ANNUAL
ANNUAL REPORT
2023 COMPANY DESCRIPTION
Xcel Energy is a major U.S. electricity and natural gas company,
with operations in eight Western and Midwestern states. Based in
Minneapolis, Minnesota, the company provides a comprehensive
portfolio of energy-related products and services to millions of electricity
and natural gas customers through its regulated operating companies.
EARNINGS PER SHARE
Dollars per share (diluted)
6
9
.
2
6
9
.
2
7
1
.
3
7
1
.
3
1
2
.
3
5
3
.
3
2021
2022
2023
GAAP (generally accepted accounting
principles) earnings per share
Ongoing earnings per share
FINANCIAL HIGHLIGHTS
2022
2023
GAAP earnings per share
3.17
3.21
Ongoing earnings per share
3.17
3.35
Dividends per share annualized
1.95
2.08
Stock price (close)
70.11
61.91
Assets (millions)
61,188
64,079
2
Bob Frenzel
Chairman, president and
chief executive officer
TO MY FELLOW
CUSTOMERS AND
SHAREHOLDERS
2023 ANNUAL REPORT | 3
2023 was another strong year for Xcel Energy, our customers and our communities. The pace of change in 2023 was extraordinary — but so were our accomplishments. We advanced significant long-term strategic objectives for the company across clean energy, clean fuels and electric transportation. All the while, we continued to serve our customers safely, reliably, affordably and sustainably. Making the clean energy future a realityIn 2023, we marked the five-year anniversary of our clean energy commitment: A bold, industry-leading vision with deep carbon emissions reductions in our electric business by 2030 and a carbon-free electric system by 2050. When we made this commitment in 2018, it was a watershed moment for the industry, as we joined environmental advocates, customers and policymakers to chart a path to a clean energy future. Leading the clean energy transition is embedded in the fabric of our company. In 2023, we continued real progress toward our goals:• We reduced our emissions 54% over 2005 levels and have plans in place to achieve our 80% reduction target by 2030. • We now have more than 10,000 megawatts of renewable energy on our systems and the opportunity to deploy an additional 15,000 to 20,000 megawatts of new, clean energy into our systems by 2030. • We’ve laid the groundwork to extend the lives of our two nuclear plants, Monticello and Prairie Island, which are the largest sources of clean energy that serve our customers. • On Dec. 31, we retired our first of three units at our Sherbourne County Generating Station while simultaneously building the largest solar facility in the Midwest at the same site. 4
• In June, we broke ground on Colorado’s Power Pathway, a $1.7 billion transmission superhighway across the Eastern Plains of Colorado — and just one of the major transmission projects we have underway that will help deliver reliable and affordable clean energy to our customers.• The Department of Energy awarded nearly $1.5 billion to support our Heartland Hydrogen Hub, long-term duration storage pilots with Form Energy, grid resilience in extreme weather and transmission expansion. These awards will be key to helping us achieve our long-term zero-carbon goals, ensure reliability and keep our customers’ bills low.• We are also building the foundation to achieve net-zero greenhouse gas emissions on our natural gas system with our Clean Heat Plan in Colorado and Natural Gas Innovation filing in Minnesota.• We had an active regulatory year in 2023, successfully reaching constructive outcomes with stakeholders across a number of rate cases, which will allow us to shift our focus in 2024 to driving our 2030 clean energy goals forward while keeping customer bills low.Delivering for our customers and communitiesEnsuring we manage customers bills and affordability is critical throughout the clean energy transition. I’m proud that our customers’ electric and natural gas bills over the last five years have remained among the lowest in the country, at 28% and 14% below the national average, respectively. Over the last 10 years, we have kept residential bill growth well under the rate of inflation.The actions we’ve taken over the past seven years to install thousands of megawatts of wind energy have provided nearly $4 billion in savings for customers through avoided fuel costs and production tax credits. And, in our gas distribution segment, the proposed Colorado Clean Heat Plan offers a portfolio of solutions that drive affordable emission reductions and have the added benefit of mitigating fuel price volatility. The proposed Minnesota Natural Gas Innovation plan maximizes benefits from the federal Inflation Reduction Act while piloting technologies that are critical to lowering emissions profiles for our Minnesota customers. For our communities, we did more than keep the lights on: The Xcel Energy Foundation granted $4.4 million to 409 nonprofits through our focus area grants. Our Giving Campaign raised $4.1 million, benefiting more than 1,300 nonprofits. Our Day of Service attracted 2,500 people who volunteered more than 7,200 hours at 126 nonprofit projects — equating an economic 2023 ANNUAL REPORT | 5
impact of approximately $230,000. And, in 2023, our Customer Care group connected customers with $186.9 million of public energy assistance. Safety first, Safety AlwaysThrough our Safety Aways program, we work to provide our employees and contractors with the resources they need to do their jobs safely and without incident — every day. In 2023, we achieved significant progress and, as a result, are making Xcel Energy a safer place to work. In fact, our significant injuries and fatalities were down 34% compared to 2022.This improvement was thanks to a continued focus on critical risk management and event learning, but it was particularly driven by strong ownership of safety from our frontline workers. We also maintained a focus on contractor safety, with continued collaboration between our contractors and Xcel Energy around Safety Always and ongoing critical risk management. Connected and committedAs we execute on our strategic priorities of leading the clean energy transition, enhancing our customers’ experience and keeping our bills low, I couldn’t be more optimistic about the next generation of leaders we have elevated throughout the company. We have new leaders in many of our operating segments — generation, transmission and distribution — as well as on our Executive Committee with Amanda Rome assuming the role of group president of Utilities and chief customer officer. In 2023, our teams continued to deliver for our customers, communities — and one another. Our employees are truly our greatest resource. Thanks to them, in 2023 Xcel Energy was recognized as one of Ethisphere’s World’s Most Ethical Companies for the fourth year in a row, as well as one of Fortune’s Most Admired Companies. We also received accolades from Military Times as a Best for Vets employer, the Human Rights Campaign for its Equality 100 Award: Leader in LGBTQ+ Workplace Inclusion and a score of 100 on the Disability: IN index for our disability inclusion in the workplace. When we keep our customers at the center of our focus and we lead with our values of Connected, Committed, Trustworthy and Safe, there is really nothing we can’t accomplish as a company. Sincerely,Bob Frenzel Chairman, president and chief executive officer SUSTAINABILITY
Technology
for a clean
energy future.
BERNIE PHOTO
6
As the first U.S. energy provider
to set ambitious goals for all
the ways our customers use
energy — electricity, heating and
transportation — Xcel Energy
knows the key to realizing our
clean energy future is leading
by example.
To reach our ambitious 2050 goal, we’ve been
actively pursuing the research, development
and commercialization of promising new
technologies for serving our customers —
and 2023 was a year of huge strides.
Clean fuels, clean heat
This year, the Heartland Hydrogen Hub,
which aims to produce and use low-carbon
hydrogen at commercial scale in Minnesota,
Wisconsin, South Dakota, North Dakota and
Montana, was selected by the Department of
Energy to receive up to $925 million in funding.
“Clean fuels are a critical component of
enabling economy-wide decarbonization. The
Heartland Hydrogen Hub is a game-changing
initiative that demonstrates how we’re
accelerating the development of the next
generation of clean energy technology with
significant benefits for our customers and the
environment,” said Bob Frenzel, Xcel Energy
chairman, president and CEO.
The project will use Xcel Energy’s existing and
future nuclear, solar and wind resources in the
Upper Midwest to produce hydrogen to blend
into power generation, existing natural gas
distribution systems and other agricultural and
industrial applications. The hub aims to reduce
carbon emissions by more than 1 million
metric tons per year, the equivalent of taking
220,000 gasoline-powered cars off the road.
Xcel Energy also joined Bank of America,
Delta Air Lines and Ecolab in establishing
the Minnesota SAF Hub — an unparalleled
collaboration among key players committed
to scaling sustainable aviation fuel (SAF)
production to replace conventional jet fuel and
reduce lifecycle carbon emissions of aviation
by more than 80%. Xcel Energy’s role will be
to provide clean energy to sustainable aviation
fuel production facilities across Minnesota, to
ensure SAF production has as small a carbon
footprint as possible.
Our Colorado Clean Heat Plan, introduced
this year, fast-tracks clean, resilient, innovative
solutions while ensuring customers receive
the reliable, affordable energy they need to
power their lives. Designed to accommodate
customers’ unique needs, the plan offers a
portfolio of solutions customers can choose
from that work for them, leading to greater
emission reductions at a lower cost.
“Natural gas remains the most affordable way
to heat customer homes and businesses, and
customers deserve more choice to determine
their own energy futures,” said Robert Kenney,
president of Xcel Energy–Colorado. “Success
will require partnership, collaboration and
new, creative ways to accelerate customer
choices so that customers can determine
what emissions reductions solutions work
best for their own needs and preferences.”
In Minnesota, our newly proposed $58 million,
five-year Natural Gas Innovation Plan
includes a portfolio of innovative pilot projects
across a broad array of technologies that, if
scaled up in the future, have the potential to
significantly reduce carbon emissions from
the natural gas system while keeping costs
affordable for customers. The proposal helps
to maximize benefits from the federal Inflation
Reduction Act, including approximately $18.6
million in anticipated tax credits and rebates.
2023 ANNUAL REPORT | 7
Climate resilience
Over the last several years, like all companies,
Xcel Energy has seen increases in severe
weather — severe storms, extreme hot and
cold temperatures, winds and droughts —
that affect our operations and ability to serve
our customers. For that reason, the company
is not only investing in the clean energy
future; it is working to improve the resilience
of its system today.
We are focused on resilience in many
different areas of operations, but one is
improving our ability to respond to the
threat of wildfires. Xcel Energy recognizes
that wildfires pose a significant threat to
our customers and communities. As part of
the company’s commitment to resilience
and safety, Xcel Energy makes strategic
investments and improvements to support
the power grid and build resilience. These
efforts include system-hardening initiatives
and inspections, operational and situational
awareness efforts and connecting with
stakeholders to understand the unique needs
of each community
In 2023, Xcel Energy was selected for a
$100 million award from the U.S. Department
of Energy to continue the company’s work
to reduce and mitigate the evolving threat
of wildfires and ensure the resiliency of
the grid through extreme weather. Through
the selected projects, Xcel Energy will take
steps to increase grid resiliency, including
adding fire-resistant coatings to wood poles,
improving equipment safety features in
power lines and electric vehicle chargers
in high fire risk conditions, moving certain
high-risk distribution circuits underground
and enhancing vegetation management.
Long-term energy storage
In partnership with Form Energy, and with a
$70 million grant from the U.S. Department
of Energy and a $20 million grant from
Breakthrough Energy Catalyst, Xcel Energy
plans to build two 10-megawatt, 100-hour
battery arrays near our retiring coal plants in
Becker, Minnesota, and Pueblo, Colorado.
Form Energy’s iron-air batteries can deliver
enough energy to power 2,000 homes for up
to five days. Both batteries would tap into our
existing transmission system and make the
renewable energy we generate more reliable
and affordable.
“Multi-day battery storage has the potential to
help us better harness the renewable energy
we generate while ensuring the grid remains
reliable for our customers,” said Bria Shea,
regional vice president, Planning and Policy for
Xcel Energy–Minnesota. “We look forward to
bringing this system online at our Sherco site
and learning more about the role it can play in our
larger effort to reach 100% carbon-free electricity.”
Sherco Solar
As Xcel Energy retired one of three coal units
at the Sherburne County Generating Plant
in late 2023, building was already underway
at the adjacent Sherco Solar site, slated to
be the largest solar facility in the Midwest.
When the first two phases of the project
are complete in 2025, the combined 710
megawatts will generate enough electricity
to power more than 150,000 homes each
year on average and fully replace the capacity
of the coal-fired Unit 2 that retired Dec. 31.
The former Sherco Unit 2, built in 1977, will
become a synchronous condenser, a piece of
equipment that manages system stability as
renewable energy increases, providing reliable
electricity for customers.
“Sherco has served our customers reliably
for nearly 50 years, and we see tremendous
potential for the plant site in the Upper
Midwest’s energy future,” said Ryan Long,
president of Xcel Energy–Minnesota, South
Dakota and North Dakota. “Just as we’re
taking a phased approach to decommissioning
the coal units, we’re building replacement
generation in phases to support clean, reliable
and affordable energy for our customers.”
8
2023 ANNUAL REPORT | 9
ECONOMIC PROSPERITY
Brighter
communities.
BERNIE PHOTO
At Xcel Energy, sustainability is a
core part of our mission to provide
customers with safe, clean, reliable
energy at a competitive price.
Sustainability also shows up in how
we strengthen communities by
delivering exceptional service and
partnership to help the places we
serve thrive.
Affordable energy, empowered customers
Xcel Energy is helping customers large and
small to lower costs and reduce their carbon
footprint. We are also committed to ensuring
customers continue to have some of the
lowest energy bills in the country.
This spring, Xcel Energy launched its new
Resources Education Delivered (RED) Truck
in Colorado, which ventures out into the
community, staffed with energy experts to
10
answer customers’ questions and help with bill
assistance, program sign-ups and more. The
truck expands on existing community outreach,
providing immediate energy assistance at a
range of events and locations.
And across our service areas, wind generation
continues to drive customer savings. For the
last three years, the company has delivered
wind turbine generator availability of more
than 96%, saving customers over $1 billion in
avoided fuel costs and tax credits.
Giving back
Through the Xcel Energy Foundation and our
employee giving and volunteerism programs,
we contributed more than $4.1 million to
our communities in 2023, $2.2 million of
which went to more than 1,700 nonprofit
and community groups and was matched
by funds from the Xcel Energy Foundation
to local United Way chapters. At our annual
Day of Service, more than 2,300 Xcel Energy
employees and community members across
the company’s eight-state service area put
good energy into action, contributing over
7,200 hours and delivering an economic impact
of $230,000 in our communities.
Fostering a diverse workforce
Xcel Energy is committed to hiring and
retaining a workforce that reflects the diversity
of our communities. This year, the company
was honored to receive a top score on the
Disability Equality Index, a top score on the
Human Rights Campaign’s annual Corporate
Equality Index and recognition as a Five-Star
Employer, a distinction for organizations
that do the most to hire, retain, promote
and support veterans. To further our support
of former service members, the company
introduced a new professional development
program to help veterans.
“Our veterans, guardsmen and reservists
will play a critical role as we continue to lead
the nation in clean energy while serving
our customers affordably and reliably,” said
chairman, president and CEO Bob Frenzel.
Investing in our community
Xcel Energy also understands the important
role we play in the local economies of the
communities we serve. As we deliver on
our plan to exit coal by 2030 across all our
service territories, we are committed to a
just transition for employees and community
members. The 2023 retirement of the Sherco
Generating Plant in Becker, Minnesota, is proof
of that commitment.
“There’s a lot of life left at the Sherco site,
and our dedicated co-workers will manage the
transition over the next decade,” said Michelle
Neal, Sherco’s plant director. “The plant, and all
those who keep it running well, have served as
the backbone of the region’s generation fleet
for decades.”
The new energy investments at the Sherco
plant site will provide economic benefits in
Becker and the surrounding area. Sherco
Solar will bring 400 union construction jobs,
18 ongoing operations and maintenance
jobs and an estimated $350 million in local
economic benefits through payments to
landowners and local governments. Our
battery storage project plans at the site
include 15 to 20 union construction jobs, and
the Minnesota Energy Connection project
will bring hundreds of jobs to build the
transmission line and new wind and solar
resources, plus an infrastructure investment
of more than $1 billion for the region.
Our newly proposed Natural Gas Innovation
Plan in Minnesota also includes a focus on local
benefits, jobs and workforce development. If
approved, the plan would create an estimated
417 construction and other jobs in Minnesota
over five years and would help to develop local
expertise in growing careers such as renewable
natural gas, hydrogen, district energy and
strategic electrification.
2023 ANNUAL REPORT | 11
ENERGY SECURITY
Grid resiliency
and reliability.
12
As a leader in the clean energy
transition, Xcel Energy intends
to move forward at a pace and
scale that allows the company
to reach net-zero carbon emissions
responsibly while meeting
emissions reductions goals
that align with science-based
climate targets.
To make these advancements without
compromising the reliable, affordable service
our customers expect, the company is
continually making strategic investments and
improvements to strengthen the power grid,
build resilience and increase its situational
awareness of risks. In 2023, we had the
lowest level of system interruptions that
we’ve experienced in the past 10 years.
Transmission upgrades
The transmission system is the backbone
of the U.S. electric grid, with nearly 160,000
miles of high-voltage power lines carrying
energy from where it is generated to where
it is needed. Adequate transmission capacity
is critical to delivering the significant amount
of renewable energy generation needed to
achieve Xcel Energy’s clean energy goals.
With Colorado’s Power Pathway, a historic
infrastructure project launched in 2023,
Xcel Energy began expansion of transmission
capacity to continue serving existing
generation and plan for future renewable
energy generation. The 550-mile Pathway
will allow Xcel Energy to connect more
than 5,000-megawatts of new renewable
energy produced in eastern Colorado,
one of the nation’s best areas for wind
and solar generation.
In the Upper Midwest, two projects being
developed by Xcel Energy were awarded
a significant portion of a $464 million U.S.
Department of Energy grant to expand
transmission lines, boost reliability and
affordability and increase capacity to add
new electricity generation to the grid.
The coordinated projects will facilitate
interconnection and our regional transmission
organizations’ ability to transfer energy
between their regions, especially during
extreme weather conditions.
Xcel Energy also has joined with other
utilities in Grid North Partners to implement
19 transmission project upgrades — primarily
to increase system capacity — that will
enable more low-cost renewable energy
to be delivered from western Minnesota
to customers throughout the region.
Expected to be built over the next three
years, these projects will span Minnesota
and touch eastern South Dakota with
the goal of reducing congestion on the
transmission system.
2023 ANNUAL REPORT | 13
“Over the last 15 years, Xcel Energy has
been the leading transmission developer
in the country, having built approximately
3,300 miles of new lines,” said Frenzel. “By
collaborating with our regional transmission
organizations, our fellow utilities and state
agencies, we will continue to build out a grid
that advances the transition to clean energy.”
Modernizing the distribution grid
Today’s grid is undergoing a dramatic shift:
The addition of renewables, electric vehicles,
and Distributed Energy Resources (DER)
poses opportunities but also planning and
operational challenges — and will continue to
do so into the future. To maintain our reliable,
affordable electric service and enable more
flexibility for customers, we are currently
planning on investing approximately $1.6
billion in distribution technologies to meet the
customer needs of today and tomorrow.
These investments include new network
infrastructure, advanced software, equipment
sensors and related data analytics capabilities.
We are investing in smart meters with grid
edge technology, other smart devices on the
grid and technologies such as an advanced
planning tool, which simulates the impact
of load, including electric vehicles and other
DER growth, to develop load forecasts
that inform planning to ensure the system
meets customers’ evolving needs. We
also implemented an advanced distribution
management system that provides enhanced
visibility and control of increasingly complex
distribution grid operations, including 2
gigawatts of third-party DER that includes 900
megawatts of community solar gardens in
Minnesota — one of the largest programs of
its kind in the country. The deployment of a
Distributed Energy Resources Management
System (DERMS) is an emerging approach
to connect and manage DER on the utility
system and is part of the company’s near-
term grid modernization roadmap.
14
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
☒
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2023 or
For the transition period from _____ to _____
001-3034
(Commission File Number)
Xcel Energy Inc.
(Exact name of registrant as specified in its charter)
Minnesota
(State or Other Jurisdiction of Incorporation or Organization)
414 Nicollet Mall Minneapolis Minnesota
(Address of Principal Executive Offices)
41-0448030
(IRS Employer Identification No.)
55401
(Zip Code)
612 330-5500
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, $2.50 par value per share
Trading Symbol(s)
Name of each exchange on which registered
XEL
Nasdaq Stock Market LLC
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒ Yes ☐ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☒ No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. ☒ Yes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation
S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒ Yes ☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging
growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the
Exchange Act. ☒ Large accelerated filer ☐ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised
financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over
financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit
report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect
the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of
the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No
As of June 30, 2023, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $34,278,999,603.
As of Feb. 15, 2024, there were 555,155,770 shares of common stock outstanding, $2.50 par value.
Portions of the Registrant’s definitive Proxy Statement for its 2024 Annual Meeting of Shareholders are incorporated by reference into Part III of this Form 10-K.
DOCUMENTS INCORPORATED BY REFERENCE
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3
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22
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TABLE OF CONTENTS
Business
PART I
Item 1 —
Item 1A — Risk Factors
Item 1B — Unresolved Staff Comments
Item 1C — Cybersecurity
Item 2 —
Item 3 —
Item 4 —
Properties
Legal Proceedings
Mine Safety Disclosures
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
[Reserved]
Management’s Discussion and Analysis of Financial Condition and Results of Operations
PART II
Item 5 —
Item 6 —
Item 7 —
Item 7A — Quantitative and Qualitative Disclosures About Market Risk
Financial Statements and Supplementary Data
Item 8 —
Item 9 —
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Item 9A — Controls and Procedures
Item 9B — Other Information
Item 9C — Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
PART III
Item 10 — Directors, Executive Officers and Corporate Governance
Item 11 — Executive Compensation
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13 — Certain Relationships and Related Transactions, and Director Independence
Item 14 — Principal Accountant Fees and Services
PART IV
Item 15 — Exhibit and Financial Statement Schedules
Item 16 — Form 10-K Summary
Signatures
2
PART I
ITEM 1 — BUSINESS
Definitions of Abbreviations
Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
Capital Services
Eloigne
e prime
Nicollet Project
Holdings
Capital Services, LLC
Eloigne Company
e prime inc.
Nicollet Project Holdings, LLC
NSP-Minnesota
NSP System
Northern States Power Company, a Minnesota corporation
The electric production and transmission system of NSP-Minnesota and
NSP-Wisconsin operated on an integrated basis and managed by NSP-
Minnesota
Northern States Power Company, a Wisconsin corporation
NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
NSP-Wisconsin
Operating
companies
PSCo
SPS
Utility subsidiaries NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
WGI
WYCO
Xcel Energy
WestGas InterState, Inc.
WYCO Development, LLC
Xcel Energy Inc. and its subsidiaries
Public Service Company of Colorado
Southwestern Public Service Co.
Federal and State Regulatory Agencies
CPUC
DOC
DOE
DOT
EPA
ERCOT
FERC
IRS
MPCA
MPUC
NDPSC
NERC
NMPRC
NRC
OAG
PHMSA
PSCW
PUCT
SDPUC
SEC
Colorado Public Utilities Commission
Minnesota Department of Commerce
United States Department of Energy
United States Department of Transportation
United States Environmental Protection Agency
Electric Reliability Council of Texas
Federal Energy Regulatory Commission
Internal Revenue Service
Minnesota Pollution Control Agency
Minnesota Public Utilities Commission
North Dakota Public Service Commission
North American Electric Reliability Corporation
New Mexico Public Regulation Commission
Nuclear Regulatory Commission
Minnesota Office of Attorney General
Pipeline and Hazardous Materials Safety Administration
Public Service Commission of Wisconsin
Public Utility Commission of Texas
South Dakota Public Utility Commission
Securities and Exchange Commission
Electric, Purchased Gas and Resource Adjustment Clauses
CIP
DSM
ECA
FCA
GCA
GUIC
RES
Conservation improvement program
Demand side management
Retail electric commodity adjustment
Fuel clause adjustment
Gas cost adjustment
Gas utility infrastructure cost rider
Renewable energy standard
Other
AFUDC
AMI
ALJ
ARO
ARRR
ASC
ATM
BART
Allowance for funds used during construction
Advanced metering infrastructure
Administrative Law Judge
Asset retirement obligation
Application for Rehearing, Reargument, or Reconsideration
Financial Accounting Standards Board Accounting Standards
Codification
At-the-market
Best available retrofit technology
C&I
CapX2020
CCN
CCR
CCR Rule
CDD
CEO
CFO
CIG
CON
CSPV
CWIP
Commercial and Industrial
Alliance of electric cooperatives, municipals and investor-owned utilities
in the upper Midwest involved in a joint transmission line planning and
construction effort
Certificates of Convenience and Necessity
Coal combustion residuals
Final rule (40 CFR 257.50 - 257.107) published by the EPA regulating
the management, storage and disposal of CCRs as a nonhazardous
waste
Cooling degree-days
Chief executive officer
Chief financial officer
Colorado Interstate Gas Company, LLC
Certificate of Need
Crystalline Silicon Photovoltaic
Construction work in progress
D.C. Circuit
United States Court of Appeals for the District of Columbia Circuit
Decommissioning method where radioactive contamination is removed
and safely disposed of at a requisite facility or decontaminated to a
permitted level
Dividend Reinvestment Program
Edison Electric Institute
Energy Impact Partners
European Mutual Association for Nuclear Insurance
Earnings per share
Effective tax rate
Financial transmission right
Generally accepted accounting principles
General Electric
Greenhouse gas
Heating degree-days
Institute of Nuclear Power Operations
Independent power producing entity
Integrated Resource Plan
Independent System Operator
Investment Tax Credit
Joint Target Interconnection Queue
Lubbock Power & Light
Manufactured gas plant
Midcontinent Independent System Operator, Inc.
Demand of retail and wholesale customers that a utility has an obligation
to serve under statute or contract
Net asset value
Nuclear Electric Insurance Ltd.
Net operating loss
Nitrogen Oxides
Operating and maintenance
Open Access Transmission Tariff
Operations, Nuclear, Environmental and Safety
Per- and Polyfluoroalkyl Substances
Prairie Island nuclear generating plant
Performance Incentive Mechanism
Post-Medicare
Power purchase agreement
Pre-Medicare
Production tax credit
Refuse-derived fuel
Renewable energy credit
Request for proposal
Return on equity
DECON
DRIP
EEI
EIP
EMANI
EPS
ETR
FTR
GAAP
GE
GHG
HDD
INPO
IPP
IRP
ISO
ITC
JTIQ
LP&L
MGP
MISO
Native load
NAV
NEIL
NOL
NOx
O&M
OATT
ONES
PFAS
PI
PIM
Post-65
PPA
Pre-65
PTC
RDF
REC
RFP
ROE
3
ROU
RTO
S&P
SERP
SPP
TCJA
THI
TSR
VaR
VIE
WACC
Right-of-use
Regional Transmission Organization
Standard & Poor’s Global Ratings
Supplemental executive retirement plan
Southwest Power Pool, Inc.
2017 federal tax reform enacted as Public Law No: 115-97, commonly
referred to as the Tax Cuts and Jobs Act
Temperature-humidity index
Total shareholder return
Value at Risk
Variable interest entity
Weighted Average Cost of Capital
Measurements
Bcf
KV
KWh
MMBtu
MW
MWh
Billion cubic feet
Kilovolts
Kilowatt hours
Million British thermal units
Megawatts
Megawatt hours
Forward-Looking Statements
Where to Find More Information
Xcel Energy’s website address is www.xcelenergy.com. Xcel Energy
makes available through its website, free of charge, 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.
Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks,
uncertainties and assumptions. Such forward-looking statements, including those relating to 2024 EPS guidance, long-term EPS and dividend growth rate
objectives, future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected
capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions
regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and
credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words
“anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and
similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any
obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for
the fiscal year ended Dec. 31, 2023 (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), could cause actual results to differ materially from management expectations as suggested by such
forward-looking information: operational safety, including our nuclear generation facilities and other utility operations; successful long-term operational
planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee workforce and third-party
contractor factors; violations of our Codes of Conduct; our ability to recover costs and our subsidiaries’ ability to recover costs from customers; changes in
regulation; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including recessionary
conditions, inflation rates, monetary fluctuations, supply chain constraints and their impact on capital expenditures and/or the ability of Xcel Energy Inc. and
its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us;
assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws;
uncertainty regarding epidemics, the duration and magnitude of business restrictions including shutdowns (domestically and globally), the potential impact
on the workforce, including shortages of employees or third-party contractors due to quarantine policies, vaccination requirements or government
restrictions, impacts on the transportation of goods and the generalized impact on the economy; effects of geopolitical events, including war and acts of
terrorism; cybersecurity threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and
other weather events; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; costs of
potential regulatory penalties and wildfire damages in excess of liability insurance coverage; regulatory changes and/or limitations related to the use of
natural gas as an energy source; challenging labor market conditions and our ability to attract and retain a qualified workforce; and our ability to execute on
our strategies or achieve expectations related to environmental, social and governance matters including as a result of evolving legal, regulatory and other
standards, processes, and assumptions, the pace of scientific and technological developments, increased costs, the availability of requisite financing, and
changes in carbon markets.
Overview
Xcel Energy (the “Company”) is a major U.S. regulated electric and natural gas delivery company headquartered in Minneapolis, Minnesota (incorporated in
Minnesota in 1909). The Company serves customers in eight 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 3.8 million electric
customers and 2.2 million natural gas customers through four utility subsidiaries (i.e., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS). Along with the
utility subsidiaries, the transmission-only subsidiaries, WYCO (a joint venture formed with CIG to develop and lease natural gas pipelines, storage and
compression facilities) and WGI (an interstate natural gas pipeline company) comprise the regulated utility operations. The Company’s nonregulated
subsidiaries include Eloigne, Capital Services, Venture Holdings and Nicollet Project Holdings.
4
Subsidiary / Affiliate
NSP-Minnesota
NSP-Wisconsin
PSCo
SPS
WGI
WYCO
Function
Electric & Gas
Electric & Gas
Electric & Gas
Electric
Interstate gas pipeline
Gas storage and transportation
Other Subsidiaries
See Note 1 to the consolidated financial statements for further
information.
Utility Subsidiary Overview
Electric customers
Natural gas customers
Total assets
Electric generating capacity
Natural gas storage capacity
Electric transmission lines (conductor miles)
Electric distribution lines (conductor miles)
Natural gas transmission lines
Natural gas distribution lines
Service Territory
3.8 million
2.2 million
$64 billion
20,935 MW
53.5 Bcf
111,000 miles
216,000 miles
2,200 miles
37,000 miles
Strategy
Xcel Energy’s vision is to be the preferred and trusted provider of the energy our customers need. We will deliver on this vision while offering a competitive
total return to shareholders. Our mission is to provide our customers with safe, clean, reliable energy services they want and value at a competitive price.
We execute on our vision and mission through three strategic priorities.
LEAD THE CLEAN ENERGY
TRANSITION
ENHANCE THE CUSTOMER
EXPERIENCE
KEEP BILLS LOW
Our employees are guided by four corporate values: Connected, Committed, Safe, and Trustworthy.
Our values, culture and Code of Conduct serve as the foundation upon which Xcel Energy’s employees, Board of Directors, contractors and suppliers
approach their work in delivering on our three strategic priorities.
5
Deliver a Competitive Total Return to Investors
Carbon-free Electricity by 2050
Successful strategy execution, along with our disciplined approach to
growth, operations and management of environmental, social and
governance issues, positions us to continue delivering a competitive TSR.
We have consistently achieved our financial objectives, meeting or
exceeding our initial ongoing earnings guidance range for 19 consecutive
years and delivering dividend growth for 21 consecutive years.
Over the past five years, ongoing earnings per share have grown annually
by 6.3% and our dividend per share by 6.5% annually. 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.
LEAD THE CLEAN ENERGY TRANSITION
Xcel Energy manages the risk of climate change and has worked to meet
the increasing demand for cleaner energy for over 20 years.
Our sustainability commitments are summarized as follows:
*Companywide goal; work also underway to meet state clean energy goals in our service area.
**Spans natural gas supply, delivery and customer use.
***Includes Xcel Energy fleet; zero-carbon fuel is carbon free electricity or other clean energy.
6
Xcel Energy was the first U.S. utility to establish a carbon-free vision,
targeting 100% carbon-free electricity by 2050 with an interim goal to
reduce carbon emissions 80% by 2030 (from 2005 levels), including owned
and purchased power. A lead author for the Intergovernmental Panel on
Climate Change (IPCC) confirmed that our vision aligns with science-based
scenarios likely to limit global warming to 1.5 degrees Celsius from pre-
industrial levels, in alignment with the Paris Climate Accords.
The pace of achieving a carbon-free vision is also governed by reliability
and customer affordability. Our approved resource plans outline a clear,
transparent path for reducing carbon emissions by 80% using current
technologies, while maintaining customer bill increases at or below the rate
of inflation. Moving from 80% carbon reduction to 100% carbon-free
electricity will require new, dispatchable technologies that are economically
viable, as well as supportive public policy.
Item 1A
See
sustainability goals and objectives.
for risks and uncertainties related
to strategic and
Xcel Energy’s operating footprint includes some of the best wind and solar
resources in the country, providing for higher capacity factors and lower
operating costs. Our “Steel for Fuel” strategy reduces costs for our
customers by taking advantage of these higher capacity factors along with
savings provided by renewable tax credits and avoided fuel costs that
mitigate higher cost fossil generation.
Through 2023, we reduced carbon emissions from generation serving
customers by an estimated 54% (from 2005 levels) and remain on track to
achieve 80% carbon reduction and fully exit coal by the end of 2030. At the
same time, our Steel for Fuel strategy has saved customers nearly $4
billion since 2017.
Xcel Energy’s wind capacity is now over 11,000 MW, including nearly 4,500
MW of owned wind. In Colorado, we anticipate adding an additional 1,850
MW of wind, 1,700 MW of solar, 1,850 MW of storage and 650 MW of gas
generation to ensure reliability on our system by 2028. In Minnesota, we
have approvals for more than 700 MW of new solar at our Sherco facility,
making it one of the largest solar facilities in the country. In 2024, we filed
our NSP Resource Plan, which proposes adding 3,600 MW of new wind
and solar, 600 MW of battery storage and 2,200 MW of dispatchable
resources by 2030, pending Commission approval. In SPS, we filed for
approval of 400 MW of solar generation, a 200 MW PPA and a broader
system IRP, which could include between 5,000 to 10,000 MW of new
generation by 2030.
Beyond carbon, we have significantly reduced other emissions and
environmental impacts, including:
*Reductions in water consumption are from owned and purchased electricity that serves our
customers. All other reductions are from owned generating plants.
**Coal ash and water consumption data are as of 2022.
As we prepare for early coal plant retirements, employees are provided
advanced notice and offered retraining and relocation opportunities. To
date, we have been successful in avoiding layoffs associated with our early
coal plant retirements. We also help foster economic development
opportunities to offset community impacts associated with coal plant
closures. Xcel Energy has a long track record of working with our
communities on energy, climate and environmental initiatives that impact
them and has publicly committed to furthering environmental justice.
Xcel Energy was selected as part of two different awards from the DOE’s
Grid Resilience and Innovation Partnership program. The DOE awarded
Xcel Energy $100 million to support projects to mitigate the threat of
wildfires and ensure resiliency of the grid through extreme weather. Xcel
Energy was also party to GRIP’s $464 million grant to expand transmission
as part of the MISO and SPP program to fund high-voltage transmission to
improve inter-regional transfer capability, reliability and resolve grid
constraints.
Significant investment in our transmission and distribution systems is
essential to ensure resiliency and reliability for customers through the clean
energy transition. We have nearly $12 billion in our 2024 - 2028 capital plan
focused specifically on this, including our $1.7 billion Pathway project in
Colorado, and additional investments to further support our recently
approved Colorado resource portfolio. As part of MISO’s planned
transmission expansion over the next decade, Xcel Energy has been
awarded $1.2 billion of projects as part of Tranche 1. We anticipate MISO
Tranche 2 awards in 2024.
Natural Gas Use in Buildings – Net-Zero GHG by 2050
Xcel Energy is committed to reducing GHG emissions 25% by 2030 (from
2020 levels) and provide net-zero natural gas service by 2050 from the
supply, distribution and end-use of natural gas. In 2023, we filed our Clean
Heat Plan in Colorado and Natural Gas Innovation Plan in Minnesota,
which provide a framework for this transition.
Similar to our electric plan, the lead author for the IPCC confirmed our
vision to deliver natural gas service with net-zero emissions by 2050 aligns
with science-based scenarios likely to limit global warming by 1.5 C.
Our net-zero natural gas frameworks include the following priorities:
• Work with suppliers to purchase only low emissions gas by 2030.
•
Operate the cleanest possible system to achieve net-zero methane
emissions on the system by 2030.
Offer customer options for conservation, beneficial electrification, and
clean fuels such as hydrogen and renewable natural gas.
Apply high-quality carbon offsets through projects that remove
emissions while providing additional environmental and social benefit.
•
•
Electrification of the Transportation Sector
We are also helping reduce carbon emissions in other sectors, including
transportation. We aim to enable one out of five vehicles in our service
areas to be electric by 2030, representing nearly $2 billion of investment,
0.6% - 0.7% of average incremental annual retail sales growth and
avoidance of roughly 5 million tons of CO2 emissions annually. By 2050,
our vision is to run all vehicles in our service area with carbon-free
electricity or other clean energy. We have approved, transportation
electrification programs and plans in Colorado, New Mexico, Minnesota and
Wisconsin and updated transportation plans pending commission approval
in Minnesota and Colorado.
Innovation and Policy
In 2023, the Department of Energy announced awards of nearly $1.5 billion
to support multiple Xcel Energy affiliated projects. The Heartland Hydrogen
Hub, which includes multiple projects from Xcel Energy and others in the
Upper Midwest, received an award of up to $925 million by the DOE. This
funding will serve as a catalyst for a clean hydrogen ecosystem in the
region. The DOE also awarded Xcel Energy up to $70 million to support our
two 10-MW, 100-hour battery pilots with Form Energy. Combined with
grants committed by Breakthrough Energy Catalyst, we have secured up to
$90 million to support these long duration energy storage pilots, a critical
asset class to ensure cost effective reliability in a high-renewable grid.
7
Xcel Energy actively engages in wildfire mitigation activities across our
operating territories. For the past three years, we have operated under a
commission-approved wildfire plan in Colorado. We are currently evaluating
updates to these plans with a wide range of options for consideration
including new
technologies, undergrounding, additional vegetation
management, composite poles, selective use of covered conductor and
preventative power system shutoffs.
Sustainability Governance and Oversight
In 2000, we instituted oversight of environmental performance by the Board
of Directors and were among the first U.S. energy providers to tie carbon
reduction to executive compensation more than 15 years ago.
Xcel Energy has provided a voluntary, third-party verified annual GHG
disclosure since 2005, longer than any other U.S. utility. We are a founding
member of The Climate Registry and a supporter of the Task Force on
Climate-Related Financial Disclosures. Our disclosures also align with the
Global Reporting Initiative, Sustainability Accounting Standards Board and
United Nations Sustainable Development Goals frameworks.
ENHANCE THE CUSTOMER EXPERIENCE
Xcel Energy has invested more than $2 billion over the past decade in a
portfolio of renewable and conservation programs that provide customers
with clean energy options and help keep bills low. New demand remains
robust in our territories, including load growth from new data centers,
industrial electrification and electric vehicle adoption. As such, we are
transforming and expanding our electric grid to accommodate load growth,
renewable energy and distributed energy resources.
We are in the process of installing smart electric meters, which will deliver
customer and operational benefits, providing near-real-time communication,
allowing customers to know how much energy they are using and what it
will cost. In addition, customers will have new digital tools to make it easier
to access their energy information, gain useful insights to understand and
manage their energy use and make energy choices that lower their bills.
KEEP BILLS LOW
Customer affordability is critical to successful strategy execution. From
2014 - 2023, we have kept residential electric bill growth to 1.8% per year
and natural gas bill growth to 1.1% per year, both below the rate of inflation.
Based on available EIA data, the five year average residential electric and
natural gas bills for an Xcel Energy customer were 28% and 14% below the
national average, respectively.
Going forward, our goal is to enable the clean energy transition while
keeping customer bill growth below the rate of inflation through initiatives
including conservation programs, O&M cost control, our One Xcel Energy
Way lean management initiative, advanced operational technologies and
our Steel for Fuel program.
A total of 70% of annual incentive compensation was tied to safety, system
reliability and inclusion metrics.
Management evaluates compensation and benefits to maintain a market-
rewards
competitive, performance-based, shareholder-aligned
package that supports our ability to attract, engage and retain a talented
and diverse workforce, while reinforcing and rewarding strong performance.
total
We partner with educational and community organizations to attract and
hire employees who reflect the communities we serve and live our values.
Xcel Energy had 11,311 full-time employees and workforce demographics
as of December 2023 were as follows:
Female
Ethnically Diverse
Board of Directors
CEO direct reports
Management
Employees
New hires
Interns (hired throughout 2023)
31 %
30
26
23
35
33
15 %
10
13
19
29
14
leaders and employees
We offer
training on microinequities and
unconscious bias to help foster a culture of inclusivity. Xcel Energy hosts
12 business resource groups to support employee interests and obtain
diverse perspectives when solving challenges and achieving goals.
Xcel Energy also respects employees’ freedom of association and their
right to collectively organize. As of Dec. 31, 2023, approximately 46% of
our employees (5,155) were covered by collective bargaining agreements.
Employee turnover for 2023 and future projected retirement eligibility:
Employee Turnover
Retirement Eligibility
Bargaining
(a)
Non-Bargaining
(b)
Overall
6 %
22
15
Within next 5 years
Within next 10 years
19 %
31
(a)
(b)
37% of turnover was due to workforce reduction initiatives.
38% of turnover was due to retirements, including the impacts of the workforce reduction
initiatives.
We are committed to the advancement and protection of human rights,
consistent with U.S. human rights laws and the general principles in the
International Labour Organization Conventions.
Annual Code of Conduct training is required for all employees and the
Board of Directors. We do not tolerate Code of Conduct violations or other
unacceptable behaviors. We expect and offer employees multiple avenues
to raise concerns or report wrong-doing and do not permit any retaliation.
Xcel Energy is proud of our track record and continue to invest in building a
best-in-class workforce. We recently received the following recognitions:
•
•
•
•
For the seventh consecutive year, The Human Rights Campaign
selected Xcel Energy as a recipient of the Equality 100 Award: Leader
in LGBTQ+ Workplace Inclusion in 2023.
For the eleventh consecutive year, Xcel Energy is one of Fortune’s
Most Admired Companies in 2024.
For the ninth consecutive year, Xcel Energy was listed as a Best for
Vets employer by Military Times and also recognized as a 2024
Military Friendly Employer by VIQTORY.
Xcel Energy is among the 2023 World’s Most Ethical Companies®
according to Ethisphere.
*Based on 2019 - Q3 2023 EIA Data
STRENGTHEN OUR COMMUNITIES
We provide a fundamental service, powering communities with safe,
reliable, competitively priced and increasingly clean energy.
Investing in our communities is important to our collective success. We
initiated 18 economic development projects for our local communities in
2023, which are projected to create more than $2.3 billion in capital
investments and 1,400 jobs. Nearly 63% of our supply chain spend was
local, with approximately $638 million spent with diverse suppliers.
Approximately 300 employees served on more
than 530 nonprofit
organizations or local community boards, providing over 28,000 volunteer
hours in 2023. Our annual Day of Service attracted 2,500 people who
volunteered over 7,200 combined hours at over 120 nonprofit projects
across the company’s service footprint.
In 2023, the Xcel Energy Foundation contributed $4 million to 409 nonprofit
organizations that support its three charitable giving focus areas of STEM
Career Pathways, Environmental Sustainability, and Community Vitality.
Through our 2023 Power Your Purpose Giving Campaign, Xcel Energy
employees, contractors and retirees donated more than $2 million to over
1,300 nonprofit and community organizations – exceeding our fundraising
goal. Combined with the Xcel Energy Foundation match to local United
Way chapters, this campaign raised over $4 million for our communities.
VALUE PEOPLE AND OPERATE WITH INTEGRITY
Champion Safety
Continuously elevating the quality and safety of the workplace is a top
priority. We are considered a benchmark company for our Safety Always
approach, focused on eliminating life-altering injuries through a trusted,
transparent culture and the use of critical controls. All employees have
“stop work authority” and are expected to keep each other, our customers
and the public safe. Employees are encouraged to speak up, share
experiences and learn from events to help protect themselves, their
coworkers and the public.
The Board of Directors has oversight for employee and public safety
through the Operations, Nuclear, Environmental and Safety committee,
both of which are also tied to annual incentive compensation.
Cultivate a Diverse, Best-in-Class Workforce
We aim to create an inclusive culture where employees are treated
equitably, and diversity is not only accepted but celebrated. This starts with
our Board of Directors.
The Board of Directors oversees our workforce strategy, including diversity
and inclusion initiatives. Xcel Energy has an incentive-based metric
focused on diverse interview panels, executive sponsorship and employee
feedback on inclusion in the workplace.
8
Utility Subsidiaries
NSP-Minnesota
Electric customers
Natural gas customers
Total assets
Rate Base (estimated)
GAAP ROE
Electric generating capacity
Gas storage capacity
Electric transmission lines (conductor miles)
Electric distribution lines (conductor miles)
Natural gas transmission lines
Natural gas distribution lines
NSP-Wisconsin
Electric customers
Natural gas customers
Total assets
Rate Base (estimated)
GAAP ROE
Electric generating capacity
Gas storage capacity
Electric transmission lines (conductor miles)
Electric distribution lines (conductor miles)
Natural gas transmission lines
Natural gas distribution lines
PSCo
Electric customers
Natural gas customers
Total assets
Rate Base (estimated)
GAAP ROE
Electric generating capacity
Gas storage capacity
Electric transmission lines (conductor miles)
Electric distribution lines (conductor miles)
Natural gas transmission lines
Natural gas distribution lines
SPS
Electric customers
Total assets
Rate Base (estimated)
GAAP ROE
Electric generating capacity
Electric transmission lines (conductor miles)
Electric distribution lines (conductor miles)
1.5 million
0.6 million
$25.0 billion
$15.7 billion
8.82%
9,081 MW
17.1 Bcf
33,000 miles
84,000 miles
78 miles
11,000 miles
0.3 million
0.1 million
$3.7 billion
$2.4 billion
10.38%
551 MW
4.3 Bcf
12,000 miles
28,000 miles
3 miles
3,000 miles
1.6 million
1.5 million
$24.6 billion
$16.9 billion
7.32%
6,203 MW
32.1 Bcf
25,000 miles
80,000 miles
2,000 miles
23,000 miles
0.4 million
$9.9 billion
$7.2 billion
9.80%
5,100 MW
41,000 miles
24,000 miles
9
in
NSP-Minnesota conducts business
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
retail customers and
transports customer-owned natural gas in
Minnesota and North Dakota.
to
NSP-Wisconsin conducts business
in
Wisconsin and Michigan and generates,
transmits, distributes and sells electricity.
NSP-Wisconsin
and
NSP-Minnesota
electric operations are managed on the
NSP
also
System. NSP-Wisconsin
purchases, transports, distributes and sells
natural gas
retail customers and
transports customer-owned natural gas.
to
PSCo conducts business in Colorado and
generates, purchases, transmits, distributes
and sells electricity. PSCo also purchases,
transports, distributes and sells natural gas
to
transports
customer-owned natural gas.
customers
retail
and
SPS conducts business in Texas and New
Mexico
purchases,
transmits, distributes and sells electricity.
generates,
and
Operations Overview
Electric Energy Sources
Utility operations are generally conducted as either electric or gas utilities in
our four utility subsidiaries.
Total electric energy generation by source for the year ended Dec. 31:
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 114,980 (millions of KWh), 3.8 million customers
and electric revenues of $11,446 million for 2023.
Electric Operations
(percentage of total)
Sales Volume
Number of
Customers
Revenues
Residential
C&I
Other
22 %
56
22
86 %
12
2
31 %
50
19
Retail Sales/Revenue Statistics (a)
KWh sales per retail customer
Revenue per retail customer
Residential revenue per KWh
C&I revenue per KWh
Total retail revenue per KWh
2023
2022
23,939
24,285
$
2,464
$
2,513
13.80 ¢
13.41 ¢
8.82 ¢
9.02 ¢
10.29 ¢
10.35 ¢
(a)
See Note 6 to the consolidated financial statements for further information.
Owned and Purchased Energy Generation — 2023
10
66%71%67%57%34%29%33%43%OwnedPurchasedXcel EnergyNSP SystemPSCoSPS
Carbon-Free
Xcel Energy’s carbon-free energy portfolio
includes wind, nuclear,
hydroelectric, biomass and solar power from both owned generation
facilities and PPAs. Carbon-free percentages will vary year-over-year
based on system additions, commodity costs, weather, system demand
and transmission constraints.
See Item 2 — Properties for further information.
Wind
Wind capacity is shown as net maximum capacity. Net maximum capacity
is attainable only when wind conditions are sufficiently available.
Owned — Owned and operated wind farms with corresponding capacity:
Solar
PPAs — Solar PPAs capacity by type:
Type
Distributed Generation
Utility-Scale
Distributed Generation
Utility-Scale
Distributed Generation
Utility-Scale
Total
Utility Subsidiary
Capacity (MW)
NSP System
NSP System
PSCo
PSCo
SPS
SPS
1,117
269
887
(a)
1,530
28
192
4,023
(a)
Includes battery storage capacity of 225 MW.
Utility
Subsidiary
NSP System
PSCo
SPS
Total
2023
2022
Wind Farms
Capacity (MW)
Wind Farms
Capacity (MW)
Average Cost (PPAs) — Average cost per MWh of solar energy under
existing PPAs:
17
2
2
21
2,444
1,059
985
4,488
16
2
2
20
2,352
1,059
984
4,395
Utility Subsidiary
NSP System
PSCo
SPS
$
2023
2022
$
90
34
67
79
69
62
PPAs — Number of PPAs with capacity range:
Utility
Subsidiary
NSP System
PSCo
SPS
2023
2022
PPAs
Range (MW)
PPAs
Range (MW)
120
17
16
1 — 206
23 — 301
1 — 250
129
17
17
1 — 206
23 — 301
1 — 250
PPAs — Contracted wind capacity (MW) for PPAs:
Utility Subsidiary
NSP System
PSCo
SPS
2023
2022
2,066
3,026
1,562
2,163
3,023
1,564
Average Cost — Average cost per MWh of wind energy from owned
generation and existing PPAs:
Type:
Owned Generation
PPA
Owned Generation
PPA
Owned Generation
PPA
Utility Subsidiary
2023
2022
NSP System
NSP System
PSCo
PSCo
SPS
SPS
$
7
$
33
7
42
6
26
18
37
11
38
13
27
Wind Development — Xcel Energy placed into service, repowered, or
contracted for the following during 2023:
Project
Utility Subsidiary
Capacity (MW)
Northern Wind
Grand Meadow Repower
NSP-Minnesota
NSP-Minnesota
92
99
Xcel Energy currently has approximately 1,900 MW of owned wind under
development or being repowered. This includes 350 MW of approved
repowering projects at the NSP System estimated to be completed in 2025,
as well as an anticipated approximately 1,550 MW at PSCo as part of the
Colorado Resource Plan. The Company also anticipates approval of an
additional 300 MW of PPAs as part of the Colorado Resource Plan,
additions are expected to be placed in service between 2026 - 2028.
Xcel Energy currently has approximately 2,900 MW of owned and PPA
solar under development. For the NSP System, this includes 700 MW of
solar approved at the Sherco site which are expected to be placed in
service in 2024 and 2025.
PSCo anticipates development of approximately 1,700 MW of solar
generation resources (650 MW Company Owned, 1,050 MW as PPAs) as
part of the Colorado Resource Plan. Colorado Resource Plan additions are
expected to be placed in service between 2026 - 2028.
For SPS, approximately 400 MW of solar and storage are pending
regulatory approval (expected to be placed in service in 2026 and 2027).
Additionally, various PPAs totaling approximately 100 MW are expected to
be completed throughout 2024 and 2025.
Nuclear
Xcel Energy has two nuclear plants with approximately 1,700 MW of total
2023 net summer dependable capacity that serve the NSP System. Our
nuclear fleet safely and reliably generates carbon free electricity at
consistently high levels of performance among the industry. 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
(nuclear, natural gas and coal):
Utility Subsidiary
NSP System
2023
2022
Nuclear
Cost
Percent
$
0.76
0.76
50 %
51
11
Other — Xcel Energy’s other carbon-free energy portfolio includes hydro
from owned generating facilities.
PSCo anticipates development of approximately 1,850 MW of storage
capacity (400 MW Company Owned, 1,450 MW as PPAs) as part of the
Colorado Resource Plan. Colorado Resource Plan additions are expected
to be placed in service between 2026 - 2028.
See Item 2 — Properties for further information.
Fossil Fuel
Xcel Energy’s fossil fuel energy portfolio includes coal and natural gas
power from both owned generating facilities and PPAs.
Coal
Xcel Energy owned and operated coal units with approximately 6,200 MW
of total 2023 net summer dependable capacity, which provided 19% of Xcel
Energy’s energy mix in 2023. Amount includes Sherco Unit 2, which was
retired on Dec. 31, 2023, net summer dependable capacity of 682 MW and
approximately 100 MW derived from RDF and wood fuel sources.
Xcel Energy has plans to retire or convert to natural gas all of its existing
coal generation by the end of 2030. Approved early coal plant retirements:
Year
Utility Subsidiary
SPS
PSCo
PSCo
PSCo
NSP-Minnesota
PSCo
PSCo
PSCo
NSP-Minnesota
NSP-Minnesota
PSCo
SPS
SPS
Plant Unit
Harrington (a)
Comanche 2
Craig 1
(a)
Pawnee
Sherco 1
Hayden 2
Hayden 1
Craig 2
A.S. King
Sherco 3
Comanche 3
(c)
Tolk 1
(c)
Tolk 2
Capacity (MW)
1,018
330
42 (b)
505
680
98 (b)
135 (b)
40 (b)
511
517 (b)
500 (b)
532
535
2024
2025
2025
2025
2026
2027
2028
2028
2028
2030
2030
2034
2034
(a)
(b)
(c)
Natural Gas
Xcel Energy has 23 natural gas plants with approximately 8,100 MW of
total 2023 net summer dependable capacity, which provided 30% of Xcel
Energy’s mix in 2023.
to provide an adequate supply of
Natural gas supplies, transportation and storage services for power plants
are procured
fuel. Remaining
requirements are procured through a liquid spot market. Generally, natural
gas supply contracts have variable pricing that is tied to natural gas indices.
Natural gas supply and transportation agreements include obligations for
the purchase and/or delivery of specified volumes or payments in lieu of
delivery.
Natural Gas Cost — Delivered cost per MMBtu of natural gas consumed for
owned electric generation and the percentage of total fuel requirements
(nuclear, natural gas and coal):
Utility Subsidiary
NSP System
2023
2022
PSCo
2023
2022
SPS
2023
2022
Natural Gas
Cost
Percent
$
3.91
7.58
3.06
7.09
2.35
5.87
21 %
12
46
45
52
41
PSCo anticipates development of approximately 650 MW of Company
Owned natural gas generation, as part of the Colorado Resource Plan to
help ensure resiliency and reliability. Colorado Resource Plan additions are
expected to be placed in service between 2026 - 2028.
Capacity and Demand
Uninterrupted system peak demand and occurrence date:
System Peak Demand (MW)
2023
9,231 Aug. 23
6,909
July 24
4,372 Aug. 17
2022
9,245
June 20
6,821 Sept. 6
4,280
July 19
Reflects conversion from coal to natural gas.
Based on Xcel Energy’s ownership interest.
Tolk Unit 1 and 2 are approved to be retired early in 2034. The NMPRC has approved a
retirement date of 2028. SPS has filed a Texas rate case settlement agreement pending
PUCT approval for a retirement date of 2028.
NSP System
PSCo
SPS
Transmission
Coal Fuel Cost — Delivered cost per MMBtu of coal consumed for owned
electric generation and the percentage of fuel requirements (nuclear,
natural gas and coal):
Utility Subsidiary
NSP System
2023
2022
PSCo
2023
2022
SPS
2023
2022
(a)
Includes RDF and wood for the NSP System.
Coal (a)
Cost
Percent
$
2.43
2.27
1.57
1.48
2.73
2.37
29 %
37
54
55
48
59
12
Transmission lines deliver electricity at high voltages and over long
distances from power sources to substations closer to customers. A strong
transmission system ensures continued reliable and affordable service,
ability to meet state and regional energy policy goals, and support for a
diverse generation mix, including renewable energy. Xcel Energy owns
approximately 110,000 conductor miles of transmission lines, serving
22,000 MW of customer load, across its service territory.
Xcel Energy plans to build approximately 1,750 additional conductor miles
of transmission lines, primarily as part of the MISO Tranche 1, MN Energy
Connection and Colorado Power Pathway projects between 2024 and
2028.
See Item 2 - Properties for further information.
Distribution
Natural Gas Supply and Cost
lines allow electricity
Distribution
from
substations directly to customers. Xcel Energy has a vast distribution
network, owning and operating approximately 215,000 conductor miles of
distribution lines across our eight-state service territory.
lower voltages
travel at
to
As of Dec. 31, 2023, Xcel Energy has invested approximately $1.1 billion of
$1.6 billion to implement new network infrastructure, smart meters,
advanced software, equipment sensors and related data analytics
capabilities.
These investments will improve reliability and reduce outage restoration
times for our customers, while 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 406,742 (thousands of MMBtu), 2.2 million customers and
natural gas revenues of $2,645 million for 2023.
Natural Gas
(percentage of total)
Deliveries
Number of
Customers
Revenues
Residential
C&I
Transportation and other
Sales/Revenue Statistics (a)
MMBtu sales per retail customer
Revenue per retail customer
Residential revenue per MMBtu
C&I revenue per MMBtu
37 %
24
39
92 %
8
<1
59 %
31
10
2023
2022
115
$
1,113
$
10.54
8.48
1.01
116
1,318
11.97
10.45
1.16
Transportation and other revenue per MMBtu
(a)
See Note 6 to the consolidated financial statements for further information.
Xcel Energy seeks natural gas supply,
transportation and storage
alternatives to yield a diversified portfolio, which increases flexibility,
decreases interruption, financial risks and 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
NSP-Minnesota
NSP-Wisconsin
PSCo
$
2023
2022
5.31
$
5.26
4.91
7.00
6.68
6.33
NSP-Minnesota, NSP-Wisconsin and PSCo have natural gas supply
transportation and storage agreements
for
purchase and/or delivery of specified volumes or to make payments in lieu
of delivery.
include obligations
that
General
General Economic Conditions
Economic conditions may have a material impact on Xcel Energy’s
operating results. Management cannot predict the impact of fluctuating
energy or commodity prices, pandemics, terrorist activity, war or the threat
of war. We could experience a material impact to our results of operations,
future growth or ability to raise capital resulting from a sustained general
slowdown in economic growth or a significant increase in interest rates or
inflation.
Seasonality
Demand for electric power and natural gas is affected by seasonal
differences in the weather. In general, peak sales of electricity occur in the
summer months and peak sales of natural gas occur in the winter months.
As a result, the overall operating results may fluctuate substantially on a
seasonal basis. Additionally, Xcel Energy’s operations have historically
generated less revenues and income when weather conditions are warmer
in the winter and cooler in the summer. Sales true-up and decoupling
mechanisms mitigate the impacts of weather in certain jurisdictions.
Capability and Demand
Competition
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:
2023
2022
Utility Subsidiary
MMBtu
Date
MMBtu
Date
NSP-Minnesota
NSP-Wisconsin
PSCo
753,642
158,029
Feb. 3
Jan. 30
867,385
187,961
2,190,155
Jan. 30
2,243,552
Feb. 12
Jan. 6
Dec. 22
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 can currently avoid paying for
most of the fixed production, transmission and distribution costs incurred to
serve them in most jurisdictions.
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 energy from generation resources of
competing generation resources quantities and transmission services from
other service providers to serve their native load.
13
FERC Order No. 1000 established competition for ownership of certain new
electric transmission facilities under Federal regulations. Some states have
state laws that allow the incumbent a Right of First Refusal to own these
transmission facilities.
FERC Order 2222 requires that RTO and ISO markets allow participation of
aggregations of distributed energy resources. This order is expected to
incentivize distributed energy resource adoption, however implementation
is expected to vary by RTO/ISO and the near, medium, and long-term
impacts of Order 2222 remain unclear.
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. No municipalization
activities are occurring presently.
While each utility subsidiary faces these challenges, Xcel Energy believes
their rates and services are competitive with alternatives currently available.
Governmental Regulations
Public Utility Regulation
See Item 7 for discussion of public utility regulation.
Environmental Regulation
Our facilities are regulated by federal and state agencies that have
jurisdiction over air emissions, water quality, wastewater discharges, solid
and hazardous wastes or substances. Certain 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
transmission and distribution
systems. Our facilities strive to operate in compliance with applicable
environmental
reporting
requirements.
related monitoring and
standards and
its generation,
However, it is not possible to determine what additional facilities or
modifications to 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 historic and current operating
sites and other waste treatment, storage and disposal sites.
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.
Emerging Environmental Regulation
Clean Air Act
Power Plant Greenhouse Gas Regulations — In May 2023, the EPA
published proposed rules addressing control of CO2 emissions from the
power sector. The rule proposed regulations for new natural gas generating
units and emission guidelines for existing coal and certain natural gas
generation. The proposed rules create subcategories of coal units based on
planned retirement date and subcategories of natural gas combustion
turbines and combined cycle units based on utilization. The CO2 control
requirements vary by subcategory. Until final rules are issued, it is not
certain what the impact will be on Xcel Energy. Xcel Energy believes that
the cost of these initiatives or replacement generation would be recoverable
through rates based on prior state commission practices.
Coal Ash Regulation
In May 2023, the EPA published proposed rules to regulate legacy CCR
surface impoundments at inactive facilities and previously exempt areas
where CCR was placed directly on land at regulated CCR facilities under
the CCR Rule for the first time. The proposed rule would subject these
areas to the CCR Rule requirements, including groundwater monitoring,
corrective action, closure, and post-closure care requirements, among
other requirements, with several of the deadlines accelerated.
The EPA has committed to a May 2024 publication date for those new
rules. It is also anticipated that the EPA may issue other CCR proposed
rules in 2024 and 2025 that further expand the scope of the CCR Rule.
Until final rules are issued, it is not certain what the impact will be on Xcel
Energy. Xcel Energy believes that the cost of these initiatives would be
recoverable through rates based on prior state commission practices.
Emerging Contaminants of Concern
PFAS are man-made chemicals that are widely used in consumer products
and can persist and bio-accumulate in the environment. Xcel Energy does
not manufacture PFAS but because PFAS are so ubiquitous in products
and the environment, it may impact our operations.
In September 2022, the EPA proposed to designate two types of PFAS as
“hazardous substances” under the CERCLA. In March 2023, the EPA
published a proposed rule that would establish enforceable drinking water
standards for certain PFAS chemicals. Final rules are expected in 2024.
Costs are uncertain until a final rule is published.
The proposed rules could result in new obligations for investigation and
cleanup. Xcel Energy is monitoring changes to state laws addressing
PFAS. The impact of these proposed regulations is uncertain.
Effluent Limitation Guidelines
In March 2023, the EPA released a proposed rule under the Clean Water
Act, setting forth proposed Effluent Limitations Guidelines and Standards
for steam generating coal plants. This proposed rule establishes more
stringent wastewater discharge standards for bottom ash transport water,
flue-gas desulfurization wastewater, and combustion residuals leachate
from steam electric power plants, particularly coal-fired power plants. The
impact of these proposed regulations is uncertain until a final rule is
published.
14
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 and depreciation of previously
incurred capital expenditures
improvements were
approximately:
for environmental
•
•
•
$275 million in 2023.
$365 million in 2022.
$365 million in 2021.
Other
for similar costs. The precise
Average annual expense of approximately $320 million from 2024 – 2028 is
estimated
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 recovered through rates may fluctuate.
Capital expenditures for environmental improvements were approximately:
•
•
•
$20 million in 2023.
$20 million in 2022.
$60 million in 2021.
Certain previously collected nuclear storage costs for the federal nuclear
waste program are reimbursed to customers by the federal government as
a result of a settlement we pursued regarding the government’s failure to
deliver a disposal program. Installments received are reimbursed to
customers as approved by the MPUC and other state regulators.
Our operations are subject to workplace safety standards under the Federal Occupational Safety and Health Act of 1970 (“OSHA”) and comparable state
laws that regulate the protection of worker health and safety. In addition, the Company is subject to other government regulations impacting such matters as
labor, competition, data privacy, etc. Based on information to date and because our policies and business practices are designed to comply with all
applicable laws, we do not believe the effects of compliance on our operations, financial condition or cash flows are material.
Capital Spending and Financing
See Item 7 for discussion of capital expenditures and funding sources.
Information about our Executive Officers (a)
Age
53
Robert C. Frenzel
Name
Chairman of the Board of Directors, Xcel Energy Inc.
Current and Recent Positions
President and Chief Executive Officer and Director, Xcel Energy Inc.
Chief Executive Officer, NSP-Minnesota, NSP-Wisconsin, PSCo, and SPS
President and Chief Operating Officer, Xcel Energy Inc.
Patricia Correa
50
Executive Vice President, Chief Financial Officer, Xcel Energy Inc.
Senior Vice President and Chief Financial Officer, Luminant, a subsidiary of Energy Future Holdings Corp. (b)
Senior Vice President, Chief Human Resources Officer, Xcel Energy Inc.
Senior Vice President, Human Resources, Eaton Corporation, a power management company
Timothy O’Connor
64
Executive Vice President, Chief Operations Officer, Xcel Energy Inc.
Vice President, Human Resources, Eaton Corporation
Executive Vice President, Chief Generation Officer, Xcel Energy Inc.
Senior Vice President, Chief Nuclear Officer, Xcel Energy Services Inc
Time in Position
December 2021 — Present
August 2021 — Present
August 2021 — Present
March 2020 — August 2021
May 2016 — March 2020
February 2012 — April 2016
February 2022 — Present
July 2019 — January 2022
March 2016 — July 2019
August 2021 — Present
March 2020 — August 2021
February 2013 — March 2020
Frank Prager
61
Senior Vice President, Strategy, Security and External Affairs and Chief Sustainability Officer, Xcel Energy Inc.
March 2022 — Present
Senior Vice President, Strategy, Planning and External Affairs, Xcel Energy Inc.
Vice President, Policy and Federal Affairs, Xcel Energy Services Inc.
Amanda Rome
43
Executive Vice President, Group President, Utilities, and Chief Customer Officer, Xcel Energy Inc.
Interim General Counsel, Xcel Energy Inc.
Executive Vice President, Chief Legal and Compliance Officer, Xcel Energy Inc.
Executive Vice President, General Counsel, Xcel Energy Inc.
Vice President and Deputy General Counsel, Xcel Energy Services Inc.
Positions of increasing responsibility in the Legal Department, Xcel Energy Services Inc.
Brian J. Van Abel
42
Executive Vice President, Chief Financial Officer, Xcel Energy Inc.
Senior Vice President, Finance and Corporate Development, Xcel Energy Services Inc.
Vice President, Treasurer, Xcel Energy Services Inc.
March 2020 — March 2022
January 2015 — March 2020
October 2023 — Present
January 2024 — Present
June 2022 — October 2023
June 2020 — June 2022
October 2019 — June 2020
July 2015 — October 2019
March 2020 — Present
September 2018 — March 2020
July 2015 — September 2018
(a)
(b)
No family relationships exist between any of the executive officers or directors.
In April 2014, Energy Future Holdings Corp., the majority of its subsidiaries, including Texas Competitive Energy Holdings the parent company of Luminant, filed a voluntary bankruptcy
petition under Chapter 11 of the United States Bankruptcy Code. Texas Competitive Energy Holdings emerged from Chapter 11 in October 2016.
15
ITEM 1A — RISK FACTORS
Xcel Energy is subject to a variety of risks, many of which are beyond our
control. Risks that may adversely affect the business, financial condition,
results of operations or cash flows are described below. Although the risks
are organized by heading, and each risk is described separately, many of
the risks are interrelated. These risks should be carefully considered
together with the other information set forth in this report and future reports
that we file with the SEC.
While we believe we have identified and discussed below the key risk
factors affecting our business,
there may be additional risks and
uncertainties that are not presently known or that are not currently believed
to be significant that may adversely affect our business, financial condition,
results of operations or cash flows in the future.
Oversight of Risk and Related Processes
The Board of Directors is responsible for the oversight of material risk and
maintaining an effective risk monitoring process. Management and the
Board of Directors’ committees have responsibility for overseeing the
identification and mitigation of key risks and reporting its assessments and
activities to the full Board of Directors.
Xcel Energy maintains a robust compliance program and promotes a
culture of compliance beginning with the tone at the top. The risk mitigation
process includes adherence to our Code of Conduct and compliance
policies, operation of formal risk management structures and overall
business management. Xcel Energy further mitigates inherent risks through
formal risk committees and corporate functions such as internal audit, and
internal controls over financial reporting and legal.
Management identifies and analyzes risks to determine materiality and
other attributes such as timing, probability and controllability. Identification
and risk analysis occurs formally through risk assessment conducted by
risk
senior management,
procedures, internal audit and compliance with financial and operational
controls.
financial disclosure process, hazard
the
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.
regarding
Management communicates regularly with the Board of Directors and key
stakeholders
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, safety 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
these risks are well understood and given
committees
appropriate focus.
to confirm
16
The Audit Committee is responsible for reviewing the adequacy of the
committees’ 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.
Emerging risks are considered and assigned as appropriate during the
annual Board of Directors and committee evaluation process, resulting in
updates to the committee charters and annual work plans. Additionally, the
Board of Directors conducts an annual strategy session where Xcel
Energy’s future plans and initiatives are reviewed.
Risks Associated with Our Business
Operational Risks
Our natural gas and electric generation/transmission and distribution
operations involve numerous risks that may result in accidents and
other operating risks and costs.
Our natural gas transmission and distribution activities include inherent
hazards and operating risks, such as leaks, explosions, outages and
mechanical problems. Our electric generation, transmission and distribution
activities include inherent hazards and operating risks such as contact, fire
and outages.
These risks could result in loss of life, significant property damage,
environmental pollution, impairment of our operations and substantial
financial losses to employees, third-party contractors, customers or the
public. We maintain insurance against most, but not all, of these risks and
losses.
The occurrence of these events, if not fully covered by insurance, could
have a material effect on our financial condition, results of operations and
cash flows as well as potential loss of reputation.
Other uncertainties and risks inherent in operating and maintaining 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
supplies.
Impact of adverse weather conditions and natural disasters, including,
tornadoes, avalanches, icing events, floods, high winds and droughts.
Performance below expected or contracted levels of output or
efficiency.
Availability of replacement equipment.
Availability of adequate water resources and ability to satisfy water
intake and discharge requirements.
Availability or changes to wind patterns.
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 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 (including regulatory approval in
jurisdictions where Xcel Energy operates), 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 processes and our
asset lives are subject to risk. The 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.
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. New data centers and crypto mining
facilities could generate significant increase in demand. Higher electric
demand may require us to adopt new technologies and make significant
transmission and distribution
including advanced grid
infrastructure, which increases exposure to overall grid instability and
technology obsolescence. Evolving stakeholder preference for lower
emissions from generation sources and end-uses, like heating, may impact
our resource mix and put pressure on our ability to recover capital
investments in natural gas generation and delivery. Multiple states may not
agree as to the appropriate resource mix, which may lead to costs to
comply with one jurisdiction that are not recoverable across all jurisdictions
served by the same assets.
investments
We require inputs such as coal, natural gas, uranium and water. Lack of
availability of these resources could jeopardize long-term operations of our
facilities or make them uneconomic to operate.
Our utilities are highly dependent on suppliers to deliver components
in accordance with short and long-term project schedules.
Our products contain components that are globally sourced from suppliers.
A shortage of key components in which an alternative supplier is not
identified could significantly impact operations and project plans for Xcel
Energy and our customers. Such impacts could include timing of projects
and the potential for project cancellation. Failure to adhere to project
budgets and timelines could adversely impact our results of operations,
financial condition or cash flows.
We are subject to commodity risks and other risks associated with
energy markets and energy production.
A significant increase in fuel costs could cause a decline in customer
demand, adverse regulatory outcomes and an increase in bad debt
expense which may have a material impact on our results of operations.
Despite existing fuel cost 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 alternatives at
potentially higher costs. Additionally, supply shortages may not be fully
resolved, which negatively impacts 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
negatively impacts 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.
Public perception often does not distinguish between pass through
commodity costs and base rates. High commodity prices that are passed
through to customer bills could impact our ability to recover costs for other
improvements and operations.
Due to the 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. If such programs and procedures are not
effective, Xcel Energy’s results of operations, financial condition or cash
flows could be materially impacted.
17
Failure to attract and retain a qualified workforce could have an
adverse effect on operations.
Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear
generation.
The competition for talent has become increasingly prevalent, and we have
experienced increased employee turnover due to the condition of the labor
market and decisions related to strategic workforce planning. In addition,
specialized knowledge and skills are required for many of our positions,
which may pose additional difficulty for us as we work to recruit, retain and
motivate employees in this climate.
train
to hire, adequately
replacement employees,
Failure
transfer
knowledge/expertise 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 businesses have collective bargaining agreements with labor unions.
Failure to renew or renegotiate these contracts could lead to labor
including strikes or boycotts. Such disruptions or any
disruptions,
negotiated wage or benefit increases could have a material adverse impact
to our results of operations, financial condition or cash flows.
National unionization efforts could affect our business, as an increase in
unionized workers could challenge our operational efficiency and increase
costs.
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 and safety standards, progress payments,
for performance. Poor vendor
insurance requirements and security
performance or contractor unavailability could impact ongoing operations,
restoration operations, regulatory recovery, our reputation and could
introduce financial risk or risks of fines.
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
INPO’s
recommendations could result in substantial capital expenditures or a
substantial increase in operating expenses.
the
financial condition or cash
If a nuclear incident did occur, it could have a material impact on our results
of operations,
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.
Our employees, directors, third-party contractors, or suppliers may
violate or be perceived to violate our Codes of Conduct, which could
have an adverse effect on our reputation.
We are 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.
We are exposed to risk of employee or third-party contractor fraud or
misconduct. All employees and members of the Board of Directors are
subject to compliance with our Code of Conduct and are required to
participate
to
compliance with our Supplier Code of Conduct.
training. Additionally, suppliers are subject
in annual
Xcel Energy does not tolerate discrimination, violations of our Code of
Conduct or other unacceptable behaviors. However, it is not always
possible to identify and deter misconduct by employees and other third-
parties, which may result in governmental investigations, other actions or
lawsuits. If such actions are taken against us we may suffer loss of
reputation and such actions could have a material effect on our financial
condition, results of operations and cash flows.
The profitability of our utility operations is dependent on our ability to
recover the costs of providing energy and utility services and earn 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.
18
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 for these types of changes, there
is no assurance that regulators would allow full recovery of all remaining
costs.
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.
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 (including changes in recovery mechanisms) 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.
Our credit ratings are subject to change and our credit ratings may be
lowered or withdrawn by a rating agency. Significant events including
disallowance of costs, use of historic test years, elimination of riders or
interim rates, increasing depreciation lives, lower returns on equity,
changes to equity ratios and impacts of tax policy may impact our cash
flows and credit metrics, potentially resulting in a change in our credit
ratings. In addition, our credit ratings may change as a result of the differing
methodologies or change in the methodologies used by the various rating
agencies.
Any credit ratings downgrade could lead to higher borrowing costs or lower
proceeds from equity issuances. It could also impact our ability to access
capital markets. Also, 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 commercial paper, issuing new securities or cause us to issue
securities with unfavorable terms and conditions, such as higher interest
rates or lower proceeds from equity issuances. Higher interest rates on
short-term borrowings with variable interest rates could also have an
adverse effect on our operating results.
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 our cash flow and liquidity and an increase in
bad debt expense. Credit risk is comprised of numerous factors including
the economy and
the price of products and services provided,
unemployment rates.
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., MISO, SPP, ERCOT and California Independent
System Operator), 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.
to
We have defined benefit pension and postretirement plans that cover most
of our employees. Assumptions related
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 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.
19
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
prioritize 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/availability of various tax credits or the
timeliness of their utilization may impact the economics or selection of
resources. If tax rates are increased, there could be timing delays before
regulated rates provide for recovery of such tax increases in revenues. In
addition, certain IRS tax policies, such as tax normalization, may impact our
ability to economically deliver certain types of resources relative to market
prices.
Macroeconomic Risks
Economic conditions impact our business.
Xcel Energy’s operations are affected by economic conditions, which
correlates to customers/sales growth (decline). Economic conditions may
be impacted by recessionary factors, rising interest rates and 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.
The oil and gas industry represents our largest commercial and industrial
customer base. Oil and natural gas prices are sensitive to market risk
factors which may impact demand.
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.
Health epidemics impact countries, communities, supply chains and
markets. Uncertainty continues to exist regarding epidemics; the duration
and magnitude of business restrictions including shutdowns (domestically
and globally); the potential impact on the workforce including shortages of
employees and
to quarantine policies,
vaccination requirements or government restrictions; impacts on the
transportation of goods, and the generalized impact on the economy.
third-party contractors due
We cannot ultimately predict whether an epidemic will have a material
impact on our future liquidity, financial condition or results of operations.
Nor can we predict the impact on the health of our employees, our supply
chain or our ability to recover higher costs associated with managing an
outbreak.
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 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, 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. While we have business continuity plans in place, our ability to
recover may be prolonged due to the type and extent of the event. 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
connect, restore and reliably serve our customers.
A major disruption could result in a significant decrease in revenues,
additional costs to repair assets, and an adverse impact on the cost and
availability of insurance, which could have a material impact on our results
of operations, financial condition or cash flows.
A cybersecurity incident or security breach could have a material
effect on our business.
information
We operate in an industry that requires the continued operation of
sophisticated
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
their
dependents, contractors, shareholders and other individuals.
regarding customers, employees and
information
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 cybersecurity 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
cybersecurity incidents from international activist organizations, other
countries and individuals. We expect to continue to experience attempts to
compromise our information technology and control systems, network
infrastructure and other assets. To date, no cybersecurity incident or attack
has had a material impact on our business or results of operations.
20
incidents could harm our businesses by
limiting our
Cybersecurity
generation,
transmission and distribution 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 cybersecurity incident on 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.
to
Generative Artificial Intelligence, such as large language models like
ChatGPT, present a range of challenges and potential risks as we consider
impacts
the
complexities of creating and deploying AI models that generate content
autonomously. Data privacy, legal concerns, and security issues are all
risks as this technology continues to be adopted.
the business. These challenges
involve navigating
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 cybersecurity
related actions.
Cybersecurity incidents and regulatory action could result in a material
decrease in revenues and may cause significant additional costs (e.g.,
insurance or compliance) and
penalties,
potentially disrupt our supply and markets for natural gas, oil and other
fuels.
third-party claims, repairs,
threats or subsequent
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 cybersecurity
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
cybersecurity threat is dynamic and evolves continually, and our efforts to
prioritize network protection may not be effective given the constant
changes to threat vulnerability.
While the Company maintains insurance relating to cybersecurity events,
such insurance is subject to a number of exclusions and may be insufficient
to offset any losses, costs or damages experienced. Also, the market for
cybersecurity insurance is relatively new and coverage available for
cybersecurity events is evolving as the industry matures.
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.
21
Public Policy Risks
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. FERC can impose penalties of up to $1.5 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, cybersecurity or safety incident did occur, it could have
a material effect on our results of operations, financial condition or cash
flows.
The continued use of natural gas for both power generation and gas
distribution have increasingly become a public policy advocacy
target. These efforts may result in a limitation of natural gas as an
energy source for both power generation and heating, which could
impact our ability to reliably and affordably serve our customers.
In recent years, there have been various local and state agency proposals
within and outside our service territories that would attempt to restrict the
use and availability of natural gas. If such policies were to prevail, we may
be forced to make new resource investment decisions which could
potentially result in stranded costs if we are not able to fully recover costs
and investments and impact the overall reliability of our service.
Environmental 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.
International commitments and agreements could result in future additional
GHG reductions in the United States. In addition, in 2023 the EPA intends
to publish draft regulations for GHG emissions from the power sector
consistent with the agency’s Clean Air Act authorities.
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 and
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.
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.
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.
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.
To the extent financial markets view climate change and emissions of
GHGs as a financial risk, this could negatively affect our ability to access
capital markets or cause us to receive less than ideal terms and conditions.
We establish strategies and expectations related to climate change and
other environmental matters. Our ability to achieve any such strategies or
expectations is subject to numerous factors and conditions, many of which
are outside of our control. Examples of such factors include, but are not
limited to, evolving legal, regulatory, and other standards, processes, and
assumptions, the pace of scientific and technological developments,
increased costs, the availability of requisite financing, and changes in
carbon markets. Failures or delays (whether actual or perceived) in
achieving our strategies or expectations related to climate change and
other environmental matters could adversely affect our business,
operations, and reputation, and increase risk of litigation.
impacts our service
Severe weather
territories, primarily when
thunderstorms, flooding, tornadoes, wildfires and snow or ice storms or
extreme temperatures (high heating/cooling days) 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 and result in more frequent
service interruptions. Periods of extreme temperatures could also impact
our ability to meet demand.
More frequent and severe drought conditions, extreme swings in amount
and timing of precipitation, changes in vegetation, unseasonably warm
temperatures, very low humidity, stronger winds and other factors have
increased the duration of the wildfire season and the potential impact of an
event. Also, the expansion of the wildland urban interface increases the
wildfire risk to surrounding communities and Xcel Energy's electric and
natural gas infrastructure.
Other potential risks associated with wildfires and other climate events
include the inability to secure sufficient insurance coverage, or increased
costs of insurance, regulatory recovery risk, and the potential for a credit
downgrade and subsequent additional costs to access capital markets.
While we carry liability insurance, given an extreme event, if Xcel Energy
was found to be liable for wildfire damages, amounts that potentially
exceed our coverage could negatively impact our results of operations,
financial condition or cash flows.
Drought or water depletion could adversely impact our ability to provide
electricity to customers, cause early retirement of power plants and
increase the cost for energy. Adverse events may result in increased
insurance costs and/or decreased insurance availability. We may not
recover all costs related to mitigating these physical and financial risks.
ITEM 1B — UNRESOLVED STAFF COMMENTS
None.
22
ITEM 1C — CYBERSECURITY
As described in Item 1A – Risk Factors, Xcel Energy operates in an
industry that requires the continued operation of sophisticated information
technology, control systems and network infrastructure, as such, our
business is subject to the risk of interruption by cybersecurity incidents that
range from attacks common to most industries, such as phishing and
denial-of-service, to attacks from more sophisticated adversaries, including
nation state actors, that target the critical infrastructure used in the
operation of our business.
The Company has a security risk program in place to identify, assess,
manage and report material risks from cybersecurity incidents. As a utility
provider, Xcel Energy complies with reliability standards imposed by NERC,
including critical
to both
cybersecurity and physical security. These standards imposed by NERC, in
alignment with the NIST Cybersecurity Framework, are the basis for which
Xcel Energy has designed the cybersecurity control framework within its
security risk program.
infrastructure protection standards related
Annually, as part of Xcel Energy’s enterprise risk program, an integrated
cybersecurity risk identification and assessment is completed across Xcel
Energy’s business, including generation, transmission, distribution and fuel
storage facilities, information technology systems and other infrastructure
or physical assets as well as information processed in our systems
(including systems hosted by third parties) that could be affected by
cybersecurity incidents. This analysis includes the impact, likelihood,
timeframe and controllability of cybersecurity risks and is presented to the
Board of Directors. Management monitors and reviews the results of this
analysis, integrating them into the enterprise risk assessment processes
and implements appropriate mitigating actions as needed.
Xcel Energy’s cybersecurity policies, standards, practices and readiness
are regularly assessed by third-party consultants. These partners are
engaged to perform independent penetration testing and other security
related services to assist in the prevention, detection, monitoring, mitigation
and remediation of cybersecurity incidents and risks. The results of these
assessments are communicated to management and the Board of
Directors by the Chief Security Officer.
Management has assigned responsibility for the security risk program to
the Chief Security Officer who has extensive experience in critical
infrastructure protection, including multiple years of experience with the
Department of Defense. The Chief Security Officer is informed about and
monitors prevention, detection, mitigation and remediation efforts through a
team of security professionals, many of whom are Certified Information
Systems Security Professionals, Certified Information Security Managers or
have received other cybersecurity certifications. The team has extensive
experience selecting, deploying and operating cybersecurity technologies,
initiatives and processes that aid in preventing, remediating and mitigating
known and unknown cybersecurity threats.
The Chief Security Officer or members of management brief the Board on
routine and regular cybersecurity risk and threat updates, typically on a
quarterly basis. In the event of a significant threat or incident, management
and the Chief Security Officer leverage Xcel Energy’s incident response
processes to assess impacts and resolve incidents. When a significant
cybersecurity incident occurs, management communicates with the Board
of Directors and relevant committees.
The Board of Directors oversees the risks associated with cybersecurity
and the physical security of our assets, with information security matters
being discussed at each regular board meeting as well as at the ONES and
Audit Committee meetings throughout the year.
While the ONES Committee has primary committee responsibility for
cybersecurity due to the operational issues involved, the Board of Directors
has determined that the topic is of sufficient importance to warrant this
comprehensive oversight approach. Augmenting such oversight efforts, the
Board of Directors conducts drills to practice its response in a possible
emergency situation to ensure it is well prepared and positioned to perform
in a possible crisis.
Cybersecurity risks are a part of Xcel Energy’s normal course of business.
To date, no cybersecurity incident or attack has had a material impact on
our business or results of operations. As of Feb. 21, 2024 there have been
no material cybersecurity incidents to report.
to vendor security
Xcel Energy employs a comprehensive risk based approach to assess the
magnitude and significance of a vendor’s risk to the Company. Certain
third-party service providers are subject
risk
assessments at the time of integration, contract execution/renewal, and
upon detection of any increase in risk profile. Xcel Energy uses a variety of
inputs in such risk assessments, including information supplied by
providers and third parties (including information analysis centers that
share daily threat intelligence and improve organizational agility associated
with management of cybersecurity risks). In addition, the Company requires
certain
to meet appropriate security
requirements, controls and responsibilities. The Company deploys periodic
monitoring activities to assess compliance with our cybersecurity control
framework and investigates security incidents that have impacted our third-
party service providers as appropriate.
third-party service providers
23
NSP-Wisconsin
Station, Location and Unit at Dec. 31, 2023
Steam:
Bay Front-Ashland, WI, 2 Units
French Island-La Crosse, WI, 2 Units
Combustion Turbine:
French Island-La Crosse, WI, 2 Units
Wheaton-Eau Claire, WI, 5 Units
Hydro:
Fuel
Installed
MW (a)
Wood/Natural
Gas
1948 - 1956
Wood/RDF
1940 - 1948
41
16
(b)
Oil
Natural Gas/
Oil
1974
1973
Various
Total
119
240
135
551
Various locations, 62 Units
Hydro
(a)
(b)
Summer 2023 net dependable capacity.
RDF is made from municipal solid waste.
PSCo
Station, Location and Unit at Dec. 31, 2023
Fuel
Installed
MW (a)
Steam:
Comanche-Pueblo, CO
Unit 2
Unit 3
Craig-Craig, CO, 2 Units
Hayden-Hayden, CO, 2 Units
Pawnee-Brush, CO, 1 Unit
Cherokee-Denver, CO, 1 Unit
Combustion Turbine:
Blue Spruce-Aurora, CO, 2 Units
Cherokee-Denver, CO, 3 Units
Coal
Coal
Coal
Coal
Coal
Natural Gas
Natural Gas
Natural Gas
1975
2010
1979 - 1980
1965 - 1976
1981
1968
2003
2015
(b)
(c)
(d)
330
500
82
233
505
310
264
576
Fort St. Vrain-Platteville, CO, 6 Units
Natural Gas
1972 - 2009
1,022
Manchief, CO, 2 Units
Rocky Mountain-Keenesburg, CO, 3 Units
Various locations, 8 Units
Hydro:
Cabin Creek-Georgetown, CO
Pumped Storage, 2 Units
Various locations, 6 Units
Wind:
Rush Creek, CO, 300 units
Cheyenne Ridge, CO, 229 units
Natural Gas
Natural Gas
2000
2004
Natural Gas
Various
Hydro
Hydro
Wind
Wind
1967
Various
2018
2020
Total
250
592
247
210
23
(e)
(e)
582
477
6,203
(a)
(b)
(c)
(d)
(e)
Summer 2023 net dependable capacity. Wind is presented as net maximum capacity.
Based on PSCo’s ownership of 67%.
Based on PSCo’s ownership of 10%.
Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2.
Net maximum capacity is attainable only when wind conditions are sufficiently available.
Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec.
31, 2023, PSCo’s wind facilities had a weighted-average capacity factors of 43%.
ITEM 2 — PROPERTIES
Virtually all of the utility plant property of the operating companies is subject
to the lien of their respective first mortgage bond indentures.
NSP-Minnesota
Station, Location and Unit at Dec. 31, 2023
Fuel
Installed
(a)
MW
Steam:
A.S. King-Bayport, MN, 1 Unit
Sherco-Becker, MN
Unit 1
Unit 2
Unit 3
Monticello, MN, 1 Unit
PI-Welch, MN
Unit 1
Unit 2
Various locations, 4 Units
Combustion Turbine:
Coal
Coal
Coal
Coal
Nuclear
Nuclear
Nuclear
1968
1976
1977
1987
1971
1973
1974
Wood/RDF
Various
Angus Anson-Sioux Falls, SD, 3 Units
Natural Gas
1994 - 2005
Black Dog-Burnsville, MN, 3 Units
Natural Gas
1987 - 2018
Blue Lake-Shakopee, MN, 6 Units
Natural
Gas/Oil
1974 - 2005
High Bridge-St. Paul, MN, 3 Units
Natural Gas
2008
Inver Hills-Inver Grove Heights, MN, 8 Units
Natural
Gas/ Oil
1972 - 1996
Riverside-Minneapolis, MN, 3 Units
Natural Gas
2009
Hydro:
511
680
682
517
617
521
519
36
343
491
454
530
276
454
Hennepin Island-Minneapolis, MN 5 Units
Hydro
1954-1955
6
Wind:
Blazing Star 1-Lincoln County, MN, 100 Units
Blazing Star 2-Lincoln County, MN, 100 Units
Border-Rolette County, ND, 75 Units
Community Wind North-Lincoln County, MN, 12
Units
Courtenay Wind-Stutsman County, ND, 100
Units
Crowned Ridge 2-Grant County, SD, 88 Units
Dakota Range, SD, 72 Units
Foxtail-Dickey County, ND, 75 Units
Freeborn-Freeborn County, MN, 100 Units
Grand Meadow-Mower County, MN, 67 Units (f)
Jeffers-Cottonwood County, MN, 20 Units
Lake Benton-Pipestone County, MN, 44 Units
Mower-Mower County, MN, 43 Units
Nobles-Nobles County, MN, 133 Units
Northern Wind-Murray County, MN, 37 Units
(g)
Pleasant Valley-Mower County, MN, 100 Units
Rock Aetna - Murray County, MN, 8 Units
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
2020
2021
2015
2020
2016
2020
2022
2019
2021
2008
2020
2019
2021
2010
2023
2015
2022
Total
200
200
148
26
190
192
298
150
200
99
43
99
91
200
92
196
20
9,081
(b)
(c)
(d)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(e)
(a)
(b)
(c)
(d)
(e)
(f)
(g)
Summer 2023 net dependable capacity. Wind is presented as net maximum capacity.
Retired on Dec. 31, 2023.
Based on NSP-Minnesota’s ownership of 59%.
RDF is made from municipal solid waste.
Net maximum capacity is attainable only when wind conditions are sufficiently available.
Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec.
31, 2023, NSP-Minnesota’s wind facilities had a weighted-average capacity factors of
43%.
Repowered in 2023.
Purchased in 2023.
24
SPS
Station, Location and Unit at Dec. 31, 2023
Fuel
Installed
MW (a)
ITEM 3 — LEGAL PROCEEDINGS
Steam:
Cunningham-Hobbs, NM, 1 Unit
Natural Gas
1957 - 1965
(b)
183
Harrington-Amarillo, TX, 3 Units
Coal
1976 - 1980
1,018
Jones-Lubbock, TX, 2 Units
Maddox-Hobbs, NM, 1 Unit
Nichols-Amarillo, TX, 3 Units
Plant X-Earth, TX, 1 Unit
Tolk-Muleshoe, TX, 2 Units
Combustion Turbine:
Natural Gas
1971 - 1974
Natural Gas
1967
Natural Gas
1960 - 1968
Natural Gas
1952 - 1964
486
112
457
190
(b)
Coal
1982 - 1985
1,067
Cunningham-Hobbs, NM, 2 Units
Natural Gas
1997
Natural Gas
2011 - 2013
Natural Gas
1963 - 1976
207
334
61
Wind
Wind
2019
2020
Total
(c)
(c)
478
507
5,100
Jones-Lubbock, TX, 2 Units
Maddox-Hobbs, NM, 1 Unit
Wind:
Hale-Plainview, TX, 239 Units
Sagamore-Dora, NM, 240 Units
(a)
(b)
(c)
Xcel Energy is involved in various litigation matters in the ordinary course of
business. The assessment of whether a loss is probable or is a reasonable
possibility, and whether the loss or a range of loss is estimable, often
involves a series of complex judgments about future events. Management
maintains accruals for losses probable of being incurred and subject to
reasonable estimation.
Management is sometimes unable to estimate an amount or range of a
reasonably possible loss in certain situations, including but not limited to
when (1) the damages sought are indeterminate, (2) the proceedings are in
the early stages, or (3) the matters involve novel or unsettled legal theories.
In such cases, there is considerable uncertainty regarding the timing or
ultimate resolution of such matters, including a possible eventual loss.
For current proceedings not specifically reported herein, management does
not anticipate that the ultimate liabilities, if any, would have a material effect
on Xcel Energy’s consolidated financial statements. Legal fees are
generally expensed as incurred.
Summer 2023 net dependable capacity. Wind is presented as net maximum capacity.
Retired unit(s) in 2023.
See Note 12 to the consolidated financial statements, Item 1 and Item 7 for
further information.
Net maximum capacity is attainable only when wind conditions are sufficiently available.
Typical average capacity factors are 35-50% for wind facilities. For the year ended Dec.
31, 2023 SPS’ wind facilities had a weighted-average capacity factors of 48%.
Electric utility overhead and underground transmission and distribution lines
at Dec. 31, 2023:
Conductor Miles
NSP-Minnesota
NSP-Wisconsin
PSCo
SPS
Transmission
500 KV
345 KV
230 KV
161 KV
138 KV
115 KV
Less than 115 KV
Total Transmission
Distribution
Less than 115 KV
2,916
12,845
2,300
626
—
8,071
6,640
33,398
—
3,019
—
1,818
—
1,862
5,467
—
5,421
12,244
—
92
4,994
1,782
12,166
24,533
—
11,701
9,854
—
—
14,896
4,494
40,945
83,854
27,971
80,176
23,965
ITEM 4 — MINE SAFETY DISCLOSURES
None.
PART II
ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY,
RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES.
Stock Data
Xcel Energy Inc.’s common stock is listed on the Nasdaq Global Select
Market (Nasdaq). The trading symbol is XEL. The number of common
stockholders of record as of Feb. 15, 2024 was 45,486.
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.
Total
117,252
40,137
104,709
64,910
Comparison of Five Year Cumulative Total Return*
Electric utility transmission and distribution substations at Dec. 31, 2023:
NSP-Minnesota
NSP-Wisconsin
PSCo
SPS
Substations
353
201
233
449
Natural gas utility mains at Dec. 31, 2023:
Miles
NSP-Minnesota
NSP-Wisconsin
PSCo
SPS
WGI
Transmission
Distribution
78
10,894
3
2,024
2,564
23,494
20
—
11
—
* $100 invested on Dec. 31, 2018 in stock or index — including
reinvestment of dividends. Fiscal years ended Dec. 31.
25
Xcel Energy Inc.EEI ElectricsS&P 500201820192020202120222023$80$100$120$140$160$180$200$220
Purchases of Equity Securities by Issuer and Affiliated Purchasers
For the quarter ended Dec. 31, 2023, no equity securities that are
registered by Xcel Energy Inc. pursuant to Section 12 of the Securities
Exchange Act of 1934 were purchased by or on behalf of us or any of our
affiliated purchasers.
ITEM 6 — [RESERVED]
ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Non-GAAP Financial Measures
financial
includes
following discussion
The
in
accordance with GAAP, as well as certain non-GAAP financial measures
such as ongoing ROE, ongoing earnings and ongoing diluted EPS.
Generally, a non-GAAP financial measure is a measure of a company’s
financial performance, financial position or cash flows that is adjusted from
measures calculated and presented in accordance with GAAP.
information prepared
Xcel Energy’s management uses non-GAAP measures for financial
planning and analysis, for reporting of results to the Board of Directors, in
determining performance-based compensation and communicating its
earnings outlook to analysts and investors. Non-GAAP financial measures
are intended to supplement investors’ understanding of our performance
and should not be considered alternatives for financial measures presented
in accordance with GAAP. These measures are discussed in more detail
below and may not be comparable to other companies’ similarly titled non-
GAAP financial measures.
Ongoing ROE
Ongoing ROE is calculated by dividing the net income or loss of Xcel
Energy or each subsidiary, adjusted for certain nonrecurring items, by each
entity’s average stockholder’s equity. We use these non-GAAP financial
measures to evaluate and provide details of earnings results.
Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing
Diluted EPS)
GAAP diluted EPS reflects the potential dilution that could occur if
securities or other agreements to issue common stock (i.e., common stock
equivalents) were settled. The weighted average number of potentially
dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS
is calculated using the treasury stock method. Ongoing earnings reflect
adjustments to GAAP earnings (net income) for certain items. Ongoing
diluted EPS is calculated by dividing the net income or loss of each
subsidiary, adjusted for certain items, by the weighted average fully diluted
Xcel Energy Inc. common shares outstanding for the period. Ongoing
diluted EPS for each subsidiary is calculated by dividing the net income or
loss of such subsidiary, adjusted for certain items, by the weighted average
fully diluted Xcel Energy Inc. common shares outstanding for the period.
We use these non-GAAP financial measures to evaluate and provide
details of Xcel Energy’s core earnings and underlying performance. For
instance, to present ongoing earnings and ongoing diluted earnings per
share, we may adjust the related GAAP amounts for certain items that are
non-recurring in nature. We believe these measurements are useful to
investors to evaluate the actual and projected financial performance and
contribution of our subsidiaries. These non-GAAP financial measures
should not be considered as an alternative to measures calculated and
reported in accordance with GAAP.
26
The following table provides a reconciliation of GAAP earnings (net income)
to ongoing earnings:
(Millions of Dollars)
GAAP net income
Loss on Comanche Unit 3 litigation
Workforce reduction expenses
Less: tax effect of adjustments
Ongoing earnings
2023
2022
$
1,771 $
1,736
35
72
(27)
—
—
—
$
1,851 $
1,736
Diluted Earnings (Loss)
Per Share
GAAP Diluted
EPS
Impact of
Adjustments
Ongoing
Diluted EPS
Twelve Months Ended Dec. 31, 2023
NSP-Minnesota
(a)
PSCo
SPS
NSP-Wisconsin
Earnings from equity method
investments — WYCO
Regulated utility
(a)
Xcel Energy Inc. and Other
(a)
Total
Diluted Earnings (Loss)
Per Share
NSP-Minnesota
PSCo
SPS
NSP-Wisconsin
Earnings from equity method
investments — WYCO
Regulated utility
(a)
Xcel Energy Inc. and Other
(a)
Total
$
1.28 $
0.04
$
1.26
0.70
0.25
0.04
3.52
(0.31)
3.21
$
0.08
0.01
—
—
0.14
—
0.14
$
1.32
1.33
0.71
0.25
0.04
3.66
(0.31)
3.35
Twelve Months Ended Dec. 31, 2022
GAAP Diluted
EPS
Impact of
Adjustments
Ongoing
Diluted EPS
$
1.23 $
1.33
0.64
0.23
0.04
3.47
(0.29)
3.17
$
—
—
—
—
—
—
—
—
$
$
1.23
1.33
0.64
0.23
0.04
3.47
(0.29)
3.17
(a)
Amounts may not add due to rounding.
Comanche Unit 3 Litigation — In the third quarter of 2023, PSCo
recognized a $34 million loss due to a jury verdict in Denver County District
Court awarding CORE lost power damages and other costs. PSCo intends
to file an appeal of this decision. Given the non-recurring nature of this
specific item, it has been excluded from ongoing earnings.
See Note 12 to the consolidated financial statements for further information.
Workforce Reduction — In 2023, Xcel Energy implemented workforce
actions to align resources and investments with our evolving business and
customer needs, and streamline the organization for long-term success.
Xcel Energy
initiated a voluntary retirement program, under which
approximately 400 eligible non-bargaining employees retired. Xcel Energy
also eliminated approximately 150 non-bargaining employees through an
involuntary severance program.
Total workforce reduction expenses of $72 million were recorded in the
fourth quarter of 2023. Given the non-recurring nature of this item, it has
been excluded from ongoing earnings.
See Note 15 to the consolidated financial statements for further information.
Results of Operations
Diluted EPS for Xcel Energy at Dec. 31:
Diluted Earnings (Loss) Per Share
NSP-Minnesota
PSCo
SPS
NSP-Wisconsin
Earnings from equity method investments —
WYCO
Regulated utility
(a)
Xcel Energy Inc. and Other
GAAP Diluted EPS
(a)
Loss on Comanche Unit 3 litigation
Workforce reduction expenses
Ongoing Diluted EPS
(a)
(a)
Amounts may not add due to rounding.
2023
2022
GAAP Diluted
EPS
GAAP Diluted
EPS
$
$
1.28
1.26
0.70
0.25
0.04
3.52
(0.31)
3.21
0.05
0.09
$
3.35
$
1.23
1.33
0.64
0.23
0.04
3.47
(0.29)
3.17
—
—
3.17
that ongoing earnings reflects
Xcel Energy’s management believes
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.
2023 Comparison with 2022
Xcel Energy — GAAP diluted earnings were $3.21 per share compared to
$3.17 per share in 2022 and ongoing diluted earnings were $3.35 per share
in 2023, compared with $3.17 per share in 2022. The increase in ongoing
earnings per share was driven by increased recovery of infrastructure
investments, higher sales and demand and lower O&M expenses, partially
offset by higher depreciation and interest charges and unfavorable weather.
Fluctuations in electric and natural gas revenues associated with changes
in fuel and purchased power and/or natural gas sold and transported
generally do not significantly impact earnings (changes in costs are offset
by the related variation in revenues).
NSP-Minnesota — GAAP earnings increased $0.05 per share and ongoing
earnings increased $0.09 per share for 2023 compared to 2022. The
change to ongoing earnings was driven by increased recovery of electric
infrastructure investments, partially offset by increased interest charges and
unfavorable weather.
PSCo — GAAP earnings decreased $0.07 per share and ongoing earnings
was flat for 2023 compared to 2022. Ongoing earnings primarily reflects
higher recovery of infrastructure investment and lower O&M expenses,
which were partially offset by increased depreciation, interest charges and
unfavorable weather.
SPS — GAAP earnings increased $0.06 per share and ongoing earnings
increased $0.07 per share for 2023 compared to 2022. Ongoing earnings
were largely impacted by regulatory rate outcomes, sales growth, partially
offset by increased depreciation, interest charges and unfavorable weather.
NSP-Wisconsin — GAAP and ongoing earnings increased $0.02 per
share for 2023 compared to 2022. The increase in ongoing earnings was
primarily a result of higher recovery of electric infrastructure investment,
partially offset by unfavorable weather and, higher depreciation, O&M
expenses and interest charges.
Xcel Energy Inc. and Other — Primarily includes financing costs and
interest income at the holding company and earnings from EIP funds equity
method investments. Fluctuations from 2022 levels were largely attributable
to increased interest rates.
Changes in Diluted EPS
Components significantly contributing to changes in EPS:
Diluted Earnings (Loss) Per Share
GAAP and ongoing diluted EPS — 2022
Dec. 31
$
3.17
2023 vs. 2022
Components of change — 2023 vs. 2022
Higher electric revenues, net of electric fuel and purchased power
Lower O&M expenses
Lower conservation and demand side management expenses (offset
in electric revenues)
Higher other income (expense)
Lower taxes (other than income taxes)
Higher natural gas revenues, net of cost of natural gas sold and
transported
Higher interest expense
Higher depreciation and amortization
Workforce reduction expenses
Loss on Comanche Unit 3 litigation
Other (net)
GAAP diluted EPS — 2023
Workforce reduction expenses
Loss on Comanche Unit 3 litigation
Ongoing diluted EPS — 2023
0.07
0.06
0.06
0.05
0.04
0.03
(0.14)
(0.05)
(0.09)
(0.05)
0.06
3.21
0.09
0.05
3.35
$
$
ROE for Xcel Energy and its utility subsidiaries:
ROE
NSP-Minnesota
PSCo
SPS
NSP-Wisconsin
Operating Companies
Xcel Energy
2023
GAAP ROE
Ongoing ROE
2022
GAAP and
Ongoing ROE
8.82 %
9.11 %
8.76 %
7.32
9.80
10.38
8.45
10.33
7.77
9.98
10.67
8.79
10.79
8.23
9.36
10.57
8.74
10.76
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
in
financial performance. However, electric decoupling mechanisms
Colorado (mechanism expired in September 2023) and electric sales true-
up mechanisms in Minnesota and gas decoupling mechanism in Minnesota
predominately mitigate the positive and adverse impacts of weather in
those jurisdictions.
27
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 increase (decrease) in normal and actual HDD, CDD and THI:
HDD
CDD
THI
2023 vs.
Normal
2022 vs.
Normal
2023 vs.
2022
(7.3) %
6.5 %
5.2
16.0
23.7
5.6
(12.9) %
(13.8)
9
Weather — Estimated impact of temperature variations on EPS compared
with normal weather conditions:
2023 vs. 2022
NSP-
Minnesota
PSCo
SPS
NSP-
Wisconsin
Xcel
Energy
Weather-normalized
Electric
residential
Electric C&I
Total retail
electric sales
Firm natural gas
sales
1.0 %
(1.1)
(0.4)
—
1.6 %
(0.4)
0.3
2.3
1.1 %
5.3
4.5
N/A
0.1 %
(0.4)
(0.3)
(0.4)
1.2 %
1.0
1.0
1.4
Annual weather-normalized electric sales growth (decline)
•
•
•
•
NSP-Minnesota — Residential sales increased due to a 1.2% increase
in customers outpacing declines in use per customer. The decline in
C&I sales was due to lower use per customer, particularly due to
weakness in the manufacturing sector compared to prior year.
PSCo — Residential sales increased due to increased use per
customer and a 1.3% increase in customers. The decline in C&I sales
was attributable to decreased use per customer, primarily in the
manufacturing sector.
SPS — Residential sales growth was primarily attributable to a 0.7%
increase in customers and increased use per customer. C&I sales
increased due to higher use per customer, primarily driven by the
energy sector.
NSP-Wisconsin — The C&I sales decline was associated with lower
use per customer, experienced primarily in the transportation and
manufacturing sectors.
Annual weather-normalized natural gas sales growth (decline)
•
Natural gas sales reflect 1.2% residential and 0.7% C&I customer
growth and an increase in C&I use per customer at PSCo. Partially
offsetting these increases were lower use per residential customer in
all jurisdictions.
2023 vs.
Normal
2022 vs.
Normal
2023 vs.
2022
Electric Margin
Retail electric
Decoupling and sales true-up
Electric total
Firm natural gas
Decoupling
Gas total
Total
$
0.013
$
0.138
$
(0.125)
(0.007)
(0.061)
0.054
$
0.006
$
0.077
$
(0.071)
(0.010)
0.013
0.003
0.009
$
$
$
$
$
$
0.037
—
0.037
0.114
$
$
$
(0.047)
0.013
(0.034)
(0.105)
Sales — Sales growth (decline) for actual and weather-normalized sales:
2023 vs. 2022
NSP-
Minnesota
PSCo
SPS
NSP-
Wisconsin
Xcel
Energy
Actual
Electric
residential
Electric C&I
Total retail
electric sales
Firm natural gas
sales
(0.5) %
(1.1)
(0.9)
(12.0)
(4.0) %
(1.9)
(2.6)
(3.0) %
5.2
3.6
(1.5)
N/A
(2.6) %
(0.5)
(1.1)
(12.6)
(2.3) %
0.5
(0.3)
(5.7)
Electric margin is presented as electric revenues less electric fuel and
purchased power expenses. Expenses incurred for electric fuel and
purchased power are generally recovered through various regulatory
recovery mechanisms.
As a result, changes in these expenses are generally offset in operating
revenues.
Electric revenues and fuel and purchased power expenses are impacted by
fluctuations in the price of natural gas, coal and uranium. These price
fluctuations generally have minimal impact on earnings impact due to fuel
recovery mechanisms. In addition, electric customers receive a credit for
PTCs generated, which reduce electric revenue and income taxes.
Electric Revenues, Fuel and Purchased Power and Electric Margin
(Millions of Dollars)
Electric revenues
Electric fuel and purchased power
Electric margin
2023
2022
$
$
11,446
$
(4,278)
7,168
$
12,123
(5,005)
7,118
28
Taxes (other than Income Taxes) —Taxes (other than income taxes)
decreased $31 million in 2023, primarily due to lower property tax expense
(lower tax rates in Minnesota offset by increase in Colorado) and deferrals
related to the Minnesota Electric Rate Case and Texas Electric Rate Case.
Other Income (Expense) — Other income (expense) increased $35 million
for the year, primarily related to rabbi trust performance, which is primarily
offset in employee benefit cost in O&M expenses.
Interest Charges — Interest charges increased $102 million in 2023. The
increase was largely due to higher long-term debt levels to fund capital
investments and higher interest rates.
Xcel Energy Inc. and Other Results
Net income and diluted EPS contributions of Xcel Energy Inc. and its
nonregulated businesses:
(Millions of Dollars)
Xcel Energy Inc. financing costs
Venture Holdings
(a)
Xcel Energy Inc. taxes and other results
Total Xcel Energy Inc. and other costs
(Diluted Earnings (Loss) Per Share)
Xcel Energy Inc. financing costs
Venture Holdings
(a)
Xcel Energy Inc. taxes and other results
Total Xcel Energy Inc. and other costs
2023
2022
(174) $
3
(2)
(173) $
2023
2022
(0.32) $
0.01
—
(0.31) $
(153)
5
(12)
(160)
(0.28)
0.01
(0.02)
(0.29)
$
$
$
$
(a)
Amounts include gains or losses associated with EIP investments.
Xcel Energy Inc.’s results include interest charges, which are incurred at
Xcel Energy Inc. and are not directly assigned to individual subsidiaries.
2022 Comparison with 2021
A discussion of changes in Xcel Energy’s results of operations, cash flows
and liquidity and capital resources from the year ended Dec. 31, 2021 to
Dec. 31, 2022 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 2022, which was filed with
the SEC on Feb. 23, 2023. However, such discussion is not incorporated
by reference into, and does not constitute a part of, this Annual Report on
Form 10-K.
Public Utility Regulation
The FERC and various state and local regulatory commissions regulate
Xcel Energy Inc.’s utility subsidiaries and West Gas Interstate. Xcel Energy
is subject to rate regulation by state utility regulatory agencies, which have
jurisdiction with respect to the rates of electric and natural gas distribution
companies
in Minnesota, North Dakota, South Dakota, Wisconsin,
Michigan, Colorado, New Mexico and Texas.
Change in Electric Margin
(Millions of Dollars)
2023 vs. 2022
Regulatory rate outcomes (MN, CO, TX, NM, WI, SD and MI)
$
Non-fuel riders
Sales and demand
(a)
Wholesale transmission (net)
Revenue recognition of the Texas rate case surcharge
(b)
Estimated impact of weather (net of decoupling/sales true-up)
Conservation and demand side management (offset in expense)
PTCs flowed back to customers (offset by lower ETR)
Other (net)
Total increase
$
100
89
57
28
(85)
(51)
(43)
(28)
(17)
50
(a)
(b)
Sales excludes weather impact, net of partial decoupling in Colorado (mechanism
expired in September 2023) and sales true-up mechanism in Minnesota.
The decline in electric margin is due to the recognition of the Texas rate case outcome
in the second quarter of 2022, which was largely offset by recognition of previously
deferred costs.
Natural Gas Margin
Natural gas margin is presented as natural gas revenues less the cost of
natural gas sold and transported. Expenses incurred for the cost of natural
gas sold are generally recovered through various regulatory recovery
mechanisms. As a result, changes in these expenses are generally offset in
operating revenues.
Natural gas expense varies with changing sales and the cost of natural gas.
However, fluctuations in the cost of natural gas generally have minimal
earnings impact due to cost recovery mechanisms.
Natural Gas Revenues, Cost of Natural Gas Sold and Transported and
Natural Gas Margin
(Millions of Dollars)
Natural gas revenues
Cost of natural gas sold and transported
Natural gas margin
Change in Natural Gas Margin
(Millions of Dollars)
Regulatory rate outcomes (CO, WI, MI)
Estimated impact of weather (net of decoupling)
Other (net)
Total increase
2023
2022
$
$
2,645
$
(1,456)
1,189
$
3,080
(1,910)
1,170
2023 vs. 2022
$
$
50
(25)
(6)
19
Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses decreased $47 million in 2023,
primarily due to the impact of management cost containment efforts, the
exit of our appliance repair services business and the change in deferred
costs associated with the Texas Electric Rate Cases (offset in Electric
revenues), offset by higher bad debt expenses, the impact of inflationary
pressures, including labor, and timing of unplanned maintenance at
generating plants.
Depreciation and Amortization — Depreciation and amortization
increased $35 million for the year, primarily related to system expansion,
offset by the change in deferred costs associated with the Texas Electric
Rate Case and depreciation life extensions implemented in the Minnesota
Electric Rate Case.
29
Rates are designed to recover plant investment, operating costs and an
allowed return on investment. Our utility subsidiaries request changes in
utility rates through commission filings. Changes in operating costs can
affect Xcel Energy’s financial results, depending on the timing of rate cases
and implementation of final rates. Other factors affecting rate filings are
new investments, sales, conservation and DSM efforts, and the cost of
capital.
In addition, the regulatory commissions authorize the ROE, capital structure
and depreciation rates in rate proceedings. Decisions by these regulators
can significantly impact Xcel Energy’s results of operations and credit
quality.
See Rate Matters and Other 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
Retail rates, services, security issuances, property transfers,
mergers, disposition of assets, affiliate transactions, and other
aspects of electric and natural gas operations.
Reviews and approves Integrated Resource Plans for meeting
future energy needs.
Certifies the need and siting for generating plants greater than
50 MW and
in
Minnesota.
than 100 KV
lines greater
transmission
Reviews and approves natural gas supply plans.
Retail rates, services and other aspects of electric and natural
gas operations.
(a)
Reviews and approves Integrated Resource Plans for meeting
future energy needs.
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.
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.
electric
operations,
Wholesale
licensing,
accounting practices, wholesale sales for resale, transmission of
electricity
interstate commerce, compliance with NERC
electric reliability standards, asset transfers and mergers, and
natural gas transactions in interstate commerce.
hydroelectric
in
MPUC
NDPSC
SDPUC
FERC
MISO
Recovery Mechanisms
Mechanism
(a)
CIP Rider
Additional Information
Recovers costs of conservation and DSM programs.
Customer Protection
Mechanisms
Decoupling
FCA
GUIC Rider
MISO capacity revenue tracker, property tax tracker, annual
incentive plan, capital true-up, and deferred tax asset refund are
all mechanisms that mitigate the impact of changes to costs as
compared to a baseline for NSP-Minnesota customers.
Measures natural gas revenues against a baseline revenue per-
customer for all Minnesota gas customers in classes with more
than 50 customers.
Recovers prudently incurred costs of fuel related items and
purchased energy (Minnesota, North Dakota and South Dakota).
Recovers costs for transmission and distribution pipeline integrity
management programs,
for pipeline
including
assessments, deferred costs for sewer separation and pipeline
integrity management programs in Minnesota.
funding
Infrastructure Rider
Recovers costs for investments in generation in South Dakota.
Purchased Gas
Adjustment
Renewable
Development Fund
Renewable Energy
Rider
Provides for prospective monthly rate adjustments in Minnesota
and North Dakota
for costs of purchased natural gas,
transportation and storage service. Includes a true-up process
for difference between projected and actual costs.
Allocates money collected from customers to support research
and development of emerging renewable energy projects and
technologies in Minnesota.
Recovers cost of renewable generation in North Dakota.
RES
Recovers cost of renewable generation in Minnesota.
Sales True-up
Mitigates the impact of changes to sales levels as compared to a
baseline for all Minnesota electric customers.
Transmission Cost
Recovery
Recovers costs for investments in Minnesota, North Dakota, and
South Dakota for electric transmission and distribution grid
modernization.
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.
Pending and Recently Concluded Regulatory Proceedings
2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota
filed a three-year electric rate case with the MPUC. The rate request was
based on a ROE of 10.2%, a 52.5% equity ratio and forward test years. In
December 2021, the MPUC approved interim rates, subject to refund, of
$247 million, effective Jan. 1, 2022. In November 2022, NSP-Minnesota
revised its rate request to $498 million over three years.
the MPUC approved a
In July 2023,
increase of
approximately $332 million for 2022-2024, based on a ROE of 9.25% and
an equity ratio of 52.5%. The MPUC also approved a continuation of the
sales true-up mechanism.
three-year rate
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
to
make wholesale electric sales at market-based prices
customers outside of
jointly
authorized by the FERC.
their balancing authority as
the MPUC denied NSP-Minnesota’s request
In October 2023,
for
reconsideration of certain aspects of the decision. NSP-Minnesota filed an
appeal of the decision to the Minnesota Court of Appeals in November
2023.
DOT
Pipeline safety compliance.
Minnesota Office of
Pipeline Safety
Pipeline safety compliance.
2024 Minnesota Natural Gas Rate Case — In November 2023, NSP-
Minnesota filed a request with the MPUC for an annual natural gas rate
increase of approximately $59 million, or 9.6%. The request is based on a
ROE of 10.2%, a 52.5% equity ratio and a 2024 forward test year with rate
base of approximately $1.27 billion. In Dec. 2023, the MPUC approved
NSP-Minnesota’s
refund, of
interim
approximately $51 million (implemented on Jan. 1, 2024).
rates, subject
request
for
to
Next steps in the procedural schedule are expected to be as follows:
•
•
•
•
•
Intervenor direct testimony: April 19, 2024
Rebuttal testimony: May 24, 2024
Evidentiary hearings: July 10-12, 2024
ALJ Report: October 28, 2024
MPUC Order Due: March 14, 2025
30
2024 North Dakota Natural Gas Rate Case — In December 2023, NSP-
Minnesota filed a request with the NDPSC for an annual natural gas rate
increase of approximately $8 million, or 9.4%. The filing is based on a ROE
of 10.2%, a 52.5% equity ratio and a 2024 forecast test year with rate base
of approximately $168 million. NSP-Minnesota requested interim rates,
subject to refund, of approximately $8 million to be implemented on March
1, 2024.
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 from Monticello and PI is
disposed of 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 of domestic spent nuclear fuel and
other high-level radioactive wastes. The Nuclear Waste Policy Act requires
for nuclear high-level waste
to
the DOE
management.
implement a program
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 current operating licenses in 2030 for Monticello, 2033
for PI Unit 1, and 2034 for PI Unit 2.
In February 2023, NSP-Minnesota filed a CON with the MPUC for
additional storage at PI to support possible life extension to 2054.
for a CON
In October 2023, the MPUC issued an order approving NSP-Minnesota’s
fuel storage (existing
for additional spent
application
Independent Spent Fuel Storage Installation) at the Monticello Nuclear
Power Generating Plant to allow continued operation of the Monticello Plant
until 2040.
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.
NSP-Wisconsin
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Regulatory Body / RTO
PSCW
Michigan Public Service
Commission
FERC
MISO
Additional Information
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.
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.
Wholesale electric operations, hydroelectric generation licensing,
accounting practices, wholesale sales for resale, transmission of
electricity
interstate commerce, compliance with NERC
electric reliability standards, asset transactions and mergers and
natural gas transactions in interstate commerce.
in
NSP-Wisconsin is a transmission owning member of the MISO
RTO that operates within the MISO RTO and wholesale energy
jointly
market. NSP-Wisconsin and NSP-Minnesota are
authorized by the FERC to make wholesale electric sales at
market-based prices.
DOT
Pipeline safety compliance.
Recovery Mechanisms
Mechanism
Annual Fuel Cost Plan
Natural Gas Cost-
Recovery Factor (MI)
Power Supply Cost
Recovery Factors
Additional Information
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.
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.
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.
Purchased Gas
Adjustment
A retail cost-recovery mechanism to recover the actual cost of
natural gas, transportation, and storage services.
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.
Recently Concluded Regulatory Proceedings
Wisconsin Rate Case — In 2023, NSP-Wisconsin filed a Wisconsin rate
case seeking a revised electric increase of $25 million and a natural gas
increase of $7 million. The filing was based on a 2024 forecast test year, a
ROE of 10.25%, an equity ratio of 52.5% and a forecasted average net rate
base of approximately $2.1 billion for the electric utility and $284 million for
the natural gas utility.
31
In December 2023, the PSCW approved a ROE of 9.8% and an equity ratio
of 52.5% as well as a rate increase of approximately $1 million for the
electric utility. Adjustments to NSP-Wisconsin’s rate request included
removal of a proposed residential affordability program and other earnings
neutral adjustments and fuel and purchased power costs. The PSCW also
approved a $5 million rate increase for the natural gas utility in 2024. The
new rates were implemented on Jan. 1, 2024.
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.
NSP System
Pending and Recently Concluded Regulatory Proceedings
2022 Upper Midwest IRP Resource Acquisition — Following the MPUC’s
approval of NSP-Minnesota and NSP-Wisconsin’s latest IRP in April 2022,
NSP-Minnesota and NSP-Wisconsin have been engaged in multiple
resource acquisition processes and proceedings to meet the need identified
in the IRP for the NSP System.
•
•
•
•
In August 2022, NSP-Minnesota and NSP-Wisconsin jointly filed an
RFP seeking at least 900 MW of solar or solar plus storage capacity.
In May 2023, NSP-Minnesota filed a recommended portfolio, which
proposed an additional 250 MW of self-build solar generation at the
site of our retiring Sherco coal units and a 100 MW solar PPA located
in Wisconsin as part of the resource plan RFP. In September 2023,
the MPUC approved the request for 350 MW, subject to a cost cap
based on projected costs for the Sherco solar project.
In the second quarter of 2023, NSP-Minnesota initiated the process
with the MPUC for acquisition of 800 MW of firm dispatchable
resources. In January 2024, NSP-Minnesota and other companies
submitted proposed resources. NSP-Minnesota expects a decision by
the fourth quarter of 2024.
In July 2023, NSP-Wisconsin issued an RFP seeking approximately
650 MW of solar and/or solar plus storage development assets that
will be developed in the 2027-2029 timeframe to replace the capacity
from the retiring King Generating Station. The RFP closed in
September 2023 and bids are being evaluated.
In October 2023, NSP-Minnesota
issued an RFP seeking
approximately 1,200 MW of wind development assets to replace
capacity and reutilize interconnection rights associated with the retiring
Sherco coal facilities. The RFP closed in December 2023 and the
NSP-Minnesota expects to file for approval of recommended projects
by mid-2024.
2024 Upper Midwest Energy Plan — In February 2024, NSP-Minnesota
filed its resource plan with the MPUC. Key components of the plan include
the following:
•
•
•
•
•
Reduced carbon emissions by more than 80%, potentially up to 88%,
by 2030.
Extends the operation of Prairie Island and Monticello nuclear plants
through the early 2050s.
Adds 3,600 MW of new wind and solar resources by 2030.
Adds 600 MW of battery energy storage by 2030.
Adds more than 2,200 MW of dispatchable resources by 2030.
NSP-Minnesota anticipates a MPUC decision in 2025.
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 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-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 risk and to hedge sales and
purchases.
NSP-Minnesota also engages in trading activity unrelated to these hedging
activities. Sharing of any margins is determined through state regulatory
proceedings as well as the operation of the FERC approved joint operating
agreement. NSP-Minnesota and NSP-Wisconsin do not serve any
wholesale requirements customers at cost-based regulated rates.
PSCo
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Additional Information on Regulatory Authority
Retail rates, accounts, services, issuance of securities and other
aspects of electric, natural gas and steam operations.
Reviews and approves Integrated Resource Plans for meeting
future energy needs.
Certifies the need and siting for generating plans greater than 50
MW.
Pipeline safety compliance.
electric
operations,
Wholesale
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.
accounting
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.
PSCo is not presently a member of an RTO and does not
operate within an RTO energy market. However, PSCo does
make certain sales
including SPP and
to other RTO’s,
participates in the SPP Western Energy Imbalance Service
market, an energy imbalance market.
Pipeline safety compliance.
Regulatory Body / RTO
CPUC
FERC
RTO
DOT
32
Recovery Mechanisms
Approved portfolio includes the following resources:
Mechanism
Colorado Energy Plan
Adjustment
Additional Information
Recovers the early retirement costs of Comanche Units 1 and 2
to a maximum of 1% of the customer’s bill.
Decoupling
Mechanism to true-up revenue to a baseline amount for
residential (excluding lighting and demand) and metered non-
demand small C&I classes (pilot program ended Sept. 2023, with
amortization of previously deferred amounts expected through
2026).
DSM Cost Adjustment
Recovers electric and gas DSM, interruptible service costs and
performance incentives for achieving energy savings goals.
ECA
FCA
GCA
Recovers fuel and purchased energy costs. Short-term sales
margins are shared with customers. The ECA is revised
quarterly.
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.
Recovers costs of purchased natural gas and transportation and
is revised quarterly to allow for changes in natural gas rates.
Purchased Capacity
Cost Adjustment
RES Adjustment
Recovers purchased capacity payments.
Recovers the incremental costs of compliance with the RES with
a maximum of 1% of the customer’s bill.
Steam Cost Adjustment
Recovers fuel costs to operate the steam system. The Steam
Cost Adjustment rate is revised quarterly.
Transmission Cost
Adjustment
Recovers costs between rate cases for transmission projects
that result in a net increase in capacity or are part of an
approved wildfire mitigation plan.
Transportation
Electrification Plan
Recovers costs associated with the investment in and adoption
of transportation electrification infrastructure.
Pending and Recently Concluded Regulatory Proceedings
Colorado Electric Rate Case — In 2022, PSCo filed a Colorado electric rate
case seeking a revised net increase of $253 million. The total request
reflected a $303 million increase, which includes $50 million of authorized
costs previously recovered through various rider mechanisms. The request
was based on a 10.25% ROE, an equity ratio of 55.7% and a 2023 forecast
test year with a 2023 average rate base of $11.3 billion.
In September 2023, the CPUC approved a settlement between PSCo and
various parties, which included the following terms:
•
Retail revenue increase (excluding rider roll-ins) of $95 million
(2.96%), based on a 2022 historic test year using year-end rate base
with forward looking known and measurable adjustments.
• Weighted-average cost of capital of 6.95% (based on 55.69% equity
ratio and 9.3% ROE).
Termination of the revenue decoupling pilot.
Continuation of previously authorized trackers and deferrals.
•
•
Rates became effective in September 2023.
Colorado Resource Plan — In August 2022, the CPUC approved a
settlement for the Colorado Resource Plan, which provides for an expected
carbon reduction and the retirement of PSCo’s remaining coal plant by the
end of 2030.
(updated
in October 2023), PSCo
its
In September 2023
recommended Preferred Portfolio of resources, which proposed a total of
7,521 MW of generation resources, including 4,716 owned MW and 2,805
purchased power MW. The filing also included several other alternative
portfolios.
filed
In December 2023, the CPUC approved an alternative portfolio of 5,835
MW. The decision provides an opportunity to assess timing and levels of
incremental renewable resources in the Just Transition Plan filing expected
to be submitted by June 1, 2024.
33
Generation Resource (in MW)
Company Owned
PPAs
Total
Wind Resources
Solar
Storage
Natural Gas
Total
1,325
858
500
450
3,133
375
760
1,348
219
2,702
1,700
1,618
1,848
669
5,835
PSCo expects to invest approximately $4.8 billion in generation resources
under the alternative portfolio for the benefit of its customers and achieving
the state’s clean energy goals. The CPUC did not approve the May Valley
to Longhorn Transmission Line, which was estimated at $250 million.
In December 2023, the CPUC approved two PIMs associated with the
generation projects in the portfolio, including a two-way sharing measure
related to capital construction costs and another related to ongoing
levelized energy costs. These PIMs will be further defined in the written
order and related proceedings throughout 2024.
In February 2024, PSCo filed an ARRR to seek approval for an updated
portfolio, reflecting inclusion of certain back-up bids and clarifications of the
application of PIMs.
Colorado Natural Gas Rate Case — In January 2024, PSCo filed a request
with the CPUC seeking an increase to retail natural gas rates of $171
million, or an approximately 9.5% increase in the average residential
customer bill. The request is based on a 2023 test year, a 10.25% ROE, an
equity ratio of 55% and a $4.2 billion retail rate base which includes
projected capital additions through Dec. 31, 2023. PSCo has requested a
proposed effective date of Nov. 1, 2024.
PSCo has proposed to defer collection of the increased rates until Feb. 15,
2025 (following the expiration of the rider to recover Winter Storm Uri costs)
to mitigate customer bill impacts, with revenues for the deferred period
collected over a 12-month period beginning on that date.
The request supports fundamental infrastructure investments to serve
customers, consistent with PSCo’s obligation to provide safe, reliable
service while enabling PSCo to continue to be a leader of the clean energy
transition in partnership with the CPUC to achieve clean heat goals.
Revenue Request (millions of dollars)
Changes since 2022 rate case:
(a)
Plant related investments
Operations and maintenance, amortization and other expenses
Property tax expense
Sales growth
Total base revenue request
$
$
145
23
10
(7)
171
(a)
Includes approximately $32 million as a result of the increase in ROE from 9.2% to
10.25%.
ECA Fuel Recovery — In December 2022, PSCo filed to recover $123
million of under-recovered 2022 fuel costs over two quarters. In December
2022, the CPUC found that the $123 million should be removed from the
proposed ECA rates, and required PSCo to file a separate application to
recover these costs.
In 2023, PSCo submitted interim ECA filings to recover $70 million and $25
million, respectively, of the 2022 under-recovered costs.
In the third quarter, PSCo and CPUC Staff filed a settlement allowing for
collection of the remaining amount, which after final adjustments was $37
million. In December 2023, the ALJ issued a recommended decision
approving the settlement in full. Recovery of costs is expected to begin in
the second quarter of 2024.
Colorado Legislation — In May 2023, Colorado Senate Bill 23-291 passed
and was signed into law. The bill includes a number of topics including
natural gas and electric fuel incentive mechanisms, natural gas planning
rules, regulatory filing requirements, and non-recovery of certain expenses
(e.g., certain organizational or membership dues, tax penalties or fines).
In November 2023, the CPUC approved PSCo’s natural gas price risk
management plan, establishing upper and lower limits for changes in the
GCA rate. As a result costs above the upper limit are deferred for future
recovery, with interest, and costs below the lower limit are deferred as a
reserve against future cost increases.
The legislation also calls for the CPUC to adopt rules to establish fuel cost
mechanisms to align the financial incentives of a utility with the interests of
the utility’s customers by Jan. 1, 2025. The CPUC issued a request for
initial comments on a potential mechanism under which gas utilities would
share a percentage, subject to an annual cap, of cost changes in the GCA.
A formal rulemaking is expected to commence in the first half of 2024.
Purchased Power and Transmission Service Providers
PSCo meets its system capacity and energy requirements through its fleet
of owned and purchased electric generation resources and, when required,
the use of demand-side management programs.
Purchased Power — PSCo purchases power from other utilities, energy
marketers and independent power producers. Long-term purchased power
contracts for dispatchable resources typically require capacity and energy
charges. Much of PSCo’s long-term purchased power is for wind, solar and
storage resources. PSCo makes short-term purchases to meet system load
for
and energy
maintenance, meet operating reserve obligations, or obtain energy at a
lower cost.
replace generation out of service
requirements,
Energy Markets — PSCo joined the SPP Western Energy Imbalance
Service Market in April 2023. This market is an incremental step in the
participation in an organized wholesale market. Energy imbalance markets
allow participants to buy and sell power close to the time electricity is
consumed and gives system operators
real-time visibility across
neighboring grids. The result improves balancing supply and demand at a
lower cost.
Purchased Transmission Services —
its own
transmission system, PSCo has contracts with regional transmission
service providers to deliver energy to its customers.
In addition
to using
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 risk and hedge sales and purchases. PSCo also
engages in trading activity unrelated to these hedging activities.
Sharing of any margin is determined through state regulatory proceedings
as well as the operation of the FERC approved joint operating agreement.
34
SPS
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Regulatory Body / RTO
PUCT
NMPRC
FERC
SPP RTO and SPP
Integrated and
Wholesale Markets
Additional Information
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.
Retail electric operations, retail rates and services and the
construction of transmission or generation.
Reviews Integrated Resource Plans for meeting future energy
needs.
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.
SPS is a transmission owning member of the SPP RTO and
operates within the SPP RTO and SPP integrated and wholesale
markets. SPS is authorized to make wholesale electric sales at
market-based prices.
DOT
Pipeline safety compliance.
Recovery Mechanisms
Mechanism
Advanced Metering
System Surcharge
Consulting Fee Rider
Distribution Cost
Recovery Factor
Electric Vehicle Rider
Energy Efficiency Cost
Recovery Factor
Additional Information
Recovers costs
incurred
Metering System in Texas.
in deployment of
the Advanced
Recovers consulting fees and carrying charges incurred by SPS
on behalf of the PUCT.
Recovers distribution costs not included in rates in Texas.
Recovers costs of the Transportation Electrification Plan in New
Mexico.
Recovers costs for energy efficiency programs in Texas.
Energy Efficiency Rider
Recovers costs for energy efficiency programs in New Mexico.
Fixed Fuel and
Purchased Recovery
Factor
Fuel and Purchased
Power Cost Adjustment
Clause
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.
Adjusts monthly to recover actual fuel and purchased power
costs in New Mexico.
Generation Cost
Recovery Rider
Allows recovery of investment in power generation facilities
outside of a base rate case proceeding.
Purchased Power
Capacity Cost Recovery
Factor
Allows recovery of purchased power capacity costs not included
in Texas rates.
Renewable Portfolio
Standards
Recovers deferred costs for renewable energy programs in New
Mexico.
Transmission Cost
Recovery Factor
Wholesale Fuel and
Purchased Energy Cost
Adjustment
Recovers certain transmission infrastructure improvement costs
and changes in wholesale transmission charges not included in
Texas base rates.
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
jurisdictional
allocation of production costs.
the
Pending and Recently Concluded Regulatory Proceedings
2022 New Mexico Electric Rate Case — In 2022, SPS filed a New Mexico
electric rate case seeking a revised revenue increase of $75 million. The
request was based on a ROE of 10.75%, an equity ratio of 54.7%, a future
test year ending June 30, 2024 and rate base of $2.4 billion.
In October 2023, the NMPRC approved a settlement between SPS,
NMPRC Staff, and various parties, which included the following terms:
•
•
•
•
Base rate revenue increase of $33 million, based on the filed future
test year.
ROE of 9.5%.
Equity ratio of 54.7%.
The reflection in rates of the retirement of Tolk Generation Station
from 2034 to 2028.
Rates went into effect in October 2023.
2023 Texas Electric Rate Case — In 2023, SPS filed a Texas electric rate
case seeking an increase in base rate revenue of $158 million (14%). The
request was based on a ROE of 10.65%, an equity ratio of 54.6% and rate
base of $3.6 billion. SPS requested a surcharge from July 13, 2023 through
the effective date of new base rates.
In December 2023, SPS, PUCT Staff and intervenors filed a black box
settlement. Key terms include:
•
•
•
A base rate increase of $65 million effective back to July 13, 2023.
A 9.55% ROE, a 54.51% equity ratio and a 7.11% WACC for purposes
of calculating SPS’ allowance for funds used during construction.
The reflection in rates of the retirement of Tolk Generation Station
from 2034 to 2028.
A PUCT decision is expected in the first half of 2024.
SPS and LP&L Termination — SPS and LP&L were parties to a 25-year,
170 MW partial requirements contract serving LP&L. In May 2021, SPS and
LP&L finalized a settlement which terminated the contract upon LP&L’s
move from the SPP to the ERCOT. Based on the approved de-escalation
clause, LP&L paid SPS $66 million in January 2024 to the benefit of SPS’
remaining customers.
2022 All-Source RFP — In July 2023, SPS filed for approval of CCN for a
recommended generation portfolio, which includes 418 MW of self-build
solar projects and a 36 MW battery. A decision from PUCT and NMPRC is
expected in mid-2024.
The second portion of the portfolio includes a November 2023 filing for the
approval of PPAs including 48 MW of battery energy storage and 230 MW
of existing gas generation. Regulatory decisions on these PPA agreements
are expected in Q3 2024.
New Mexico Resource Plan — In October 2023, SPS filed its IRP with the
NMPRC, which supports projected load growth and secures replacement
energy and capacity for retiring resources. Based on load forecast
scenarios, SPS’ initial IRP modeling projects a total resource need ranging
from approximately 5,300 MW to 10,200 MW by 2030. Upon acceptance of
the IRP, SPS expects to issue an RFP for new generation in mid-2024. The
RFP will be evaluated in the latter half of 2024 with portfolio selection
expected in early 2025.
Purchased Power Arrangements and Transmission Service Providers
SPS expects to use electric generating stations, power purchases, DSM
and new generation options to meet its system capacity requirements.
Purchased Power — SPS purchases power from other utilities and IPPs.
Long-term purchased power contracts typically require periodic capacity
and energy charges. SPS also makes short-term purchases to meet
system load and energy requirements to replace owned generation, meet
operating reserve obligations or obtain energy at a lower cost.
Purchased Transmission Services — SPS has contractual arrangements
with SPP and regional transmission service providers to deliver power and
energy to its native load customers.
Natural Gas
SPS does not provide retail natural gas service, but purchases and
transports natural gas for its generation facilities and operates limited
natural gas pipeline facilities connecting the generation facilities to
interstate natural gas pipelines. SPS is subject to the jurisdiction of the
FERC with respect to natural gas transactions in interstate commerce and
the PHMSA, DOT 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 risk and to hedge sales and purchases. Sharing
of any margin is determined through state regulatory proceedings as well
as the operation of the FERC approved joint operating agreement.
Other
Supply Chain
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. Manufacturing
processes have experienced disruptions related to the scarcity of certain
raw materials and interruptions in production and shipping. Inflationary
pressures, labor shortages, and the impact of geopolitical events have
further exacerbated these disruptions. Xcel Energy continues to monitor the
situation as it remains fluid and seeks to mitigate the impacts by securing
alternative suppliers, modifying design standards, and adjusting the timing
of work.
Additionally, certain products, components, and equipment, particularly in
renewables categories, originate in countries that could face tariffs, fines, or
restrictions from government or other regulatory bodies and present a cost
and supply risk until there is sufficient capacity and supply base with
adequate capacity to meet US needs.
Electric Meters and Transformers
issues associated with semiconductors delayed
Supply chain
the
availability of AMI meters, which led to a reduced number of meters
deployed in 2022. Xcel Energy saw significant improvement in meter
availability in 2023 and we expect normal conditions in 2024 and going
forward. Xcel Energy expects to complete AMI meter deployment in 2025.
Additionally, the availability of certain transformers is an industry-wide issue
that has significantly impacted and in some cases resulted in delays to
projects and new customer connections. Proposed governmental actions
related to transformer efficiency standards may compound these delays in
the future. Xcel Energy continues to seek alternative suppliers and prioritize
work plans to mitigate the impacts of supply constraints.
Solar Resources
In August 2023, the U.S. Department of Commerce completed its anti-
circumvention investigation. It concluded that CSPV solar panels and cells
imported from Malaysia, Vietnam, Thailand, and Cambodia would be
subject to incremental tariffs ranging from 50% to 250%. These countries
account for more than 80% of CSPV panel imports.
35
An interim stay on tariffs remains in effect until June 2024. Many significant
solar projects have resumed with modified costs and projected in-service
dates, including the Sherco Solar facility in Minnesota and certain PPAs in
PSCo. Further policy action, a change in the interim stay of tariffs, or other
restrictions on solar imports (e.g., due to implementation of the Uyghur
Forced Labor Protection Act) or disruptions in solar imports from key
suppliers could impact project timelines and costs.
New Technology and Government Grants
Hydrogen Hub Grant
low-carbon hydrogen at commercial scale
In October 2023, the DOE selected the Heartland Hydrogen Hub, including
multiple clean hydrogen projects from Xcel Energy, for award negotiations
to receive up to $925 million. The Heartland Hydrogen Hub is one of seven
selected to receive DOE funding. The hub includes Xcel Energy, Marathon
Petroleum Corporation and TC Energy, in collaboration with the University
of North Dakota’s Energy & Environmental Resource Center, to produce
in Minnesota,
and use
Wisconsin, South Dakota, North Dakota and Montana. The hub aims to
reduce carbon emissions by more than 1 million metric tons per year. Xcel
Energy expects to receive a large portion of the federal award for its
projects within the hub, subject to negotiations. In its application, Xcel
Energy proposed investing up to $2 billion over a decade for clean
hydrogen producing equipment and infrastructure, representing 75% of full
program costs for the company’s portion of the hub. Project detailed design
will begin after the Heartland Hydrogen Hub finishes award negotiations.
Project development will likely continue through 2035.
Form Energy Long Duration Storage Grant
In September 2023, the DOE awarded Xcel Energy a $70 million grant to
support our two 10 MW, 100-hour battery pilots with Form Energy. Xcel
Energy expects to develop a 10 MW 100-hour-battery storage unit at the
Sherco retiring coal plant site in Minnesota and the Comanche retiring coal
plant site in Colorado. Combined with grants from Breakthrough Energy’s
Catalyst Fund, Xcel Energy has secured $90 million to support these pilots,
which will reduce the costs of the projects for our customers. Long duration
energy storage systems are critical to achieve 100% carbon free generation
and strengthen the grid from the variability of renewable energy.
Wildfire/Extreme Weather Grant
In October 2023, the DOE awarded Xcel Energy $100 million to support
projects to mitigate the threat of wildfires and ensure resiliency of the grid
through extreme weather. Xcel Energy plans to match the grant with $140
million of investment. The projects will take a number of steps to boost grid
resiliency, including adding fire-resistant coatings to 6,000 wood poles,
improving equipment safety features in power lines and electric vehicle
chargers in high fire risk conditions, moving high-risk distribution circuits
underground, and enhancing vegetation management. They will also build
on current programs using emerging technology, such as drones aided by
artificial intelligence that inspect power lines for safety, wind strength
testing, satellite identification of trees that pose a risk and modeling
software to predict how fires would spread.
Joint Targeted Interconnection Queue (JTIQ) Grant
In October 2023, the DOE awarded a $464 million grant to Xcel Energy and
several other utilities for five JTIQ projects. The projects are part of a
collaboration between MISO and SPP that will help to fund the construction
of high-voltage transmission lines that improve reliability and resolve
constraints in the transmission system for up to 30 gigawatts of new
generation. Xcel Energy is part of two of these project awards.
36
Critical Accounting Policies and Estimates
requires
the consolidated
financial statements
Preparation of
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, 2023 and 2022, Xcel Energy had regulatory assets of $3.4
billion and $3.9 billion, respectively and regulatory liabilities of $6.4 billion
and $6.0 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, 2023, in assessing the probability of recovery of recognized
regulatory assets, unless otherwise disclosed, Xcel Energy noted no
current or anticipated proposals or changes in the regulatory environment
that it expects will materially impact the recovery of the assets.
See Notes 4 and 12 to the consolidated financial statements for further
information.
Income Tax Accruals
Judgment, uncertainty and estimates are a significant aspect of the income
tax accrual process that accounts for the effects of current and deferred
income taxes. Uncertainty associated with the application of tax statutes
and regulations and outcomes of tax audits and appeals require that
judgment and estimates be made in the accrual process and in the
calculation of the ETR.
Changes in tax laws and rates may affect recorded deferred tax assets and
liabilities and our future ETR. ETR calculations are revised every quarter
based on best available year-end tax assumptions, adjusted in the following
year after returns are filed. Tax accrual estimates are trued-up to the actual
amounts claimed on the tax returns and further adjusted after examinations
by taxing authorities, as needed.
In accordance with the interim period reporting guidance, income tax
expense for the first three quarters in a year is based on the forecasted
annual ETR. The forecasted ETR reflects a number of estimates, including
forecasted annual income, permanent tax adjustments and tax credits.
Valuation allowances are applied to deferred tax assets if it is more likely
than not that at least a portion may not be realized. 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, 2023, Xcel Energy set the rate of return on assets used to
measure pension costs at 6.93%, which is unchanged from the rate set at
Dec. 31, 2022. The rate of return used to measure postretirement health
care costs is 5.00% at Dec. 31, 2023, which is unchanged from the rate set
in 2022. Xcel Energy’s pension investment strategy includes plan-specific
investments that seek to align the investment allocations to optimize risk
adjusted return and interest rate risk management based on factors that
include the plan’s funded status. This strategy generally results in a greater
percentage of interest rate sensitive securities being allocated to plans with
higher funded status ratios and a greater percentage of growth assets
being allocated to plans having lower funded status ratios.
Xcel Energy set the discount rates used to value the pension obligations
and postretirement health care obligations at 5.49% and 5.54% at Dec. 31,
2023, respectively. This represents a 31 basis point and 26 basis point
decrease, respectively, from 2022. 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 Bank of America US 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 2023 pension costs:
(Millions of Dollars)
(a)
Rate of return
Discount rate (a)
Pension Costs
+1%
-1%
$
(10) $
3
26
8
(a)
These costs include the effects of regulation.
Mortality rates are developed from actual and projected plan experience for
pension plan and postretirement benefits. Xcel Energy’s actuary conducts
an experience study periodically 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, 2023, the initial medical trend cost claim assumptions for
Pre-65 was 6.5% and Post-65 was 5.5%. 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
levels projected and
in
recommended by industry experts, as well as recent actual medical cost
experienced by Xcel Energy’s retiree medical plan.
the health care market, considering
the
Funding contributions in 2023 were $50 million and will remain relatively
consistent in future years, with the exception of 2024, when Xcel Energy
plans on making a higher contributions as a result of the Voluntary
Retirement Program offering in 2023. Investment returns were more than
the assumed levels in 2023 and 2021, but were less than the assumed
levels in 2022.
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 2023).
Xcel Energy currently projects the pension costs recognized for financial
reporting purposes will be $59 million in 2024 and $61 million in 2025, while
the actual pension costs were $74 million in 2023 and $114 in 2022. The
expected decrease in 2024 is primarily due to reductions in the effects or
regulations.
Pension funding contributions across all four of Xcel Energy’s pension
plans, both voluntary and required, for 2021 - 2024:
•
•
•
•
$100 million in January 2024.
$50 million in 2023.
$50 million in 2022.
$131 million in 2021.
37
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, $13 million and $15 million during 2023,
2022 and 2021, respectively, to the postretirement health care plans. Xcel
Energy expects to contribute approximately $11 million during 2024. Xcel
Energy recovers employee benefits costs in its utility operations consistent
with accounting guidance with the exception of the areas noted below.
•
•
•
•
•
in all
NSP-Minnesota
regulatory
recognizes pension expense
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 2021, the PSCW approved NSP-Wisconsin’s request for deferred
accounting treatment of the 2021 pension settlement accounting
expense. Escrow accounting treatment was also approved for ongoing
pension and other post-employment benefit expenses, including
settlement charges.
Regulatory Commissions
in 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 is required to create a regulatory liability that adjusts the annual
post-retirement benefits amount to zero in order to match the amount
collected in rates.
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.
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 $2.1 billion in 2023 and $2.2 billion
in 2022.
NSP-Minnesota obtains periodic independent cost studies 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 2022 - 2024 Nuclear Decommissioning Study and Assumptions were
approved by the MPUC in August 2022. The MPUC ordered the next
triennial decommissioning study be filed by December 1, 2024, allowing for
four years between filings.
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 approved retirement dates
which can be different than the expiration dates 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).
In April 2022, the Company received approval from the MPUC, in the
Integrated Resource Plan, to pursue extending the operating life of the
Monticello Nuclear Generating Plant by ten years from 2030 to 2040. This
life extension is subject to NRC approval of Monticello’s nuclear license
extension request.
The retirement dates of the Prairie Island Unit 1 and Unit 2 remain
unchanged, 2033 and 2034 respectively. The estimated timing of the
decommissioning activities is based upon the DECON method, which
assumes prompt removal and dismantlement. Decommissioning activities
are expected to begin at the commission approved retirement date and be
completed for both facilities by 2101.
Technology and Regulation — There is limited experience with actual
decommissioning of large nuclear facilities. Changes in technology,
experience and regulations could cause cost estimates
to change
significantly.
Escalation Rates — Escalation rates represent projected cost increases
due to general inflation and increases in the cost of decommissioning
activities. NSP-Minnesota used an escalation rate of 3.2% in calculating the
ARO for nuclear decommissioning of its nuclear facilities, based on
weighted averages of labor and non-labor escalation factors calculated by
Goldman Sachs Asset Management.
Discount Rates — Changes in timing or estimated cash flows that result in
upward revisions to the ARO are calculated using the then-current credit-
adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect
when the change occurs is used to discount the revised estimate of the
incremental expected cash flows of the retirement activity.
If the change in timing or estimated expected cash flows results in a
downward revision of the ARO, the undiscounted revised estimate of
expected cash flows is discounted using the credit-adjusted risk-free rate in
effect at the date of initial measurement and recognition of the original
ARO. Discount rates ranging from approximately 3% to 7% have been used
to calculate the net present value of the expected future cash flows over
time.
Significant uncertainties exist in estimating future costs including the
method to be utilized, ultimate costs to decommission and planned method
of disposing spent fuel. If different cost estimates, life assumptions or cost
escalation rates were utilized, the AROs could change materially.
38
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
risk
natural gas-related
management policy allows management to conduct these activities within
guidelines and limitations as approved by our risk management committee.
including derivatives. Our
instruments,
Fair value of net commodity trading contracts as of Dec. 31, 2023:
(Millions of Dollars)
NSP-Minnesota (a)
NSP-Minnesota (b)
PSCo (a)
PSCo (b)
(Millions of Dollars)
NSP-Minnesota (b)
PSCo (b)
Futures / Forwards Maturity
Less
Than
1 Year
1 to 3
Years
4 to 5
Years
Greater
Than
5 Years
Total
Fair Value
$
1
$
(3) $
(3) $
—
$
(1)
—
(10)
(8)
1
6
(6)
2
2
(1)
—
—
(5)
(16)
3
(2)
$
(10) $
(4) $
(5) $
(1) $
(20)
Options Maturity
Less
Than
1 Year
1 to 3
Years
4 to 5
Years
Greater
Than
5 Years
Total Fair
Value
$
$
—
$
4
4
$
—
—
—
$
$
9
$
8
$
—
—
9
$
8
$
17
4
21
(a)
(b)
Prices actively quoted or based on actively quoted prices.
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)
2023
2022
Fair value of commodity trading net contracts outstanding at Jan. 1
$ (10) $ (33)
Contracts realized or settled during the period
Commodity trading contract additions and changes during the period
(2)
13
(15)
38
Fair value of commodity trading net contracts outstanding at Dec. 31
$
1
$ (10)
A 10% increase and 10% decrease in forward market prices for Xcel
Energy’s commodity trading contracts would have likewise increased and
decreased pretax income from continuing operations, by approximately
$4 million at Dec. 31, 2023 and $8 million at Dec. 31, 2022. Market price
movements can exceed 10% under abnormal circumstances.
Xcel Energy’s’ commodity trading operations measure the outstanding risk
exposure to price changes on contracts and obligations using an industry
standard methodology known as VaR. VaR expresses the potential change
in fair value of 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 purchases 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
Average
High
Low
2023
2022
$
—
$
—
$
2
1
$
1
5
—
—
However, changes in estimates have minimal impact on results of
operations as NSP-Minnesota expects to continue to recover all costs in
future rates.
NSP-Minnesota 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
financial
statements reflect management’s best estimates and judgments of the
impact of these factors as of Dec. 31, 2023.
that becomes available. The accompanying
See Note 12 to the consolidated financial statements for further information.
Loss Contingencies – Marshall Fire
The outcomes of legal proceedings and claims brought against Xcel Energy
related to the Marshall Fire are subject to uncertainty. An estimated loss
from a loss contingency such as a legal proceeding or claim is accrued if it
is probable of being incurred and the amount of the loss can be reasonably
estimated. Each reporting period we evaluate, among other factors, the
degree of probability of an unfavorable outcome and the ability to make a
reasonable estimate of the amount of loss. The process for evaluating any
wildfire-related liabilities requires a series of complex judgments about past
and future events. Factors such as the cause of the wildfire, the extent and
magnitude of potential damages, and the status of investigations and legal
proceedings are considered. See Note 12 to the consolidated financial
statements for additional 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 for 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
on the contracts underlying our derivatives, the contracts expose us to
credit and non-performance risk.
Distress in the financial markets may impact counterparty risk and the fair
value of the securities in the nuclear decommissioning fund and pension
fund.
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 us to manage
commodity price risk within each rate-regulated operation per commission
approved hedge plans.
39
Fair Value Measurements
Derivative contracts, with the exception of those designated as normal
purchases and normal sales, 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. 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 — 2022
$
Components of change — 2023 vs. 2022
Higher net income
Non-cash transactions
Changes in working capital
Changes in net regulatory and other assets and liabilities
Cash provided by operating activities — 2023
$
3,932
35
88
900
372
5,327
Net cash provided by operating activities increased by $1,395 million for
2023 as compared to 2022. The increase was largely due to continued
collections of prior year deferred net natural gas, fuel and purchased
energy costs, as well as the impact of decreased natural gas prices on
accounts payable and receivables.
Investing Cash Flows
(Millions of Dollars)
Cash used in investing activities — 2022
Components of change — 2023 vs. 2022
Increased capital expenditures
Other investing activities
Cash used in investing activities — 2023
Twelve Months Ended Dec. 31
$
$
(4,653)
(1,216)
(57)
(5,926)
Net cash used in investing activities increased by $1,273 million for 2023 as
compared to 2022. The increase in capital expenditures was largely due to
continued system expansion.
Financing Cash Flows
(Millions of Dollars)
Twelve Months Ended Dec. 31
Cash provided by financing activities — 2022
$
Components of change — 2023 vs. 2022
Higher debt issuances, net of repayments
Lower proceeds from issuance of common stock
Higher dividends paid to shareholders
Other financing activities
Cash provided by financing activities — 2023
$
666
80
(52)
(80)
3
617
Net cash provided by financing activities decreased by $49 million for 2023
as compared to 2022. The decrease was largely related to the amount/
timing of debt issuances and repayments.
See Note 5 to the consolidated financial statements for further information.
Nuclear Fuel Supply — NSP-Minnesota has contracted for its 2024
through 2027 enriched nuclear material requirements, which are in various
stages of processing in Canada, Europe and the United States. NSP-
Minnesota is scheduled to take delivery of approximately 29% of its
average enriched nuclear material requirements from Russia through 2030.
Given the evolving situation in Ukraine and its global impacts, we have
entered
that cover potential supply
interruptions of nuclear material from Russia.
into additional new contracts
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.
A 100 basis point change in the benchmark rate on Xcel Energy’s variable
rate debt would impact pretax interest expense annually by approximately
$9 million and $8 million in 2023 and 2022, respectively.
NSP-Minnesota maintains a nuclear decommissioning fund, as required by
the NRC. The nuclear decommissioning fund is subject to interest rate and
equity price risk. The fund is invested in a diversified portfolio of debt
securities, equity securities and other investments. These investments may
be used only for the purpose of decommissioning NSP-Minnesota’s nuclear
generating plants.
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. Realized and unrealized gains on the
decommissioning fund investments are deferred as an offset of NSP-
Minnesota’s regulatory asset for nuclear decommissioning costs.
The value of pension and postretirement plan assets and benefit costs are
impacted by changes in discount rates and expected return on plan assets.
Xcel Energy’s ongoing pension and postretirement investment strategy is
based on plan-specific investment recommendations that seek to optimize
potential investment risk and minimize interest rate risk associated with
changes in the obligations as a plan’s funded status increases over time.
The impacts of fluctuations in interest rates on pension and postretirement
costs are mitigated by pension cost calculation methodologies and
regulatory mechanisms that minimize the earnings impacts of such
changes.
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 monitors these policies to reflect
changes and scope of operations.
At Dec. 31, 2023, a 10% increase in commodity prices would have resulted
in an increase in credit exposure of $27 million, while a decrease in prices
of 10% would have resulted in a decrease in credit exposure of $24 million.
At Dec. 31, 2022, a 10% increase in commodity prices would have resulted
in an increase in credit exposure of $56 million, while a decrease in prices
of 10% would have resulted in an decrease in credit exposure of $47
million.
Xcel Energy conducts credit reviews for all wholesale, trading and non-
trading commodity 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.
40
Capital Requirements
Xcel Energy has contractual obligations and other commitments that will need to be funded in the future. Xcel Energy expects to have adequate amounts of
cash from operating and financing activities to meet both its short-term and long-term cash requirements. Xcel Energy’s financing requirements are
dependent on both existing contractual obligations and other commitments, as well as projected capital forecasts. Xcel Energy expects to meet future
financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization
ratios. Projected future financing requirements can be impacted by various factors including constraints to supply chain and labor, regulatory lag and
inflation.
Material Cash Requirements and Other Commitments
(Millions of Dollars)
Long-term debt, principal and interest payments
Finance lease obligations
Operating leases obligations (a)
Unconditional purchase obligations (b) (c)
Other long-term obligations, including current portion
(d)
Other short-term obligations
Short-term debt
Total contractual cash obligations
(a)
Payments Due by Period (as of Dec. 31, 2023)
Total
Less than 1 Year
1 to 3 Years
3 to 5 Years
After 5 Years
$
43,659
$
1,567
$
3,631
$
3,564
$
34,897
218
1,520
4,022
57
591
785
10
277
1,429
18
591
785
19
509
1,267
27
—
—
16
313
686
12
—
—
173
421
640
—
—
—
$
50,852
$
4,677
$
5,453
$
4,591
$
36,131
Included in operating lease obligations are $244 million, $461 million, $269 million and $259 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively,
(b)
(c)
(d)
pertaining to PPAs that were accounted for as operating leases.
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.
Amounts exclude approximately $1 billion of minimum payments related to SPS’ extension of a non-lease PPA that otherwise expires in 2026, pending PUCT and NMPRC approvals to
extend the agreement to 2039. Approval processes are expected to conclude in 2024.
Primarily consists of contracts for information technology services.
Capital Expenditures — Base capital expenditures and incremental capital forecasts:
Total base capital expenditures
$
6,210
$
7,420
$
9,280
$
7,940
$
7,600
$
6,760
$
(a)
Other category includes intercompany transfers for safe harbor wind turbines.
Actual
2023
2024
2025
2026
2027
2028
2024 - 2028 Total
Base Capital Forecast (Millions of Dollars)
$
2,310
$
3,300
$
5,230
$
4,320
$
3,620
$
2,730
$
2,370
2,660
750
450
330
910
570
(20)
2,970
780
600
(300)
2,380
2,500
2,540
660
570
10
870
600
10
830
650
10
Actual
2023
2024
2025
2026
2027
2028
2024 - 2028 Total
Base Capital Forecast (Millions of Dollars)
$
1,320
$
1,710
$
2,020
$
2,450
$
2,850
$
2,470
$
1,730
350
780
780
1,250
1,770
1,500
940
740
760
1,960
2,910
1,290
680
420
2,200
940
1,050
630
670
2,200
240
1,060
620
630
2,470
20
600
570
630
19,200
13,050
4,050
2,990
(290)
39,000
11,500
10,600
5,610
4,940
3,240
3,110
39,000
By Regulated Utility
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Other (a)
By Function
Electric transmission
Electric distribution
Renewables
Electric generation
Natural gas
Other
Total base capital expenditures
$
6,210
$
7,420
$
9,280
$
7,940
$
7,600
$
6,760
$
The base plan does not include potential renewable generation additions at
the NSP System, SPS and PSCo, which could result in additional capital
expenditures of approximately $5 billion. Xcel Energy generally expects to
fund additional capital investment with approximately 40% equity and 60%
debt.
Xcel Energy’s capital expenditure forecast is subject to continuing review
and modification. Actual capital expenditures may vary from estimates due
to changes in electric and natural gas projected load growth, safety and
reliability needs, regulatory decisions, legislative initiatives (e.g., federal
clean energy and
tax policy), reserve requirements, availability of
purchased power, alternative plans for meeting long-term energy needs,
environmental initiatives and regulation, and merger, acquisition and
divestiture opportunities.
41
Pension Assumptions
Discount rate
Expected long-term rate of return
Capital Sources
2023
2022
5.49 %
6.93
5.80 %
6.93
Short-Term Funding Sources — Xcel Energy generally funds short-term
needs, through operating cash flows, notes payable, commercial paper and
bank lines of credit. The amount and timing of short-term funding needs
depend on construction expenditures, working capital and dividend
payments.
Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-
Wisconsin, PSCo and SPS maintain cash and short-term investment
accounts.
Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin,
PSCo and SPS each have individual commercial paper programs.
Authorized levels for these commercial paper programs are:
•
•
•
•
•
$1.50 billion for Xcel Energy Inc.
$700 million for PSCo.
$700 million for NSP-Minnesota.
$500 million for SPS.
$150 million for NSP-Wisconsin.
See Note 5 to the consolidated financial statements for further information.
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. 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. 20, 2024, Xcel Energy Inc. and its utility subsidiaries had the
following committed credit facilities available to meet liquidity needs:
(Millions of Dollars)
Xcel Energy Inc.
Facility (a)
1,500
$
Drawn (b)
486
$
Available
Cash
Liquidity
$
1,014
$
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Total
700
700
500
150
258
273
99
43
442
427
401
107
2
6
10
3
8
$
1,016
448
437
404
115
$
3,550
$
1,159
$
2,391
$ 29
$
2,420
(a)
(b)
Credit facilities expire in September 2027.
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, 2023 and 2022, Xcel Energy had approximately 555
million shares and 550 million shares of common stock outstanding,
respectively.
Xcel Energy Inc. and its utility subsidiaries have registration statements on
file with the SEC which are uncapped, permitting Xcel Energy Inc. and its
utility subsidiaries to issue debt, equity and other securities. Debt issuance
at our utility subsidiaries are subject to commission approval.
Financing for Capital Expenditures through 2028 — 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.
Current estimated financing plans of Xcel Energy for 2024 through 2028
(includes the impact of tax credit transferability):
(Millions of Dollars)
Funding Capital Expenditures
Cash from operations (a)
(b)
New debt
Equity through the DRIP and benefit program
Other equity
Base capital expenditures 2024 - 2028
Maturing Debt
(a)
Net of dividends and pension funding.
$
22,000
13,000
500
3,500
$
39,000
$
3,780
(b)
Reflects a combination of short and long-term debt; net of refinancing.
Off-Balance Sheet Arrangements
Xcel Energy does not have any off-balance-sheet arrangements, other than
those currently disclosed, that have or are reasonably likely to have a
current or future effect on financial condition, changes in financial condition,
revenues or expenses, results of operations, liquidity, capital expenditures
or capital resources that is material to investors.
Common Stock Dividends — Future dividend levels will be dependent on
Xcel Energy’s results of operations, financial condition, cash flows,
reinvestment opportunities and other factors, and will be evaluated by the
Xcel Energy Inc. Board of Directors. In February 2024, Xcel Energy
announced an increase in the annual dividend of 11 cents per share, which
represents an increase of 5.3%.
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)
Fair value of pension assets
Projected pension obligation (a)
Funded status
Dec. 31, 2023
Dec. 31, 2022
$
$
2,690
$
2,943
(253) $
2,685
2,871
(186)
(a)
Excludes non-qualified plan of $12 million and $11 million at Dec. 31, 2023 and 2022,
respectively.
42
Planned Financing Activity — Xcel Energy’s 2024 financing plans reflect
the following:
Issuer
Security
Xcel Energy Inc.
Senior Unsecured
Notes
Amount
(Millions of
Dollars)
Anticipated
Timing
Expected
Tenor
$
900 First Quarter
10 Year
PSCo
First Mortgage Bonds
1,200 Second Quarter
10 Year and
30 Year
NSP-Minnesota
First Mortgage Bonds
SPS
First Mortgage Bonds
NSP-Wisconsin
First Mortgage Bonds
700
550
400
First Quarter
30 Year
Second Quarter
30 Year
Second Quarter
30 Year
Issuances and Other Financing
Long-Term Borrowings, Equity
Instruments — Xcel Energy may issue equity through its at-the-market
program or other offerings. Financing plans are subject to change,
depending on capital expenditures, regulatory outcomes, internal cash
generation, market conditions, changes in tax policies and other factors.
Long-Term EPS and Dividend Growth Rate Objectives — Xcel Energy
expects to deliver an attractive total return to our shareholders through a
combination of earnings growth and dividend yield, based on the following
long-term objectives:
• Deliver long-term annual EPS growth of 5% to 7% based off of a 2023
actual ongoing earnings base of $3.35 per share.
Deliver annual dividend increases of 5% to 7%.
Target a dividend payout ratio of 50% to 60%.
•
•
• Maintain senior secured debt credit ratings in the A range.
ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
See the “Derivatives, Risk Management and Market Risk” section in Item 7,
incorporated by reference.
ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See Note 5 to the consolidated financial statements for further information.
See Item 15-1 for an index of financial statements included herein.
Earnings Guidance and Long-Term EPS and Dividend Growth Rate
Objectives
Xcel Energy 2024 Earnings Guidance — Xcel Energy’s 2024 ongoing
earnings guidance is a range of $3.50 to $3.60 per share.(a)
Key assumptions as compared with 2023 actual levels unless noted:
See Note 15 to the consolidated financial statements for further information.
•
Constructive outcomes in all pending rate case and regulatory
proceedings.
Normal weather patterns for the remainder of the year.
•
• Weather-normalized retail electric sales are projected to increase 2%
to 3%.
• Weather-normalized retail firm natural gas sales are projected to be
•
•
•
•
•
•
•
(a)
flat.
Capital rider revenue is projected to increase $70 million to $80 million
(net of PTCs).
O&M expenses are projected to increase 1% to 2%.
Depreciation expense is projected to increase approximately $250
million to $260 million.
Property taxes are projected to increase $50 million to $60 million.
Interest expense (net of AFUDC - debt) is projected to increase $130
million to $140 million, net of interest income.
AFUDC - equity is projected to increase $45 million to $55 million.
ETR is projected to be ~(4%) to (6%). The negative ETR is largely
offset by PTCs flowing back to customers in the capital riders and fuel
mechanisms and is largely earnings neutral. The projected ETR does
not reflect the potential impact of nuclear PTCs, which are also
expected to flow back to customers.
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. As Xcel Energy is unable to quantify the
financial impacts of any additional adjustments that may occur for the year, we are
unable to provide a quantitative reconciliation of the guidance for ongoing EPS to
corresponding GAAP EPS.
43
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, 2023. 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, 2023, 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 attestation report on Xcel Energy Inc.’s internal control over financial
reporting. Its report appears herein.
/s/ ROBERT C. FRENZEL
Robert C. Frenzel
Chairman, President, Chief Executive Officer and Director
Feb. 21, 2024
/s/ BRIAN J. VAN ABEL
Brian J. Van Abel
Executive Vice President, Chief Financial Officer
Feb. 21, 2024
44
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, 2023 and 2022,
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, 2023, 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, 2023, 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,
2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, 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, 2023, 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.
45
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 recovery in future rates of incurred costs and refunds due to customers. Given that
management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments
required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
• We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as
regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness
of management’s controls over the recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that
may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
• We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
• We read relevant regulatory orders issued by the Commissions for the Company, other regulatory filings, legal decisions and recommendations
being evaluated by the Commissions, and other publicly available information to assess the likelihood of recovery in future rates or of a future
reduction in rates. We evaluated historic orders for precedents of the Commissions’ treatment of similar costs under similar circumstances. We
compared the regulatory orders, filings and other publicly available information to the Company’s recorded regulatory assets and liabilities for
completeness.
• We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet
addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 21, 2024
We have served as the Company’s auditor since 2002.
46
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(amounts in millions, except per share data)
Operating revenues
Electric
Natural gas
Other
Total operating revenues
Operating expenses
Electric fuel and purchased power
Cost of natural gas sold and transported
Cost of sales — other
Operating and maintenance expenses
Conservation and demand side management expenses
Depreciation and amortization
Taxes (other than income taxes)
Loss on Comanche Unit 3 litigation
Workforce reduction expenses
Total operating expenses
Operating income
Other income (expense), net
Earnings from equity method investments
Allowance for funds used during construction — equity
Interest charges and financing costs
Interest charges — includes other financing costs of $32, $31 and $29, respectively
Allowance for funds used during construction — debt
Total interest charges and financing costs
Income before income taxes
Income tax benefit
Net income
Weighted average common shares outstanding:
Basic
Diluted
Earnings per average common share:
Basic
Diluted
Year Ended Dec. 31
2023
2022
2021
$
11,446
$
12,123
$
2,645
115
14,206
4,278
1,456
49
2,444
286
2,448
657
35
72
3,080
107
15,310
5,005
1,910
44
2,491
331
2,413
688
—
—
11,205
2,132
94
13,431
4,733
1,081
38
2,321
304
2,121
630
—
—
11,725
12,882
11,228
2,481
2,428
2,203
22
35
91
1,055
(51)
1,004
1,625
(146)
(13)
36
75
953
(28)
925
1,601
(135)
$
1,771
$
1,736
$
552
552
547
547
$
3.21
$
3.21
3.18
$
3.17
5
62
73
842
(26)
816
1,527
(70)
1,597
539
540
2.96
2.96
See Notes to Consolidated Financial Statements
47
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(amounts in millions)
Net income
Other comprehensive income
Pension and retiree medical benefits:
Net pension and retiree medical (losses) gains arising during the period, net of tax
Reclassification of losses to net income, net of tax
Derivative instruments:
Net fair value (decrease) increase, net of tax
Reclassification of losses to net income, net of tax
Total other comprehensive (loss) income
Total comprehensive income
Year Ended Dec. 31
2023
2022
2021
$
1,771
$
1,736
$
1,597
(4)
2
(2)
3
(1)
5
4
16
5
30
—
8
4
6
18
1,615
See Notes to Consolidated Financial Statements
$
1,770
$
1,766
$
48
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in millions)
Operating activities
Net income
Adjustments to reconcile net income to cash provided by operating activities:
2023
Year Ended Dec. 31
2022
2021
$
1,771
$
1,736
$
1,597
Depreciation and amortization
Nuclear fuel amortization
Deferred income taxes
Allowance for equity funds used during construction
Earnings from equity method investments
Dividends from equity method investments
Provision for bad debts
Share-based compensation expense
Changes in operating assets and liabilities:
Accounts receivable
Accrued unbilled revenues
Inventories
Other current assets
Accounts payable
Net regulatory assets and liabilities
Other current liabilities
Pension and other employee benefit obligations
Other, net
Net cash provided by operating activities
Investing activities
Capital/construction expenditures
Purchase of investment securities
Proceeds from the sale of investment securities
Other, net
Net cash used in investing activities
Financing activities
(Repayments of) proceeds from short-term borrowings, net
Proceeds from issuances of long-term debt
Repayments of long-term debt
Proceeds from issuance of common stock
Dividends paid
Other, net
Net cash provided by financing activities
Net change in cash and cash equivalents
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)
Cash received (paid) for income taxes, net
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions
Inventory transfers to property, plant and equipment
Operating lease right-of-use assets
Allowance for equity funds used during construction
Issuance of common stock for reinvested dividends and/or equity awards
See Notes to Consolidated Financial Statements
49
2,471
96
(59)
(91)
(35)
35
79
25
(27)
252
(98)
86
(149)
911
200
17
(157)
5,327
(5,854)
(994)
959
(37)
(5,926)
(28)
2,630
(1,151)
270
(1,092)
(12)
617
2,436
118
(140)
(75)
(36)
37
73
20
(429)
(243)
(203)
(58)
195
570
102
(49)
(122)
3,932
(4,638)
(1,332)
1,297
20
(4,653)
(192)
2,164
(601)
322
(1,012)
(15)
666
$
$
$
18
111
129
$
(55)
166
111
$
(945) $
92
(887) $
(15)
$
553
197
238
91
64
$
626
78
141
75
57
2,143
114
(79)
(73)
(62)
42
60
31
(164)
(149)
(126)
(34)
138
(973)
(1)
(135)
(140)
2,189
(4,244)
(757)
743
(29)
(4,287)
421
2,710
(417)
366
(935)
(10)
2,135
37
129
166
(788)
(4)
501
87
8
73
60
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in millions, except share and per share)
Assets
Current assets
Cash and cash equivalents
Accounts receivable, net
Accrued unbilled revenues
Inventories
Regulatory assets
Derivative instruments
Prepaid taxes
Prepayments and other
Total current assets
Property, plant and equipment, net
Other assets
Nuclear decommissioning fund and other investments
Regulatory assets
Derivative instruments
Operating lease right-of-use assets
Other
Total other assets
Total assets
Liabilities and Equity
Current liabilities
Current portion of long-term debt
Short-term debt
Accounts payable
Regulatory liabilities
Taxes accrued
Accrued interest
Dividends payable
Derivative instruments
Operating lease liabilities
Other
Total current liabilities
Deferred credits and other liabilities
Deferred income taxes
Deferred investment tax credits
Regulatory liabilities
Asset retirement obligations
Derivative instruments
Customer advances
Pension and employee benefit obligations
Operating lease liabilities
Other
Total deferred credits and other liabilities
Commitments and contingencies
Capitalization
Long-term debt
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 554,941,703 and 549,578,018 shares outstanding at Dec. 31, 2023
and Dec. 31, 2022, respectively
Additional paid in capital
Retained earnings
Accumulated other comprehensive loss
Total common stockholders’ equity
Total liabilities and equity
See Notes to Consolidated Financial Statements
50
Dec. 31
2023
2022
$
129
1,315
853
711
611
104
52
294
4,069
111
1,373
1,105
803
1,059
279
54
360
5,144
51,642
48,253
$
$
3,599
2,798
76
1,217
678
8,368
64,079
552
785
1,668
528
557
251
289
74
226
722
5,652
4,885
60
5,827
3,218
86
167
469
1,038
148
15,898
24,913
1,387
8,465
7,858
(94)
17,616
64,079
$
3,234
2,871
93
1,204
389
7,791
61,188
1,151
813
1,804
418
569
217
268
76
217
545
6,078
4,756
48
5,569
3,380
113
181
390
1,038
147
15,622
22,813
1,374
8,155
7,239
(93)
16,675
61,188
$
$
$
$
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
(amounts in millions, except per share data; shares in actual amounts)
Common Stock Issued
Shares
Par Value
Additional Paid
In Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Loss
Total Common
Stockholders’
Equity
Balance at Dec. 31, 2020
537,438,394
$
1,344
$
7,404
$
5,968
$
(141) $
14,575
Net income
Other comprehensive income
Dividends declared on common stock ($1.83 per share)
Issuances of common stock
Share-based compensation
Balance at Dec. 31, 2021
Net Income
Other comprehensive loss
Dividends declared on common stock ($1.95 per share)
Issuances of common stock
Share-based compensation
Balance at Dec. 31, 2022
Net income
Other comprehensive income
Dividends declared on common stock ($2.08 per share)
Issuances of common stock
Share-based compensation
Balance at Dec. 31, 2023
6,586,875
16
387
12
1,597
(989)
(4)
18
1,597
18
(989)
403
8
544,025,269
$
1,360
$
7,803
$
6,572
$
(123) $
15,612
5,552,749
14
345
7
1,736
(1,066)
(3)
30
1,736
30
(1,066)
359
4
549,578,018
$
1,374
$
8,155
$
7,239
$
(93) $
16,675
5,363,685
13
295
15
1,771
(1,148)
(4)
(1)
1,771
(1)
(1,148)
308
11
554,941,703
$
1,387
$
8,465
$
7,858
$
(94) $
17,616
See Notes to Consolidated Financial Statements
51
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 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:
Nonregulated Subsidiary
Purpose
Eloigne
Capital Services
Xcel Energy Venture
Holdings, Inc.
Nicollet Project Holdings
Invests in rental housing projects that qualify for low-income
housing tax credits.
Procures equipment for construction of renewable
generation facilities at other subsidiaries.
Invests in limited partnerships, including EIP funds with
portfolios of investments in energy technology companies.
Invests in nonregulated assets such as the Minnesota
community solar gardens.
Xcel Energy Inc. owns the following additional direct subsidiaries, some of
which are intermediate holding companies with additional subsidiaries:
Direct Subsidiary
Xcel Energy Wholesale Group Inc.
Xcel Energy Markets Holdings Inc.
Xcel Energy Ventures Inc.
Xcel Energy Retail Holdings Inc.
Xcel Energy Communication Group Inc.
Xcel Energy International Inc.
Xcel Energy Transmission Holding Company, LLC
Nicollet Holdings Company, LLC
Xcel Energy Nuclear Services Holdings, LLC
Xcel Energy Services Inc.
Xcel Energy and its subsidiaries collectively are referred to as Xcel Energy.
Xcel Energy’s consolidated financial statements include its wholly-owned
subsidiaries and VIEs
the primary beneficiary. All
it
intercompany transactions and balances are eliminated unless a different
treatment is appropriate for rate regulated transactions. The equity method
of accounting is used for its investments in EIP funds and WYCO.
for which
is
Investments in certain plants and transmission facilities are jointly owned
with nonaffiliated utilities. A proportionate share of jointly owned facilities is
recorded as property, plant and equipment on the consolidated balance
sheets, and Xcel Energy’s share of operating costs associated with these
facilities is included in the consolidated statements of income.
The 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.
52
Xcel Energy has evaluated events occurring after Dec. 31, 2023 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 to record transactions and balances resulting from
business operations.
regulatory assets and
Estimates are used for items such as plant depreciable lives or potential
disallowances, AROs, certain
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.
liabilities,
Regulatory Accounting — The 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 and assumptions for recovery of deferred costs and refund of
deferred credits are based on specific ratemaking decisions, precedent or
other available information. 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. 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 consolidated financial statements. Income taxes are
deferred for all temporary differences between pretax financial and taxable
income and between the book and tax bases of assets and liabilities
utilizing 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.
Utility rate regulation has resulted in the recognition of regulatory assets
and liabilities related to income taxes. 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, refundable to utility
customers over the remaining life of the related assets.
Xcel Energy anticipates that a tax rate increase would predominantly result
in the establishment of a regulatory asset, subject to an evaluation of
whether future recovery is expected.
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 over the book depreciable lives of related
property. The requirement to defer and amortize these credits specifically
applies to certain federal ITCs, as determined by tax regulations and Xcel
Energy tax elections. For tax credits otherwise eligible to be recognized
when earned, Xcel Energy considers the impact of rate regulation to
determine if these credits and related adjustments should be deferred as
regulatory assets or liabilities.
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. This evaluation includes consideration of whether tax credits are
expected to be sold at a discount and impact the realization of amounts
presented as deferred tax assets. Transferable tax credits are accounted
for under ASC 740 Income Taxes, and valuation allowances and any
adjustments for discounts incurred on sales transactions are recorded to
deferred tax expense, typically recovered in the utility subsidiaries’
regulatory mechanisms.
Xcel Energy measures and discloses uncertain tax positions that it has
taken or expects to take in its income tax returns. A tax position is
recognized in the 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.
Interest and penalties related to income taxes are reported within Other
income (expense), net or interest charges in the consolidated statements of
income.
Xcel Energy Inc. and its subsidiaries file consolidated federal income tax
returns as well as consolidated or separate state income tax returns.
Federal income taxes paid by Xcel Energy Inc. are allocated to its
subsidiaries based on separate company computations. A similar allocation
is made for state income taxes paid by Xcel Energy Inc. in connection with
consolidated state filings. Xcel Energy Inc. also allocates its own income
tax benefits to its direct subsidiaries.
See Note 7 for further information.
in Regulated
Property, Plant and Equipment and Depreciation
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 and replacement of items determined to be less than a
unit of property are charged to expense as incurred.
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.
Depreciation expense is recorded using the straight-line method over the
plant’s commission approved useful life. Actuarial life studies are performed
and submitted to the state and federal commissions for review. Upon
acceptance by the various commissions, the resulting lives and net salvage
rates are used to calculate depreciation. Plant removal costs are typically
recognized at the amounts recovered in rates as authorized by the
applicable regulator. 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 3.6% for 2023, 3.7% for 2022 and 3.5% for 2021.
See Note 3 for further information.
AROs — Xcel Energy records AROs as a liability in the period incurred (if
fair value can be reasonably estimated), with the offsetting/associated 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 typically depreciated over the useful life of the long-
lived asset. Changes resulting from revisions to timing or amounts 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 normally performed at least every three years and submitted to
the state commissions for approval. Due to other regulatory activity, the
next decommissioning study has been deferred one year until 2024.
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 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.
53
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 amount can be
reasonably estimated. Costs are deferred as a regulatory asset if it is
probable the costs will be recovered from customers in future rates.
Otherwise, the costs are expensed. For certain environmental costs related
to facilities currently in use, such as for emission-control equipment, the
cost is capitalized and depreciated over the life of the plant.
Estimated remediation costs are regularly adjusted as estimates are
revised and remediation is performed. 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.
Estimated future expenditures to restore 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
is
reading are estimated, and
recognized.
the corresponding unbilled revenue
A separate financing component of collections from customers is not
recognized as contract terms are short-term in nature. Revenues are 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 RTO/ISOs are also
recorded on a gross basis. Other revenues and charges settled/facilitated
through an RTO/ISO 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, 2023 and 2022, the allowance for bad debts was $128
million and $122 million, respectively.
Inventory — Inventory is recorded at the lower of average cost or net
realizable value and consisted of the following:
(Millions of Dollars)
Inventories
Materials and supplies
Fuel
Natural gas
Total inventories
Dec. 31, 2023
Dec. 31, 2022
$
$
377
$
211
123
711
$
330
201
272
803
Equity Method Investments — The equity method of accounting is used
for certain investments including WYCO and EIP funds, which requires Xcel
Energy’s recognition of its share of these investees’ results, based on Xcel
Energy’s proportional ownership interest. For investments in EIP funds, this
includes Xcel Energy’s share of fund expenses and realized gains and
losses, as well as unrealized gains and losses resulting from valuations of
the funds’ investments in emerging energy technology companies.
Fair Value Measurements — Xcel Energy presents cash equivalents,
interest rate derivatives, rabbi trust assets, commodity derivatives, pension
and postretirement plan assets and nuclear decommissioning fund assets
at estimated fair values in its consolidated financial statements.
For interest rate derivatives, quoted prices based primarily on observable
market interest rate curves are used to estimate 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,
quoted prices for similar contracts or internally prepared valuation models
may be used to determine fair value.
For rabbi trust assets, pension and postretirement plan assets and nuclear
decommissioning fund assets, published trading data and pricing models,
generally using the most observable inputs available, are utilized to
determine fair value for each security.
See Notes 10 and 11 for further information.
Derivative Instruments — Xcel Energy uses derivative instruments in
connection with its commodity trading activities, and to manage risk
associated with changes in interest rates and utility commodity prices,
including forward contracts, futures, swaps and options. Derivatives 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.
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 they contain a
derivative, and if so, whether they may be exempted from derivative
accounting if designated as normal purchases or normal sales.
See Note 10 for further information.
54
Cost of RECs that are utilized to support commodity trading activities are
recorded in a similar manner as the associated commodities and are
presented on a net basis in electric operating revenues in the consolidated
statements of income.
2. Accounting Pronouncements
Recently Issued
the existing
requirements
Segment Reporting — In November 2023, the FASB issued ASU 2023-07
– Segment Reporting (Topic 280) – Improvements to Reportable Segment
Disclosures, which extends
for annual
disclosures to quarterly periods, and requires that both annual and
quarterly disclosures present segment expenses using line items consistent
with information regularly provided to the chief operating decision maker.
The ASU is effective for annual periods beginning after Dec. 15, 2023 and
quarterly periods beginning after Dec. 15, 2024, and Xcel Energy does not
expect implementation of the new disclosure guidance to have a material
impact to its consolidated financial statements.
Income Taxes — In December 2023, the FASB issued ASU 2023-09 –
Income Taxes (Topic 740) – Improvements to Income Tax Disclosures, with
new disclosure requirements including presentation of prescribed line items
in the effective tax rate reconciliation and disclosures regarding state and
local tax payments. The ASU is effective for annual periods beginning after
Dec. 15, 2024, and Xcel Energy does not expect implementation of the new
disclosure guidance to have a material impact to its consolidated financial
statements.
3. Property, Plant and Equipment
Major classes of property, plant and equipment
(Millions of Dollars)
Dec. 31, 2023
Dec. 31, 2022
Property, plant and equipment, net
Electric plant
Natural gas plant
Common and other property
Plant to be retired (a)
CWIP
Total property, plant and equipment
Less accumulated depreciation
Nuclear fuel
Less accumulated amortization
$
52,494
$
49,639
9,080
3,190
2,055
2,873
69,692
(18,399)
3,337
(2,988)
8,514
2,970
2,217
2,124
65,464
(17,502)
3,183
(2,892)
Property, plant and equipment, net
$
51,642
$
48,253
Amounts include Sherco 1 and 3 and A.S. King for NSP-Minnesota; Comanche Units 2
and 3, Craig Units 1 and 2, Hayden Units 1 and 2 and coal generation assets at Pawnee
pending facility gas conversion for PSCo; and Tolk Unit 1 and 2 and coal generation
assets at Harrington pending facility gas conversion for SPS. The Dec. 31, 2022 balance
also includes Sherco 2, which was retired on Dec. 31, 2023. Amounts are presented net
of accumulated depreciation.
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
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 and 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.
Alternative Revenue — Certain rate rider mechanisms (including
decoupling/sales true up and CIP/DSM programs) qualify as alternative
revenue programs. These mechanisms arise from instances in which the
regulator authorizes a future surcharge in response to past activities or
completed events. When certain criteria are met, including expected
collection within 24 months, revenue is recognized, 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.
Emissions Allowances — Emissions allowances are recorded at cost,
including broker commission fees. The inventory accounting model is
utilized for all emissions allowances and any sales of these allowances are
included in electric revenues.
(a)
Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and
amortization method for nuclear refueling costs. This method amortizes
costs over the period between refueling outages consistent with rate
recovery.
RECs — Cost of RECs that are utilized for compliance is recorded as
electric fuel and purchased power expense. In certain jurisdictions, Xcel
Energy reduces recoverable fuel and purchased power costs for the cost of
RECs received.
An inventory accounting model is used to account for RECs, however these
assets are classified as regulatory assets if amounts are recoverable in
future rates.
Sales of RECs are recorded in electric revenues on a gross basis. The cost
of these RECs and amounts credited to customers under margin-sharing
mechanisms are recorded in electric fuel and purchased power expense.
55
Joint Ownership of Generation, Transmission and Gas Facilities
The utility subsidiaries’ jointly owned assets as of Dec. 31, 2023:
(Millions of Dollars, Except Percent Owned)
Plant in
Service
Accumulated
Depreciation
Percent
Owned
NSP-Minnesota
Electric generation:
Sherco Unit 3
Sherco common facilities
Sherco substation
Electric transmission:
Grand Meadow
Huntley Wilmarth
CapX2020
$
633
$
185
5
11
49
820
Total NSP-Minnesota
(a)
$
1,703
$
(a)
Projects additionally include $2 million in CWIP.
59 %
80
59
50
50
51
480
121
4
4
2
141
752
(Millions of Dollars, Except Percent Owned)
Plant in
Service
Accumulated
Depreciation
Percent
Owned
NSP-Wisconsin
Electric transmission:
La Crosse, WI to Madison, WI
CapX2020
Total NSP-Wisconsin
(a)
$
$
178
$
169
347
$
25
39
64
37 %
80
(a)
Projects additionally include $1 million in CWIP.
(Millions of Dollars, Except Percent Owned)
Plant in
Service
Accumulated
Depreciation
Percent
Owned
PSCo
Electric generation:
Hayden Unit 1
Hayden Unit 2
Hayden common facilities
Craig Units 1 and 2
Craig common facilities
Comanche Unit 3
Comanche common facilities
Electric transmission:
Transmission and other facilities
Gas transmission:
Rifle, CO to Avon, CO
Gas transmission compressor
Total PSCo
(a)
$
157
$
108
76 %
151
44
82
39
916
29
189
28
8
87
31
55
25
191
4
37
53
10
7
67
77
75
Various
9
2
60
50
$
1,643
$
587
(a)
Projects additionally include $18 million in CWIP.
Each company’s share of operating expenses and construction
expenditures is included in the applicable utility accounts. Respective
owners are responsible for providing their own financing.
56
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)
Regulatory Assets
Pension and retiree medical obligations
Recoverable deferred taxes on AFUDC
Net AROs
(b)
Excess deferred taxes — TCJA
Depreciation differences
Environmental remediation costs
Deferred natural gas, electric, steam energy/fuel costs
Conservation programs (c)
Purchased power contract costs
PI extended power uprate
Benson biomass PPA termination and asset purchase
Sales true-up and revenue decoupling
State commission adjustments
Losses on reacquired debt
MISO capacity revenue tracker
Gas pipeline inspection and remediation costs
Contract valuation adjustments (d)
Nuclear refueling outage costs
Grid modernization costs
Renewable resources and environmental initiatives
Other
Total regulatory assets
See Note(s)
Remaining Amortization
Period
Dec. 31, 2023
Dec. 31, 2022
(a)
Current
Noncurrent
Current
Noncurrent
11
Various
Plant lives
1, 12
Various
7
Various
One to 12 years
1, 12
Various
One to three years
1 One to two years
Term of related contract
11 years
Five years
One to two years
Plant lives
Term of related debt
One to two years
One to two years
1, 10
Term of related contract
1 One to two years
One to two years
One to two years
Various
$
27
—
—
10
17
15
239
19
4
4
10
7
1
2
36
40
18
43
16
38
65
$
1,106
$
332
316
198
189
94
80
54
40
38
36
33
32
30
26
25
22
19
17
5
22
—
—
13
17
20
581
16
10
4
10
54
1
3
—
42
28
30
14
50
106
144
$
1,069
292
339
205
193
92
299
36
36
42
45
—
33
32
—
13
28
12
24
6
75
$
611
$
2,798
$
1,059
$
2,871
(a)
(b)
(c)
(d)
Prior period amounts have been reclassified to conform with current year presentation.
The 2022 amount is net of the nuclear decommissioning accruals and gains from decommissioning investments. In 2023, the nuclear decommissioning accruals and gains from
decommissioning investments exceeded the expected cost of AROs in NSP-Minnesota and was reclassified to a regulatory liability.
Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
57
Components of regulatory liabilities:
(Millions of Dollars)
Regulatory Liabilities
Deferred income tax adjustments and TCJA refunds
(a)
Plant removal costs
Effects of regulation on employee benefit costs (b)
Renewable resources and environmental initiatives
Net AROs
(c)
Sales true-up and revenue decoupling
ITC deferrals
LP&L departure payment
Formula rates
DOE settlement
Deferred natural gas, electric, steam energy/fuel costs
(d)
Contract valuation adjustments
Conservation programs (e)
Other
Total regulatory liabilities (f)
See Note(s)
Remaining Amortization
Period
Dec. 31, 2023
Dec. 31, 2022
Current
Noncurrent
Current
Noncurrent
7
Various
1, 12
Various
Various
Various
Various
Two years
1
Various
Up to 10 years
One to two years
One to two years
Less than one year
1, 10
Less than one year
1
Less than one year
Various
$
7
$
3,015
$
9
$
—
—
9
—
18
1
33
29
18
220
56
47
90
1,984
253
188
90
76
60
33
18
6
—
—
—
104
—
—
6
—
—
1
—
32
12
39
175
72
72
3,110
1,819
247
173
—
77
61
—
17
3
—
1
—
61
$
528
$
5,827
$
418
$
5,569
(a)
(b)
(c)
(d)
(e)
(f)
Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes due to the TCJA.
Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset.
Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion.
Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
Revenue subject to refund of $187 million and $67 million for 2023 and 2022, respectively, is included in other current liabilities.
Xcel Energy’s regulatory assets not earning a return include past expenditures of $1,085 million and $1,020 million at Dec. 31, 2023 and 2022 respectively,
which predominately relate to purchased natural gas and electric energy costs (including certain costs related to Winter Storm Uri), sales true-up and
revenue decoupling, various renewable resources/environmental initiatives and certain prepaid pension amounts. Additionally, the unfunded portion of
pension and retiree medical obligations and net AROs (i.e. deferrals for which cash has not been disbursed) do not earn a return.
5. Borrowings and Other Financing Instruments
Short-Term Borrowings
Short-Term Debt — Xcel Energy meets
liquidity
requirements primarily through the issuance of commercial paper and
borrowings under their credit facilities and term loan agreements.
its short-term
Commercial paper and other borrowings outstanding:
(Millions of Dollars, Except
Interest Rates)
Three Months
Ended Dec. 31,
2023
Year Ended Dec. 31
2023
2022
2021
Borrowing limit
$
3,550
$ 3,550
$ 3,550
$ 3,100
Amount outstanding at period end
Average amount outstanding
Maximum amount outstanding
Weighted average interest rate,
computed on a daily basis
Weighted average interest rate at
period end
785
339
785
785
491
1,241
813
552
1,357
1,005
1,399
2,054
5.51 %
5.12 %
1.47 %
0.57 %
5.52
5.52
4.66
0.31
Bilateral Credit Agreement —
In April 2023, NSP-Minnesota’s
uncommitted bilateral credit agreement was renewed for an additional one-
year term. The credit agreement is limited in use to support letters of credit.
As of Dec. 31, 2023, NSP-Minnesota had $65 million outstanding letters of
credit under the $75 million Bilateral Credit Agreement.
to provide
Letters of Credit — Xcel Energy uses letters of credit, typically with terms
of one year,
for certain operating
obligations. As of Dec. 31, 2023 and 2022, there were $44 million and $43
million of letters of credit outstanding under the credit facilities, respectively.
Amounts approximate their fair value.
financial guarantees
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 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 September 2022, Xcel Energy Inc., NSP-
Minnesota, NSP-Wisconsin, PSCo and SPS each entered into an amended
five-year credit agreement with a syndicate of banks. The aggregate
borrowing limit is $3.55 billion. The amended credit agreements mature in
September 2027.
58
Features of the credit facilities:
Debt-to-Total
Capitalization Ratio
(a)
Amount
Facility May Be
Increased
(millions of
dollars) (b)
Additional Periods
for Which a One-
Year Extension May
Be Requested (c)
(d)
Xcel Energy Inc.
NSP-Minnesota
NSP-Wisconsin
SPS
PSCo
2023
2022
59.8 %
59.7 % $
47.7
48.2
46.1
44.8
47.7
47.4
45.7
44.0
350
150
N/A
50
100
2
2
1
2
2
(a)
(b)
(c)
(d)
Each credit facility has a financial covenant requiring that the debt-to-total capitalization
ratio be less than or equal to 65%.
Amounts authorized by state commissions in respective jurisdictions.
All extension requests are subject to majority bank group approval.
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, 2023, 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, 2023:
(Millions of Dollars)
Xcel Energy Inc.
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Total
$
Credit Facility
$
(a)
1,500
700
700
500
150
3,550
Drawn (b)
Available
$
$
165
349
180
75
60
829
$
$
1,335
351
520
425
90
2,721
(a)
(b)
These credit facilities mature in September 2027.
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, 2023 and 2022.
Long-Term Borrowings and Other Financing Instruments
Generally, the property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
is subject to the liens of their respective first mortgage indentures for the
benefit of bondholders.
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 (in millions of dollars):
Xcel Energy Inc.
Financing Instrument
Interest
Rate
Maturity Date
2023
2022
Unsecured senior notes
Unsecured senior notes
Unsecured senior notes
Unsecured senior notes
Unsecured senior notes
Unsecured senior notes
Unsecured senior notes
Unsecured senior notes
Unsecured senior notes
Unsecured senior notes
Unsecured senior notes
Unsecured senior notes (b)
Unsecured senior notes
(a)
Unsecured senior notes
Unsecured senior notes
Unamortized discount
Unamortized debt issuance cost
Current maturities
Total long-term debt
(a)
2022 financing.
(b)
2023 financing.
0.50 %
Oct. 15, 2023
$
—
$
3.30
3.30
3.35
1.75
4.00
4.00
2.60
3.40
2.35
4.60
5.45
6.50
4.80
3.50
June 1, 2025
June 1, 2025
Dec. 1, 2026
March 15, 2027
June 15, 2028
June 15, 2028
Dec. 1, 2029
June 1, 2030
Nov. 15, 2031
June 1, 2032
Aug. 15, 2033
July 1, 2036
Sept. 15, 2041
Dec. 1, 2049
250
350
500
500
130
500
500
600
300
700
800
300
250
500
(8)
(36)
—
500
250
350
500
500
130
500
500
600
300
700
—
300
250
500
(7)
(35)
(500)
$
6,136
$
5,338
NSP-Minnesota
Financing Instrument
Interest
Rate
Maturity Date
2023
2022
2.60 %
May 15, 2023
$
—
$
7.125
July 1, 2025
6.50
2.25
5.25
6.25
6.20
5.35
4.85
3.40
March 1, 2028
April 1, 2031
July 15, 2035
June 1, 2036
July 1, 2037
Nov. 1, 2039
Aug. 15, 2040
Aug. 15, 2042
4.125
May 15, 2044
4.00
3.60
3.60
2.90
2.60
3.20
4.50
5.10
Aug. 15, 2045
May 15, 2046
Sept. 15, 2047
March 1, 2050
June 1, 2051
April 1, 2052
June 1, 2052
May 15, 2053
250
150
425
250
400
350
300
250
500
300
300
350
600
600
700
425
500
800
2
(49)
(73)
—
400
250
150
425
250
400
350
300
250
500
300
300
350
600
600
700
425
500
—
3
(45)
(66)
(400)
$
7,330
$
6,542
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
(a)
First mortgage bonds
(b)
Other long-term debt
Unamortized discount
Unamortized debt issuance cost
Current maturities
Total long-term debt
(a)
2022 financing.
(b)
2023 financing.
59
NSP-Wisconsin
Financing Instrument
Interest
Rate
Maturity Date
2023
2022
Financing Instrument
SPS
Interest
Rate
Maturity Date
2023
2022
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
(a)
First mortgage bonds
(b)
Unamortized discount
Unamortized debt issuance cost
Current maturities
Total long-term debt
(a)
2022 financing.
2023 financing.
(b)
Financing Instrument
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
(a)
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
(a)
First mortgage bonds
(b)
Unamortized discount
Unamortized debt issuance cost
Current maturities
Total long-term debt
(a)
2022 financing.
(b)
2023 financing.
3.30 %
June 15, 2024
$
3.30
6.375
3.70
3.75
4.20
3.05
2.82
4.86
5.30
June 15, 2024
Sept. 1, 2038
Oct. 1, 2042
Dec. 1, 2047
Sept. 1, 2048
May 1, 2051
May 1, 2051
Sept. 15, 2052
June 15, 2053
$
100
100
200
100
100
200
100
100
100
125
(3)
(11)
(200)
100
100
200
100
100
200
100
100
100
—
(3)
(11)
—
$
1,011
$
1,086
PSCo
Interest
Rate
Maturity Date
2023
2022
2.50 % March 15, 2023
$
—
$
2.90
3.70
1.90
May 15, 2025
June 15, 2028
Jan. 15, 2031
1.875
June 15, 2031
4.10
6.25
6.50
4.75
3.60
3.95
4.30
3.55
3.80
4.10
4.05
3.20
2.70
4.50
5.25
June 1, 2032
Sept. 1, 2037
Aug. 1, 2038
Aug. 15, 2041
Sept. 15, 2042
March 15, 2043
March 15, 2044
June 15, 2046
June 15, 2047
June 15, 2048
Sept. 15, 2049
March 1, 2050
Jan. 15, 2051
June 1, 2052
April 1, 2053
250
350
375
750
300
350
300
250
500
250
300
250
400
350
400
550
375
400
850
(41)
(59)
—
250
250
350
375
750
300
350
300
250
500
250
300
250
400
350
400
550
375
400
—
(37)
(53)
(250)
$
7,450
$
6,610
First mortgage bonds
First mortgage bonds
Unsecured senior notes
Unsecured senior notes
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
(a)
First mortgage bonds
(b)
Unamortized discount
Unamortized debt issuance cost
Current maturities
Total long-term debt
(a)
2022 financing.
(b)
2023 financing.
3.30 %
June 15, 2024
$
150
$
3.30
6.00
6.00
4.50
4.50
4.50
3.40
3.70
4.40
3.75
3.15
3.15
5.15
6.00
June 15, 2024
Oct. 1, 2033
Oct. 1, 2036
Aug. 15, 2041
Aug. 15, 2041
Aug. 15, 2041
Aug. 15, 2046
Aug. 15, 2047
Nov. 15, 2048
June 15, 2049
May 1, 2050
May 1, 2050
June 1, 2052
Sept. 15, 2053
200
100
250
200
100
100
300
450
300
300
350
250
200
100
(10)
(29)
(350)
150
200
100
250
200
100
100
300
450
300
300
350
250
200
—
(10)
(29)
—
$
2,961
$
3,211
Other Subsidiaries
Interest
Rate
0.00% -
8.00%
Financing Instrument
Various Eloigne affordable
housing project notes
Current maturities
Total long-term debt
Maturities of long-term debt:
(Millions of Dollars)
2024
2025
2026
2027
2028
Maturity Date
2023
2022
2024 - 2055
$
27
$
(2)
$
25
$
$
27
(1)
26
552
1,103
501
501
1,133
Deferred Financing Costs — Deferred financing costs of approximately
$209 million and $193 million, net of amortization, are presented as a
deduction from the carrying amount of long-term debt as of Dec. 31, 2023
and 2022, respectively.
Equity through DRIP and Benefits Program — Xcel Energy issued
$88 million of equity in 2023 and $84 million of equity in 2022 through the
DRIP and benefits programs. The program allows shareholders to reinvest
their dividends directly in Xcel Energy Inc. common stock.
ATM Equity Offering — In November 2021, Xcel Energy Inc. filed a
prospectus supplement under which it may sell up to $800 million of its
common stock through an ATM program. In 2021, 5.33 million shares of
common stock were issued (approximately $350 million in net proceeds
and $3 million in transaction fees paid). In 2022, 4.30 million shares of
common stock were issued (approximately $300 million in net proceeds
and $3 million in transaction fees paid). In 2023, 0.90 million shares of
common stock were issued ($62 million in net proceeds and $1 million in
transaction fees paid). In October 2023, the 2021 ATM offering was closed.
60
Amounts authorized to issue as of Dec. 31, 2023:
(Millions of Dollars)
Long-Term Debt
Short-Term Debt
NSP-Minnesota
NSP-Wisconsin
PSCo
$
52.8% of total
capitalization
(a)
$
625
450
100
(a)
2,400
150
800
600
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.
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:
(Millions of Dollars)
Major revenue types
Year Ended Dec. 31, 2023
Electric
Natural
Gas
All Other
Total
Revenue from contracts with customers:
Residential
C&I
Other
Total retail
Wholesale
Transmission
Other
Total revenue from
contracts with customers
Alternative revenue and other
$
3,560
$
1,560
$
5,703
150
9,413
815
649
63
10,940
506
833
—
2,393
—
—
156
2,549
96
59
30
13
$
5,179
6,566
163
102
11,908
—
—
—
102
13
815
649
219
13,591
615
Total revenues
$ 11,446
$
2,645
$
115
$ 14,206
(Millions of Dollars)
Major revenue types
Year Ended Dec. 31, 2022
Electric
Natural
Gas
All Other
Total
Revenue from contracts with customers:
Residential
C&I
Other
Total retail
Wholesale
Transmission
Other
Total revenue from
contracts with customers
Alternative revenue and other
$
3,542
$
1,814
$
5,807
148
9,497
1,354
675
97
11,623
500
998
—
2,812
—
—
178
2,990
90
53
32
10
95
—
—
—
95
12
$
5,409
6,837
158
12,404
1,354
675
275
14,708
602
Total revenues
$ 12,123
$
3,080
$
107
$ 15,310
In October 2023, Xcel Energy Inc. filed a prospectus supplement under
which it may sell up to $2.5 billion of its common stock through an ATM
program. In the fourth quarter, through this ATM Program, Xcel Energy Inc.
issued 3.12 million shares of common stock ($188 million in net proceeds
and $2 million in transaction fees paid).
Capital Stock — Preferred stock authorized/outstanding:
Preferred Stock
Authorized
(Shares)
Par Value of
Preferred Stock
Preferred Stock
Outstanding (Shares)
2023 and 2022
SPS
(a)
Xcel Energy Inc.
7,000,000
$
PSCo
SPS
10,000,000
10,000,000
100
0.01
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, 2023
Common Stock
Outstanding
(Shares) as of
Dec. 31, 2022
1,000,000,000
$
2.50
554,941,703
549,578,018
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
for NSP-
Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those
imposed by the FERC.
impose dividend
limitations
Requirements and actuals as of Dec. 31, 2023:
Equity to Total
Capitalization Ratio
Required Range
Equity to Total
Capitalization Ratio
Actual
Low
High
2023
NSP-Minnesota
NSP-Wisconsin (a)
SPS (b)
47.2 %
52.5
45.0
57.6 %
N/A
55.0
52.3 %
52.7
54.6
(a)
(b)
Cannot pay annual dividends in excess of forecasted levels if its average equity-to-total
capitalization ratio falls below the commission authorized level.
Excludes short-term debt.
(Amounts in
Millions)
Unrestricted Retained
Earnings
Total
Capitalization
Limit on Total
Capitalization
NSP-Minnesota
$
1,508
$
15,702
$
16,140
NSP-Wisconsin
(a)
SPS
9
617
2,520
7,298
N/A
N/A
(a)
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.
61
Year Ended Dec. 31, 2021
Components of deferred income tax expense as of Dec. 31:
Electric
Natural
Gas
All Other
Total
(Millions of Dollars)
(Millions of Dollars)
Major revenue types
Revenue from contracts with customers:
Residential
C&I
Other
Total retail
Wholesale
Transmission
Other
Total revenue from
contracts with customers
Alternative revenue and other
$
3,194
$
1,222
$
5,050
127
8,371
1,540
604
61
10,576
629
640
—
1,862
—
—
148
2,010
122
Total revenues
$ 11,205
$
2,132
$
7. Income Taxes
45
30
7
82
—
—
—
82
12
94
$
4,461
5,720
134
10,315
1,540
604
209
12,668
763
$ 13,431
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:
Federal statutory rate
2023
21.0 %
2022
21.0 %
2021
21.0 %
State income tax on pretax income, net of federal tax
effect
4.9
4.9
5.0
(Decreases) increases in tax from:
Wind PTCs
(a)
Plant regulatory differences
(b)
Other tax credits, net NOL & tax credit allowances
Other, net
Effective income tax rate
(a)
(28.1)
(27.4)
(23.4)
(5.6)
(1.3)
0.1
(5.5)
(1.3)
(0.1)
(6.2)
(1.1)
0.1
(9.0) %
(8.4) %
(4.6) %
Wind PTCs net of estimated transfer discount are credited to customers (reduction to
revenue) and do not materially impact net income.
(b)
Plant regulatory differences primarily relate to the credit of excess deferred taxes to
customers through the average rate assumption method. Income tax benefits associated
with the credit are offset by corresponding revenue reductions.
Components of income tax expense for years ended Dec. 31:
(Millions of Dollars)
Current federal tax expense
Current state tax expense (benefit)
Current change in unrecognized tax (benefit) expense
Deferred federal tax benefit
Deferred state tax expense
Deferred change in unrecognized tax expense
Deferred ITCs
Total income tax benefit
2023
2022
2021
$
113
$
16
(21)
1
3
5
$
15
(2)
1
(331)
(239)
(183)
75
7
(5)
96
3
(4)
99
5
(5)
$
(146) $
(135) $
(70)
Deferred tax expense (benefit) excluding items below
Adjustments to deferred income taxes for wind production
tax credit cash transfers
(a)
Amortization and adjustments to deferred income taxes
on income tax regulatory assets and liabilities
Tax benefit allocated to other comprehensive income and
other
Deferred tax benefit
2023
2022
2021
$
129
$
(138) $
148
(190)
(188)
—
8
—
(221)
—
(10)
(6)
$
(249) $
(140) $
(79)
(a)
Proceeds from tax credit transfers are included in cash received (paid) for income taxes
in the consolidated statement of cash flows.
Components of net deferred tax liability as of Dec. 31:
(Millions of Dollars)
Deferred tax liabilities:
2023
(a)
2022
Differences between book and tax bases of property
$ 6,744
$ 6,442
Regulatory assets
Operating lease assets
Pension expense
Deferred fuel costs
Other
538
327
151
67
84
484
325
159
222
90
Total deferred tax liabilities
$ 7,911
$ 7,722
Deferred tax assets:
Tax credit carryforward
Regulatory liabilities
Operating lease liabilities
Other employee benefits
Deferred investment tax credits
NOL carryforward
NOL and tax credit valuation allowances
Other
Total deferred tax assets
Net deferred tax liability
(a)
$ 1,718
$ 1,679
730
327
117
16
—
(70)
188
718
325
102
14
57
(62)
133
3,026
2,966
$ 4,885
$ 4,756
Prior periods have been reclassified to conform to current year presentation.
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)
Federal NOL carryforward
Federal tax credit carryforwards
Valuation allowances for federal credit carryforwards
State NOL carryforwards
Valuation allowances for state NOL carryforwards
State tax credit carryforwards, net of federal detriment (a)
Valuation allowances for state credit carryforwards, net of federal
benefit (b)
(a)
2023
2022
$
—
$
20
1,644
1,593
(10)
—
11
1,022
(2)
74
(3)
85
(60)
(62)
State tax credit carryforwards are net of federal detriment of $20 million and $23 million
as of Dec. 31, 2023 and 2022, respectively.
(b)
Valuation allowances for state tax credit carryforwards were net of federal benefit of
$16 million as of Dec. 31, 2023 and 2022.
Federal carryforward periods expire between 2037 and 2043 and state
carryforward periods expire starting 2024.
62
Unrecognized Tax Benefits
Changes in unrecognized tax benefits:
Federal Audit — Statute of limitations applicable to Xcel Energy’s
consolidated federal income tax returns expire as follows:
(Millions of Dollars)
Balance at Jan. 1
Tax Year(s)
2014 - 2016
2020
Expiration
March 2025
September 2024
Additionally, the statute of limitations related to the federal tax credit
carryforwards will remain open until those credits are utilized in subsequent
returns. Further, the statute of limitations related to the additional federal
tax loss carryback claim filed in 2020 has been extended. As of Dec. 31,
2023 the IRS issued its Revenue Agent’s Report related to the federal tax
loss carryback claim. The Company materially agrees with the report and
re-recognized the related benefit in December 2023.
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, 2023, Xcel Energy’s earliest open tax years (subject to
examination by state taxing authorities in its major operating jurisdictions)
were as follows:
Additions based on tax positions related to the current year
Additions for tax positions of prior years
Reductions for tax positions of prior years
Reductions for tax positions related to settlements with taxing
authorities
Reductions for tax positions related to statute of limitations
2023
2022
2021
$ 67
$ 58
$ 52
5
1
(29)
(1)
(2)
7
6
(1)
5
2
(1)
(1)
—
(2)
—
Balance at Dec. 31
$ 41
$ 67
$ 58
Unrecognized tax benefits were reduced by tax benefits associated with
NOL and tax credit carryforwards:
(Millions of Dollars)
Dec. 31, 2023
Dec. 31, 2022
NOL and tax credit carryforwards
$
(35) $
(40)
As IRS audits resume and as state audits progress, it is reasonably
possible that the amount of unrecognized tax benefit could decrease up to
approximately $14 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.
State
Tax Year(s)
Expiration
Interest payable related to unrecognized tax benefits:
Colorado
Colorado
Minnesota
Minnesota
Texas
Texas
Texas
Wisconsin
Wisconsin
2014 - 2016
2019
2014 - 2016
2019
2016, 2018
2017
2019
2016 - 2018
2019
March 2026
October 2024
September 2025
May 2024
May 2024
July 2025
August 2024
May 2024
October 2024
•
•
•
•
In 2020, Minnesota began an audit of tax years 2015 - 2018. In 2022,
the state of Minnesota issued its audit report and in 2023, the
Company agreed to the report without any material adjustments.
In 2021, Texas began an audit of tax years 2016 - 2019. As of Dec.
31, 2023, no material adjustments have been proposed.
In 2021, Wisconsin began an audit of tax years 2016-2019. As of Dec.
31, 2023, no material adjustments have been proposed.
No other state income tax audits are in progress for its major operating
jurisdictions as of Dec. 31, 2023.
Unrecognized tax benefit balance includes permanent tax positions, which
if recognized would affect the ETR. In addition, the unrecognized tax
benefit balance includes temporary tax positions for which deductibility is
highly certain, but for which there is uncertainty about the timing. A change
in the period of deductibility would not affect the ETR but would accelerate
the payment to the taxing authority.
Unrecognized tax benefits - permanent vs. temporary:
(Millions of Dollars)
Dec. 31, 2023
Dec. 31, 2022
Unrecognized tax benefit — Permanent tax positions
Unrecognized tax benefit — Temporary tax positions
Total unrecognized tax benefit
$
$
41
—
41
$
$
55
12
67
(Millions of Dollars)
2023
2022
2021
Payable for interest related to unrecognized
tax benefits at Jan. 1
Interest benefit (expense) related to
unrecognized tax benefits
Payable for interest related to unrecognized
tax benefits at Dec. 31
$
$
(4) $
(3) $
3
(1)
(1) $
(4) $
(3)
—
(3)
No penalties were accrued related to unrecognized tax benefits as of Dec.
31, 2023, 2022 or 2021.
8. Share-Based Compensation
Incentive Plan Including Share-Based Compensation — Xcel Energy
has authorized 7.0 million equity shares under an incentive plan (the
Amended and Restated 2015 Omnibus Incentive Plan).
Equity Awards — Xcel Energy‘s Board of Directors has granted equity
awards under the 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.
The total time-based equity shares granted subject only to service
conditions was 0.4 million in 2023 and 0.2 million in 2022 and 2021
respectively.
The performance conditions for a portion of the awards granted from 2021
to 2023 are based on relative TSR and environmental goals. Equity awards
with performance conditions will be settled after three years, with payouts
ranging from zero to 200% depending on achievement.
Equity award units granted to employees:
(Units in Thousands)
2023
2022
2021
Granted units
586
395
421
Weighted average grant date
fair value
$
67.06
$
68.43
$
66.03
63
Equity awards vested:
(Units in Thousands, Fair
Value in Millions)
2023
2022
2021
Vested Units
Total Fair Value
$
329
20
$
319
22
$
392
27
Changes in the nonvested portion of equity award units:
(Units in Thousands)
Units
Nonvested Units at Jan. 1, 2023
708
$
Granted
Forfeited
Vested
Dividend equivalents
Nonvested Units at Dec. 31, 2023
586
(184)
(329)
38
819
Weighted Average
Grant Date Fair Value
67.35
67.06
68.42
66.23
67.65
67.36
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 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.
Share-Based Compensation Expense — Award settlement determination
(permitting cash or share settlement) is made by Xcel Energy, not the
participants. Equity 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 are accounted for as liabilities, as historically they are
partially settled in cash. 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 award
on the date the settlement date.
Compensation costs related to share-based awards:
(Millions of Dollars)
Cost for share-based awards (a)
Tax benefit recognized in income
(a)
2023
2022
2021
$
27
$
36
$
7
9
31
8
Compensation costs for share-based payments are included in O&M expense. Amount
for equity awards (non-cash) was $25 million in 2023.
There was approximately $38 million and $37 million as of Dec. 31, 2023
and 2022, respectively, 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.
Stock equivalent units granted:
9. Earnings Per Share
(Units in Thousands)
2023
2022
2021
Granted units
Weighted average grant date
fair value
38
29
31
$
63.12
$
71.97
$
68.15
Changes in stock equivalent units:
(Units in Thousands)
Units
Stock equivalent units at Jan. 1, 2023
597
$
Granted
Units distributed
Dividend equivalents
Stock equivalent units at Dec. 31, 2023
38
(134)
16
517
Weighted Average
Grant Date Fair Value
41.75
63.12
33.90
64.95
46.07
Liability Awards — Xcel Energy’s Board of Directors has granted TSR
liability awards under the 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%.
Liability awards granted:
(In Thousands)
Awards granted
Liability awards settled:
(Units In Thousands, Settlement
Amount in Millions)
2023
2022
2021
216
165
221
2023
2022
2021
Awards settled
282
411
Settlement amount (cash, common stock
and deferred amounts)
$
19
$
27
$
446
27
TSR liability awards of $13 million were settled in cash in 2023.
64
Basic EPS was computed by dividing the earnings available to common
shareholders by the weighted average number of common shares
outstanding. Diluted EPS was computed by dividing the earnings available
to common shareholders by the diluted weighted average number of
common shares outstanding.
Diluted EPS reflects the potential dilution that could occur if securities or
other agreements to issue common stock (i.e., common stock equivalents)
were settled. The weighted average number of potentially dilutive shares
outstanding used to calculate diluted EPS is calculated using the treasury
stock method.
Common Stock Equivalents — Common stock equivalents include
commitments
time-based equity
compensation awards.
issue common stock related
to
to
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 following the grant of
these awards. Restricted stock issued to employees under the Executive
Annual Incentive Award Plan is included in common shares outstanding
when granted.
Share-based compensation arrangements for which there is currently no
dilutive impact to EPS include the following:
•
•
Equity awards subject to a performance condition; included in
common shares outstanding when all necessary conditions for
settlement have been satisfied by the end of the reporting period.
Liability awards subject to a performance condition; any portions
settled in shares are included in common shares outstanding upon
settlement.
Common shares outstanding used
computation:
in
the basic and diluted EPS
(Shares in Millions)
2023
2022
2021
Basic
(a)
Diluted
552
552
547
547
539
540
(a)
Diluted common shares outstanding included common stock equivalents of 0.3 million
shares for 2023, 2022 and 2021.
10. Fair Value of Financial Assets and Liabilities
Fair Value Measurements
Accounting guidance for fair value measurements and disclosures provides
a hierarchical framework for disclosing the observability of the inputs
utilized in measuring assets and liabilities at fair value.
•
•
•
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 actively traded instruments with
observable actual trading prices.
Level 2 — Pricing inputs are other than actual trading 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 include those valued with models requiring significant
judgment or estimation.
Specific valuation methods include:
funds are measured using NAVs. The
Investments in equity securities and other funds — Equity securities
are valued using quoted prices in active markets. The fair values for
in
commingled
commingled funds may be redeemed for NAV with proper notice. Private
equity commingled funds require approval of the fund for any unscheduled
redemption, and such redemptions may be approved or denied by the fund
real estate
at
commingled funds may be redeemed with proper notice, however,
withdrawals may be delayed or discounted as a result of fund illiquidity.
its sole discretion. Unscheduled distributions
investments
from
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 contracts relate to
inactive delivery locations or extend to periods beyond those readily
observable on active exchanges, the significance of the use of less
observable inputs 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 an RTO are financial instruments that entitle or obligate the
holder to monthly revenues or charges based on transmission congestion
across a given transmission path.
65
The values of these instruments are derived from, and designed to offset,
the costs 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 these instruments.
FTRs are recognized at fair value and adjusted each period prior to
settlement. Given the limited observability of certain variables underlying
the reported auction values of FTRs, these fair value measurements have
been assigned a Level 3 classification.
Net congestion costs, including the impact of FTR settlements, are shared
through fuel and purchased energy cost recovery mechanisms. As such,
the fair value of the unsettled instruments (i.e., derivative asset or liability)
is offset/deferred as a regulatory asset or liability.
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 $1.2 billion
and $1.0 billion as of Dec. 31, 2023 and 2022, respectively, and unrealized
losses were $29 million and $90 million as of Dec. 31, 2023 and 2022,
respectively.
Non-derivative instruments with recurring fair value measurements in the
nuclear decommissioning fund:
Dec. 31, 2023
Fair Value
(Millions of Dollars)
Nuclear decommissioning fund (a)
Cost
Level 1
Level 2
Level 3
NAV
Total
Cash equivalents
$
41
$
Commingled funds
Debt securities
721
784
41
—
—
Equity securities
508
1,339
$ —
$ —
$ —
$
41
—
771
2
—
1,049
9
—
—
—
1,049
780
1,341
Total
$ 2,054
$ 1,380
$
773
$
9
$ 1,049
$ 3,211
(a)
Reported in nuclear decommissioning fund and other investments on the consolidated
balance sheets, which also includes $244 million of equity method investments and
$144 million of rabbi trust assets and other miscellaneous investments.
Dec. 31, 2022
Fair Value
(Millions of Dollars)
Nuclear decommissioning fund (a)
Cost
Level 1
Level 2
Level 3
NAV
Total
Cash equivalents
$
29
$
Commingled funds
Debt securities
Equity securities
803
738
406
29
—
—
999
$ —
$ —
$ —
$
29
—
669
1
—
1,178
6
—
—
—
1,178
675
1,000
Total
$ 1,976
$ 1,028
$
670
$
6
$ 1,178
$ 2,882
(a)
Reported in nuclear decommissioning fund and other investments on the consolidated
balance sheets, which also
includes $219 million of equity
investments
in
unconsolidated subsidiaries and $133 million of rabbi
trust assets and other
miscellaneous investments.
For the years ended Dec. 31, 2023 and 2022, there were immaterial Level
3 nuclear decommissioning fund investments or transfer of amounts
between levels.
Contractual maturity dates of debt securities
decommissioning fund as of Dec. 31, 2023:
in
the nuclear
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
$
4
$
261
$
269
$
246
$
780
Rabbi Trusts
Xcel Energy has established rabbi trusts to provide partial funding for future
deferred compensation plan distributions. The fair value of assets held in
the rabbi trusts were $88 million and $80 million at Dec. 31, 2023 and 2022,
respectively, comprised of cash equivalents and mutual funds (level 1
valuation methods). Amounts are reported in nuclear decommissioning
fund and other investments on the consolidated balance sheet.
Derivative Activities and 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, and utility commodity prices.
Interest Rate Derivatives — Xcel Energy enters into contracts that
effectively fix the interest rate on a specified principal amount of a
hypothetical future debt issuance. These financial swaps net settle based
on changes in a specified benchmark interest rate, acting as a hedge of
changes in market interest rates that will impact specified anticipated debt
issuances. These derivative instruments are designated as cash flow
hedges for accounting purposes, with changes in fair value prior to
occurrence of the hedged transactions recorded as other comprehensive
income.
As of Dec. 31, 2023, accumulated other comprehensive loss related to
interest rate derivatives included $2 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, 2023, Xcel Energy had
unsettled interest swaps outstanding with a notional amount of $420 million.
These interest rate derivatives were designated as cash flow hedges, with
changes in fair value recorded to other comprehensive income.
See Note 13 for the financial impact of qualifying interest rate cash flow
hedges on Xcel Energy’s accumulated other comprehensive loss included
in the consolidated statements of common stockholder’s equity and in the
consolidated statements of comprehensive income.
66
Wholesale and Commodity Trading — 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 the activities governed by
this policy.
Derivative instruments entered into for trading purposes are presented in
the consolidated statements of income as electric revenues, net of any
sharing with customers. These activities are not intended to mitigate
commodity price risk associated with regulated electric and natural gas
operations. Sharing of these margins is determined through state regulatory
proceedings as well as the operation of the FERC-approved joint operating
agreement.
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. This could include the
purchase or sale of energy or energy-related products, natural gas to
generate electric energy, natural gas for resale and FTRs.
The most significant derivative positions outstanding at Dec. 31, 2023 and
2022 for this purpose relate to FTR instruments administered by MISO and
SPP. These instruments are intended to offset the impacts of transmission
system congestion.
Higher congestion costs in recent years have led to an increase in the fair
value of FTRs. Settlements of FTRs are shared with electric customers
through fuel and purchased energy cost-recovery mechanisms.
instruments
When Xcel Energy enters
that mitigate
into derivative
commodity price risk on behalf of electric and natural gas customers, the
instruments are not typically designated as qualifying hedging transactions.
The classification of unrealized losses or gains on these instruments as a
regulatory asset or liability, if applicable, is based on approved regulatory
recovery mechanisms.
As of Dec. 31, 2023, Xcel Energy had no commodity contracts designated
as cash flow hedges.
Gross notional amounts of commodity forwards, options and FTRs:
(Amounts in Millions)
(a)(b)
MWh of electricity
MMBtu of natural gas
(a)
Dec. 31, 2023
Dec. 31, 2022
48
84
61
131
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, 2023, four of Xcel Energy’s ten most significant
counterparties for these activities, comprising $49 million or 23% of this
credit exposure, had investment grade credit ratings from S&P Global
Ratings, Moody’s Investor Services or Fitch Ratings.
Five of the ten most significant counterparties, comprising $78 million or
37% of this credit exposure, were not rated by these external ratings
agencies, but based on Xcel Energy’s internal analysis, had credit quality
consistent with investment grade.
One of these significant counterparties, comprising $45 million or 21% 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.
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, 2023 and 2022, there were $12 million and $4 million,
respectively, of derivative
liabilities with such underlying contract
provisions, respectively.
Also, certain contracts may contain cross default provisions that may
require the posting of collateral or settlement of the contracts if there was a
failure under other financing arrangements related to payment terms or
other covenants.
As of Dec. 31, 2023 and 2022, there were approximately $88 million and
$76 million of derivative liabilities with such underlying contract provisions,
respectively.
Certain derivative instruments are also subject to contract provisions that
contain adequate assurance
clauses. These provisions allow
counterparties to seek performance assurance, including cash collateral, in
the event that 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, 2023 and 2022.
Recurring Derivative Fair Value Measurements
Impact of derivative activity:
Pre-Tax Fair Value Gains (Losses) Recognized
During the Period in:
Accumulated Other
Comprehensive Loss
Regulatory (Assets) and
Liabilities
(Millions of Dollars)
Year Ended Dec. 31, 2023
Derivatives designated as cash flow hedges
Interest rate
Total
Other derivative instruments
Electric commodity
Natural gas commodity
Total
Year Ended Dec. 31, 2022
Interest rate
Total
Other derivative instruments
Electric commodity
Natural gas commodity
Total
Year Ended Dec. 31, 2021
Interest rate
Total
Other derivative instruments
Electric commodity
Natural gas commodity
Total
$
$
$
$
$
$
$
$
$
$
$
$
(2)
(2)
—
—
—
22
22
—
—
—
5
5
—
—
—
$
$
$
$
$
$
$
$
$
$
$
$
—
—
(137)
(13)
(150)
—
—
(10)
(16)
(26)
—
—
32
(4)
28
67
(Millions of Dollars)
Year Ended Dec. 31, 2023
Derivatives designated as cash flow hedges
Interest rate
Total
Other derivative instruments
Commodity trading
Electric commodity
Natural gas commodity
Total
Year Ended Dec. 31, 2022
Derivatives designated as cash flow hedges
Interest rate
Total
Other derivative instruments
Commodity trading
Electric commodity
Natural gas commodity
Total
Year Ended Dec. 31, 2021
Derivatives designated as cash flow hedges
Interest rate
Total
Other derivative instruments
Commodity trading
Electric commodity
Natural gas commodity
Total
Pre-Tax (Gains) Losses Reclassified into Income During the
Period from:
Accumulated Other
Comprehensive Loss
Regulatory Assets and
(Liabilities)
Pre-Tax Gains (Losses)
Recognized During the
Period in Income
$
$
$
$
$
$
$
$
$
$
$
$
(a)
(a)
(a)
5
5
—
—
—
—
7
7
—
—
—
—
8
8
—
—
—
—
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(c)
(d)
(c)
(d)
—
—
—
123
15
138
—
—
—
3
10
13
—
—
—
(23)
5
(c)
(d)
(18)
$
—
—
(7)
—
(27)
(34)
—
—
25
—
(27)
(2)
—
—
63
—
(22)
41
(b)
(d)(e)
(b)
(d)(e)
(b)
(d)(e)
(a)
(b)
(c)
(d)
(e)
Recorded to interest charges.
Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers.
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. FTR settlements are shared with customers and do not have a material impact on net income.
Presented amounts reflect changes in fair value between FTR auction and settlement dates, but exclude the original auction fair value.
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.
Relates primarily to option premium amortization.
Xcel Energy had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2023, 2022 and 2021.
68
(Millions of Dollars)
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate
Other derivative instruments:
Commodity trading
Electric commodity
Natural gas commodity
Derivative assets and liabilities measured at fair value on a recurring basis were as follows:
Dec. 31, 2023
Dec. 31, 2022
Fair Value
Fair Value
Level
1
Level
2
Level
3
Fair Value
Total
Netting (a)
Total
Level
1
Level
2
Level
3
Fair Value
Total
(a)
Netting
Total
(Millions of Dollars)
Current derivative assets
Other derivative instruments:
Commodity trading
Electric commodity
Natural gas commodity
$
8
$ 51
$ 32
$
—
—
62
—
14
—
91
62
14
$
(59) $
(7)
—
(66)
32
55
14
$ 32
$ 259
$ 33
$
324
$
(242) $
—
—
177
—
19
—
177
19
(2)
—
101
$ 32
$ 278
$ 210
$
520
$
(244)
3
104
$
$
Total current derivative assets
$
8
$ 65
$ 94
$
167
$
PPAs (b)
Current derivative instruments
Noncurrent derivative assets
Other derivative instruments:
Commodity trading
$ 14
$ 51
$ 45
Total noncurrent derivative assets
$ 14
$ 51
$ 45
$
$
110
110
$
$
(34) $
(34)
PPAs (b)
Noncurrent derivative instruments
$
76
76
—
76
$ 34
$ 71
$ 74
$ 34
$ 71
$ 74
$
$
179
179
$
$
(89) $
(89)
$
Dec. 31, 2023
Dec. 31, 2022
Fair Value
Level
2
Level
1
Level
3
Fair Value
Total
Netting (a)
Total
Fair Value
Level
2
Level
1
Level
3
Fair Value
Total
Netting (a)
Total
$ —
$ 17
$ —
$
17
$
—
$
17
$ —
$
1
$ —
$
1
$
—
$
6
86
—
—
5
7
—
12
—
97
7
12
Total current derivative liabilities
$
6
$ 115
$ 12
$
133
$
PPAs (b)
Current derivative instruments
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading
$ 16
$ 50
$ 37
Total noncurrent derivative liabilities
$ 16
$ 50
$ 37
$
$
103
103
$
$
(39) $
(39)
PPAs (b)
Noncurrent derivative instruments
$
29
297
—
—
6
2
—
13
—
332
2
13
(287)
(2)
—
$ 29
$ 311
$
8
$
348
$
(289)
$
$ 43
$ 97
$ 41
$ 43
$ 97
$ 41
$
$
181
181
$
$
(98) $
(98)
(60)
(7)
—
(67)
$
37
—
12
66
8
74
64
64
22
86
$
113
(a)
(b)
Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Dec. 31, 2023 and
2022, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2023 and 2022, derivative assets and liabilities include rights to reclaim cash collateral of
$7 million and $53 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.
Xcel Energy currently applies the normal purchase exception to qualifying PPAs. Balance relates to specific contracts that were previously recognized at fair value prior to applying the
normal purchase exception, and are being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
69
82
175
19
276
3
279
90
90
3
93
1
45
—
13
59
17
76
83
83
30
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, 2023 and
2022 were $12 million and $11 million, respectively. Xcel Energy
recognized net benefit cost for the SERP and nonqualified plans of $2
million in 2023 and $17 million in 2022.
Xcel Energy’s postretirement health care benefit plan is a continuation of
certain welfare benefit programs for current employees. A full time
employee’s date of hire or a retiree’s date of retirement determine eligibility
for each of the programs.
Xcel Energy’s investment-return assumption considers the expected long-
term performance for each of the asset classes in its pension and
postretirement health care portfolio. Xcel Energy considers the historical
returns achieved by its asset portfolios over long time periods, as well as
the long-term projected return levels from investment experts.
Pension cost determination assumes a forecasted mix of investment types
over the long-term.
•
•
•
•
Investment returns in 2023 were above the assumed level of 6.93%.
Investment returns in 2022 were below the assumed level of 6.49%.
Investment returns in 2021 were above the assumed level of 6.49%.
In 2024, expected investment-return assumption is 6.93%.
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
liquidity
characteristics of each particular asset class.
long-term risk, return, correlation and
the
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 plans for
Texas and New Mexico equal to amounts collected in rates. These assets
are invested in a manner consistent with the investment strategy for the
pension plan.
Xcel Energy’s ongoing investment strategy is based on plan-specific
investment recommendations that seek to minimize potential investment
and interest rate risk as a plan’s funded status increases over time.
The investment recommendations consider many factors and generally
result in a greater percentage of long-duration fixed income securities being
allocated to specific plans having relatively higher funded status ratios and
a greater percentage of growth assets being allocated to plans having
relatively lower funded status ratios.
Changes in Level 3 commodity derivatives:
(Millions of Dollars)
Balance at Jan. 1
Purchases
(a)
Settlements
(a)
Net transactions recorded during the period:
Gains recognized in earnings (b)
Net (losses) gains recognized as regulatory
(a)
assets and liabilities
Balance at Dec. 31
(a)
Year Ended Dec. 31
2023
2022
2021
$
236
$
19
$
(49)
176
(154)
406
(350)
65
(158)
6
151
(174)
10
$
90
$
236
$
49
112
19
Relates primarily to NSP-Minnesota and SPS FTR instruments administered by MISO
and SPP.
(b)
Relates to commodity trading and is subject to substantial offsetting losses and gains on
derivative instruments categorized as levels 1 and 2 in the income statement. See
above tables for the income statement impact of derivative activity, including commodity
trading gains and losses.
Fair Value of Long-Term Debt
As of Dec. 31, other financial instruments for which the carrying amount did
not equal fair value:
(Millions of Dollars)
Long-term debt, including current
portion
2023
2022
Carrying
Amount
Fair
Value
Carrying
Amount
Fair
Value
$
25,465
$ 22,927
$
23,964
$ 20,897
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, 2023 and 2022, 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 4.72, 4.89
and 2.03% in 2023, 2022, and 2021, 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.
70
Plan Assets
For each of the fair value hierarchy levels, Xcel Energy’s pension plan assets measured at fair value:
Dec. 31, 2023 (a)
Dec. 31, 2022 (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
Commingled funds
Debt securities
Equity securities
Other
Total
$
233
$
491
—
35
—
$
—
—
683
—
9
—
—
4
—
—
$
—
$
233
$
129
$
1,235
—
—
—
1,726
687
35
9
935
—
47
—
$
—
—
682
—
7
—
—
3
—
—
$
—
$
882
—
—
—
129
1,817
685
47
7
$
759
$
692
$
4
$
1,235
$
2,690
$
1,111
$
689
$
3
$
882
$
2,685
(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, 2023 (a)
Dec. 31, 2022 (a)
(Millions of Dollars)
Cash equivalents
Insurance contracts
Commingled funds
Debt securities
Other
Total
Level 1
Level 2
Level 3
Measured
at NAV
Total
Level 1
Level 2
Level 3
Measured
at NAV
Total
$
$
33
—
22
—
—
55
$
$
—
40
—
187
1
$
—
—
—
1
—
$
228
$
1
$
—
—
72
—
—
72
$
$
33
40
94
188
1
$
356
$
31
—
54
—
—
85
$
$
—
41
—
175
(1)
$
—
—
—
1
—
$
215
$
1
$
—
—
63
—
—
63
$
$
31
41
117
176
(1)
364
(a)
See Note 10 for further information on fair value measurement inputs and methods.
Immaterial assets were transferred in or out of Level 3 for 2023 and 2022.
Funded Status — 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:
(Millions of Dollars)
Change in Benefit Obligation:
Obligation at Jan. 1
Service cost
Interest cost
Plan amendments
Actuarial (gain) loss
Plan participants’ contributions
Medicare subsidy reimbursements
Benefit payments (a)
Obligation at Dec. 31
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1
Actual return on plan assets
Employer contributions
Plan participants’ contributions
Benefit payments
Fair value of plan assets at Dec. 31
Funded status of plans at Dec. 31
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
Noncurrent assets
Current liabilities
Noncurrent liabilities
Net amounts recognized
Pension Benefits
Postretirement Benefits
2023
2022
2023
2022
$
2,871
$
3,718
$
405
$
74
158
(3)
126
—
—
(283)
2,943
$
97
110
1
(703)
—
—
1
22
—
14
8
—
(352)
2,871
$
(56)
394
$
2,685
$
3,670
$
364
$
238
50
—
(283)
2,690
(683)
50
—
(352)
2,685
29
11
8
(56)
356
(253) $
(186) $
(38) $
1
$
—
(254)
(253) $
$
15
—
(201)
(186) $
28
$
(3)
(63)
(38) $
$
$
$
$
$
511
2
15
—
(85)
8
2
(48)
405
442
(51)
13
8
(48)
364
(41)
33
(2)
(72)
(41)
(a)
Includes lump-sum benefit payments used in the determination of a settlement charges of $195 million of in 2022.
71
Significant Assumptions Used to Measure Benefit Obligations:
2023
2022
2023
2022
Pension Benefits
Postretirement Benefits
Discount rate for year-end valuation
Expected average long-term increase in compensation level
Mortality table
Health care costs trend rate — initial: Pre-65
Health care costs trend rate — initial: Post-65
Ultimate trend assumption — initial: Pre-65
Ultimate trend assumption — initial: Post-65
Years until ultimate trend is reached
5.49 %
4.25 %
PRI-2012
N/A
N/A
N/A
N/A
N/A
5.80 %
4.25 %
PRI-2012
N/A
N/A
N/A
N/A
N/A
5.54 %
N/A
PRI-2012
6.50 %
5.50 %
4.50 %
4.50 %
6
5.80 %
N/A
PRI-2012
6.50 %
5.50 %
4.50 %
4.50 %
7
Accumulated benefit obligation for the pension plan was $2,728 million and $2,672 million as of Dec. 31, 2023 and 2022, respectively.
Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other income (expense) in the
consolidated statements of income.
Components of net periodic benefit cost (credit) and amounts recognized in other comprehensive income and regulatory assets and liabilities:
(Millions of Dollars)
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service credit
Amortization of net loss
Settlement charge (a)
Net periodic pension cost (credit)
Effects of regulation
Net benefit cost (credit) recognized for financial reporting
Significant Assumptions Used to Measure Costs:
Discount rate
Expected average long-term increase in compensation level
Expected average long-term rate of return on assets
$
$
Pension Benefits
Postretirement Benefits
2023
2022
2021
2023
2022
2021
$
$
74
158
(209)
(1)
22
—
44
30
74
5.80 %
4.25
6.93
$
$
97
110
(208)
(1)
75
71
144
(30)
114
3.08 %
3.75
6.49
$
$
104
104
(206)
(1)
107
59
167
(46)
121
2.71 %
3.75
6.49
1
22
(17)
(1)
1
—
6
—
6
$
$
2
15
(18)
(6)
2
—
(5)
3
(2)
$
$
2
15
(18)
(8)
5
—
(4)
2
(2)
5.80 %
—
5.00
3.09 %
—
4.10
2.65 %
—
4.10
(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. There were no settlement charges recorded for the qualified pension plans in 2023. In 2022 and 2021, as a result of lump-sum distributions during each plan year, Xcel Energy
recorded a total pension settlement charge of $71 million and $59 million, respectively, the majority of which was not recognized due to the effects of regulation. A total of $9 million and $7
million was recorded in the consolidated statements of income in 2022 and 2021, respectively.
(Millions of Dollars)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss
Prior service credit
Total
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
Noncurrent regulatory assets
Current regulatory liabilities
Noncurrent regulatory liabilities
Deferred income taxes
Net-of-tax accumulated other comprehensive income
Total
Measurement date
Pension Benefits
Postretirement Benefits
2023
2022
2023
2022
$
$
$
1,096
$
1,021
$
(9)
(7)
1,087
$
1,014
$
64
—
64
$
$
20
$
1,014
—
—
14
39
21
$
2
$
943
—
—
14
36
79
(1)
(19)
1
2
$
1,087
$
1,014
$
64
$
63
(1)
62
—
78
(1)
(20)
1
4
62
Dec. 31, 2023
Dec. 31, 2022
Dec. 31, 2023
Dec. 31, 2022
72
Cash Flows — Funding requirements can be impacted by changes to
actuarial assumptions, actual asset levels and other calculations prescribed
by the requirements of income tax and other pension-related regulations.
Required contributions were made in 2021 - 2024 to meet minimum funding
requirements.
Voluntary and required pension funding contributions:
•
•
•
•
$100 million in January 2024.
$50 million in 2023.
$50 million in 2022.
$131 million in 2021.
Voluntary Retirement Program
Incremental to amounts presented above for postretirement benefits, Xcel
Energy recognized new postemployment costs and obligations in the fourth
quarter of 2023 for employees accepted to a voluntary retirement program.
Utilizing employee information and the following inputs, the estimated costs
of the program of $34 million for health plan subsidies and $5 million for
other medical benefits, each commencing in 2024, were recognized in the
fourth quarter of 2023. These unfunded obligations are presented in other
current liabilities and noncurrent pension and employee benefit obligations
in the consolidated balance sheet as of Dec. 31, 2023.
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.
Significant Assumptions to Measure Benefit Obligations:
2023
Discount rate for year-end valuation
Mortality table
Health care costs trend rate and ultimate trend assumption
5.50 %
PRI-2012
7.00 %
Voluntary postretirement funding contributions:
•
•
•
•
$11 million expected during 2024.
$11 million during 2023.
$13 million during 2022.
$15 million during 2021.
Targeted asset allocations:
Long-duration fixed income securities
Domestic and international equity
securities
Alternative investments
Short-to-intermediate fixed income
securities
Cash
Total
Pension Benefits
Postretirement
Benefits
2023
2022
2023
2022
38 %
38 %
— %
— %
31
20
9
2
33
18
9
2
9
13
77
1
16
12
71
1
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 2023, Xcel Energy amended the Xcel Energy
Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) to
reduce supplemental social security benefits for all active participants on
and after Jan. 1, 2024.
There were no significant plan amendments made in 2022 which affected
the postretirement benefit obligation.
In 2021, Xcel Energy amended the Xcel Energy Pension Plan and Xcel
Energy Inc. Nonbargaining Pension Plan (South) to reduce supplemental
benefits for non-bargaining participants as well as to allow the transfer of a
portion of non-qualified pension obligations into the qualified plans.
Projected Benefit Payments
Xcel Energy’s projected benefit payments:
(Millions of
Dollars)
2024
2025
2026
2027
2028
2029 - 2033
Projected
Pension
Benefit
Payments
398
$
Gross Projected
Postretirement
Health Care
Benefit Payments
42
$
214
217
223
226
1,131
40
39
37
36
161
Expected
Medicare Part
D
Subsidies
Net Projected
Postretirement
Health Care
Benefit
Payments
$
$
2
2
2
2
2
12
40
38
37
35
34
149
73
Defined Contribution Plans
Xcel Energy maintains 401(k) and other defined contribution plans that
cover most employees. Total expense to these plans was approximately
$49 million in 2023, $46 million in 2022 and $43 million in 2021.
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
to a
that
multiemployer pension plan, additional unfunded obligations may need to
be funded over time by remaining participating employers.
if another participating employer ceases
to contribute
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,
loss. For current
including a possible eventual
proceedings not specifically reported herein, management does not
anticipate that the ultimate liabilities, if any, would have a material effect on
Xcel Energy’s consolidated financial statements. Legal fees are generally
expensed as incurred.
Gas Trading Litigation — e prime is a wholly owned subsidiary of Xcel
Energy. e prime was in the business of natural gas trading and marketing
but has not engaged in natural gas trading or marketing activities since
2003. Multiple lawsuits involving multiple plaintiffs seeking monetary
damages were commenced against e prime and its affiliates, including Xcel
Energy, between 2003 and 2009 alleging fraud and anticompetitive
activities in conspiring to restrain the trade of natural gas and manipulate
natural gas prices. Cases were all consolidated in the U.S. District Court in
Nevada.
One case remains active which includes a multi-district litigation matter
consisting of a Wisconsin purported class (Arandell Corp.). The Court
issued a ruling in June 2022 granting plaintiffs’ class certification. In April
2023, the Seventh Circuit Court of Appeals heard the defendants’ appeal
challenging whether the district court properly assessed class certification.
A decision relating to class certification is expected imminently. Xcel
Energy considers the reasonably possible loss associated with this litigation
to be immaterial.
Comanche Unit 3 Litigation — In 2021, CORE filed a lawsuit in Denver
County District Court, alleging PSCo breached ownership agreement terms
by failing to operate Comanche Unit 3 in accordance with prudent utility
practices. In April 2022, CORE filed a supplement to include damages
related to a 2022 outage. Also in 2022, CORE sent notice of withdrawal
from the ownership agreement based on the same alleged breaches.
In February 2023, the court granted PSCo’s motion precluding CORE from
seeking damages related to its withdrawal as part of the lawsuit. In October
2023, the jury ruled that CORE may not withdraw as a joint owner of the
facility but awarded CORE lost power damages of $26 million. PSCo
recognized a $34 million loss for the verdict in the third quarter of 2023,
including estimated interest and other costs. PSCo intends to file an appeal
of this decision.
Marshall Wildfire Litigation — In December 2021, a wildfire ignited in
Boulder County, Colorado (the “Marshall Fire”), which burned over 6,000
acres and destroyed or damaged over 1,000 structures. On June 8, 2023,
the Boulder County Sheriff’s Office released its Marshall Fire Investigative
Summary and Review and its supporting documents (the “Sheriff’s
Report”). According to an October 2022 statement from the Colorado
Insurance Commissioner, the Marshall Fire is estimated to have caused
more than $2 billion in property losses.
According to the Sheriff’s Report, on Dec. 30, 2021, a fire ignited on a
residential property in Boulder, Colorado, located in PSCo’s service
territory, for reasons unrelated to PSCo’s power lines. According to the
Sheriff’s Report, approximately one hour and 20 minutes after the first
ignition, a second fire ignited just south of the Marshall Mesa Trailhead in
unincorporated Boulder County, Colorado, also located in PSCo’s service
territory. According to the Sheriff’s Report, the second ignition started
approximately 80 to 110 feet away from PSCo’s power lines in the area.
The Sheriff’s Report states that the most probable cause of the second
ignition was hot particles discharged from PSCo’s power lines after one of
the power lines detached from its insulator in strong winds, and further
states that it cannot be ruled out that the second ignition was caused by an
underground coal fire. According to the Sheriff’s Report, no design,
installation or maintenance defects or deficiencies were identified on
PSCo’s electrical circuit in the area of the second ignition. PSCo disputes
that its power lines caused the second ignition.
PSCo is aware of 302 complaints, most of which have also named Xcel
Energy Inc. and Xcel Energy Services, Inc. as additional defendants,
relating to the Marshall Fire. The complaints are on behalf of at least 4,047
plaintiffs, and one complaint is filed on behalf of a putative class of first
responders who allegedly were exposed to the threat of serious bodily
injury, or smoke, soot and ash from the Marshall Fire. The complaints
generally allege that PSCo’s equipment ignited the Marshall Fire and assert
various causes of action under Colorado law, including negligence,
premises liability, trespass, nuisance, wrongful death, willful and wanton
conduct, negligent infliction of emotional distress, loss of consortium and
inverse condemnation. In addition to seeking compensatory damages,
certain of the complaints also seek exemplary damages.
In September 2023, the Boulder County District Court Judge consolidated
eight lawsuits that were pending at that time into a single action for pretrial
purposes and has subsequently consolidated additional lawsuits that have
been filed. At the case management conference in February 2024, a trial
date was set for September 2025.
Colorado courts do not apply strict liability in determining an electric utility
company’s liability for fire-related damages. For inverse condemnation
claims, Colorado courts assess whether a defendant acted with intent to
take a plaintiff’s property or intentionally took an action which has the
natural consequence of taking the property. For negligence claims,
Colorado courts look to whether electric power companies have operated
their system with a heightened duty of care consistent with the practical
conduct of its business, and liability does not extend to occurrences that
cannot be reasonably anticipated.
Colorado law does not impose joint and several liability in tort actions.
Instead, under Colorado law, a defendant is liable for the degree or
percentage of the negligence or fault attributable to that defendant, except
where the defendant conspired with another defendant. A jury’s verdict in a
Colorado civil case must be unanimous. Under Colorado law, in a civil
action other than a medical malpractice action, the total award for
noneconomic loss is capped at $0.6 million per defendant for claims that
accrued at the time of the Marshall Fire unless the court finds justification to
exceed that amount by clear and convincing evidence, in which case the
maximum doubles.
Colorado law caps punitive or exemplary damages to an amount equal to
the amount of the actual damages awarded to the injured party, except the
court may increase any award of punitive damages to a sum up to three
times the amount of actual damages if the conduct that is the subject of the
claim has continued during the pendency of the case or the defendant has
acted in a willful and wanton manner during the action which further
aggravated plaintiff’s damages.
In the event Xcel Energy Inc. or PSCo was found liable related to this
litigation and were required to pay damages, such amounts could exceed
our insurance coverage of approximately $500 million and have a material
adverse effect on our financial condition, results of operations or cash
flows. However, due to uncertainty as to the cause of the fire and the extent
and magnitude of potential damages, Xcel Energy Inc. and PSCo are
unable to estimate the amount or range of possible losses in connection
with the Marshall Fire.
74
Rate Matters and Other
Environmental
Xcel Energy’s operating subsidiaries are involved in various regulatory
proceedings arising in the ordinary course of business. Until resolution,
typically in the form of a rate order, uncertainties may exist regarding the
ultimate rate treatment for certain activities and transactions. Amounts have
been recognized for probable and reasonably estimable losses that may
result. Unless otherwise disclosed, any reasonably possible range of loss in
excess of any recognized amount is not expected to have a material effect
on the consolidated financial statements.
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. NSP-
Minnesota notified the MPUC of its proposal to refund settlement proceeds
to customers through the FCA.
In March 2019, the MPUC approved NSP-Minnesota’s settlement refund
proposal. Additionally, the MPUC decided to withhold any decision as to
NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3
until after conclusion of an appeal pending between GE and NSP-
Minnesota’s insurers. In February 2020, the Minnesota Court of Appeals
affirmed the district court’s judgment in favor of GE.
In January 2021, the OAG and DOC recommended that NSP-Minnesota
refund approximately $17 million of replacement power costs previously
recovered through the FCA. NSP-Minnesota responded 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.
In July 2022, the MPUC referred the matter to the Office of Administrative
Hearings to conduct a contested case on the prudence of the replacement
power costs incurred by NSP-Minnesota. In 2023, NSP-Minnesota and
various parties
the DOC which
recommended a $56 million customer refund. The Xcel Large Industrial
customer group recommended a refund of $72 million. A final decision by
the MPUC is expected in mid-2024. A loss related to this matter is deemed
remote.
recommendations,
including
filed
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%.
The FERC subsequently issued various related orders related to ROE
methodology/calculations and
timing. NSP-Minnesota has processed
refunds to customers for applicable complaint periods based on the ROE in
the most recent applicable opinions.
The MISO TOs and various other parties have filed petitions for review of
the FERC’s most recent applicable opinions at the D.C. Circuit. In August
2022, the D.C. Circuit ruled that FERC had not adequately supported its
conclusions, vacated FERC’s related orders and remanded the issue back
to FERC for further proceedings, which remain pending. Additional
exposure, if any related to this matter is expected to be immaterial.
75
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
Xcel Energy is investigating, remediating or performing post-closure actions
at 12 historical MGP, landfill or other disposal sites across its service
territories, excluding sites that are being addressed under current coal ash
regulations (see below).
Xcel Energy has recognized approximately $20 million of costs/liabilities
from final resolution of these issues; however, the outcome and timing are
unknown. In addition, there may be insurance recovery and/or recovery
from other potentially responsible parties, offsetting a portion of costs
incurred.
Environmental Requirements — Water and Waste
Coal Ash Regulation — Xcel Energy’s operations are subject to federal and
state regulations that impose requirements for handling, storage, treatment
and disposal of solid waste, including the CCR Rule. As a specific
requirement of the CCR Rule, utilities must complete groundwater sampling
around their applicable landfills and surface impoundments as well as
perform corrective actions where offsite groundwater has been impacted.
If certain impacts to groundwater are detected, utilities are required to
perform additional groundwater investigations and/or perform corrective
actions beginning with an Assessment of Corrective Measures.
Investigation and/or corrective action related to groundwater impacts are
currently underway at four Xcel Energy sites under the federal CCR
program at a current estimated cost of at least $40 million. A liability has
been recorded and is expected to be fully recoverable through regulatory
mechanisms.
For required coal ash disposal, PSCo has executed an agreement with a
third party that will excavate and process ash for beneficial use (at two
sites) at a cost of approximately $45 million. An estimated liability has been
recorded and amounts are expected to be fully recoverable through
regulatory mechanisms.
Federal Clean Water Act Section 316(b) — The Federal Clean Water Act
requires the EPA to regulate cooling water intake structures to assure they
reflect the best technology available for minimizing impingement and
entrainment of aquatic species.
Estimated capital expenditures of approximately $50 million may be
required to comply with the requirements. Xcel Energy anticipates these
costs will be recoverable through regulatory mechanisms.
Environmental Requirements — Air
Xcel Energy’s AROs were as follows:
Clean Air Act NOx Allowance Allocations — In June 2023, the EPA
published final regulations for ozone under the “Good Neighbor” provisions
of the Clean Air Act. The final rule applies to generation facilities in
Minnesota, Texas and Wisconsin, as well as other states outside of our
service territory. The rule establishes an allowance trading program for
NOx that will impact subject Xcel Energy fossil fuel-fired electric generating
facilities. Subject facilities will have to secure additional allowances, install
NOx controls and/or develop a strategy of operations that utilizes the
existing allowance allocations. Guidelines are also established
for
allowance banking and emission limit backstops.
While the financial impacts of the final rule are uncertain and dependent on
market forces and anticipated generation, Xcel Energy anticipates the
annual costs could be significant, but would be recoverable through
regulatory mechanisms.
SPS and NSP-Minnesota have joined other companies in litigation
challenging
the EPA’s disapproval of Texas and Minnesota state
implementation plans. Currently, the regulation is under a judicial stay for
both Texas and Minnesota. The regulation may become applicable in those
states in the future, depending on the outcome of the litigation. The rule is
in effect in NSP-Wisconsin but has been managed without the additional
need for allowances.
In February 2024, the EPA proposed to partially disapprove New Mexico’s
state implementation plan and bring New Mexico into the federal Good
Neighbor plan. Xcel Energy continues to evaluate impacts to generation
units at SPS.
Regional Haze Rules — The EPA has proposed rules addressing Regional
Haze compliance in Texas, which address requirements for reasonable
progress at Tolk and BART at Harrington. As proposed, these rules would
not require additional controls at either facility, in part due to the conversion
of Harrington to gas in 2025 and the planned retirement of Tolk. These
rules will be monitored until final versions are published.
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 $3.2 billion and $2.9 billion for
2023 and 2022, respectively.
Jan. 1,
2023
Amounts
Incurred
(a)
Amounts
Settled
Accretion
Cash
Flow
Revisions
(b)
Dec.
31,
2023
$
2,160
$
514
348
48
307
3
$
—
10
—
—
—
—
—
—
(1)
—
—
$
105
$
(158) $ 2,107
19
15
1
14
—
(17)
526
(1)
—
361
49
(149)
172
—
3
$
3,380
$
10
$
(1) $
154
$
(325) $ 3,218
(Millions
of Dollars)
Electric
Nuclear
Wind
Steam, hydro
and other
production
Distribution
Natural gas
Transmission
and
distribution
Other
Miscellaneous
Total
liability
(a)
(b)
Amounts incurred relate to the Northern Wind farm placed in service in NSP-Minnesota.
In 2023, AROs were revised for changes in timing and estimates of cash flows.
Revisions in wind and nuclear AROs were primarily incurred due to changes in useful
lives. Changes in gas transmission and distribution AROs were a result of updated gas
line mileage and number of services, as well as changes to inflation and discount rate
assumptions.
(Millions
of Dollars)
Electric
Nuclear
Wind
Steam, hydro and
other production
Distribution
Natural gas
Transmission and
distribution
(c)
Other
Miscellaneous
Jan. 1,
2022
Amounts
Incurred
(a)
Accretion
Cash Flow
Revisions
(b)
Dec. 31,
2022
$
2,056
$
478
288
47
279
3
—
25
34
—
—
—
59
$
104
$
—
$
19
12
1
12
—
$
148
$
(8)
14
—
16
—
22
2,160
514
348
48
307
3
Total liability
$
3,151
$
$
3,380
(a)
(b)
(c)
Amounts incurred related to the wind farms placed in service in 2022 for NSP-Minnesota
(Dakota Range and Rock Aetna) and steam production pond remediation costs for
PSCo.
In 2022, AROs were revised for changes in timing and estimates of cash flows.
Revisions in steam, hydro and other production AROs were primarily related to changes
in cost estimates for remediation of ash containment facilities. Changes in gas
transmission and distribution AROs were primarily related to changes in labor rates
coupled with increased gas line mileage and number of services.
Prior periods have been reclassified to conform with current year presentation.
Indeterminate AROs — Outside of the recorded asbestos 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, 2023. Therefore, an ARO was
not recorded for these facilities.
76
Nuclear
Nuclear Insurance — NSP-Minnesota’s public liability for claims from any
nuclear incident is limited to $16.2 billion under the Price-Anderson
amendment to the Atomic Energy Act. NSP-Minnesota has $450 million of
coverage for its public liability exposure with a pool of insurance
companies. The remaining $15.8 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 $166 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 $25 million per reactor-incident during any
one year. Maximum assessments are subject to inflation adjustments.
insurance
NSP-Minnesota purchases
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 $490 million
and $420 million at Monticello and Prairie Island, respectively, 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
retroactive premium
NSP-Minnesota would have no exposure
assessments in case of a single incident under the business interruption
and the property damage insurance coverage.
for
NSP-Minnesota could be subject to annual maximum assessments of $15
million for business interruption insurance and $32 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. 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. In October 2023, a
CON for additional storage at the Monticello site was approved by the
MPUC to support possible life extension to 2040.
The PI dry-cask storage facility currently stores 50 of the 64 authorized
casks. In February 2023, NSP-Minnesota filed a CON with the MPUC for
additional storage at PI to support possible life extension to 2054.
Regulatory Plant Decommissioning Recovery — Decommissioning
activities for NSP-Minnesota’s nuclear facilities are planned to begin at the
end of each unit’s authorized retirement dates, which can be different than
the currently approved NRC operating licenses. These decommissioning
activities are planned to be completed at both facilities by 2101.
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. The MPUC reaffirmed a 60-year DECON
scenario, where Monticello continues operations under a 10-year license
extension (approved in August 2022). NRC approval of the extension is
pending.
77
In February 2023, NSP-Minnesota also filed an application with the NDPSC
for an Advance Determination of Prudence for continued operation of the
Monticello Plant until at least 2040. A decision is expected in 2024.
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. The MPUC ordered the
next triennial decommissioning study be filed by Dec. 1, 2024.
Obligations for decommissioning are expected to be funded 100% by the
external decommissioning trust fund. NSP-Minnesota had $3.2 billion and
$2.9 billion of assets held in external decommissioning trusts at Dec. 31,
2023, and 2022, respectively.
See Note 10 to the consolidated financial statements for additional
discussion.
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 is 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 4.4%). For
currently exiting asset classes, Xcel Energy has elected the practical
expedient under which non-lease components, such as asset maintenance
costs included in payments, are not deducted from 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, 2023
Dec. 31, 2022
PPAs
Other
Gross operating lease ROU assets
Accumulated amortization
Net operating lease ROU assets
$
$
1,832 $
315
2,147
(930)
1,217 $
1,669
244
1,913
(709)
1,204
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.
PPAs and Fuel Contracts
Non-Lease PPAs — NSP-Minnesota, PSCo and SPS have entered into
PPAs with other utilities and energy suppliers for purchased power to meet
system load and energy requirements, operating reserve obligations and as
part of wholesale and commodity trading activities. In general, these
agreements provide for energy payments, based on actual energy
delivered, and may also include capacity payments. Certain non-lease
PPAs with various expiration dates through 2033, contain minimum energy
purchase commitments. Total energy payments on those contracts were
$214 million, $182 million and $149 million in 2023, 2022 and 2021,
respectively.
Included in electric fuel and purchased power expenses for PPAs
accounted for as executory contracts were payments for capacity of $77
million, $75 million and $69 million in 2023, 2022 and 2021, 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, 2023, the estimated future payments for capacity and energy
that the utility subsidiaries of Xcel Energy are obligated to purchase
pursuant to these non-lease contracts, subject to availability, were as
follows:
(Millions of Dollars)
Capacity
Energy (a)
2024
2025
2026
2027
2028
$
$
80
45
28
9
1
2
$
165
$
207
94
47
10
10
18
386
(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 2024 and 2060. Xcel Energy is required to pay additional amounts
depending on actual quantities delivered under these agreements.
Estimated minimum purchases under these contracts as of Dec. 31, 2023:
(Millions of
Dollars)
2024
2025
2026
2027
2028
Thereafter
Total
Coal
Nuclear fuel
Natural gas
supply
Natural gas
storage and
transportation
$
350 $
142 $
339 $
157
81
56
21
1
179
63
180
50
177
13
—
—
—
—
311
284
276
238
111
442
$
666 $
791 $
352 $
1,662
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)
Gas storage facilities
Gas pipeline
Gross finance lease ROU assets
Accumulated amortization
Net finance lease ROU assets
Components of lease expense:
(Millions of Dollars)
Operating leases
Dec. 31, 2023
Dec. 31, 2022
$
$
160
$
21
181
(67)
114
$
160
21
181
(64)
117
2023
2022
2021
PPA capacity payments
Other operating leases (a)
Total operating lease expense
(b)
Finance leases
Amortization of ROU assets
Interest expense on lease liability
Total finance lease expense
$
$
$
$
241
$
241
$
42
39
283
$
280
$
3
$
15
18
$
4
$
16
20
$
251
36
287
7
17
24
(a)
(b)
Includes short-term lease expense of $3 million, $6 million, and $5 million for 2023,
2022 and 2021, respectively.
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, 2023:
(a) (b)
(Millions of Dollars)
2024
2025
2026
2027
2028
Thereafter
Total minimum obligation
Interest component of obligation
Present value of minimum
obligation
Less current portion
Noncurrent operating and
finance lease liabilities
Weighted-average remaining
lease term in years
(a)
$
244
$
245
216
162
107
259
1,233
(157)
$
1,076
33
26
22
22
22
162
287
(99)
188
$
277
$
271
238
184
129
421
1,520
(256)
1,264
(226)
$
1,038
$
10
10
9
8
8
173
218
(154)
64
(2)
62
8.2
36.8
Amounts do not include PPAs accounted for as executory contracts and/or contingent
payments, such as energy payments on renewable PPAs.
(b)
(c)
PPA operating leases contractually expire at various dates through 2039.
Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.
78
PPA
Operating
Leases
Other
Operating
Leases
Total
Operating
Leases
Finance
Leases
(c)
Thereafter
Total
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,
however 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 Xcel Energy does not have
the power to direct the activities that most significantly impact the entities’
economic performance.
The utility subsidiaries had approximately 3,751 MW and 3,961 MW of
capacity under long-term PPAs at Dec. 31, 2023 and 2022, respectively,
with entities that have been determined to be VIEs. These 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 2024 and December 2027, respectively. 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 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 with affordable rental
housing activities that qualify for low-income housing tax credits.
Eloigne and NSP-Wisconsin, as primary beneficiaries of these activities,
consolidate these limited partnerships in their consolidated financial
statements.
Amounts reflected in Xcel Energy’s consolidated balance sheets for these
investments include $41 million of assets and $35 million of liabilities at
Dec. 31, 2023, and $44 million of assets and $35 million of liabilities at Dec.
31, 2022.
Other
Technology Agreements — Xcel Energy has several contracts for
information technology services that extend through 2027. The contracts
are cancelable, although there are financial penalties for early termination.
Xcel Energy capitalized or expensed $28 million, $181 million and $103
million associated with these vendors in 2023, 2022 and 2021, respectively.
Committed minimum payments under these obligations as follows:
(Millions of Dollars)
2024
2025
2026
2027
2028
Thereafter
Minimum
Payments
$
18
14
13
12
—
—
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, 2023 and 2022, 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 $75 million and $62 million at Dec. 31,
2023 and 2022, respectively.
Indemnification Agreements — Xcel Energy
its
Other
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.
Inc. and
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:
Gains and
Losses on
Interest Rate
Cash Flow
Hedges
2023
Defined
Benefit
Pension and
Postretirement
Items
Total
$
(54)
$
(39)
$
(93)
(2)
(a)
3
—
1
(4)
—
2
(b)
(2)
(6)
3
2
(1)
$
(53)
$
(41)
$
(94)
(Millions of Dollars)
Accumulated other comprehensive
loss at Jan. 1
Other comprehensive loss before
reclassifications
Amortization of interest rate hedges
Amortization of net actuarial loss
Net current period other
comprehensive income (loss)
Accumulated other comprehensive
loss at Dec. 31
(a)
Included in interest charges.
Losses reclassified from net accumulated other comprehensive loss:
(b)
Included in the computation of net periodic pension and postretirement benefit costs.
See Note 11 for further information.
79
Gains and
Losses on
Interest Rate
Cash Flow
Hedges
2022
Defined
Benefit
Pension and
Postretirement
Items
Total
$
(75)
$
(48)
$ (123)
16
(a)
5
—
21
5
—
4
9
(b)
21
5
4
30
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)
Regulated Electric
2023
2022
2021
$
(54)
$
(39)
$
(93)
Operating revenues — external
$
11,446
$
12,123
$
11,205
Losses reclassified from net accumulated other comprehensive loss:
(Millions of Dollars)
Accumulated other comprehensive
loss at Jan. 1
Other comprehensive gain before
reclassifications
Amortization of interest rate hedges
Amortization of net actuarial loss
Net current period other
comprehensive income
Accumulated other comprehensive
loss at Dec. 31
(a)
Included in interest charges.
of NSP-Minnesota,
(b)
Included in the computation of net periodic pension and postretirement benefit costs.
See Note 11 for further information.
14. Segment Information
utility
electric
Xcel Energy evaluates performance by each utility subsidiary based on
profit or loss generated from the product or service provided, including the
regulated
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.
operating
results
Xcel Energy has the following reportable segments:
•
•
Regulated Electric — The
regulated electric utility segment
generates, purchases, transmits, distributes and sells electricity in
Colorado, Michigan, Minnesota, New Mexico, North Dakota, South
Dakota, Texas and Wisconsin. 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
purchases, transports, stores, distributes and sells natural gas
primarily in portions of Colorado, Michigan, Minnesota, North Dakota
and Wisconsin.
the necessary quantitative
Xcel Energy also presents All Other, which includes operating segments
with revenues below
thresholds. Those
operating segments primarily include steam revenue, appliance repair
services, non-utility real estate activities, revenues associated with
processing solid waste into RDF, investments in rental housing projects
that qualify for low-income housing tax credits and equity method
investments in EIP funds.
investments of $244 million and
Xcel Energy had equity method
$219 million as of Dec. 31, 2023 and 2022, 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.
Intersegment revenue
Total revenues
Depreciation and amortization
Interest charges and financing costs
Income tax benefit
Net income
Regulated Natural Gas
Operating revenues — external
Intersegment revenue
Total revenues
Depreciation and amortization
Interest charges and financing costs
Income tax expense
Net income
All Other
Total revenues
Depreciation and amortization
Interest charges and financing costs
Income tax benefit
Net loss
Consolidated Total
Total revenues
Reconciling eliminations
Total operating revenues
Depreciation and amortization
Interest charges and financing costs
Income tax benefit
Net income
15. Workforce Reduction
2
2
2
$
11,448
$
12,125
$
11,207
2,111
670
(135)
1,686
2,122
636
(162)
1,631
1,855
568
(96)
1,478
$
$
2,645
$
3,080
$
2,132
3
2
2
2,648
$
3,082
$
2,134
323
96
50
219
276
86
68
264
$
115
$
107
$
14
238
(61)
(134)
15
203
(41)
(159)
254
75
54
231
94
12
173
(28)
(112)
$
14,211
$
15,314
$
13,435
(5)
(4)
(4)
$
14,206
$
15,310
$
13,431
2,448
1,004
(146)
1,771
2,413
925
(135)
1,736
2,121
816
(70)
1,597
In 2023, Xcel Energy implemented workforce actions to align resources and
investments with evolving business and customer needs, and streamline
the organization for long-term success.
In September 2023, Xcel Energy announced a voluntary retirement
program to a group of eligible non-bargaining employees, with an enhanced
retirement package including certain health care and cash benefits for
accepted employees. Approximately 400 employees retired under this
program in December 2023.
In November 2023, Xcel Energy, Inc. also reduced its non-bargaining
involuntary
workforce by approximately 150 employees
severance program.
through an
80
In the fourth quarter of 2023, Xcel Energy recorded total expense of
$72 million related to these workforce actions, primarily related to the
estimated cost of future health plan subsidies and other medical benefits for
the voluntary retirement program, as well as severance and other employee
payouts and legal and other professional fees.
For further information on the estimated costs and obligations for future
health plan subsidies and other medical benefits, see Note 11 to the
consolidated financial statements.
ITEM 9 — CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A — CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Xcel Energy maintains a set of disclosure controls and procedures
designed to ensure that information required to be disclosed in reports that
it files or submits under the Securities Exchange Act of 1934 is recorded,
processed, summarized, and reported within the time periods specified in
SEC rules and forms. In addition, the disclosure controls and procedures
ensure that information required to be disclosed is accumulated and
communicated to management, including the CEO and CFO, allowing
timely decisions regarding required disclosure.
As of Dec. 31, 2023, based on an evaluation carried out under the
supervision and with the participation of Xcel Energy’s management,
including the CEO and CFO, of the effectiveness of its disclosure controls
and procedures, the CEO and CFO have concluded that Xcel Energy’s
disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
No changes in Xcel Energy’s internal control over financial reporting
occurred during the most recent fiscal quarter ended Dec. 31, 2023 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, 2023 on internal controls under section 404 of the Sarbanes-Oxley
Act of 2002, Xcel Energy conducted testing and monitoring of its internal
control over financial reporting. Based on the control evaluation, testing and
remediation performed, Xcel Energy did not identify any material control
weaknesses, as defined under the standards and rules issued by the Public
Company Accounting Oversight Board, as approved by the SEC and as
indicated in Xcel Energy’s Management Report on Internal Controls over
Financial Reporting, which is contained in Item 8 herein.
ITEM 9B — OTHER INFORMATION
Effective March 1, 2024, Melissa Ostrom, Vice President, Controller at Xcel
Energy Inc., will begin serving as principal accounting officer of Xcel
Energy. Brian Van Abel, Xcel Energy’s Executive Vice President, Chief
Financial Officer will cease serving as Xcel Energy’s principal accounting
officer effective March 1, 2024.
Melissa Ostrom, age 40, has served as Vice President, Controller at Xcel
Energy since April 2022. Prior to that Ms. Ostrom served as Director,
Financial Forecasting and Reporting from November 2018 to March 2022
and as Director, Capital Asset Accounting from April 2016 to November
2018. Ms. Ostrom served in various other finance and accounting positions
of increasing responsibility since joining Xcel Energy in 2010.
There are no arrangements or understandings between Ms. Ostrom and
any other person pursuant to which she was selected to serve as principal
accounting officer. There are no family relationships between Ms. Ostrom
and any director or officer of Xcel Energy or any other related-party
transaction involving Ms. Ostrom and Xcel Energy.
There were no material amendments made to Ms. Ostrom’s compensation
in connection with her service as principal accounting officer.
On Feb. 21, 2024, the Board of Directors of Xcel Energy approved the Xcel
Energy Inc. Annual Incentive Plan (the “Plan”) in order to provide for annual
incentive awards to eligible employees. The Plan replaces the Xcel Energy
Inc. Executive Annual Incentive Award Subplan pursuant to the Xcel
Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan. The
Governance, Compensation and Nominating Committee (the “Committee”)
of Xcel Energy’s Board of Directors administers the Plan and has authority
to determine when and to whom awards will be granted, the amount of
awards, and the terms and conditions of awards including the applicable
performance goals, and will certify the level of goal achievement for award
payouts. Awards will be paid in the form of cash or, if provided by the
Committee, eligible employees may elect to receive payment in the form of
stock or restricted stock, or a combination of the foregoing, and any shares
of stock will be
then-current equity
issued under Xcel Energy’s
compensation plan, all on such terms as the Committee may determine.
The Plan also includes a “clawback” provision providing that awards are
subject to recoupment under Xcel Energy’s clawback policies in effect from
time to time. A copy of the Plan is filed as Exhibit 10.18 hereto and
incorporated herein by reference.
None of the Company’s directors or officers adopted, modified, or
terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1
trading arrangement during the Company’s fiscal quarter ended Dec. 31,
2023.
ITEM 9C — DISCLOSURE REGARDING FOREIGN JURISDICTIONS
THAT PREVENT INSPECTIONS
Not applicable.
PART III
ITEM 10 — DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE
Information required under this Item with respect to Directors and
Corporate Governance is set forth in Xcel Energy Inc.’s Proxy Statement
for its 2024 Annual Meeting of Shareholders, which is expected to be filed
on April 9, 2024, which is incorporated by reference. Information with
respect to Executive Officers is included in Item 1 to this report.
ITEM 11 — EXECUTIVE COMPENSATION
Information required under this Item is set forth in Xcel Energy Inc.’s Proxy
Statement
is
for
incorporated by reference.
its 2024 Annual Meeting of Shareholders, which
81
ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information required under this Item (aggregate fees billed to us by our
principal accountant, Deloitte & Touche LLP (PCAOB ID No. 34)) is
contained in Xcel Energy Inc.’s Proxy Statement for its 2024 Annual
Meeting of Shareholders, which is incorporated by reference.
ITEM 12 — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS
Information required under this Item is contained in Xcel Energy Inc.’s
Proxy Statement for its 2024 Annual Meeting of Shareholders, which is
incorporated by reference.
ITEM
TRANSACTIONS, AND DIRECTOR INDEPENDENCE
13 — CERTAIN RELATIONSHIPS AND RELATED
Information required under this Item is contained in Xcel Energy Inc.’s
Proxy Statement for its 2024 Annual Meeting of Shareholders, which is
incorporated by reference.
PART IV
ITEM 15 — EXHIBIT AND FINANCIAL STATEMENT SCHEDULES
1
Consolidated Financial Statements
Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2023.
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, 2023, 2022, and 2021.
Consolidated Statements of Comprehensive Income — For each of the three years ended Dec. 31, 2023, 2022, and 2021.
Consolidated Statements of Cash Flows — For each of the three years ended Dec. 31, 2023, 2022, and 2021.
Consolidated Balance Sheets — As of Dec. 31, 2023, 2022.
Consolidated Statements of Common Stockholders’ Equity — For each of the three years ended Dec. 31, 2023, 2022, and 2021.
Schedule I — Condensed Financial Information of Registrant.
Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2023, 2022, and 2021.
Exhibits
Indicates incorporation by reference
Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
2
3
*
+
Xcel Energy Inc.
Exhibit
Number Description
3.01*
Amended and Restated Articles of Incorporation of Xcel Energy Inc.
3.02*
Bylaws of Xcel Energy Inc., as Amended and Restated on August 23, 2023
4.01*
Description of Securities
Report or Registration Statement
Xcel Energy Inc. Form 8-K dated May 16,
2012
Xcel Energy Inc. Form 8-K dated August 23,
2023
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2019
Indenture, dated as of Dec. 1, 2000, by and between Xcel Energy Inc. and Computershare Trust Company, N.A. (as
successor to Wells Fargo Bank Minnesota, National Association), as Trustee
Xcel Energy Inc. Form 8-K dated Dec. 14,
2000
Exhibit
Reference
3.01
3.02
4.01
4.01
4.02*
4.03*
4.04*
Supplemental Indenture No. 3, dated as of June 1, 2006, by and between Xcel Energy Inc. and Computershare Trust
Company, N.A. (as successor to Wells Fargo Bank, National Association), as Trustee, creating $300 million of 6.50%
Senior Notes, Series due July 1, 2036
Junior Subordinated Indenture, dated as of Jan. 1, 2008, by and between Xcel Energy Inc. and Computershare Trust
Company, N.A. (as successor to Wells Fargo Bank, National Association), as Trustee
4.05*
Replacement Capital Covenant, dated Jan. 16, 2008
4.06*
4.07*
4.08*
4.09*
Supplemental Indenture No. 6, dated as of Sept. 1, 2011, by and between Xcel Energy Inc. and Computershare Trust
Company, N.A. (as successor to Wells Fargo Bank, National Association), as Trustee, creating $250 million of 4.80%
Senior Notes, Series due Sept. 15, 2041
Supplemental Indenture No. 8, dated as of June 1, 2015, by and between Xcel Energy Inc. and Computershare Trust
Company, N.A. (as successor to Wells Fargo Bank, National Association), as Trustee, creating $250 million aggregate
principal amount of 3.30% Senior Notes, Series due June 1, 2025
Supplemental Indenture No. 10, dated as of Dec. 1, 2016, by and between Xcel Energy Inc. and Computershare Trust
Company, N.A. (as successor to Wells Fargo Bank, National Association, as Trustee), creating $500 million aggregate
principal amount of 3.35% Senior Notes, Series due Dec. 1, 2026
Supplemental Indenture No. 11, dated as of June 25, 2018, by and between Xcel Energy Inc. and Computershare Trust
Company, N.A. (as successor to Wells Fargo Bank, National Association), as Trustee, creating $500 million aggregate
principal amount of 4.00% Senior Notes, Series due June 15, 2028
82
Xcel Energy Inc. Form 8-K dated June 6, 2006 4.01
Xcel Energy Inc. Form 8-K dated Jan. 16,
2008
Xcel Energy Inc. Form 8-K dated Jan. 16,
2008
Xcel Energy Inc. Form 8-K dated Sept. 12,
2011
4.01
4.03
4.01
Xcel Energy Inc. Form 8-K dated June 1, 2015 4.01
Xcel Energy Inc. Form 8-K dated Dec. 1, 2016 4.01
Xcel Energy Inc. Form 8-K dated June 25,
2018
4.01
4.10*
4.11*
4.12*
4.13*
4.14*
10.01*
Supplemental Indenture No. 12, dated as of Nov. 7, 2019 by and between Xcel Energy Inc. and Computershare Trust
Company, N.A. (as successor to Wells Fargo Bank, National Association), as Trustee, creating $500 million aggregate
principal amount of 2.60% Senior Notes, Series due Dec 1. 2029 and $500 million aggregate principal amount of 3.50%
Senior Notes, Series due Dec. 1, 2049
Supplemental Indenture No. 13, dated as of April 1, 2020 by and between Xcel Energy Inc. and Computershare Trust
Company, N.A. (as successor to Wells Fargo Bank, National Association), as Trustee creating $600 million aggregate
principal amount of 3.40% Senior Notes, Series due June 1, 2030
Supplemental Indenture No. 15, dated as of Nov. 3, 2021 between Xcel Energy Inc. and Computershare Trust
Company, N.A. (as successor to Wells Fargo Bank, National Association), as Trustee, creating $500 million aggregate
principal amount of 1.75% Senior Notes, Series due March 15, 2027 and $300 million aggregate principal amount of
2.35% Senior Notes, Series due Nov. 15, 2031
Supplemental Indenture No. 16, dated as of May 6, 2022, by and between Xcel Energy Inc. and Computershare Trust
Company, N.A. (as successor to Wells Fargo Bank, National Association), as trustee, creating $700 million aggregate
principal amount of 4.60% Senior Notes, Series due June 1, 2032
Supplemental Indenture No. 17, dated as of August 3, 2023, by and between Xcel Energy Inc. and Computershare Trust
Company, N.A. (as successor to Wells Fargo Bank, National Association), as trustee, creating $800 million aggregate
principal amount of 5.45% Senior Notes, Series due August 15, 2033.
Xcel Energy Inc. Nonqualified Pension Plan (2009 Restatement)
10.02*+
Xcel Energy Senior Executive Severance and Change-in-Control Policy (2009 Restatement)
10.03*+
Second Amendment to Exhibit 10.02 dated Oct. 26, 2011
10.04*+
Fifth Amendment to Exhibit 10.02 dated May 3, 2016
10.05*+
Seventh Amendment to Exhibit 10.02 dated May 7, 2018
10.06*+
Eighth Amendment to Exhibit 10.02 dated March 31, 2020
10.07*+
Ninth Amendment to Exhibit 10.02 dated May 22, 2020
10.08*+
Xcel Energy Inc. Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009
10.09*+
Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement)
10.10*+
First Amendment to Exhibit 10.09 effective Nov. 29, 2011
10.11*+
Second Amendment to Exhibit 10.09 dated May 21, 2013
10.12*+
Third Amendment to Exhibit 10.09 dated Sept. 30, 2016
10.13*+
Fourth Amendment to Exhibit 10.09 dated Oct. 23, 2017
10.14*+
Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan
Xcel Energy Inc. Form 8-K dated Nov. 7, 2019 4.01
Xcel Energy Inc. Form 8-K dated April 1, 2020
4.01
Xcel Energy Inc. Form 8-K dated Nov. 3, 2021 4.01
Xcel Energy Form 8-K dated May 6, 2022
4.01
Xcel Energy Form 8-K dated August 3, 2023
4.01
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2008
10.02
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2008
10.05
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2011
10.18
Xcel Energy Inc. Form 10-Q for the quarter
ended June 30, 2016
Xcel Energy Inc. Form 10-Q for the quarter
ended June 30, 2018
Xcel Energy Inc. Form 10-Q for the quarter
ended March 31, 2020
Xcel Energy Inc. Form 10-Q for the quarter
ended June 30, 2020
10.01
10.01
10.02
10.01
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2008
10.17
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2008
10.07
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2011
10.17
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2013
10.22
Xcel Energy Inc. Form 10-Q for the quarter
ended Sept. 30, 2016
Xcel Energy Inc. Form 10-Q for the quarter
ended Sept. 30, 2017
10.01
10.1
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2018
10.34
Form of Award Agreement for Restricted Stock Units and/or Performance Share Units under the Xcel Energy Inc. 2015
Omnibus Incentive Plan for awards between 2020-2023
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2019
10.32
10.15*+
10.16+
10.17*+
Form of Award Agreement for Restricted Stock Units and/or Performance Share Units under the Xcel Energy Inc. 2015
Omnibus Incentive Plan for awards since 2024
Form of Award Agreement for Retention-Based Restricted Stock Units under the Xcel Energy Inc. Amended and
Restated 2015 Omnibus Incentive Plan
10.18+
Xcel Energy Inc. Annual Incentive Plan, effective Feb. 21, 2024
10.19*+
Summary of Non-Employee Director Compensation, effective as of May 24, 2023
Xcel Energy Inc. Form 8-K dated Dec. 10,
2021
10.01
Xcel Energy Inc. Form 10-Q for the quarter
ended June 30, 2023
10.01
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 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
10.22*+
Form of Services Agreement between Xcel Energy Services Inc. and utility companies
10.23*
Fourth Amended and Restated Credit Agreement, dated as of September 19, 2022, 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, and Citibank, N.A., MUFG Bank, Ltd., and Wells
Fargo Bank, National Association., as Documentation Agents
Xcel Energy Inc. Form U5B dated Nov. 16,
2000
Xcel Energy Inc. Form 8-K dated Sept. 19,
2022
H-1
99.01
NSP-Minnesota
4.15*
4.16*
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
Supplemental Trust Indenture, dated as of June 1, 1995, from NSP-Minnesota to Harris Trust and Savings Bank, as
Trustee, creating $250 million aggregate principal amount of 7.125% First Mortgage Bonds, Series due July 1, 2025
Xcel Energy Inc. Form S-3 dated April 18,
2018
4(b)(3)
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2017
4.11
83
4.17*
Supplemental Trust Indenture, dated as of March 1, 1998, from NSP-Minnesota to Harris Trust and Savings Bank, as
Trustee, creating $150 million aggregate principal amount of 6.5% First Mortgage Bonds, Series due March 1, 2028
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2017
4.18*
Supplemental Trust Indenture, dated as of Aug. 1, 2000 (Assignment and Assumption of Trust Indenture)
NSP-Minnesota Form 10-12G dated Oct. 5,
2000
Indenture, dated as of July 1, 1999, by and between NSP-Minnesota and Wells Fargo Bank Minnesota, NA (as
successor to Norwest Bank Minnesota, NA), as Trustee, providing for the issuance of Sr. Debt Securities
Xcel Energy Inc. Form S-3 dated April 18,
2018
4.12
4.51
4(b)(7)
4.63
Supplemental Indenture No. 2, dated Aug. 18, 2000, supplemental to the Indenture, dated as of July 1, 1999, among
Xcel Energy Inc., NSP-Minnesota and Wells Fargo Bank Minnesota, NA (as successor to Norwest Bank Minnesota, NA),
as Trustee
Supplemental Trust Indenture, dated as of July 1, 2005, by and between NSP-Minnesota and The Bank of New York
Mellon Trust Company, NA (as successor to BNY Midwest Trust Company), as Trustee, creating $250 million aggregate
principal amount of 5.25% First Mortgage Bonds, Series due July 15, 2035
Supplemental Trust Indenture, dated as of May 1, 2006, by and between NSP-Minnesota and The Bank of New York
Mellon Trust Company, NA (as successor to BNY Midwest Trust Company), as Trustee, creating $400 million aggregate
principal amount of 6.25% First Mortgage Bonds, Series due June 1, 2036
Supplemental Trust Indenture, dated as of June 1, 2007, by and between NSP-Minnesota and The Bank of New York
Mellon Trust Company, NA (as successor to BNY Midwest Trust Company), as Trustee, creating $350 million aggregate
principal amount of 6.20% First Mortgage Bonds, Series due July 1, 2037
Supplemental Trust Indenture, dated as of Nov. 1, 2009, by and between NSP-Minnesota and The Bank of New York
Mellon Trust Company., NA, as Trustee, creating $300 million aggregate principal amount of 5.35% First Mortgage
Bonds, Series due Nov. 1, 2039
Supplemental Trust Indenture, dated as of Aug. 1, 2010, by and between NSP-Minnesota and The Bank of New York
Mellon Trust Company, NA, as Trustee, creating $250 million aggregate principal amount of 4.85% First Mortgage
Bonds, Series due Aug. 15, 2040
Supplemental Trust Indenture, dated as of Aug. 1, 2012, by and between NSP-Minnesota and The Bank of New York
Mellon Trust Company, NA, as Trustee, creating $500 million aggregate principal amount of 3.40% First Mortgage
Bonds, Series due Aug. 15, 2042
Supplemental Trust Indenture, dated as of May 1, 2014, by and between NSP-Minnesota and The Bank of New York
Mellon Trust Company, N.A., as Trustee, creating $300 million aggregate principal amount of 4.125% First Mortgage
Bonds, Series due May 15, 2044
Supplemental Trust Indenture, dated as of Aug. 1, 2015, by and between NSP-Minnesota and The Bank of New York
Mellon Company, N.A., as Trustee, creating $300 million aggregate principal amount of 4.00% First Mortgage Bonds,
Series due Aug. 15, 2045
Supplemental Trust Indenture, dated as of May 1, 2016, by and between NSP-Minnesota and The Bank of NY Mellon
Trust Company, N.A., as Trustee, creating $350 million aggregate principal amount of 3.60% First Mortgage Bonds,
Series due May 15, 2046
Supplemental Trust Indenture, dated as of Sept. 1, 2017, by and between NSP-Minnesota and The Bank of New York
Mellon Trust Company, N.A., as Trustee, creating $600 million aggregate principal amount of 3.60% First Mortgage
Bonds, Series due Sept. 15, 2047
Supplemental Trust Indenture, dated as of Sept. 1, 2019, by and between NSP-Minnesota and The Bank of New York
Mellon Trust Company, N.A., as Trustee, creating $600 million aggregate principal amount of 2.90% First Mortgage
Bonds, Series due March 1, 2050
Supplemental Indenture, dated as of June 8, 2020, by and between NSP-Minnesota and The Bank of New York Mellon
Trust Company, N.A., as Trustee, creating $700 million aggregate principal amount of 2.60% First Mortgage Bonds,
Series due June 1, 2051
Supplemental Indenture, dated as of March 1, 2021, by and between NSP-Minnesota and The Bank of New York Mellon
Trust Company, N.A., as Trustee, creating $425 million principal amount of 2.25% First Mortgage Bonds, Series due
April 1, 2031 and $425 million principal amount of 3.20% First Mortgage Bonds, Series due April 1, 2052
Supplemental Indenture, dated as of May 1, 2022, by and between NSP-Minnesota and The Bank of New York Mellon
Trust Company, N.A., as Trustee, creating $500 million aggregate principal amount of 4.50% First Mortgage Bonds,
Series due June 1, 2052
Supplemental Trust Indenture dated as of May 1, 2023 between NSP-Minnesota and The Bank of New York Mellon
Trust Company, N.A., as successor Trustee, creating $800 million aggregate principal amount of 5.10% First Mortgage
Bonds, Series due May 15, 2053.
Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota
Fourth Amended and Restated Credit Agreement, dated as of September 19, 2022, 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, and Citibank, N.A., MUFG Bank, Ltd., and Wells
Fargo Bank, National Association, as Documentation Agents
NSP-Minnesota Form 10-12G dated Oct. 5,
2000
NSP-Minnesota Form 8-K dated July 14, 2005 4.01
NSP-Minnesota Form 8-K dated May 18, 2006 4.01
NSP-Minnesota Form 8-K dated June 19,
2007
NSP-Minnesota Form 8-K dated Nov. 16,
2009
4.01
4.01
NSP-Minnesota Form 8-K dated Aug. 4, 2010
4.01
NSP-Minnesota Form 8-K dated Aug. 13,
2012
4.01
NSP-Minnesota Form 8-K dated May 13, 2014 4.01
NSP-Minnesota Form 8-K dated Aug. 11,
2015
4.01
NSP-Minnesota Form 8-K dated May 31, 2016 4.01
NSP-Minnesota Form 8-K dated Sept. 13,
2017
NSP-Minnesota Form 8-K dated Sept. 10,
2019
4.01
4.01
NSP-Minnesota 8-K dated June 15, 2020
4.01
NSP-Minnesota 8-K dated March 30, 2021
4.01
NSP-Minnesota 8-K dated May 9, 2022
4.01
NSP-Minnesota 8-K dated May 8, 2023
4.01
NSP-Wisconsin Form S-4 dated Jan. 21, 2004 10.01
Xcel Energy Inc. Form 8-K dated Sept. 19,
2022
99.02
4.19*
4.20*
4.21*
4.22*
4.23*
4.24*
4.25*
4.26*
4.27*
4.28*
4.29*
4.30*
4.31*
4.32*
4.33*
4.34*
4.35*
10.23*
10.24*
NSP-Wisconsin
4.36*
4.37*
4.38*
4.39*
4.40*
Supplemental and Restated Trust Indenture, dated as of March 1, 1991, by and between NSP-Wisconsin and U.S. Bank
Trust Company, National Association (as successor to First Wisconsin Trust Company), as Trustee providing for the
issuance of First Mortgage Bonds
Trust Indenture, dated Sept. 1, 2000, by and between NSP-Wisconsin and U.S. Bank Trust Company, National
Association (as successor to Firstar Bank, N.A.), as Trustee
Supplemental Trust Indenture, dated as of Sept. 1, 2008, by and between NSP-Wisconsin and U.S. Bank Trust
Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $200 million
aggregate principal amount of 6.375% First Mortgage Bonds, Series due Sept. 1, 2038
Supplemental Trust Indenture, dated as of Oct. 1, 2012, by and between NSP-Wisconsin and U.S. Bank Trust Company,
National Association (as successor to U.S. Bank National Association), as Trustee, creating $100 million aggregate
principal amount of 3.70% First Mortgage Bonds, Series due Oct. 1, 2042
Supplemental Trust Indenture, dated as of June 1, 2014, between NSP-Wisconsin and U.S. Bank Trust Company,
National Association (as successor to U.S. Bank National Association), as Trustee, creating $100 million aggregate
principal amount of 3.30% First Mortgage Bonds, Series due June 15, 2024
Xcel Energy Inc. Form S-3 dated April 18,
2018
4(c)(3)
NSP-Wisconsin Form 8-K dated Sept. 25,
2000
4.01
NSP-Wisconsin Form 8-K dated Sept. 3, 2008
4.01
NSP-Wisconsin Form 8-K dated Oct. 10, 2012 4.01
NSP-Wisconsin Form 8-K dated June 23,
2014
4.01
84
4.41*
4.42*
4.43*
4.44*
4.45*
4.46*
10.25*
10.26*
PSCo
4.47*
4.48*
4.49*
4.50*
4.51*
4.52*
4.53*
4.54*
4.55*
4.56*
4.57*
4.58*
4.59*
4.60*
4.61*
Supplemental Trust Indenture, dated as of Nov 1, 2017, by and between NSP-Wisconsin and U.S. Bank Trust Company,
National Association (as successor to U.S. Bank National Association), as Trustee, creating $100 million aggregate
principal amount of 3.75% First Mortgage Bonds, Series due Dec. 1, 2047
Supplemental Indenture, dated as of Sept. 1, 2018, by and between NSP-Wisconsin and U.S. Bank Trust Company,
National Association (as successor to U.S. Bank National Association), as Trustee, creating $200 million aggregate
principal amount of 4.20% First Mortgage Bonds, Series due Sept. 1, 2048
Supplemental Trust Indenture, dated as of May 18, 2020, by and between NSP-Wisconsin and U.S. Bank Trust
Company, National Association (as successor to U.S. Bank National Association), as Trustee, creating $100 million
aggregate principal amount of 3.05% First Mortgage Bonds, Series due May 1, 2051
Supplemental Indenture dated as of July 19, 2021 between NSP-Wisconsin and U.S. Bank Trust Company, National
Association (as successor to U.S. Bank National Association), as Trustee, creating $100 million principal amount of
2.82% First Mortgage Bonds, Series due May 1, 2051
Supplemental Trust Indenture, dated as of July 15, 2022, by and between NSP-Wisconsin and U.S. Bank Trust
Company, National Association, as Trustee, creating $100 million aggregate principal amount of 4.86% First Mortgage
Bonds, Series due Sept. 15, 2052
Supplemental Indenture dated as of May 10, 2023 between NSP-Wisconsin and U.S. Bank Trust Company, National
Association, as successor Trustee, creating 5.30% First Mortgage Bonds, Series due June 15, 2053
NSP-Wisconsin Form 8-K dated Dec. 4, 2017
4.01
NSP-Wisconsin Form 8-K dated Sept. 12,
2018
4.01
NSP-Wisconsin Form 8-K dated May 26, 2020 4.01
NSP-Wisconsin Form 8-K dated July 20, 2021
4.01
NSP-Wisconsin Form 8-K dated July 15, 2022
4.01
NSP-Wisconsin Form 8-K dated May 10, 2023 4.01
Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota
NSP-Wisconsin Form S-4 dated Jan. 21, 2004 10.01
Fourth Amended and Restated Credit Agreement, dated as of Sept. 19, 2022, 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, and Citibank, N.A., MUFG Bank, Ltd. and Wells Fargo
Bank, National Association, as Documentation Agents
Xcel Energy Inc. Form 8-K dated Sept. 19,
2022
99.05
Indenture, dated as of Oct. 1, 1993, by and between PSCo and U.S. Bank Trust Company, National Association (as
successor to Morgan Guaranty Trust Company of New York), as Trustee, providing for the issuance of First Collateral
Trust Bonds
Supplemental Indenture No. 17, dated as of Aug. 1, 2007, by and between PSCo and U.S. Bank Trust Company,
National Association (as successor to U.S. Bank National Association), as Trustee, creating $350 million of 6.25% First
Mortgage Bonds, Series No. 17 due Sept. 1, 2037
Supplemental Indenture No. 18, dated as of Aug. 1, 2008, by and between PSCo and U.S. Bank Trust Company,
National Association (as successor to U.S. Bank National Association), as Trustee, creating $300 million aggregate
principal amount of 6.50% First Mortgage Bonds, Series No. 19 due Aug. 1, 2038
Supplemental Indenture No. 21, dated as of Aug. 1, 2011, by and between PSCo and U.S. Bank Trust Company,
National Association (as successor to U.S. Bank National Association), as Trustee, creating $250 million aggregate
principal amount of 4.75% First Mortgage Bonds, Series No. 22 due Aug. 15, 2041
Supplemental Indenture No. 22, dated as of Sept. 1, 2012, between PSCo and U.S. Bank Trust Company, National
Association (as successor to U.S. Bank National Association), as Trustee, creating $500 million aggregate principal
amount of 3.60% First Mortgage Bonds, Series No. 24 due Sept. 15, 2042
Supplemental Indenture No. 24, dated as of March 1, 2014, by and between PSCo and U.S. Bank Trust Company,
National Association (as successor to U.S. Bank National Association), as Trustee, creating $300 million aggregate
principal amount of 4.30% First Mortgage Bonds, Series No. 27 due March 15, 2044
Supplemental Indenture No. 25, dated as of May 1, 2015, by and between PSCo and U.S. Bank Trust Company,
National Association (as successor to U.S. Bank National Association), as Trustee, creating $250 million aggregate
principal amount of 2.90% First Mortgage Bonds, Series No. 28 due May 15, 2025
Supplemental Indenture No. 26, dated as of June 1, 2016, by and between PSCo and U.S. Bank Trust Company,
National Association (as successor to U.S. Bank National Association), as Trustee, creating $250 million aggregate
principal amount of 3.55% First Mortgage Bonds, Series No. 29 due June 15, 2046
Supplemental Indenture No. 27, dated as of June 1, 2017, by and between PSCo and U.S. Bank Trust Company,
National Association (as successor to U.S. Bank National Association), as Trustee, creating $400 million aggregate
principal amount of 3.80% First Mortgage Bonds, Series No. 30 due June 15, 2047
Supplemental Indenture No. 28, dated as of June 1, 2018, by and between PSCo and U.S. Bank Trust Company,
National Association (as successor to U.S. Bank National Association), as Trustee, creating $350 million aggregate
principal amount of 3.70% First Mortgage Bonds, Series No. 31 due June 15, 2028, and $350 million aggregate principal
amount of 4.10% First Mortgage Bonds, Series No. 32 due June 15, 2048
Supplemental Indenture No. 29, dated as of March 1, 2019, by and between PSCo and U.S. Bank Trust Company,
National Association (as successor to U.S. Bank National Association), as Trustee, creating $400 million aggregate
principal amount of 4.05% First Mortgage Bonds, Series No. 33 due Sept. 15, 2049
Supplemental Indenture No. 30, dated as of Aug. 1, 2019, by and between PSCo and U.S. Bank Trust Company,
National Association (as successor to U.S. Bank National Association), as Trustee, creating $550 million aggregate
principal amount of 3.20% First Mortgage Bonds, Series No. 34 due March 1, 2050
Supplemental Indenture No. 31, dated as of May 1, 2020, by and between PSCo and U.S. Bank Trust Company,
National Association (as successor to U.S. Bank National Association), as Trustee, creating $375 million aggregate
principal amount of 2.70% First Mortgage Bonds, Series No. 35 due Jan. 15, 2051 and $375 million aggregate principal
amount of 1.90% First Mortgage Bonds, Series No. 36 due Jan. 15, 2031
Supplemental Indenture No. 32, dated as of February 1, 2021, by and between PSCo and U.S. Bank Trust Company,
National Association (as successor to U.S. Bank National Association), as Trustee, creating $750 million aggregate
principal amount of 1.875% First Mortgage Bonds, Series No. 37 due June 15, 2031
Supplemental Indenture No. 33, dated as of May 1, 2022, by and between PSCo and U.S. Bank Trust Company,
National Association, as Trustee, creating $300 million aggregate principal amount of 4.10% First Mortgage Bonds,
Series No. 38 due June 1, 2032 and $400 million aggregate principal amount of 4.50% First Mortgage Bonds, Series No.
39 due June 1, 2052
Xcel Energy Inc. Form S-3 dated April 18,
2018
4(d)(3)
PSCo Form 8-K dated Aug. 8, 2007
PSCo Form 8-K dated Aug. 6, 2008
PSCo Form 8-K dated Aug. 9, 2011
PSCo Form 8-K dated Sept. 11, 2012
4.01
4.01
4.01
4.01
PSCo Form 8-K dated March 10, 2014
4.01
PSCo Form 8-K dated May 12, 2015
PSCo Form 8-K dated June 13, 2016
PSCo Form 8-K dated June 19, 2017
PSCo Form 8-K dated June 21, 2018
4.01
4.01
4.01
4.01
PSCo Form 8-K dated March 13, 2019
4.01
PSCo Form 8-K dated August 13, 2019
4.01
PSCo Form 8-K dated May 15, 2020
4.01
PSCo Form 8-K dated March 1, 2021
PSCo Form 8-K dated May 17, 2022
4.01
4.01
4.62*
10.27*
Supplemental Indenture No. 34, dated as of March 1, 2023, between PSCo and U.S. Bank Trust Company, National
Association, as successor Trustee, creating $850 million principal amount of 5.25% First Mortgage Bonds, Series No. 40
due April 1, 2053.
Proposed Settlement Agreement, excerpts, as filed with the CPUC
PSCo Form 8-K dated April 3, 2023
4.01
Xcel Energy Inc. Form 8-K dated Dec. 3, 2004 99.02
85
10.28*
Fourth Amended and Restated Credit Agreement, dated as of September 19, 2022, 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, and Citibank, N.A., MUFG Bank, Ltd., and Wells Fargo
Bank, National Association, as Documentation Agents
Xcel Energy Inc. Form 8-K dated Sept. 19,
2022
99.03
SPS
4.63*
4.64*
4.65*
4.66*
4.67*
4.68*
4.69*
4.70*
4.71*
4.72*
4.73*
4.74*
4.75*
10.29*
Indenture, dated as of Feb. 1, 1999, by and between SPS and The Chase Manhattan Bank, as Trustee
SPS Form 8-K dated Feb. 25, 1999
Third Supplemental Indenture, dated as of Oct. 1, 2003, by and between SPS and JPMorgan Chase Bank (as successor
to The Chase Manhattan Bank), as Trustee, creating $100 million aggregate principal amount of Series C Notes, 6% due
Oct. 1, 2033 and Series D Notes, 6% due Oct. 1, 2033
Fourth Supplemental Indenture, dated as of Oct. 1, 2006, by and between SPS and The Bank of New York (as
successor to The Chase Manhattan Bank), as Trustee, creating $250 million aggregate principal amount of Series F
Notes, 6% due Oct. 1, 2036
Indenture, dated as of Aug. 1, 2011, by and between SPS and U.S. Bank Trust Company, National Association (as
successor to U.S. Bank National Association), as Trustee
Supplemental Indenture No. 1, dated as of Aug. 3, 2011, by and between SPS and U.S. Bank Trust Company, National
Association (as successor to U.S. Bank National Association), as Trustee, creating $200 million aggregate principal
amount of 4.50% First Mortgage Bonds, Series No. 1 due Aug. 15, 2041
Supplemental Indenture No. 3, dated as of June 1, 2014, by and between SPS and U.S. Bank Trust Company, National
Association (as successor to U.S. Bank National Association), as Trustee, creating $150 million aggregate principal
amount of 3.30% First Mortgage Bonds, Series No. 3 due June 15, 2024
Supplemental Indenture No. 4, dated as of Aug. 1, 2016, by and between SPS and U.S. Bank Trust Company, National
Association (as successor to U.S. Bank National Association), as Trustee, creating $300 million aggregate principal
amount of 3.40% First Mortgage Bonds, Series No. 4 due Aug. 15, 2046
Supplemental Indenture No. 5, dated as of Aug. 1, 2017, by and between SPS and U.S. Bank Trust Company, National
Association (as successor to U.S. Bank National Association), as Trustee, creating $450 million aggregate principal
amount of 3.70% First Mortgage Bonds, Series No. 5 due Aug. 15 2047
Supplemental Indenture No. 6, dated as of Oct. 1, 2018, by and between SPS and U.S. Bank Trust Company, National
Association (as successor to U.S. Bank National Association), as Trustee, creating $300 million aggregate principal
amount of 4.40% First Mortgage Bonds, Series No. 6 due Nov. 15, 2048
Supplemental Indenture No. 7, dated as of June 1, 2019, by and between SPS and U.S. Bank Trust Company, National
Association (as successor to U.S. Bank National Association), as Trustee, creating $300 million aggregate principal
amount of 3.75% First Mortgage Bonds, Series No. 7 due June 15, 2049
Supplemental Indenture No. 8, dated as of May 1, 2020, by and between SPS and U.S. Bank Trust Company, National
Association (as successor to U.S. Bank National Association), as Trustee, creating $600 million aggregate principal
amount of 3.15% First Mortgage Bonds, Series No. 8 due May 1, 2050
Supplemental Indenture No. 9, dated as of May 1, 2022, by and between SPS and U.S. Bank Trust Company, National
Association, as Trustee, creating $200 million aggregate principal amount of 5.15% First Mortgage Bonds, Series No. 9
due June 1, 2052
Supplemental Indenture No. 10 dated as of August 21, 2023 between SPS and U.S. Bank Trust Company, National
Association (as successor to U.S. Bank National Association), as Trustee, creating $100 million aggregate principal
amount of 6.00% First Mortgage Bonds, Series No. 10 due 2053.
Fourth Amended and Restated Credit Agreement, dated as of Sept. 19, 2022, 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, and Citibank, N.A., MUFG Bank, Ltd. and Wells Fargo Bank, National
Association, as Documentation Agents
Xcel Energy Inc. Form 10-Q for the quarter
ended Sept. 30, 2003
SPS Form 8-K dated Oct. 3, 2006
SPS Form 8-K dated Aug. 10, 2011
SPS Form 8-K dated Aug. 10, 2011
SPS Form 8-K dated June 9, 2014
SPS Form 8-K dated Aug. 12, 2016
SPS Form 8-K dated Aug 9. 2017
SPS Form 8-K dated Nov. 5, 2018
SPS Form 8-K dated June 18, 2019
SPS Form 8-K dated May 18, 2020
SPS Form 8-K dated May 31, 2022
99.2
4.04
4.01
4.01
4.02
4.02
4.02
4.02
4.02
4.02
4.02
4.02
SPS Form 8-K dated August 21, 2023
4.01
Xcel Energy Inc. Form 8-K dated Sept. 19,
2022
99.04
Xcel Energy Inc.
21.01
23.01
24.01
31.01
31.02
32.01
97.01
Subsidiaries of Xcel Energy Inc.
Consent of Independent Registered Public Accounting Firm
Powers of Attorney
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
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
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Mandatory Compensation Recovery Policy for Section 16 Officers
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)
86
XCEL ENERGY INC.
CONDENSED BALANCE SHEETS
(amounts in millions)
SCHEDULE I
XCEL ENERGY INC.
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(amounts in millions, except per share data)
Year Ended Dec. 31
2022
2021
2023
Income
Equity earnings of subsidiaries
Total income
Expenses and other deductions
Operating expenses
Other (income) expenses
Interest charges and financing costs
Total expenses and other deductions
Income before income taxes
Income tax benefit
Net income
Other Comprehensive Income
$ 1,948
1,948
$ 1,905
1,905
$ 1,744
1,744
25
(13)
235
247
1,701
(70)
$ 1,771
19
(2)
206
223
1,682
(54)
$ 1,736
21
3
173
197
1,547
(50)
$ 1,597
Pension and retiree medical benefits, net of tax
$
(2) $
9
$
8
Derivative instruments, net of tax
Other comprehensive income
Comprehensive income
1
(1)
$ 1,770
21
30
$ 1,766
10
18
$ 1,615
Assets
Cash and cash equivalents
Accounts receivable from subsidiaries
Derivative instruments
Other current assets
Total current assets
Investment in subsidiaries
Other assets
Total other assets
Total assets
Liabilities and Equity
Current portion of long-term debt
Dividends payable
Short-term debt
Other current liabilities
Total current liabilities
Other liabilities
Total other liabilities
Weighted average common shares outstanding:
Basic
Diluted
Earnings per average common share:
Basic
Diluted
Commitments and contingencies
552
552
547
547
539
540
Capitalization
Long-term debt
$ 3.21
3.21
$ 3.18
3.17
$ 2.96
2.96
Common stockholders' equity
Total capitalization
Total liabilities and equity
Dec. 31
2023
2022
$
24
$
404
—
5
433
23,873
(20)
23,853
$
24,286
$
—
289
165
66
520
12
12
6,137
17,617
23,754
$
24,286
$
1
443
1
7
452
22,597
(7)
22,590
23,042
500
268
231
17
1,016
13
13
5,338
16,675
22,013
23,042
See Notes to Condensed Financial Statements
XCEL ENERGY INC.
CONDENSED STATEMENTS OF CASH FLOWS
(amounts in millions)
Operating activities
Net cash provided by operating activities
$ 1,586
$ 1,340
$ 1,147
Year Ended Dec. 31
2023
2022
2021
(921)
(1,661)
—
(921)
57
(1,604)
Investing activities
Capital contributions to subsidiaries
Net return in the utility money pool
Net cash used in investing activities
Financing activities
(Repayment of) proceeds from short-term borrowings,
net
Proceeds from issuance of long-term debt
Repayment of long-term debt
Proceeds from issuance of common stock
Dividends paid
Other
Net cash (used in) provided by financing activities
Net change in cash, cash equivalents, and restricted cash
Cash, cash equivalents and restricted cash at beginning of
period
Cash, cash equivalents and restricted cash at end of
period
(975)
21
(954)
(66)
792
(500)
270
(407)
694
—
322
(1,092)
(1,012)
(13)
(609)
23
1
(16)
(419)
—
1
638
791
(400)
366
(935)
(16)
444
(13)
14
$
24
$
1
$
1
See Notes to Condensed Financial Statements
87
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, 2023 and 2022,
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,
2023:
(Millions of Dollars)
Guarantor
Guarantee
Amount
Current
Exposure
Triggering
Event
Guarantees of Capital
Services purchase contracts
for wind and solar generating
equipment
(a)
Guarantees of Xcel Energy
Inc.’s utility subsidiaries’
performance on tax credit
sale agreements
Guarantee performance and
payment of surety bonds for
Xcel Energy Inc.’s utility
subsidiaries (e)
Xcel Energy
Inc.
Xcel Energy
Inc.
Xcel Energy
Inc.
951
100
75
(b)
(d)
(f)
(c)
(c)
(g)
(a)
(b)
(c)
(d)
(e)
(f)
(g)
Guarantees expire upon the satisfaction of all buyer obligations under the purchase
contracts.
Given that the manufacturing of equipment has not yet commenced, related exposure to
the performance obligations of Capital Services at Dec. 31, 2023 has been assessed as
immaterial.
Nonperformance and/or nonpayment.
Exposure to the performance obligations of the utility subsidiaries has been assessed as
immaterial. The tax credit sales transactions closed as scheduled in January 2024.
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.
Due to the number 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.
Per the indemnity agreement between Xcel Energy Inc. and the various surety
companies, surety companies have the discretion to demand that collateral be posted.
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)
NSP-Minnesota
NSP-Wisconsin
PSCo
SPS
Xcel Energy Services Inc.
Other subsidiaries of Xcel Energy Inc.
$
$
2023
2022
120
$
13
44
47
144
35
403
$
82
17
111
61
145
27
443
Dividends — Cash dividends paid to Xcel Energy Inc. by its subsidiaries
were $1,693 million, $1,503 million and $1,344 million for the years ended
Dec. 31, 2023, 2022 and 2021, 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, 2023
Loan outstanding at period end
Average loan outstanding
Maximum loan outstanding
Weighted average interest rate, computed on a daily basis
Weighted average interest rate at end of period
Money pool interest income
$
$
21
90
250
1.34 %
5.34
1
(Amounts in Millions, Except
Interest Rates)
Year Ended
Dec. 31, 2023
Year Ended
Dec. 31, 2022
Year Ended
Dec. 31, 2021
Loan outstanding at period end
$
Average loan outstanding
Maximum loan outstanding
Weighted average interest rate,
computed on a daily basis
Weighted average interest rate at
end of period
$
21
27
250
$
—
10
204
—
16
439
5.33 %
0.73 %
0.08 %
5.34
N/A
N/A
—
Money pool interest income
$
1
$
—
$
See notes to the consolidated financial statements in Part II, Item 8.
88
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)
Balance at Jan. 1
2023
$ 122
2022
$ 106
2021
$ 79
2023
$ 62
2022
$ 64
2021
$ 64
Additions charged to
costs and expenses
Additions charged to
other accounts
Deductions from
reserves
Balance at Dec. 31
79
73
60
26
6
5
(a)
(b)
13
(86)
$ 128
(a)
(b)
26
(83)
$ 122
(a)
(b)
14
(47)
$ 106
—
—
—
(18)
$ 70
(c)
(c)
(8)
(c)
(5)
$ 62
$ 64
(a)
(b)
(c)
Recovery of amounts previously written-off.
Deductions related primarily to bad debt write-offs.
Primarily reversals of valuation allowances on completed tax credit sales and reductions
of valuation allowances for items forecasted to be used prior to expiration.
ITEM 16 — FORM 10-K SUMMARY
None.
89
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed
on its behalf by the undersigned thereunto duly authorized.
Feb. 21, 2024
XCEL ENERGY INC.
By:
/s/ BRIAN J. VAN ABEL
Brian J. Van Abel
Executive Vice President, Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant
and in the capacities on the date indicated above.
/s/ ROBERT C. FRENZEL
Robert C. Frenzel
/s/ BRIAN J. VAN ABEL
Brian J. Van Abel
Megan Burkhart
Lynn Casey
Netha Johnson
Patricia L. Kampling
George J. Kehl
Richard T. O’Brien
Charles Pardee
Christopher J. Policinski
James Prokopanko
Timothy Welsh
Kim Williams
*
*
*
*
*
*
*
*
*
*
*
*
Daniel Yohannes
*By:
/s/ BRIAN J. VAN ABEL
Brian J. Van Abel
Chairman, President, Chief Executive Officer and Director
(Principal Executive Officer)
Executive Vice President, Chief Financial Officer
(Principal Accounting Officer and Principal Financial Officer)
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Attorney-in-Fact
90
XCEL ENERGY BOARD OF DIRECTORS
SHAREHOLDER INFORMATION
Headquarters
414 Nicollet Mall, Minneapolis, MN 55401
Website
xcelenergy.com
Stock Transfer Agent
EQ Shareowner Services
1110 Centre Pointe Curve, Suite 101
Mendota Heights, MN 55120
Telephone: 877-778-6786, toll free
Reports Available Online
Financial reports, including filings with the Securities and
Exchange Commission and other investor materials, are
available online at xcelenergy.com; click on Investors. Other
information about Xcel Energy, including our Code of Conduct,
Guidelines on Corporate Governance, Sustainability Report and
Committee Charters, is also available at xcelenergy.com.
Stock Exchange Listings and Ticker Symbol
Common stock is listed on the Nasdaq Global Select Market
(Nasdaq) under the ticker symbol XEL. In newspaper listings, it
may appear as XcelEngy.
Investor Relations
Website: investors.xcelenergy.com or contact Paul Johnson,
vice president, Treasurer & Investor Relations, at 612-215-4535.
Shareholder Services
Website: investors.xcelenergy.com or contact Darin Norman,
consultant, Investor Relations, at 612-337-2310 or email:
darin.norman@xcelenergy.com.
Corporate Governance
Xcel Energy has filed with the Securities and Exchange
Commission certifications of its Chief Executive Officer and Chief
Financial Officer pursuant to section 302 of the Sarbanes-Oxley Act
of 2002 as exhibits to its Annual Report on Form 10-K for 2023.
To contact the Board of Directors, send an email to
boardofdirectors@xcelenergy.com.
You also may direct questions to the Corporate Secretary’s
department at corporatesecretary@xcelenergy.com.
Megan Burkhart 1,3
Senior executive vice president, chief
administrative officer and chief human
resources officer, Comerica Incorporated
Lynn Casey 2,4
Retired chair and CEO, Padilla
Bob Frenzel
Chairman, president and CEO,
Xcel Energy Inc.
Netha Johnson 2,4
President, Specialties global
business unit, Albemarle Corporation
Patricia Kampling 1,3
Retired chairman and CEO,
Alliant Energy Corporation
George Kehl 1,2
Retired office managing partner, KPMG
Richard O’Brien 2,3
Independent consultant
Charles Pardee 1,4
President, Terrestrial Energy, USA
Christopher Policinski 3,4
Retired president and CEO,
Land O’ Lakes, Inc.
James Prokopanko 1,2
Retired president and CEO,
The Mosaic Company
Timothy Welsh 1,4
Vice chair, Consumer and Business
Banking, U.S. Bancorp
Kim Williams 3
Lead independent director, retired
partner, Wellington Management
Company LLP
Daniel Yohannes 2,4
Former United States ambassador
to the Organization for Economic
Cooperation and Development
Board Committees:
1. Audit
2. Finance
3. Governance, Compensation
and Nominating
4. Operations, Nuclear,
Environmental and Safety
2023 ANNUAL REPORT
FISCAL AGENTS
XCEL ENERGY INC.
Transfer Agent, Registrar, Dividend
Distribution, Common Stock
EQ Shareowner Services,
1110 Centre Pointe Curve, Suite 101
Mendota Heights, MN 55120
Trustee–Bonds
U.S. Bank Corporate Trust Services
CM-9690
PO Box 70870
St. Paul, MN 55107-9690
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