (a)
2021 $ 71 $ 156
2022 75 172
2023 77 176
2024 72 181
2025 29 60
Thereafter 24 85
Total $ 348 $ 830
(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 2021 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:
(Millions of Dollars) Coal Nuclear fuel Natural gas supply Natural gas supply and transportation
2021 $ 298 $ 101 $ 453 $ 287
2022 165 87 120 280
2023 58 103 55 217
2024 24 83 3 165
2025 24 121 - 149
Thereafter 52 274 - 708
Total $ 621 $ 769 $ 631 $ 1,806
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.
The utility subsidiaries had approximately 4,062 MW and 3,986 MW of capacity under long-term PPAs at Dec. 31, 2020 and 2019, respectively, with entities that have been determined to be VIEs. Agreements have expiration dates through 2041.
Fuel Contracts - SPS purchases all of its coal requirements for its Harrington and Tolk plants from TUCO Inc. under contracts that will expire in December 2022. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.
SPS has not provided any significant financial support to TUCO, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of fuel procurement costs.
SPS has determined that TUCO is a VIE, however it has concluded that SPS is not the primary beneficiary of TUCO because it does not have the power to direct the activities that most significantly impact TUCO’s economic performance.
Low-Income Housing Limited Partnerships - Eloigne and NSP-Wisconsin have entered into limited partnerships for the construction and operation of affordable rental housing developments which qualify for low-income housing tax credits. Xcel Energy Inc. has determined Eloigne and NSP-Wisconsin’s low-income housing partnerships to be VIEs primarily due to contractual arrangements within each limited partnership that establish sharing of ongoing voting control and profits and losses that does not align with the partners’ proportional equity ownership.
Eloigne and NSP-Wisconsin have the power to direct the activities that most significantly impact these entities’ economic performance. Therefore, Xcel Energy Inc. consolidates these limited partnerships in its consolidated financial statements. Xcel Energy’s risk of loss for these partnerships is limited to its capital contributions, adjusted for any distributions and its share of undistributed profits and losses; no significant additional financial support has been, or is required to be, provided to the limited partnerships by Eloigne or NSP-Wisconsin.
Amounts reflected in Xcel Energy’s consolidated balance sheets for the Eloigne and NSP-Wisconsin low-income housing limited partnerships:
(Millions of Dollars)
Dec. 31, 2020 Dec. 31, 2019
Current assets $ 7 $ 7
Property, plant and equipment, net 38 41
Other noncurrent assets 1 1
Total assets $ 46 $ 49
Current liabilities $ 8 $ 8
Mortgages and other long-term debt payable 25 26
Other noncurrent liabilities 1 -
Total liabilities $ 34 $ 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 $110 million, $101 million and $127 million associated with these contracts in 2020, 2019 and 2018, 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, 2020 and 2019, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements. Guarantees and bond indemnities issued and outstanding for Xcel Energy were $62 million at both Dec. 31, 2020 and 2019.
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:
(Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total
Accumulated other comprehensive loss at Jan. 1 $ (80) $ (61) $ (141)
Other comprehensive loss before reclassifications (net of taxes of $(3) and $(2), respectively)
(10) (5) (15)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $2 and $-, respectively)
5 (a)
- 5
Amortization of net actuarial loss (net of taxes of $- and $3, respectively)
- 10 (b)
Net current period other comprehensive (loss) income (5) 5 -
Accumulated other comprehensive loss at Dec. 31 $ (85) $ (56) $ (141)
(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.
(Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total
Accumulated other comprehensive loss at Jan. 1 $ (60) $ (64) $ (124)
Other comprehensive loss before reclassifications (net of taxes of $(8) and $-, respectively)
(23) - (23)
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $1 and $-, respectively)
3 (a)
- 3
Amortization of net actuarial loss (net of taxes of $- and $1, respectively)
- 3 (b)
Net current period other comprehensive (loss) income (20) 3 (17)
Accumulated other comprehensive loss at Dec. 31 $ (80) $ (61) $ (141)
(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs. See Note 11 for further information.
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 investments in unconsolidated subsidiaries of $165 million and $155 million as of Dec. 31, 2020 and 2019, 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) 2020 2019 2018
Regulated Electric
Operating revenues - external $ 9,802 $ 9,575 $ 9,719
Intersegment revenue 2 1 1
Total revenues $ 9,804 $ 9,576 $ 9,720
Depreciation and amortization 1,673 1,535 1,421
Interest charges and financing costs 534 500 449
Income tax expense 1 125 187
Net income 1,407 1,288 1,177
Regulated Natural Gas
Operating revenues - external $ 1,636 $ 1,868 $ 1,739
Intersegment revenue 1 2 2
Total revenues $ 1,637 $ 1,870 $ 1,741
Depreciation and amortization 252 219 212
Interest charges and financing costs 71 69 61
Income tax expense 17 48 28
Net income 190 195 187
All Other
Total revenues $ 88 $ 86 $ 79
Depreciation and amortization 23 11 9
Interest charges and financing costs 193 167 142
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 amortization 1,948 1,765 1,642
Interest charges and financing costs 798 736 652
Income tax (benefit) expense (6) 128 181
Net income 1,473 1,372 1,261
15. Summarized Quarterly Financial Data (Unaudited)
Quarter Ended
(Amounts in millions, except per share data) March 31, 2020 June 30, 2020 Sept. 30, 2020 Dec. 31, 2020
Operating revenues $ 2,811 $ 2,586 $ 3,182 $ 2,947
Operating income 455 422 813 426
Net income 295 287 603 288
EPS total - basic
$ 0.56 $ 0.54 $ 1.15 $ 0.54
EPS total - diluted
0.56 0.54 1.14 0.54
Cash dividends declared per common share 0.43 0.43 0.43 0.43
Quarter Ended
(Amounts in millions, except per share data) March 31, 2019 June 30, 2019 Sept. 30, 2019 Dec. 31, 2019
Operating revenues $ 3,141 $ 2,577 $ 3,013 $ 2,798
Operating income 486 410 758 450
Net income 315 238 527 292
EPS total - basic
$ 0.61 $ 0.46 $ 1.02 $ 0.56
EPS total - diluted
0.61 0.46 1.01 0.56
Cash dividends declared per common share 0.405 0.405 0.405 0.405

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

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ITEM 9A. CONTROLS AND PROCEDURES
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.
As of Dec. 31, 2020, 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 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, 2020 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.

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ITEM 9B. OTHER INFORMATION
ITEM 9B - OTHER INFORMATION
None.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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 2021 Annual Meeting of Shareholders, which is expected to occur on April 6, 2021, incorporated by reference. Information with respect to Executive Officers is included in Item 1 to this report.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11 - EXECUTIVE COMPENSATION
Information required under this Item is set forth in Xcel Energy Inc.’s Proxy Statement for its 2021 Annual Meeting of Shareholders, which is incorporated by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
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 2021 Annual Meeting of Shareholders, which is incorporated by reference.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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 2021 Annual Meeting of Shareholders, which is incorporated by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14 - PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2021 Annual Meeting of Shareholders, which is incorporated by reference.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15 - EXHIBIT AND FINANCIAL STATEMENT SCHEDULES
1 Consolidated Financial Statements
Management Report on Internal Controls Over Financial Reporting - For the year ended Dec. 31, 2020.
Report of Independent Registered Public Accounting Firm - Financial Statements and Internal Controls Over Financial Reporting
Consolidated Statements of Income - For each of the three years ended Dec. 31, 2020, 2019, and 2018.
Consolidated Statements of Comprehensive Income - For each of the three years ended Dec. 31, 2020, 2019, and 2018.
Consolidated Statements of Cash Flows - For each of the three years ended Dec. 31, 2020, 2019, and 2018.
Consolidated Balance Sheets - As of Dec. 31, 2020 and 2019.
Consolidated Statements of Common Stockholders’ Equity - For each of the three years ended Dec. 31, 2020, 2019, and 2018.
2 Schedule I - Condensed Financial Information of Registrant.
Schedule II - Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2020, 2019 and 2018.
3 Exhibits
* Indicates incorporation by reference
+ Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
Xcel Energy Inc.
Exhibit Number Description Report or Registration Statement Exhibit Reference
3.01*
Amended and Restated Articles of Incorporation of Xcel Energy Inc.
Xcel Energy Inc. Form 8-K dated May 16, 2012 3.01
3.02*
Bylaws of Xcel Energy Inc. as Amended on April 3, 2020
Xcel Energy Inc. Form 8-K dated April 3, 2020 3.01
4.01*
Description of Securities
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019 4.01
4.02*
Indenture dated Dec. 1, 2000 between Xcel Energy Inc. and Wells Fargo Bank Minnesota, National Association, as Trustee
Xcel Energy Inc. Form 8-K dated Dec. 14, 2000 4.01
4.03*
Supplemental Indenture No. 3 dated June 1, 2006 between Xcel Energy Inc. and Wells Fargo Bank, National Association, as Trustee
Xcel Energy Inc. Form 8-K dated June 6, 2006 4.01
4.04*
Junior Subordinated Indenture, dated as of Jan. 1, 2008, by and between Xcel Energy Inc. and Wells Fargo Bank, National Association, as Trustee
Xcel Energy Inc. Form 8-K dated Jan. 16, 2008 4.01
4.05*
Replacement Capital Covenant, dated Jan. 16, 2008
Xcel Energy Inc. Form 8-K dated Jan. 16, 2008 4.03
4.06*
Supplemental Indenture No. 6, dated as of Sept. 1, 2011 between Xcel Energy Inc. and Wells Fargo Bank, National Association, as Trustee
Xcel Energy Inc. Form 8-K dated Sept. 12, 2011 4.01
4.07*
Supplemental Indenture No. 8, dated as of June 1, 2015 between Xcel Energy Inc. and Wells Fargo Bank, National Association, as Trustee
Xcel Energy Inc. Form 8-K dated June 1, 2015 4.01
4.08*
Supplemental Indenture No. 9, dated as of March 1, 2016, by and between Xcel Energy Inc. and Wells Fargo Bank, National Association, as Trustee
Xcel Energy Inc. Form 8-K dated March 8, 2016 4.02
4.09*
Supplemental Indenture No. 10, dated as of Dec. 1, 2016, by and between Xcel Energy Inc. and Wells Fargo Bank, National Association, as Trustee
Xcel Energy Inc. Form 8-K dated Dec. 1, 2016 4.01
4.10*
Supplemental Indenture No. 11, dated as of June 25, 2018, by and between Xcel Energy Inc. and Wells Fargo Bank, National Association, as Trustee
Xcel Energy Inc. Form 8-K dated June 25, 2018 4.01
4.11*
Supplemental Indenture No. 12, dated as of Nov. 7, 2019 by and between Xcel Energy Inc. and Wells Fargo Bank, National Association, as Trustee, creating 2.60% Senior Notes, Series Due 2029 and 3.50% Senior Notes, Series due 2049
Xcel Energy Inc. Form 8-K dated Nov. 7, 2019 4.01
4.12*
Supplemental Indenture No. 13, dated as of April 1, 2020 by and between Xcel Energy Inc. and Wells Fargo Bank, National Association as Trustee creating $600 million principal amount of 3.40% Senior Notes, Series due 2030
Xcel Energy Inc. Form 8-K dated April 1, 2020 4.01
4.13*
Supplemental Indenture No. 14, dated as of Sept. 25, 2020 between Xcel Energy Inc. and Wells Fargo Bank, National Association as Trustee, creating $500 million principal amount of 0.50% Senior Notes, Series due Oct. 15, 2023
Xcel Energy Inc. Form 8-K dated Sept. 25, 2020 4.01
10.01*
Xcel Energy Inc. Nonqualified Pension Plan (2009 Restatement)
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 10.02
10.02*+
Xcel Energy Senior Executive Severance and Change-in-Control Policy (2009 Restatement)
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 10.05
10.03*+
Second Amendment to Exhibit 10.02 dated Oct. 26, 2011
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011 10.18
10.04*+
Fifth Amendment to Exhibit 10.02 dated May 3, 2016
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016 10.01
10.05*+
Seventh Amendment to Exhibit 10.02 dated May 7, 2018
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018 10.01
10.06*+
Eighth Amendment to Exhibit 10.02 dated March 31, 2020
Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2020 10.02
10.07*+
Ninth Amendment to Exhibit 10.02 dated May 22, 2020
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2020 10.01
10.08*+
Xcel Energy Inc. Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 10.17
10.09*+
Xcel Energy Inc. Executive Annual Incentive Plan (as amended and restated effective Feb. 17, 2010)
Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010 Appendix A
10.10*+
First Amendment to Exhibit 10.09 dated Feb. 20, 2013
Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013 10.01
10.11*+
Xcel Energy Inc. Executive Annual Incentive Award Plan Form of Restricted Stock Agreement
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009 10.08
10.12*+
Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement)
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008 10.07
10.13*+
First Amendment to Exhibit 10.12 effective Nov. 29, 2011
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011 10.17
10.14*+
Second Amendment to Exhibit 10.12 dated May 21, 2013
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013 10.22
10.15*+
Third Amendment to Exhibit 10.12 dated Sept. 30, 2016
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2016 10.01
10.16*+
Fourth Amendment to Exhibit 10.12 dated Oct. 23, 2017
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017 10.1
10.17*+
Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 10.34
10.18*+
Form of Terms and Conditions under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan for Awards of Restricted Stock Units and/or Performance Share Units
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 10.35
10.19*+
Form of Award Agreement for Restricted Stock Units and/or Performance Share Units under the Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement for awards since 2020
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2019 10.32
10.20*+
Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc. as amended and restated effective Feb. 23, 2011
Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011 Appendix A
10.21*+
Stock Equivalent Program for Non-Employee Directors of Xcel Energy Inc. under the Xcel Energy Inc. 2015 Omnibus Incentive Plan
Xcel Energy Inc. Form 8-K dated May 20, 2015 10.02
10.22+
Summary of Non-Employee Director Compensation, effective as of Sept. 1, 2019
10.23*+
Stock Program for Non-Employee Directors of Xcel Energy Inc. as Amended and Restated on Dec. 12, 2017 under the 2015 Omnibus Incentive Plan
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018 10.36
10.24*+
Form of Services Agreement between Xcel Energy Services Inc. and utility companies
Xcel Energy Inc. Form U5B dated Nov. 16, 2000 H-1
10.25*
Third Amended and Restated Credit Agreement, dated as of June 7, 2019 among Xcel Energy Inc., as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, Wells Fargo Bank, National Association, MUFG Bank, Ltd., and Citibank, N.A., as Documentation Agents
Xcel Energy Inc. Form 8-K dated June 7, 2019
99.01
NSP-Minnesota
4.14*
Supplemental and Restated Trust Indenture, dated May 1, 1988, from NSP-Minnesota to Harris Trust and Savings Bank, as Trustee, providing for the issuance of First Mortgage Bonds, Supplemental Indentures between NSP-Minnesota and said Trustee
Xcel Energy Inc. Form S-3 dated April 18, 2018 4(b)(3)
4.15*
Supplemental Trust Indenture dated June 1, 1995, creating $250 million principal amount of 7.125% First Mortgage Bonds, Series due 2025
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017 4.11
4.16*
Supplemental Trust Indenture dated March 1, 1998, creating $150 million principal amount of 6.5% First Mortgage Bonds, Series due 2028
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017 4.12
4.17*
Supplemental Trust Indenture dated Aug. 1, 2000 (Assignment and Assumption of Trust Indenture)
NSP-Minnesota Form 10-12G dated Oct. 5, 2000 4.51
4.18*
Indenture, dated July 1, 1999, between NSP-Minnesota and Norwest Bank Minnesota, NA, as Trustee, providing for the issuance of Sr. Debt Securities
Xcel Energy Inc. Form S-3 dated April 18, 2018 4(b)(7)
4.19*
Supplemental Indenture, dated Aug. 18, 2000, supplemental to the Indenture dated July 1, 1999, among Xcel Energy, NSP-Minnesota and Wells Fargo Bank Minnesota, NA, as Trustee
NSP-Minnesota Form 10-12G dated Oct. 5, 2000 4.63
4.20*
Supplemental Trust Indenture dated July 1, 2005 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $250 million principal amount of 5.25% First Mortgage Bonds, Series due 2035
NSP-Minnesota Form 8-K dated July 14, 2005 4.01
4.21*
Supplemental Trust Indenture dated May 1, 2006 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $400 million principal amount of 6.25% First Mortgage Bonds, Series due 2036
NSP-Minnesota Form 8-K dated May 18, 2006 4.01
4.22*
Supplemental Trust Indenture, dated June 1, 2007, between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee
NSP-Minnesota Form 8-K dated June 19, 2007 4.01
4.23*
Supplemental Trust Indenture dated as of Nov. 1, 2009 between NSP-Minnesota and the Bank of New York Mellon Trust Co., NA, as successor Trustee, creating $300 million principal amount of 5.35% First Mortgage Bonds, Series due 2039
NSP-Minnesota Form 8-K dated Nov. 16, 2009 4.01
4.24*
Supplemental Trust Indenture dated as of Aug. 1, 2010 between NSP-Minnesota and the Bank of New York Mellon Trust Company, NA, as successor Trustee, creating $250 million principal amount of 1.95% First Mortgage Bonds, Series due 2015 and $250 principal amount of 4.85% First Mortgage Bonds, Series due 2040
NSP-Minnesota Form 8-K dated Aug. 4, 2010 4.01
4.25*
Supplemental Trust Indenture dated as of Aug. 1, 2012 between NSP-Minnesota and the Bank of New York Mellon Trust Company, NA, as successor Trustee, creating $300 million principal amount of 2.15% First Mortgage Bonds, Series due 2022 and $500 million principal amount of 3.40% First Mortgage Bonds, Series due 2042
NSP-Minnesota Form 8-K dated Aug. 13, 2012 4.01
4.26*
Supplemental Trust Indenture dated as of May 1, 2013 between NSP-Minnesota and the Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $400 million principal amount of 2.60% First Mortgage Bonds, Series due 2023
NSP-Minnesota Form 8-K dated May 20, 2013 4.01
4.27*
Supplemental Trust Indenture dated as of May 1, 2014 between NSP-Minnesota and the Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $300 million principal amount of 4.125% First Mortgage Bonds, Series due 2044
NSP-Minnesota Form 8-K dated May 13, 2014 4.01
4.28*
Supplemental Trust Indenture dated as of Aug. 1, 2015 between NSP-Minnesota and the Bank of New York Mellon Company, N.A., as successor Trustee, creating $300 million principal amount of 2.20% First Mortgage Bonds, Series due 2020 and $300 million principal amount of 4.00% First Mortgage Bonds, Series due 2045
NSP-Minnesota Form 8-K dated Aug. 11, 2015 4.01
4.29*
Supplemental Trust Indenture dated as of May 1, 2016 between NSP-Minnesota and the Bank of NY Mellon Trust Company, N.A., as successor Trustee, creating $350 million principal amount of 3.60% First Mortgage Bonds, Series due 2046
NSP-Minnesota Form 8-K dated May 31, 2016 4.01
4.30*
Supplemental Trust Indenture dated as of Sept. 1, 2017 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $600 million principal amount of 3.60% First Mortgage Bonds, Series due 2047
NSP-Minnesota Form 8-K dated Sept. 13, 2017 4.01
4.31*
Supplemental Trust Indenture dated as of Sept. 1, 2019 between Northern States Power Company and the Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $600 million principal amount of 2.90% First Mortgage Bonds, Series due 2050
NSP-Minnesota Form 8-K dated Sept. 10, 2019 4.01
4.32*
Supplemental Indenture dated as of June 8, 2020 between NSP-Minnesota and the Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $700 million principal amount of 2.60% First Mortgage Bonds, Series due 2051
NSP-Minnesota 8-K dated June 15, 2020 4.01
10.26*
Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota
NSP-Wisconsin Form S-4 dated Jan. 21, 2004 10.01
10.27*
Third Amended and Restated Credit Agreement, dated as of June 7, 2019 among NSP-Minnesota, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, Wells Fargo Bank, National Association, MUFG Bank, Ltd., and Citibank, N.A., as Documentation Agents
Xcel Energy Inc. Form 8-K dated June 7, 2019 99.02
NSP-Wisconsin
4.33*
Supplemental and Restated Trust Indenture, dated March 1, 1991, between NSP-Wisconsin and First Wisconsin Trust Company, providing for the issuance of First Mortgage Bonds
Xcel Energy Inc. Form S-3 dated April 18, 2018 4(c)(3)
4.34*
Trust Indenture dated Sept. 1, 2000 between NSP-Wisconsin and Firstar Bank, NA as Trustee
NSP-Wisconsin Form 8-K dated Sept. 25, 2000 4.01
4.35*
Supplemental Trust Indenture dated as of Sept. 1, 2008 between NSP-Wisconsin and U.S. Bank National Association, as successor Trustee, creating $200 million principal amount of 6.375% First Mortgage Bonds, Series due 2038
NSP-Wisconsin Form 8-K dated Sept. 3, 2008 4.01
4.36*
Supplemental Trust Indenture dated as of Oct. 1, 2012 between NSP-Wisconsin and U.S. Bank National Association, as successor Trustee, creating $100 million principal amount of 3.70% First Mortgage Bonds, Series due 2042
NSP-Wisconsin Form 8-K dated Oct. 10, 2012 4.01
4.37*
Supplemental Trust Indenture dated as of June 1, 2014 between NSP-Wisconsin and U.S. Bank National Association, as successor Trustee, creating $100 million principal amount of 3.30% First Mortgage Bonds, Series due 2024
NSP-Wisconsin Form 8-K dated June 23, 2014 4.01
4.38*
Supplemental Trust Indenture dated as of Nov 1, 2017 between NSP-Wisconsin and U.S. Bank National Association, as successor Trustee, creating $100 million principal amount of 3.75% First Mortgage Bonds, Series due 2047
NSP-Wisconsin Form 8-K dated Dec. 4, 2017 4.01
4.39*
Supplemental Indenture dated as of Sept. 1, 2018 between NSP-Wisconsin and U.S. Bank National Association, as successor Trustee, creating $200 million principal amount of 4.20% First Mortgage Bonds, Series due 2048
NSP-Wisconsin Form 8-K dated Sept. 12, 2018 4.01
4.40*
Supplemental Indenture dated as of May 18, 2020 between NSP-Wisconsin and U.S. Bank National Association, as Trustee, creating $100 million principal amount of 3.05% First Mortgage Bonds, Series due 2051
NSP-Wisconsin Form 8-K dated May 26, 2020 4.01
10.28*
Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota
NSP-Wisconsin Form S-4 dated Jan. 21, 2004 10.01
10.29*
Third Amended and Restated Credit Agreement, dated as of June 7, 2019 among NSP-Wisconsin, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, Wells Fargo Bank, National Association, MUFG Bank, Ltd., and Citibank, N.A., as Documentation Agents
Xcel Energy Inc. Form 8-K dated June 7, 2019 99.05
PSCo
4.41*
Indenture, dated as of Oct. 1, 1993 between PSCo and Morgan Guaranty Trust Company of New York, as Trustee, providing for the issuance of First Collateral Trust Bonds
Xcel Energy Inc. Form S-3 dated April 18, 2018 4(d)(3)
4.42*
Supplemental Indenture, dated Aug. 1, 2007 between PSCo and U.S. Bank Trust National Association, as successor Trustee
PSCo Form 8-K dated Aug. 8, 2007 4.01
4.43*
Supplemental Indenture dated as of Aug. 1, 2008 between PSCo and U.S. Bank Trust National Association, as successor Trustee, creating $300 million principal amount of 5.80% First Mortgage Bonds, Series due 2018 and $300 million principal amount of 6.50% First Mortgage Bonds, Series due 2038
PSCo Form 8-K dated Aug. 6, 2008 4.01
4.44*
Supplemental Indenture dated as of Aug. 1, 2011 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of 4.75% First Mortgage Bonds, Series due 2041
PSCo Form 8-K dated Aug. 9, 2011 4.01
4.45*
Supplemental Indenture dated as of Sept. 1, 2012 between PSCo and U.S. Bank National Association, as successor Trustee, creating $300 million principal amount of 2.25% First Mortgage Bonds, Series due 2022 and $500 million principal amount of 3.60% First Mortgage Bonds, Series due 2042
PSCo Form 8-K dated Sept. 11, 2012 4.01
4.46*
Supplemental Indenture dated as of March 1, 2013 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of 2.50% First Mortgage Bonds, Series due 2023 and $250 million principal amount of 3.95% First Mortgage Bonds, Series due 2043
PSCo Form 8-K dated March 26, 2013 4.01
4.47*
Supplemental Indenture dated as of March 1, 2014 between PSCo and U.S. Bank National Association, as successor Trustee, creating $300 million principal amount of 4.30% First Mortgage Bonds, Series due 2044
PSCo Form 8-K dated March 10, 2014 4.01
4.48*
Supplemental Indenture dated as of May 1, 2015 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of 2.90% First Mortgage Bonds, Series due 2025
PSCo Form 8-K dated May 12, 2015 4.01
4.49*
Supplemental Indenture dated as of June 1, 2016 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of 3.55% First Mortgage Bonds, Series due 2046
PSCo Form 8-K dated June 13, 2016 4.01
4.50*
Supplemental Indenture dated as of June 1, 2017 between PSCo and U.S. Bank National Association, as successor Trustee, creating $400 million principal amount of 3.80% First Mortgage Bonds, Series due 2047
PSCo Form 8-K dated June 19, 2017 4.01
4.51*
Supplemental Indenture dated as of June 1, 2018 between PSCo and U.S. Bank National Association, as successor Trustee, creating $350 million principal amount of 3.70% First Mortgage Bonds, Series due 2028, and $350 million principal amount of 4.10% First Mortgage Bonds, Series due 2048
PSCo Form 8-K dated June 21, 2018 4.01
4.52*
Supplemental Indenture dated as of March 1, 2019 between PSCo and U.S. Bank National Association, as successor Trustee, creating $400 million principal amount of 4.05% First Mortgage Bonds, Series due 2049
PSCo Form 8-K dated March 13, 2019 4.01
4.53*
Supplemental Indenture dated as of Aug. 1, 2019 between PSCo and U.S. Bank National Association, as successor Trustee, creating $550 million principal amount of 3.20% First Mortgage Bonds, Series due 2050
PSCo Form 8-K dated August 13, 2019 4.01
4.54*
Supplemental Indenture dated as of May 1, 2020 between PSCo and U.S. Bank National Association, as successor Trustee, creating $375 million principal of 2.70% First Mortgage Bonds, Series No. 35 due 2051 and $375 million principal amount of 1.90% First Mortgage Bonds, Series No. 36 due 2031
PSCo Form 8-K dated May 15, 2020 4.01
10.30*
Proposed Settlement Agreement, excerpts, as filed with the CPUC
Xcel Energy Inc. Form 8-K dated Dec. 3, 2004 99.02
10.31*
Third Amended and Restated Credit Agreement, dated as of June 7, 2019 among PSCo, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, Wells Fargo Bank, National Association, MUFG Bank, Ltd., and Citibank, N.A., as Documentation Agents
Xcel Energy Inc. Form 8-K dated June 7, 2019 99.03
SPS
4.55*
Indenture dated Feb. 1, 1999 between SPS and the Chase Manhattan Bank
SPS Form 8-K dated Feb. 25, 1999 99.2
4.56*
Supplemental Indenture dated Oct. 1, 2003 between SPS and JPMorgan Chase Bank, as successor Trustee, creating $100 million principal amount of Series C and Series D Notes, 6% due 2033
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2003 4.04
4.57*
Supplemental Indenture dated Oct. 1, 2006 between SPS and the Bank of New York, as successor Trustee, creating $200 million principal amount of 5.6% Series E Notes due 2016 and $250 million principal amount of 6% Series F Notes due 2036
SPS Form 8-K dated Oct. 3, 2006 4.01
4.58*
Indenture dated as of Aug. 1, 2011 between SPS and U.S. Bank National Association, as Trustee
SPS Form 8-K dated Aug. 10, 2011 4.01
4.59*
Supplemental Indenture dated as of Aug. 3, 2011 between SPS and U.S. Bank National Association, as Trustee, creating $200 million principal amount of 4.50% First Mortgage Bonds, Series due 2041
SPS Form 8-K dated Aug. 10, 2011 4.02
4.60*
Supplemental Indenture dated as of June 1, 2014 between SPS and U.S. Bank National Association, as Trustee, creating $150 million principal amount of 3.30% First Mortgage Bonds, Series due 2024
SPS Form 8-K dated June 9, 2014 4.02
4.61*
Supplemental Indenture dated as of Aug. 1, 2016 between SPS and U.S. Bank National Association, as Trustee, creating $300 million principal amount of 3.40% First Mortgage Bonds, Series due 2046
SPS Form 8-K dated Aug. 12, 2016 4.02
4.62*
Supplemental Indenture dated as of Aug. 1, 2017 between SPS and U.S. Bank National Association, as Trustee, creating $450 million principal amount of 3.70% First Mortgage Bonds, Series due 2047
SPS Form 8-K dated Aug 9. 2017 4.02
4.63*
Supplemental Indenture dated as of Oct. 1, 2018 between SPS and U.S. Bank National Association, as Trustee, creating $300 million principal amount of 4.40% First Mortgage Bonds, Series due 2048
SPS Form 8-K dated Nov. 5, 2018 4.02
4.64*
Supplemental Indenture dated as of June 1, 2019 between SPS and U.S. Bank National Association, as Trustee, creating $300 million principal amount of 3.75% First Mortgage Bonds, Series due 2049
SPS Form 8-K dated June 18, 2019 4.02
4.65*
Supplemental Indenture No. 8, dated as of May 1, 2020 between SPS and U.S. Bank National Association, as Trustee, creating $350 million principal amount of 3.15% First Mortgage Bonds, Series due 2050
SPS Form 8-K dated May 18, 2020 4.02
10.32*
Third Amended and Restated Credit Agreement, dated as of June 7, 2019 among SPS, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, Wells Fargo Bank, National Association, MUFG Bank, Ltd., and Citibank, N.A., as Documentation Agents
Xcel Energy Inc. Form 8-K dated June 7, 2019 99.04
Xcel Energy Inc.
21.01
Subsidiaries of Xcel Energy Inc.
23.01
Consent of Independent Registered Public Accounting Firm
24.01
Powers of Attorney
31.01
Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.02
Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.01
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.INS Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH Inline XBRL Schema
101.CAL Inline XBRL Calculation
101.DEF Inline XBRL Definition
101.LAB Inline XBRL Label
101.PRE Inline XBRL Presentation
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
SCHEDULE I
XCEL ENERGY INC.
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(amounts in millions, except per share data)
Year Ended Dec. 31
2020 2019 2018
Income
Equity earnings of subsidiaries $ 1,646 $ 1,505 $ 1,393
Total income 1,646 1,505 1,393
Expenses and other deductions
Operating expenses 43 23 24
Other income (4) (9) (1)
Interest charges and financing costs 198 173 149
Total expenses and other deductions 237 187 172
Income before income taxes 1,409 1,318 1,221
Income tax benefit (64) (54) (40)
Net income $ 1,473 $ 1,372 $ 1,261
Other Comprehensive Income
Pension and retiree medical benefits, net of tax of $ 1, $1 and $1, respectively
$ 5 $ 3 $ 3
Derivative instruments, net of tax of $(1), $(7) and $(1), respectively
(5) (20) (2)
Other comprehensive income (loss) - (17) 1
Comprehensive income $ 1,473 $ 1,355 $ 1,262
Weighted average common shares outstanding:
Basic 527 519 511
Diluted 528 520 511
Earnings per average common share:
Basic $ 2.79 $ 2.64 $ 2.47
Diluted 2.79 2.64 2.47
See Notes to Condensed Financial Statements
XCEL ENERGY INC.
CONDENSED STATEMENTS OF CASH FLOWS
(amounts in millions)
Year Ended Dec. 31
2020 2019 2018
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) - -
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 debt 1,089 1,120 492
Repayment of long-term debt (300) (550) -
Proceeds from issuance of common stock 727 458 230
Repurchase of common stock (4) - (1)
Dividends paid (856) (791) (730)
Other (17) (14) (12)
Net cash provided by (used in) financing activities 139 235 (316)
Net change in cash and cash equivalents (56) 69 -
Cash and cash equivalents at beginning of period 70 1 1
Cash and cash equivalents at end of period $ 14 $ 70 $ 1
See Notes to Condensed Financial Statements
XCEL ENERGY INC.
CONDENSED BALANCE SHEETS
(amounts in millions)
Dec. 31
2020 2019
Assets
Cash and cash equivalents $ 14 $ 70
Accounts receivable from subsidiaries 424 370
Other current assets 6 12
Total current assets 444 452
Investment in subsidiaries 19,102 17,443
Other assets 40 60
Total other assets 19,142 17,503
Total assets $ 19,586 $ 17,955
Liabilities and Equity
Current portion of long-term debt 400 -
Dividends payable 231 212
Short-term debt - 500
Other current liabilities 21 33
Total current liabilities 652 745
Other liabilities 17 23
Total other liabilities 17 23
Commitments and contingencies
Capitalization
Long-term debt 4,342 3,948
Common stockholders' equity 14,575 13,239
Total capitalization 18,917 17,187
Total liabilities and equity $ 19,586 $ 17,955
See Notes to Condensed Financial Statements
Notes to Condensed Financial Statements
Incorporated by reference are Xcel Energy’s consolidated statements of common stockholders’ equity and other comprehensive income in Part II, Item 8.
Basis of Presentation - The condensed financial information of Xcel Energy Inc. is presented to comply with Rule 12-04 of Regulation S-X. Xcel Energy Inc.’s investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in net assets of the subsidiaries are recorded in the balance sheets. The income from operations of the subsidiaries is reported on a net basis as equity in income of subsidiaries.
As a holding company with no business operations, Xcel Energy Inc.’s assets consist primarily of investments in its utility subsidiaries. Xcel Energy Inc.’s material cash inflows are only from dividends and other payments received from its utility subsidiaries and the proceeds raised from the sale of debt and equity securities. The ability of its utility subsidiaries to make dividend and other payments is subject to the availability of funds after taking into account their respective funding requirements, the terms of their respective indebtedness, the regulations of the FERC under the Federal Power Act, and applicable state laws. Management does not expect maintaining these requirements to have an impact on Xcel Energy Inc.’s ability to pay dividends at the current level in the foreseeable future. Each of its utility subsidiaries, however, is legally distinct and has no obligation, contingent or otherwise, to make funds available to Xcel Energy Inc.
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, 2020 and 2019, 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:
(Millions of Dollars) Guarantor Guarantee
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. 60 (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) 2020 2019
NSP-Minnesota $ 81 $ 60
NSP-Wisconsin 9 17
PSCo 98 78
SPS 55 47
Xcel Energy Services Inc. 159 112
Xcel Energy Ventures Inc. - 25
Other subsidiaries of Xcel Energy Inc. 22 31
$ 424 $ 370
Dividends - Cash dividends paid to Xcel Energy Inc. by its subsidiaries were $2,527 million, $2,987 million and $1,097 million for the years ended Dec. 31, 2020, 2019 and 2018, 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, 2020
Loan outstanding at period end $ 57
Average loan outstanding 185
Maximum loan outstanding 318
Weighted average interest rate, computed on a daily basis 0.08 %
Weighted average interest rate at end of period 0.07 %
Money pool interest income $ -
(Amounts in Millions, Except Interest Rates) Year Ended Dec. 31, 2020 Year Ended Dec. 31, 2019 Year Ended Dec. 31, 2018
Loan outstanding at period end $ 57 $ 39 $ -
Average loan outstanding 104 47 71
Maximum loan outstanding 350 250 243
Weighted average interest rate, computed on a daily basis 0.60 % 2.15 % 1.95 %
Weighted average interest rate at end of period 0.07 % 1.63 % N/A
Money pool interest income $ 1 $ 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 debts NOL and tax credit valuation allowances
(Millions of Dollars) 2020 2019 2018 2020 2019 2018
Balance at Jan. 1 $ 55 $ 55 $ 52 $ 67 $ 79 $ 77
Additions charged to costs and expenses 60 42 42 6 9 7
Additions charged to other accounts 12 (a)
16 (a)
11 (a)
- - -
Deductions from reserves (48) (b)
(58) (b)
(50) (b)
(9) (c)
(21) (d)
(5) (d)
Balance at Dec. 31 $ 79 $ 55 $ 55 $ 64 $ 67 $ 79
(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.