Xcel Energy Annual Report 2022

FY2022 Annual Report · Xcel Energy

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ANNUAL

2022ANNUAL REPORT

BUILDING THE FUTURECOMPANY DESCRIPTION

Xcel Energy is a major U.S. electric and natural gas company with annual revenues of
$15.3 billion. Based in Minneapolis, Minnesota, the company operates in eight states
and provides a comprehensive portfolio of energy-related products and services to
3.8 million electricity customers and 2.1 million natural gas customers.

FINANCIAL HIGHLIGHTS

EARNINGS PER SHARE
Dollars per share (diluted)

2021

2022

Total GAAP earnings per share

2.96

3.17

Ongoing earnings per share

2.96

3.17

9
7
.
2

6
9
.
2

7
1
.
3

Dividends annualized

1.83

1.95

Stock price (close)

67.70

70.11

Assets (millions)

57,851

61,188

2020

2021

2022

GAAP (generally accepted accounting
principles) earnings per share

Ongoing earnings per share

ON THE COVER:
Lineman during construction of
new Xcel Energy transmission
lines in Wisconsin. Transmission
development is essential to
accelerating clean energy growth.

To my fellow
customers and
shareholders

Bob Frenzel
Chairman, President and Chief Executive Officer

BUILDING THE FUTURE ANNUAL REPORT 2022Despite historic headwinds for the industry in 2022, Xcel Energy continued its record of providing our communities with safe, reliable energy while charting a course for a clean energy future. As always, in 2022 we were there for our customers when they needed us most while continuing our track record of strong financial results for our shareholders.We are in a remarkable time. It’s the most exciting and dynamic period in our industry since Tesla and Edison competed for intellectual dominance in the Current Wars more than a century ago. The changes we see today are equally consequential. But despite the extraordinary times in which we do business, we never lose sight of the experience and day-to-day needs of our customers.I believe this is what has made Xcel Energy successful. In 2022, we continued to lead the clean energy transition while delivering our 18th straight year of consistent results for shareholders and keeping our customers’ bills low. We are committed to shaping an energy future that is sustainable in every way: it delivers clean, carbon-free energy to customers; it is safe, reliable and affordable for communities; and it generates opportunity and prosperity for all.But we also know the path to get there needs to be equally sustainable, making consistent progress toward our goals while never straying from delivering the core values of our customers, policymakers and other stakeholders: that our energy is always reliable and affordable while meeting our customers’ changing energy needs.We seek to be trusted for the strength of the service we provide — and preferred for our commitment to our customers and clean energy leadership. This is how we will build an energy future that powers economic prosperity and social progress for another 100+ years.6

Expanding our clean energy visionTrue to our commitment to lead, we expanded our goal for clean energy in 2022 and became the first major U.S. energy provider to include a net-zero carbon emission footprint for all the energy our customers use in our service territory: electricity, gas and transportation. Consistent with our approach to leadership, this expanded goal is informed by climate science and grounded in clean technology — both the renewable energy we will build today and the advanced technologies we will explore in the future. Committed to our communities and customers2022 saw customers across the country struggling with the dual pressures of lingering pandemic-related financial challenges and a global spike in natural gas commodity prices. Our commitment to our customers and keeping bills low remains as strong as ever, which is why Xcel Energy expanded both our financial support programs and direct outreach campaign to connect customers with the greatest need to public energy assistance. As a result, Xcel Energy customers accessed more than $200 million from public assistance and company programs combined last year.At the same time, 2022 was a particularly volatile weather year, with extreme temperatures in both heating and cooling seasons and an active storm season. Throughout, our customers experienced one of the highest levels of energy reliability in the country. Reliability and affordability are core values we will never stray from, and I am extremely proud of this continued focus on the vitality and financial stability of our customers and communities.Enabling a rapidly maturing EV marketXcel Energy paid significant attention in 2022 to developing the expertise and infrastructure to assure electric vehicle (EV) ownership is accessible and attractive to customers. We moved forward with a multi-jurisdictional package of EV programs that addresses all our major customer segments. We proposed to invest $325 million in EV programs, and we obtained approval for Xcel Energy-owned high-speed public charging in Minnesota, New Mexico and Colorado.Building our safety cultureSafety remains our number one priority, and our focus on continuous improvement through learning is taking hold. Under our Safety Always program, employees are encouraged to identify, discuss and learn from safety events that could have resulted in serious injuries or fatalities. As a result of this program, near-miss event reporting last year was up 19% from 2020 levels. And we are constantly training, with 15,000 individual employees and contractors receiving Critical Risk Management training and hazard identification while achieving 98% contractor compliance with Safety Always orientation. However, the tragic deaths of two contractors working at our Comanche generating plant last summer remind us that our safety work is never done. We must be tireless in our vigilance.Making the clean energy future a realityLast year saw us achieve important milestones in the journey to make our clean energy vision a reality with exciting new opportunities for partnerships and investment:• We reached 53% carbon reduction from 2005levels on our electric grid while remaining atop quartile energy provider in reliability.• We worked to support new federal cleanenergy incentives and policy reforms in theInflation Reduction Act that help pave the wayfor our clean energy strategy and removedsome of the barriers to utility ownership ofrenewable energy resources.• We led the way in unlocking the full potentialof the country’s abundant renewable energy,securing approvals for major new transmissionprojects in both Colorado and the Upper Midwest.• Our regulators approved our clean energyplans in Minnesota and Colorado, pavingthe way for nearly 10 gigawatts of additionalrenewables and the construction ofsignificant new transmission to supportour clean energy strategy.• We received final approvals to move forwardwith the Sherco Solar project which, whencomplete, will convert a coal generation facilityinto one of the largest solar generation facilitiesin the country.OUR CLEAN ENERGY VISION:
NET-ZERO CARBON EMISSIONS
FOR ALL ENERGY

Xcel Energy is committed to leading the clean
energy transition. In 2022, we took this charge
one step further, becoming the first major
U.S. energy company to set a goal to enable
a comprehensive net-zero carbon energy
economy in our service territory. We expanded
our industry-leading pledge from 2018 for
100% carbon-free electricity by 2050 to include
transportation and net-zero targets for gas.

Our transportation vision builds on an initial
target with a new goal of enabling one out
of five vehicles in the areas we serve to be
electric by 2030. In addition to delivering clean,
carbon-free power to charging points, we will
actively contribute to the buildout of necessary
infrastructure, support customers with effective
programs to manage charging at home and help
business electrify their vehicle fleets.

Our vision for net-zero gas service acknowledges
that electrifying home heating, cooking and
other appliances powered by natural gas is not
the right choice for every customer, so we are
taking responsibility for delivering safe, reliable
and affordable energy that minimizes the
impact to customers while still achieving the
environmental targets they value.

We will continue building a world-class energy
infrastructure while providing sustainability,
energy security and economic prosperity
for our customers, always striving to be the
preferred and trusted provider of energy for the
communities we serve.

While we’re thrilled with this progress, we
know there’s still a long way to go. Leading
this transition will take operational excellence,
strong stakeholder engagement and regulatory
effectiveness, and a balanced, thoughtful
approach to drive carbon reductions while
continuing to ensure reliability and affordability
for our customers.

We invite you to join us as we harness the
power of innovation to meet the needs of the
electric system of the future, delivering energy
that is affordable, reliable, safe and sustainable.

BUILDING THE FUTURE ANNUAL REPORT 2022• We launched our new Clean Fuels initiative todrive the innovations that will deliver zero- or low-carbon fuel sources to homes, transportationand generating facilities. This includes newdemonstration projects to generate hydrogencommercially with carbon-free electricity.Serving ethically and equitablyAs we lead the way to an economy powered by clean, carbon-free energy, we will continue to be responsible stewards of the health, well-being, and economic opportunity of all the communities we serve. It starts with our own company, and I am pleased with our continued progress toward a diverse leadership team and workforce. The company’s executive leadership became more diverse over the course of 2022, and we again exceeded our corporate targets on diversity, equity and inclusion.At the same time, we are investing in partnerships to expand a workforce trained in clean energy jobs that is reflective of all the communities we serve. Our customer programs have a strong focus on equitable outreach to low-income communities, including several innovative concepts in our EV partnerships and programs. We are committed to ensuring the prosperity and opportunity of the clean energy transition is shared by all.As a result of our commitment to our customers, communities and employees, Xcel Energy was again recognized as one of Fortune magazine’s World’s Most Admired Companies and is listed among the World’s Most Ethical Companies® by Ethisphere. We also earned recognition for being one of the best places to work for veterans, for disability inclusion and for LGBTQ+ equality.The promise of a clean energy future is quickly becoming reality, and Xcel Energy will remain on the forefront of building this future. I am confident that we will continue to be the trusted and preferred energy partner for our customers. Thank you for the continued trust you place in us.Sincerely,Bob Frenzel Chairman, President and Chief Executive OfficerINVESTING IN
OUR COMMUNITIES
AND CUSTOMERS

XCEL ENERGY IS PARTNERING
WITH COMMUNITIES TO BUILD THE
ENERGY FUTURE, SUPPORTING
OUR CUSTOMERS AND GROWING A
CLEAN ENERGY WORKFORCE

Our customers trust
Xcel Energy will be
there for them.
We demonstrate that commitment
every time our trucks roll for storm
response; every time our crews
relight customers after a gas event;
every time we deliver service that
empowers customers to achieve
their personal energy goals.

We also build trust in how we give
back. Last year, we served more
than 3 million electric customers
and 2 million natural gas customers
with the energy that powers their
lives, livelihoods and celebrations.

Through the Xcel Energy Foundation,
we granted $4.4 million to 426
nonprofits in 2022. Thanks to
our giving, 820,000 students will
receive hands-on STEM learning,
including 380,000 female learners;
11,000 trees will be planted,
offsetting 7,800 tons of carbon
emissions; and 8,000 individuals
will gain employment, generating
$260 million in wages.

Beyond this, our team’s generosity
to local communities changed lives
and demonstrated the power of our
values. Through our annual United
Way Giving Campaign, we raised
more than $5 million, and on our
Day of Service, we contributed
9,000 volunteer hours. Since
2020, we’ve donated more than
$30 million across our eight states
through giving and volunteering.

Meeting our customers’ needs:
today and in the future
Economic hardships have been
challenging for customers
throughout our footprint. But we
want to ensure our energy brings
prosperity and opportunity today,
and in the future.

“ Xcel Energy and its partners are connecting a new,
diverse generation of bright students to be a part of
leading the transition to a clean energy future.”

Patricia Correa, Senior Vice President, Human Resources &
Employee Services, Chief Human Resources Officer

In late 2022, as natural gas
commodity prices rose to historic
highs, our Customer Care team
responded quickly to connect
customers with public energy
assistance. Ultimately, they
helped connect nearly 200,000
customers — from New Mexico
to Michigan — with more than
$200 million in assistance that
reduced or entirely paid for their
energy bills. Hard-hit Colorado
customers alone received more
than $87 million.

“We acted to reach out to
customers of all backgrounds
needing additional support to help
them access energy assistance
funds,” said Brett C. Carter,
executive vice president and
group president, Utilities and chief
customer officer. “Our agents
stayed on the phone, sometimes
for over an hour, to ensure their
applications went through.”

We know these challenges and
volatility also underscore the
importance of one of our key
strategic priorities: leading the clean
energy transition. In the last five years,
our wind energy investments have
saved customers nearly $3 billion.

For Xcel Energy, the future is about
energy security and economic
prosperity for our customers. As
we look toward the future, we will
meet the needs of the electric
system of the future that is
affordable, reliable, safe and clean,
while never losing sight of our
highest priority: customers.

Developing tomorrow’s
workforce
Xcel Energy’s commitment to
its communities goes beyond
our customers. Much of our
workforce comes right from the
neighborhoods we serve, and as
we lead the clean energy transition,
we are committed to building a
workforce of tomorrow reflective
of those communities.

A central pillar of this commitment
is reaching out through partnerships
with local nonprofits and the
education system to expose
students to energy careers
early, and to create new training
programs in locations underserved
with energy technical programs.
One example is the Energy Careers
Academy — a partnership with the
Minnesota State Energy Center of
Excellence — through which we
work together to engage students
with diverse backgrounds in
energy-related fields of study.

“Xcel Energy and its partners
are connecting a new, diverse
generation of bright students to be
a part of leading the transition to a
clean energy future,” said Patricia
Correa, senior vice president,
Human Resources & Employee
Services and chief human
resources officer.

The success of the clean energy
transition will be tied to the
success of connecting all our
communities to its promise, and
we’re proud of our work to build
that reality.

BUILDING THE FUTURE ANNUAL REPORT 2022The speed of the
country’s transition to
a clean energy future
will be limited by
national transmission
infrastructure that
currently operates at or
near top capacity, unless
the network grows at a
much higher rate.
Xcel Energy intends to lead that
acceleration.

A recent study from Princeton
University estimated that to realize
the total potential greenhouse gas
emission reduction possible over
the next decade, U.S. transmission
infrastructure would need to
expand at more than double
its current pace. This is notable
because while the vast majority of
the public attention on the clean
energy transition focuses on flashy
topics like renewable generation

Tim O’Connor, executive vice
president and chief operations
officer. “We’ve already saved
our customers more than $3
billion through our wind energy
investments, benefits we look to
grow by expanding the capacity to
transport the energy potential of
the Great Plains and the Southwest
with our transmission development
plans.”

In 2022, Xcel Energy achieved
key milestones in its transmission
infrastructure development
plan with approvals of marquee
proposals in the Upper Midwest
and Colorado representing more
than $3 billion in new investment.
The Colorado Power Pathway
project and the Upper Midwest
projects are initial steps in a
five-year, $7.4 billion transmission
development plan to reduce
congestion and increase regional
reliability while connecting tens of
thousands of megawatts (MW) of
new renewable energy generation
over the same period.

“ We’re moving forward building an electric transmission
network for the future, to deliver the energy economy
of the future.”

Michael Lamb, Senior Vice President, Transmission

development, long-duration storage
and electrification, the nation’s
transmission infrastructure will truly
be a keystone for the success of a
zero-carbon energy economy.

“We are tapping into one of the
richest wind energy resources in
the world, capable of delivering
clean, low-cost energy to not only
our customers but areas poor in
carbon-free energy sources,” said

“The capacity constraints already
limit the total potential benefit of
existing renewable generation,
with forced curtailment and
congestion issues occurring across
systems,” said Michael Lamb,
senior vice president, Transmission.
“We’re moving forward building
an electric transmission network
for the future, to deliver the energy
economy of the future.”

The Colorado and Upper Midwest
transmission projects will add
more than 1,000 miles of lines
and several new or expanded
substations. In Colorado, the
new lines will create essential
connections between communities
and key development areas for
wind and solar generation. The
more than 500 miles of new high-
voltage transmission will provide
greater reliability for the overall
grid, connecting more generation
sources — a broader mix of
generation to reduce issues with
the intermittency of renewable
generation — while making it
easier to move power from where
it’s being generated to where it’s
most needed.

Xcel Energy’s Upper Midwest plans
are just one part of a more than
$10 billion regional transmission
plan to reduce congestion and
increase grid reliability by 2030.
Similar to the Colorado plan, five
new projects will stretch from the
South Dakota-Minnesota border
to central Wisconsin, expanding
the capacity to move energy from
the wind-rich regions of western
Minnesota and the eastern
Dakotas to communities across
the Upper Midwest and helping
to unlock the full potential of this
tremendous resource.

“This isn’t just a grid management
operation,” said Lamb. “It’s part of
bringing the economic potential
of a clean energy future to life and
enabling the regions we serve
to reap the full benefits of this
unique global resource. It will drive
local investment and economic
development, overall energy
savings and jobs.”

XCEL ENERGY TOOK KEY STEPS TOWARD
EXPANDING TRANSMISSION NETWORKS
CAPABLE OF UNLOCKING OUR FULL
RENEWABLE ENERGY POTENTIAL

BUILDING

CLEAN ENERGY

SUPERHIGHWAYS

BUILDING THE FUTURE ANNUAL REPORT 2022BLUEPRINTS FOR HISTORIC

RENEWABLE
ENERGY
EXPANSION

FROM PLEDGE TO PLAN, A
COURSE TO OUR CLEAN ENERGY
TARGET IS NOW MAPPED OUT

“ Sherco Solar will drive reinvestment, sustain jobs and
create new opportunities on land that Xcel Energy has
owned and operated in Benton County for decades.”

Chris Clark, President, Xcel Energy–Minnesota, North Dakota
and South Dakota

Today, Xcel Energy
customers receive 23%
of their power from
coal-fired generators.
By year-end 2030, that
figure will be zero.
That’s because in 2022, Xcel Energy
filed proposals with the New
Mexico Public Utilities Commission
that included a provision to move
up the retirement date of coal-fired
generation at its Tolk Generating
Station. If approved, the company
will be coal-free within seven years.

Coal’s retirement closes one
chapter in Xcel Energy’s history
as another opens. For more than
a century, this fuel and thousands
of workers at our plants powered
millions of homes and businesses,
helping to drive America’s rise as
a superpower and a global leader
for economic opportunity. But
as we noted in our 2018 pledge
to deliver carbon-free electricity

Last year, Xcel Energy delivered
on commitments to lay out our
specific plans to reach the first
milestone on the path to a 2050
target: by 2030, achieve an 80%
reduction of carbon-emissions
over 2005 levels. Plans filed and
approved in our Upper Midwest
Region and Colorado call for
Xcel Energy to add nearly 10,000
MW of renewable energy capacity
over the next 10 years.

“We have the tremendous
opportunity and responsibility
to develop some of the world’s
greatest potential sources of wind
and solar energy,” said Brett C.
Carter, executive vice president and
group president, Utilities and chief
customer officer. “Through our

“ We have the tremendous opportunity and responsibility

to develop some of the world’s greatest potential
sources of wind and solar energy.”

Brett C. Carter, Executive Vice President and Group President,
Utilities and Chief Customer Officer

to our customers by 2050,
technological innovation and new
scientific observations create fresh
opportunities to deliver the energy
our customers demand. Today, we
are building on the strengths of our
energy legacy and tapping into the
next great domestic energy sources:
renewable wind and solar power.

commitment to customers and an
equitable clean energy future, this
won’t just be a watershed moment
for the energy industry but for the
collective economies of the regions
we serve.”

Xcel Energy’s plans call for adding
an additional 24,500 MW of wind
energy to its wind portfolio, which

already is among the nation’s
largest and has saved customers
more than $3 billion over the past
five years in avoided fuel costs and
other savings.

Excitingly, the plans approved in
2022 identify the largest expansion
of solar energy generation in the
company’s history, 4,100 MW
of large-scale solar. New solar
projects are particularly exciting
for their potential to play a role in
redeveloping former coal operating
facilities like the Sherco site in
Minnesota, where all coal-fired
operations are scheduled to retire
by 2030.

“Sherco Solar will drive
reinvestment, sustain jobs and
create new opportunities on
land that Xcel Energy has
owned and operated in Benton
County for decades,” said Chris
Clark, President, Xcel Energy–
Minnesota, North Dakota and
South Dakota. “When the
project is completed in 2025, it
will be one of the largest solar
generating facilities in the country
at 460 MW, creating more than
900 construction jobs and an
estimated $240 million in local
economic benefit.”

Xcel Energy’s plans for the Sherco
Solar project received final approval
in 2022 and will be one of the
company’s marquee renewable
energy development initiatives
over the next several years.

BUILDING THE FUTURE ANNUAL REPORT 2022From 80% to 100%:
that is the puzzle
Xcel Energy, our peer
energy providers,
engineers, scientists,
entrepreneurs, policy
makers and many more
stakeholders across the
global community are
working to solve.
There is broad consensus that
existing generation and grid
technologies will support an
electrical grid with carbon emissions
80% lower than 2005 levels. There
is also broad consensus that making
the jump to a 100% carbon-free
electrical grid — even more so an
entire net-zero energy economy

funds dedicated to clean energy
innovation. Now, some of the most
promising emerging segments
of a future energy economy
are reaching the point of field
demonstration, and Xcel Energy
is again on the leading edge.

“There is a hotbed of activity in
energy innovation, with many
promising technologies to address
some of the key barriers to a
sustainable clean energy economy
on the cusp of emerging,” said
Justin Tomljanovic, vice president,
Corporate Development for
Xcel Energy. “Within the next
several years, I expect we’ll see
a sharp increase in grid-scale test
cases, and it’s important to us
that Xcel Energy is actively
involved in developing the
most promising concepts.”

“ Within the next several years, I expect we’ll see a sharp
increase in grid-scale and distribution-level test cases,
and it’s important to us that Xcel Energy is actively
involved in developing the most promising concepts.”

Justin Tomljanovic, Vice President, Corporate Development

as Xcel Energy has pledged
for its service territory — while
maintaining the reliability, resiliency
and affordability necessary
to sustain it will require new
approaches and technologies, some
of which have yet to be invented.

Xcel Energy has always been
an active partner in bridging
that gap and putting real skin in
the game, from committing its
company leadership and experts to
industry collaboration efforts, to co-
launching and investing in venture

Three initiatives that will enable
Xcel Energy’s pledges to a net-
zero carbon future across three
energy markets warrant particular
attention: fleet electrification,
long-duration storage and
zero- or low-carbon fuels.

Fleet electrification
This last summer, Xcel Energy
introduced the country’s first
all-electric utility bucket truck, an
important milestone in its own
fleet electrification progress
that offers a valuable testing

ground for electric fleet vehicles
performing light- to heavy-duty
work. Medium- to heavy-duty fleet
conversion has larger question
marks in its future than the light-
duty market, but also significant
potential for both impactful carbon
emission reductions and new grid
management capabilities such as
on-site or local resiliency support.

Long-duration storage
Expanding the amount of renewable
energy powering the grid comes
hand in hand with solving for
greater generation intermittency
when the sun doesn’t shine or
the wind doesn’t blow. Even
with significant expansions of
distributed generation sources
like rooftop solar, the grid will
always require dispatchable
power sources to protect the
grid, communities and customers.
Developing effective long-duration
storage solutions to capture excess
renewable energy to deploy when
demand is higher is essential to a
clean energy future.

That excess energy exists even
today. In 2022, Xcel Energy alone
curtailed enough wind energy
during low-demand periods to
power more than 75,000 homes.
As renewable energy generation
expands, this excess capacity will
only grow. This is why Xcel Energy
developed a partnership with
Form Energy to be one of the first
to deploy its 100-hour storage
iron-air battery technology at sites
in Colorado and Minnesota as
demonstration projects to test its
capabilities in the field. This is one
of the most promising alternatives
to lithium batteries, which
are more expensive and less
sustainable for the environment.

NEW INNOVATION PROJECTS MAY HOLD
KEYS TO THE CLEAN ENERGY FUTURE

BRIDGING THE

GAP TO100%

BUILDING THE FUTURE ANNUAL REPORT 2022These demonstrations will provide
valuable data to further develop
their viability for implementation.

Clean Fuels
Today, natural gas is an essential
component for the energy our
customers rely on. Nearly 85%
of Xcel Energy’s customers
rely on natural gas for heating
their homes or businesses, and
natural gas generated 24% of the
electricity we produced in 2022.
Electrification of residential heating
and cooling and the expansion of
renewable generation will reduce
these figures, but it’s also a reality
that both the costs to transition
that much infrastructure and an
interest in accelerating carbon
emissions reductions mean that
building a clean energy future
requires innovation in the fuels

we use for natural gas service and
power generation.

Our Clean Fuels initiative leads the
effort on this and took important
steps in 2022 to make lower-
carbon gas a reality. Much of the
focus today is on the potential for
hydrogen, which not only burns
with no carbon emissions, but
can be produced in a carbon-
free process using renewable
or nuclear energy. Projects
are in development for several
hydrogen use and production
demonstrations, including test
burns in electric generating plants,
blending demonstrations for
residential service and a production
demonstration project at our Prairie
Island Nuclear Generating Station
in conjunction with the Idaho
National Lab.

“The environmental and economic
opportunities with hydrogen
are tremendous and could be
an essential resource for our
customers to participate in a
clean energy future without costly
and disruptive changes to their
lifestyle,” said Greg Chamberlain,
vice president, Clean Fuels. “We
have some of the best performing
wind, nuclear and gas operations,
which we can leverage to lead the
way on lower-carbon gas.”

Xcel Energy’s commitment to lead
means a commitment to leading
the innovation which will enable a
safe, reliable and affordable clean
energy future.

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, 2022 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, 2022, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $38,692,119,433.

As of Feb. 16, 2023, there were 549,847,034 shares of common stock outstanding, $2.50 par value.

Portions of the Registrant’s definitive Proxy Statement for its 2023 Annual Meeting of Shareholders are incorporated by reference into Part III of this Form 10-K.

DOCUMENTS INCORPORATED BY REFERENCE

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TABLE OF CONTENTS

Business

PART I
Item 1 —
Item 1A — Risk Factors
Item 1B — Unresolved Staff Comments
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 —
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Item 9 —
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

PART I

ITEM 1 — BUSINESS

Definitions of Abbreviations

Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
Capital Services
Eloigne
e prime
NSP-Minnesota
NSP System

Capital Services, LLC
Eloigne Company
e prime inc.
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
FERC
IRS
MPCA
MPUC
NDPSC
NERC
NMPRC
NRC
PHMSA
PSCW
PUCT
SDPUC
SEC
TCEQ

Colorado Public Utilities Commission
Minnesota Department of Commerce
United States Department of Energy
United States Department of Transportation
United States Environmental Protection Agency
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
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
Texas Commission on Environmental Quality

Electric, Purchased Gas and Resource Adjustment Clauses

CIP
DSM
ECA
FCA
GCA
GUIC
RES

Other
AFUDC

AMT

ALJ

ARO

ASC

ATM

BART

C&I

Conservation improvement program
Demand side management
Retail electric commodity adjustment
Fuel clause adjustment
Gas cost adjustment
Gas utility infrastructure cost rider
Renewable energy standard

Allowance for funds used during construction

Alternative minimum tax

Administrative Law Judge

Asset retirement obligation

Financial Accounting Standards Board Accounting Standards
Codification

At-the-market

Best available retrofit technology

Commercial and Industrial

CapX2020

CCR

Alliance of electric cooperatives, municipals and investor-owned utilities
in the upper Midwest involved in a joint transmission line planning and
construction effort
Coal combustion residuals

CCR Rule

CDD

CEO

CFO

CIG

CON

CSPV

CWIP

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
Inflation Reduction Act
Independent System Operator
Investment Tax Credit
Lubbock Power & Light
Mankato Energy Center
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
Notice of proposed rulemaking
Nitrogen Oxides
Operating and maintenance
Open Access Transmission Tariff
Per- and PolyFluoroAlkyl Substances
Prairie Island nuclear generating plant
Post-Medicare
Purchased power agreement
Pre-Medicare
Production tax credit
Renewable energy credit
Request for proposal
Return on equity
Right-of-use
Regional Transmission Organization
Standard & Poor’s Global Ratings
Supplemental executive retirement plan
Sulfur dioxide
Southwest Power Pool, Inc.
Transmission cost adjustment

DECON

DRIP

EEI

EIP

EMANI

EPS

ETR

FTR

GAAP

GHG

HDD

INPO
IPP
IRA
ISO
ITC
LP&L
MEC
MGP
MISO
Native load

NAV
NEIL
NOL
NOPR
NOx
O&M
OATT
PFAS
PI
Post-65
PPA
Pre-65
PTC
REC
RFP
ROE
ROU
RTO
S&P
SERP
SO2
SPP
TCA

TCJA

THI
TO
TSR
VaR
VIE
WACC

2017 federal tax reform enacted as Public Law No: 115-97, commonly
referred to as the Tax Cuts and Jobs Act
Temperature-humidity index
Transmission owner
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 2023 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, 2022 (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 work force 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; cyber security 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; 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 2.1 million natural gas customers through four utility subsidiaries (i.e., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS). Along with the
utility subsidiaries, the transmission-only subsidiaries, WYCO (a joint venture formed with CIG to develop and lease natural gas pipelines, storage and
compression facilities) and WGI (an interstate natural gas pipeline company) comprise the regulated utility operations. The Company’s nonregulated
subsidiaries include Eloigne, Capital Services, Venture Holdings and Nicollet Project Holdings.

Subsidiary / Affiliate
NSP-Minnesota

NSP-Wisconsin

PSCo

SPS

WGI

WYCO

Function
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

2.1 million

$61.1 billion

20,897 MW

53.5 Bcf

110,000 miles

213,000 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 our four corporate values: Connected, Committed, Safe, and Trustworthy.

Our values, culture and Code of Conduct serve as the foundation upon which Xcel Energy’s Board of Directors, employees, contractors and suppliers
approach their work in delivering on our three strategic priorities.

Our sustainability and Environmental, Social and Governance commitments
are summarized as follows:

(1)

(2)

Spans natural gas supply, delivery and customer use.
Includes the Xcel Energy fleet; zero-carbon fuel is electricity or other clean energy.

Deliver a Competitive Total Return to Investors

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 earnings guidance range for 18 consecutive years and
delivering dividend growth for 19 consecutive years.

Over the past five years, GAAP earnings per share have grown by 7.1%
annually and our annual dividend growth was 6.3%. 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. Current ratings are
consistent with this goal.

LEAD THE CLEAN ENERGY TRANSITION

For nearly two decades, Xcel Energy has proactively managed the risk of
climate change and worked to meet increasing demand for cleaner energy.

Carbon-free Electricity by 2050

In 2018, Xcel Energy became 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 climate change
scientific analysis issued by the Intergovernmental Panel on Climate
Change confirmed that our vision aligns with science-based scenarios likely
to limit global warming to 1.5 degrees Celsius from pre-industrial levels.

Goal includes owned and purchased power.

The pace of achieving a carbon-free vision is governed by reliability and
customer affordability. Our approved resource plans outline a clear,
transparent path for reducing carbon emissions 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

Through 2022, we reduced carbon emissions from generation serving
customers by an estimated 53% (from 2005 levels) and remain on track to
achieve 80% carbon reduction by 2030.

Xcel Energy will be coal-free by year-end 2030, pending the approval of the
proposed acceleration of the Tolk coal plant retirement to 2028. As we
transition to clean energy, service reliability is a priority. Xcel Energy was
ranked in the top quartile for customer reliability as determined in the 2022
Institute of Electrical and Electronics Engineers Annual Benchmarking
Study.

Xcel Energy’s wind capacity is now over 11,000 MW, including nearly 4,500
MW of owned wind. Our fleet continues to demonstrate high wind
availability with 2022 performance at approximately 97%, while saving
customers over $3 billion in fuel related costs and PTCs since 2017.In
2022, Minnesota and Colorado commissions approved resource plans that
will add nearly 10,000 MW of utility-scale renewable energy to our systems.

Beyond carbon emissions, we have significantly reduced other emissions
and environmental impacts. Notable environmental improvements include:

*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 2021.

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 lay offs associated with our early
coal plant retirements. We also help foster economic development
opportunities to offset community economic 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.

Significant transmission expansion will also be required to enable the clean
energy transition, and Xcel Energy is already investing towards its goals.
For example, our $2 billion Pathway project in Colorado will provide over
560 miles of transmission lines and enable nearly 5,500 MW of new
renewable energy. In addition, 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.

Natural Gas Use in Buildings – Net Zero GHG by 2050

In 2021, we committed to reduce 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. Similar to our electric plan, our
vision to deliver gas service with net-zero emissions by 2050 aligns with
science-based scenarios likely to limit warming by 1.5 C.

Our net-zero natural gas strategy includes:
• Working with suppliers to purchase only low emissions gas supply by

•

2030.
Operating the cleanest possible system to achieve net-zero methane
emissions on the system by 2030.
Offering customer options that promote conservation, encourage
electrification, where beneficial, and incorporate clean fuels such as
hydrogen and renewable natural gas.
Applying high quality carbon offsets through projects that remove
emissions from other parts of the economy while providing additional
environmental and social benefit.

Electrification of the Transportation Sector

In addition to transitioning our own generation fleet, we are helping to
decarbonize other sectors, starting with transportation. We aim to enable
one out of five vehicles in our service areas to be electric by 2030,
representing a nearly $2 billion investment, 0.6% to 0.7% incremental
annual retail sales growth and avoidance of roughly 5 million tons of CO2
emissions annually. By 2050, our vision is to run all vehicles in our service
area with carbon-free electricity or other clean energy. We have launched
new products and services across our service territories. In addition, we
have an approved, transportation electrification plan in Colorado and
comprehensive transportation plans in Minnesota and Wisconsin that are
pending commission approval.

Innovation and Policy

Passage of the IRA is expected to reduce the cost of renewables for our
customers, improve the competitiveness of our renewable projects and
improve liquidity and credit metrics. The IRA is expected to reduce the cost
of future wind projects by 50-60% and solar projects by 25-40% (levelized
cost of energy basis). The IRA also lowers the costs of hydrogen
production that could be used for generation and the natural gas system.
Finally, the IRA is likely to provide customers additional benefits from PTCs
for the generation of electricity from our nuclear fleet.

New and emerging technologies are foundational to fulfilling our strategic
priorities. Advancement of economical, resilient and reliable zero-carbon
24/7 power technologies, as well as advanced storage and new low-carbon
fuels, are needed to deliver on our clean energy goals by 2050.

through collaborations with

We actively monitor and participate in emerging and advanced energy
technologies
technology
developers, venture investors and others in our industry. We have several
initiatives, pilots and demonstration projects underway that are advancing
and testing the real-world applications of cutting-edge technologies. Our
recently announced partnership with Form Energy to develop two 10 MW,
100-hour energy storage pilot projects is an example.

researchers,

ENHANCE THE CUSTOMER EXPERIENCE

Xcel Energy has a comprehensive suite of renewable and conservation
programs that provide customers with clean energy options and help keep
their bills low. We are also transforming and expanding our electric grid to
accommodate load growth, renewable energy and distributed energy
resources. We are in the process of installing smart meters, which will
deliver numerous customer and operational benefits, providing near-real-
time communication, allowing customers to know how much energy they
are using and what it will cost them. Along with the smart meters,
customers will have new digital tools to make it easier to access their
energy information, gain useful insights to better understand and manage
their energy use and make smarter energy choices that lower their bills.

KEEP BILLS LOW

Customer affordability is critical to successful strategy execution. From
2013 - 2022, we have kept residential electric bill growth to 1.8% per year
and below the rate of inflation. Residential gas bills were near flat, growing
0.3% per year from 2013 - 2021. Global pressures on natural gas prices
increased customer natural gas bills in 2022. We pass the cost of natural
gas directly to customers (without markup) through fuel clauses in most of
our states, and higher gas prices affected the affordability of the service we
provide.

We have taken several steps to address this concern:

•

Low-income customers are eligible to receive assistance with their
bills. In 2022, we set a company record for energy assistance
outreach as 193,000 customers were connected to programs that
provided $216 million in funding.
Xcel Energy has invested more than $2 billion over the past decade in
a comprehensive suite of electric and natural gas conservation
programs.

• We also kept O&M expenses flat from 2014 through 2021. While O&M
increased in 2022 due to global inflation pressures and other drivers,
our goal is to reduce 2023 O&M expenses 2% from 2022 levels and
keep them relatively flat thereafter.

•

• We continue to invest to reduce operating costs through ongoing
process and technology improvements, including the use of drone
technologies, automated work processes, artificial intelligence and
continuous improvement methodologies.
In addition, we are augmenting our One Xcel Energy Way program in
2023, which we expect to drive increased productivity and efficiency
across all levels of the Company.
As previously discussed, our geographic advantages in wind and solar
also enable customer savings, which we call our “Steel for Fuel”
strategy. High capacity factors, coupled with renewable tax credits and
avoided fuel costs, enable Xcel Energy to add renewable energy while
saving customers money.

•

REACHING OUR GOALS RESPONSIBLY

We instituted oversight of environmental performance by the Board of
Directors beginning in 2000 and was among the first U.S. energy providers
to tie carbon reduction to executive compensation over fifteen 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.

STRENGTHEN OUR COMMUNITIES

We provide a fundamental service, powering communities with safe,
reliable, affordable and increasingly clean energy.

For our local communities, we initiated 40 economic development projects
in 2022, which are projected to create over $1.8 billion in capital
investments and 2,900 jobs. Additionally, nearly 60% of our supply chain
spend was local and we spent approximately $550 million with diverse
suppliers.

Our employees served on more than 520 nonprofit organization or local
community boards in 2022. The Xcel Energy Foundation contributed $4.4
million to 426 nonprofit organizations that support its three charitable giving
focus areas: STEM Career Pathways, Environmental Sustainability, and
Community Vitality.

The Foundation, Company, employees and retirees also contributed more
than $5 million to local communities through Xcel Energy’s annual United
Way Giving Campaign and nearly 3,000 volunteers participated in Xcel
Energy’s annual Day of Service, supporting more than 100 nonprofit
projects.

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. In 2021, Xcel Energy added an incentive-based
metric focused on diverse interview panels, executive sponsorship and
employee feedback on inclusion in the workplace. A total of 70% of annual
incentive pay was tied to safety, system reliability and diversity, equity and
inclusion metrics.

Management continuously evaluates benefits to maintain a market-
competitive, performance-based, shareholder-aligned
rewards
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 diverse employees who reflect the communities we serve and live our
values. Xcel Energy had 11,982 full-time employees and workforce
demographics as of December 2022 were as follows:

Board of Directors

CEO direct reports

Management

Employees

New hires

Interns (hired throughout 2022)

Female

Ethnically Diverse

33 %

17 %

To help foster a culture of inclusivity, we offer leaders and employees
training on microinequities and unconscious bias. The Company 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, 2022, approximately 42% of
our employees (5,087) were covered by collective bargaining agreements.

Employee turnover for 2022 and future projected retirement eligibility:

Employee Turnover

Retirement Eligibility

Bargaining

Non-Bargaining
(a)

Overall

7 %

(a)

24% of turnover was due to retirements.

Within next 5 years

Within next 10 years

24 %

We have publicly confirmed our commitment to the advancement and
protection of human rights, consistent with U.S. human rights laws and the
general principles in the International Labour Organization Conventions.

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 received the following recognitions in 2022:

Fortune

World’s Most
Admired
Companies

Human Rights
Campaign

Ethisphere

GI Jobs

Best Places to Work
for LGBTQ Equality

World’s Most Ethical
Companies

Military Friendly
Employer

Utility Subsidiaries

NSP-Minnesota

Electric customers
Natural gas customers

Total assets

Rate Base (estimated)

1.5 million
0.5 million

$23.7 billion

$15.1 billion

ROE (net income / average stockholder's equity)

8.76%

Electric generating capacity

Gas storage capacity

Electric transmission lines (conductor miles)

Electric distribution lines (conductor miles)

Natural gas transmission lines

Natural gas distribution lines

8,949 MW
17.1 Bcf

33,000 miles

82,000 miles

78 miles

11,000 miles

NSP-Wisconsin

Electric customers

Natural gas customers

Total assets

Rate Base (estimated)

0.3 million

0.1 million

$3.4 billion

$2.1 billion

ROE (net income / average stockholder's equity)

10.57%

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)

548 MW

4.3 Bcf

12,000 miles

28,000 miles

3 miles

3,000 miles

1.6 million

1.5 million

$23.6 billion

$14.9 billion

ROE (net income / average stockholder's equity)

8.23%

Electric generating capacity

Gas storage capacity
Electric transmission lines (conductor miles)

Electric distribution lines (conductor miles)

Natural gas transmission lines

Natural gas distribution lines

6,151 MW

32.1 Bcf

25,000 miles

79,000 miles

2,000 miles

24,000 miles

SPS

Electric customers

Total assets

Rate Base (estimated)

0.4 million

$9.7 billion

$6.7 billion

ROE (net income / average stockholder's equity)

9.36%

Electric generating capacity
Electric transmission lines (conductor miles)

Electric distribution lines (conductor miles)

5,249 MW

41,000 miles

24,000 miles

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.

NSP-Wisconsin conducts business
in
Wisconsin and Michigan and generates,
transmits, distributes and sells electricity.
NSP-Minnesota
NSP-Wisconsin
and
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.

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

Electric Energy Sources

Total electric energy generation by source for the year ended Dec. 31:

Operations Overview

Utility operations are generally conducted as either electric or gas utilities in
our four utility subsidiaries.

Electric Operations

Electric operations consist of energy supply, generation, transmission and
distribution activities across all four operating companies. Xcel Energy had
electric sales volume of 116,885 (millions of KWh), 3.8 million customers
and electric revenues of $12,123 million for 2022.

Electric Operations
(percentage of total)

Sales Volume

Number of
Customers

Revenues

Residential

C&I

Other

23 %

86 %

29 %

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

2022

2021

24,285

23,968

2,513

2,405

13.41 ¢

9.02 ¢

10.35 ¢

12.94 ¢

8.73 ¢

10.03 ¢

(a)

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

Owned and Purchased Energy Generation — 2022

67%74%66%56%33%26%34%44%OwnedPurchasedXcel EnergyNSP SystemPSCoSPSCarbon-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

Xcel Energy currently has approximately 550 MW of owned wind under
development or being repowered.

Project

Northern Wind

Utility
Subsidiary

NSP-Minnesota

Grand Meadow Repower

NSP-Minnesota

Border Winds Repower

NSP-Minnesota

Pleasant Valley Repower

NSP-Minnesota

(a)

Placed in service in January 2023.

Capacity (MW)

Estimated
Completion

100

150

200

2023 (a)
2023

2025

Owned — Owned and operated wind farms with corresponding capacity:

Solar

Utility
Subsidiary

NSP System

PSCo

SPS

Total

2022
Capacity (MW) (a)
2,352

1,059

984

4,395

2021
Capacity (MW) (b)
2,031

1,059

984

4,074

Wind Farms

(a)

(b)

Summer 2022 net dependable capacity.

Summer 2021 net dependable capacity.

PPAs — Number of PPAs with capacity range:

Utility
Subsidiary

NSP System

PSCo

SPS

2022

2021

PPAs

Range (MW)

PPAs

Range (MW)

129

1 — 206

23 — 301

1 — 250

128

1 — 206

23 — 301

1 — 250

Capacity — Wind capacity (MW) for owned wind farms and PPAs:

Utility Subsidiary

NSP System

PSCo

SPS

2022

2021

4,515

4,082

2,548

3,997

4,085

2,548

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

Utility Subsidiary

NSP System

PSCo

SPS

2022

2021

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

Utility Subsidiary

NSP System

PSCo

SPS

2022

2021

Wind Development — Xcel Energy placed into service, repowered, or
contracted for the following during 2022:

Project

Utility Subsidiary

Capacity (MW)

NSP-Minnesota

Various

298 (a)(b)
200 (a)(b)
20 (a)(b)
220 (c)

Dakota Range

Nobles Repower

Rock Aetna

Various PPAs
(a)

(b)

(c)

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

PSCo

SPS

1,074

269

848

732

192

3,135

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

Utility Subsidiary

NSP System

PSCo

SPS

2022

2021

Solar Development — In September 2022, the MPUC approved NSP-
Minnesota's proposal to add 460 MW of solar facilities at the Sherco site.
The project is expected to cost approximately $690 million (two phases to
be completed in 2024 and 2025). As a result of the IRA, the levelized cost
of the project is expected to be approximately 30% lower than previously
estimated.

PSCo placed approximately 200 MW of PPAs into service during 2022 and
expects to place approximately 800 MW (including storage) of PPAs into
service during 2023.

Nuclear

Xcel Energy has two nuclear plants with approximately 1,700 MW of total
2022 net summer dependable capacity that serve the NSP System. Our
nuclear fleet has become one of the best performing and dependable in the
nation, as rated by both the NRC and INPO. Xcel Energy secures contracts
for uranium concentrates, uranium conversion, uranium enrichment and
fuel fabrication to operate its nuclear plants. We use varying contract
lengths as well as multiple producers for uranium concentrates, conversion
services and enrichment services to minimize potential impacts caused by
supply interruptions due to geographical and world political issues.

Nuclear Fuel Cost — Delivered cost per MMBtu of nuclear fuel consumed
for owned electric generation and the percentage of total fuel requirements
(nuclear, natural gas and coal):

Nuclear

Cost

Percent

0.76

0.77

51 %

Summer 2022 net dependable capacity.

Values disclosed are the maximum generation levels. Capacity is attainable only when
wind conditions are sufficiently available.
Based on contracted capacity.

2022

2021

Utility Subsidiary

NSP System

Natural Gas

Cost

Percent

7.58

4.98

7.09

8.38

5.87

6.72

12 %

Other — Xcel Energy’s other carbon-free energy portfolio includes hydro
from owned generating facilities.

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 owns and operates coal units with approximately 6,200 MW of
total 2022 net summer dependable capacity, which provided 23% of Xcel
Energy’s energy mix in 2022.

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):

Xcel Energy has plans to retire all of its existing coal generation by the end
of 2030. Approved early coal plant retirements:

Utility Subsidiary

NSP System

2022

(a)

2021

PSCo

2022

(a)

2021

SPS

2022

(a)

2021

2023

2024

2025

2026

2027

2028

2030

2034

(a)

(b)

(c)

(d)

Year

Utility Subsidiary

Plant Unit

Capacity (MW)

NSP-Minnesota

SPS

PSCo

NSP-Minnesota

PSCo

NSP-Minnesota

PSCo

SPS

Sherco 2
Harrington (a)
Comanche 2

Craig 1

(c)

Pawnee

Sherco 1

Hayden 2

Hayden 1

Craig 2

A.S. King

Sherco 3

Comanche 3

(d)

Tolk 1

(d)

Tolk 2

682

1,018

335
42 (b)
505

680
98 (b)
135 (b)
40 (b)
511
517 (b)
500 (b)
532

535

Reflects expected conversion from coal to natural gas following the TCEQ order that

Harrington cease use of coal fuel by Jan. 1, 2025.

Based on Xcel Energy’s ownership interest.

Reflects conversion from coal to natural gas.

Tolk Unit 1 and 2 are approved to be retired early in 2034. SPS proposed to retire both

units in 2028 in the pending New Mexico and Texas rate cases.

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

2022

2021

PSCo

2022

2021

SPS

2022

2021
(a)

Coal (a)

Cost

Percent

2.27

1.95

1.48

1.43

2.37

2.07

37 %

Includes refuse-derived fuel and wood for the NSP System.

Natural Gas

Xcel Energy has 23 natural gas plants with approximately 8,100 MW of
total 2022 net summer dependable capacity, which provided 24% of Xcel
Energy’s mix in 2022.

(a)

Reflective of Winter Storm Uri.

Capacity and Demand

Uninterrupted system peak demand and occurrence date:

System Peak Demand (MW)

2022

9,245

June 20

6,821 Sept. 6

4,280

July 19

2021

8,837

June 9

6,958

July 28

4,054 Aug. 9

NSP System

PSCo

SPS

Transmission

Transmission lines deliver electricity at high voltages and over long
distances from power sources to transmission substations closer to
customers. A strong transmission system ensures continued reliable and
affordable service, ability to meet state and regional energy policy goals,
and support for a diverse generation mix, including renewable energy. Xcel
Energy owns approximately 110,000 conductor miles of transmission lines,
serving 22,000 MW of customer load, across its service territory.

Between 2023 and 2028, Xcel Energy plans to build approximately 1,700
additional conductor miles of transmission lines, primarily as part of the
MISO Tranche 1 and Colorado Power Pathway projects.

See Item 2 - Properties for further information.

Distribution

lines allow electricity

Distribution
from
substations directly to customers. Xcel Energy has a vast distribution
network, owning and operating approximately 210,000 conductor miles of
distribution lines across our eight-state service territory.

lower voltages

travel at

To continue providing reliable, affordable electric service and enable more
flexibility for customers, we are working to digitize the distribution grid, while
at the same time keeping it secure. Xcel Energy plans to invest
approximately $1.7 billion implementing new network infrastructure, smart
meters, advanced software, equipment sensors and related data analytics
capabilities. As of Dec. 31, 2022, Xcel Energy had spent approximately
$765 million on these investments.

Investments of this nature will further improve reliability and reduce outage
restoration times for our customers, while at the same time enabling new
options and opportunities for increased efficiency savings. The new
capabilities will also enable integration of battery storage and other
distributed energy resources into the grid, including electric vehicles.

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 400,741 (thousands of MMBtu), 2.1 million customers and
natural gas revenues of $3,080 million for 2022.

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

38 %

92 %

59 %

2022

2021

116

1,318

11.97

10.45

1.16

114

917

8.61

7.20

1.20

Transportation and other revenue per MMBtu
(a)

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

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible
(customers with an alternate energy supply).

Maximum daily output (firm and interruptible) and occurrence date:

Utility Subsidiary

MMBtu

Date

MMBtu

2022

2021

(a)

Date

NSP-Minnesota

NSP-Wisconsin

PSCo

867,385

187,961

2,243,552

Feb. 12

Jan. 6

Dec. 22

899,133

167,656

2,316,283

Feb. 11

Feb. 14

(a)

Reflective of Winter Storm Uri.

Natural Gas Supply and Cost

Xcel Energy seeks natural gas supply,
transportation and storage
alternatives to yield a diversified portfolio, which 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:

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 milder in
the winter and cooler in the summer.

Competition

Xcel Energy is subject to public policies that promote competition and
development of energy markets. Xcel Energy’s industrial and large
commercial customers have the ability to generate their own electricity. In
addition, customers may have the option of substituting other fuels or
relocating their facilities to a lower cost region.

Customers have the opportunity to supply their own power with distributed
generation including solar generation and in most jurisdictions can currently
avoid paying for most of the fixed production, transmission and distribution
costs incurred to serve them.

Several states have incentives for the development of rooftop solar,
community solar gardens and other distributed energy resources.
Distributed generating resources are potential competitors to Xcel Energy’s
electric service business with these incentives and federal tax subsidies.

The FERC has continued to promote competitive wholesale markets
through open access transmission and other means. Xcel Energy’s
wholesale customers can purchase their output from generation resources
of competing suppliers or non-contracted quantities and use
the
transmission systems of the utility subsidiaries on a comparable basis to
serve their native load.

FERC Order No. 1000 established competition for 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.

Utility Subsidiary

NSP-Minnesota
NSP-Wisconsin

PSCo

(a)

Reflective of Winter Storm Uri.

(a)

2021

2022

7.00
6.68

6.33

7.48
7.11

6.06

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.

Coal Ash Regulation — In February 2023, the EPA entered into a Consent
Decree, committing the agency to either issue new proposed rules by May
5, 2023, to regulate inactive CCR landfills under the CCR Rule for the first
time, or to determine no such rules are necessary by that date. If proposed
rules are issued in May, the EPA has committed to a May 2024 effective
date for the new rules. Until proposed rules are issued, it is not certain what
the impact will be on Xcel Energy, but we anticipate that additional inactive
ash units could become regulated for the first time. It is also anticipated that
the EPA may issue other CCR proposed rules in 2023 that further expand
the scope of the CCR Rule.

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
Comprehensive Environmental Response, Compensation, and Liability Act,
specifically perfluorooctanoic acid and perfluorooctanesulfonic acid. This
proposed rule could result in new obligations for investigation and cleanup
wherever PFAS are found to be present. The impact the proposed
regulation may have on electric and gas utilities is currently uncertain.

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

•
•
•

$365 million in 2022.
$365 million in 2021.
$400 million in 2020.

for similar costs. The precise

Average annual expense of approximately $430 million from 2023 – 2027 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 included in and recovered through rates may
fluctuate.

Capital expenditures for environmental improvements were approximately:

•
•
•

$20 million in 2022.
$60 million in 2021.
$30 million in 2020.

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.

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 — In April 2022, the EPA proposed regulations under the
"Good Neighbor" provisions of the Clean Air Act. The proposed rules apply
to Minnesota, Texas and Wisconsin. The proposal establishes an
allowance trading program for NOx, potentially impacting Xcel Energy fossil
fuel generating facilities. Under the proposed rule, facilities without NOx
controls will have to secure additional allowances, install NOx controls, or
develop a strategy of operations that utilizes the existing allowance
allocations. The EPA has indicated that it intends for the rule to be final and
applicable in the first half of 2023. While the financial impacts of the
proposed regulation are uncertain and dependent on market forces, Xcel
Energy anticipates that costs will be approximately $60 million annually and
will be recoverable through regulatory mechanisms based on prior state
commission practices.

In a June 2022 ruling, the United States Supreme Court held that an
economy-wide approach to reducing greenhouse gas emissions from coal-
fired power plants was not consistent with the Clean Air Act. Therefore, if
the EPA proceeds with new rules, it cannot set a standard based on
economy-wide generation shifting to other sources, such as renewable
energy. It is anticipated that EPA will propose rules to limit GHG emissions
from new and existing coal and natural gas-fired electric generating units in
2023. If any new rules require additional investment, Xcel Energy believes
that the cost of these initiatives or replacement generation would be
recoverable through rates based on prior state commission practices.

Other

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

Capital Spending and Financing

See Item 7 for discussion of capital expenditures and funding sources.

Information about our Executive Officers (a)
Age (b)
52

Robert C. Frenzel

Name

Chairman of the Board of Directors, Xcel Energy Inc.

Current and Recent Positions

Brett C. Carter

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.

Executive Vice President, Chief Financial Officer, Xcel Energy Inc.
Senior Vice President and Chief Financial Officer, Luminant, a subsidiary of Energy Future Holdings Corp. (c)
Executive Vice President, Group President, Utilities, and Chief Customer Officer, Xcel Energy Inc.

Executive Vice President and Chief Customer and Innovation Officer, Xcel Energy Inc.

Senior Vice President and Shared Services Executive, Bank of America, an institutional investment bank and financial
services company

Patricia Correa

Senior Vice President, Chief Human Resources Officer, Xcel Energy Inc.

Senior Vice President, Human Resources, Eaton Corporation, a power management company

Vice President, Human Resources, Eaton Corporation

Timothy O’Connor

Executive Vice President, Chief Operations Officer, Xcel Energy Inc.

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

March 2020 — August 2021

May 2016 — March 2020

February 2012 — April 2016

March 2022 — Present

May 2018 — March 2022

October 2015 — May 2018

February 2022 — Present

July 2019 — January 2022

March 2016 — July 2019

August 2021 — Present

March 2020 — August 2021

February 2013 — March 2020

Frank Prager

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

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.

Managing Attorney, Xcel Energy Services Inc.

Rotational Position, Xcel Energy Services Inc.

Lead Assistant General Counsel, Xcel Energy Services Inc.

Brian J. Van Abel

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

June 2022 — Present

June 2020 — June 2022

October 2019 — June 2020

July 2018 — October 2019

January 2018 — July 2018

July 2015 — January 2018

March 2020 — Present

September 2018 — March 2020

July 2015 — September 2018

(a)

(b)

(c)

No family relationships exist between any of the executive officers or directors.

Ages as of Feb. 23, 2023.

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.

ITEM 1A — RISK FACTORS

Xcel Energy is subject to a variety of risks, many of which are beyond our
control. Risks that may adversely affect the business, financial condition,
results of operations or cash flows are described below. Although the risks
are organized by heading, and each risk is described separately, many of
the risks are interrelated. These risks should be carefully considered
together with the other information set forth in this report and future reports
that we file with the SEC. You should not interpret the disclosure of any risk
factor to imply that the risk has not already materialized.

While we believe we have identified and discussed below the key risk
there may be additional risks and
factors affecting our business,
uncertainties that are not presently known or that are not currently believed
to be significant that may adversely affect our business, financial condition,
results of operations or cash flows in the future.

Oversight of Risk and Related Processes

The Board of Directors is responsible for the oversight of material risk and
maintaining an effective risk monitoring process. Management and the
Board of Directors’ committees have responsibility for overseeing the
identification and mitigation of key risks and reporting its assessments and
activities to the full Board of Directors.

Xcel Energy maintains a robust compliance program and promotes a
culture of compliance beginning with the tone at the top. The risk mitigation
process includes adherence to our Code of Conduct and compliance
policies, operation of formal risk management structures and overall
business management. Xcel Energy further mitigates inherent risks through
formal risk committees and corporate functions such as internal audit, and
internal controls over financial reporting and legal.

Management identifies and analyzes risks to determine materiality and
other attributes such as timing, probability and controllability. Identification
and risk analysis occurs formally through risk assessment conducted by
senior management,
risk
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
committees
these risks are well understood and given
appropriate focus.

to confirm

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, icing events, floods 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.

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

Our products contain components that are globally sourced from suppliers
who, in turn, source components from their suppliers. A shortage of key
components in which an alternative supplier is not identified could
significantly impact operations and project plans for Xcel Energy and our
customers. Such impacts could include timing of projects, including
potential for project cancellation. Failure to adhere to project budgets and
timelines adversely impacts 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 alternative supply
services 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 being
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, the Company 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.

Additionally, compliance with existing and potential new regulations related
to the operation and maintenance of our natural gas infrastructure could
result in significant costs. The PHMSA is responsible for administering the
DOT’s national regulatory program to assure the safe transportation of
natural gas, petroleum and other hazardous materials by pipelines. The
PHMSA continues to develop regulations and other approaches to risk
management to assure safety in design, construction, testing, operation,
maintenance and emergency
response of natural gas pipeline
infrastructure. We have programs in place to comply with these regulations
and systematically monitor and renew infrastructure over time, however, a
significant incident or material finding of non-compliance could result in
penalties and higher costs of operations.

Our natural gas and electric transmission and distribution operations are
dependent upon complex information technology systems and network
infrastructure, the failure of which could disrupt our normal business
operations, which could have a material adverse effect on our ability to
process transactions and provide services.

Our utility operations are subject to long-term planning and project
risks.

Most electric utility investments are planned to be used for decades.
Transmission and generation investments typically have long lead times
and are planned well in advance of in-service dates and typically subject to
long-term
resource plans. These plans are based on numerous
assumptions such as: sales growth, customer usage, commodity prices,
economic activity, costs, regulatory mechanisms, customer behavior,
available technology and public policy. Xcel Energy’s long-term resource
plan is dependent on our ability to obtain required approvals, develop
necessary technical expertise, allocate and coordinate sufficient resources
and adhere to budgets and timelines.

In addition, the long-term nature of both our planning processes and our
asset lives are subject to risk. The electric utility sector is undergoing
significant change (e.g., increases in energy efficiency, wider adoption of
distributed generation and shifts away from fossil fuel generation to
renewable generation). Customer adoption of these technologies and
increased energy efficiency could result in excess transmission and
generation resources, downward pressure on sales growth, and potentially
stranded costs if we are not able to fully recover costs and investments.

The magnitude and timing of resource additions and changes in customer
demand may not coincide with evolving customer preference for generation
resources and end-uses, which introduces further uncertainty into long-term
planning. Efforts to electrify the transportation and building sectors to
reduce GHG emissions may result in higher electric demand and lower
natural gas demand over time. Higher electric demand may require us to
adopt new technologies and make significant transmission and distribution
investments
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.

including advanced grid

infrastructure, which

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

Failure to attract and retain a qualified workforce could have an
adverse effect on operations.

The competition for talent has become increasingly prevalent, and we have
experienced increased employee turnover due to the condition of the labor
market. 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.

Failure to hire and adequately train replacement employees, including the
transfer of significant knowledge and expertise to new employees or future
availability and cost of contract labor may adversely affect the ability to
manage and operate our business. Inability to attract and retain these
employees adversely impacts our results of operations, financial condition
or cash flows.

Our operations use third-party contractors in addition to employees to
perform periodic and ongoing work.

We rely on third-party contractors to perform operations, maintenance and
construction work. Our contractual arrangements with these contractors
typically include performance 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.

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

We are exposed to risk of employee or third-party contractor fraud or
misconduct. All employees and members of the Board of Directors are
subject to comply with our Code of Conduct and are required to participate
in annual training. Additionally, suppliers are subject to comply with our
Supplier Code of Conduct.

Xcel Energy does not tolerate discrimination, violations of our Code of
Conduct or other unacceptable behaviors. However, it is not always
possible to identify and deter misconduct by employees and other third-
parties, which may result in governmental investigations, other actions or
lawsuits. If such actions are taken against us we may suffer loss of
reputation and such actions could have a material effect on our financial
condition, results of operations and cash flows.

Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear
generation.

NSP-Minnesota has two nuclear generation plants, PI and Monticello. Risks
of nuclear generation include:

•

Hazards associated with the use of radioactive material in energy
production, including management, handling, storage and disposal.
Limitations on insurance available to cover losses that may arise in
connection with nuclear operations, as well as obligations to contribute
to an insurance pool in the event of damages at a covered U.S.
reactor.
Technological and financial uncertainties related to the costs of
decommissioning nuclear plants may cause our funding obligations to
change.

The NRC has authority to impose licensing and safety-related requirements
for the operation of nuclear generation facilities, including the ability to
impose fines and/or shut down a unit until compliance is achieved. NRC
safety requirements could necessitate substantial capital expenditures or
an increase in operating expenses. In addition, the INPO reviews NSP-
Minnesota’s nuclear operations. Compliance with
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.

We are subject to comprehensive regulation by federal and state utility
regulatory agencies, including siting and construction of facilities, customer
service and the rates that we can charge customers.

The profitability of our utility operations is dependent on our ability to
recover the costs of providing energy and utility services and 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.

Changes in the long-term cost-effectiveness or to the operating conditions
of our assets may result in early retirements of utility facilities. While
regulation typically provides cost recovery relief for these types of changes,
there is no assurance that regulators would allow full recovery of all
remaining costs.

Higher than expected inflation or tariffs may increase costs of construction
and operations. Also, rising fuel costs could increase the risk that 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.

We cannot be assured that our current credit ratings will remain in effect, or
that a rating will not be lowered or withdrawn by a rating agency. Significant
events including disallowance of costs, use of historic test years,
elimination of riders or interim rates, increasing depreciation lives, lower
returns on equity, changes to equity ratios and impacts of tax policy may
impact our cash flows and credit metrics, potentially resulting in a change in
our credit ratings. In addition, our credit ratings may change as a result of
the differing methodologies or change in the methodologies used by the
various rating agencies.

Any credit ratings downgrade could lead to higher borrowing costs or lower
proceeds from equity issuances. It could also impact our ability to access
capital markets. Also, 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 liquidity and an increase in bad debt
expense. Credit risk is comprised of numerous factors including the price of
products and services provided, the economy and unemployment rates.

Credit risk also includes the risk that counterparties that owe us money or
product will become insolvent and may breach their obligations. Should the
counterparties fail to perform, we may be forced to enter into alternative
arrangements. In that event, our financial results could be adversely
affected and incur losses.

Xcel Energy may have direct credit exposure in our short-term wholesale
and commodity trading activity to financial institutions trading for their own
accounts or issuing collateral support on behalf of other counterparties. We
may also have some indirect credit exposure due to participation in
organized markets, (e.g., MISO, SPP, Electric Reliability Council of Texas
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.

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.

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.

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 continue to 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 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.

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 cyber 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 cyber security incidents, including those
caused by human error.

The utility industry has been the target of several attacks on operational
systems and has seen an increased volume and sophistication of cyber
security incidents from international activist organizations, 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.

Cyber security incidents could harm our businesses by limiting our
generating,
transmitting and distributing capabilities, delaying our
development and construction of new facilities or capital improvement
projects to existing facilities, disrupting our customer operations or causing
the release of customer information, all of which would likely receive state
and federal regulatory scrutiny and could expose us to liability.

Xcel Energy’s generation, transmission systems and natural gas pipelines
are part of an interconnected system. Therefore, a disruption caused by the
impact of a cyber security incident 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.

Our supply chain for procurement of digital equipment and services may
expose software or hardware to these risks and could result in a breach or
significant costs of remediation. We are unable to quantify the potential
impact of cyber security threats or subsequent related actions. Cyber
security incidents and regulatory action could result in a material decrease
in revenues and may cause significant additional costs (e.g., penalties,
third-party claims, repairs, insurance or compliance) and potentially disrupt
our supply and markets for natural gas, oil and other fuels.

We maintain security measures to protect our information technology and
control systems, network infrastructure and other assets. However, these
assets and the information they process may be vulnerable to cyber
security incidents, including asset failure or unauthorized access to assets
or information.

A failure or breach of our technology systems or those of our third-party
service providers could disrupt critical business functions and may
negatively impact our business, our brand, and our reputation. The cyber
security threat is dynamic and evolves continually, and our efforts to
prioritize network protection may not be effective given the constant
changes to threat vulnerability.

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.

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, cyber or safety incident did occur, it could have a
material effect on our results of operations, financial condition or cash
flows.

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

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

Environmental 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.

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.

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 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.

Environmental laws and regulations can also require us to restrict or limit
the output of facilities or the use of certain fuels, shift generation to lower-
emitting facilities, install pollution control equipment, clean up spills and
other contamination and correct environmental hazards. Failure to meet
requirements of environmental mandates may result in fines or penalties.
We may be required to pay all or a portion of the cost to remediate sites
where our past activities, or the activities of other parties, caused
environmental contamination.

Changes in environmental policies and regulations or regulatory decisions
may result in early retirements of our generation facilities. While regulation
typically provides relief for these types of changes, there is no assurance
that regulators would allow full recovery of all remaining costs.

We are subject to mandates to provide customers with clean energy,
renewable energy and energy conservation offerings. It could have a
material effect on our results of operations, financial condition or cash flows
if our regulators do not allow us to recover the cost of capital investment or
O&M costs incurred to comply with the requirements.

In addition, existing environmental laws or regulations may be revised and
new laws or regulations may be adopted. We may also incur additional
unanticipated obligations or liabilities under existing environmental laws
and regulations.

We are subject to physical and financial risks associated with climate
change and other weather, natural disaster and resource depletion
impacts.

Climate change can create physical and financial risk. Physical risks
include changes in weather conditions and extreme weather events. Our
customers’ energy needs vary with weather. To the extent weather
conditions are affected by climate change, customers’ energy use could
increase or decrease. Increased energy use due to weather changes may
require us to invest in generating assets, transmission and infrastructure.
Decreased energy use due to weather changes may result in decreased
revenues.

Climate change may impact the economy, which could impact our sales
and revenues. The price of energy has an impact on the economic health of
our communities. The cost of additional regulatory requirements, such as
regulation of GHG, could impact the availability of goods and prices
charged by our suppliers which would normally be borne by consumers
through higher prices for energy and purchased goods.

To the extent financial markets view climate change and emissions of
GHGs as a financial risk, this could negatively affect our ability to access
capital markets or cause us to receive less than ideal terms and conditions.

We 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.

NSP-Wisconsin
Station, Location and Unit at Dec. 31, 2022
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/Refuse

1940 - 1948

(b)

Oil

Natural Gas/
Oil

1974

1973

Various

Total

122

234

135

548

Various locations, 62 Units

Hydro

(a)

(b)

Summer 2022 net dependable capacity.

Refuse-derived fuel is made from municipal solid waste.

PSCo
Station, Location and Unit at Dec. 31, 2022

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

Natural Gas

1975

2010

1979 - 1980

1965 - 1976

1981

1968

2003

2015

Fort St. Vrain-Platteville, CO, 6 Units

Natural Gas

1972 - 2009

Manchief, CO, 2 Units

(e)

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

2000

2004

Natural Gas

Various

Hydro

Wind

1967

Various

2018

2020

Total

(a)

(b)

(c)

(d)

(e)

(f)

Summer 2022 net dependable 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.

Purchased in 2022.

Capacity is attainable only when wind conditions are sufficiently available.

(b)

(c)

(d)

335

500

233

505

310

264

576

973

250

580

251

210

(f)

582

477

6,151

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, 2022

Fuel

Installed

(a)

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

Nuclear

1968

1976

1977

1987

1971

1973

1974

Wood/Refuse

Various

Angus Anson-Sioux Falls, SD, 3 Units

Natural Gas

1994 - 2005

Black Dog-Burnsville, MN, 3 Units

Blue Lake-Shakopee, MN, 6 Units

Natural Gas

1987 - 2018

Natural Gas

1974 - 2005

High Bridge-St. Paul, MN, 3 Units

Natural Gas

Inver Hills-Inver Grove Heights, MN, 6 Units

Natural Gas

Riverside-Minneapolis, MN, 3 Units

Various locations, 7 Units

Natural Gas

2008

1972

2009

Various

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

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

(e)

Pleasant Valley-Mower County, MN, 100
Units

Rock Aetna - Murray County, MN, 8 Units

Wind

2020

2021

2015

2020

2016

2020

2022

2019

2021

2008

2020

2019

2021

2010

2015

2022

Total

(a)

(b)

(c)

(d)

(e)

Summer 2022 net dependable capacity.

Based on NSP-Minnesota’s ownership of 59%.

Refuse-derived fuel is made from municipal solid waste.

Capacity is attainable only when wind conditions are sufficiently available.

Repowered in 2022.

511

680

682

517

617

521

519

327

494

447

530

252

454

200

148

190

192

298

150

200

196

(b)

(c)

(d)

8,949

SPS
Station, Location and Unit at Dec. 31, 2022

Fuel

Installed

MW (a)

ITEM 3 — LEGAL PROCEEDINGS

Steam:

Cunningham-Hobbs, NM, 2 Units

Natural Gas

1957 - 1965

225

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, 3 Units

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

298

Coal

1982 - 1985

1,067

Cunningham-Hobbs, NM, 2 Units

Natural Gas

1997

Jones-Lubbock, TX, 2 Units

Maddox-Hobbs, NM, 1 Unit

Wind:

Hale-Plainview, TX, 239 Units

Sagamore-Dora, NM, 240 Units

Natural Gas

2011 - 2013

Natural Gas

1963 - 1976

Wind

2019

2020

Total

207

334

(b)

477

507

5,249

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.

(a)

(b)

Summer 2022 net dependable capacity.

Capacity is attainable only when wind conditions are sufficiently available.

See Note 12 to the consolidated financial statements, Item 1 and Item 7 for
further information.

Electric utility overhead and underground transmission and distribution lines
at Dec. 31, 2022:

ITEM 4 — MINE SAFETY DISCLOSURES

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

2,915

12,183

2,300

626

—

8,033

6,537

32,594

—

2,457

—

1,795

—

1,829

5,571

—

5,418

12,141

—

5,011

1,839

11,652

24,501

—

11,676

9,829

—

14,905

4,469

40,879

82,024

27,817

79,331

23,538

Total

114,618

39,469

103,832

64,417

Electric utility transmission and distribution substations at Dec. 31, 2022:

NSP-Minnesota

NSP-Wisconsin

PSCo

SPS

Substations

352

206

238

457

Natural gas utility mains at Dec. 31, 2022:

Miles

NSP-Minnesota

NSP-Wisconsin

PSCo

SPS

WGI

Transmission

Distribution

10,902

2,067

2,570

23,542

—

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. 16, 2023 was 47,359.

The following compares our cumulative TSR on common stock with the
cumulative TSR of the EEI Investor-Owned Electrics Index and the S&P
500 Composite Stock Price Index over the last five years.

The EEI Investor-Owned Electrics Index (market capitalization-weighted)
included 39 companies at year-end and is a broad measure of industry
performance.

Comparison of Five Year Cumulative Total Return*

* $100 invested on Dec. 31, 2017 in stock or index — including

reinvestment of dividends. Fiscal years ended Dec. 31.

Xcel Energy Inc.EEI ElectricsS&P 500201720182019202020212022$80$100$120$140$160$180$200$220$240Purchases of Equity Securities by Issuer and Affiliated Purchasers

Results of Operations

Diluted EPS for Xcel Energy at Dec. 31:

Diluted Earnings (Loss) Per Share

PSCo

NSP-Minnesota

SPS

NSP-Wisconsin

Earnings from equity method investments —
WYCO

(a)

Regulated utility
Xcel Energy Inc. and Other

(a)

Total
(a)

Amounts may not add due to rounding.

2022
GAAP and
Ongoing Diluted
EPS

2021
GAAP and
Ongoing Diluted
EPS

1.33

1.23

0.64

0.23

0.04

3.47

(0.29)

3.17

1.22

1.12

0.59

0.20

0.05

3.18

(0.22)

2.96

Xcel Energy’s management believes
that ongoing earnings reflects
management’s performance in operating Xcel Energy and provides a
meaningful representation of the performance of Xcel Energy’s core
business. In addition, Xcel Energy’s management uses ongoing earnings
internally for financial planning and analysis, reporting results to the Board
of Directors and when communicating its earnings outlook to analysts and
investors.

2022 Comparison with 2021

Xcel Energy — GAAP and ongoing earnings increased $0.21 per share for
2022. The increase was driven by regulatory outcomes, partially offset by
higher depreciation, O&M expenses and interest charges. Costs for natural
gas significantly increased in 2022 due to market conditions. However,
fluctuations in electric and natural gas revenues associated with changes in
fuel and purchased power and/or natural gas sold and transported
generally do not significantly impact earnings (changes in revenues are
offset by the related variation in costs).

PSCo — Earnings increased $0.11 per share for 2022, driven by regulatory
outcomes and favorable weather. Higher revenues were partially offset by
higher depreciation, O&M expenses and interest charges.

NSP-Minnesota — Earnings increased $0.11 per share for 2022 compared
to 2021, driven by regulatory rate outcomes, partially offset by additional
depreciation and O&M expenses.

SPS — Earnings increased $0.05 per share for 2022, largely related to
regulatory rate outcomes, strong sales growth and favorable weather,
partially offset by higher depreciation and O&M expenses.

NSP-Wisconsin — Earnings increased $0.03 per share for 2022 compared
to 2021. The increase is due to regulatory rate outcomes and sales growth,
partially offset by higher depreciation and O&M expenses.

Xcel Energy Inc. and Other — Earnings decreased $0.07 per share year-
to-date due to higher interest charges and decreased earnings from EIP
investments.

For the quarter ended Dec. 31, 2022, 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

includes

financial

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 are 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. We
believe these measurements are useful to investors to evaluate the actual
and projected financial performance and contribution of our subsidiaries.
For the years ended Dec. 31, 2022 and 2021, there were no such
adjustments to GAAP earnings and therefore GAAP earnings equal
ongoing earnings.

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

2022 vs.
Normal

2021 vs.
Normal

2022 vs.
2021

6.5 %

(6.6) %

13.0 %

23.7

5.6

12.2

26.8

16.1

(15.8)

Weather — Estimated impact of temperature variations on EPS compared
with normal weather conditions:

Retail electric

Decoupling and sales true-up

Electric total

Firm natural gas

Total

2022 vs.
Normal

2021 vs.
Normal

2022 vs.
2021

0.138

0.096

(0.061)

(0.066)

0.077

0.030

0.037

(0.025)

0.114

0.005

0.042

0.005

0.047

0.062

0.109

Sales — Sales growth (decline) for actual and weather-normalized sales:

Actual
Electric
residential

Electric C&I

Total retail
electric sales
Firm natural gas
sales

2022 vs. 2021

PSCo

NSP-
Minnesota

SPS

NSP-
Wisconsin

Xcel
Energy

(1.5) %

—

(0.5)

5.4

(1.2) %

6.5 %

1.1 %

(0.1) %

1.7

0.8

8.9

8.4

3.3

2.6

3.3

2.3

18.3

N/A

17.3

10.1

2022 vs. 2021

PSCo

NSP-
Minnesota

SPS

NSP-
Wisconsin

Xcel
Energy

Weather-normalized
Electric
residential
Electric C&I

Total retail
electric sales
Firm natural gas
sales

(3.6) %
(0.3)

(1.4)

(3.1)

(0.2) %
2.1

1.3

5.5

0.8 %
8.4

6.9

N/A

— %
3.4

2.4

5.8

(1.3) %
3.2

1.8

0.1

Changes in Diluted EPS

Components significantly contributing to changes in EPS:

Diluted Earnings (Loss) Per Share

GAAP and ongoing diluted EPS — 2021

Dec. 31

2.96

2022 vs. 2021

Components of change — 2022 vs. 2021

Higher electric revenues, net of electric fuel and purchased power

Higher natural gas revenues, net of cost of natural gas sold and
transported
Lower ETR (a)
Higher depreciation and amortization

Higher O&M expenses

Higher interest expense

Higher taxes (other than income taxes)

Other (net)

GAAP and ongoing diluted EPS — 2022

0.89

0.16

0.15

(0.40)

(0.24)

(0.15)

(0.08)

(0.12)

3.17

(a)

Includes PTCs and plant regulatory amounts, which are primarily offset as a reduction to
electric revenues.

ROE for Xcel Energy and its utility subsidiaries:

ROE

PSCo

NSP-Minnesota

SPS

NSP-Wisconsin

Operating Companies

Xcel Energy

2022

2021

GAAP and Ongoing ROE

8.23 %

8.76

9.36

10.57

8.74

10.76

8.23 %

8.45

9.22

9.92

8.58

10.58

Statement of Income Analysis

The following summarizes the items that affected the individual revenue
and expense items reported in the consolidated statements of income.

Estimated Impact of Temperature Changes on Regulated Earnings —
Unusually hot summers or cold winters increase electric and natural gas
sales, while mild weather reduces electric and natural gas sales. The
estimated impact of weather on earnings is based on the number of
customers, temperature variances, the amount of natural gas or electricity
historically used per degree of temperature and excludes any incremental
related operating expenses that could result due to storm activity or
vegetation management requirements.

As a result, weather deviations from normal levels can affect Xcel Energy’s
financial performance. However, sales true-up and decoupling mechanisms
in Minnesota and Colorado predominately mitigate the positive and adverse
impacts of weather.

Degree-day or THI data is used to estimate amounts of energy required to
maintain comfortable indoor temperature levels based on each day’s
average temperature and humidity.

HDD is the measure of the variation in the weather based on the extent to
which the average daily temperature falls below 65° Fahrenheit. CDD is the
measure of the variation in the weather based on the extent to which the
average daily temperature rises above 65° Fahrenheit.

Each degree of temperature above 65° Fahrenheit is counted as one CDD,
and each degree of temperature below 65° Fahrenheit is counted as one
HDD.

Weather-normalized electric sales growth (decline) — year-to-date

Change in Electric Margin

•

PSCo — Residential sales declined due to decreased use per
customer, partially offset by a 1.1% increase in customers. C&I sales
decline was attributable to decreased use per customer, primarily in
the manufacturing sector (largely due to an alternative generation
arrangement with a significant customer), partially offset by strong
small C&I sales in the food services and health care sectors.

NSP-Minnesota — Residential sales decline reflects a decreased use
per customer, partially offset by a 1.1% increase in customers. Growth
in C&I sales was primarily due to higher use per customer, particularly
in the manufacturing, real estate and leasing, and food service
sectors.

SPS — Residential sales growth was primarily attributable to a 0.9%
increase in customers, partially offset by lower use per customer. C&I
sales increased due to higher use per customer, primarily driven by
the energy sector.

NSP-Wisconsin — C&I sales growth was associated with higher use
per customer, experienced primarily
transportation and
manufacturing sectors.

the

Weather-normalized natural gas sales growth (decline) — year-to-date

•

Natural gas sales reflect growth in NSP-Minnesota and NSP-
Wisconsin attributable primarily to increased residential use per
customer and customer growth as well as increases in C&I sales due
to higher use per customer. These increases were offset by a
reduction in PSCo natural gas sales, primarily driven by declines in
residential use per customer.

Electric Margin

Electric margin is presented as electric revenues less electric fuel and
purchased power expenses. Expenses incurred for electric fuel and
purchased power are generally recovered through various regulatory
recovery mechanisms.

As a result, changes in these expenses are generally offset in operating
revenues.

Electric revenues and fuel and purchased power expenses are impacted by
fluctuations in the price of natural gas, coal and uranium. 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

2022

2021

12,123

(5,005)

7,118

11,205

(4,733)

6,472

(Millions of Dollars)

2022 vs. 2021

Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico
and Wisconsin)
Revenue recognition for the Texas rate case surcharge (a)
Sales and demand

(b)

Non-fuel riders

Wholesale transmission (net)

Estimated impact of weather (net of decoupling/sales true-up)

PTCs flowed back to customers (offset by lower ETR)

Other (net)

Total increase

506

(150)

(22)

646

(a)

(b)

Recognition of revenue from the Texas rate case outcome is largely offset by

recognition of previously deferred costs.

Sales excludes weather impact, net of decoupling in Colorado and proposed sales true-

up mechanism in Minnesota.

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

2022

2021

3,080

(1,910)

1,170

2,132

(1,081)

1,051

(Millions of Dollars)

2022 vs. 2021

Regulatory rate outcomes (Minnesota, Colorado, Wisconsin, North
Dakota)

Estimated impact of weather

Conservation revenue (offset in expenses)

Infrastructure and integrity riders

Winter Storm Uri disallowances

Other (net)

Total increase

(20)

119

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $170 million year-to-date,
due to the following approximately equal drivers: inflation and impacts of
supply chain constraints; operational activities (vegetation management,
repairs/maintenance and storms); costs for technology and customer
programs; insurance-related costs; recognition of previously deferred
amounts related to the 2021 Texas rate case; and other.

Depreciation and Amortization — Depreciation and amortization
increased $292 million year-to-date. The increase was primarily driven by
capital investment, recognition of previously deferred costs related to the
Texas Electric Rate Case and several wind farms going into service.

Other Income (Expense) — Other income (expense) decreased $18
million year-to-date, largely related to rabbi trust performance, which is
primarily offset in O&M expenses (employee benefit costs).

Earnings from Equity Method Investments — Earnings from equity
method investments decreased $26 million year-to-date. The year-to-date
change was largely attributable to the performance of the EIP funds, which
invest in energy technology companies.

Interest Charges — Interest charges increased $111 million year-to-date.
The increase was largely due to higher long-term debt levels to fund capital
investments and higher interest rates.

Income Taxes — Income tax benefit increased $65 million year-to-date.
The year-to-date increase was primarily driven by an increase in wind
PTCs due to greater production at existing wind farms, several new wind
farms going into service and an increase in the PTC rate partially offset by
higher pretax earnings.

Xcel Energy Inc. and Other Results

Net income and diluted EPS contributions of Xcel Energy Inc. and its
nonregulated businesses:

Contribution (Millions of Dollars)

Public Utility Regulation

The FERC and various state and local regulatory commissions regulate
Xcel Energy Inc.’s utility subsidiaries and West Gas Interstate. Xcel Energy
is subject to rate regulation by state utility regulatory agencies, which have
jurisdiction with respect to the rates of electric and natural gas distribution
companies
in Minnesota, North Dakota, South Dakota, Wisconsin,
Michigan, Colorado, New Mexico and Texas.

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

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

See Rate Matters within Note 12 to the consolidated financial statements
for further information.

NSP-Minnesota

Summary of Regulatory Agencies / RTO and Areas of Jurisdiction

2022

2021

Regulatory Body / RTO

Additional Information

Xcel Energy Inc. financing costs

Venture Holdings

(a)

Xcel Energy Inc. taxes and other results

Total Xcel Energy Inc. and other costs

Xcel Energy Inc. financing costs

Venture Holdings

(a)

Xcel Energy Inc. taxes and other results

Total Xcel Energy Inc. and other costs

(153) $

(12)

(160) $

(129)

(12)

(120)

Contribution (Diluted Earnings
(Loss) Per Share)

2022

2021

(0.28) $

0.01

(0.02)

(0.29) $

(0.24)

0.04

(0.02)

(0.22)

(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.

2021 Comparison with 2020

A discussion of changes in Xcel Energy’s results of operations, cash flows
and liquidity and capital resources from the year ended Dec. 31, 2020 to
Dec. 31, 2021 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 2021, which was filed with
the SEC on Feb. 23, 2022. However, such discussion is not incorporated
by reference into, and does not constitute a part of, this Annual Report on
Form 10-K.

MPUC

NDPSC

SDPUC

FERC

MISO

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.

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

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

DOT

Pipeline safety compliance.

Minnesota Office of
Pipeline Safety

Pipeline safety compliance.

Recovery Mechanisms

Mechanism

CIP Rider

(a)

Additional Information

Recovers costs of conservation and DSM programs
Minnesota.

Environmental
Improvement Rider

Recovers costs of environmental improvement projects in
Minnesota.

Renewable
Development Fund

RES

Renewable Energy
Rider

Transmission Cost
Recovery

Infrastructure Rider

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 Minnesota.

Recovers cost of renewable generation in North Dakota.

Recovers costs for investments in Minnesota, North Dakota, and
South Dakota for electric transmission and distribution grid
modernization.
Recovers costs for investments in generation in South Dakota.

FCA

Recovers prudently incurred costs of fuel related items and
purchased energy (Minnesota, North Dakota and South Dakota).

Purchased Gas
Adjustment

GUIC Rider

Sales True-up

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.

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. The statute
authorizing the GUIC Rider is set to expire June 30, 2023.

funding

NSP-Minnesota has historically had a sales true-up mechanism
for all electric customer classes which ended in 2021. We are
requesting implementation of a new sales true-up mechanism for
2022 - 2024. These mechanisms mitigate the impact of changes
to sales levels as compared to a baseline.

(a)

Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues

and 0.5% of its state natural gas revenues on CIP. These costs are recovered through

an annual cost-recovery mechanism.

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 request is 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 revised request is detailed as follows:
(Amounts in Millions)

2022

2023

2024

Total

Rate request (annual increase)

234 $

94 $

170 $

Rate base

10,923

11,425

11,902

498

N/A

In 2022, several parties filed testimony with various recommendations. The
DOC provided the following recommendations in surrebuttal testimony.

NSP-Minnesota’s filed base revenue request

396 $

546 $

677

2022

2023

2024

Recommended adjustments:

Rate base and rate of return

MISO capacity credits

Sales forecast update

Monticello and wind farm life extension

PTC forecast

Property tax

Prepaid pension asset and liability

O&M expenses

Sherco 3 and King remaining life

Other, net

Total adjustments

Total proposed revenue change

(72)

(66)

(51)

(21)

(28)

(14)

(13)

(37)

—

(23)

(65)

(112)

(65)

(111)

—

(54)

(1)

(23)

(21)

(39)

(33)

—

(51)

(1)

(34)

(32)

(44)

(43)

(325)

(319)

(353)

71 $

227 $

324

Next steps in the procedural schedule are expected to be as follows:

•
•

ALJ Report: March 31, 2023.
MPUC Order: June 30, 2023.

2022 Minnesota Natural Gas Rate Case — In November 2021, NSP-
Minnesota filed a request with the MPUC for a natural gas rate increase of
$36 million, or 6.6%. The filing is based on a 2022 forecast test year and
includes a requested ROE of 10.5%, an equity ratio of 52.5% and a rate
base of $934 million. In December 2021, the MPUC approved an interim
rate increase of $25 million, subject to refund, effective Jan. 1, 2022.

In October 2022, NSP-Minnesota and various parties filed an uncontested
settlement, which includes the following key terms:

•

•
•
•
•

Base rate revenue increase of $21 million, with a true up to weather
normalized actual sales for 2022.
Revenue decoupling mechanism.
Symmetrical property tax true-up.
ROE of 9.57%.
Equity ratio of 52.5%.

In December 2022, the ALJ recommended MPUC approval of the
settlement. A MPUC decision is expected in the first half of 2023.

2021 North Dakota Natural Gas Rate Case — In September 2021, NSP-
Minnesota filed a request with the NDPSC for a natural gas rate increase of
$7 million, or 10.5%. The filing is based on a ROE of 10.5%, an equity ratio
of 52.54%, a 2022 forecast test year and rate base of $124 million. Interim
rates of $7 million, subject to refund, were implemented on Nov. 1, 2021.

In May 2022, NSP-Minnesota and NDPSC Staff reached a settlement,
which reflects a rate increase of $5 million, based on a 9.8% ROE and
52.54% equity ratio. In October 2022, the NDPSC approved the settlement
and final rates were implemented on Nov. 1, 2022.

South Dakota Electric Rate Case — In June 2022, NSP-Minnesota filed a
South Dakota electric rate case seeking a revenue
increase of
approximately $44 million. The filing is based on a 2021 historic test year
adjusted for certain known and measurable changes for 2022 and 2023, a
ROE of 10.75%, rate base of approximately $947 million and an equity ratio
of 53%. Interim rates were implemented on Jan. 1, 2023. Final rates are
expected to be approved by the SDPUC in mid-2023.

Wind Repowering — In January 2021, the MPUC approved NSP-
Minnesota’s request for the repowering of 651 MW of owned wind projects.
Two of the four repowering projects, where construction has not yet begun
(in-service dates in 2025), now expect costs in excess of the original
approval. While the capital costs have increased, the passage of the IRA
and other changes result in a levelized cost of energy that is approximately
30% lower than the original approval.

In October 2022, NSP-Minnesota filed a request with the MPUC seeking
approval of the higher capital costs for these repowering projects. In
February 2023, the DOC filed comments recommending approval of
recovery of the increased costs of these projects through the RES Rider. A
final decision is pending.

2022 Upper Midwest RFP — In August 2022, NSP-Minnesota launched a
RFP for 900 MW of solar or solar-plus-storage hybrid resources to come
online by the end of 2025, including up to 300 MW of capacity to reuse the
Sherco Unit 2 interconnection rights when the coal facility retires at the end
of 2023.

NSP-Minnesota completed its bid evaluation process in December 2022
and will file for approval of the selected projects in early 2023.

2022 Minnesota Electric Vehicle Proposal — In August 2022, NSP-
Minnesota filed a request with the MPUC for approval of approximately
$320 million of capital investments (2022 through 2026) to support a public
charging network, electric school bus pilot, and other expansions and
modifications to its residential and commercial electric vehicle programs.

In October 2022, the MPUC referred the matter to the Office of
Administrative Hearings to conduct a contested case on the proposals. In
February 2023, other parties to the contested proceeding filed their direct
testimony ranging in levels of support / opposition to the proposals. The
evidentiary hearing is scheduled in Q2 2023 with a report from the ALJ
expected in Q3 2023. A MPUC decision is expected in late 2023.

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 operating licenses in 2030 for Monticello, 2033 for PI
Unit 1, and 2034 for PI Unit 2.

In September 2021, NSP-Minnesota filed an application for a CON for
additional spent fuel storage (existing Independent spent fuel storage
installation) at the Monticello Nuclear Power Generating Plant to allow
continued operation of the Monticello Plant until 2040.

A decision is expected in late 2023. Authorizations for additional spent fuel
storage capacity may be required at each site to support either continued
operation or decommissioning
federal government does not
commence storage operations.

the

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 2023.

Wholesale and Commodity Marketing Operations

NSP-Minnesota conducts wholesale marketing operations, including the
purchase and sale of electric capacity, energy, ancillary services and
energy-related products. NSP-Minnesota uses physical and financial
instruments to minimize commodity price 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 does not serve any wholesale requirements
customers at cost-based regulated rates.

NSP-Wisconsin

Summary of Regulatory Agencies / RTO and Areas of Jurisdiction

Regulatory Body / RTO

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.

NSP-Wisconsin is a transmission owning member of the MISO
RTO that operates within the MISO RTO and wholesale energy
market. NSP-Wisconsin and NSP-Minnesota are
jointly
authorized by the FERC to make wholesale electric sales at
market-based prices.

DOT

Pipeline safety compliance.

Recovery Mechanisms

PSCo

Mechanism

Annual Fuel Cost Plan

Power Supply Cost
Recovery Factors

Wisconsin Energy
Efficiency Program

Purchased Gas
Adjustment

Natural Gas Cost-
Recovery Factor (MI)

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 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.

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.

A retail cost-recovery mechanism to recover the actual cost of
natural gas, transportation, and storage services.
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.

Purchased Power and Transmission Services
The NSP System expects to use power plants, power purchases,
conservation and DSM options, new generation facilities and expansion of
power plants to meet its system capacity requirements.

Purchased Power — Through the Interchange Agreement, NSP-Wisconsin
receives power purchased by NSP-Minnesota from other utilities and
independent power producers. Long-term purchased power contracts for
dispatchable resources typically require a capacity charge and an energy
charge. NSP-Minnesota makes short-term purchases to meet system
requirements, replace company owned generation, meet operating reserve
obligations or obtain energy at a lower cost.

Purchased Transmission Services — NSP-Minnesota and NSP-Wisconsin
have contracts with MISO and other regional transmission service providers
to deliver power and energy to their customers.

Wholesale and Commodity Marketing Operations

NSP-Wisconsin does not serve any wholesale requirements customers at
cost-based regulated rates.

Summary of Regulatory Agencies / RTO and Areas of Jurisdiction

Regulatory Body / RTO

CPUC

FERC

RTO

DOT

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
including SPP and
to other RTO’s,
make certain sales
participates in a joint dispatch agreement with neighboring
utilities.

Pipeline safety compliance.

Recovery Mechanisms

Mechanism

ECA

Additional Information
Recovers fuel and purchased energy costs. Short-term sales
margins are shared with customers. The ECA is revised
quarterly.

Purchased Capacity
Cost Adjustment

Steam Cost Adjustment

Recovers purchased capacity payments.

Recovers fuel costs to operate the steam system. The Steam
Cost Adjustment rate is revised quarterly.

DSM Cost Adjustment

Recovers electric and gas DSM, interruptible service costs and
performance initiatives for achieving energy savings goals.

RES Adjustment

Recovers the incremental costs of compliance with the RES with
a maximum of 1% of the customer’s bill.

Colorado Energy Plan
Adjustment

Recovers the early retirement costs of Comanche units 1 and 2
to a maximum of 1% of the customer’s bill.

Wind Cost Adjustment

Recovers costs for customers who choose renewable resources.

Transmission Cost
Adjustment

FCA

GCA

Recovers costs for transmission investment between rate cases.

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.

Pipeline system integrity
adjustment

Recovers costs for transmission and distribution pipeline integrity
management programs (rider ended on Dec. 31, 2022).

Decoupling

Mechanism to true-up revenue to a baseline amount for
residential (excluding lighting and demand) and metered non-
demand small C&I classes.

Transportation
Electrification Plan

Recovers costs associated with the investment in and adoption
of transportation electrification infrastructure.

Pending and Recently Concluded Regulatory Proceedings

Colorado Natural Gas Rate Case — In January 2022, PSCo filed a request
with the CPUC seeking a net increase to retail natural gas rates of $107
million. The total change to base rates is $215 million, which reflects the
transfer of $108 million previously recovered from customers through the
pipeline system integrity adjustment rider. The request was based on a
10.25% ROE, an equity ratio of 55.66% and a 2022 current test year with a
projected rate base of $3.6 billion.

PSCo’s request also included step revenue increases of $40 million
(effective Nov. 1, 2023) and $41 million (effective Nov. 1, 2024) related to
continued capital investment.

In October 2022, the CPUC approved a rate increase net of rider roll-ins of
$64 million. The decision reflects a stated WACC of 6.7%, a historic test
year with a year-end rate base and $16 million of incremental depreciation
expense. PSCo has the option to determine its ROE within a range of 9.2%
to 9.5% and its equity ratio within a range of 52% to 55%, as long as it
results in a WACC of 6.7%. The CPUC denied the 2023-2024 step
increases. Base rates were placed in effect November 1, 2022.

Colorado Electric Rate Case — In November 2022, PSCo filed an electric
rate case seeking a net increase of $262 million, or 8.2%. The total request
reflects a $312 million increase, which includes $50 million of authorized
costs currently recovered through various rider mechanisms. The request is
based on a 10.25% ROE, an equity ratio of 55.7% and a 2023 forecast test
year with a 2023 year-end rate base of $11.3 billion. PSCo requested rates
effective in September 2023. A procedural schedule is expected to be
established by the CPUC in the first quarter of 2023.

Colorado Resource Plan — In August 2022, the CPUC approved an
updated settlement, which will result in the further acceleration of the
retirement of the Comanche Unit 3 coal plant, an expected carbon
reduction of at least 85% and an 80% renewable mix by 2030. The CPUC
deferred a decision on the method of cost recovery for the retiring coal units
to a separate docket, which will consider accelerated depreciation, creation
of regulatory assets and securitization. PSCo filed the recovery method
docket in the fourth quarter of 2022.

Key settlement terms include:

•

•
•
•
•
•

Early retirement of Hayden: Unit 2 in 2027 (was 2036); and Unit 1 in
2028 (was 2030).
Conversion of the Pawnee coal plant to natural gas by no later than
Jan. 1, 2026.
Early retirement of Comanche Unit 3 by Jan. 1, 2031 (was 2070) with
reduced operations beginning in 2025.
Addition of ~2,400 MW of wind.
Addition of ~1,600 MW of universal-scale solar.
Addition of 400 MW of storage.
Addition of 1,300 MW of flexible, dispatchable generation.
Addition of ~1,200 MW of distributed solar resources through our
renewable energy programs.

In December 2022, the Company commenced the RFP process for
generation resources with a bid receipt date of March 1, 2023. After
reviewing the bids received, PSCo will file a report with the CPUC with
the
recommended resource acquisitions and a CPUC decision on
resources to be acquired is expected in October 2023.

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

In October 2021, a settlement was reached on Winter Storm Uri costs and
also addressed certain components of the 2020 decoupling refunds.

In April 2022, PSCo made its annual filing on this matter. In December
2022, the ALJ approved a settlement between PSCo, CPUC Staff and the
UCA. The settlement requires PSCo to file a petition for declaratory
judgment to address the treatment of any expired balance under the 3%
soft cap provisions.

As of Dec. 31, 2022, PSCo has recognized a refund for Residential
customers and a surcharge for small C&I customers based on 2020, 2021
and 2022 results.

In December 2022,

Transmission Cost Adjustment —
the CPUC
suspended PSCo’s request for 2023 TCA rate changes. The CPUC Staff
protested the TCA on the grounds that only projects resulting in new
transmission should be included and no repair or replacement of existing
infrastructure should be included. The CPUC consolidated the matter with
the pending electric rate case for assessment.

ECA Fuel Recovery — In December 2022, PSCo filed its first quarter 2023
ECA Advice Letter, which sought to recover $123 million of under-
recovered 2022 fuel costs over two quarters (instead of the typical one). 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 fuel costs. Proposed ECA rates were updated
to remove the 2022 under-recovered balance and were implemented on
Jan. 1, 2023. In February 2023, PSCo submitted an interim ECA filing
which included $70 million of the 2022 under-recovered costs. A filing for
the remaining amount is anticipated in the first quarter of 2023.

GCA NOPR — In June 2021, the CPUC issued a NOPR addressing the
recovery of costs through the GCA. The CPUC has reopened the GCA
NOPR and proposed a 2-step process aimed at 1) considering near term
process changes to the GCA and 2) a longer term process to evaluate
potential performance incentive structures. In step 1, consensus proposed
rule amendments to update the process and filing requirements for GCA
and related filings have been submitted to the CPUC for consideration.
PSCo worked with other utilities and stakeholders regarding consensus
proposed rule amendments for step 2, including a provision that each LDC
bring forward its own performance incentive mechanism in a future filing. In
December 2022, the CPUC approved the consensus proposal.

In February 2023, the Governor of Colorado issued an open letter to the
CPUC, utilities, and other stakeholders directing agencies to take additional
steps to address energy costs. It is likely this request will result in the
opening of additional dockets to further explore the GCA and other related
the
mechanisms. Additionally,
formation of a Joint Select Committee to investigate the source of rising
utility rates and explore potential actions to prevent future price instability.

the Colorado Legislature announced

Natural Gas Planning NOPR — In October 2021, the CPUC issued a
NOPR to implement recent state legislation requiring natural gas utilities to
develop clean heat plans to meet state greenhouse gas emission reduction
targets, as well as updated demand-side management criteria. Additionally,
the proposed rules included new comprehensive natural gas infrastructure
planning requirements and related Certificate of Public Convenience and
Necessity application procedures, changes in natural gas line extension
policy, and details on emission accounting related to clean heat plans.
PSCo recommended changes to the proposed rules, which may be
incorporated into the final rules issued in the first quarter of 2023.

Purchased Power and Transmission Service Providers

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

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

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

Purchased Transmission Services —
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.

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.

Reviews and approves Integrated Resource Plans for meeting
future energy needs

Retail electric operations, retail rates and services and the
construction of transmission or generation.

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
Distribution Cost
Recovery Factor

Energy Efficiency Cost
Recovery Factor

Energy Efficiency Rider
Fuel and Purchased
Power Cost Adjustment
Clause

Additional Information

Recovers distribution costs not included in rates in Texas.

Recovers costs for energy efficiency programs in Texas.

Recovers costs for energy efficiency programs in New Mexico.

Adjusts monthly to recover actual fuel and purchased power
costs in New Mexico.

Power Cost Recovery
Factor

Allows recovery of purchased power costs not included in Texas
rates.

Renewable Portfolio
Standards

Recovers deferred costs for renewable energy programs in New
Mexico.

Transmission Cost
Recovery Factor

Fixed Fuel and
Purchased Recovery
Factor

Wholesale Fuel and
Purchased Energy Cost
Adjustment

Electric Vehicle Rider

Advanced Metering
System Surcharge

Consulting Fee Rider

Recovers certain transmission infrastructure improvement costs
and changes in wholesale transmission charges not included in
Texas base rates.

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.
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
jurisdictional
FERC. Wholesale customers also pay
allocation of production costs.

the

Recovers costs of the Transportation Electrification Plan in New
Mexico.
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.

Pending and Recently Concluded Regulatory Proceedings

2021 Texas Electric Rate Case — In May 2022, the PUCT approved a
settlement between SPS and intervening parties.

In July 2022, SPS filed to surcharge the final under-recovered amount,
estimated to be approximately $85 million, substantially offset by the
recognition of previously deferred costs.

(Millions of Dollars)

Revenue surcharge accrual

Depreciation and amortization

O&M expenses

Interest expense

Taxes other than income taxes

Fuel and purchased power

Year Ended Dec. 31, 2022

Natural Gas

(43)

(16)

(12)

(10)

(2)

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.

2022 New Mexico Electric Rate Case — In November 2022, SPS filed an
electric rate case with NMPRC seeking a revenue increase of $78 million,
or 10%. The request is based on a future test year ending June 30, 2024, a
ROE of 10.75%, an equity ratio of 54.7% and rate base of $2.4 billion.
Additionally, the request reflects further acceleration of the Tolk coal plant
depreciation life from 2032 to 2028.

Next steps in the procedural schedule are expected to be as follows:

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.

•
•
•
•
•

Staff and intervenor testimony: March 31, 2023.
Rebuttal testimony: April 25, 2023.
Stipulation: May 8, 2023.
Hearing: June 5, 2023.
End of rate suspension: Sept. 19, 2023.

2023 Texas Electric Rate Case — On Feb. 8, 2023, SPS filed an electric
rate case with the PUCT seeking an increase in base rate revenue of $149
million. The impact to overall customer bills is expected to be approximately
13%. The request is based on a historical test year period ended Sept. 30,
2022, with an Update Period ended Dec. 31, 2022, a ROE of 10.65%, an
equity ratio of 54.6% and retail rate base of $3.6 billion. Additionally, the
request reflects further acceleration of the Tolk coal plant depreciation life
from 2034 to 2028.

SPS is requesting a surcharge from July 13, 2023 through the effective
date of new base rates. A PUCT decision is expected in the first quarter of
2024.

SPS and LP&L Contract Termination — SPS and LP&L have a 25-year,
170 MW partial requirements contract. In May 2021, SPS and LP&L
finalized a settlement which would terminate the contract upon LP&L’s
move from the SPP to the Electric Reliability Council of Texas (expected in
2023). The settlement agreement requires LP&L to pay SPS $78 million (to
the benefit of SPS’ remaining customers). LP&L would remain obligated to
pay for SPP transmission charges associated with LP&L’s load in SPP. The
agreement is pending PUCT and FERC approval.

2022 All-Source RFP — In 2022, SPS issued an RFP, which seeks up to
947 MW of new or existing capacity resources to provide replacement
capacity for retiring units and meet SPS’ growing capacity needs through
2027. SPS will receive bids in the first quarter of 2023 and file for the
approval of successful proposals in the second quarter of 2023.

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.

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 scarcity of certain raw
materials and interruptions in production and shipping. These disruptions
have been further exacerbated by inflationary pressures, labor shortages
and the impact of international conflicts/issues. 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.

Electric Distribution and Transmission Transformers

The availability of certain transformers is an industry-wide issue that has
been significantly impacted and in some cases may result in delays in
projects and new customer connections. Xcel Energy continues to seek
alternative suppliers and prioritize work plans to mitigate impacts of supply
constraints.

Solar Resources

In April 2022, the U.S. Department of Commerce initiated an anti-
circumvention investigation that would subject CSPV solar panels and cells
imported from Malaysia, Vietnam, Thailand, and Cambodia with potential
incremental tariffs ranging from 50% to 250%. These countries account for
more than 80% of CSPV panel imports.

An interim stay on tariffs has been issued and 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 or other restrictions on solar imports (i.e., as a result of
implementation of the Uyghur Forced Labor Protection Act) could impact
project timelines and costs.

Marshall Wildfire

In December 2021, a wildfire ignited in Boulder County, Colorado (the
“Marshall Fire”), which burned over 6,000 acres and destroyed or damaged
over 1,000 structures. Boulder County authorities are currently investigating
the fire and have not yet determined a cause. There were no downed
power lines in the ignition area, and nothing the Company has seen to this
point indicates that our equipment or operations caused the fire.

In Colorado, the standard of review governing liability differs from the
“inverse condemnation” or strict liability standard utilized in California. In
Colorado, courts look to whether electric power companies have operated
their system with a heightened duty of care consistent with the practical
conduct of its business, and liability does not extend to occurrences that
cannot be reasonably anticipated. In addition, PSCo has been operating
under a commission approved wildfire mitigation plan and carries wildfire
liability insurance.

In March 2022, a class action suit was filed in Boulder County pertaining to
the Marshall Fire. In the remote event PSCo was found liable related to this
litigation and were required to pay damages, such amounts could exceed
our insurance coverage and have a material adverse effect on our financial
condition, results of operations or cash flows. In December 2022, the
District Court judge denied PSCo’s Motion to Dismiss.

MISO Capacity Credits

The NSP System offered 1,500 MW of excess capacity into the MISO
planning resource auction for June 2022 through May 2023. Due to a
projected overall capacity shortfall in the MISO region, the 1,500 MWs
offered cleared the auction at maximum pricing, generating revenues of
approximately $90 million in 2022, with approximately $60 million expected
in 2023. These amounts will primarily be used to mitigate customer rate
increases or returned through earnings sharing or other mechanisms.

Inflation Reduction Act

In August 2022, the IRA was signed into law.

Key provisions impacting Xcel Energy include:

•

•
•

•

Extends current PTC and ITC for renewable technologies (e.g., wind
and solar).
Restores full value of the PTC and ITC for qualifying facilities placed
in-service after 2021.
Creates a PTC for solar, clean hydrogen and nuclear.
Establishes an ITC for energy storage, microgrids, interconnection
facilities, etc.
Allows companies to monetize or sell credits to unrelated parties.

Xcel Energy anticipates the IRA will materially reduce the cost of renewable
energy, resulting in significant customer savings.

The IRA is expected to allow Xcel Energy to monetize tax credits more
efficiently with the incremental benefits passed through to customers.
Transferability provisions apply to eligible tax credits generated starting in
2023 for both new and existing facilities. Xcel Energy anticipates tax credit
transferability from existing renewable projects will improve cash from
operations by $1.8 billion (2023 - 2027), assuming constructive regulatory
outcomes and the development of a market.

The IRA creates a nuclear PTC beginning in 2024 that may also provide
additional customer savings. The annual customer benefit from these PTCs
could range from $0 to $300 million, depending on locational marginal
pricing, as well as constructive U.S. Treasury guidance regarding
computation of the credits.

In addition, the IRA created a new corporate AMT. Xcel Energy does not
anticipate AMT having a material cash impact based on current estimates
and our interpretation of its application.

Winter Storm Uri

In February 2021, the United States experienced Winter Storm Uri.
Extreme cold temperatures impacted certain operational assets as well as
the availability of renewable generation. The cold weather also affected the
country’s supply and demand for natural gas.

These factors contributed to extremely high market prices for natural gas
and electricity. As a result of the extremely high market prices, Xcel Energy
incurred net natural gas, fuel and purchased energy costs of approximately
$1 billion (largely deferred as regulatory assets).

Xcel Energy has received recovery approval from all of our impacted states
except for Texas, which is pending. A summary of pending and recently
approved regulatory requests for Winter Storm Uri cost recovery is listed
below.

Utility
Subsidiary Jurisdiction Regulatory Status
NSP-
Minnesota

Minnesota

In 2021, the MPUC allowed recovery of $179 million of costs
(with no financing charge) starting in September 2021, pending
a prudency review. The C&I class ($82 million) will be recovered
over 27 months and the residential class ($97 million) will be
recovered over a 63-month recovery period.

PSCo

Colorado

SPS

Texas

In August 2022, the MPUC approved recovery of Uri storm costs
with a $19 million disallowance.

In May 2021, PSCo filed a request with the CPUC to recover
$263 million in weather-related electric costs, $287 million in
incremental natural gas costs and $4 million in incremental
steam costs over 24 months with no financing charge.

In July 2022, the CPUC approved a partial settlement providing
full recovery of fuel costs, with the exception of an $8 million
disallowance, over 24 months for electric and 30 months for
natural gas customers.

In 2021, SPS filed to recover $88 million of Winter Storm Uri
costs over 24 months, as part of the Texas fuel surcharge filing,
with total under-recovered costs of $121 million. In April 2022,
interim rates designed to recover $121 million over 30 months
were approved, subject to PUCT approval through the triennial
Fuel Reconciliation proceeding.

In July 2022, the intervenors filed recommendations. The Texas
Industrial Energy Consumers and PUCT staff recommended
disallowances of approximately $10 million (off-system sales
margins). The Office of Public Utility Counsel recommended
disallowances of approximately $15 million (off-system sales
margins and adjustment to energy loss factors). The Alliance of
of
recommended
Xcel Municipalities
approximately $100 million (natural gas storage, contracted
capability and off-system sales margins).

disallowances

In November 2022, the ALJs found that costs were prudently
incurred and recommended no disallowances. A final PUCT
decision is anticipated in the first quarter of 2023.

Critical Accounting Policies and Estimates

requires

the consolidated

financial statements

the
Preparation of
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, 2022 and 2021, Xcel Energy had regulatory assets of $3.9
billion and $3.8 billion, respectively and regulatory liabilities of $6.0 billion
and $5.7 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, 2022, 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 based on an evaluation
of expected future taxable income. Accounting for income taxes also
requires that only tax benefits that meet the more likely than not recognition
threshold can be recognized or continue to be recognized.

We may adjust our unrecognized tax benefits and interest accruals as
disputes with the IRS and state tax authorities are resolved, and as new
developments occur. These adjustments may increase or decrease
earnings.

See Note 7 to the consolidated financial statements for further information.

Employee Benefits

We sponsor several noncontributory, defined benefit pension plans and
other postretirement benefit plans that cover almost all employees and
certain retirees. Projected benefit costs are based on historical information
and actuarial calculations that include key assumptions (annual return level
on pension and postretirement health care investment assets, discount
rates, mortality rates and health care cost trend rates, etc.). In addition, the
pension cost calculation uses a methodology to reduce the volatility of
investment performance over time. Pension assumptions are continually
reviewed.

At Dec. 31, 2022, Xcel Energy set the rate of return on assets used to
measure pension costs at 6.93%, which is 44 basis points higher than the
rate set in 2021. The rate of return used to measure postretirement health
care costs is 5.00% at Dec. 31, 2022, which is 90 basis points higher than
the rate set in 2021. Xcel Energy’s pension investment strategy is based on
plan-specific investments that seek to minimize investment and interest rate
risk as a plan’s funded status increases over time. This strategy results in a
greater percentage of interest rate sensitive securities being allocated to
plans with 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 5.80% at Dec. 31, 2022. This
represents a 272 basis point and 271 basis point increase, respectively,
from 2021. 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 2022 pension costs:

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 $13 million, $15 million and $11 million during 2022,
2021 and 2020, respectively, to the postretirement health care plans. Xcel
Energy expects to contribute approximately $12 million during 2023. Xcel
Energy recovers employee benefits costs in its utility operations consistent
with accounting guidance with the exception of the areas noted below.

(Millions of Dollars)

(a)

Rate of return
Discount rate (a)

Pension Costs

+1%

-1%

(11) $

(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, 2022, 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 2022 were $50 million and will remain relatively
consistent in future years. Investment returns were less than the assumed
levels in 2022, but exceeded the assumed levels in 2021 and 2020.

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 2022).

Xcel Energy currently projects the pension costs recognized for financial
reporting purposes will be $66 million in 2023 and $58 million in 2024, while
the actual pension costs were $114 million in 2022 and $121 million in
2021. The expected decrease in 2023 is primarily due to the reductions in
loss amortizations.

Pension funding contributions across all four of Xcel Energy’s pension
plans, both voluntary and required, for 2020 - 2023:

•
•
•
•

$50 million in January 2023.
$50 million in 2022.
$131 million in 2021.
$150 million in 2020.

•

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 Colorado, Texas, New Mexico and FERC
jurisdictions allow the recovery of other postretirement benefit costs
only to the extent that recognized expense is matched by cash
contributions to an irrevocable trust. Xcel Energy has consistently
funded at a level to allow full recovery of costs in these jurisdictions.
PSCo 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 $2.2 billion in 2022 and $2.1 billion
in 2021.

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, 2022.

that becomes available. The accompanying

See Note 12 to the consolidated financial statements for further information.

Derivatives, Risk Management and Market Risk

We are exposed to a variety of market risks in the normal course of
business. Market risk is the potential loss that may occur as a result of
adverse changes in the market or fair value 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.

Wholesale and Commodity Trading Risk — Xcel Energy conducts
various wholesale and commodity trading activities, including the purchase
and sale of electric capacity, energy, energy-related instruments and
natural gas-related
risk
management policy allows management to conduct these activities within
guidelines and limitations as approved by our risk management committee.

including derivatives. Our

instruments,

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.

Fair value of net commodity trading contracts as of Dec. 31, 2022:

(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

(8) $

(6) $

(7) $

(2) $

(23)

(56)

(4)

(15)

(49) $

(22) $

—

(3)

—

(5) $

(2)

(63)

(72)

Options Maturity

Less
Than
1 Year

1 to 3
Years

4 to 5
Years

—

Greater
Than
5 Years
$

—

Total Fair
Value

(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)

Fair value of commodity trading net contracts outstanding at Jan. 1

Contracts realized or settled during the period

Commodity trading contract additions and changes during the period

2022

2021

$ (33) $ (54)

(15)

(54)

Fair value of commodity trading net contracts outstanding at Dec. 31

$ (10) $ (33)

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 $8
million at Dec. 31, 2022 and $13 million at Dec. 31, 2021. Market price
movements can exceed 10% under abnormal circumstances.

the
The utility subsidiaries’ commodity
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.

trading operations measure

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

2022

2021

—

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

Nuclear Fuel Supply — NSP-Minnesota has contracted for its 2023 and
2024 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 26% of its average enriched
nuclear material requirements from Russia through 2030. We are closely
monitoring the evolving situation in Ukraine and its global impacts. NSP-
Minnesota is in the process of entering into new contracts to reduce the risk
of supply interruptions of nuclear material from Russia. NSP-Minnesota will
take additional further action to reduce this risk as necessary.

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
$8 million and $11 million in 2022 and 2021, 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, 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 a decrease in credit exposure of $47 million.
At Dec. 31, 2021, a 10% increase in commodity prices would have resulted
in an increase in credit exposure of $36 million, while a decrease in prices
of 10% would have resulted in an decrease in credit exposure of $26
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.

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.

Net cash provided by financing activities decreased by $1,469 million for
2022 as compared to 2021. The decrease was primarily related to the
amount/timing of debt issuances and repayments associated with Winter
Storm Uri.

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

Capital Requirements

Xcel Energy has contractual obligations and other commitments that will
need to be funded in the future. 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
financing
requirements can be impacted by various factors including constraints to
supply chain and labor, as well as inflation.

ratios. Projected

future

Recovery of the effects of inflation through higher customer rates is
dependent upon receiving adequate and timely rate increases. Rate
increases may not be retroactive and often lag increases in costs caused
by inflation. On occasion, Xcel Energy may enter into rate settlement
agreements, which require us to wait for a period of time to file the next
base rate increase request. These agreements may result in regulatory lag
whereby the impact of inflation may not yet be reflected in rates, or a delay
may occur between capital project completion and the start of rate
recovery. Xcel Energy attempts to mitigate the potential impact of inflation
through the use of fuel, energy and other cost adjustment clauses and bill
riders, by employing prudent risk management and hedging strategies and
by considering, among other areas, its impact on purchases of energy,
operating expenses, materials and equipment costs, contract negotiations,
future capital spending programs and long-term debt issuances.

Liquidity and Capital Resources

Cash Flows

Operating Cash Flows

(Millions of Dollars)

Twelve Months Ended Dec. 31

Cash provided by operating activities — 2021

Components of change — 2022 vs. 2021

Higher net income

Non-cash transactions

Changes in working capital

Changes in net regulatory and other assets and liabilities

Cash provided by operating activities — 2022

2,189

139

257

(300)

1,647

3,932

Net cash provided by operating activities increased by $1,743 million for
2022 as compared to 2021. The increase was primarily due to the deferral
of net natural gas, fuel and purchased energy costs incurred during Winter
Storm Uri in the first quarter of 2021.

Investing Cash Flows

(Millions of Dollars)

Cash used in investing activities — 2021

Components of change — 2022 vs. 2021

Increased capital expenditures

Other investing activities

Cash used in investing activities — 2022

Twelve Months Ended Dec. 31

(4,287)

(394)

(4,653)

Net cash used in investing activities increased by $366 million for 2022 as
compared to 2021. 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 — 2021

2,135

Components of change — 2022 vs. 2021

Lower debt issuances

Higher repayments of long-term debt

Lower proceeds from issuance of common stock

Higher dividends paid to shareholders

Other financing activities

Cash provided by financing activities — 2022

(1,159)

(184)

(44)

(77)

(5)

666

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)
Other long-term obligations, including current portion

(c)

Other short-term obligations

Short-term debt

Total contractual cash obligations
(a)

Payments Due by Period (as of Dec. 31, 2022)

Total

Less than 1 Year

1 to 3 Years

3 to 5 Years

After 5 Years

39,750

2,059

3,492

2,714

31,485

228

1,457

5,129

111

436

813

264

1,899

436

813

506

1,475

—

287

921

—

181

400

834

—

47,924

5,534

5,528

3,962

32,900

Included in operating lease obligations are $231 million, $455 million, $251 million and $326 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively,

(b)

(c)

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.

Primarily consists of contracts for information technology services.

Capital Expenditures — Base capital expenditures and incremental capital forecasts:

Total base capital expenditures

4,890

5,400

6,200

6,270

5,410

6,220

(a)

Other category includes intercompany transfers for safe harbor wind turbines.

Actual

2022

2023

2024

2025

2026

2027

2023 - 2027 Total

Base Capital Forecast (Millions of Dollars)

1,940

2,140

2,440

2,550

1,980

2,190

1,980

2,000

2,400

2,530

2,200

2,580

610

370

(10)

710

540

780

570

720

500

(30)

770

450

900

540

Actual

2022

2023

2024

2025

2026

2027

2023 - 2027 Total

Base Capital Forecast (Millions of Dollars)

1,370

1,610

1,790

1,680

2,000

2,450

960

720

730

700

410

1,280

1,650

1,890

1,690

1,900

710

740

780

280

910

730

840

280

900

760

570

470

560

650

510

—

650

680

540

—

11,300

11,710

3,880

2,600

29,500

9,530

8,410

3,730

3,560

3,240

1,030

29,500

By Regulated Utility

PSCo

NSP-Minnesota

SPS

NSP-Wisconsin
Other (a)

By Function

Electric distribution

Electric transmission

Electric generation

Natural gas

Other

Renewables

Total base capital expenditures

4,890

5,400

6,200

6,270

5,410

6,220

The base five-year capital forecast includes transmission expansion
through the proposed Colorado Pathway (approximately $1.7 billion) and
MISO Tranche 1 (approximately $1.2 billion) as well as the proposed 460
MW Sherco Solar Generating Unit 1 and 2 (approximately $600 million).

The base capital investment plan does not include any potential renewable
generation assets approved in our Minnesota and Colorado resource plans
or additional transmission capital needed to integrate new renewable
generation additions in Colorado, beyond the Pathway project.

We expect further clarification in the second half of 2023 after the
commissions rule on the recommended resource plan portfolios, which
could result in incremental capital expenditures of approximately $2 to $4
billion (assuming 50% ownership of the renewable projects). Furthermore,
the base capital investment plan does not include any potential generation
assets associated with our 2022 SPS Request for Proposal, which seeks
up to 947 MW of new or existing capacity resources.

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
tax policy), reserve requirements, availability of
clean energy and
purchased power, alternative plans for meeting long-term energy needs,
environmental initiatives and regulation, and merger, acquisition and
divestiture opportunities.

Financing for Capital Expenditures through 2027 — 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 2023 through 2027:

Capital Sources

Short-Term Funding Sources — Xcel Energy generally funds short-term
needs, through operating cash flows, notes payable, commercial paper and
bank lines of credit. The amount and timing of short-term funding needs
depend on construction expenditures, working capital and dividend
payments.

Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-
Wisconsin, PSCo and SPS maintain cash and short-term investment
accounts.

Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin,
PSCo and SPS each have individual commercial paper programs.
Authorized levels for these commercial paper programs are:

•
•
•
•
•

$1.50 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. 22, 2023, 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)
328
$

Available

Cash

Liquidity

1,172

PSCo

NSP-Minnesota

SPS

NSP-Wisconsin

Total

700

500

150

123

186

577

514

409

121

1,178

582

520

411

123

3,550

757

2,793

$ 21

2,814

(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, 2022 and 2021, Xcel Energy had approximately 550
million shares and 544 million shares of common stock outstanding,
respectively.

Xcel Energy Inc. and its utility subsidiaries have registration statements on
file with the SEC pursuant to which they may sell securities from time to
time. These registration statements, which are uncapped, permit Xcel
Energy Inc. and its utility subsidiaries to issue debt and other securities in
the future at amounts, prices and with terms to be determined at the time of
future offerings, and in the case of our utility subsidiaries, subject to
commission approval.

(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 2023 - 2027

Maturing Debt
(a)

Net of dividends and pension funding.

20,540

8,210

425

325

29,500

3,800

(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 2023, Xcel Energy
announced an increase in the annual dividend of 13 cents per share, which
represents an increase of 6.7%.

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, 2022

Dec. 31, 2021

2,685

2,871

(186) $

3,670

3,718

(48)

(a)

Excludes non-qualified plan of $11 million and $43 million at Dec. 31, 2022 and 2021,

respectively.

Pension Assumptions

Discount rate

Expected long-term rate of return

2022

2021

5.80 %

6.93

3.08 %

6.49

Planned Financing Activity — Xcel Energy’s 2023 financing plans reflect
the following:

ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK

See the “Derivatives, Risk Management and Market Risk” section in Item 7,
incorporated by reference.

ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

See Note 15 to the consolidated financial statements for further information.

(Millions of Dollars)

Security

Amount

Anticipated Timing

Xcel Energy Inc.

Senior Unsecured Bonds

500 Third Quarter

PSCo

SPS

NSP-Minnesota

NSP-Wisconsin

First Mortgage Bonds

700

100

750

125

Second Quarter

Third Quarter

Second Quarter

Long-Term Borrowings, Equity
Issuances and Other Financing
Instruments — Xcel Energy also plans to issue approximately $85 million
of equity annually through the DRIP and benefit programs during the five-
year forecast time period.

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

Earnings Guidance and Long-Term EPS and Dividend Growth Rate
Objectives

Xcel Energy 2023 Earnings Guidance — Xcel Energy’s 2023 GAAP and
ongoing earnings guidance is a range of $3.30 to $3.40 per share.(a)

Key assumptions as compared with 2022 levels unless noted:
•
•
• Weather-normalized retail electric sales are projected to increase

Constructive outcomes in all rate case and regulatory proceedings.
Normal weather patterns for the year.

~1%.

• Weather-normalized retail firm natural gas sales are projected to

•

•
•

•

•
•

(a)

increase ~1%.
Capital rider revenue is projected to increase $90 million to $100
million (net of PTCs).
O&M expenses are projected to decline ~2%.
Depreciation expense is projected to increase approximately $130
million to $140 million.
Property taxes are projected to increase approximately $35 million to
$45 million.
Interest expense (net of AFUDC - debt) is projected to increase $100
million to $110 million.
AFUDC - equity is projected to increase $0 million to $10 million.
ETR is projected to be ~(5%) to (7%).

Ongoing earnings is calculated using net income and adjusting for certain nonrecurring

or infrequent items that are, in management’s view, not reflective of ongoing operations.

Ongoing earnings could differ from those prepared in accordance with GAAP for

unplanned and/or unknown adjustments. Xcel Energy is unable to forecast if any of
these items will occur or provide a quantitative reconciliation of the guidance for ongoing

EPS to corresponding GAAP EPS.

Long-Term EPS and Dividend Growth Rate Objectives — Xcel Energy
expects to deliver an attractive total return to our shareholders through a
combination of earnings growth and dividend yield, based on the following
long-term objectives:

•

Deliver long-term annual EPS growth of 5% to 7% based off of a 2022
base of $3.15 per share, which represents the mid-point of the original
2022 guidance range of $3.10 to $3.20 per share.

Deliver annual dividend increases of 5% to 7%.

Target a dividend payout ratio of 60% to 70%.

Maintain senior secured debt credit ratings in the A range.

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, 2022. 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, 2022, 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. 23, 2023

/s/ BRIAN J. VAN ABEL
Brian J. Van Abel
Executive Vice President, Chief Financial Officer

Feb. 23, 2023

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, 2022 and 2021,
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, 2022, 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, 2022, 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,
2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, 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, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by
COSO.

Basis for Opinions

The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its
assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Controls over
Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial
reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB)
and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations
of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain
reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal
control over financial reporting was maintained in all material respects.

Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due
to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the
amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included
obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the
design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we
considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control
over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial
statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required
to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our
especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial
statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or
on the accounts or disclosures to which it relates.

Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements — Refer to Notes 4 and 12 to the consolidated financial
statements.

Critical Audit Matter Description

The Company is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas
distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico, and Texas. The Company is also subject to
the jurisdiction of the Federal Energy Regulatory Commission for its wholesale electric operations, hydroelectric generation licensing, accounting practices,
wholesale sales for resale, transmission of electricity in interstate commerce, compliance with North American Electric Reliability Corporation standards,
asset transactions and mergers and natural gas transactions in interstate commerce, (collectively with state utility regulatory agencies, the “Commissions”).
Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its
financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation
affects multiple financial statement line items and disclosures, including property, plant and equipment, regulatory assets and liabilities, operating revenues
and expenses, and income taxes.

The Company is subject to regulatory rate setting processes. Rates are determined and approved in regulatory proceedings based on an analysis of the
Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in assets required to deliver services to customers.
Accounting for the Company’s regulated operations provides that rate-regulated entities report assets and liabilities consistent with the recovery of those
incurred costs in rates, if it is probable that such rates will be charged and collected. The Commissions’ regulation of rates is premised on the full recovery of
incurred costs and a reasonable rate of return on invested capital. Decisions by the Commissions in the future will impact the accounting for regulated
operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. In
the rate setting process, the Company’s rates result in the recording of regulatory assets and liabilities based on the probability of future cash flows.
Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory
liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.

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

How the Critical Audit Matter Was Addressed in the Audit

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

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

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

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

• We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet

addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.

/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 23, 2023

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

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

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)

Total operating expenses

Operating income

Other (expense) income, 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 $31, $29 and $28, 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

2022

2021

2020

12,123

11,205

3,080

107

15,310

5,005

1,910

2,491

331

2,413

688

2,132

13,431

4,733

1,081

2,321

304

2,121

630

12,882

11,228

2,428

2,203

(13)

953

(28)

925

1,601

(135)

842

(26)

816

1,527

(70)

1,736

1,597

547

539

540

3.18

3.17

2.96

9,802

1,636

11,526

3,512

689

2,324

288

1,948

612

9,410

2,116

(6)

115

840

(42)

798

1,467

(6)

1,473

527

528

2.79

See Notes to Consolidated Financial Statements

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 gains (losses) arising during the period, net of tax of $1, $— and $(2), respectively

Reclassification of losses to net income, net of tax of $1, $3 and $3, respectively

Derivative instruments:

Net fair value increase (decrease), net of tax of $6, $1 and $(3), respectively

Reclassification of losses to net income, net of tax of $2, $2 and $2, respectively

Total other comprehensive income

Total comprehensive income

Year Ended Dec. 31

2022

2021

2020

1,736

1,597

1,473

—

(5)

(10)

—

1,473

See Notes to Consolidated Financial Statements

1,766

1,615

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:

2022

Year Ended Dec. 31
2021

2020

1,736

1,597

1,473

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
Sale of MEC
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 (paid) received 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

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

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

(55)
166
111

37
129
166

(887) $
(15)

(788) $
(4)

626
78
141
75
57

501
87
8
73
60

1,959
123
(8)
(115)
(40)
42
60
73

(154)
(3)
(80)
(45)
(33)
(144)
29
(125)
(164)
2,848

(5,369)
684
(1,398)
1,378
(35)
(4,740)

(11)
2,940
(1,001)
727
(856)
(26)
1,773

(119)
248
129

(758)
12

400
275
369
115
67

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; 549,578,018 and 544,025,269 shares outstanding at Dec. 31, 2022
and Dec. 31, 2021, 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

Dec. 31

2022

2021

111
1,373
1,105
803
1,059
279
54
360
5,144

166
1,018
862
631
1,106
123
44
289
4,239

48,253

45,457

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

3,628
2,738
67
1,291
431
8,155
57,851

601
1,005
1,409
271
569
209
249
69
205
459
5,046

4,894
53
5,405
3,151
105
196
306
1,146
158
15,414

21,779

1,360
7,803
6,572
(123)
15,612
57,851

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

Par Value

Additional Paid
In Capital

Retained
Earnings

Accumulated
Other
Comprehensive
Loss

Total Common
Stockholders’
Equity

Balance at Dec. 31, 2019

524,539,000

1,311

6,656

5,413

(141) $

13,239

Net income

Dividends declared on common stock ($1.72 per share)

Issuances of common stock

Repurchases of common stock

Share-based compensation

Adoption of ASC Topic 326

Balance at Dec. 31, 2020

Net Income

Other comprehensive loss

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 income

Dividends declared on common stock ($1.95 per share)

Issuances of common stock

Share-based compensation

Balance at Dec. 31, 2022

12,953,869

(54,475)

—

731

(4)

1,473

(909)

(7)

(2)

1,473

(909)

764

(4)

(2)

537,438,394

1,344

7,404

5,968

(141) $

14,575

6,586,875

387

1,597

(989)

(4)

1,597

(989)

403

544,025,269

1,360

7,803

6,572

(123) $

15,612

5,552,749

345

1,736

(1,066)

(3)

1,736

(1,066)

359

549,578,018

1,374

8,155

7,239

(93) $

16,675

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

General — Xcel Energy Inc.’s utility subsidiaries are engaged in the
regulated generation, purchase, transmission, distribution and sale of
electricity and 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

Venture Holdings

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 Market 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

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.

Xcel Energy has evaluated events occurring after Dec. 31, 2022 up to the
date of issuance of these consolidated financial statements. These
statements contain all necessary adjustments and disclosures resulting
from that evaluation.

Use of Estimates — Xcel Energy uses estimates based on the best
information available in recording transactions and balances resulting from
business operations.

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 information available. 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 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.

Rates are utilized that are scheduled to be in effect when the temporary
differences are expected to reverse. The effect of a change in tax rates on
deferred tax assets and liabilities is recognized in the period that includes
the enactment date.

The effects of tax rate changes that are attributable to the utility
subsidiaries are generally subject to a normalization method of accounting.
Therefore, the revaluation of most of the utility subsidiaries’ net deferred
taxes upon a tax rate reduction results in the establishment of a net
regulatory liability, 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 the 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. Utility rate regulation has resulted in the recognition of regulatory
assets and liabilities related to income taxes.

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
(expense) income 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.

Property, Plant and Equipment and Depreciation
in Regulated
Operations — Property, plant and equipment is stated at original cost. The
cost of plant includes direct labor and materials, contracted work, overhead
costs and AFUDC. The cost of plant retired is charged to accumulated
depreciation and amortization. Amounts recovered in rates for future
removal costs are recorded as regulatory liabilities. Significant additions or
improvements extending asset lives are capitalized, while repairs and
maintenance costs are charged to expense as incurred. Maintenance and
replacement of items determined to be less than a unit of property are
charged to operating expenses as incurred.

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 3.7% for 2022, 3.5% for 2021 and 3.4% for 2020.

See Note 3 for further information.

AROs — Xcel Energy records AROs as a liability for the fair value of an
ARO to be recognized in the period incurred (if it 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 the payment of future decommissioning expenditures
in nuclear
for NSP-Minnesota’s nuclear
decommissioning fund and other assets on the consolidated balance
sheets.

facilities are

included

See Notes 10 and 12 for further information.

Benefit Plans and Other Postretirement Benefits — Xcel Energy
maintains pension and postretirement benefit plans for eligible employees.
Recognizing the cost of providing benefits and measuring the projected
benefit obligation of these plans requires management to make various
assumptions and estimates.

Certain unrecognized actuarial gains and losses and unrecognized prior
service costs or credits are deferred as regulatory assets and liabilities,
rather than recorded as other comprehensive income, based on regulatory
recovery mechanisms.

See Note 11 for further information.

Environmental Costs — Environmental costs are recorded when it is
probable Xcel Energy is liable for remediation costs and the 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.

Future costs of restoring sites are treated as a capitalized cost of plant
retirement. The depreciation expense levels recoverable in rates include a
provision for removal expenses. Removal costs recovered in rates before
the related costs are incurred are classified as a regulatory liability.

See Note 12 for further information.

Revenue from Contracts with Customers — Performance obligations
related to the sale of energy are satisfied as energy is delivered to
customers. Xcel Energy recognizes revenue that corresponds to the price
of the energy delivered to the customer. The measurement of energy sales
to customers is generally based on the reading of their meters, which
occurs systematically throughout the month. At the end of each month,
amounts of energy delivered to customers since the date of the last meter
reading are estimated, and
is
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 RTOs are also
recorded on a gross basis. Other revenues and charges settled/facilitated
through an RTO are recorded on a net basis in cost of sales.

See Note 6 for further information.

Cash and Cash Equivalents — Xcel Energy considers investments in
instruments with a remaining maturity of three months or less at the time of
purchase to be cash equivalents.

Accounts Receivable and Allowance for Bad Debts — Accounts
receivable are stated at the actual billed amount net of an allowance for
bad debts. Xcel Energy establishes an allowance
for uncollectible
receivables based on a policy that reflects its expected exposure to the
credit risk of customers.

As of Dec. 31, 2022 and 2021, the allowance for bad debts was $122
million and $106 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, 2022

Dec. 31, 2021

330

201

272

803

289

182

160

631

Fair Value Measurements — Xcel Energy presents cash equivalents,
interest
nuclear
commodity
decommissioning fund assets at estimated fair values in its consolidated
financial statements.

derivatives,

derivatives

rate

and

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
the pension and postretirement plan assets and nuclear
trading data and pricing models,
decommissioning
generally using the most observable inputs available, are utilized to
determine fair value for each security.

fund, published

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. Any derivative
instruments not qualifying for the normal purchases and normal sales
exception are recorded on the consolidated balance sheets at fair value as
derivative instruments. Classification of changes in fair value for those
derivative instruments is dependent on the designation of a qualifying
hedging relationship.

Changes in fair value of derivative instruments not designated in a
qualifying hedging relationship are reflected in current earnings or as a
regulatory asset or liability. Classification as a regulatory asset or liability is
based on commission approved regulatory recovery mechanisms.

Gains or losses on commodity trading transactions are recorded as a
component of electric operating revenues.

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.

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

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.

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.

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.

Cost of RECs that are utilized to support commodity trading activities are
recorded in a similar manner as the associated commodities and are on a
net basis in electric operating revenues in the consolidated statements of
income.

2. Accounting Pronouncements

As of Dec. 31, 2022, there was no material impact from the recent adoption
of new accounting pronouncements, nor expected material impact from
recently issued accounting pronouncements yet to be adopted, on Xcel
Energy’s consolidated financial statements.

3. Property, Plant and Equipment

Major classes of property, plant and equipment

(Millions of Dollars)

Dec. 31, 2022

Dec. 31, 2021

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

49,639

48,680

8,514

2,970

2,217

2,124

65,464

(17,502)

3,183

(2,892)

7,758

2,602

1,200

1,969

62,209

(17,060)

3,081

(2,773)

Property, plant and equipment, net

48,253

45,457

(a)

Amounts as of Dec. 31, 2021 include Sherco Units 1, 2 and 3 and A.S. King for NSP-

Minnesota; Comanche Unit 1 and 2 and Craig Units 1 and 2 for PSCo; and Tolk and

coal generation assets at Harrington pending facility gas conversion for SPS. Following

the June 2022 approval of PSCo’s revised resource plan settlement, amounts as of Dec.

31, 2022 include the addition of Comanche Unit 3, Hayden Units 1 and 2 and coal

generation assets at Pawnee pending facility gas conversion as well as the removal of

Comanche Unit 1 that was retired in 2022. Amounts are presented net of accumulated

depreciation.

Joint Ownership of Generation, Transmission and Gas Facilities

The utility subsidiaries’ jointly owned assets as of Dec. 31, 2022:

(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

623

180

818

Total NSP-Minnesota

(a)

1,686

(a)

Projects additionally include $4 million in CWIP.

59 %

468

115

124

715

(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)

177

166

343

37 %

(a)

Projects additionally include $1 million in CWIP.

(Millions of Dollars, Except 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)

Plant in
Service

Accumulated
Depreciation

Percent
Owned

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.

157
151
42
82
39
918
28

186

25
8

1,636

99
81
29
51
24
174
3

76 %
37
53
10
7
67
82

Various

60
50

9
2

544

(a)

Projects additionally include $10 million in CWIP.

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

Net AROs

(b)

See Note(s)

Remaining Amortization
Period

Dec. 31, 2022

Dec. 31, 2021

(a)

Current

Noncurrent

Current

Noncurrent

Various

1, 12

Various

Deferred natural gas, electric, steam energy/fuel costs

One to five years

Recoverable deferred taxes on AFUDC

Excess deferred taxes — TCJA

Depreciation differences

Environmental remediation costs

Benson biomass PPA termination and asset purchase

PI extended power uprate
Conservation programs (c)
Purchased power contract costs

State commission adjustments

Losses on reacquired debt
Contract valuation adjustments (d)
Grid modernization costs

Gas pipeline inspection and remediation costs

Nuclear refueling outage costs

Renewable resources and environmental initiatives

Texas revenue surcharges

Sales true-up and revenue decoupling

Other

Total regulatory assets

Plant lives

Various

One to 12 years

1, 12

Various

Six years

12 years

1 One to two years

Term of related contract

Plant lives

Term of related debt

1, 10

Term of related contract

Various

One to two years

1 One to two years

One to two years

Less than one year

One to two years

Various

—

581

—

1,069

339

299

292

205

193

—

504

—

170

118

944

(112)

543

289

219

173

1,059

2,871

1,106

2,738

(a)

(b)

(c)

(d)

Prior period amounts have been restated to conform with current year presentation.

Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.

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.

Components of regulatory liabilities:

(Millions of Dollars)

Regulatory Liabilities

Deferred income tax adjustments and TCJA refunds
Plant removal costs
Effects of regulation on employee benefit costs (c)
Renewable resources and environmental initiatives

(b)

Revenue decoupling

ITC deferrals

Formula rates

(d)

Contract valuation adjustments
Deferred natural gas, electric, steam energy/fuel costs
Conservation programs (e)
DOE settlement

Other
Total regulatory liabilities (f)

See Note(s)

Remaining Amortization
Period

Dec. 31, 2022

Dec. 31, 2021

(a)

Current

Noncurrent

Current

Noncurrent

Various

1, 12

Various

One to two years

Various

One to two years

1, 10 One to two years

Less than one year

Various

—

175

3,110

1,819

247

173

—

3,230

1,655

235

101

—

418

5,569

271

5,405

(a)

(b)

(c)

(d)

(e)

(f)

Prior period amounts have been restated to conform with current year presentation.

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 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 $67 million and $17 million for 2022 and 2021, respectively, is included in other current liabilities.

Xcel Energy’s regulatory assets not earning a return include the unfunded portion of pension and retiree medical obligations and net AROs (i.e. deferrals for
which cash has not been disbursed). In addition, regulatory assets included $1,020 million and $1,718 million at Dec. 31, 2022 and 2021 respectively, of
past expenditures not earning a return. Amounts are predominately related 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.

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,
2022

Year Ended Dec. 31

2022

2021

2020

Borrowing limit

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

813

416

813

552

1,357

1,005

1,399

2,054

584

1,126

2,080

4.20 %

1.47 %

0.57 %

1.45 %

4.66

0.31

0.23

Bilateral Credit Agreement —
In April 2022, 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, 2022, NSP-Minnesota had $54 million outstanding letters of
credit under the $75 million Bilateral Credit Agreement.

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.

Amended 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 was increased to $3.55 billion. The amended
credit agreements have substantially the same terms and conditions as the
prior agreements, with the following changes:

•
•

•

Maturities extended from June 2024 to September 2027.
Borrowing limit for Xcel Energy Inc. increased from $1.25 billion to
$1.5 billion.
Borrowing limit for NSP-Minnesota increased from $500 million to
$700 million.

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, 2022 and 2021, there were $43 million and $19
million of letters of credit outstanding under the credit facilities, respectively.
Amounts approximate their fair value.

financial guarantees

Features of the credit facilities:

Debt-to-Total

Capitalization Ratio

(a)

Amount
Facility May Be
Increased
(millions of
dollars)

Additional Periods
for Which a One-
Year Extension May
Be Requested (b)

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

2022

2021

(c)

Xcel Energy Inc.
NSP-Minnesota

NSP-Wisconsin

SPS

PSCo

2022

2021

60 %

60 % $

350

150

N/A

100

(a)

(b)

(c)

Each credit facility has a financial covenant requiring that the debt-to-total capitalization
ratio be less than or equal to 65%.
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, 2022, 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, 2022:

Unsecured senior notes

Unsecured senior notes
Unsecured senior notes (a)
Unsecured senior notes

Unsecured senior notes

Unsecured senior notes
Unsecured senior notes (a)
(b)
Unsecured senior notes

Unsecured senior notes

Unamortized discount

Unamortized debt issuance cost

Current maturities

Total long-term debt
(a)

2021 financing.

(b)

2022 financing.

0.50

3.30

3.35

1.75

4.00

2.60

3.40

2.35

4.60

6.50

4.80

3.50

Oct. 15, 2023

June 1, 2025

Dec. 1, 2026

March 15,2027

June 15, 2028

Dec. 1, 2029

June 1, 2030

Nov. 15, 2031

June 1, 2032

July 1, 2036

Sep. 15, 2041

Dec. 1, 2049

500

250

350

500

130

500

600

300

700

300

250

500

(7)

(35)

(500)

500

250

350

500

130

500

600

300

—

300

250

500

(8)

(33)

—

5,338

5,139

Drawn (b)

Available

NSP-Minnesota

(Millions of Dollars)
Xcel Energy Inc.
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin

Total

Credit Facility
$

(a)

1,500
700
700
500
150
3,550

231
321
222
36
47
857

1,269
379
478
464
103
2,693

(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, 2022 and 2021.

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.

Financing Instrument

Interest
Rate

Maturity Date

2022

2021

2.15 %

Aug. 15, 2022

—

2.60

7.125

6.50

2.25

5.25

6.25

6.20

5.35

4.85

3.40

May 15, 2023

July 1, 2025

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

2.90

2.60

3.20

4.50

Aug. 15, 2045

May 15, 2046

Sep. 15, 2047

March 1, 2050

June 1, 2051

April 1,2052

June 1, 2052

400

250

150

425

250

400

350

300

250

500

300

350

600

700

425

500

(45)

(66)

300

400

250

150

425

250

400

350

300

250

500

300

350

600

700

425

—

(44)

(62)

(400)

(300)

6,542

6,447

First mortgage bonds

(a)

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)

2021 financing.

(b)

2022 financing.

NSP-Wisconsin

Interest
Rate

3.30

6.375

3.70

3.75

4.20

3.05

2.82

4.86

Financing Instrument

First mortgage bonds

First mortgage bonds
First mortgage bonds (a)
First mortgage bonds (b)
Other long-term debt

Unamortized discount

Unamortized debt issuance cost

Total long-term debt
(a)

2021 financing.

(b)

2022 financing.

Maturity Date

2022

2021

Financing Instrument

June 15, 2024

Sept. 1, 2038

Oct. 1, 2042

Dec. 1, 2047

Sept. 1, 2048

May 1, 2051

Sept. 15, 2052

100

200

100

200

100

—

(3)

(11)

1,086

100

200

100

200

100

—

(4)

(10)

987

First mortgage bonds

Unsecured senior notes

First mortgage bonds

(a)

First mortgage bonds

(b)

Unamortized discount

SPS

Interest
Rate

Maturity Date

2022

2021

3.30 %

June 15, 2024

150

3.30

6.00

4.50

3.40

3.70

4.40

3.75

3.15

5.15

June 15, 2024

Oct. 1, 2033

Oct. 1, 2036

Aug. 15, 2041

Aug. 15, 2046

Aug. 15, 2047

Nov. 15, 2048

June 15, 2049

May 1, 2050

June 1, 2052

200

100

250

200

100

300

450

300

350

250

200

(10)

(29)

150

200

100

250

200

100

300

450

300

350

250

—

(9)

(28)

3,211

3,013

Financing Instrument

PSCo

Interest
Rate

Maturity Date

2022

2021

First mortgage bonds

First mortgage bonds
First mortgage bonds (a)
First mortgage bonds (b)
First mortgage bonds

First mortgage bonds

First mortgage bonds
First mortgage bonds (b)
Unamortized discount

Unamortized debt issuance cost

Current maturities

Total long-term debt
(a)

2021 financing.

(b)

2022 financing.

2.25 %

Sept. 15, 2022

—

2.50

2.90

3.70

1.90

March 15, 2023

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

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

250

350

375

750

300

350

300

250

500

250

300

250

400

350

400

550

375

400

(37)

(53)

(250)

300

250

350

375

750

—

350

300

250

500

250

300

250

400

350

400

550

375

—

(33)

(50)

(300)

6,610

6,167

Unamortized debt issuance cost

Total long-term debt
(a)

2020 financing re-opened in 2021.

(b)

2022 financing.

Other Subsidiaries

Interest
Rate

0.00% -
8.00%

Financing Instrument

Various Eloigne affordable
housing project notes

Current maturities

Total long-term debt

Maturity Date

2022

2021

2024 - 2055

(1)

Maturities of long-term debt:

(Millions of Dollars)

2023

2024

2025

2026

2027

1,151

552

1,103

501

Deferred Financing Costs — Deferred financing costs of approximately
$193 million and $184 million, net of amortization, are presented as a
deduction from the carrying amount of long-term debt as of Dec. 31, 2022
and 2021, respectively.

Equity through DRIP and Benefits Program — Xcel Energy issued
$84 million and $74 million of equity through the DRIP and benefits
programs in 2022 and 2021, respectively. 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 2022, 4.30
million shares of common stock were issued (approximately $300 million).
As of Dec. 31, 2022, approximately $150 million remained available for sale
under the ATM program.

Capital Stock — Preferred stock authorized/outstanding:

6. Revenues

Preferred Stock
Authorized
(Shares)

Par Value of
Preferred Stock

Preferred Stock
Outstanding (Shares)
2022 and 2021

Xcel Energy Inc.

7,000,000

PSCo

SPS

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, 2022

Common Stock
Outstanding
(Shares) as of
Dec. 31, 2021

1,000,000,000

2.50

549,578,018

544,025,269

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, 2022:

Equity to Total
Capitalization Ratio
Required Range

Equity to Total
Capitalization Ratio
Actual

Low

High

2022

47.2 %

52.5

45.0

57.6 %

N/A

55.0

52.3 %

52.8

54.3

NSP-Minnesota

NSP-Wisconsin
SPS (a)

(a)

Excludes short-term debt.

(Amounts in
Millions)

NSP-Minnesota
NSP-Wisconsin (a)
SPS (b)

540

2,280

7,094

N/A

(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.
May not pay a dividend that would cause a loss of its investment grade bond rating.

Issuance of securities by Xcel Energy Inc. is not generally subject to
regulatory approval. However, utility financings and intra-system financings
are subject to the jurisdiction of state regulatory commissions and/or the
FERC. Xcel Energy may seek additional authorization as necessary.

Amounts authorized to issue as of Dec. 31, 2022:

(Millions of Dollars)

Long-Term Debt

Short-Term Debt

NSP-Minnesota

NSP-Wisconsin

SPS

PSCo
(a)

52.8% of total
capitalization

(a)

—

1,300

(a)

2,400

150

600

800

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.

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, 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

11,623

500

998

—

2,812

—

178

2,990

—

5,409

6,837

158

12,404

1,354

675

275

14,708

602

Total revenues

$ 12,123

3,080

107

$ 15,310

(Millions of Dollars)

Major revenue types

Year Ended Dec. 31, 2021

Electric

Natural
Gas

All Other

Total

Revenue from contracts with customers:

Residential

C&I

Other

Total retail

Wholesale

Transmission

Other

3,194

1,222

5,050

127

8,371

1,540

604

10,576

629

640

—

1,862

—

148

2,010

122

—

4,461

5,720

134

10,315

1,540

604

209

12,668

763

$ 13,431

(Millions of Dollars)

Major revenue types

Year Ended Dec. 31, 2020

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

3,066

975

4,596

125

7,787

759

579

9,198

604

462

—

1,437

—

137

1,574

Total revenues

9,802

1,636

—

4,083

5,085

131

9,299

759

579

210

10,847

679

$ 11,526

Unrestricted Retained
Earnings

Total
Capitalization

Limit on Total
Capitalization

Total revenue from
contracts with customers

Alternative revenue and other

1,446

14,984

16,140

Total revenues

$ 11,205

2,132

Income Taxes

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

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

2022

21.0 %

2021 (a)
21.0 %

(a)

2020

21.0 %

State income tax on pretax income, net of federal tax
effect

4.9

5.0

4.9

(Millions of Dollars)

Deferred tax liabilities:

2022

(a)

2021

Differences between book and tax bases of property

$ 6,442

$ 6,231

Regulatory assets

Operating lease assets

Deferred fuel costs

Pension expense

Other

508

325

222

159

560

351

262

175

Total deferred tax liabilities

$ 7,748

$ 7,667

(Decreases) increases in tax from:

Wind PTCs

(b)

Plant regulatory differences

(c)

Other tax credits, net NOL & tax credit allowances

NOL Carryback

Other, net

Effective income tax rate
(a)

(27.4)

(23.4)

(15.7)

Deferred tax assets:

(5.5)

(1.3)

—

(0.1)

(6.2)

(1.1)

—

0.1

(7.6)

(1.2)

(0.9)

(8.4) %

(4.6) %

(0.4) %

Tax credit carryforward

Regulatory liabilities

Operating lease liabilities

Other employee benefits

NOL carryforward

Prior period amounts have been restated to conform with current year presentation.

NOL and tax credit valuation allowances

(b)

(c)

Wind PTCs are credited to customers (reduction to revenue) and do not materially

Deferred ITCs

impact net income.

Other

Regulatory differences for income tax primarily relate to the credit of excess deferred

Total deferred tax assets

taxes to customers through the average rate assumption method. Income tax benefits

associated with the credit of excess deferred taxes are offset by corresponding revenue

reductions and additional prepaid pension asset amortization.

Components of income tax expense for years ended Dec. 31:

(Millions of Dollars)

Current federal tax expense (benefit)

Current state tax expense (benefit)

Current change in unrecognized tax expense

Deferred federal tax benefit

Deferred state tax expense

Deferred change in unrecognized tax expense (benefit)

Deferred ITCs

Total income tax benefit

2022

2021

2020

(13)

(2)

(239)

(183)

(4)

(5)

(135) $

(70) $

(89)

(10)

(5)

(6)

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

Net deferred tax liability
(a)

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

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)

State tax credit carryforwards are net of federal detriment of $23 million and $24 million

as of Dec. 31, 2022 and 2021.

(Millions of Dollars)

2022

2021

2020

(b)

Valuation allowances for state tax credit carryforwards were net of federal benefit of

Deferred tax (benefit) expense excluding items below

(138) $

148

237

$16 million and $17 million as of Dec. 31, 2022 and 2021.

Amortization and adjustments to deferred income taxes
on income tax regulatory assets and liabilities

Tax (benefit) expense allocated to other comprehensive
income and other

Deferred tax benefit

(221)

(247)

(10)

(6)

(140) $

(79) $

(8)

Federal carryforward periods expire starting 2032 and state carryforward
periods expire starting 2022.

Federal Loss Carryback Claims - In 2020, Xcel Energy identified certain
expense related to tax years 2009 - 2011 that qualify for an extended
carryback claim. As a result, a tax benefit of approximately $13 million was
recognized in 2020.

Unrecognized Tax Benefits

Federal Audit — Statute of limitations applicable to Xcel Energy’s
consolidated federal income tax returns expire as follows:

Expiration

March 2024

October 2023

Tax Year(s)

2014 - 2016

2019

$ 1,679

$ 1,261

742

325

102

(62)

135

742

351

119

247

(64)

102

$ 2,992

$ 2,773

$ 4,756

$ 4,894

2022

2021

765

1,593

1,022

(3)

1,172

1,648

(3)

(62)

(64)

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. Xcel Energy has
recognized its best estimate of income tax expense that will result from a
final resolution of this issue; however, the outcome and timing of a
resolution is unknown.

State Audits — 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, 2022, Xcel Energy’s earliest open tax years (subject to
examination by state taxing authorities in its major operating jurisdictions)
were as follows:

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

(Millions of Dollars)

Dec. 31, 2022

Dec. 31, 2021

NOL and tax credit carryforwards

(40) $

(36)

As the IRS progresses its review of the tax loss carryback claims and as
state audits progress, it is reasonably possible that the amount of
unrecognized tax benefit could decrease up to approximately $40 million in
the next 12 months.

Payable for interest related to unrecognized tax benefits is partially offset
by the interest benefit associated with NOL and tax credit carryforwards.

Interest payable related to unrecognized tax benefits:

State

Tax Year(s)

Expiration

(Millions of Dollars)

2022

2021

2020

Colorado

Minnesota

Texas
Texas

Texas

Wisconsin

2014 - 2016

2018

2014 - 2016

2018

2016
2017

2018

2016 - 2017

2018

March 2025

September 2023

September 2024

June 2023

May 2023
July 2025

November 2023

April 2023

October 2023

•

In 2020, Minnesota began an audit of tax years 2015-2018. In 2022,
the state of Minnesota issued its audit report without any material
adjustments.
In 2021, Texas began an audit of tax years 2016-2019. As of Dec. 31,
2022, no material adjustments have been proposed.
In 2021, Wisconsin began an audit of tax years 2016-2019. As of Dec.
31, 2022, no material adjustments have been proposed.
No other state income tax audits are in progress for its major operating
jurisdictions as of Dec. 31, 2022.

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, 2022

Dec. 31, 2021

Unrecognized tax benefit — Permanent tax positions

Unrecognized tax benefit — Temporary tax positions

Total unrecognized tax benefit

Changes in unrecognized tax benefits:

(Millions of Dollars)

Balance at Jan. 1

Additions based on tax positions related to the current year

Reductions 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

2022

2021

2020

$ 58

$ 52

$ 44

—

(1)

(2)

—

(1)

—

(2)

(34)

—

Balance at Dec. 31

$ 67

$ 58

$ 52

Payable for interest related to unrecognized
tax benefits at Jan. 1

Interest expense related to unrecognized tax
benefits

Payable for interest related to unrecognized
tax benefits at Dec. 31

(3) $

(1)

—

(4) $

(3) $

—

(3)

No penalties were accrued related to unrecognized tax benefits as of Dec.
31, 2022, 2021 or 2020.

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.
A total of 0.2 million time-based equity shares subject only to service
conditions were granted annually in 2022, 2021 and 2020.

The performance conditions for a portion of the awards granted from 2020
to 2022 are based on relative TSR and environmental goals. Equity awards
with performance conditions will be settled or forfeited after three years,
with payouts ranging from zero to 200% depending on achievement.

Equity award units granted to employees:

(Units in Thousands)

2022

2021

2020

Granted units

395

421

411

Weighted average grant date
fair value

Equity awards vested:

(Units in Thousands, Fair
Value in Millions)

68.43

66.03

62.92

2022

2021

2020

Vested Units

Total Fair Value

319

392

442

Changes in the nonvested portion of equity award units:

(Units in Thousands)

Units

Nonvested Units at Jan. 1, 2022

695

Granted

Forfeited

Vested

Dividend equivalents

Nonvested Units at Dec. 31, 2022

395

(96)

(319)

708

Weighted Average
Grant Date Fair Value

64.59

68.43

65.53

63.03

65.40

67.35

Stock Equivalent Units — Non-employee members of Xcel Energy‘s
Board of Directors may elect to receive their annual equity grant as stock
equivalent units in lieu of common stock. Each unit’s value is equal to one
share of common stock. The annual equity grant is vested as of the date of
each member’s election to the Board of Directors; there is no further
service or other condition. Directors may also elect to receive their cash
fees as stock equivalent units in lieu of cash. Stock equivalent units are
payable as a distribution of common stock upon a director’s termination of
service.

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 shares
on the date the award is settled.

Compensation costs related to share-based awards:

(Millions of Dollars)
Cost for share-based awards (a)
Tax benefit recognized in income
(a)

2022

2021

2020

Compensation costs for share-based payments are included in O&M expense. Amount

for equity awards (non-cash) amounted to $20 million in 2022.

There was approximately $37 million and $28 million as of Dec. 31, 2022
and 2021, 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 1.8
years.

Stock equivalent units granted:

9. Earnings Per Share

(Units in Thousands)

2022

2021

2020

Granted units

Weighted average grant date
fair value

71.97

68.15

61.61

Changes in stock equivalent units:

(Units in Thousands)

Units

Stock equivalent units at Jan. 1, 2022

604

Granted

Units distributed

Dividend equivalents

Stock equivalent units at Dec. 31, 2022

(52)

597

Weighted Average
Grant Date Fair Value

39.27

71.97

38.16

67.79

41.75

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)

2022

2021

2020

165

221

212

2022

2021

2020

Awards settled

411

446

Settlement amount (cash, common stock
and deferred amounts)

476

TSR liability awards of $21 million were settled in cash in 2022.

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.

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
time-based equity
commitments
compensation awards.

issue common stock related

Stock equivalent units granted to Xcel Energy’s Board of Directors are
included in common shares outstanding upon grant date as there is no
further service, performance or market condition associated with these.
Restricted stock issued to employees under the Executive Annual Incentive
Award Plan is included in common shares outstanding when granted.

Share-based compensation arrangements for which there is currently no
dilutive impact to EPS include the following:

•

Equity awards subject to a performance condition; included in
common shares outstanding when all necessary conditions for
settlement have been satisfied by the end of the reporting period.
Liability awards subject to a performance condition; any portions
settled in shares are included in common shares outstanding upon
settlement.

Common shares outstanding used
computation:

the basic and diluted EPS

(Shares in Millions)

2022

2021

2020

Basic

(a)

Diluted

547

539

540

527

528

(a)

Diluted common shares outstanding included common stock equivalents of 0.3 million,

0.3 million and 1.1 million shares for 2022, 2021 and 2020, respectively.

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
at
real estate
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.

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 billion and
$1.3 billion as of Dec. 31, 2022 and 2021, respectively, and unrealized
losses were $90 million and $7 million as of Dec. 31, 2022 and 2021,
respectively.

Non-derivative instruments with recurring fair value measurements in the
nuclear decommissioning fund:

Dec. 31, 2022

Fair Value

(Millions of Dollars)
Nuclear decommissioning fund (a)

Cost

Level 1

Level 2

Level 3

NAV

Total

Cash equivalents

Commingled funds

Debt securities

Equity securities

803

738

406

—

999

$ —

—

669

—

1,178

—

1,178

675

1,000

Total

$ 1,976

$ 1,028

670

$ 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 method investments and

$133 million of rabbi trust assets and other miscellaneous investments.

Dec. 31, 2021

Fair Value

(Millions of Dollars)
Nuclear decommissioning fund (a)

Cost

Level 1

Level 2

Level 3

NAV

Total

Cash equivalents

Commingled funds

Debt securities

Equity securities

856

631

411

—

1,222

$ —

—

666

—

1,294

—

1,294

675

1,223

Total

$ 1,962

$ 1,286

667

$ 1,294

$ 3,256

Reported in nuclear decommissioning fund and other investments on the consolidated

balance sheets, which also

includes $208 million of equity

investments

unconsolidated subsidiaries and $164 million of rabbi

trust assets and other

miscellaneous investments.

(a)

For the years ended Dec. 31, 2022 and 2021, 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, 2022:

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

204

250

215

675

Rabbi Trusts

Xcel Energy has established rabbi trusts to provide partial funding for future
distributions of deferred compensation plan. The fair value of assets held in
the rabbi trusts were $80 million and $109 million at Dec. 31, 2022 and
2021, 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, 2022, 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, 2022, Xcel Energy had
unsettled interest swaps outstanding with a notional amount of $40 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.

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 December 31, 2022
and 2021 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, 2022, 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, 2022

Dec. 31, 2021

131

156

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, 2022, four of Xcel Energy’s ten most significant
counterparties for these activities, comprising $75 million or 37% of this
credit exposure, had investment grade credit ratings from S&P Global
Ratings, Moody’s Investor Services or Fitch Ratings.

Four of the ten most significant counterparties, comprising $63 million or
32% 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.

Two of these significant counterparties, comprising $62 million or 31% of
this credit exposure, had credit quality less than investment grade, based
on internal analysis. Six of these significant counterparties are municipal or
cooperative electric entities, RTOs or other utilities.

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

(Millions of Dollars)

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

—

Year Ended Dec. 31, 2020

Derivatives designated as cash flow hedges

Interest rate

Total

Other derivative instruments

Commodity trading

Electric commodity

Natural gas commodity

Total

—

(a)

—

(23)

(18)

—

(3)

(c)

(d)

(c)

(d)

(c)

(d)

—

(27)

(2)

—

(22)

—

(1)

—

(13)

(14)

(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 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, 2022, 2021 and 2020.

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, 2022 and 2021, there were $4 million and $3 million,
respectively, of derivative
liabilities with such underlying contract
provisions, respectively.

Certain contracts also contain cross default provisions that may require the
posting of collateral or settlement of the contracts if there was a failure
under other financing arrangements related to payment terms or other
covenants.

As of Dec. 31, 2022 and 2021, there were approximately $76 million and
$64 million of derivative liabilities with such underlying contract provisions,
respectively.

Certain derivative instruments are also subject to contract provisions that
clauses. These provisions allow
contain adequate assurance
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, 2022 and 2021.

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, 2022

Derivatives designated as cash flow hedges

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

Year Ended Dec. 31, 2020

Interest rate

Total

Other derivative instruments

Electric commodity

Natural gas commodity

Total

—

(13)

—

(10)

(16)

(26)

—

(4)

—

(5)

(13)

(18)

(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, 2022

Dec. 31, 2021

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

$ 32

$ 259

$ 33

324

(242) $

$ 22

$ 137

$ 21

180

(134) $

—

177

—

177

(2)

—

175

—

(1)

—

Total current derivative assets

$ 32

$ 278

$ 210

520

(244)

276

$ 22

$ 155

$ 78

255

(135)

PPAs (b)

Current derivative instruments

Noncurrent derivative assets

Other derivative instruments:

279

Commodity trading

$ 34

$ 71

$ 74

Total noncurrent derivative assets

$ 34

$ 71

$ 74

179

(89) $

(89)

PPAs (b)

Noncurrent derivative instruments

$ 16

$ 63

$ 89

$ 16

$ 63

$ 89

168

(107) $

(107)

Dec. 31, 2022

Dec. 31, 2021

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

$ —

—

$ —

—

$ 29

$ 297

—

332

(287) $

(2)

—

Total current derivative liabilities

$ 29

$ 311

348

(289)

PPAs (b)

Current derivative instruments

Noncurrent derivative liabilities

Other derivative instruments:

Commodity trading

$ 43

$ 97

$ 41

Total noncurrent derivative liabilities

$ 43

$ 97

$ 41

181

(98) $

(98)

PPAs (b)

$ 19

$ 148

$ 20

187

(143) $

—

(1)

—

$ 19

$ 156

$ 21

196

(144)

$ 18

$ 48

$ 127

$ 18

$ 48

$ 127

193

(128) $

(128)

—

Noncurrent derivative instruments

113

105

(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, 2022 and

2021, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2022 and 2021, derivative assets and liabilities include rights to reclaim cash collateral of

$53 million and $30 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.

120

123

—

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, 2022 and
2021 were $11 million and $43 million, respectively. Xcel Energy
recognized net benefit cost for the SERP and nonqualified plans of $17
million in 2022 and $4 million in 2021.

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 2022 were below the assumed level of 6.49%.
Investment returns in 2021 were above the assumed level of 6.49%.
Investment returns in 2020 were above the assumed level of 6.87%.
In 2023, 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 costs for Texas
and New Mexico amounts collected in rates. PSCo is required to fund
postretirement benefit costs in irrevocable external trusts that are dedicated
to the payment of these postretirement benefits. These assets are invested
in a manner consistent with the investment strategy for the pension plan.

Xcel Energy’s ongoing investment strategy is based on plan-specific
investment recommendations that seek to minimize potential investment
and interest rate risk as a plan’s funded status increases over time.

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

Changes in Level 3 commodity derivatives:

(Millions of Dollars)

Balance at Jan. 1

Purchases

(a)

Settlements

(a)

Net transactions recorded during the period:
Gains (losses) recognized in earnings (b)
Net gains recognized as regulatory assets and
liabilities

(a)

Balance at Dec. 31
(a)

Year Ended Dec. 31

2022

2021

2020

(49) $

406

(350)

(158)

(73)

151

(39)

112

236

(49)

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

2022

2021

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value

23,964

$ 20,897

22,380

$ 25,232

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, 2022 and 2021, 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 4.89, 2.03
and 1.89% in 2022, 2021, and 2020, 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.

Plan Assets

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

Dec. 31, 2022 (a)

Dec. 31, 2021 (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

129

935

—

682

—

129

133

882

—

1,817

685

1,324

—

959

—

1,143

—

133

2,467

964

1,111

689

882

2,685

1,524

966

1,175

3,670

(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, 2022 (a)

Dec. 31, 2021

(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

—

175

(1)

—

215

—

117

176

(1)

364

—

218

—

272

—

141

219

442

(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 2022. No assets were transferred in or out of Level 3 for 2021.

Funded Status — Benefit obligations for both pension and postretirement plans decreased from Dec. 31, 2021 to Dec. 31, 2022, due primarily to benefit
payments and increases in discount rates used in actuarial valuations. Comparisons of the actuarially computed benefit obligation, changes in plan assets
and funded status of the pension and postretirement health care plans for Xcel Energy are as follows:

(Millions of Dollars)

Change in Benefit Obligation:

Obligation at Jan. 1

Service cost

Interest cost

Plan amendments

Actuarial gain

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

2022

2021

2022

2021

3,718

3,964

511

110

(703)

—

(352)

104

(94)

—

(365)

—

(85)

(48)

2,871

3,718

405

3,670

3,599

442

(683)

—

(352)

2,685

(186) $

—

(201)

(186) $

305

131

—

(365)

3,670

(48) $

—

(67)

(48) $

(51)

(48)

364

(41) $

(2)

(72)

(41) $

574

—

(41)

(49)

511

452

(49)

442

(69)

(4)

(98)

(69)

(a)

Includes approximately $195 million in 2022 and $197 million in 2021 of lump-sum benefit payments used in the determination of a settlement charge.

Significant Assumptions Used to Measure Benefit Obligations:

2022

2021

2022

2021

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

5.80 %

4.25

PRI-2012

N/A

3.08 %

3.75

PRI-2012

N/A

5.80 %

N/A

PRI-2012

6.50 %

5.50 %

4.50 %

3.09 %

N/A

PRI-2012

5.30 %

4.90 %

4.50 %

Accumulated benefit obligation for the pension plan was $2,672 million and $3,469 million as of Dec. 31, 2022 and 2021, 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

2022

2021

2020

2022

2021

2020

110

(208)

(1)

144

(30)

114

3.08 %

3.75

6.49

104

(206)

(1)

107

167

(46)

121

2.71 %

3.75

6.49

125

(208)

(4)

100

—

108

117

(18)

(6)

—

(5)

(2)

(18)

(8)

—

(4)

(2)

(19)

(8)

—

(4)

(1)

3.49 %

3.75

6.87

3.09 %

—

4.10

2.65 %

—

4.10

3.47 %

—

4.50

(a)

A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic

pension cost. In 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. There were no settlement charges recorded for the qualified pension plans in 2020.

(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

2022

2021

2022

2021

1,021

(7)

1,014

978

(9)

969

943

—

846

—

(1)

—

(1)

(20)

1,014

969

(7)

—

(1)

(19)

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2022

Dec. 31, 2021

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 2020 - 2023 to meet minimum funding
requirements.

Voluntary and required pension funding contributions:

•
•
•
•

$50 million in January 2023.
$50 million in 2022.
$131 million in 2021.
$150 million in 2020.

The postretirement health care plans have no funding requirements other
than fulfilling benefit payment obligations when claims are presented and
approved. Additional cash funding requirements are prescribed by certain
state and federal rate regulatory authorities.

Voluntary postretirement funding contributions:

•
•
•
•

$12 million expected during 2023.
$13 million during 2022.
$15 million during 2021.
$11 million during 2020.

Targeted asset allocations:

Domestic and international equity
securities

Long-duration fixed income securities
Short-to-intermediate fixed income
securities

Alternative investments

Cash

Total

Pension Benefits

Postretirement
Benefits

2022

2021

2022

2021

33 %

16 %

15 %

—

100 %

The asset allocations above reflect target allocations approved in the
calendar year to take effect in the subsequent year.

Plan Amendments — There were no significant plan amendments made
in 2022 or 2020 which affected the postretirement benefit obligation.

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

Projected Benefit Payments

Xcel Energy’s projected benefit payments:

Projected
Pension
Benefit
Payments
283
$

Gross Projected
Postretirement
Health Care
Benefit Payments
42
$

249

246
243

1,162

39
37

167

Expected
Medicare Part
D
Subsidies

Net Projected
Postretirement
Health Care
Benefit
Payments

2
2

37
35

155

(Millions of
Dollars)
2023

2024

2025

2026
2027

2028 - 2032

Defined Contribution Plans

Xcel Energy maintains 401(k) and other defined contribution plans that
cover most employees. Total expense to these plans was approximately
$46 million in 2022, $43 million in 2021 and $42 million in 2020.

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 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

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 on June 30, 2022 granting plaintiffs’ class certification.
Defendants will work together to prepare and file a petition appealing the
class certification ruling to the Seventh Circuit. Xcel Energy has concluded
that a loss is remote for the remaining lawsuit.

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 January 2022, the Court granted PSCo’s motion to dismiss
CORE’s claims for unjust enrichment, declaratory judgment and damages
for replacement power costs. In April 2022, CORE filed a supplement to
include the January 2022 outage and damages related to this event. Also in
2022, CORE sent notice of withdrawal from the ownership agreement
based on the same alleged breaches. In February 2023, CORE disclosed
its expert witness, who estimated damages incurred of $270 million. Also in
February 2023, the court granted PSCo’s motion precluding CORE from
seeking damages related to its withdrawal as part of the lawsuit. PSCo
continues to believe CORE's claims are without merit and disputes CORE’s
right to withdraw.

Rate Matters and Other

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 Southern Minnesota Municipal
Power Agency (Co-owner of Sherco Unit 3) reached a settlement with GE
related to a 2011 incident, which damaged the turbine at Sherco Unit 3 and
resulted in an extended outage for repair. NSP-Minnesota notified the
MPUC of its proposal to refund settlement proceeds to customers through
the fuel clause adjustment.

In March 2019, the MPUC approved NSP-Minnesota’s settlement refund
proposal. Additionally, the MPUC decided to withhold any decision as to
NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3
until after conclusion of an appeal pending between GE and NSP-
Minnesota’s insurers.

In February 2020, the Minnesota Court of Appeals affirmed the district
court’s judgment in favor of GE. In March 2020, NSP-Minnesota’s insurers
filed a petition seeking additional review by the Minnesota Supreme Court.
In April 2020, the Minnesota Supreme Court denied the insurers’ petition for
further review, ending the litigation.

In January 2021, the Minnesota Office of the Attorney General and DOC
recommended that NSP-Minnesota refund approximately $17 million of
replacement power costs previously recovered through the fuel clause
adjustment. NSP-Minnesota subsequently filed its response, asserting that
it acted prudently in connection with the Sherco Unit 3 outage, the MPUC
has previously disallowed $22 million of related costs and no additional
refund or disallowance is appropriate.

A final decision by the MPUC is expected in mid-2024. A loss related to this
matter is deemed remote.

MISO ROE Complaints — In November 2013 and February 2015,
customer groups filed two ROE complaints against MISO TOs, which
first complaint
includes NSP-Minnesota and NSP-Wisconsin. The
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 (including Opinion
Nos. 569, 569A and 569B) 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.

SPP OATT Upgrade Costs — Costs of transmission upgrades may be
recovered from other SPP customers whose transmission service depends
on capacity enabled by the upgrade under the SPP OATT. SPP had not
been charging its customers for these upgrades, even though the SPP
OATT had allowed SPP to do so since 2008. In 2016, the FERC granted
SPP’s request to recover these previously unbilled charges and SPP
subsequently billed SPS approximately $13 million.

In 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting
SPP the right to recover previously unbilled charges was remanded to the
FERC. In 2019, the FERC reversed its 2016 decision and ordered SPP to
refund charges retroactively collected from its transmission customers,
including SPS, related to periods before September 2015. In 2020, SPP
and Oklahoma Gas & Electric separately filed petitions for review of the
FERC’s orders at the D.C. Circuit. In 2021, the D.C. Circuit issued a
decision denying these appeals and upholding the FERC’s orders. Refunds
received by SPS are expected to be given back to SPS customers through
future rates.

In 2017, SPS filed a separate related complaint asserting SPP assessed
upgrade charges to SPS in violation of the SPP OATT. In 2018, the FERC
issued an order denying the SPS complaint. SPS filed a request for
rehearing in 2018. The FERC subsequently issued a tolling order granting a
rehearing for further consideration. If SPS’ complaint results in additional
charges or refunds, SPS will seek to recover or refund the amount through
future SPS customer rates. In 2020, SPS filed a petition for review of the
FERC’s 2018 orders at the D.C. Circuit. In February 2022, FERC issued an
order rejecting SPS’ request for hearing. SPS has appealed that order.
That appeal has been combined with SPS’ prior appeal.

Wind Operating Commitments — PUCT and NMPRC orders related to
the Hale and Sagamore wind projects included certain operating and
savings minimums. In general, annual generation must exceed a net
capacity factor of 48%. If annual generation is below the guaranteed level,
SPS would be obligated to refund an amount equal to foregone PTCs and
fuel savings. Additionally, retail customer savings must exceed project
costs included in base rates over the first ten years of operations. SPS
would be required to refund excess costs, if any, after ten years of
operations. As of Dec. 31, 2022, the full-year net capacity factor exceeded
the guaranteed level, resulting in no refund liability for 2022.

Environmental

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

Site Remediation

Environmental Requirements — Air

Various federal and state environmental laws impose liability where
hazardous substances or other regulated materials have been released to
the environment. Xcel Energy Inc.’s subsidiaries may sometimes pay all or
a portion of the cost to remediate sites where past activities of their
predecessors or other parties have caused environmental contamination.

Environmental contingencies could arise from various situations, including
sites of former MGPs; and third-party sites, such as landfills, for which one
or more of Xcel Energy Inc.’s subsidiaries are alleged to have sent wastes
to that site.

Historical MGP, Landfill and Disposal Sites

Xcel Energy is currently investigating, remediating or performing post-
closure actions at 9 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 its best estimate of costs/liabilities from final
resolution of these issues; however, the outcome and timing are unknown.
In addition, there may be insurance recovery and/or recovery from other
potentially responsible parties, offsetting a portion of costs incurred.

Environmental Requirements — Water and Waste

Reasonable Progress Rule and BART — In 2016, the EPA adopted a final
rule establishing a federal implementation plan for reasonable further
progress under the regional haze program for the state of Texas. The rule
imposes SO2 emission limitations which would require the installation of dry
scrubbers on Tolk Units 1 and 2; compliance would have been required by
February 2021. SPS appealed the EPA’s decision and obtained a stay of
the final rule.

In 2017, the EPA adopted a final BART rule for Texas. Under that rule,
Harrington Units 1, 2, and 3 and Tolk Units 1 and 2 participate in intrastate
SO2 budget and trading program. The rule also implemented participation
in a federal ozone season NOx budget and trading program, named the
Cross State Air Pollution Rule. The EPA is reconsidering this rule.

AROs — AROs have been recorded for Xcel Energy’s assets. For nuclear
assets, the ARO is associated with the decommissioning of NSP-Minnesota
nuclear generating plants.

Aggregate fair value of NSP-Minnesota’s legally restricted assets, for
funding future nuclear decommissioning was $2.9 billion and $3.3 billion for
2022 and 2021, respectively.

Xcel Energy’s AROs were as follows:

Amounts
Incurred
(a)

Accretion

Cash Flow
Revisions
(b)

Jan. 1, 2022

2,056

478

288

271

—

104

—

148

—

(8)

—

(7)

—

Dec. 31, 2022

2,160

514

348

306

3,380

Transmission and
distribution

Miscellaneous

Common

Miscellaneous

Non-utility

Miscellaneous

Total liability

3,151

(a)

(b)

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.

Coal Ash Regulation — Xcel Energy’s operations are subject to federal and
state regulations that impose requirements for handling, storage, treatment
and disposal of solid waste. Under the CCR Rule, utilities are required to
complete groundwater sampling around their applicable landfills and
surface impoundments as well as perform corrective actions where offsite
groundwater has been impacted.

(Millions
of Dollars)

Electric

Nuclear

Wind

Steam, hydro and
other production

As of Dec. 31, 2022, Xcel Energy had eight regulated ash units in
operation.

Distribution

Natural gas

PSCo is currently exploring an agreement with a third party that would
excavate and process ash for beneficial use (at two sites) and perform
restoration at one site at a cost of approximately $45 million. An estimated
liability has been recorded and amounts are expected to be fully
recoverable through regulatory mechanisms.

Investigation and feasibility studies for additional corrective action related to
offsite groundwater are ongoing (three sites). While the results are
uncertain, additional costs are estimated to be up to $35 million. A liability
has been recorded for the portion estimable/probable and 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 $45 million may be
required for NSP-Minnesota to comply with the requirements pending
approval of mitigation plans from the MPCA. Xcel Energy anticipates these
costs will be recoverable through regulatory mechanisms.

(Millions
of Dollars)

Electric

Nuclear

Wind

Steam, hydro and
other production

Distribution

Natural gas

Transmission and
distribution

Miscellaneous

Common

Miscellaneous

Non-utility

Miscellaneous

Jan. 1,
2021

Amounts
Incurred
(a)

Accretion

Cash Flow
Revisions
(b)

Dec. 31,
2021

1,957

—

360

264

252

101

—

2,056

478

288

271

3,151

Total liability

2,884

107

138

(a)

(b)

Amounts incurred related to the wind farms placed in service in 2021 for NSP-Minnesota

(Blazing Star 2, Mower and Freeborn) and removal of a utility scale battery asset in

NSP-Minnesota.

In 2021, AROs were revised for changes in timing and estimates of cash flows.

Revisions in steam, hydro and other production AROs were primarily related to changes

in cost estimates for remediation of ash containment facilities. Changes in gas

transmission and distribution AROs were primarily related to changes in labor rates

coupled with increased gas line mileage and number of services.

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, 2022. Therefore, an ARO was
not recorded for these facilities.

Nuclear

Nuclear Insurance — NSP-Minnesota’s public liability for claims from any
nuclear incident is limited to $13.7 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 $13.2 billion of exposure is funded by the
Secondary Financial Protection Program available from assessments by
the federal government.

NSP-Minnesota is subject to assessments of up to $138 million per reactor-
incident for each of its three reactors, for public liability arising from a
nuclear incident at any licensed nuclear facility in the United States. The
maximum funding requirement is $20 million per reactor-incident during any
one year. Maximum assessments are subject to inflation adjustments.

insurance

for property damage and site
NSP-Minnesota purchases
decontamination cleanup costs from NEIL and EMANI. The coverage limits
are $2.8 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL
also provides business interruption insurance coverage up to $350 million,
including the cost of replacement power during prolonged accidental
outages of nuclear generating units. Premiums are expensed over the
policy term.

All companies insured with NEIL are subject to retroactive premium
adjustments if losses exceed accumulated reserve funds. Capital has been
accumulated in the reserve funds of NEIL and EMANI to the extent that
NSP-Minnesota would have no exposure
retroactive premium
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 $12
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. The PI dry-cask storage facility currently stores
50 of the 64 authorized casks. Monticello’s future spent fuel will continue to
be placed in its spent fuel pool. The decommissioning plan addresses the
disposition of spent fuel at the end of the licensed life. A CON for additional
storage at the Monticello site has been filed with the MPUC, to support
possible life extension to 2040. NSP-Minnesota expects a decision by year-
end 2023.

Regulatory Plant Decommissioning Recovery — Decommissioning
activities for NSP-Minnesota’s nuclear facilities are planned to begin at the
end of each unit’s 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.

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 2020 nuclear
decommissioning filing was approved by the MPUC and became effective
in 2022.

Obligations for decommissioning are expected to be funded 100% by the
external decommissioning trust fund. NSP-Minnesota had $2.9 billion and
$3.3 billion of assets held in external decommissioning trusts at Dec. 31,
2022, and 2021, 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 4.1%). Xcel
Energy has elected the practical expedient under which non-lease
components, such as asset maintenance costs included in payments, are
not deducted from minimum lease payments for the purposes of lease
accounting and disclosure.

Leases with an initial term of 12 months or less are classified as short-term
leases and are not recognized on the consolidated balance sheet.

Operating lease ROU assets:

(Millions of Dollars)

Dec. 31, 2022

Dec. 31, 2021

PPAs

Other

Gross operating lease ROU assets

Accumulated amortization

Net operating lease ROU assets

1,669 $

244

1,913

(709)

1,204 $

1,656

225

1,881

(590)

1,291

Commitments under operating and finance leases as of Dec. 31, 2022:
(a) (b)

(Millions of Dollars)
2023
2024
2025
2026
2027
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)

PPA
Operating
Leases

Other
Operating
Leases

Total
Operating
Leases

231
238
217
161
90
326
1,263
(170)

1,093

33
28
23
18
18
74
194
(32)

162

264
266
240
179
108
400
1,457
(202)

1,255

(217)

Finance
(c)
Leases
$

10
10
10
9
8
181
228
(162)

(2)

1,038

7.9

37.8

Amounts do not include PPAs accounted for as executory contracts and/or contingent

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.

(b)

(c)

payments, such as energy payments on renewable PPAs.

PPA operating leases contractually expire at various dates through 2033.

Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.

Xcel Energy’s most significant finance lease activities are related to WYCO,
a joint venture with CIG, to develop and lease natural gas pipeline, storage
and compression facilities. Xcel Energy Inc. has a 50% ownership interest
in WYCO. WYCO leases its facilities to CIG, and CIG operates the
facilities, providing natural gas storage and transportation services to PSCo
under separate service agreements.

PSCo accounts for its Totem natural gas storage service and Front Range
pipeline arrangements with CIG and WYCO, respectively, as finance
leases. Xcel Energy Inc. eliminates 50% of the finance lease obligation
related to WYCO in the consolidated balance sheet along with an equal
amount of Xcel Energy Inc.’s equity investment in WYCO.

Finance lease ROU assets:

(Millions of Dollars)
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

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

Dec. 31, 2022

Dec. 31, 2021

160
21
181
(64)
117

201
21
222
(97)
125

2022

2021

2020

241

251

280

287

4
16
20

7
17
24

238

264

7
18
25

(a)

(b)

Includes short-term lease expense of $6 million for 2022 and $5 million for 2021 and

2020.

PPA capacity payments are included in electric fuel and purchased power on the

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 capacity payments. Certain PPAs, accounted for as
executory contracts with various expiration dates through 2033, contain
minimum energy purchase commitments. Total energy payments on those
contracts were $182 million, $149 million and $112 million in 2022, 2021
and 2020, respectively.

Included in electric fuel and purchased power expenses for PPAs
accounted for as executory contracts were payments for capacity of $75
million, $69 million and $75 million in 2022, 2021 and 2020, 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, 2022, the estimated future payments for capacity and energy
that the utility subsidiaries of Xcel Energy are obligated to purchase
pursuant to these executory contracts, subject to availability, were as
follows:

(Millions of Dollars)
2023
2024
2025
2026
2027
Thereafter
Total

Capacity

Energy (a)

77
72
29
10
7
3
198

50
45
51
48
55
28
277

consolidated statements of income. Expense for other operating leases is included in

(a)

O&M expense and electric fuel and purchased power.

Excludes contingent energy payments for renewable energy PPAs.

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 $44 million of assets and $35 million of liabilities at
Dec. 31, 2022, and $45 million of assets and $35 million of liabilities at Dec.
31, 2021.

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 $181 million, $103 million and $110
million associated with these vendors in 2022, 2021 and 2020, respectively.

Committed minimum payments under these obligations as follows:

(Millions of Dollars)

2023

2024

2025

2026

2027

Thereafter

Minimum
Payments

—

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, 2022 and 2021, Xcel Energy Inc. and its subsidiaries had no
assets held as collateral related to their guarantees, bond indemnities and
indemnification agreements. Guarantees and bond indemnities issued and
outstanding for Xcel Energy were $62 million and $60 million at Dec. 31,
2022 and 2021 respectively.

Indemnification Agreements — Xcel Energy

Other
its
subsidiaries provide indemnifications through various contracts. These are
primarily indemnifications against adverse litigation outcomes in connection
with underwriting agreements, as well as breaches of representations and
warranties, including corporate existence, transaction authorization and
income tax matters with respect to assets sold.

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.

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 2023 and 2060. Xcel Energy is required to pay additional amounts
depending on actual quantities shipped under these agreements.

Estimated minimum purchases under these contracts as of Dec. 31, 2022:

Coal

Nuclear fuel

Natural gas
supply

Natural gas
supply and
transportation

628 $
343
90
53
55
2
1,171 $

144 $
112
158
37
155
194
800 $

684 $
8
1
—
—
—
693 $

316
290
276
276
225
607
1,990

(Millions of
Dollars)
2023
2024
2025
2026
2027
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 it is not subject to risk of loss from the operations of these entities,
and no significant financial support is required other than contractual
payments for energy and capacity.

In addition, certain solar PPAs provide an option to purchase emission
allowances or sharing provisions related to production credits generated by
the solar facility under contract. These specific PPAs create a variable
interest in the IPP.

Xcel Energy evaluated each of these VIEs for possible consolidation,
including review of qualitative factors such as the length and terms of the
contract, control over O&M, control over dispatch of electricity, historical
and estimated future fuel and electricity prices, and financing activities. Xcel
Energy concluded that these entities are not required to be consolidated in
its consolidated financial statements because it does not have the power to
direct the activities that most significantly impact the entities’ economic
performance.

The utility subsidiaries had approximately 3,961 MW and 4,062 MW of
capacity under these long-term PPAs at Dec. 31, 2022 and 2021,
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.

13. Other Comprehensive Income

14. Segment Information

Changes in accumulated other comprehensive loss, net of tax, for the years
ended Dec. 31:

Gains and
Losses on
Interest Rate
Cash Flow
Hedges

2022

Defined
Benefit
Pension and
Postretirement
Items

Total

(75)

(48)

$ (123)

—

(a)

(b)

—

(54)

(39)

(93)

(Millions of Dollars)

Accumulated other comprehensive
loss at Jan. 1

Other comprehensive gain before
reclassifications

Losses reclassified from net
accumulated other comprehensive
loss:

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.

(b)

Included in the computation of net periodic pension and postretirement benefit costs.

See Note 11 for further information.

Gains and
Losses on
Interest Rate
Cash Flow
Hedges

2021

Defined
Benefit
Pension and
Postretirement
Items

Total

(85)

(56)

$ (141)

—

(a)

—

(b)

(75)

(48)

$ (123)

(Millions of Dollars)

Accumulated other comprehensive
loss at Jan. 1

Other comprehensive gain before
reclassifications

Losses reclassified from net
accumulated other comprehensive
loss:

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.

(b)

Included in the computation of net periodic pension and postretirement benefit costs.
See Note 11 for further 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
of NSP-Minnesota,
NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility
operating results of NSP-Minnesota, NSP-Wisconsin and PSCo. These
segments are managed separately because the revenue streams are
dependent upon regulated rate recovery, which is separately determined
for each segment.

operating

results

Xcel Energy has the following reportable segments:

•

transmits and distributes electricity

regulated electric utility segment
Regulated Electric — The
generates,
in Minnesota,
Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas
and New Mexico. In addition, this segment includes sales for resale
and provides wholesale transmission service to various entities in the
United States. The regulated electric utility segment also includes
wholesale commodity and trading operations.
Regulated Natural Gas — The regulated natural gas utility segment
transports, stores and distributes natural gas primarily in portions of
Minnesota, Wisconsin, North Dakota, Michigan and Colorado.

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 refuse-derived fuel, investments in rental
housing projects that qualify for low-income housing tax credits and the
operations of MEC until July 2020.

Xcel Energy had equity method
investments of $219 million and
$208 million as of Dec. 31, 2022 and 2021, respectively, included in the
natural gas utility and all other segments.

Asset and capital expenditure information is not provided for Xcel Energy’s
reportable segments. As an integrated electric and natural gas utility, Xcel
Energy operates significant assets that are not dedicated to a specific
business segment.

Reporting assets and capital expenditures by business segment would
require arbitrary and potentially misleading allocations, which may not
necessarily reflect the assets that would be required for the operation of the
business segments on a stand-alone basis.

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

Xcel Energy’s segment information:

Internal Control Over Financial Reporting

(Millions of Dollars)

Regulated Electric

2022

2021

2020

Operating revenues — external

12,123

11,205

9,802

Intersegment revenue

Total revenues

Depreciation and amortization

Interest charges and financing costs

Income tax (benefit) expense

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) expense

Net income

12,125

11,207

2,122

636

(162)

1,631

1,855

568

(96)

1,478

9,804

1,673

534

1,407

3,080

2,132

1,636

3,082

2,134

1,637

276

264

107

203

(41)

(159)

254

231

173

(28)

(112)

252

190

193

(24)

(124)

No changes in Xcel Energy’s internal control over financial reporting
occurred during the most recent fiscal quarter ended Dec. 31, 2022 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, 2022 on internal controls under section 404 of the Sarbanes-Oxley
Act of 2002, Xcel Energy conducted testing and monitoring of its internal
control over financial reporting. Based on the control evaluation, testing and
remediation performed, Xcel Energy did not identify any material control
weaknesses, as defined under the standards and rules issued by the Public
Company Accounting Oversight Board, as approved by the SEC and as
indicated in Xcel Energy’s Management Report on Internal Controls over
Financial Reporting, which is contained in Item 8 herein.

ITEM 9B — OTHER INFORMATION

None.

ITEM 9C — DISCLOSURE REGARDING FOREIGN JURISDICTIONS
THAT PREVENT INSPECTIONS

Not applicable.

PART III

15,314

13,435

11,529

(4)

(3)

15,310

13,431

11,526

2,413

925

(135)

1,736

2,121

1,948

816

(70)

798

(6)

1,597

1,473

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 2023 Annual Meeting of Shareholders, which is expected to occur on
April 11, 2023, incorporated by reference. Information with respect to
Executive Officers is included in Item 1 to this report.

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

ITEM 11 — EXECUTIVE COMPENSATION

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, 2022, 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.

Information required under this Item is set forth in Xcel Energy Inc.’s Proxy
Statement
is
for
incorporated by reference.

its 2023 Annual Meeting of Shareholders, which

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 2023 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 2023 Annual Meeting of Shareholders, which is
incorporated by reference.

ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information required under this Item (aggregate fees billed to us by our principal accountant, Deloitte & Touche LLP (PCAOB ID No. 34)) is contained in Xcel
Energy Inc.’s Proxy Statement for its 2023 Annual Meeting of Shareholders, which is incorporated by reference.

PART IV

ITEM 15 — EXHIBIT AND FINANCIAL STATEMENT SCHEDULES

Consolidated Financial Statements

Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2022.

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, 2022, 2021, and 2020.

Consolidated Statements of Comprehensive Income — For each of the three years ended Dec. 31, 2022, 2021, and 2020.

Consolidated Statements of Cash Flows — For each of the three years ended Dec. 31, 2022, 2021, and 2020.

Consolidated Balance Sheets — As of Dec. 31, 2022 and 2021.

Consolidated Statements of Common Stockholders’ Equity — For each of the three years ended Dec. 31, 2022, 2021, and 2020.

Schedule I — Condensed Financial Information of Registrant.

Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2022, 2021, and 2020.

Exhibits

Indicates incorporation by reference

Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

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

Xcel Energy Inc.

Exhibit
Number Description
3.01*

Amended and Restated Articles of Incorporation of Xcel Energy Inc.

Bylaws of Xcel Energy Inc., as Amended on April 3, 2020

Description of Securities

3.02*

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*

4.10*

4.11*

4.12*

4.13*

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
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. 14, dated as of Sept. 25, 2020 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 0.50% Senior Notes, Series due Oct. 15, 2023
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

Report or Registration Statement
Xcel Energy Inc. Form 8-K dated May 16,
2012

Xcel Energy Inc. Form 8-K dated April 3, 2020

Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2019

Exhibit
Reference
3.01

3.01

4.01

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 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

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 Sept. 25,
2020

4.01

Xcel Energy Inc. Form 8-K dated Nov. 3, 2021 4.01

4.14*

10.01*

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
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. Executive Annual Incentive Plan (as amended and restated effective Feb. 17, 2010)

10.10*+

First Amendment to Exhibit 10.09 dated Feb. 20, 2013

10.11*+

Xcel Energy Inc. Executive Annual Incentive Award Plan Form of Restricted Stock Agreement

10.12*+

Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement)

10.13*+

First Amendment to Exhibit 10.12 effective Nov. 29, 2011

10.14*+

Second Amendment to Exhibit 10.12 dated May 21, 2013

10.15*+

Third Amendment to Exhibit 10.12 dated Sept. 30, 2016

10.16*+

Fourth Amendment to Exhibit 10.12 dated Oct. 23, 2017

10.17*+

Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan

Xcel Energy Form 8-K dated May 6, 2022

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

10.02

10.01

Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2008

10.17

Xcel Energy Inc. Definitive Proxy Statement
dated April 6, 2010

Appendix
A

Xcel Energy Inc. Form 10-Q for the quarter
ended March 31, 2013

Xcel Energy Inc. Form 10-Q for the quarter
ended Sept. 30, 2009

10.01

10.08

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

10.18*+

10.19*+

Form of Terms and Conditions under the Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan for
Awards of Restricted Stock Units and/or Performance Share Units

Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2018

10.35

Form of Award Agreement for Restricted Stock Units and/or Performance Share Units under the Xcel Energy Inc. 2015
Omnibus Incentive Plan for awards since 2020

Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2019

10.32

10.20*+

Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc. as amended and restated effective Feb. 23, 2011 Xcel Energy Inc. Definitive Proxy Statement

dated April 5, 2011

10.21*+

Stock Equivalent Program for Non-Employee Directors of Xcel Energy Inc. under the Xcel Energy Inc. 2015 Omnibus
Incentive Plan

Xcel Energy Inc. Form 8-K dated May 20,
2015

10.22*+

Summary of Non-Employee Director Compensation, effective as of Oct. 1, 2021

Xcel Energy Inc. Form 10-Q for the quarter
ended Sept. 30, 2021

Appendix
A

10.02

10.01

10.23*+

Stock Program for Non-Employee Directors of Xcel Energy Inc. as Amended and Restated on Dec. 12, 2017 under the
2015 Omnibus Incentive Plan

Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2018

10.36

10.24*+

Form of Services Agreement between Xcel Energy Services Inc. and utility companies

10.25*

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

10.26*+

Form of Award Agreement for Retention-Based Restricted Stock Units under the Xcel Energy Inc. Amended and
Restated 2015 Omnibus Incentive Plan

Xcel Energy Inc. Form 8-K dated Dec. 10,
2021

10.01

NSP-Minnesota

4.15*

4.16*

4.17*

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

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

4.19*

Indenture, dated as of July 1, 1999, by and between NSP-Minnesota and The Bank of New York Mellon Trust Company,
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(b)(7)

4.11

4.12

4.51

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*

10.27*

10.28*

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 The Bank of New York Mellon Trust Company, NA (as successor to Wells Fargo
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, 2013, by and between NSP-Minnesota and The Bank of New York
Mellon Trust Company, N.A., as Trustee, creating $400 million aggregate principal amount of 2.60% First Mortgage
Bonds, Series due May 15, 2023
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
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

4.63

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

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 20, 2013 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

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-Wisconsin Form S-4 dated Jan. 21, 2004 10.01

Xcel Energy Inc. Form 8-K dated Sept. 19,
2022

99.02

NSP-Wisconsin

4.36*

4.37*

4.38*

4.39*

4.40*

4.41*

4.42*

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
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

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

NSP-Wisconsin Form 8-K dated Dec. 4, 2017

4.01

NSP-Wisconsin Form 8-K dated Sept. 12,
2018

4.01

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
Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota

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

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 S-4 dated Jan. 21, 2004 10.01

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. 23, dated as of March 1, 2013, 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 2.50% First Mortgage Bonds, Series No. 25 due March 15, 2023 and $250 million aggregate
principal amount of 3.95% First Mortgage Bonds, Series No. 26 due March 15, 2043

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

Proposed Settlement Agreement, excerpts, as filed with the CPUC

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 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

PSCo Form 8-K dated March 26, 2013

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

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

Xcel Energy Inc. Form 8-K dated Dec. 3, 2004 99.02

Xcel Energy Inc. Form 8-K dated Sept. 19,
2022

99.03

4.43*

4.44*

4.45*

10.29*

10.30*

PSCo

4.46*

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*

10.31*

10.32*

SPS

4.62*

4.63*

4.64*

4.65*

4.66*

4.67*

4.68*

4.69*

4.70*

4.71*

4.72*

4.73*

10.33*

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
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 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

4.02

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

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

101.INS

Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

101.SCH Inline XBRL Schema

101.CAL

Inline XBRL Calculation

101.DEF Inline XBRL Definition

101.LAB Inline XBRL Label
101.PRE Inline XBRL Presentation

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

SCHEDULE I

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

Year Ended Dec. 31
2021

2020

2022

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

$ 1,905
1,905

$ 1,744
1,744

$ 1,646
1,646

19
(2)
206
223
1,682
(54)
$ 1,736

21
3
173
197
1,547
(50)
$ 1,597

43
(4)
198
237
1,409
(64)
$ 1,473

Pension and retiree medical benefits, net of tax of $ 1,
$1 and $1, respectively

Derivative instruments, net of tax of $3, $(1) and $(7),
respectively

Other comprehensive income
Comprehensive income

21
30
$ 1,766

10
18
$ 1,615

(5)
—
$ 1,473

Weighted average common shares outstanding:

Basic
Diluted

Earnings per average common share:

Basic
Diluted

547
547

539
540

527
528

$ 3.18
3.17

$ 2.96
2.96

$ 2.79
2.79

See Notes to Condensed Financial Statements

XCEL ENERGY INC.
CONDENSED STATEMENTS OF CASH FLOWS
(amounts in millions)

Year Ended Dec. 31

2022

2021

2020

Operating activities

Net cash provided by operating activities

$ 1,340

$ 1,147

$ 2,377

Investing activities

Capital contributions to subsidiaries

(921)

(1,661)

(2,553)

Net return (investments) in the utility money pool

Other, net

Net cash used in investing activities

Financing activities

Proceeds (repayment of) from short-term borrowings,
net

Proceeds from issuance of long-term debt

Repayment of long-term debt

Proceeds from issuance of common stock

Repurchase of common stock

Dividends paid

Other

Net cash 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

—

—
(921)

(407)

694

—

322

—

(1,012)

(16)

(419)

—

(18)

—
(1,604)

(1)
(2,572)

638

791

(400)

366

—

(935)

(16)

444

(13)

(500)

1,089

(300)

727

(4)

(856)

(17)

139

(56)

See Notes to Condensed Financial Statements

XCEL ENERGY INC.
CONDENSED BALANCE SHEETS
(amounts in millions)

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

Commitments and contingencies

Capitalization

Long-term debt

Common stockholders' equity

Total capitalization

Total liabilities and equity

Dec. 31

2022

2021

443

452

22,597

(7)

22,590

23,042

500

268

231

1,016

5,338

16,675

22,013

23,042

430

—

437

21,167

21,238

21,675

—

249

638

916

5,137

15,612

20,749

21,675

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, 2022 and 2021,
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,
2022:

(Millions of Dollars)

Guarantor

Guarantee
Amount

Current
Exposure

Triggering
Event

Dividends — Cash dividends paid to Xcel Energy Inc. by its subsidiaries
were $1,503 million, $1,344 million and $2,527 million for the years ended
Dec. 31, 2022, 2021 and 2020, 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.:

Guarantee of loan for
Hiawatha Collegiate High
School (a)
Guarantee of Capital
Services purchase contract
for solar generating
equipment.

(c)

Guarantee performance and
payment of surety bonds for
Xcel Energy Inc.’s utility
subsidiaries (e)

Xcel Energy
Inc.

—

Xcel Energy
Inc.

(d)

(f)

(b)

(Amounts in Millions, Except Interest Rates)

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

(g)

Money pool interest income

Three Months Ended
Dec. 31, 2022

—

0.01 %

N/A

—

(a)

(b)

(c)

(d)

(e)

(f)

(g)

The guarantee expires the earlier of 2024 or full repayment of the loan.

Nonperformance and/or nonpayment.

The guarantee expires the earlier of termination or payment of all obligations under the

purchase contract.

Given that the manufacturing of solar generating equipment has not yet commenced,

related exposure to the payment obligations of Capital Services at Dec. 31, 2022 is

immaterial.

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.

(Amounts in Millions, Except
Interest Rates)

Year Ended
Dec. 31, 2022

Year Ended
Dec. 31, 2021

Year Ended
Dec. 31, 2020

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

—

204

—

439

104

350

0.73 %

0.08 %

0.60 %

Money pool interest income

—

N/A

0.07

Due to the magnitude of projects associated with the surety bonds, the total current

See notes to the consolidated financial statements in Part II, Item 8.

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.

82
17
111
61
145

104
25
91
58
125

2021

2022

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)

2022

Balance at Jan. 1

$ 106

2021

$ 79

2020

$ 55

2022

$ 64

2021

$ 64

2020

$ 67

Additions charged to
costs and expenses

Additions charged to
other accounts

Deductions from
reserves

(83)

(a)

(b)

(47)

(a)

(b)

(a)

(b)

(48)

—

(c)

(8)

(c)

(5)

(d)

(9)

Balance at Dec. 31
(a)

Recovery of amounts previously written-off.

$ 122

$ 106

$ 79

$ 62

$ 64

(b)

(c)

(d)

Deductions related primarily to bad debt write-offs.

Primarily reductions to valuation allowances due to additional NOLs and tax credits

forecasted to be used prior to expiration.

Primarily the reduction of valuation allowances for North Dakota ITC, net of federal

income tax benefit, that is offset to a regulatory liability forecasted to be used prior to

expiration along with valuation allowances that expired.

ITEM 16 — FORM 10-K SUMMARY

Other subsidiaries of Xcel Energy Inc.

27
443

27
430

None.

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. 23, 2023

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

Kim Williams

Chairman, President, Chief Executive Officer and Director
(Principal Executive Officer)

Executive Vice President, Chief Financial Officer
(Principal Accounting Officer and Principal Financial Officer)

Director

Daniel Yohannes

*By:

/s/ BRIAN J. VAN ABEL
Brian J. Van Abel

Attorney-in-Fact

XCEL ENERGY BOARD OF DIRECTORS

SHAREHOLDER INFORMATION

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, Bromine Specialties,
Albemarle Corporation

Patricia Kampling 2,3
Retired Chairman and CEO,
Alliant Energy Corporation

George Kehl 1,2
Retired Office Managing Partner, KPMG

Richard O’Brien 1,4
Independent Consultant

Charles Pardee 1,4
President, Terrestrial Energy, USA

Christopher Policinski 3
Lead Independent Director
Retired President and CEO,
Land O’ Lakes, Inc.

James Prokopanko 3,4
Retired President and CEO,
The Mosaic Company

Kim Williams 2,3
Retired Partner,
Wellington Management Company LLP

Daniel Yohannes 1,2
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

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 2022.

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.

BUILDING THE FUTURE ANNUAL REPORT 2022FISCAL 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
Computershare Corporate Trust
MAC 9300-070
600 South 4th Street
Minneapolis, MN 55415