Xcel Energy Annual Report 2021

FY2021 Annual Report · Xcel Energy

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HORIZON
BOUND

2021

ANNUAL REPORT

HORIZON BOUNDANNUAL REPORT 2021COMPANY DESCRIPTION

Xcel Energy is a major U.S. electric and natural gas
company with annual revenues of $13.4 billion. Based in
Minneapolis, Minnesota, the company operates in eight
states and provides a comprehensive portfolio of energy-
related products and services to 3.7 million electricity
customers and 2.1 million natural gas customers.

FINANCIAL HIGHLIGHTS

2020

2021

Total GAAP earnings per share

2.79

2.96

Ongoing earnings per share

2.79

2.96

Dividends annualized

1.72

1.83

Stock price (close)

66.67

67.70

Assets (millions)

53,957

57,851

EARNINGS PER SHARE

Dollars per share (diluted)

4
6
.
2

9
7
.
2

6
9
.
2

2019

2020

2021

GAAP (generally accepted accounting
principles) earnings per share

Ongoing earnings per share

INCREASED FOCUS ON DEI
DRIVES POSITIVE RESULTS

Xcel Energy is committed to cultivating an
equitable and inclusive work environment,
with a skilled, engaged and diverse workforce
that reflects the communities we serve. We
continue to weave the importance of diversity,
equity and inclusion (DEI) into the fabric of our
company and to provide an environment where
all employees feel they can be themselves and
genuinely are included and empowered to do
their best work.

To ensure this crucial topic receives appropriate
attention and visibility, the company adopted
a new index to measure progress on specific
aspects of DEI for the corporate scorecard in
2021. The index measures three key elements
of the company’s DEI strategy: the use of
diverse interview panels in the hiring process,
performance of our overall inclusion index and
active participation in the executive sponsorship
program that supports career growth by pairing
executives with employees who are diverse
from themselves.

Xcel Energy exceeded its targets for each of
the three factors in 2021 and will retain the DEI
metric on its corporate scorecard in 2022.

As a result of our commitment to diversity, we
have seen a 6% increase in women and a 5%
increase in diverse representation within our
senior leadership at the vice-presidential level
and above.

“As a purpose-driven and values-led organization,
we continue to build a culture of belonging
where diverse viewpoints are appreciated,” said
Baird McKevitt, Director, Inclusion and Diversity.

ON THE COVER:
Pictured is a solar facility
in Eau Claire, Wisconsin,
adjacent to our state
headquarters. Xcel Energy
is working towards several
clean energy milestones on
the horizon at the end of
the decade.

DEAR
FELLOW
SHAREHOLDERS

Bob Frenzel
Chairman,
President and
Chief Executive
Officer

HORIZON BOUND
ANNUAL REPORT 2021

3
3

HORIZON BOUNDANNUAL REPORT 2021Xcel Energy achieved strong financial and operational results again in 2021, despite the second year of a global pandemic and severe weather challenges. During these tough times, we delivered for our customers and communities when they needed us most, and we continued to advance our financial, operational, and sustainability goals.Our theme for this report, “Horizon Bound,” reflects our balanced, organic growth and our aggressive clean energy targets for the next decade and beyond. In the next eight years, we will add significant renewable generation to our system, expand our transmission infrastructure to enable those resources, deploy new clean fuels to power our customers and heat their homes, invest in grid resiliency and automation, and enable electrification of transportation at scale, all while keeping customer bills affordable. This report showcases how our team is working hard to deliver for you, our valued shareholders. CEO transitionIt was an honor to be elected by our Board of Directors to replace retiring Ben Fowke as our company’s CEO in August. I worked closely with Ben for five years, first as Chief Financial Officer and more recently as President and Chief Operating Officer. We share the same vision for the company and executed our transition in August from a position of strength — our reputation is excellent, our balance sheet is healthy, our operations are strong, and our strategy is sound.4

Solid financial performanceFor the 17th consecutive year, we met or exceeded our earnings guidance, and we increased our dividend for the 18th consecutive year. We delivered earnings of $2.96 per share, within the upper half of our initial guidance range. We increased our dividend 6.4%, or 11 cents per share in 2021, which is in line with our 5% to 7% goal. Our stock continues to trade at a premium and has outperformed our peer group for the three-, five- and ten-year periods. Our robust five-year, $26 billion capital investment plan will provide significant customer value and drive regulated rate base growth of 6.5%. And, we’ve identified additional investment opportunities in that timeframe for an incremental capital investment of $1.5 to $2.5 billion, which would increase our growth rate to 7.4%.Clean energy leadershipIn November, we announced a clean energy vision for our natural gas distribution business. Our vision reduces greenhouse gas emissions 25% from 2020 levels by 2030, including net-zero methane emissions from our distribution system, and delivers net-zero natural gas service to customers by 2050. (See story on page 14).Our natural gas vision builds on our previously announced electric goals for reducing carbon emissions 80% by 2030 and producing 100% carbon-free electricity by 2050. We also plan to use our increasingly clean product to power 1.5 million electric vehicles in our states by the end of the decade, resulting in additional carbon reduction, future sales growth, and customer fuel savings. Together, these commitments represent a comprehensive clean energy vision, making Xcel Energy the first U.S. energy provider to set aggressive clean energy goals across all the ways our customers use energy: electricity, transportation, and heating. And we are well on our way to achieving that vision. Delivering at critical timesWe never take for granted the trust we have earned to power millions of homes and businesses all day, every day, particularly during extreme weather. In 2021, there were two significant events that impacted our service territory — Winter Storm Uri in Texas and the Marshall Wildfire in Colorado. These two natural disasters challenged our teams to deliver in the most arduous conditions. And as always, we rose to the challenge. Historic cold temperatures during Winter Storm Uri froze natural gas wells throughout Texas and Oklahoma, creating natural gas supply constraints and price spikes across the country. At the same time, the Texas electric system saw generation equipment failures caused by the cold, which left millions without power or heat. Our plants and equipment in the Southwest are winterized for extreme temperatures and performed very well during the event, despite widespread failures of other generating assets. Despite our employees operating our gas distribution system extremely capably during the 10-day record-setting cold period, we were not immune from the sudden, extraordinary increase in natural gas prices that went along with Winter Storm Uri. We incurred $925 million of additional fuel costs that we are working with regulators to recover while helping customers manage costs. Following a particularly dry fourth quarter, on Dec. 30, Colorado faced an intense windstorm that packed 110 mph winds and fueled the devastating Marshall Wildfire. The Boulder County fires destroyed more than 1,200 homes and businesses in the area, and partially or totally destroyed the homes of 17 of our own employees. Hundreds of employees, contractors and mutual aid crews were on the scene as soon as it was safe and worked around the clock to get service restored to the impacted communities. These extreme weather events reinforce the need for continued investment in system resiliency, such as our approved wildfire mitigation program, to protect communities from the growing impacts of climate change.Constructive regulatory outcomesWe reached constructive rate case settlements in six states last year. In Colorado, we also reached constructive settlements for Winter Storm Uri cost recovery, our electric resource plan and our Power Pathway transmission project, a nearly $2 billion investment necessary to enable future renewable generation assets.The New Mexico commission approved our Transportation Electrification Plan, and we launched several commercial and residential programs to support electric vehicle adoption in Colorado as part of our approved, industry-leading Transportation Electrification Plan. (See story on pages 10-11). In February 2022, the New Mexico commission also approved our electric rate case settlement. Sincerely,

Bob Frenzel
Chairman, President and
Chief Executive Officer

HORIZON BOUNDANNUAL REPORT 2021Also in February 2022, the company received approval for its Upper Midwest Generation Resource Plan, including a full closure of all coal plants in the region by 2030, over 85% carbon reduction, 5,750 megawatts of new wind and solar assets, and transmission infrastructure to enable those resources. The plan also includes a license extension of our Monticello nuclear plant through 2040. Our proposed resource plan in Colorado would add 5,100 megawatts of new renewable generation assets and is expected to reduce carbon emissions 87% by 2030. (See story on pages 8-9). Renewable energy expansionOur Steel for Fuel strategy — building and owning wind farms that deliver economic and environmental benefits for our customers — continues to drive organic growth, provide an attractive shareholder return, and save customers money. Since 2017, wind energy — through a combination of fuel savings and tax credits — saved customers an estimated $1.8 billion.We now have over 11,000 megawatts of total wind capacity, including nearly 4,500 megawatts of owned wind. We also advanced plans for owning our first large-scale solar projects. We received approval for a 74-megawatt solar project in Wisconsin and proposed a 460-megawatt project near our Sherco coal plant in Minnesota. Advanced Grid InitiativeOur $1.7 billion, multi-year Advanced Grid Initiative, to use advanced technology to bring customers cleaner, safer, more reliable energy, achieved a significant milestone in 2021 as the first batch of 310,000 smart meters were installed in Colorado. The two-way communication capabilities will help improve reliability, reduce the time it takes to restore power during an outage, and provide customers more options to manage their energy use and save money. (See story on pages 6-7).Operational excellenceOperational excellence is at the core of our commitment and approach to operating our plants and facilities and our preparedness to respond to extreme weather and other events. We remain the top-performing nuclear fleet in the country. One of our units at Prairie Island operated for a record 703 consecutive days before its scheduled refueling in October. Additionally, we have held our operating and maintenance costs flat since 2013, helping to keep customer bills low without compromising safety or reliability. We remain committed to our industry-leading “Safety Always” program. (See story on pages 12-13).Employee focusAs we have done since the start of the pandemic, our employees continue to follow extra safety protocols to protect themselves, their coworkers, and their loved ones from COVID-19. Approximately half of our employees worked remotely in 2021 but are returning to the office this spring with a hybrid work schedule as the pandemic continues to recede. The company added diversity, equity, and inclusion (DEI) metrics to its corporate scorecard for the first time in 2021, and I am pleased to report that we exceeded our goals. Diversity and inclusion make us a stronger company and a more welcoming workplace, where we can attract and retain top talent. (See story on page 2).It’s an honor to lead this team — more than 11,000 employees strong — that is consistently recognized with its outstanding business practices and ethics, operational performance, veteran hiring, and workplace culture. We were honored to be named among the World’s Most Ethical Companies® by Ethisphere for the third consecutive year, reflecting the company’s commitment to sustainability and ethical business practices. We also were among the Human Rights Campaign’s Best Places to Work for LGBTQ Equality, earning a perfect score on its Corporate Equality Index for the sixth consecutive year. We were named one of Fortune’s Most Admired Companies for the ninth consecutive year and ranked second among energy providers.With the best employees in the industry serving you, I’m excited about the future — not just what’s in store for 2022, but for the transformative progress on the horizon. You can count on the Xcel Energy team to deliver for you. Thanks for the continued trust you place in us. A SMARTER,
MORE
RESILIENT
ENERGY GRID

SMART METER ROLLOUT BEGINS IN COLORADO,
WILL EXPAND TO OTHER STATES IN 2022

BUILDING THE ENERGY GRID OF THE FUTURE IS

WELL ON ITS WAY. AFTER FOUR YEARS OF PLANNING,

FOUNDATIONAL WORK AND SOFTWARE DEVELOPMENT,

XCEL ENERGY’S ADVANCED GRID INITIATIVE ACHIEVED

A MAJOR MILESTONE IN 2021 WHEN THE FIRST

WAVE OF SMART METERS WAS DEPLOYED AT

310,000 COLORADO CUSTOMER HOMES.

The $1.7 billion, multi-year grid
transformation deploys industry-
leading technology to help
Xcel Energy better manage the
grid and deliver an improved
customer experience through
improved outage response and
the ability for customers to better
manage their energy use.

The Advanced Grid Initiative
enhances distribution operations
through the deployment of new
software, building a two-way
communications network, adding

new automated field devices and
installing smart meters at customer
premises. The smart meters
deliver numerous customer and
operational benefits, providing near-
real-time communication between
the customer and Xcel Energy, so
customers know exactly how much
energy they are using and what
it will cost them. The meters also
provide increased automation that
reduces the need for manual meter
reading or estimating usage, and
improves efficiency.

“Smart meters are the foundational
technology needed to enable a new
suite of energy-related products
and services for our customers,”
said Steve Foss, Regional
Vice President for Distribution
Operations. “Our industry-leading
Advanced Grid Initiative will
deliver outstanding value to our
customers, and we are excited
about the potential capabilities
we see on the horizon.”

In Colorado, the initiative
includes time-of-use rates that
incent customers who use
electricity during off-peak hours.
Small changes like running the
dishwasher or operating laundry
machines later at night or in the
morning will generate savings on
energy bills. Previously, energy
rates in the state remained
constant at all hours because
older meter technology could not
differentiate usage by time of day.

Customers will have new digital
tools to make it easy to access
their energy information and gain
useful insights to better understand
and manage their energy use and
make smarter energy choices that
lower their bills and save money.

To prepare for the smart meter
rollout, a secure field network
communications system was
built and expanded, allowing the
smart meters to send encrypted
information to Xcel Energy through

a series of secure communication
devices. Simultaneously, new
software tools and controls were
deployed for the company’s
distribution control centers to
increase reliability and resiliency,
optimize voltage levels throughout
the system and help the company
better manage the energy grid
throughout our eight-state
footprint. An advanced application
in the new system software for
voltage management, along with
the addition of 430 field devices,
generated 127.5 gigawatt hours of
energy savings for customers in
Colorado last year.

While the rollout will continue
in Colorado over the next three
years, the first smart meters are
expected to begin deployment in
Minnesota in 2022 and the Dakotas
in 2023, with Texas, New Mexico,
Wisconsin and Michigan starting
later. By the end of 2024, nearly
3.9 million smart meters will be
installed across our eight states.

Operations Manager Jamin Argon
from the Advanced Grid Initiative
team explains the benefits of
a smart meter to Xcel Energy
customer Kelly Almer of Littleton,
Colorado. Installed by Senior
Meter Technician Sandra Perez, the
smart meter was one of 310,000
connected to the grid in Colorado
last year.

“Our customers and communities
will benefit significantly from
our industry-leading Advanced
Grid Initiative,” Foss said. “The
Advanced Grid Initiative dovetails
nicely with the company’s strategic
priorities, including enhancing the
customer experience and keeping
bills low.”

HORIZON BOUNDANNUAL REPORT 2021LEADING THE CLEAN ENERGY TRANSITION DOESN’T

HAPPEN BY ACCIDENT. IT TAKES A TRACK RECORD OF

OPERATIONAL EXCELLENCE, STRONG STAKEHOLDER

ENGAGEMENT AND A BALANCED, THOUGHTFUL

APPROACH TO DRIVE SIGNIFICANT CARBON

REDUCTIONS WHILE ENSURING RELIABILITY AND

AFFORDABILITY FOR CUSTOMERS.

By completing the Dakota Range
Wind Farm near Watertown, S.D., in
early 2022, Xcel Energy successfully
completed the largest multi-state
wind investment in the nation,
adding 3,600 megawatts of new
company-owned wind projects since
2017. Xcel Energy now has more
than 11,000 megawatts of wind
capacity on its system and is among
a handful of companies to exceed
the 10,000-megawatt threshold.

“Wind energy drives both
economic and environmental
benefits for our customers, while

wind ownership provides an
attractive investment return for
our shareholders. We’ve proven
that we can effectively build and
operate wind farms as part of our
Steel for Fuel growth strategy,”
said Paul Johnson, Vice President,
Treasurer and Investor Relations.
“We estimate our wind farms
generated approximately $1.8 billion
in savings for customers over the
past five years. In addition, wind
farms provide a strong tax base,
along with both construction and
permanent jobs, and landowner

lease payments help drive the
economy in rural communities.”

Transitioning from fossil fuels to
renewable energy sources like
wind and solar has helped the
company reduce carbon emissions
50% since 2005 and remain on
pace for an 80% reduction by the
end of the decade.

Specific plans to achieve that
goal are now being finalized after
the Minnesota Public Utilities
Commission approved our clean
energy proposal for the Upper
Midwest system. They include
retiring all coal plants in the
region by 2030, extending the
use of our carbon-free Monticello
Nuclear Generating Station to
2040 and adding approximately
5,800 megawatts of wind and
solar power. Natural gas would
continue to be used as a bridge
fuel to ensure reliability until new
technologies are developed.

ON PACE
FOR A
CARBON-FREE
FUTURE

COMPANY FINALIZING PLANS TO REDUCE
CARBON EMISSIONS MORE THAN 85% IN
MINNESOTA AND COLORADO BY 2030

“The approved plan delivers more
than 85% carbon reduction across
our Upper Midwest system,
while ensuring we continue to
provide the reliable, affordable
electricity our customers count
on,” said Chris Clark, President,
Xcel Energy Minnesota, North
Dakota and South Dakota.
“Receiving commission approval
for this transformational energy
plan required significant outreach
and dialogue with policymakers,
customers and stakeholders;
a process that takes years of
planning and negotiating.”

Meanwhile in Colorado,
the company is expecting a
commission decision by the
end of first quarter 2022 on its
landmark clean energy proposal,
which is estimated to reduce
carbon emissions 87% by the
end of the decade and retire all
its coal plants in the state by
2034. In addition, the company
has received verbal approval for

Colorado’s Power Pathway, a nearly
$2 billion transmission investment
to improve the state’s electric
grid and deliver various proposed
renewable energy projects to our
customers. Once the written order
is issued and work can begin, the
transmission projects and new
substations are expected to be
completed starting in 2025 and
continuing through 2027.

Achieving the company’s industry-
leading vision to produce carbon-
free electricity for our customers
by 2050 will require new clean
energy technologies. One of
the most promising emerging
technologies is using carbon-free
energy to produce hydrogen.
Xcel Energy is partnering with the
Department of Energy and the
Idaho National Laboratory on a pilot
project that is scheduled to begin
producing carbon-free hydrogen
at our Prairie Island Nuclear
Generating Station next year that
can be used in other applications.

In early 2022, Xcel Energy
completed the largest multi-state
wind investment in the country at
the time — 14 wind farms in seven
states. More wind projects are on
the horizon in the recently approved
Upper Midwest Resource Plan and
proposed Colorado Energy Plan.

In 2020, the company created the
Carbon-Free Technology Initiative,
a cross-functional group set up
to identify and support the future
technologies critical to achieving
our carbon-free goals. That work
has now been expanded at the
industry level by the Edison Electric
Institute trade association.

HORIZON BOUNDANNUAL REPORT 2021NOT A
QUESTION
OF IF, BUT
WHEN

ELECTRIC VEHICLES WILL BECOME
DOMINANT MODE OF TRANSPORTATION

IN 2020, ELECTRIC VEHICLES (EVs) COMPRISED

ONLY 3% OF VOLKSWAGEN’S GLOBAL NEW

CAR SALES. BY 2030, VOLKSWAGEN PREDICTS A

WHOPPING 50% OF ITS NEW CAR SALES WILL

COME FROM EVs, ACCORDING TO REUTERS.

Europe’s largest car manufacturer
is investing $86 billion in EV
technology, knowing that it’s not
a question of if — but when —
EVs are the dominant mode of
transportation across the globe.

Ford and General Motors have
announced similar 2030 EV
sales goals. In fact, demand for
the new F-150 Lightning pickup
truck, scheduled to come out in
2022, has been so intense that
reservations have temporarily
closed with a three-year waitlist,
according to news reports.

Like the world’s largest car
manufacturers, Xcel Energy sees

significant EV growth on the
horizon, which will expand the
company’s clean energy leadership
to the transportation sector, drive
electricity sales growth and help
keep bills low for customers. The
company has set an aggressive
goal to power 1.5 million electric
vehicles in its eight-state service
territory — or approximately 20%
of the cars on the road — by the
end of the decade.

“We know EV adoption will grow
exponentially in the coming years,
and we will be ready,” said Nadia
El Mallakh, who leads Xcel Energy’s
Clean Transportation team. “Our
employees are working hard to

make sure the transition to EVs is
easy, seamless and less costly
for our customers.”

From a regulatory and policy
perspective, the company made
significant strides in 2021 —
receiving final written approval for
comprehensive, inaugural EV plans
in both Colorado and New Mexico.
Colorado’s nation-leading $110 million
Transportation Electrification Plan
provides charging equipment for
both single-family and multi-family
homes and aligns with the state’s
goal to help place 940,000 EVs on
Colorado roads by 2030. Broad and
innovative, these plans focus on
residential and business customers
as well as our communities, while
also embracing tools to bring
electrification to all customers.

“We want to give everyone the
opportunity to experience the
benefits of EVs,” El Mallakh said.
“Income-qualified customers in
Colorado can receive rebates on
new and used EVs under $50,000,

and all Colorado customers have
access to a rebate that essentially
covers most of the home wiring
costs to install a faster, more
powerful home charger.”

In addition to the strong regulatory
and policy outcomes, the company
launched a record number of
clean transportation programs in
Colorado and Minnesota last year
— 14 to be exact.

In Minnesota, Xcel Energy is
partnering with the cities of
Minneapolis and St. Paul and
the nonprofit Hourcar to build 70
curbside charging hubs across the
metro area to support increased
access and use of electric vehicles.
Overall, the company is investing
more than $30 million in public
charging infrastructure across
several states to provide more
charging options for longer trips.

A new dedicated customer care
team was created to tailor service
for our new EV customers. The

team helps customers find local
EV dealers, directs them to tools
to understand savings options
and lines them up with hassle-
free installation of a home charger
by one of our certified program
electricians through Xcel Energy’s
EV Accelerate At Home program.
A separate, dedicated EV Advisor
team helps commercial customers
and municipalities find programs
that best suit their needs and helps
them evaluate the cost to transition
all or part of their fleet of vehicles
from gas to electric.

Xcel Energy customers can charge
their EVs overnight at home using
off-peak rates for the equivalent of
about $1 per gallon of gas. Couple
that with no oil changes and limited
maintenance costs, and customers
can save significant dollars as they
drive past the gas station while
simultaneously reducing their
carbon footprint.

Rehana Power, an Xcel Energy
customer, charges a Volkswagen
ID.4 electric vehicle at an EV Spot
charging station near Macalester
College in St. Paul, Minnesota.
The EV Spot network is a series of
70 curbside hubs that offer public
access to the new all-electric Evie
carshare service and the EV Spot
electric charging stations.

Early adopters are already enjoying
the economic and environmental
benefits of driving electric. By 2030
under our aggressive vision, we
expect our EV driving customers to
collectively save $1 billion annually,
while all our customers benefit
from eliminating 5 million tons of
carbon annually by the same year.

HORIZON BOUNDANNUAL REPORT 2021TWO YEARS AGO, XCEL ENERGY BEGAN

A PIVOTAL EVOLUTION OF ITS SAFETY

APPROACH TO FOCUS ON ELIMINATING

SERIOUS INJURIES AND FATALITIES.

Safety Always aims to develop
a culture of enhanced trust and
transparency with employees
and contractors, so that we can
collaborate to identify the most
serious risks inherent in our work
and make sure that all the possible
controls are in place to mitigate
those risks before we start work.

Culture change has been a key
focus in the first two years of
implementing this approach. This
includes preparing employees to
make critical changes to how work
is done every day and establishing
the trust and transparency
necessary for people to have
open and honest conversations.
Central to this change is conducting

Event Learnings, which are candid
conversations designed to provide
a deep understanding of how
an incident occurred so we can
address what needs to be changed
and improve together.

Collaborating to understand how
work is truly performed in the
field has allowed us to implement
a new risk-based continuous
improvement process to identify
energy-based hazards and the
critical controls needed to prevent
life-ending and life-altering injuries
from occurring.

“Everyone wants the same thing
— to return home safely to their
loved ones every night,” said
Jennifer Bailey, Director of Safety.
“The most important strategy we
can employ to prevent life-changing
events from happening is to use
controls — because they save
lives. Our Safety Always approach
is critical to ensuring that we have
controls in place to prevent life-
changing and life-ending injuries.”

LEARNING
NEW WAYS
TO WORK

FOCUS ON SAFETY ALWAYS,
INTRODUCING HYBRID WORK MODEL

COVID-19
Since the start of the pandemic,
Xcel Energy has been working to
protect the health and safety of our
employees at all our facilities. Our
health and safety strategy kept most
office employees continuing to work
from home throughout 2021, while
our employees who work at our
power plants, service centers and
in the field served our customers
onsite, all while following additional
safety protocols.

Hybrid work program
This fall, the company’s expanded
leadership team began returning
to their work locations to prepare
for a full-scale return of all
employees in 2022. As the entire
workforce returns to their job
sites in March 2022, the company
is implementing a hybrid work
program to offer eligible employees
a mix of at-home and in-office work
schedules. This hybrid approach
ensures that valuable, in-person

collaboration is embedded in
the work culture and allows the
flexibility that is critical to attracting
and retaining top talent, especially
in a tight labor market.

Corporate recognition
Xcel Energy has reached many
milestones in 2021, among those
included recognition for our
company, our workplace and our
commitment to living our values.

We were honored to be named
among the World’s Most Ethical
Companies® by Ethisphere for the
third consecutive year, reflecting
the company’s commitment to
sustainability and ethical business
practices. We also were among
the Human Rights Campaign’s
Best Places to Work for LGBTQ
Equality, earning a perfect score on
its Corporate Equality Index for the
sixth consecutive year.

We were named one of Fortune’s
Most Admired Companies for

Dora Solon, Operations Training
Supervisor, adjusts a dial in the
Control Room Simulator for the
Monticello Nuclear Generating
Station in Minnesota. Dora was
among thousands of employees
who continued to work safely
onsite during the pandemic to
provide energy for our customers.

the ninth consecutive year and
ranked second among energy
providers. The company was also
among Forbes’ America’s Best
Large Employers, based on a
survey of employees who rate
their employers by describing
how likely they would be to
recommend them and identifying
companies they admired.

HORIZON BOUNDANNUAL REPORT 2021ON THE HORIZON:
NET-ZERO NATURAL
GAS SERVICE

COMPANY WORKING TO REDUCE GREENHOUSE GAS
EMISSIONS ACROSS THREE MAJOR ECONOMIC SECTORS

After more than a year of study,
Xcel Energy last fall announced
a vision to achieve net-zero
greenhouse gas emissions from
its natural gas business by 2050.
In doing so, the company became
the first U.S. energy provider to
announce a comprehensive vision
with aggressive goals for reducing
greenhouse gas emissions
across three large sectors of the
economy: electricity, natural gas
use in buildings and transportation.

“Our vision for delivering net-zero
energy by 2050 is an important
evolution in our clean energy
strategy,” said Frank Prager,
Xcel Energy’s Chief Sustainability
Officer. “As a clean energy leader,
it’s important that we have a plan
for reducing our footprint across all
areas of our business and provide
customers a path to continue using
reliable, affordable energy while
reducing their emissions as well.”

The new clean natural gas
commitment builds on Xcel Energy’s
vision to deliver 100% carbon-free
electricity to customers by 2050,
with an aggressive interim goal of

reducing emissions 80% by 2030.
That vision, announced in 2018, led
to dozens of U.S. power providers
announcing similar goals to
eliminate carbon from their electric
systems. In 2020, we announced a
goal to use our increasingly green
product for powering 1.5 million
electric vehicles in our service
areas by the end of the decade.

Along with a net-zero natural
gas commitment, we set an
important interim goal to reduce
greenhouse gas emissions from
our natural gas service 25% from
2020 levels, including net-zero
methane emissions on our own
infrastructure by 2030. We will
target three discrete segments
of the natural gas value chain: our
own natural gas infrastructure,
our suppliers and their upstream
infrastructure, and customer usage
and emissions.

This clean energy transformation
starts with our own system
where significant progress has
already been made to reduce
methane emissions. We will
increase our emissions detection

Gas fitter Debbra Trevino checks
the pressure at a natural gas
meter in Denver, Colorado.

and repair work and continue to
make operational and system
improvements. As we move up
the supply chain, we will, over
time, purchase only certified low-
emissions gas from our suppliers.

And for our customers, we will
offer new voluntary programs
to reduce carbon emissions
from their own natural gas use,
through expanded conservation
efforts and the use of electric
appliances and low-carbon gas
alternatives, including hydrogen
and renewable natural gas.
Xcel Energy is set to launch a
series of pilots to test renewable
natural gas, smart electric water
heaters and air source heat pumps
with customers, as well as test
both hydrogen production and the
blending of hydrogen in its natural
gas delivery system.

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, 2021 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. ☒ Yes

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No

As of June 30, 2021, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $35,463,594,471.

As of Feb. 17, 2022, there were 544,213,730 shares of common stock outstanding, $2.50 par value.

Portions of the Registrant’s definitive Proxy Statement for its 2022 Annual Meeting of Shareholders are incorporated by reference into Part III of this Form 10-K.

DOCUMENTS INCORPORATED BY REFERENCE

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26
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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
MPSC
MPUC
NDPSC
NERC
NMPRC
NRC
PHMSA
PSCW
PUCT
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
Michigan Public Service Commission
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
Securities and Exchange Commission
Texas Commission on Environmental Quality

Electric, Purchased Gas and Resource Adjustment Clauses

CIP
DSM
ECA
FCA
GCA
GUIC
PSIA
RES
TCR

Other
AFUDC

ALJ

ARO

ASC

ATM

BART

C&I

CAGR

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

Allowance for funds used during construction

Administrative Law Judge

Asset retirement obligation

FASB Accounting Standards Codification

At-the-market

Best available retrofit technology

Commercial and Industrial

Corporate annual growth rate

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

COEO

CON

COVID-19

CUB

CWA

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

Colorado Energy Office

Certificate of Need

Novel coronavirus

Citizens Utility Board

Clean Water Act

Construction work in progress

D.C. Circuit

United States Court of Appeals for the District of Columbia Circuit

DECON

DRIP

EEI

EIP

ELG

EMANI

EPS

ESG

ETR

EVs

FASB

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

Effluent limitations guidelines

European Mutual Association for Nuclear Insurance

Earnings per share

Environmental, Social and Governance

Effective tax rate

Electric Vehicles

Financial Accounting Standards Board

Fifth Circuit

United States Court of Appeals for the Fifth Circuit

Financial transmission right

Generally accepted accounting principles

General Electric

Greenhouse gas

Heating degree-days

Institute of Nuclear Power Operations
Intergovernmental Panel on Climate Change
Independent power producing entity
Independent System Operator
Investment Tax Credit
Lubbock Power & Light
Mankato Energy Center
Manufactured gas plant
Midcontinent Independent System Operator, Inc.
National Ambient Air Quality Standard
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
Operating and maintenance
Minnesota Office of the Attorney General
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

FTR

GAAP

GHG

HDD

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

NAV
NEIL
NOL
NOPR
O&M
OAG
OATT
PFAS
PI
Post-65
PPA
Pre-65
PTC
REC

ROE
ROU
RTO
S&P
SERP
SMMPA
SO2
SPP
TCJA

THI
TO
TSR
VaR
VIE

Return on equity
Right-of-use
Regional Transmission Organization
Standard & Poor’s Global Ratings
Supplemental executive retirement plan
Southern Minnesota Municipal Power Agency
Sulfur dioxide
Southwest Power Pool, Inc.
2017 federal tax reform enacted as Public Law No: 115-97, commonly
referred to as the Tax Cuts and Jobs Act
Temperature-humidity index
Transmission owner
Total shareholder return
Value at Risk
Variable interest entity

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, free of charge through its website, its annual report on
Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K
and all amendments to those reports filed or furnished pursuant to Section
13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as
reasonably practicable after the reports are electronically filed with or
furnished to the SEC.

The SEC maintains an internet site that contains reports, proxy and
information statements, and other information regarding issuers that file
electronically at http://www.sec.gov. The information on Xcel Energy’s
website is not a part of, or incorporated by reference in, this annual report
on Form 10-K. Xcel Energy intends to make future announcements
regarding Company developments and financial performance through its
website, www.xcelenergy.com, as well as through press releases, filings
with the SEC, conference calls and webcasts.

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 2022 EPS guidance, long-term EPS and dividend growth rate
objectives, future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected
capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions
regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and
credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words
“anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and
similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any
obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for
the fiscal year ended Dec. 31, 2021 (including risk factors listed from time to time by Xcel Energy Inc. in reports filed with the SEC, including “Risk Factors”
in Item 1A of this Annual Report on Form 10-K hereto), could cause actual results to differ materially from management expectations as suggested by such
forward-looking information: uncertainty around the impacts and duration of the COVID-19 pandemic, including potential workforce impacts resulting from
vaccination requirements, quarantine policies or government restrictions, and sales volatility; 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; ability to recover costs; changes in
regulation and subsidiaries’ ability to recover costs from customers; reductions in our credit ratings and the cost of maintaining certain contractual
relationships; general economic conditions, including inflation rates, monetary fluctuations, supply chain constraints and their impact on capital expenditures
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; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data
security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather; natural disaster and
resource depletion, including compliance with any accompanying legislative and regulatory changes; costs of potential regulatory penalties; and regulatory
changes and/or limitations related to the use of natural gas as an energy source.

Overview

Xcel Energy (the “Company”) is a major U.S. regulated electric and natural gas delivery company headquartered in Minneapolis, Minnesota (incorporated in
Minnesota in 1909). Xcel Energy serves customers in eight mid-western and western states, including portions of Colorado, Michigan, Minnesota, New
Mexico, North Dakota, South Dakota, Texas and Wisconsin. Xcel Energy provides a comprehensive portfolio of energy-related products and services to
approximately 3.7 million electric customers and 2.1 million natural gas customers through four utility subsidiaries (i.e., NSP-Minnesota, NSP-Wisconsin,
PSCo and SPS). Along with the utility subsidiaries, the transmission-only subsidiaries, WYCO (a joint venture formed with CIG to develop and lease natural
gas pipelines, storage and compression facilities) and WGI (an interstate natural gas pipeline company) comprise the regulated utility operations. Xcel
Energy’s nonregulated subsidiaries include Eloigne, Capital Services, Venture Holdings and Nicollet Project Holdings.

Utility Subsidiaries’ Service Territory

Electric customers

Natural gas customers

Total assets

Electric generating capacity

Natural gas storage capacity

3.7 million

2.1 million

$57.9 billion

20,653 MW

53.4 Bcf

Electric transmission lines (conductor miles)

111,434 miles

Electric distribution lines (conductor miles)

210,470 miles

Natural gas transmission lines

Natural gas distribution lines

2,293 miles

36,510 miles

Strategy

Xcel Energy strives to be the preferred and trusted provider of the energy
our customers need, while offering a competitive
to
total return
shareholders. We deliver on our vision through three strategic priorities:

LEAD THE CLEAN
ENERGY TRANSITION

ENHANCE THE
CUSTOMER EXPERIENCE

KEEP BILLS LOW

Sustainability is embedded in our strategy. We are retiring coal plants,
adding renewables, exploring new technologies and helping to electrify
other sectors, while maintaining customer affordability and supporting our
employees and communities.

We are the first U.S. energy provider to set aggressive goals for reducing
GHG emissions across three large sectors of the economy: electricity,
natural gas use in buildings and transportation.

Our sustainability commitments include:

(1)

(2)

Includes owned and purchased electricity provided to customers.
Spans natural gas supply, distribution and customer use; includes net-zero methane
emissions on our natural gas system by 2030.

We demonstrate environmental, social and governance leadership by
engaging with stakeholders and mitigating risk, while staying committed to
our customers, employees and communities.

Rooted in a culture of compliance and ethical conduct, our decisions and
actions are guided by our Code of Conduct and our four values:

Connected

Committed

Safe

Trustworthy

These values are reinforced by policies that govern safety practices, ethical
standards and conduct, environmental performance, diversity and inclusion,
political contributions, and other aspects of our business.

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

Lead the Clean Energy Transition

For more than a decade, Xcel Energy has proactively managed the risk of
climate change and worked to meet increasing demand for cleaner energy.

Xcel Energy was the first major U.S. utility to establish a carbon-free vision,
targeting 100% carbon-free electricity by 2050 and an interim goal of 80%
reduction in carbon emissions by 2030 (from 2005 levels), including owned
and purchased power. A lead author for the IPCC confirmed that our vision
aligns with science-based scenarios likely to limit global warming to 1.5
degrees Celsius from pre-industrial levels.

Other notable environmental improvements include:

Results from owned generation except for water, which includes owned and purchased power.
*

Coal ash reduction is as of 2020.

Xcel Energy has provided a voluntary, third-party verified annual GHG
disclosure since 2005, longer than any other U.S. utility. We are a founding
member of The Climate Registry and a supporter of the Task Force on
Climate-Related Financial Disclosures. Our disclosures also align with the
Global Reporting Initiative, Sustainability Accounting Standards Board and
United Nations Sustainable Development Goals frameworks.

Since year-end 2020, we have completed four wind farms, adding ~800
MW (includes the Dakota Range project which went in service in January
2022) of owned wind to our system that provides significant environmental
benefits and cost savings for our customers. Xcel Energy’s wind capacity is
now over 11,000 MW, including nearly 4,500 MW of owned wind.

By 2030, we project that approximately 80% of our energy will come from
carbon-free resources.

Goal includes owned and purchased power.

The pace of achieving a carbon-free vision is governed by reliability and
customer affordability. Our filed resource plans outline a clear, transparent
path to achieve an 80% carbon reduction using current technologies, while
maintaining customer bill increases at or below the rate of inflation. Moving
from 80% carbon reduction to 100% carbon-free electricity will require new
dispatchable and scalable technologies that are economically viable, as
well as supportive public policy. Resiliency and innovation also remain
paramount to a successful transition, as does the economic vitality of our
communities.

As we prepare for early coal plant retirements, we provide employees
advanced notice and offer retraining and relocation opportunities, with no
layoffs to date. We also help attract and make investments to offset
community economic impacts. Xcel Energy has a long track record of
working with our communities on energy, climate and environmental
initiatives that impact them and has publicly committed to furthering
environmental justice.

We consistently set aggressive goals and hold ourselves accountable to
our customers, communities and investors, as well as, to our own values.
Xcel Energy instituted oversight of environmental performance by the
Board of Directors beginning in 2000 and was among the first U.S. utilities
to tie carbon reduction to executive compensation over fifteen years ago.

Through 2021, we reduced carbon emissions from generation serving
customers by an estimated 50% (from 2005 levels) and remain on track to
achieve 80% carbon reduction by 2030.

Based on resource plans filed in Minnesota and Colorado, Xcel Energy
anticipates nearly 10,000 MW of additional renewables over the next
decade, and expects to be coal-free by 2034.

Colorado resource plan — settlement pending CPUC approval

•
•
•
•

87% carbon reduction by 2030 and full coal exit by 2034.
~3,900 MW of wind and solar additions.
~1,700 MW of flexible resources and storage.
~1,200 MW of distributed solar generation.

Minnesota resource plan — approved by MPUC

•
•

•
•
•

•

85% carbon reduction and full coal exit by 2030.
4,650 MW of wind and solar additions by 2032; the plan includes an
additional 1,100 MW of renewables beyond 2032.
Transmission infrastructure to connect new renewables to the grid.
Extension of the Monticello nuclear plant through 2040.
~3,800 MW of firm peaking capacity for reliability before 2030,
including hydrogen-ready combustion
the combustion
turbines will need to go through a CON process.
Additional ~2,100 MW of firm capacity and storage post 2030, to be
addressed in future proceedings.

turbines,

Texas and New Mexico

•
•

Proposed full coal exit by 2034 upon early retirement of our Tolk plant.
Conversion of our Harrington coal plant to natural gas.

We plan to limit coal usage through dispatching units seasonally where
possible. Natural gas and other dispatchable resources will be used as
needed for reliability and resiliency as more renewables come on the
system.

Significant transmission expansion will be required to enable future
renewables. Our Pathway project (if approved) in Colorado will provide over
560 miles of transmission lines and enable nearly 5,500 MW of new
renewables, including access to some of the region’s richest wind
resources. We also anticipate expansion in the Upper Midwest over the
next decade as part of MISO’s transmission expansion planning effort,
creating investment opportunity.

Our clean energy leadership encompasses our natural gas business as
well. In 2021, we committed to reduce GHG emissions by 25% by 2030
from 2020 levels and deliver net-zero natural gas service by 2050, including
customer use.

Plans include:

•
•
•

Influencing suppliers - pursue certified low/no net emissions supply.
Operating the cleanest possible system – incorporate clean fuels.
Offering customer options – encourage electrification, where
beneficial.

Xcel Energy’s leadership also extends beyond our electric and gas
businesses to other parts of the economy. In addition to transitioning our
own generation fleet, we are helping to decarbonize other sectors, starting
with transportation. We aim to enable 1.5 million EVs across our states by
2030, representing a nearly $2 billion investment, 0.6% to 0.7% incremental
annual retail sales growth and avoidance of roughly 5 million tons of CO2
emissions annually.

Enhance the Customer Experience

Xcel Energy 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 increased load growth, renewable energy and distributed
energy resources.

In 2021, Xcel Energy installed over 300,000 smart meters and plans to
install more than one million in 2022. Xcel Energy also launched 12 EV
programs for residential and commercial customers, received approval of
our New Mexico plan, and continued to prepare for increased levels of EV
adoption across our states.

For our local communities, we initiated 20 economic development projects
in 2021, which are projected to lead to over $1 billion in capital investments
and 5,000 jobs. Additionally, over 60% of our supply chain spend was local.

Keep Bills Low

Customer affordability is critical to successful strategy execution and we
are working to keep bill increases at or below the rate of inflation. Since
2013, we have managed average residential bill growth to below 1%
annually, with electric and natural gas bill increases of 0.8% and 0.3%,
respectively.

Xcel Energy has invested more than $2 billion over the past decade in a
comprehensive suite of conservation programs. We have kept O&M
expenses flat since 2014, while adding significant renewables and without
compromising safety or reliability.

Xcel Energy continues to prudently invest in appropriate areas consistent
with its continuing commitment to minimize costs through ongoing process
and technology improvements.

Our 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 renewables while saving customers money. To date, we
have delivered more than $1.8 billion in customer savings by adding
owned wind to our system.

In addition to continued savings from economic renewables, disciplined
cost control and future coal plant retirements, we anticipate sales growth
from electric vehicles will help keep bills low for all customers in the long
term, as well as provide customers with annual fuel savings (equivalent
cost per gallon for fueling with electricity vs. gasoline) of approximately $1
billion by 2030.

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 17 consecutive years and
delivering dividend growth for 18 consecutive years.

Over the past five years, GAAP earnings have grown by 6% annually and
our annual dividend growth was 6.1%. Xcel Energy works to maintain
senior secured debt credit ratings in the A range and senior unsecured debt
credit ratings in the BBB+ to A range. Current ratings are consistent with
this goal.

Human Capital

Xcel Energy employees are the driving force behind our Company’s
success. Our strategic, data-driven approach to workforce planning helps
ensure we will continue to have the skills and capabilities required to meet
the evolving needs of our business, customers and communities. We are
also deeply committed to diversity, equity, human rights and safety.

Safety

Continuously elevating the quality and safety of the workplace is a top
priority. We are considered a benchmark company for our Safety Always
approach, focused on eliminating life-altering injuries through a trusted,
transparent culture and the use of critical controls. All employees have
“stop work authority” and are expected to keep each other, our customers
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.

Veteran hiring is also a focus, with roughly 10% of employees having
served in the military.

To help foster a culture of inclusivity, leaders and employees receive
training on microinequities and unconscious bias. The Company hosts 11
business resource groups to support employee interests and obtain diverse
perspectives when solving challenges and achieving goals.

Xcel Energy also respects employees’ freedom of association and their
right to collectively organize. As of Dec. 31, 2021, approximately 44% of
our employees were covered by collective bargaining agreements.

NSP-Minnesota

NSP-Wisconsin

PSCo

SPS

XES

Total

Employees Covered by
Collective Bargaining
Agreements

Total Full-Time
Employees

2,020

382

1,818

736

—

4,956

3,083

518

2,314

1,099

4,307

11,321

Employee turnover for 2021 and future projected retirement eligibility:

Employee Turnover

Retirement Eligibility

Bargaining

Non-Bargaining
(a)

Overall

7 %

15 %

12 %

(a)

31% of turnover was due to retirements.

Within next 5 years

Within next 10 years

26 %

40 %

Xcel Energy has publicly confirmed our commitment to the advancement
and protection of human rights, consistent with U.S. human rights laws and
the general principles in the International Labour Organization Conventions.
Code of Conduct training is required for all employees annually and the
Board of Directors.

The Company does not tolerate Code violations or other unacceptable
behaviors. We expect and offer employees multiple avenues to raise
concerns or report wrong-doing and do not permit any retaliation.

Xcel Energy recently received the following recognitions:

Fortune

Human Rights
Campaign

GI Jobs

Military Times

World’s Most
Admired Companies

Best Places to Work
for LGBTQ Equality

Military Friendly
Employer

Best for Vets

Benefits

Xcel Energy offers a competitive benefits package, including: performance-
based compensation, supported by a management system
that
emphasizes ongoing coaching conversations. Benefits also include floating
holidays and recognition, retirement and holistic well-being programs.

to maintain a market
Management continuously evaluates benefits
competitive, performance-based, shareholder-aligned
rewards
total
package that supports our ability to attract, engage and retain a talented
and diverse workforce, while reinforcing and rewarding strong performance.

Diversity, Equity, Inclusion and Human Rights

We aim to create an inclusive culture where employees are treated
equitably, and diversity is not only accepted but celebrated. This starts with
our Board of Directors, of which eight members were elected in the past
five years.

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.

In 2021, nearly all offers made had diverse hiring panels and executive
sponsors consistently met with their employee counterparts at least
monthly. We have also disclosed our Equal Employment Opportunity
Employer Information Report (EEO-1).

Our CEO and senior executives lead by example, fostering an open and
inclusive work environment through their interactions, communications and
personal sponsorship of diverse talent throughout the organization.

We partner with educational and community organizations to attract and
hire diverse employees who reflect the communities we serve and live our
values. Workforce demographics as of December 2021 (unless otherwise
noted):

Board of Directors

(a)

CEO direct reports

(a)

Management

Employees

New hires

Interns (hired throughout 2021)
(a)

Demographics as of Feb. 1, 2022.

Female

Ethnically Diverse

23 %

36 %

22 %

24 %

39 %

34 %

15 %

18 %

11 %

17 %

26 %

27 %

Utility Subsidiaries

NSP-Minnesota

Electric customers

Natural gas customers

Total assets

Rate Base (estimated)

1.5 million

0.5 million

$22.8 billion

$13.7 billion

ROE (net income / average stockholder's equity)

8.45%

Electric generating capacity

Gas storage capacity

Electric transmission lines (conductor miles)

Electric distribution lines (conductor miles)

Natural gas transmission lines

Natural gas distribution lines

NSP-Wisconsin

Electric customers

Natural gas customers

Total assets

Rate Base (estimated)

8,628 MW
17.1 Bcf

34,155 miles

81,406 miles

85 miles

10,741 miles

0.3 million

0.1 million

$3.1 billion

$2.0 billion

ROE (net income / average stockholder's equity)

9.92%

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

3.8 Bcf

12,409 miles

27,701 miles

3 miles

2,526 miles

1.5 million

$22.0 billion

$14.0 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

SPS

Electric customers

Total assets

Rate Base (estimated)

6,228 MW

32.5 Bcf

24,116 miles

78,712 miles

2,174 miles

23,243 miles

0.4 million

$9.3 billion

$6.4 billion

ROE (net income / average stockholder's equity)

9.22%

Electric generating capacity
Electric transmission lines (conductor miles)

Electric distribution lines (conductor miles)

5,249 MW

40,754 miles

22,651 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
retail customers and
natural gas
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
transports
to
customer-owned natural gas.

customers

retail

and

SPS conducts business in Texas and New
Mexico
purchases,
transmits, distributes and sells electricity.

generates,

and

Operations Overview

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 115,474 (millions of KWh), 3.7 million customers and electric revenues of $11,205 (millions of dollars) for 2021.

Retail Sales/Revenue Statistics (a)

Owned and Purchased Energy Generation — 2021

KWh sales per retail customer

Revenue per retail customer

Residential revenue per KWh

Large C&I revenue per KWh

Small C&I revenue per KWh

Total retail revenue per KWh

2021

2020

23,968

23,910

2,405

2,199

12.94 ¢

12.12 ¢

6.60 ¢

10.47 ¢

10.03 ¢

5.78 ¢

9.56 ¢

9.20 ¢

(a)

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

Electric Energy Sources

Total electric energy generation by source (including energy market purchases) for the year ended Dec. 31, 2021:

* Distributed generation from the Solar*Rewards® program is not included (approximately 666 million KWh for 2021).

Sales VolumeResidential23%C&I54%Sales for Resale22%Other 1%Number of CustomersC&I12%Other2%Residential86%RevenuesResidential31%C&I48%Other21%68%74%67%56%32%26%33%44%OwnedPurchasedXcel EnergyNSP SystemPSCoSPSXcel EnergyCoal25%NaturalGas 26%Carbon–Free*49%NSP SystemCoal18%NaturalGas 22%Carbon–Free60%PSCoCoal32%NaturalGas 29%Carbon–Free39%SPSCoal28%NaturalGas 32%Carbon–Free40%

Carbon-Free

Xcel Energy’s carbon-free energy portfolio
includes wind, nuclear,
hydroelectric, biomass and solar power from both owned generation
facilities and PPAs. Carbon-free percentages will vary year-over-year
based on system additions, commodity costs, weather, system demand
and transmission constraints.

See Item 2 — Properties for further information.

Carbon-free energy as a percentage of total energy for 2021:

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

Utility Subsidiary

NSP System

PSCo

SPS

Wind Development

2021

2020

Xcel Energy placed approximately 500 MW of owned wind and
approximately 255 MW of PPAs into service during 2021:

Project

Utility Subsidiary

Capacity (MW)

Blazing Star 2

Freeborn

Mower

Various PPAs
(a)

(b)

(c)

NSP-Minnesota

Various

(a)(b)

200

(a)(b)

200

(a)(b)

91
~255 (c)

Summer 2021 net dependable capacity.

Values disclosed are the maximum generation levels. Capacity is attainable only when
wind conditions are sufficiently available (on-demand net dependable capacity is zero).

Based on contracted capacity.

Xcel Energy currently has approximately 1,050 MW of owned wind under
development or being repowered.
to add
approximately 200 MW of planned PPAs.

In addition, we expect

Project

Northern Wind

Nobles

Dakota Range

Grand Meadow

Border Winds

Pleasant Valley

Various PPAs

Utility
Subsidiary

Capacity
(MW)

Estimated
Completion

NSP-Minnesota

Various

100

200

300

100

150

200

~200

2022

(a)

2023

2025

2022

(a)

Placed in service in January 2022.

Solar

Solar PPA(s):

Type

Distributed Generation

Utility-Scale

Distributed Generation

Utility-Scale

Distributed Generation

Utility-Scale

Total

Utility Subsidiary

Capacity (MW)

NSP System

PSCo

SPS

994

268

736

562

192

2,767

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

Utility Subsidiary

NSP System

PSCo

SPS

2021

2020

* Includes biomass and hydroelectric.

Wind

Owned — Owned and operated wind farms with corresponding capacity:

Utility
Subsidiary

NSP System

PSCo

SPS

Total

Wind Farms

2021
Capacity (MW) (a)
2,031

1,059

984

4,075

2020
Capacity (MW) (b)
1,540

1,059

967

3,566

Wind Farms

(a)

Summer 2021 net dependable capacity.

(b)

Summer 2020 net dependable capacity.

PPAs — Number of PPAs with capacity range:

Utility
Subsidiary

NSP System
PSCo

SPS

2021

2020

PPAs

Range (MW)

PPAs

Range (MW)

128
17

1 — 206
23 — 301

1 — 250

129
17

1 — 206
23 — 301

1 — 250

Capacity — Wind capacity (MW):

Utility Subsidiary

NSP System

PSCo

SPS

2021

3,997

4,085

2,548

2020

3,348

4,085

2,535

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

Utility Subsidiary

NSP System

PSCo

SPS

2021

2020

49%60%39%40%30%23%33%38%3%4%4%2%13%27%3%6%2%Other *NuclearSolarWindXcel Energy Inc.NSP SystemPSCoSPS

Solar Development

In June 2021, the PSCW approved NSP-Wisconsin’s request to purchase
the 74 MW Western Mustang build-own-transfer solar
for
approximately $100 million. Also, as part of the Minnesota Recovery and
Relief Recovery docket, NSP-Minnesota proposed to add 460 MW of solar
facilities at the Sherco site with an incremental investment of approximately
$575 million. An MPUC decision is expected by the third quarter of 2022.

facility

PSCo placed approximately 260 MW of PPAs into service during 2021.

Nuclear

Xcel Energy has two nuclear plants with approximately 1,700 MW of total
2021 net summer dependable capacity that serves 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:

Utility Subsidiary

NSP System

2021

2020

Other

Nuclear

Cost

Percent

0.77

0.80

46 %

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 6,500 MW of
total 2021 net summer dependable capacity.

Approved early coal plant retirements:

Year

Utility Subsidiary

Plant Unit

Capacity (MW)

2022

2023

2024

2025

2026

2028

2030

(a)

(b)

PSCo

NSP-Minnesota

SPS

PSCo

NSP-Minnesota

PSCo

NSP-Minnesota

Comanche 1

Sherco 2
Harrington (a)
Comanche 2

Craig 1

Sherco 1

Craig 2

A.S. King

Sherco 3

325

682

1,018

335
42 (b)
680
40 (b)
511
517 (b)

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

Harrington cease use of coal fuel by Jan. 1, 2025, pending PUCT and NMPRC review.

Based on Xcel Energy’s ownership interest.

Year

Utility Subsidiary

Plant Unit

Proposed

PSCo
PSCo
PSCo
SPS
SPS
PSCo

(a)

Pawnee
Hayden 2
Hayden 1
Tolk 1
Tolk 2
Comanche 3

Capacity (MW)
505
98 (b)
135 (c)
532
535
500

(d)

Reflects conversion from coal to natural gas.

Based on PSCo’s ownership of 37% of Unit 2.

Based on PSCo’s ownership of 76% of Unit 1.

Based on PSCo’s ownership of 67%.

2025
2027
2028
2034
2034
2034
(a)

(b)

(c)

(d)

Coal Fuel Cost

Delivered cost per MMBtu of coal consumed for owned electric generation
and the percentage of fuel requirements:

Utility Subsidiary

NSP System

2021

2020

PSCo

2021

2020

SPS

2021

2020
(a)

Coal (a)

Cost

Percent

1.60

1.97

1.43

1.41

2.07

2.28

39 %

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

Natural Gas

Xcel Energy has 22 natural gas plants with approximately 7,900 MW of
total 2021 net summer dependable capacity.

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:

Natural Gas

Cost

Percent

4.98

2.67

8.38

3.01

6.72

1.43

15 %

Utility Subsidiary

NSP System
(a)

2021

2020

PSCo
(a)

2021

2020

SPS

(a)

2021

2020
(a)

Reflective of Winter Storm Uri.

Capacity and Demand

Notable upcoming projects:

Uninterrupted system peak demand and occurrence date for the regulated
utilities:

System Peak Demand (MW)

2021

8,837

6,958

4,054

June 9

July 28

Aug. 9

2020

8,571

6,899

4,195

July 8

Aug. 17

July 14

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 more than 111,000 conductor miles of transmission lines,
serving 22,000 MW of customer load, across its service territory.

Transmission projects completed in 2021 include:

Project

Utility Subsidiary

Miles

Size (KV)

Hibbing Taconite Relocation

Huntley - Wilmarth

Helena Scott County

Centerville to Lincoln County

Turtle Lake Almena

NSP-Minnesota

NSP-Wisconsin

Roadrunner-China Draw

SPS

500

345

Project

Utility Subsidiary Miles

Size (KV)

Completion Date

Baytown to Long Lake

NSP-Minnesota

115

Bird Island - Atwater - Big
Swan

Pipestone - Tracy

NSP-Minnesota

Line Rebuild - Central

NSP-Minnesota

West St. Cloud to
Millwood Tap
Bayfield Second Circuit
Colorado Energy Plan

Tolk Plant Substation

Bus Reconfiguration

Twist to Wilco Line

Pathway

NSP-Minnesota
NSP-Wisconsin
PSCo

SPS

PSCo

24
19
15

n/a

560

69
35
345

345, 230

115

345

See Item 2 - Properties for further information.

Distribution

2022

2022
2022
2022

2022

2024

2027

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. Over the multi-year project that started
in 2016, Xcel Energy plans
invest approximately $1.7 billion
implementing new network
infrastructure, smart meters, advanced
software, equipment sensors and related data analytics capabilities. To
date, Xcel Energy has spent approximately $568 million on these
investments.

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 405,895 (thousands of MMBtu), 2.1 million customers and natural gas
revenues of $2,132 (millions of dollars) for 2021.

Sales/Revenue Statistics (a)

MMBtu sales per retail customer

Revenue per retail customer

Residential revenue per MMBtu

C&I revenue per MMBtu

2021

2020

114

917

8.61

7.20

1.20

118

720

6.64

5.22

0.67

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

2021

(a)

Date

2020

MMBtu

Date

NSP-Minnesota

NSP-Wisconsin
PSCo

899,133

167,656
2,316,283

Feb. 11

Feb. 11
Feb. 14

871,921

150,320
1,931,888

Jan. 16

Dec. 24
Feb. 4

(a)

Reflective of Winter Storm Uri.

Natural Gas Supply and Cost

Xcel Energy seeks natural gas supply,
transportation and storage
alternatives to yield a diversified portfolio, which increase flexibility,
decrease interruption, financial risks and customer rates. In addition, the
utility subsidiaries conduct natural gas price hedging activities approved by
their states’ commissions.

Average delivered cost per MMBtu of natural gas for regulated retail
distribution:

Utility Subsidiary

NSP-Minnesota

NSP-Wisconsin

PSCo

(a)

Reflective of Winter Storm Uri.

(a)

2021

2020

7.48

7.11

6.06

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 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.

3.32

3.08

2.52

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.

DeliveriesResidential:36%C&I: 23%Transportationand Other:41%Number of CustomersResidential: 92%C&I: 8%Transportationand Other: —%RevenuesResidential:59%C&I: 31%Transportationand Other:9%

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
the
of competing suppliers or non-contracted quantities and use
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.

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.

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
reporting
environmental
requirements.

related monitoring and

standards and

its generation,

However, it is not possible to determine what additional facilities or
modifications of existing or planned facilities will be required as a result of
changes to regulations, interpretations or enforcement policies or what
effect future laws or regulations may have. We may be required to incur
expenditures in the future for remediation of MGP and other sites.

Xcel Energy must comply with emission levels in Minnesota, Texas and
Wisconsin that may require the purchase of emission allowances. The
Denver North Front Range Non-attainment Area does not meet the ozone
NAAQS. Colorado will continue to consider further reductions available in
the non-attainment area as it develops plans to meet ozone standards.
Natural gas plants which operate in PSCo’s non-attainment area may be
required to improve or add controls, implement further work practices and/
or enhanced emissions monitoring as part of future Colorado state plans.

There are significant environmental regulations to encourage use of clean
energy technologies and regulate emissions of GHGs. We have undertaken
numerous initiatives to meet current requirements and prepare for potential
future regulations, reduce GHG emissions and respond to state renewable
and energy efficiency goals. Future environmental regulations may result in
substantial costs.

In July 2019, the EPA adopted the Affordable Clean Energy rule, which
requires states to develop plans by 2022 for GHG reductions from coal-
fired power plants. In January 2021, the U.S. Court of Appeals for the D.C.
Circuit issued a decision vacating and remanding the Affordable Clean
Energy rule. That decision would allow the EPA to proceed with alternate
regulation of coal-fired power plants. However, the Court of Appeals
decision is now before the U.S. Supreme Court, where the Court is
expected to rule on the nature and extent of the EPA’s GHG regulatory
authority. 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.

In October 2020, the TCEQ approved an agreement that SPS will convert
the Harrington plant from coal to natural gas by Jan. 1, 2025. This
conversion is necessary to attain Federal Clean Air Act standards for
emissions of SO2.

Xcel Energy seeks to address climate change and potential climate change
regulation through efforts to reduce its GHG emissions in a balanced, cost-
effective manner.

Emerging Environmental Regulation

New regulations and legislation are being considered to regulate PFAS in
drinking water, water discharges, commercial products, wastes, and other
areas. PFAS are man-made chemicals found in many consumer products
that can persist and accumulate in the environment. These chemicals have
received heightened attention from environmental regulators. Increased
regulation of PFAS and other emerging contaminants at the federal, state,
and local level could have a potential adverse effect on our operations but
at this time, it is uncertain what impact, if any, there will be on our
operations, financial condition or cash flows. Xcel Energy will continue to
monitor these regulatory developments and their potential impact on its
operations.

Environmental Costs

Environmental costs include amounts for nuclear plant decommissioning
and payments for storage of spent nuclear fuel, disposal of hazardous
materials and waste, remediation of contaminated sites, monitoring of
discharges to the environment and compliance with laws and permits with
respect to emissions.

Costs charged to operating expenses for nuclear decommissioning, spent
nuclear fuel disposal, environmental monitoring and remediation and
disposal of hazardous materials and waste were approximately:

•
•
•

$365 million in 2021.
$400 million in 2020.
$345 million in 2019.

for similar costs. The precise

Average annual expense of approximately $425 million from 2022 – 2026 is
timing and amount of
estimated
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:

Other

•
•
•

$60 million in 2021.
$30 million in 2020.
$30 million in 2019.

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.

Executive Officers (a)

Name

Robert C. Frenzel

Age (b)
51

Current and Recent Positions

Chairman of the Board of Directors, Xcel Energy Inc.

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.

Brett C. Carter

(d)

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 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

Senior Director, Talent & Organization Development, Kellogg Company, a food manufacturing company

Timothy O’Connor

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

Frank Prager

Amanda Rome

(e)

Jeffrey S. Savage
Brian J. Van Abel

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

Senior Vice President, Chief Nuclear Officer, Xcel Energy Services Inc

Senior Vice President, Strategy, Planning and External Affairs, Xcel Energy Inc.

Vice President, Policy and Federal Affairs, Xcel Energy Services 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.

Senior Vice President, Controller, Xcel Energy Inc.

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.

Time in Position
December 2021 — Present

August 2021 — Present

March 2020 — August 2021

May 2016 — March 2020

February 2012 — April 2016

May 2018 — Present

October 2015 — May 2018

February 2022 — Present

July 2019 — January 2022

March 2016 — July 2019

July 2015 — March 2016

August 2021 — Present

March 2020 — August 2021

February 2013 — March 2020

March 2020 — Present

January 2015 — March 2020

June 2020 — Present

October 2019 — June 2020

July 2018 — October 2019

January 2018 — July 2018

July 2015 — January 2018

January 2015 — Present

March 2020 — Present

September 2018 — March 2020

July 2015 — September 2018

(a)

(b)

(c)

(d)

(e)

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

Ages as of Feb. 23, 2022.

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.

Effective March 1, 2022, Mr. Carter will assume the role of Executive Vice President, Group President, Utilities, and Chief Customer Officer.

Effective March 1, 2022, Mr. Savage will assume the role of Chief Audit and Financial Services Officer and will no longer be serving as an executive officer.

The Audit Committee is responsible for reviewing the adequacy of the
committee’s risk oversight and affirming appropriate aggregate oversight
occurs. Committees regularly report on their oversight activities and certain
risk issues may be brought to the full Board of Directors for consideration
when deemed appropriate.

New risks are considered and assigned as appropriate during the annual
Board of Directors and committee evaluation process, resulting in updates
to the committee charters and annual work plans. Additionally, the Board
of Directors conducts an annual strategy session where Xcel Energy’s
future plans and initiatives are reviewed.

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
necessary supplies.
The impact of unusual or adverse weather conditions and natural
disasters, including, but not limited to, tornadoes, icing events, floods
and droughts.
Performance below expected or contracted levels of output or
efficiency (e.g., performance guarantees).
Availability of replacement equipment.
Availability of adequate water resources and ability to satisfy water
intake and discharge requirements.
Inability to identify, manage properly or mitigate equipment defects.
Use of new or unproven technology.
Risks associated with dependence on a specific type of fuel or fuel
source, such as commodity price risk, availability of adequate fuel
supply and transportation and lack of available alternative fuel
sources.
Increased competition due to, among other factors, new facilities,
excess supply, shifting demand and regulatory changes.

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 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 ensure

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

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

Our products contain components that are globally sourced from suppliers
who, in turn, source components from their suppliers. A shortage of key
components in which an alternative supplier is not identified could
significantly impact project plans. Such impacts could include timing of
projects, including potential for project cancellation. Failure to adhere to
project budgets and timelines could adversely impact our results of
operations, financial condition or cash flows.

We are subject to commodity risks and other risks associated with
energy markets and energy production.

In the event fuel costs increase, customer demand could decline and bad
debt expense may rise, which may have a material impact on our results of
operations. Despite existing fuel recovery mechanisms in most of our
states, higher fuel costs could significantly impact our results of operations
if costs are not recovered. Delays in the timing of the collection of fuel cost
recoveries could impact our cash flows and liquidity.

A significant disruption in supply could cause us to seek alternative supply
services at potentially higher costs and supply shortages may not be fully
resolved, which could cause disruptions in our ability to provide services to
our customers. Failure to provide service due to disruptions may also result
in fines, penalties or cost disallowances through the regulatory process.
Also, significantly higher energy or fuel costs relative to sales commitments
could negatively impact our cash flows and results of operations.

We also engage in wholesale sales and purchases of electric capacity,
energy and energy-related products as well as natural gas. In many
markets, emission allowances and/or RECs are also needed to comply with
various statutes and commission rulings. As a result, we are subject to
market supply and commodity price risk.

Commodity price changes can affect the value of our commodity trading
derivatives. We mark certain derivatives to estimated fair market value on a
daily basis. Settlements can vary significantly from estimated fair values
recorded and significant changes from the assumptions underlying our fair
value estimates could cause earnings variability. The management of risks
associated with hedging and trading is based, in part, on programs and
procedures which utilize historical prices and trends.

Due to the inherent uncertainty involved in price movements and potential
deviation from historical pricing, Xcel Energy is unable to fully assure that
its risk management programs and procedures would be effective to protect
against all significant adverse market deviations.

In addition, Xcel Energy cannot fully assure that its controls will be effective
limitation, employee
against all potential
misconduct. If such programs and procedures are not effective, Xcel
Energy’s results of operations, financial condition or cash flows could be
materially impacted.

including, without

risks,

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

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

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

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

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

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

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

technical employees

In 2021, the competition for talent has become increasingly intense as a
result of the ongoing “great resignation”, and we may experience increased
employee turnover due to this tightening labor market. In addition,
specialized knowledge
for
is required of our
construction and operation of transmission, generation and distribution
assets, which may pose additional difficulty for us as we work to recruit,
retain and motivate employees in this climate. Failure to hire and
adequately
transfer of
significant internal historical knowledge and expertise to new employees or
future availability and cost of contract labor may adversely affect the ability
to manage and operate our business. Inability to attract and retain these
employees could adversely impact our results of operations, financial
condition or cash flows.

train replacement employees,

including

the

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

We rely on third-party contractors to perform operations, maintenance and
construction work. Our contractual arrangements with these contractors
typically include performance standards, progress payments, insurance
requirements and security for performance. Poor vendor performance or
contractor unavailability could impact ongoing operations, restoration
operations, our reputation and could introduce financial risk or risks of fines.

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

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

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

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

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

•

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

The NRC has authority to impose licensing and safety-related requirements
for the operation of nuclear generation facilities, including the ability to
impose fines and/or shut down a unit until compliance is achieved. NRC
safety requirements could necessitate substantial capital expenditures or
an increase in operating expenses. In addition, the INPO reviews NSP-
Minnesota’s nuclear operations. Compliance with
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 earning a
return on capital investment. Our rates are generally regulated and are
based on an analysis of the utility’s costs incurred in a test year. The utility
subsidiaries are subject to both future and historical test years depending
upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge
may or may not match its costs at any given time. Rate regulation is
premised on providing an opportunity to earn a reasonable rate of return on
invested capital.

There can also be no assurance that our regulatory commissions will judge
all the costs of our utility subsidiaries to be prudent, which could result in
disallowances, or that the regulatory process will always result in rates that
will produce full recovery.

Overall, management believes prudently incurred costs are recoverable
given the existing regulatory framework. However, there may be changes in
the regulatory environment that could impair the ability of our utility
subsidiaries to recover costs historically collected from customers, or these
subsidiaries could exceed caps on capital costs required by commissions
and result in less than full recovery.

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

Higher than expected inflation or tariffs may increase costs of construction
and operations. Also, rising fuel costs could increase the risk that our utility
subsidiaries will not be able to fully recover their fuel costs from their
customers.

Adverse regulatory rulings or the imposition of additional regulations could
have an adverse impact on our results of operations and materially affect
our ability to meet our financial obligations, including debt payments and
the payment of dividends on common stock.

Any reductions in our credit ratings could increase our financing
costs and the cost of maintaining certain contractual relationships.

We cannot be assured that our current credit ratings or our subsidiaries’
ratings will remain in effect, or that a rating will not be lowered or withdrawn
by a rating agency. Significant events including disallowance of costs, 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 short-term 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 liquidity and an increase in bad debt expense.
Credit risk is comprised of numerous factors including the price of products
and services provided, the economy and unemployment rates.

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

Xcel Energy may have direct credit exposure in our short-term wholesale
and commodity trading activity to financial institutions trading for their own
accounts or issuing collateral support on behalf of other counterparties. We
may also have some indirect credit exposure due to participation in
organized markets, (e.g., California Independent System Operator, SPP,
PJM Interconnection, LLC, MISO and Electric Reliability Council of Texas),
in which any credit losses are socialized to all market participants.

We have additional indirect credit exposure to financial institutions from
letters of credit provided as security by power suppliers under various
purchased power contracts. If any of the credit ratings of the letter of credit
issuers were to drop below investment grade, the supplier would need to
replace that security with an acceptable substitute. If the security were not
replaced, the party could be in default under the contract.

Increasing costs of our defined benefit retirement plans and employee
benefits may adversely affect our results of operations, financial
condition or cash flows.

We have defined benefit pension and postretirement plans that cover most
of our employees. Assumptions related
future costs, return on
investments, interest rates and other actuarial assumptions have a
significant impact on our funding requirements of these plans. Estimates
and assumptions may change. In addition, the Pension Protection Act sets
the minimum funding requirements for defined benefit pension plans.
Therefore, our funding requirements and contributions may change in the
future. Also, the payout of a significant percentage of pension plan liabilities
in a single year, due to high numbers of retirements or employees leaving,
would trigger settlement accounting and could require Xcel Energy to
recognize incremental pension expense related to unrecognized plan
losses in the year liabilities are paid. Changes in industry standards utilized
in key assumptions (e.g., mortality tables) could have a significant impact
on future obligations and benefit costs.

Increasing costs associated with health care plans may adversely
affect our results of operations.

Increasing levels of large individual health care claims and overall health
care claims could have an adverse impact on our results of operations,
financial condition or cash flows. Health care legislation could also
significantly impact our benefit programs and costs.

We must rely on cash from our subsidiaries to make dividend
payments.

Investments in our subsidiaries are our primary assets. Substantially all of
our operations are conducted by our subsidiaries. Consequently, our
operating cash flow and ability to service our debt and pay dividends
depends upon the operating cash flows of our subsidiaries and their
payment of dividends.

Our subsidiaries are separate legal entities that have no obligation to pay
any amounts due pursuant to our obligations or to make any funds
available for dividends on our common stock. In addition, each subsidiary’s
ability to pay dividends depends on statutory and/or contractual restrictions
which may include requirements to maintain minimum levels of equity
ratios, working capital or assets.

If the utility subsidiaries were to cease making dividend payments, our
ability to pay dividends on our common stock or otherwise meet our
financial obligations could be adversely affected. Our utility subsidiaries are
regulated by state utility commissions, which possess broad powers to
ensure that the needs of the utility customers are met. We may be
negatively impacted by the actions of state commissions that limit the
payment of dividends by our utility subsidiaries.

Federal tax law may significantly impact our business.

Operations could be impacted by war, terrorism or other events.

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 local, national and worldwide
economic conditions, which correlates to customers/sales growth (decline).
Economic conditions may be impacted by insufficient financial sector
liquidity leading to potential increased unemployment, which may impact
customers’ ability to pay their bills, which could lead to additional bad debt
expense.

Our utility subsidiaries face competitive factors, which could have an
adverse impact on our financial condition, results of operations and cash
flows. Further, worldwide economic activity impacts the demand for basic
commodities necessary for utility infrastructure, which may inhibit our ability
to acquire sufficient supplies. We operate in a capital-intensive industry and
federal trade policy could significantly impact the cost of materials we use.
There may be delays before these additional material costs can be
recovered in rates.

We face risks related to health epidemics and other outbreaks, which
may have a material effect on our financial condition, results of
operations and cash flows.

impact countries,
The global outbreak of COVID-19 continues
communities, supply chains and markets. A high degree of uncertainty
continues to exist regarding the pandemic; the duration and magnitude of
business restrictions (domestically and globally); the potential shortages of
to quarantine policies,
employees and
vaccination requirements or government restrictions; re-shutdowns, if any,
and the level and pace of economic recovery.

third-party contractors due

Xcel Energy has experienced and may continue to experience sales
volatility and shifts between residential and C&I sales as a result of
COVID-19. Xcel Energy has a decoupling mechanism in Colorado for
residential and non-demand small C&I electric customer classes. In
Minnesota, Xcel Energy has historically had a sales true-up mechanism for
all electric customer classes which has ended in 2021. We are requesting
implementation of a new sales true-up mechanism for 2022 - 2024. These
mechanisms mitigate the impact of changes to sales levels as compared to
a baseline.

Although the financial impact of the pandemic on our financial results has
largely been mitigated, we cannot ultimately predict whether it will have a
material impact on our future liquidity, financial condition or results of
operations. Nor can we predict the impact of the virus on the health of our
employees, our supply chain or our ability to recover higher costs
associated with managing through the pandemic. The impact of COVID-19
may exacerbate other risks discussed herein, which could have a material
effect on us. The situation is evolving and additional impacts may arise.

Our generation plants, fuel storage facilities, transmission and distribution
facilities and information and control systems may be targets of terrorist
activities. Any disruption could impact operations or result in a decrease in
revenues and additional costs to repair and insure our assets. These
disruptions could have a material impact on our financial condition, results
of operations or cash flows.

The potential for terrorism has subjected our operations to increased risks
and could have a material effect on our business. We have already incurred
increased costs for security and capital expenditures in response to these
risks. The insurance industry has also been affected by these events and
the availability of insurance may decrease. In addition, insurance may have
higher deductibles, higher premiums and more restrictive policy terms.

A disruption of the regional electric transmission grid, interstate natural gas
pipeline infrastructure or other fuel sources, could negatively impact our
business, brand and reputation. Because our facilities are part of an
interconnected system, we face the risk of possible loss of business due to
a disruption caused by the actions of a neighboring utility.

We also face the risks of possible loss of business due to significant events
such as severe storms, severe temperature extremes, wildfires (particularly
in Colorado), widespread pandemic, generator or transmission facility
outage, pipeline rupture, railroad disruption, operator error, sudden and
significant increase or decrease in wind generation or a workforce
disruption.

In addition, major catastrophic events throughout the world may disrupt our
business. Xcel Energy participates in a global supply chain, which includes
materials and components that are globally sourced. A prolonged disruption
could result in the delay of equipment and materials that may impact our
ability to reliably serve our customers.

A major disruption could result in a significant decrease in revenues and
additional costs to repair assets, which could have a material impact on our
results of operations, financial condition or cash flows.

Xcel Energy participates in GridEx, which is the largest grid security
exercise in North America. These efforts, led by the NERC, test and further
develop the coordination, threat sharing and interaction between utilities
and various government agencies relative to potential cyber and physical
threats against the nation’s electric grid.

A cyber incident or security breach could have a material effect on
our business.

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.

individuals. During

The utility industry has been the target of several attacks on operational
systems and has seen an increased volume and sophistication of cyber
security incidents from international activist organizations, Nation States
the normal course of business, we have
and
experienced and expect to continue to experience attempts to compromise
our information technology and control systems, network infrastructure and
other assets. To date, no cybersecurity incident or attack has had a
material impact on our business or results of operation.

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

Xcel Energy’s generation, transmission systems and natural gas pipelines
are part of an interconnected system. Therefore, a disruption caused by the
impact of a cyber security incident of the regional electric transmission grid,
natural gas pipeline infrastructure or other fuel sources of our third-party
service providers’ operations, could also negatively impact our business.

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

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

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

Public Policy Risks

We may be subject to legislative and regulatory responses to climate
change, with which compliance could be difficult and costly.

Legislative and regulatory responses related to climate change may create
financial risk as our facilities may be subject to additional regulation at
either the state or federal level in the future. International agreements could
additionally lead to future federal or state regulations.

In 2015, the United Nations Framework Convention on Climate Change
reached consensus among 190 nations on an agreement (the Paris
Agreement) that establishes a framework for GHG mitigation actions by all
countries, with a goal of holding the increase in global average temperature
to below 2º Celsius above pre-industrial levels and an aspiration to limit the
increase to 1.5º Celsius.

In April 2021, ahead of the United Nations Climate Change Conference in
Glasgow, the Biden Administration committed the U.S. to a Nationally
Determined Contribution of 50-52% net GHG emissions reduction
economy-wide from 2005 levels. This commitment and other agreements
made in Glasgow could result in future additional GHG reductions in the
United States. In addition, the Biden Administration has announced plans to
implement new climate change programs, including potential regulation of
GHG emissions targeting the utility industry.

Many states and localities continue to pursue their own climate policies.
The steps Xcel Energy has taken to date to reduce GHG emissions,
including energy efficiency measures, adding renewable generation or
retiring or converting coal plants to natural gas, occurred under state-
endorsed resource plans, renewable energy standards and other state
policies.

We may be subject to climate change lawsuits. An adverse outcome could
require substantial capital expenditures and possibly require payment of
substantial penalties or damages. Defense costs associated with such
litigation can also be significant and could affect results of operations,
financial condition or cash flows if such costs are not recovered through
regulated rates.

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.

Our operating results may fluctuate on a seasonal and quarterly basis
and can be adversely affected by milder weather.

Increased risks of regulatory penalties could negatively impact our
business.

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.

The Energy Act increased civil penalty authority for violation of FERC
statutes, rules and orders. The FERC can impose penalties of up to $1.3
million per violation per day, particularly as it relates to energy trading
activities for both electricity and natural gas. In addition, NERC electric
reliability standards and critical infrastructure protection requirements are
mandatory and subject to potential financial penalties. Also, the PHMSA,
Occupational Safety and Health Administration and other federal agencies
have the authority to assess penalties.

In the event of serious incidents, these agencies may pursue penalties. In
addition, certain states have the authority to impose substantial penalties. If
a serious reliability, cyber or safety incident did occur, it could have a
material effect on our results of operations, financial condition or cash
flows.

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

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

We have committed to a number of long-term climate change goals, which
in part are dependent on future technologies not currently in existence.
Given the long-term nature of these goals, there is an inherent uncertainty
due to internal and external factors regarding our ability to achieve our
stated climate change goals. To the extent climate change goals are not
met, this could negatively impact our reputation and potentially result in
financial risk.

impacts our service

Severe weather
territories, primarily when
thunderstorms, flooding, tornadoes, wildfires and snow or ice storms occur.
Extreme weather conditions in general require system backup and can
contribute to increased system stress, including service interruptions.
Extreme weather conditions creating high energy demand may raise
electricity prices, increasing the cost of energy we provide to our
customers.

To the extent the frequency of extreme weather events increases, this
could
increase our cost of providing service. Periods of extreme
temperatures could impact our ability to meet demand. Changes in
precipitation resulting in droughts or water shortages could adversely affect
our operations. Drought conditions also contribute to the increase in wildfire
risk from our electric generation facilities.

While we carry liability insurance, given an extreme event, if Xcel Energy
was found to be liable for wildfire damages, amounts that potentially
exceed our coverage could negatively impact our results of operations,
financial condition or cash flows.

Drought or water depletion could adversely impact our ability to provide
electricity to customers, cause early retirement of power plants and
increase the cost for energy. Adverse events may result in increased
insurance costs and/or decreased insurance availability. We may not
recover all costs related to mitigating these physical and financial risks.

ITEM 1B — UNRESOLVED STAFF COMMENTS

None.

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

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

Environmental Risks

We are subject to environmental laws and regulations, with which
compliance could be difficult and costly.

We are subject to environmental laws and regulations that affect many
aspects of our operations,
including air emissions, water quality,
wastewater discharges and the generation, transport and disposal of solid
wastes and hazardous substances. Laws and regulations require us to
obtain permits, licenses, and approvals and to comply with a variety of
environmental requirements.

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

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.

NSP-Wisconsin
Station, Location and Unit at Dec. 31, 2021
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, 63 Units

Hydro

(b)

(a)

(b)

Summer 2021 net dependable capacity.

Refuse-derived fuel is made from municipal solid waste.

PSCo
Station, Location and Unit at Dec. 31, 2021

Fuel

Installed

MW (a)

(c)

Steam:

Comanche-Pueblo, CO

(b)

Unit 1

Unit 2

Unit 3

(d)

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

1973

1975

2010

1979 - 1980

1965 - 1976

1981

1968

2003

2015

Fort St. Vrain-Platteville, CO, 6 Units

Natural Gas

1972 - 2009

Rocky Mountain-Keenesburg, CO, 3 Units

Natural Gas

2004

Various locations, 8 Units

Natural Gas

Various

Hydro:

Cabin Creek-Georgetown, CO

Pumped Storage, 2 Units

Various locations, 8 Units

Wind:

Rush Creek, CO, 300 units

Cheyenne Ridge, CO, 229 units

Hydro

Wind

1967

Various

2018

2020

Total

(c)

(e)

(f)

325

335

500

233

505

310

264

576

973

580

251

210

(g)

582

477

6,228

(a)

(b)

(c)

(d)

(e)

(f)

(g)

Summer 2021 net dependable capacity.

In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in
2022 and 2025, respectively.
Based on PSCo’s ownership of 67%.

Craig Unit 1 and 2 are expected to be retired early in 2025 and 2028, respectively.

Based on PSCo’s ownership of 10%.

Based on PSCo’s ownership of 76% of Unit 1 and 37% of Unit 2.

Values disclosed are the generation levels at the point-of-interconnection. Capacity is
attainable only when wind conditions are sufficiently available (on-demand net
dependable capacity is zero).

ITEM 2 — PROPERTIES

Virtually all of the utility plant property of the operating companies is subject
to the lien of their respective first mortgage bond indentures.

NSP-Minnesota
Station, Location and Unit at Dec. 31, 2021

Fuel

Installed

(a)

Steam:
A.S. King-Bayport, MN, 1 Unit (f)
Sherco-Becker, MN (e)

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

Natural Gas

1987 - 2018

Blue Lake-Shakopee, MN, 6 Units

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

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, 134 Units

Pleasant Valley-Mower County, MN, 100
Units

Wind

2020

2021

2015

2020

2016

2020

2019

2021

2008

2020

2019

2021

2010

2015

Total

511

680

682

517

617

521

519

327

494

447

530

252

454

200

148

190

192

150

200

197

196

8,628

(d)

(a)

(b)

(c)

(d)

(e)

(f)

Summer 2021 net dependable capacity.

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

Refuse-derived fuel is made from municipal solid waste.

Values disclosed are the generation levels at the point-of-interconnection for these wind

units. Capacity is attainable only when wind conditions are sufficiently available (on-

demand net dependable capacity is zero).

A.S. King is expected to be retired early in 2028.
Sherco Unit 1, 2, and 3 are expected to be retired early in 2026, 2023 and 2030,

respectively.

SPS
Station, Location and Unit at Dec. 31, 2021

Fuel

Installed

MW (a)

ITEM 3 — LEGAL PROCEEDINGS

Steam:

Cunningham-Hobbs, NM, 2 Units

Harrington-Amarillo, TX, 3 Units

(b)

Jones-Lubbock, TX, 2 Units

Maddox-Hobbs, NM, 1 Unit

Nichols-Amarillo, TX, 3 Units

Plant X-Earth, TX, 4 Units
Tolk-Muleshoe, TX, 2 Units (d)
Combustion Turbine:

Natural Gas

1957 - 1965

225

Coal

1976 - 1980

1,018

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

207

334

Wind

2019

2020

Total

(c)

477

507

5,249

(a)

(b)

Summer 2021 net dependable capacity.
Harrington is expected to be converted to natural gas by the end of 2024.

(c)

(d)

Values disclosed are the generation levels at the point-of-interconnection for these wind
units. Capacity is attainable only when wind conditions are sufficiently available (on-
demand net dependable capacity is zero).
Tolk Unit 1 and 2 are proposed to be retired in 2034.

Electric utility overhead and underground transmission and distribution lines
at Dec. 31, 2021:

Conductor 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

13,570

2,300

640

—

8,086

6,644

34,155

—

2,943

—

1,778

—

1,818

5,870

—

4,978

12,141

—

5,075

1,830

12,409

24,116

—

11,688

9,763

—

14,880

4,423

40,754

81,406

27,701

78,712

22,651

Management is sometimes unable to estimate an amount or range of a
reasonably possible loss in certain situations, including but not limited to
when (1) the damages sought are indeterminate, (2) the proceedings are in
the early stages, or (3) the matters involve novel or unsettled legal theories.
In such cases, there is considerable uncertainty regarding the timing or
ultimate resolution of such matters, including a possible eventual loss.

For current proceedings not specifically reported herein, management does
not anticipate that the ultimate liabilities, if any, would have a material effect
on Xcel Energy’s consolidated financial statements. Legal fees are
generally expensed as incurred.

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

ITEM 4 — MINE SAFETY DISCLOSURES

None.

PART II

ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY,
RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES.

Stock Data

Xcel Energy Inc.’s common stock is listed on the Nasdaq Global Select
Market (Nasdaq). The trading symbol is XEL. The number of common
stockholders of record as of Feb. 17, 2022 was approximately 49,137.

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

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

Total

115,561

40,110

102,828

63,405

Comparison of Five Year Cumulative Total Return*

Electric utility transmission and distribution substations at Dec. 31, 2021:

NSP-Minnesota

NSP-Wisconsin

PSCo

SPS

Quantity

354

204

237

458

Natural gas utility mains at Dec. 31, 2021:

Miles

NSP-Minnesota

NSP-Wisconsin

PSCo

SPS

WGI

Transmission

Distribution

10,741

2,174

2,526

23,243

—

* $100 invested on Dec. 31, 2016 in stock or index — including

reinvestment of dividends. Fiscal years ended Dec. 31.

Xcel Energy Inc.EEI ElectricsS&P 500201620172018201920202021$80$100$120$140$160$180$200$220$240

Purchases 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.

2021
GAAP and
Ongoing Diluted
EPS

2020
GAAP and
Ongoing Diluted
EPS

1.22

1.12

0.59

0.20

0.05

3.18

(0.22)

2.96

1.11

1.12

0.56

0.20

0.05

3.04

(0.25)

2.79

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

2021 Comparison with 2020

Xcel Energy — GAAP and ongoing earnings increased $0.17 per share for
2021. The increase was driven by capital investment recovery and other
regulatory outcomes, partially offset by increases in depreciation and lower
AFUDC. Fluctuations in electric and natural gas revenues associated with
changes in fuel and purchased power and/or natural gas sold and
transported generally do not significantly impact earnings (changes in
revenues are offset by the related variation in costs).

PSCo — Earnings increased $0.11 per share for 2021, driven by capital
investment recovery and other regulatory outcomes. Higher revenues were
partially offset by increased depreciation, O&M expenses and other taxes
(other than income taxes).

NSP-Minnesota — Earnings were flat for 2021 compared to 2020,
reflecting capital investment recovery offset by additional depreciation and
interest charges.

SPS — Earnings increased $0.03 per share for 2021, largely related to
capital investment recovery, other regulatory outcomes and higher sales
and demand, partially offset by decreased AFUDC.

NSP-Wisconsin — Earnings were flat for 2021 compared to 2020.

Xcel Energy Inc. and Other — Primarily includes financing costs at the
holding company, offset by earnings from EIP investments.

For the quarter ended Dec. 31, 2021, no equity securities that are
registered by Xcel Energy Inc. pursuant to Section 12 of the Securities
Exchange Act of 1934 were purchased by or on behalf of us or any of our
affiliated purchasers.

ITEM 6 — [RESERVED]

ITEM 7 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Non-GAAP Financial Measures

includes

financial

following discussion

information prepared

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 excludes (or
includes) amounts that are adjusted from measures calculated and
presented in accordance with GAAP.

Xcel Energy’s management uses non-GAAP measures for financial
planning and analysis, for reporting of results to the Board of Directors, in
determining performance-based compensation and communicating its
earnings outlook to analysts and investors. Non-GAAP financial measures
are intended to supplement investors’ understanding of our performance
and should not be considered alternatives for financial measures presented
in accordance with GAAP. These measures are discussed in more detail
below and may not be comparable to other companies’ similarly titled non-
GAAP financial measures.

Ongoing ROE

Ongoing ROE is calculated by dividing the net income or loss of Xcel
Energy or each subsidiary, adjusted for certain nonrecurring items, by each
entity’s average stockholder’s equity. We use these non-GAAP financial
measures to evaluate and provide details of earnings results.

Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing
Diluted EPS)

GAAP diluted EPS reflects the potential dilution that could occur if
securities or other agreements to issue common stock (i.e., common stock
equivalents) were settled. The weighted average number of potentially
dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS
is calculated using the treasury stock method. Ongoing earnings reflect
adjustments to GAAP earnings (net income) for certain items. Ongoing
diluted EPS is calculated by dividing the net income or loss of each
subsidiary, adjusted for certain items, by the weighted average fully diluted
Xcel Energy Inc. common shares outstanding for the period. Ongoing
diluted EPS for each subsidiary is calculated by dividing the net income or
loss of such subsidiary, adjusted for certain items, by the weighted average
fully diluted Xcel Energy Inc. common shares outstanding for the period.

We use these non-GAAP financial measures to evaluate and provide
details of Xcel Energy’s core earnings and underlying performance. We
believe these measurements are useful to investors to evaluate the actual
and projected financial performance and contribution of our subsidiaries.
For the years ended Dec. 31, 2021 and 2020, there were no such
adjustments to GAAP earnings and therefore GAAP earnings equal
ongoing earnings.

Changes in Diluted EPS

Components significantly contributing to changes in EPS:

Diluted Earnings (Loss) Per Share

GAAP and ongoing diluted EPS — 2020

Dec. 31

2.79

2021 vs. 2020

Components of change — 2021 vs. 2020

Higher electric revenues, net of electric fuel and purchased power
Lower ETR (a)
Higher natural gas revenues, net of cost of natural gas sold and
transported

Changes in taxes (other than income taxes)

Lower AFUDC

Higher depreciation and amortization

Other (net)

GAAP and ongoing diluted EPS — 2021

0.26

0.17

0.15

(0.03)

(0.10)

(0.24)

(0.04)

2.96

(a)

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

ROE for Xcel Energy and its utility subsidiaries:

ROE

NSP-Minnesota

PSCo

SPS

NSP-Wisconsin

Operating Companies

Xcel Energy

2021

2020

GAAP and Ongoing ROE

8.45 %

8.23

9.22

9.92

8.58

10.58

9.20 %

8.06

9.54

10.52

8.87

10.59

Statement of Income Analysis

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

Estimated Impact of Temperature Changes on Regulated Earnings —
Unusually hot summers or cold winters increase electric and natural gas
sales, while mild weather reduces electric and natural gas sales. The
estimated impact of weather on earnings is based on the number of
customers, temperature variances, the amount of natural gas or electricity
historically used per degree of temperature and excludes any incremental
related operating expenses that could result due to storm activity or
vegetation management requirements. As a result, weather deviations from
normal levels can affect Xcel Energy’s financial performance. However,
sales true-up and decoupling mechanisms in Minnesota and Colorado
predominately mitigate the positive and adverse impacts of weather.

Degree-day or THI data is used to estimate amounts of energy required to
maintain comfortable indoor temperature levels based on each day’s
average temperature and humidity. HDD is the measure of the variation in
the weather based on the extent to which the average daily temperature
falls below 65° Fahrenheit. CDD is the measure of the variation in the
weather based on the extent to which the average daily temperature rises
above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit
is counted as one CDD, and each degree of temperature below 65°
Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service
territories, a THI is used in place of CDD, which adds a humidity factor to
CDD. HDD, CDD and THI are most likely to impact the usage of Xcel
Energy’s residential and commercial customers. Industrial customers are
less sensitive to weather.

Normal weather conditions are defined as either the 10, 20 or 30-year
average of actual historical weather conditions. The historical period of time
used in the calculation of normal weather differs by jurisdiction, based on
regulatory practice. To calculate the impact of weather on demand, a
demand factor is applied to the weather impact on sales. Extreme weather
variations, windchill and cloud cover may not be reflected in weather-
normalized estimates.

Percentage (decrease) increase in normal and actual HDD, CDD and THI:

HDD

CDD

THI

2021 vs.
Normal

2020 vs.
Normal

2021 vs. 2020

(6.6) %

12.2

26.8

(3.1) %

22.2

6.3

(4.3) %

(9.2)

20.7

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

2021 vs.
Normal

2020 vs.
Normal

2021 vs.
2020

0.096

0.090

0.006

(0.066)

(0.041)

(0.025)

0.030

0.049

(0.019)

(0.025)

(0.011)

(0.014)

0.005

0.038

(0.033)

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

2021 vs. 2020

PSCo

NSP-
Minnesota

SPS

NSP-
Wisconsin

Xcel
Energy

— %

2.2 %

(4.7) %

0.5 %

0.3 %

0.4

0.3

(1.1)

2.3

2.2

2.9

1.4

3.6

2.7

2.0

1.4

(4.0)

N/A

(5.0)

(2.2)

2021 vs. 2020

PSCo

NSP-
Minnesota

SPS

NSP-
Wisconsin

Xcel
Energy

1.5 %
0.4

0.8

1.3

0.3 %
1.7

1.2

(1.0) %
3.3

2.5

(2.2)

N/A

(0.2) %
3.3

2.2

(4.1)

0.5 %
1.9

1.4

(0.1)

2021 vs. 2020 (2020 Leap Year Adjusted)

PSCo

NSP-
Minnesota

SPS

NSP-
Wisconsin

Xcel
Energy

1.7 %
0.7

1.1

1.8

0.6 %
1.9

1.5

(0.7) %
3.6

2.7

(1.7)

N/A

0.1 %
3.6

2.5

(3.6)

0.8 %
2.1

1.7

0.4

Actual
Electric
residential

Electric C&I

Total retail
electric sales
Firm natural gas
sales

Weather-normalized
Electric
residential
Electric C&I

Total retail
electric sales
Firm natural gas
sales

Weather-normalized
Electric
residential
Electric C&I

Total retail
electric sales
Firm natural gas
sales

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

Weather-adjusted sales results for each of our utility subsidiaries in 2021
reflect improving economies as the adverse effects of COVID-19 lessen.
The recovery reflects increased sales in the C&I sector as businesses
return to a more normal level. Residential sales remain elevated from pre-
pandemic levels due to continuance of individuals working from home.

•

PSCo — Residential sales rose based on a 1.2% increase in
customers, combined with higher use per customer. The growth in C&I
sales was due to a 1.2% increase in customers, partially offset by
slightly lower use per customer, primarily in the services sector.
NSP-Minnesota — Residential sales growth reflects a 1.2% increase
in customers, partially offset by a lower use per customer. The growth
in C&I sales was due to a 0.9% increase in customers and higher use
per customer, primarily in the manufacturing, retail and services
sectors.
SPS — Residential sales declined as lower use per customer offset a
0.9% increase in customers. C&I sales increased due to a 0.5%
increase in customers and higher use per customer, primarily driven
by the oil and gas and professional services sectors.
NSP-Wisconsin — Residential sales growth was attributable to a 0.8%
increase in customer additions, partially offset by slightly lower use per
customer. The growth in C&I sales was due to a 1.1% increase in
customers, primarily led by increases in the manufacturing, health
care and retail trade sectors.

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

•

Natural gas sales primarily reflect a 1.2% increase in residential
customers and a 0.5% increase in C&I customers, partially offset by a
decrease in use per customer.

Electric Margin

Electric margin is presented as electric revenues less electric fuel and
purchased power expenses. Expenses incurred for electric fuel and
purchased power are generally recovered through various regulatory
recovery mechanisms. As a result, changes in these expenses are
generally offset in operating revenues.

Electric revenues and fuel and purchased power expenses are impacted by
fluctuations in the price of natural gas, coal and uranium. However, these
price fluctuations generally have minimal impact on earnings impact due to
fuel recovery mechanisms. In addition, electric customers receive a credit
for PTCs generated, which reduce electric revenue and income taxes.

Electric Revenues, Fuel and Purchased Power and Electric Margin

(Millions of Dollars)

Electric revenues

Electric fuel and purchased power

Electric margin

2021

2020

11,205

(4,733)

6,472

9,802

(3,512)

6,290

Changes in Electric Margin

(Millions of Dollars)
Non-fuel riders
Regulatory rate outcomes (Texas, Wisconsin, Colorado, New Mexico
and North Dakota)
Proprietary commodity trading, net of sharing
Sales and demand
PTCs flowed back to customers (offset by lower ETR)
Texas 2019 rate case surcharge
Estimated impact of weather (net of decoupling/sales true-up)
Other (net)

(c)

(a)

(b)

Increase in electric margin

2021 vs. 2020

221

114
40
29
(149)
(70)
(12)
9
182

(a)

(b)

(c)

Includes $27 million of net gains recognized in the first quarter of 2021, driven by market

changes associated with Winter Storm Uri. Additional amounts are primarily related to

long-term physical generation contracts, which have increased in value as a result of

higher energy prices.

Sales excludes weather impact, net of decoupling/sales true-up, and demand is net of

sales true-up.

Impact is due to the Texas rate case outcome, which resulted in a revenue increase that

was recognized in the third quarter of 2020 (largely offset by recognition of previously
deferred costs).

Natural Gas Margin

Natural gas margin is presented as natural gas revenues less the cost of
natural gas sold and transported. Expenses incurred for the cost of natural
gas sold are generally recovered through various regulatory recovery
mechanisms. As a result, changes in these expenses are generally offset in
operating revenues.

Natural gas expense varies with changing sales and the cost of natural gas.
However, fluctuations in the cost of natural gas generally have minimal
earnings impact due to cost recovery mechanisms.

Natural Gas Revenues, Cost of Natural Gas Sold and Transported and
Natural Gas Margin

(Millions of Dollars)
Natural gas revenues
Cost of natural gas sold and transported

Natural gas margin

2021

2020

2,132
(1,081)
1,051

1,636
(689)
947

Changes in Natural Gas Margin

(Millions of Dollars)

2021 vs. 2020

Regulatory rate outcomes (Colorado and North Dakota)

Infrastructure and integrity riders

Conservation incentive

Estimated impact of weather

Other (net)

Increase in natural gas margin

(10)

104

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses decreased $3 million year-to-date.
Increases for distribution, wind farm maintenance and technology costs
were offset by a decrease in employee benefits expense (e.g., long term
incentives), additional Texas 2021 rate case deferrals and the year-over-
year impact of amounts associated with the Texas 2019 rate case
surcharge.

Depreciation and Amortization — Depreciation and amortization
increased $173 million year-to-date. The increase was primarily driven by
several wind farms going into service, normal system expansion and the
implementation of new depreciation rates in various states.

Other Income (Expense) — Other income (expense) increased $11 million
year-to-date. The change was largely related to gains associated with rabbi
trust performance (offset in O&M expenses).

AFUDC, Equity and Debt — AFUDC decreased $58 million year-to-date.
The decrease was driven by completion of various wind projects throughout
2020 and 2021.

Interest Charges — Interest charges increased $2 million year-to-date.
The increase was largely due to higher debt levels to fund capital
investments, partially offset by lower long-term and short-term interest
rates.

Earnings from Equity Method Investments — Earnings from equity
method investments increased $22 million year-to-date. The year-to-date
change was largely attributable to the performance of the EIP funds, which
invest in energy technology companies.

Income Taxes — Income tax benefit increased $64 million year-to-date.
The change was driven by an increase in wind PTCs due to additional wind
facilities going into service. Impact of PTCs was partially offset by an
increase in pretax earnings, lower plant regulatory differences and lower
non-plant accumulated deferred income tax amortization.

Xcel Energy Inc. and Other Results

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

Public Utility Regulation

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

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

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

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

NSP-Minnesota

Summary of Regulatory Agencies / RTO and Areas of Jurisdiction

Contribution (Millions of Dollars)

Regulatory Body / RTO

Xcel Energy Inc. financing costs
MEC (a)
Venture Holdings

(b)

Xcel Energy Inc. taxes and other results

Total Xcel Energy Inc. and other costs

2021

2020

(129) $

(147)

—

(12)

(5)

(120) $

(133)

Contribution (Diluted Earnings
(Loss) Per Share)

2021

2020

Xcel Energy Inc. financing costs

(0.24) $

(a)

MEC

Venture Holdings

(b)

Xcel Energy Inc. taxes and other results

—

0.04

(0.02)

Total Xcel Energy Inc. and other costs

(0.22) $

(a)

(b)

MEC was sold in the third quarter of 2020.

Amounts include gains or losses associated with EIP investments.

(0.28)

0.03

0.01

(0.01)

(0.25)

Xcel Energy Inc.’s results include interest charges, which are incurred at
Xcel Energy Inc. and are not directly assigned to individual subsidiaries.

2020 Comparison with 2019

A discussion of changes in Xcel Energy’s results of operations, cash flows
and liquidity and capital resources from the year ended Dec. 31, 2019 to
Dec. 31, 2020 can be found in Part II, “Item 7, Management’s Discussion
and Analysis of Financial Condition and Results of Operations” of our
Annual Report on Form 10-K for the fiscal year 2020, which was filed with
the SEC on Feb. 17, 2021. However, such discussion is not incorporated
by reference into, and does not constitute a part of, this Annual Report on
Form 10-K.

Additional Information
Retail rates, services, security issuances, property transfers,
mergers, disposition of assets, affiliate transactions, and other
aspects of electric and natural gas operations.

Reviews and approves Integrated Resource Plans for meeting
future energy needs.

Certifies the need and siting for generating plants greater than
50 MW and
in
Minnesota.

than 100 KV

lines greater

transmission

Reviews and approves natural gas supply plans.

Pipeline safety compliance.

Retail rates, services and other aspects of electric and natural
gas operations.

Regulatory authority over generation and transmission facilities,
along with the siting and routing of new generation and
transmission facilities in North Dakota.

Pipeline safety compliance.

Retail rates, services and other aspects of electric operations.

MPUC

NDPSC

South Dakota Public
Utilities Commission

Regulatory authority over generation and transmission facilities,
along with the siting and routing of new generation and
transmission facilities in South Dakota.

Pipeline safety compliance.

FERC

MISO

electric

operations,

Wholesale
licensing,
accounting practices, wholesale sales for resale, transmission of
interstate commerce, compliance with NERC
electricity
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
(a)

CIP Rider
Environmental
Improvement Rider

Renewable
Development Fund

RES

Renewable Energy
Rider

Additional Information

Recovers costs of conservation and DSM programs in Minnesota.

Recovers costs of environmental improvement projects in Minnesota.

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.

State Energy Policy
Rider

Recovers costs related to various energy policies approved by the
Minnesota legislature.

TCR

Recovers costs
distribution grid modernization.

for

investments

in electric

transmission and

Infrastructure Rider

Recovers costs for investments in generation and incremental
property taxes in South Dakota.

FCA (b)

Purchased Gas
Adjustment

GUIC Rider

Sales True-up

Minnesota, North Dakota and South Dakota include a FCA for
monthly billing adjustments to recover changes in prudently incurred
costs of fuel related items and purchased energy. Capacity costs are
recovered through base rates and are not recovered through the
FCA. MISO costs are generally recovered through either the FCA or
base rates.
Provides for prospective monthly rate adjustments for costs of
purchased natural gas, transportation and storage service. Includes a
true-up process for difference between projected and actual costs.
Recovers costs for transmission and distribution pipeline integrity
management programs, including funding for pipeline assessments,
deferred costs
integrity
management programs in Minnesota.

for sewer separation and pipeline

In February 2022, NSP-Minnesota filed the 2021 sales true-up
compliance report, resulting in a total surcharge of $59 million. An
MPUC ruling is anticipated in the second quarter of 2022. In their
current rate case, NSP-Minnesota has proposed a sales true-up
mechanism for 2022 and beyond that would operate similarly to the
2021 sales true-up. Under the stay-out petition, 2021 NSP-Minnesota
jurisdictional earnings was capped at a 9.06% ROE. Any excess
earnings are required to be refunded to customers.

2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota
filed a three-year electric rate case with the MPUC. The rate case is based
on a requested ROE of 10.2%, a 52.50% equity ratio and forward test
years.

The request is detailed as follows:
(Amounts in Millions, Except
Percentages)

2022

2023

2024

Total

Rate request

Increase percentage

Rate base

396

150

131

677

12.2 %

4.8 %

4.2 %

21.2 %

$ 10,931

$ 11,446

$ 11,918

N/A

In addition, NSP-Minnesota requested interim rates, subject to refund, of
$288 million to be implemented in January 2022 and an incremental $135
million to be implemented in January 2023. In December 2021, the MPUC
approved rates of $247 million to begin on Jan. 1, 2022. The adjusted level
reflects exigent circumstances from the COVID-19 pandemic.

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

•
•
•
•
•

Intervenor testimony: Oct. 3, 2022.
Rebuttal testimony: Nov. 8, 2022.
Public hearing: Dec. 13-16, 2022.
ALJ Report: March 31, 2023.
MPUC Order: June 30, 2023.

2021 North Dakota Natural Gas Rate Case — In September 2021, NSP-
Minnesota filed a request with the NDPSC for a natural gas rate increase of
$7 million, or 10.49%. The filing is based on a requested ROE of 10.5%, an
equity ratio of 52.54%, a 2022 forecast test year and a rate base of
approximately $140 million. Interim rates of $7 million, subject to refund,
were implemented on Nov. 1, 2021. An NDPSC decision is expected in
early fall 2022.

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

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

•
•
•

Intervenor testimony: March 1, 2022
Rebuttal testimony: April 1, 2022
Hearings: June 1-3, 2022

2020 North Dakota Electric Rate Case — In November 2020, NSP-
Minnesota filed a rate case with the NDPSC seeking a rate increase of $19
million based on a ROE of 10.2%, an equity ratio of 52.5% and rate base of
$677 million.

In August 2021, the NDPSC approved a settlement between NSP-
Minnesota and various parties, which includes the following, effective
Jan. 1, 2021:

•
•
•
•

•

Base revenue increase of $7 million.
ROE of 9.5%.
Equity ratio of 52.5%.
Deferral of advanced grid intelligence and security initiative capital and
O&M expenses.
An earnings cap mechanism, which would return to customers 100%
of earnings equal to or in excess of 9.75% ROE, effective until the
next rate case.

(a)

(b)

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

an annual cost-recovery mechanism.

The MPUC changed the FCA process in Minnesota (effective in 2020). Each month,

utilities collect amounts equal to baseline cost of energy set at the start of the plan year

(base would be reset annually). Monthly variations to baseline costs are tracked and

netted over a 12-month period. Utilities issue refunds above the baseline costs and can

seek recovery of any overage.

Pending and Recently Concluded Regulatory Proceedings

2022 Minnesota Natural Gas Rate Case — In November 2021, NSP-
Minnesota filed a request with the MPUC for an annual natural gas rate
increase of $36 million, or 6.6%. The filing is based on a 2022 forecast test
year and includes a requested ROE of 10.5%, rate base of $934 million and
an equity ratio of 52.50%.

In December 2021, the MPUC approved the requested interim rates of $25
million, subject to refund, beginning on Jan. 1, 2022.

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

•
•
•
•
•

Intervenor testimony: Aug. 30, 2022.
Rebuttal testimony: Oct. 4, 2022.
Public hearing: Nov. 1-4, 2022.
ALJ Report: Feb. 6, 2023.
MPUC Order: April 26, 2023.

Minnesota Relief and Recovery — In 2020, the MPUC opened a docket
and invited utilities in the state to submit potential projects that would create
jobs and help jump start the economy to offset the impacts of COVID-19.

The status of the various proposals is listed below:

•

In January 2021, the MPUC approved NSP-Minnesota’s request for
the repowering of 651 MW of owned wind projects and 20 MW of wind
projects under PPAs. These projects are estimated to save customers
approximately $160 million over the next 25 years.
In April 2021, NSP-Minnesota proposed to add 460 MW of solar
facilities at the Sherco site with an incremental investment of
approximately $575 million. An MPUC decision is expected by the
third quarter of 2022.
In June 2021, the MPUC approved NSP-Minnesota’s proposal to
acquire a repowered wind farm from ALLETE, Inc.
The MPUC is also considering NSP-Minnesota’s revised proposal to
provide $40 million of incremental electric vehicle rebates.

Minnesota Resource Plan — In July 2019, NSP-Minnesota filed its
Minnesota resource plan, which runs through 2034.

On Feb. 8, 2022, the MPUC approved the following:
•
•
•

10-year extension for the Monticello nuclear facility.
Retirement of the A.S. King plant in 2028 and Sherco 3 in 2030.
NSP-Minnesota ownership of Sherco and A.S. King gen-tie lines plus
additional renewable resources on the lines up to its current
interconnection rights (2,000 MW for Sherco and 600 MW for A.S.
King).
The need for 2,150 MW of new wind and 2,500 MW of new solar by
2032, as well as additional renewable generation of 1,100 MW beyond
2032.
Recognition of the need for 800 MW of additional firm dispatchable
resources between 2027 and 2029. The dispatchable generation will
need to be approved through a CON process.

•

The next Minnesota resource plan is due on Feb. 1, 2024.

2022 RES Electric Rider — In November 2021, NSP-Minnesota filed the
RES Rider. The requested amount of $264 million includes a true-up (2020
and 2021 riders) of $154 million and the 2022 requested amount of $110
million. The filing included a ROE of 9.06%. An MPUC decision is pending.

2021 RES Electric Rider — In November 2020, NSP-Minnesota filed the
RES Rider. The requested amount of $189 million includes a true-up (2019
and 2020 riders) of $96 million and the 2021 requested amount of $93
million. The filing included a ROE of 9.06%. An MPUC decision is pending.

2022 GUIC Natural Gas Rider — In October 2021, NSP-Minnesota filed the
GUIC Rider for an amount of $27 million based on a ROE of 9.04%. An
MPUC decision is pending.

2021 GUIC Natural Gas Rider — In October 2020, NSP-Minnesota filed the
GUIC Rider for an amount of $27 million based on a ROE of 9.04%. An
MPUC decision is pending.

2022 TCR Electric Rider — In November 2021, NSP-Minnesota filed the
TCR Rider for an amount of $105 million based on a ROE of 9.06%. An
MPUC decision is pending.

2020 TCR Electric Rider — In November 2019, NSP-Minnesota filed the
TCR Rider for an amount of $82 million based on a ROE of 9.06%, which
was approved by the MPUC in December 2021.

FERC NOPR on ROE Incentive Adders — In April 2021, the FERC issued
a NOPR proposing to limit collection of ROE incentive adders for RTO
membership to the first three years after an entity begins participation in an
RTO. If adopted as a final rule, NSP-Minnesota (as well as NSP-Wisconsin
and SPS) would prospectively discontinue charging their current 50 basis
point ROE incentive adders. Amounts related to a discontinuance of the
adder would ultimately be offset by an increase in retail rates, subject to
future rate cases.

Purchased Power Arrangements and Transmission Service Provider

NSP-Minnesota expects to use power plants, power purchases, CIP/DSM
options, new generation facilities and expansion of power plants to meet its
system capacity requirements.

Purchased Power — NSP-Minnesota has contracts to purchase power from
other utilities and
for
dispatchable resources typically require a capacity and an energy charge.

IPPs. Long-term purchased power contracts

NSP-Minnesota makes short-term purchases to meet system requirements,
replace company owned generation, meet operating reserve obligations or
obtain energy at a lower cost.

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

Nuclear Power Operations

Nuclear power plant operations produce gaseous,
liquid and solid
radioactive wastes, which are covered by federal regulation. High-level
radioactive wastes primarily include used nuclear fuel. Low-level waste
consists primarily of demineralizer resins, paper, protective clothing, rags,
tools and equipment contaminated through use.

NRC Regulation — The NRC regulates nuclear operations. Costs of
complying with NRC requirements can affect both operating expenses and
capital investments of the plants. NSP-Minnesota has obtained recovery of
these compliance costs and expects to recover future compliance costs.

Low-Level Waste Disposal — Low level waste disposal from Monticello and
PI is disposed at the Clive facility located in Utah and the Waste Control
Specialists facility in Texas. NSP-Minnesota has storage capacity available
on-site at PI and Monticello which would allow both plants to continue to
operate until the end of their current licensed lives if off-site low-level waste
disposal facilities become unavailable.

High-Level Radioactive Waste Disposal — The federal government has
responsibility to permanently dispose domestic spent nuclear fuel and other
high-level radioactive wastes. The Nuclear Waste Policy Act requires the
DOE to implement a program for nuclear high-level waste management.
This includes the siting, licensing, construction and operation of a
repository for spent nuclear fuel from civilian nuclear power reactors and
other high-level radioactive wastes at a permanent federal storage or
disposal facility. Currently, there are no definitive plans for a permanent
federal storage facility site.

Nuclear Spent Fuel Storage — NSP-Minnesota has interim on-site storage
for spent nuclear fuel at its Monticello and PI nuclear generating plants.
Authorized storage capacity is sufficient to allow NSP-Minnesota to operate
until the end of the operating licenses in 2030 for Monticello, 2033 for PI
Unit 1, and 2034 for PI Unit 2. Authorizations for additional spent fuel
storage capacity may be required at each site to support either continued
operation or decommissioning
federal government does not
commence storage operations.

the

Monticello CON — In September 2021, NSP-Minnesota filed an application
for a CON for additional spent fuel storage (existing independent spent fuel
storage installation) at the Monticello Nuclear Power Generating Plant. The
CON requests sufficient additional spent fuel storage at the existing
independent spent fuel storage installation to allow continued operation of
the Monticello Plant until 2040. The filing passed completeness review and
has been referred to an ALJ. A decision is expected in late 2023.

Wholesale and Commodity Marketing Operations

NSP-Minnesota conducts wholesale marketing operations, including the
purchase and sale of electric capacity, energy, ancillary services and
energy-related products. NSP-Minnesota uses physical and financial
instruments to minimize commodity price and credit risk and to hedge sales
and purchases.

NSP-Minnesota also engages in trading activity unrelated to hedging.
Sharing of any margins is determined through state regulatory proceedings
as well as the operation of the FERC approved joint operating agreement.
NSP-Minnesota does not serve any wholesale requirements customers at
cost-based regulated rates.

NSP-Wisconsin

Summary of Regulatory Agencies / RTO and Areas of Jurisdiction

Regulatory Body / RTO

PSCW

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.

MPSC

Certifies the need for new generating plants and electric
transmission lines before the facilities may be sited and built.

FERC

MISO

Pipeline safety compliance.

Wholesale electric operations, hydroelectric generation
licensing, accounting practices, wholesale sales for resale,
transmission of electricity in interstate commerce, compliance
with NERC electric reliability standards, asset transactions and
mergers and natural gas transactions in interstate commerce.

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

DOT

Pipeline safety compliance.

Recovery Mechanisms

Mechanism

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.

Pending and Recently Concluded Regulatory Proceedings

Wisconsin Electric and Natural Gas Settlement — In December 2021, the
PSCW approved a rate case settlement agreement and 2022 fuel cost plan
without modification. New rates and tariffs were effective Jan. 1, 2022. Key
elements of the settlement:

•

•
•
•

•

An increase in electric rates of $35 million (4.9%) for 2022 and an
incremental $18 million increase (2.5%) for 2023.
An increase in natural gas rates of $10 million (8.4%) for 2022 and an
incremental $3 million (2.3%) for 2023.
ROE of 9.80% for 2022 and 10.00% for 2023.
Equity ratio of 52.5% for both 2022 and 2023.
Returning $9 million in various net regulatory liabilities to offset
customer impacts in 2023.
Deferring certain pension and other post-employment benefit expense
in 2021 through 2023.
Incorporating an earnings sharing mechanism for 2022 and 2023.

Michigan Electric Rate Case — In January 2022, NSP-Wisconsin reached
an electric rate case settlement in principle with the MPSC staff and others.
The settlement grants NSP-Wisconsin an electric revenue increase of $1.6
million in 2022, based on a ROE of 9.7% and an equity ratio of 52.5%. The
MPSC is expected to rule on the settlement in the first quarter of 2022.

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

Pending and Recently Concluded Regulatory Proceedings

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

PSCo

Summary of Regulatory Agencies / RTO and Areas of Jurisdiction

Regulatory Body / RTO

Additional Information on Regulatory Authority

CPUC

FERC

RTO

DOT

SPP Western Energy
Imbalance Service
Market

Retail rates, accounts, services, issuance of securities and other
aspects of electric, natural gas and steam operations.

Pipeline safety compliance.

electric

operations,

Wholesale
practices,
hydroelectric licensing, wholesale sales for resale, transmission
of electricity in interstate commerce, compliance with the NERC
electric reliability standards, asset transactions and mergers and
natural gas transactions in interstate commerce.

accounting

Wholesale electric sales at cost-based prices to customers
inside PSCo’s balancing authority area and at market-based
prices to customers outside PSCo’s balancing authority area.

PSCo holds a FERC certificate that allows it to transport natural
gas in interstate commerce without PSCo becoming subject to
full FERC jurisdiction.

PSCo is not presently a member of an RTO and does not
operate within an RTO energy market. However, PSCo does
make certain sales
including SPP and
to other RTO’s,
participates in a joint dispatch agreement with neighboring
utilities.

Pipeline safety compliance.

Balances generation and load regionally and in real time for
participants in the Western Interconnection

Recovery Mechanisms

Mechanism

ECA

Purchased
Capacity Cost
Adjustment

Steam Cost
Adjustment

DSM Cost
Adjustment

Additional Information

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

Recovers purchased capacity payments.

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

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

interruptible service costs and

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

Wind Cost
Adjustment

Transmission

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

Recovers costs for customers who choose renewable resources.

Cost Adjustment Recovers costs for transmission investment between rate cases.
Clean Air Clean
Jobs Act

Recovers costs associated with the Clean Air Clean Jobs Act.

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.
Recovers costs for transmission and distribution pipeline integrity
management programs.

Mechanism to true-up revenue to a baseline amount for residential
(excluding lighting and demand) and metered non-demand small C&I
classes.
Recovers costs associated with the investment in and adoption of
transportation electrification infrastructure.

FCA

GCA

PSIA

Decoupling

Transportation
Electrification
Plan

Colorado Natural Gas Rate Case — In January 2022, PSCo filed a request
with the CPUC seeking a net increase to retail natural gas rates of $107
million. The total change to base rates is $215 million, reflecting the transfer
of $108 million previously recovered from customers through the PSIA
rider, which was closed to new investments at the end of 2021. The request
is based on a 10.25% ROE, an equity ratio of 55.66% and a 2022 current
test year. PSCo has requested a proposed effective date of Nov. 1, 2022.

Additionally, PSCo’s request includes step revenue increases of $40 million
in 2023 (effective Nov. 1, 2023) and $41 million in 2024 (effective Nov. 1,
2024) related to continued capital investment. Under this proposal, PSCo
would not request another base rate change prior to Nov. 1, 2025. An
informational historical test year, including a 10.75% ROE, was also filed as
required by the CPUC.

Revenue Request (millions of dollars)

2022

Changes since 2020 rate case:
(a)

Plant related investments

Operations and maintenance, amortization and other expenses

Property tax expense

Sales growth

Net increase to revenue

Previously authorized costs:

Transfer of costs previously recovered through the PSIA rider

Total base revenue request

210

(17)

215

(108)

107

3.6

Projected 2022 year-end rate base (billions of dollars)
(a)

Includes approximately $28 million as a result of the increase in ROE from 9.2% to
10.25%.

Colorado Electric Rate Request — In July 2021, PSCo filed a request with
the CPUC seeking a net electric rate increase of $343 million (or 12.4%).
The total request reflects a $470 million increase, which includes $127
million of previously authorized costs currently recovered through various
rider mechanisms. The request is based on a 10.0% ROE, an equity ratio
of 55.64%, a 2022 forecast test year, a rate base of $10.3 billion and
impacts of a new depreciation study.

In January 2022, PSCo reached an unopposed comprehensive settlement.
The CPUC is expected to rule on the settlement in March 2022 with final
rates expected to be effective in April 2022. Key settlement terms include:

•

•
•

•

A net electric rate increase of $177 million. The total change in base
rates is $299 million, which includes $122 million of revenue
previously collected through various rider mechanisms.
A ROE of 9.3% and an equity ratio of 55.69%.
A current 2021 test year (average rate base) with the transfer of
Cheyenne Ridge, Wildfire Mitigation Plan and Advanced Grid
Intelligence and Security investments at year-end rate base.
Approval of all of PSCo’s proposed depreciation adjustments.
Continuation of the property tax, qualified pension, and non-qualified
pension trackers.
Continuation of Advanced Grid Intelligence and Security deferral
including interest equivalent to PSCo's weighted average cost of
capital once the balance exceeds $50 million.
Continuation of the Wildfire Mitigation Plan deferral, with a debt return.

PSIA Rider Extension — In October 2021, the CPUC approved a
settlement agreement to allow the rider to end on Dec. 31, 2021, transfer
the investments recovered under the rider to base rates Jan. 1, 2022, and
defer $9 million of depreciation expense and return on $143 million in
project costs in 2022.

Pathway Transmission Expansion Settlement — In November 2021, PSCo
filed a non-unanimous settlement agreement with Staff and several other
parties regarding its CPCN request for the Pathway Transmission project.

Key settlement terms include:

•

The parties agreed that PSCo met the burden of proof demonstrating
that the project was needed to facilitate the renewables in the
Integrated Resource Plan and is in the public interest.
Agreed to a cost estimate of $1.7 billion and recovery through the
transmission rider.
The Pathway project will also include a Performance Incentive
Mechanism such that applicable costs in a given year above or below
a 5% dead band would allow for a ROE penalty or adder.
Parties agreed to conditional CPCN approval for 345 kV extension
project subject to the project being included in the final approved
Integrated Resource Plan with a cost estimate of $247 million.

The settlement agreement is currently being deliberated by the CPUC.

Resource Plan Settlement — In November 2021, PSCo and intervenors
filed a partial settlement of the resource plan, which will result in an
expected 87% carbon reduction and an 80% renewable mix by 2030. A
CPUC decision is expected in the first quarter of 2022. Key settlement
terms include:

•

•
•

•
•
•
•
•

Early retirement of Hayden: Unit 2 in 2027 (was 2036); and Unit 1 in
2028 (was 2030).
Conversion of Pawnee to burn natural gas by 2026.
Early retirement of Comanche 3 in 2034 with reduced operations
beginning in 2025.
Addition of ~2,300 MW of wind.
Addition of ~1,600 MW of utility-scale solar.
Addition of 400 MW of storage.
Addition of 1,300 MW of flexible, dispatchable generation.
Addition of ~1,200 MW of distributed solar resources through our
renewable energy programs.

Partial Settlement — In October 2021, PSCo filed a comprehensive
settlement with the CPUC Staff and the COEO, which proposed to address
four outstanding regulatory items, including recovery of fuel costs related to
Winter Storm Uri, disputed revenue associated with the 2020 electric
decoupling pilot program year, replacement power costs associated with an
extended outage at Comanche Unit 3 during 2020 and deferred customer
bad debt balances associated with COVID-19. The Utility Consumer
Advocate has not signed the settlement. A hearing and a CPUC decision
on the settlement is expected in the first quarter of 2022.

Key terms of the proposed settlement:

•

PSCo would fully recover Winter Storm Uri deferred net natural gas,
fuel and purchased energy costs of $263 million (electric utility) and
$287 million (natural gas utility) over a 24-month and 30-month period,
respectively, with no carrying charges through a rider mechanism.
Recovery would commence Jan. 1, 2022 for electric costs and April 1,
2022 for natural gas costs.
PSCo will refund electric customers $41 million (previously deferred)
related to the 2020 electric decoupling pilot program.
PSCo agreed to forego recovery of $14 million for replacement power
costs due to an extended outage at Comanche Unit 3 during 2020
(approved by the CPUC in February 2022 as part of the 2020 ECA
settlement agreement).
PSCo also agreed to not seek recovery of COVID-19 related bad debt
expense, previously deferred as a regulatory asset, and recorded an
additional $11 million of incremental bad debt expense for the period
ended Dec. 31, 2021.

Decoupling Filing — PSCo's 2019 Electric Rate Case
included a
decoupling program, effective April 1, 2020 through Dec. 31, 2023. The
program applies to Residential and metered small C&I customers who do
not pay a demand charge. The program includes a refund and surcharge
cap not to exceed 3% of forecasted base rate revenue for a specified
period.

In April 2021, PSCo made its annual filing for 2020, and the revised tariff
went into effect by operation of law on June 1, 2021. In the annual filing
review, the CPUC indicated they may pursue reopening the case in order to
revisit the cap. As of Dec. 31, 2021, PSCo has recognized a refund for
Residential customers and a surcharge for C&I customers based on 2020
and 2021 results.

In October 2021, a settlement was reached on Winter Storm Uri costs and
also addressed certain components of decoupling. See Partial Settlement
disclosure above for further discussion.

Comanche Unit 3 — PSCo is part owner and operator of Comanche Unit 3,
a 750 MW, coal-fueled electric generating unit. In January 2020, the unit
experienced a turbine failure causing the unit to be taken offline for repairs,
which were completed in June 2020. During start-up, the unit experienced a
loss of
the unit. Comanche Unit 3
recommenced operations in January 2021. Replacement and repair of
damaged systems in excess of a $2 million deductible are expected to be
recovered through insurance policies. PSCo incurred replacement power
costs of approximately $16 million during the outage.

turbine oil, which damaged

In October 2020, the CPUC initiated a review of Comanche Unit 3’s
performance. In March 2021, the CPUC Staff issued a report, which noted
higher-than average outages and included criticisms of PSCo’s operations
of Comanche Unit 3 over the last ten years. The report recommended
thorough explanation of the future of Comanche Unit 3 operations in the
next resource plan, performance standards
for all company-owned
generation and a review of outage and repair costs in upcoming ECA
proceedings.

In October 2021, a comprehensive settlement was reached, which
addressed treatment of 2020 Comanche Unit 3 replacement power costs.
See Partial Settlement disclosure above for further discussion.

2019 Electric Rate Case Appeal — In August 2020, PSCo filed an appeal
with the Denver District Court seeking a review of CPUC decisions on gains
and losses on sales of assets, oil and gas royalty revenues, Board of
Directors equity compensation and a true-up surcharge to collect the
difference between rates from February through August 2020 based on the
CPUC’s decision on the Company’s Application for Reconsideration,
Rehearing or Reargument and rates that were actually in place. In January
2022, the Denver District Court issued its decision that the CPUC’s
approach to gains and losses on certain sales of assets was legally
erroneous and confiscatory to PSCo and set aside and remanded the issue
for further consideration. The District Court affirmed the CPUC with respect
to the remaining decisions.

GCA NOPR — In June 2021, the CPUC issued a NOPR addressing the
recovery of costs through the GCA. The proposed rule would establish an
annual forecast of GCA costs for each utility and allow each utility to
recover only 90%-95% of any costs in excess of the forecasted amount.
The proposed rule would allow utilities to earn an incentive equal to an
undefined portion of any savings relative to forecasted costs. Comments
were filed and requested that the CPUC delay the rule making process
until after the 2021 - 2022 heating season; in part because utilities have
already proceeded with purchasing gas for the upcoming heating season in
accordance with prior CPUC decisions. The CPUC has reopened the GCA
NOPR matter and the parties will submit follow-up comments during the
first quarter of 2022.

Purchased Power and Transmission Service Providers

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

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

Energy Markets — PSCo plans to join the SPP Western Energy Imbalance
Service Market in April 2023. This market is an incremental step in the
participation in the organized wholesale market. Energy imbalance markets
allow participants to buy and sell power close to the time electricity is
real-time visibility across
consumed and gives system operators
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 and credit risk and hedge sales and purchases.
PSCo also engages in trading activity unrelated to hedging. Sharing of any
margin is determined through state regulatory proceedings as well as the
operation of the FERC approved 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.

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
integrated and
the SPP RTO and SPP
wholesale markets. SPS is authorized to make wholesale
electric sales at market-based prices.

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

TCR Factor

Fixed Fuel and
Purchased Recovery
Factor

Wholesale Fuel and
Purchased Energy Cost
Adjustment

Recovers deferred costs for renewable energy programs in New
Mexico.
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
FERC. Wholesale customers also pay
jurisdictional
allocation of production costs.

the

Pending and Recently Concluded Regulatory Proceedings

2021 New Mexico Electric Rate Case — In January 2021, SPS filed an
electric rate case with the NMPRC with a current requested base rate
increase of approximately $84 million.

In June 2021, SPS and various parties filed an uncontested stipulation with
the NMPRC, which reflected a $62 million rate increase, a change in the
depreciation life of the Tolk coal plant to 2032, an equity ratio of 54.72%
and ROE of 9.35% for reconciliation statements and determining the
revenue requirements for the Sagamore and Hale wind projects. In
December 2021, the Hearing Examiner issued a recommendation that the
NMPRC approve the rate case settlement agreement without modification.

On Feb. 2, 2022, the NMPRC voted 3-2 to reject the uncontested
stipulation as filed. The NMPRC then approved a modified settlement,
which would maintain the proposed revenue requirement increase of $62
million, but would adjust the class cost allocation such that all rate classes
would have a uniform increase of 4.89%. The NMPRC required the parties
to either file their acceptance or opposition to the modified settlement.

On Feb. 9, 2022, the signatories informed the NMPRC they did not
unanimously support the modifications. Accordingly, the Hearing Examiner
will issue a procedural order for further proceedings on SPS’ originally filed
application.

On Feb. 10, 2022, SPS filed a motion requesting the NMPRC either
approve the original settlement or approve the modified settlement.

Wholesale and Commodity Marketing Operations

SPS conducts various wholesale marketing operations, including the
purchase and sale of electric capacity, energy, ancillary services and
energy related products. SPS uses physical and financial instruments to
minimize commodity price and credit risk and to hedge sales and
purchases.

On Feb. 16, 2022, the NMPRC voted to reconsider its order and voted 3-2
to approve the stipulation without modification. New rates will go into effect
on Feb. 26, 2022.

Other Public Utility Matters

Comanche Unit 3 Outage

2021 Texas Rate Case — In February 2021, SPS filed an electric rate case
with the PUCT and its municipalities, seeking an increase in base rates of
approximately $140 million. SPS’ proposed net rate increase to Texas
customers was approximately $71 million, or 9.2%, as a result of the
offsetting $69 million in fuel cost reductions and PTCs from the Sagamore
wind project.

The request was based on a ROE of 10.35%, an equity ratio of 54.60%, a
rate base of approximately $3.3 billion and a historic test year based on the
12-month period ended Dec. 31, 2020. The request included the effect of
losing approximately 400 MW from a wholesale transmission customer and
changes to depreciation lives of SPS’ Tolk power plant (from 2037 to 2032)
and coal handling assets at the Harrington facility (to 2024).

In January 2022, SPS and intervenors filed a blackbox settlement. Key
terms include:

•

A base rate increase of approximately $89 million effective back to
March 15, 2021.
A 9.35% ROE and 7.01% weighted average cost of capital for AFUDC
purposes only.
The depreciation lives for Tolk moved up to 2034 and Harrington coal
assets moved up to 2024.

In February 2022, the ALJ issued an order approving interim rates to be
effective on March 1, 2022. A PUCT decision is expected in the first quarter
of 2022.

Purchased Power Arrangements and Transmission Service Providers

SPS expects to use electric generating stations, power purchases, DSM
and new generation options to meet its system capacity requirements.

Purchased Power — SPS purchases power from other utilities and IPPs.
Long-term purchased power contracts typically require periodic capacity
and energy charges. SPS also makes short-term purchases to meet
system load and energy requirements to replace owned generation, meet
operating reserve obligations or obtain energy at a lower cost.

Purchased Transmission Services — SPS has contractual arrangements
with SPP and regional transmission service providers to deliver power and
energy to its native load customers.

Natural Gas

SPS does not provide retail natural gas service, but purchases and
transports natural gas for its generation facilities and operates limited
natural gas pipeline facilities connecting the generation facilities to
interstate natural gas pipelines. SPS is subject to the jurisdiction of the
FERC with respect to natural gas transactions in interstate commerce and
the PHMSA and PUCT for pipeline safety compliance.

In January 2022, PSCo experienced an incident at the Comanche Unit 3
plant (750 MW, coal-fueled electric generating unit) resulting in damage
and an outage that is expected to last approximately two months. PSCo
has notified the CPUC and informed them that it will not seek recovery of
any replacement power costs above the expected costs if Comanche 3 had
been in service. The estimated incremental replacement power costs could
be approximately $10 million, assuming a two month outage, normal
weather and current market pricing.

Marshall Wildfire

In December 2021, a wildfire ignited in Boulder County, Colorado (the
“Marshall Fire”), which burned over 6,000 acres and destroyed or damaged
over 1,000 structures. While there were no downed power lines in the
ignition area, the determination of the cause of the Marshall Fire is pending.

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

However, in the unlikely event we were found liable, the damages awarded
could exceed our coverage and negatively impact our results of operations,
financial conditions or cash flows.

Winter Storm Uri

In February 2021, the United States experienced Winter Storm Uri.
Extreme cold temperatures impacted certain operational assets as well as
the availability of renewable generation. The cold weather also affected the
country’s supply and demand for natural gas. These factors contributed to
extremely high market prices for natural gas and electricity. As a result of
the extremely high market prices, Xcel Energy incurred net natural gas, fuel
and purchased energy costs of approximately $1 billion (largely deferred as
regulatory assets).

Regulatory Overview — Xcel Energy has natural gas, fuel and purchased
energy mechanisms in each jurisdiction for recovering incurred costs.
However, the utility subsidiaries have deferred February 2021 cost
increases for future recovery and sought recovery of the cost increases
over a period of up to 63 months to mitigate the impact to customer bills.
Additionally, we did not request recovery of financing costs in order to
further limit the impact to our customers.

Proceedings initiated:

Utility
Subsidiary
NSP-Minnesota Minnesota

Jurisdiction

Regulatory Status
NSP-Minnesota filed with the MPUC seeking recovery of $215 million in incremental costs from natural gas customers. In August 2021, the MPUC allowed
recovery of $179 million of costs deemed to be extraordinary beginning in September 2021 over 27 months (no financing charge) and $36 million of ordinary
costs over 12 months through the monthly Purchased Gas Adjustment. The $179 million in extraordinary cost recovery is subject to refund pending the
outcome of a contested case before an ALJ.

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

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

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

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

South Dakota Winter Storm Uri had no impact on South Dakota electric costs as NSP-Minnesota was a net seller in the electric market.

North Dakota

In June, the NDPSC approved recovery of $32 million in natural gas costs over 15 months (starting July 2021) with no financing charge.

NSP-Wisconsin Wisconsin

In March, the PSCW approved NSP-Wisconsin’s proposal to recover $45 million of Winter Storm Uri natural gas costs over nine months through December
2021 with no financing charge.

PSCo

Michigan

Colorado

In May, the MPSC approved recovery of $2 million in natural gas costs over 10 months with no financing charge.

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

In September, intervenors filed testimony. The CPUC Staff recommended disallowances of approximately $99 million (electric) and $105 million (natural gas).
Additionally, they proposed to net approximately $50 million of regulatory liabilities (decoupling related) from electric costs. The Utility Consumer Advocate
recommended disallowances of approximately $131 million. The COEO recommended disallowances of approximately $46 million for not utilizing demand
response programs during the event.

In October, a partial settlement was reached with the CPUC Staff and the COEO, allowing full recovery of Winter Storm Uri deferred net natural gas, fuel and
purchased energy costs of $263 million (electric utility) and $287 million (natural gas utility) over a 24-month and 30-month period, respectively, with no
carrying charges through a rider mechanism.

A decision is expected in the first quarter of 2022. In addition, the CPUC is considering prospective changes in fuel cost recovery.

SPS

Texas

As part of the Texas fuel surcharge filing, SPS filed for recovery of $76 million, over 24 months, in under-collected purchased power and fuel costs through
March 2021, subject to revision due to re-settlements. Of this amount, $62 million was attributed to Winter Storm Uri.

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

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

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

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

New Mexico

Potential Tax Reform

The U.S. Congress is currently discussing potential proposals that may
impact federal tax law. At this time, it is unknown what, if any, changes may
ultimately occur. Based on provisions passed by the U.S. House of
Representatives in November 2021, known as the Build Back Better Act, if
any of such provisions were to be enacted into law, we would not expect
the impact of such changes to have a material impact on our earnings.

Critical Accounting Policies and Estimates

requires

the consolidated

financial statements

Preparation of
the
application of accounting rules and guidance, as well as the use of
estimates. Application of these policies involves judgments regarding future
events, including the likelihood of success of particular projects, legal and
regulatory challenges and anticipated recovery of costs. These judgments
could materially impact the consolidated financial statements, based on
varying assumptions. In addition, the financial and operating environment
also may have a significant effect on the operation of the business and
results reported.

Accounting policies and estimates that are most significant to Xcel Energy’s
results of operations, financial condition or cash flows, and require
management’s most difficult, subjective or complex judgments are outlined
below. Each of these has a higher likelihood of resulting in materially
different reported amounts under different conditions or using different
assumptions. Each critical accounting policy has been reviewed and
discussed with the Audit Committee of Xcel Energy Inc.’s Board of
Directors on a quarterly basis.

Regulatory Accounting

Xcel Energy is subject to the accounting for Regulated Operations, which
provides that rate-regulated entities report assets and liabilities consistent
with the recovery of those incurred costs in rates, if it is probable that such
rates will be charged and collected. Our rates are derived through the
ratemaking process, which results in the recording of regulatory assets and
liabilities based on the probability of future cash flows.

Regulatory assets generally represent incurred or accrued costs that have
been deferred because future recovery from customers is probable.
Regulatory liabilities generally represent amounts that are expected to be
refunded to customers in future rates or amounts collected in current rates
for future costs. In other businesses or industries, regulatory assets and
regulatory liabilities would generally be charged to net income or other
comprehensive income.

Each reporting period we assess the probability of future recoveries and
obligations associated with regulatory assets and liabilities. Factors such as
the current regulatory environment, recently issued rate orders and
historical precedents are considered. Decisions made by regulatory
agencies can directly impact the amount and timing of cost recovery as well
as the rate of return on invested capital, and may materially impact our
results of operations, financial condition or cash flows.

At Dec. 31, 2021, in assessing the probability of recovery of recognized
regulatory assets, unless otherwise disclosed, Xcel Energy noted no
current or anticipated proposals or changes in the regulatory environment
that it expects will materially impact the 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, 2021, Xcel Energy set the rate of return on assets used to
measure pension costs at 6.49%, which is consistent with the rate set in
2020. The rate of return used to measure postretirement health care costs
is 4.10% at Dec. 31, 2021, which is consistent with the rate set in 2020.

As of Dec. 31, 2021 and 2020, Xcel Energy had regulatory assets of
$3.8 billion and $3.4 billion, respectively and regulatory liabilities of
$5.7 billion and $5.6 billion, respectively. Each subsidiary is subject to
regulation that varies from jurisdiction to jurisdiction. If future recovery of
costs in any such jurisdiction is no longer probable, Xcel Energy would be
required
income or other
comprehensive income.

to current net

these assets

to charge

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 at
3.08% and postretirement health care obligations at 3.09% at Dec. 31,
2021. This represents a 37 basis point and 44 basis point decrease,
respectively, from 2020. Xcel Energy uses a bond matching study as its
primary basis for determining the discount rate used to value pension and
postretirement health care obligations. The bond matching study utilizes a
portfolio of high grade (Aa or higher) bonds that matches the expected cash
flows of Xcel Energy’s benefit plans in amount and duration.

The effective yield on this cash flow matched bond portfolio determines the
discount rate for the individual plans. The bond matching study is validated
for reasonableness against the Merrill Lynch Corporate 15+ Bond Index. In
addition, Xcel Energy reviews general actuarial survey data to assess the
reasonableness of the discount rate selected.

If Xcel Energy were to use alternative assumptions, a 1% change would
result in the following impact on 2021 pension costs:

(Millions of Dollars)

Rate of return
Discount rate (a)

Pension Costs

+1%

-1%

(13) $

(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, 2021, the initial medical trend cost claim assumptions for
Pre-65 was 5.3% and Post-65 was 4.9%. The ultimate trend assumption
remained at 4.5% for both Pre-65 and Post-65 claims costs. Xcel Energy
bases its medical trend assumption on the long-term cost inflation expected
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 2021 were $131 million and are expected to
decline in the following years. Investment returns exceeded assumed levels
in 2021, 2020 and 2019.

The pension cost calculation uses a market-related valuation of pension
assets. Xcel Energy uses a calculated value method to determine the
market-related value of the plan assets. The market-related value is
determined by adjusting the fair market value of assets at the beginning of
the year to reflect the investment gains and losses (the difference between
the actual investment return and the expected investment return on the
market-related value) during each of the previous five years at the rate of
20% per year. As differences between actual and expected investment
returns are incorporated into the market-related value, amounts are
recognized in pension cost over the expected average remaining years of
service for active employees (approximately 13 years in 2021).

Xcel Energy currently projects the pension costs recognized for financial
reporting purposes will be $77 million in 2022 and $60 million in 2023, while
the actual pension costs were $121 million in 2021 and $117 million in
2020. The expected decrease in 2022 and future year costs is primarily due
to the reductions in loss amortizations.

Pension funding contributions across all four of Xcel Energy’s pension
plans, both voluntary and required, for 2019 - 2022:

•
•
•
•

$50 million in January 2022.
$131 million in 2021.
$150 million in 2020.
$154 million in 2019.

Future amounts may change based on actual market performance,
changes in interest rates and any changes in governmental regulations.
Therefore, additional contributions could be required in the future.

Xcel Energy contributed $15 million, $11 million and $15 million during
2021, 2020 and 2019, respectively, to the postretirement health care plans.
Xcel Energy expects to contribute approximately $9 million during 2022.
Xcel Energy recovers employee benefits costs in its utility operations
consistent with accounting guidance with the exception of the areas noted
below.

•

in all

In addition,

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
the Commission order approved escrow
expense.
accounting treatment for pension and other post-employment benefit
expenses.
Regulatory Commissions in Colorado, Texas, New Mexico and FERC
jurisdictions allow the recovery of other postretirement benefit costs
only to the extent that recognized expense is matched by cash
contributions to an irrevocable trust. Xcel Energy has consistently
funded at a level to allow full recovery of costs in these jurisdictions.
in all regulatory
PSCo and SPS recognize pension expense
jurisdictions based on GAAP. The Texas and Colorado electric retail
jurisdictions and the Colorado gas retail jurisdiction, each record the
difference between annual recognized pension expense and the
annual amount of pension expense approved in their last respective
general rate case as a deferral to a regulatory asset.
In 2018, PSCo was required to create a regulatory liability to adjust
postretirement health care costs to zero in order to match the amounts
collected in rates in the Colorado Gas retail jurisdiction. In 2020, this
requirement was extended to the Colorado Electric retail jurisdiction.
See Note 11 to the consolidated financial statements for further information.

•

Nuclear Decommissioning

Xcel Energy recognizes liabilities for the expected cost of retiring tangible
long-lived assets for which a legal obligation exists. These AROs are
recognized at fair value as incurred and are capitalized as part of the cost
of the related long-lived assets. In the absence of quoted market prices,
Xcel Energy estimates the fair value of its AROs using present value
techniques, in which it makes assumptions including estimates of the
amounts and timing of future cash flows associated with retirement
activities, credit-adjusted risk free rates and cost escalation rates. When
Xcel Energy revises any assumptions, it adjusts the carrying amount of
both the ARO liability and related long-lived asset. ARO liabilities are
accreted to reflect the passage of time using the interest method.

A significant portion of Xcel Energy’s AROs relates to the future
decommissioning of NSP-Minnesota’s nuclear
facilities. The nuclear
decommissioning obligation is funded by the external decommissioning
trust fund. Difference between regulatory funding (including depreciation
expense less returns from the external trust fund) and expense recognized
is deferred as a regulatory asset. The amounts recorded for AROs related
to future nuclear decommissioning were $2.1 billion in 2021 and $2.0 billion
in 2020.

NSP-Minnesota obtains periodic independent cost studies in order to
estimate the cost and timing of planned nuclear decommissioning activities.
Estimates of future cash flows are highly uncertain and may vary
significantly from actual results. NSP-Minnesota is required to file a nuclear
decommissioning filing every three years. The filing covers all expenses for
the decommissioning of the nuclear plants, including decontamination and
removal of radioactive material.

The currently approved triennial filing was ordered by the MPUC in January
2019. This approval did not result in a change to the ARO liability. In
December 2020, the MPUC ordered Xcel Energy to maintain the current
accrual through 2021 to align with the approved one year stay out of the
previously filed multi-year electric rate case. Also, in December 2020, Xcel
Energy filed an accrual proposal with the MPUC to be effective in 2022
based on an updated independent cost study. In December 2021, Xcel
Energy submitted its petition for approval of the 2022-2024 NSP-
Minnesota’s Nuclear Decommission Study and Assumptions. Xcel Energy
anticipates the MPUC to deliberate on this filing in February 2022.

The following assumptions have a significant effect on the estimated
nuclear obligation:

Timing — Decommissioning cost estimates are impacted by each facility’s
retirement date and timing of the actual decommissioning activities.
Estimated retirement dates coincide with the expiration of each unit’s
operating license with the NRC (i.e., 2030 for Monticello and 2033 and
2034 for PI’s Unit 1 and 2, respectively). The estimated timing of the
decommissioning activities is based upon the DECON method (required by
the MPUC), which assumes prompt
removal and dismantlement.
Decommissioning activities are expected to begin at the end of the license
date and be completed for both facilities by 2091.

Technology and Regulation — There is limited experience with actual
decommissioning of large nuclear facilities. Changes in technology,
experience and regulations could cause cost estimates
to change
significantly.

Escalation Rates — Escalation rates represent projected cost increases
due to general inflation and increases in the cost of decommissioning
activities. NSP-Minnesota used an escalation rate of 3.2% 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.

However, changes in estimates have minimal impact on results of
operations as NSP-Minnesota expects to continue to recover all costs in
future rates.

Xcel Energy continually makes judgments and estimates related to these
critical accounting policy areas, based on an evaluation of the assumptions
and uncertainties for each area. The information and assumptions of these
judgments and estimates will be affected by events beyond the control of
Xcel Energy, or otherwise change over time. This may require adjustments
to recorded results to better reflect updated information that becomes
available. The accompanying financial statements reflect management’s
best estimates and judgments of the impact of these factors as of Dec. 31,
2021.

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

Derivatives, Risk Management and Market Risk

We are exposed to a variety of market risks in the normal course of
business. Market risk is the potential loss that may occur as a result of
adverse changes in the market or fair value of a particular instrument or
commodity. All financial and commodity-related instruments, including
derivatives, are subject to market risk.

Xcel Energy is exposed to the impact of adverse changes in price for
energy and energy-related products, which is partially mitigated by the use
of commodity derivatives. In addition to ongoing monitoring and maintaining
credit policies intended to minimize overall credit risk, management takes
steps to mitigate changes in credit and concentration risks associated with
its derivatives and other contracts, including parental guarantees and
requests of collateral. While we expect that the counterparties will perform
under the contracts underlying its derivatives, the contracts expose us to
some credit and non-performance risk.

Distress in the financial markets may impact counterparty risk, the fair value
of the securities in the nuclear decommissioning fund and pension fund and
Xcel Energy’s ability to earn a return on short-term investments.

Commodity Price Risk — We are exposed to commodity price risk in our
electric and natural gas operations. Commodity price risk is managed by
entering into long- and short-term physical purchase and sales contracts for
electric capacity, energy and energy-related products and fuels used in
generation and distribution activities. Commodity price risk is also managed
through the use of financial derivative instruments. Our risk management
policy allows 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
risk
natural gas-related
management policy allows management to conduct these activities within
guidelines and limitations as approved by our risk management committee.

including derivatives. Our

instruments,

Fair value of net commodity trading contracts as of Dec. 31, 2021:

(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

(4) $

(7) $

—

(1) $

(1)

(37)

(48)

(9)

—

(8)

—

(36) $

(46) $

(8) $

(12)

(15)

(85)

(98)

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)

2021

2020

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

$ (54) $ (59)

Contracts realized or settled during the period

Commodity trading contract additions and changes during the period

(54)

(9)

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

$ (33) $ (54)

At Dec. 31, 2021, a 10% increase in market prices for commodity trading
contracts through the forward curve would increase pretax income from
continuing operations by approximately $13 million, whereas a 10%
decrease would decrease pretax income from continuing operations by
approximately $13 million. At Dec. 31, 2020, a 10% increase in market
prices for commodity trading contracts would increase pretax income from
continuing operations by approximately $13 million, whereas a 10%
decrease would decrease pretax income from continuing operations by
approximately $13 million. Market price movements can exceed 10% under
abnormal circumstances.

trading operations measure

the
The utility subsidiaries’ commodity
outstanding risk exposure to price changes on contracts and obligations
that have been entered into, but not closed, using an industry standard
methodology known as VaR. VaR expresses the potential change in fair
value on the outstanding contracts and obligations over a particular period
of time under normal market conditions.

The VaRs for the NSP-Minnesota and PSCo commodity trading operations,
excluding both non-derivative transactions and derivative transactions
designated as normal purchase and normal sales, calculated on a
consolidated basis using a Monte Carlo simulation with a 95% confidence
level and a one-day holding period, were as follows:

(Millions of
Dollars)

2021

2020

Year Ended
Dec. 31

VaR Limit

Average

High

Low

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

Nuclear Fuel Supply — NSP-Minnesota has contracted for approximately
78% of its 2022 enriched nuclear material requirements from sources that
could be impacted by sanctions against entities doing business with Iran.
Those sanctions may impact the supply of enriched nuclear material
supplied
is
scheduled to take delivery of approximately 30% of its average enriched
nuclear material requirements from these sources. NSP-Minnesota is able
to manage nuclear fuel supply with alternate potential sources. NSP-
Minnesota periodically assesses if further actions are required to assure a
secure supply of enriched nuclear material.

through 2030, NSP-Minnesota

from Russia. Long-term,

Interest Rate Risk — Xcel Energy is subject to interest rate risk. Our risk
management policy allows interest rate risk to be managed through the use
of fixed rate debt, floating rate debt and interest rate derivatives such as
swaps, caps, collars and put or call options.

A 100 basis point change in the benchmark rate on Xcel Energy’s variable
rate debt would impact pretax interest expense annually by approximately
$11 million and $6 million in 2021 and 2020, respectively.

NSP-Minnesota maintains a nuclear decommissioning fund, as required by
the NRC. The nuclear decommissioning fund is subject to interest rate risk
and equity price risk. The fund is invested in a diversified portfolio of cash
equivalents, debt securities, equity securities and other investments. These
investments may be used only for the purpose of decommissioning NSP-
Minnesota’s nuclear generating plants.

Realized and unrealized gains on the decommissioning fund investments
are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear
decommissioning costs. Fluctuations in equity prices or interest rates
affecting the nuclear decommissioning fund do not have a direct impact on
earnings due to the application of regulatory accounting.

Changes in discount rates and expected return on plan assets impact the
value of pension and postretirement plan assets and/or benefit costs.

Credit Risk — Xcel Energy is also exposed to credit risk. Credit risk relates
to the risk of loss resulting from counterparties’ nonperformance on their
contractual obligations. Xcel Energy maintains credit policies intended to
minimize overall credit risk and actively monitors these policies to reflect
changes and scope of operations.

At Dec. 31, 2021, a 10% increase in commodity prices would have resulted
in an increase in credit exposure of $36 million, while a decrease in prices
of 10% would have resulted in a decrease in credit exposure of $26 million.
At Dec. 31, 2020, a 10% increase in commodity prices would have resulted
in an increase in credit exposure of $11 million, while a decrease in prices
of 10% would have resulted in an immaterial increase in credit exposure.

Xcel Energy conducts credit reviews for all counterparties and employs
credit risk controls, such as letters of credit, parental guarantees, master
netting agreements and
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.

termination provisions. Credit exposure

Fair Value Measurements

Xcel Energy uses derivative contracts such as futures, forwards, interest
rate swaps, options and FTRs to manage commodity price and interest rate
risk. Derivative contracts, with the exception of those designated as normal
purchase and normal sale contracts, are reported at fair value.

Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi
trusts, pension and other postretirement funds are also subject to fair value
accounting.

Commodity Derivatives — Xcel Energy monitors the creditworthiness of
the counterparties to its commodity derivative contracts and assesses each
counterparty’s ability to perform on the transactions. The impact of
discounting commodity derivative assets for counterparty credit risk was not
material to the fair value of commodity derivative assets at Dec. 31, 2021.

Adjustments to fair value for credit risk of commodity trading instruments
are recorded in electric revenues. Credit risk adjustments for other
commodity derivative instruments are recorded as other comprehensive
income or deferred as regulatory assets and liabilities. Classification as a
regulatory asset or liability is based on commission approved regulatory
recovery mechanisms. The impact of discounting commodity derivative
liabilities for credit risk was immaterial at Dec. 31, 2021.

See Notes 10 and 11 to the consolidated financial statements for further
information.

Liquidity and Capital Resources

Cash Flows

Operating Cash Flows

(Millions of Dollars)

Twelve Months Ended Dec. 31

2,848

124

(50)

(785)

2,189

Cash provided by operating activities — 2020

Components of change — 2021 vs. 2020

Higher net income

Non-cash transactions

(a)

Changes in working capital

(b)

Changes in net regulatory and other assets and liabilities

Cash provided by operating activities — 2021
(a)

Non-cash transactions applicable to net income (e.g., depreciation, nuclear fuel
amortization, changes in deferred income taxes, allowance for equity funds used during
construction, etc.).
Working capital includes accounts receivable, accrued unbilled revenues, inventories,
accounts payable, other current assets and other current liabilities.

(b)

Net cash provided by operating activities decreased by $659 million for
2021 as compared to 2020. The decrease was primarily due to the deferral
of net natural gas, fuel and purchased energy costs related to Winter Storm
Uri in the first quarter.

Investing Cash Flows

(Millions of Dollars)

Cash used in investing activities — 2020

Components of change — 2021 vs. 2020

Decreased capital expenditures

Sale of MEC in 2020

Other investing activities

Cash used in investing activities — 2021

Twelve Months Ended Dec. 31

(4,740)

1,125

(684)

(4,287)

Net cash used in investing activities decreased by $453 million for 2021 as
compared to 2020. The decrease in capital expenditures was largely due to
the purchase of MEC in January 2020, which was subsequently sold in July
2020, as well as the completion of various wind projects.

Financing Cash Flows

(Millions of Dollars)

Twelve Months Ended Dec. 31

Cash provided by financing activities — 2020

Components of change — 2021 vs. 2020

Higher debt issuances

Lower 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 — 2021

1,773

202

584

(361)

(79)

2,135

Net cash provided by financing activities increased by $362 million for 2021
as compared to 2020. The increase was primarily attributable to the
amount/timing of debt issuances and repayments, changes in capital
investment and incremental financing due to the lag in recovery costs
associated with Winter Storm Uri.

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

Capital Requirements

Xcel Energy has contractual obligations and other commitments that will
need to be funded in the future. The Company expects to have adequate
amounts of cash from operating and/or financing activities to meet both its
short-term and long-term cash requirements. Xcel Energy’s financing
requirements are dependent on both existing contractual obligations and
other commitments, as well as projected capital forecasts. Xcel Energy
expects to meet future financing requirements by periodically issuing short-
term debt, long-term debt, common stock, hybrid and other securities to
maintain desired capitalization
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, the Company may enter into rate settlement
agreements, which require us to wait for a period of time to file the next
base rate increase request. These agreements may result in regulatory lag
whereby the impact of inflation may not yet be reflected in rates, or a delay
may occur between capital project completion and the start of rate
recovery. Xcel Energy attempts to mitigate the potential impact of inflation
through the use of fuel, energy and other cost adjustment clauses and bill
riders, by employing prudent risk management and hedging strategies and
by considering, among other areas, its impact on purchases of energy,
operating expenses, materials and equipment costs, contract negotiations,
future capital spending programs and long-term debt issuances.

Contractual Obligations 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, 2021)

Total

Less than 1 Year

1 to 3 Years

3 to 5 Years

After 5 Years

37,014

1,419

3,323

3,175

29,097

242

1,594

4,837

455

1,005

256

1,718

455

1,005

478

1,538

—

363

617

—

187

497

964

—

45,187

4,901

5,367

4,174

30,745

Included in operating lease obligations are $229 million, $430 million, $335 million and $416 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively,

(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

4,380

5,280

4,960

5,140

5,560

5,060

By Regulated Utility

PSCo

NSP-Minnesota

SPS

NSP-Wisconsin
Other (a)

By Function

Electric distribution

Electric transmission

Electric generation

Natural gas

Other

Renewables

Actual

2021

2022

2023

2024

2025

2026

2022 - 2026 Total

Base Capital Forecast (Millions of Dollars)

1,625

1,930

1,850

2,070

2,220

1,860

1,885

2,250

2,030

1,830

2,130

2,010

555

290

630

480

(10)

660

420

—

690

540

780

460

(30)

790

390

Actual

2021

2022

2023

2024

2025

2026

2022 - 2026 Total

Base Capital Forecast (Millions of Dollars)

1,110

1,485

1,600

1,520

1,605

1,720

830

575

655

610

600

1,105

1,220

1,575

1,965

1,555

645

655

725

665

580

670

545

345

670

695

450

230

650

660

340

650

660

450

9,930

10,250

3,550

2,290

(20)

26,000

7,930

7,420

3,195

3,340

2,510

1,605

26,000

Total base capital expenditures

4,380

5,280

4,960

5,140

5,560

5,060

(a)

Other category includes intercompany transfers for safe harbor wind turbines.

The five-year capital forecast includes the proposed Colorado Pathway
transmission expansion (approximately $1.7 billion) and the proposed 460
MW Sherco solar facility (approximately $600 million).

Additional capital investment in renewable generation and transmission
may be needed in the five-year forecast pending approval of regulatory
filings in Minnesota and Colorado. The approval of the proposed resource
plans could result in up to 2,000 MW of renewable generation being
needed between 2024 - 2026, resulting in potential capital expenditures
estimated between $1.0 to $1.5 billion (assuming Xcel Energy were to own
~50% of the renewables). Additionally, the associated $0.5 billion to $1.0
billion of network upgrades, voltage support and interconnection work
related to the Colorado Power Pathway could also be needed during this
five-year forecast depending on resource mix, location and timing. Any
additional capital investment would likely be funded with approximately
50% equity and 50% debt.

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 2026 — 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 2022 through 2026:

Capital Sources

(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 2021 - 2025

Maturing Debt
(a)

Net of dividends and pension funding.

17,640

7,110

450

800

26,000

3,900

(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 2022, Xcel Energy
announced an increase in the annual dividend of 12 cents per share, which
represents an increase of 6.6%.

Xcel Energy’s dividend policy balances the following:

•
•
•
•

Projected cash generation.
Projected capital investment.
A reasonable rate of return on shareholder investment.
The impact on Xcel Energy’s capital structure and credit ratings.

In addition, there are certain statutory limitations that could affect dividend
levels. Federal law places limits on the ability of public utilities within a
holding company to declare dividends. Under the Federal Power Act, a
public utility may not pay dividends from any funds properly included in a
capital account. The utility subsidiaries’ dividends may be limited directly or
indirectly by state regulatory commissions or bond indenture covenants.

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

Pension Fund — Xcel Energy’s pension assets are invested in a
diversified portfolio of domestic and international equity securities, short-
term to long-duration fixed income securities and alternative investments,
including private equity, real estate and hedge funds.

Funded status and pension assumptions:

(Millions of Dollars)

Fair value of pension assets
Projected pension obligation (a)

Funded status

Dec. 31, 2021

Dec. 31, 2020

3,670

3,718

(48) $

3,599

3,964

(365)

(a)

Excludes non-qualified plan of $43 million and $43 million at Dec. 31, 2021 and 2020,

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

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

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

•
•
•
•
•

$1.25 billion for Xcel Energy Inc.
$700 million for PSCo.
$500 million for NSP-Minnesota.
$500 million for SPS.
$150 million for NSP-Wisconsin.

Xcel Energy Inc. repaid its $1.2 billion 364-Day Term Loan Agreement in
the fourth quarter.

Xcel Energy’s outstanding short-term debt:

(Amounts in Millions, Except Interest Rates)

Three Months Ended
Dec. 31, 2021

Borrowing limit

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 end of period

3,100

1,005

1,200

1,774

0.54 %

0.31

(Amounts in Millions, Except Interest Rates)
Borrowing limit
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 end of period

Year Ended
Dec. 31, 2021
3,100
$
1,005
1,399
2,054

Year Ended
Dec. 31, 2020
3,100
$
584
1,126
2,080

0.57 %
0.31

1.45 %
0.23

Credit Facility Agreements — Xcel Energy Inc., NSP-Minnesota, PSCo
and SPS each have the right to request an extension of the revolving credit
facility for two additional one-year periods beyond the June 2024
termination date. NSP-Wisconsin has the right to request an extension of
the revolving credit facility for an additional year. All extension requests are
subject to majority bank group approval.

As of Feb. 18, 2022, Xcel Energy Inc. and its utility subsidiaries had the
following committed credit facilities available to meet liquidity needs:

(Millions of Dollars)

Xcel Energy Inc.

Facility (a)
1,250
$

Drawn (b)
757
$

Available

Cash

Liquidity

493

700

500

150

235

—

674

489

265

150

495

696

502

268

153

3,100

1,029

2,071

$ 43

2,114

Credit facilities expire in June 2024.

Includes outstanding commercial paper and letters of credit.

(a)

(b)

respectively.

Pension Assumptions

Discount rate

Expected long-term rate of return

2021

2020

3.08 %

6.49

2.71 %

6.49

PSCo

NSP-Minnesota

SPS

NSP-Wisconsin

Total

Registration Statements — Xcel Energy Inc.’s Articles of Incorporation
authorize the issuance of one billion shares of $2.50 par value common
stock. As of Dec. 31, 2021 and 2020, Xcel Energy had approximately 544
million shares and 537 million shares of common stock outstanding,
respectively.

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

Planned Financing Activity — Xcel Energy’s 2022 financing plans reflect
the following:

•

•
•

•

Xcel Energy Inc. — approximately $600 million in unsecured bonds
during Q2.
PSCo — approximately $650 million of first mortgage bonds during
Q2.
SPS — approximately $150 million of first mortgage bonds during Q2.
NSP-Minnesota — approximately $500 million of first mortgage bonds
during Q2.
NSP-Wisconsin — approximately $100 million of first mortgage bonds
during Q3.

Equity through DRIP and Benefits Program — Xcel Energy also plans to
issue approximately $90 million of equity annually through the DRIP and
benefit programs during the five-year forecast time period.

(a)

ATM Equity Offering — In November 2021, Xcel Energy Inc. filed a
prospectus supplement under which it may sell up to $800 million of its
common stock through an ATM program. As of Dec. 31, 2021, Xcel Energy
Inc. issued 5.33 million shares of common stock with net proceeds of $347
million through the ATM program.

Long-Term Borrowings and Other Financing Instruments — See Note
5 to the consolidated financial statements for further information.

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

Xcel Energy 2022 Earnings Guidance — Xcel Energy’s 2022 GAAP and
ongoing earnings guidance is a range of $3.10 to $3.20 per share.(a)

Key assumptions as compared with 2021 levels unless noted:

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

•
•
• Weather-normalized retail electric sales are projected to increase

~1%.

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

•

•
•

•

•
•

0% to 1%.
Capital rider revenue is projected to increase $35 million to $45 million
(net of PTCs). PTCs are credited to customers, through capital riders
and reductions to other regulatory mechanisms.
O&M expenses are projected to increase approximately 1% to 2%.
Depreciation expense is projected to increase approximately $255
million to $265 million.
Property taxes are projected to increase approximately $40 million to
$50 million.
Interest expense (net of AFUDC - debt) is projected to increase $55
million to $65 million.
AFUDC - equity is projected to be relatively flat.
ETR is projected to be ~(3%) to (5%). The ETR reflects benefits of
PTCs which are credited to customers through electric margin and will
not have a material impact on net income.

Ongoing earnings is calculated using net income and adjusting for certain nonrecurring
or infrequent items that are, in management’s view, not reflective of ongoing operations.
Ongoing earnings could differ from those prepared in accordance with GAAP for
unplanned and/or unknown adjustments. Xcel Energy is unable to forecast if any of
these items will occur or provide a quantitative reconciliation of the guidance for ongoing
EPS to corresponding GAAP EPS.

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

• Deliver long-term annual EPS growth of 5% to 7% based off of a 2021
base of $2.96 per share, which represents the mid-point of the revised
2021 guidance range of $2.94 to $2.98 per share.
Deliver annual dividend increases of 5% to 7%.
Target a dividend payout ratio of 60% to 70%.

•
•
• Maintain senior secured debt credit ratings in the A range.

ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK

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

ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

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, 2021. In making this
assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control —
Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2021, Xcel Energy Inc.’s internal control over financial reporting is
effective at the reasonable assurance level based on those criteria.

Xcel Energy Inc.’s independent registered public accounting firm has issued an 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, 2022

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

Feb. 23, 2022

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, 2021 and 2020,
the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows, for each of the three years in the period ended
December 31, 2021, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the "financial statements"). We also
have audited the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated
Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31,
2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with
accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by
COSO.

Basis for Opinions

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

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

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

Definition and Limitations of Internal Control over Financial Reporting

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

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

Critical Audit Matter

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

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, 2022

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 income (expense), net

Earnings from equity method investments

Allowance for funds used during construction — equity

Interest charges and financing costs

Interest charges — includes other financing costs of $29, $28 and $26, respectively

Allowance for funds used during construction — debt

Total interest charges and financing costs

Income before income taxes

Income tax (benefit) expense

Net income

Weighted average common shares outstanding:

Basic

Diluted

Earnings per average common share:

Basic

Diluted

Year Ended Dec. 31

2021

2020

2019

11,205

9,802

2,132

13,431

4,733

1,081

2,321

304

2,121

630

11,228

2,203

842

(26)

816

1,527

(70)

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)

1,597

1,473

539

540

527

528

2.96

2.79

9,575

1,868

11,529

3,510

918

2,338

285

1,765

569

9,425

2,104

773

(37)

736

1,500

128

1,372

519

520

2.64

See Notes to Consolidated Financial Statements

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

Net income

Other comprehensive income (loss)

Pension and retiree medical benefits:

Net pension and retiree medical losses arising during the period, net of tax of $—, $(2) and $—, respectively

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

Derivative instruments:

Net fair value increase (decrease), net of tax of $1, $(3) and $(8), respectively

Reclassification of losses to net income, net of tax of $2, $2 and $1, respectively

Total other comprehensive income (loss)

Total comprehensive income

Year Ended Dec. 31

2021

2020

2019

1,597

1,473

1,372

—

(5)

(10)

—

(23)

(17)

1,355

See Notes to Consolidated Financial Statements

1,615

1,473

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:

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
Net realized and unrealized hedging and derivative transactions
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

Proceeds from (repayments of) short-term borrowings, net
Proceeds from issuances of long-term debt
Repayments of long-term debt, including reacquisition premiums
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

2021

Year Ended Dec. 31
2020

2019

1,597

1,473

1,372

2,143
114
(79)
(73)
(62)
42
60
31
(57)

(164)
(149)
(126)
(34)
138
(973)
(1)
(135)
(83)
2,189

(4,244)
—
(757)
743
(29)
(4,287)

421
2,710
(417)
366
(935)
(10)
2,135

1,959
123
(8)
(115)
(40)
42
60
73
(27)

(154)
(3)
(80)
(45)
(33)
(144)
29
(125)
(137)
2,848

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

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

37
129
166

(119)
248
129

(788) $
(4)

(758) $
12

501
87
8
73
60

400
275
369
115
67

1,785
119
143
(77)
(39)
40
42
58
45

(20)
42
(84)
25
(12)
(66)
(15)
(135)
40
3,263

(4,225)
—
(995)
975
(98)
(4,343)

(443)
2,920
(949)
458
(791)
(14)
1,181

101
147
248

(698)
53

421
88
1,843
77
63

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; 544,025,269 and 537,438,394 shares outstanding at Dec. 31, 2021
and Dec. 31, 2020, 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

2021

2020

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

129
916
714
535
640
49
42
250
3,275

45,457

42,950

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

3,096
2,737
30
1,490
379
7,732
53,957

421
584
1,237
311
578
203
231
53
214
407
4,239

4,746
45
5,302
2,884
131
197
666
1,344
183
15,498

19,645

1,344
7,404
5,968
(141)
14,575
53,957

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, 2018

514,036,787

1,285

6,168

4,893

(124) $

12,222

Net income

Other comprehensive income

Dividends declared on common stock ($1.62 per share)

Issuances of common stock

Repurchases of common stock

Share-based compensation

Balance at Dec. 31, 2019

Net Income

Dividends declared on common stock ($1.72 per share)

Issuances of common stock

Repurchase of common stock

Share-based compensation

Adoption of ASC Topic 326

Balance at Dec. 31, 2020

Net income

Other comprehensive income

Dividends declared on common stock ($1.83 per share)

Issuances of common stock

Share-based compensation

Balance at Dec. 31, 2021

10,507,943

(5,730)

—

468

—

1,372

(846)

(6)

(17)

1,372

(17)

(846)

494

—

524,539,000

1,311

6,656

5,413

(141) $

13,239

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

See Notes to Consolidated Financial Statements

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 — Xcel Energy Inc.’s regulated utility subsidiaries
account for income and expense items in accordance with accounting
guidance for regulated operations. Under this guidance:

•

Certain costs, which would otherwise be charged to expense or other
comprehensive income, are deferred as regulatory assets based on
the expected ability to recover the costs in future rates.
Certain credits, which would otherwise be reflected as income or other
comprehensive income, are deferred as regulatory liabilities based on
the expectation the amounts will be returned to customers in future
rates, or because the amounts were collected in rates prior to the
costs being incurred.

Estimates of recovering deferred costs and returning deferred credits are
based on specific ratemaking decisions or precedent for each item.
Regulatory assets and liabilities are amortized consistent with the treatment
in the rate setting process.

If changes in the regulatory environment occur, the utility subsidiaries may
no longer be eligible to apply this accounting treatment and may be
required to eliminate regulatory assets and liabilities from their balance
sheets. Such changes could have a material effect on Xcel Energy’s results
of operations, financial condition and cash flows.

See Note 4 for further information.

Income Taxes — Xcel Energy accounts for income taxes using the asset
and liability method, which requires recognition of deferred tax assets and
liabilities for the expected future tax consequences of events that have
been included in the financial statements. Xcel Energy defers income taxes
for all temporary differences between pretax financial and taxable income
and between the book and tax bases of assets and liabilities.

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

The effects of tax rate changes that are attributable to the utility
subsidiaries are generally subject to a normalization method of accounting.
Therefore, the revaluation of most of the utility subsidiaries’ net deferred
taxes upon a tax rate reduction results in the establishment of a net
regulatory liability, which would be refundable to utility customers over the
remaining life of the related assets. Xcel Energy anticipates that a tax rate
increase would result in the establishment of a regulatory asset, subject to
an evaluation of whether future recovery is expected.

XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

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

Xcel Energy’s regulated operations include the activities of NSP-Minnesota,
NSP-Wisconsin, PSCo and SPS. These utility subsidiaries serve electric
and natural gas customers in portions of Colorado, Michigan, Minnesota,
New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Also
included in regulated operations are WGI, an interstate natural gas pipeline
company, and WYCO, a joint venture with CIG to develop and lease natural
gas pipeline, storage and compression facilities.

technology companies. Nicollet Project Holdings

Xcel Energy Inc.’s nonregulated subsidiaries include Eloigne, Capital
Services, Venture Holdings and Nicollet Project Holdings. Eloigne invests in
rental housing projects that qualify for low-income housing tax credits.
Capital Services procures equipment
for construction of renewable
generation facilities at other subsidiaries. Venture Holdings invests in
limited partnerships, including EIP funds with portfolios of investments in
energy
in
nonregulated assets such as the MEC generating facility (through July
2020) and Minnesota community solar gardens. Xcel Energy Inc. owns the
following additional direct subsidiaries, some of which are intermediate
holding companies with additional subsidiaries: Xcel Energy Wholesale
Group Inc., Xcel Energy Markets Holdings Inc., Xcel Energy Ventures Inc.,
Xcel Energy Retail Holdings Inc., Xcel Energy Communications Group, Inc.,
Xcel Energy
Inc., Xcel Energy Transmission Holding
Company, LLC, Nicollet Holdings Company, LLC, Xcel Energy Nuclear
Services Holdings, LLC and Xcel Energy Services Inc. Xcel Energy Inc.
and its subsidiaries collectively are referred to as Xcel Energy.

International

invests

for which

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. Xcel Energy uses
the equity method of accounting for its investments in EIP funds and
WYCO.

Xcel Energy has investments in certain plants and transmission facilities
jointly owned with nonaffiliated utilities. Xcel Energy’s proportionate share
of jointly owned facilities is recorded as property, plant and equipment on
the consolidated balance sheets, and Xcel Energy’s proportionate share of
the operating costs associated with these facilities is included in its
consolidated statements of income.

financial statements are presented

Xcel Energy’s consolidated
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, 2021 up to the
date of issuance of these consolidated financial statements. These
statements contain all necessary adjustments and disclosures resulting
from that evaluation.

Reversal of certain temporary differences are accounted for as current
income tax expense due to the effects of past regulatory practices when
deferred taxes were not required to be recorded due to the use of flow
through accounting for ratemaking purposes. Tax credits are recorded
when earned unless there is a requirement to defer the benefit and
amortize it over the book depreciable lives of the related property. The
requirement to defer and amortize tax credits only applies to federal ITCs
related to public utility property. Utility rate regulation also has resulted in
the recognition of regulatory assets and liabilities related to income taxes.
Deferred tax assets are reduced by a valuation allowance if it is more likely
than not that some portion or all of the deferred tax asset will not be
realized.

Xcel Energy records depreciation expense using the straight-line method
over the plant’s commission approved useful life. Actuarial life studies are
performed and submitted to the state and federal commissions for review.
Upon acceptance by the various commissions, the resulting lives and net
salvage rates are used to calculate depreciation. Plant removal costs of
Xcel Energy’s utility subsidiaries are recovered in rates as authorized by
the appropriate regulatory entities. The amount of removal costs is based
on current factors used in existing depreciation rates. Accumulated removal
costs are reflected in the consolidated balance sheet as a regulatory
liability. Depreciation expense, expressed as a percentage of average
depreciable property, was approximately 3.5% for 2021, 3.4% for 2020 and
3.3% for 2019.

tax returns. Xcel Energy recognizes a

Xcel Energy follows the applicable accounting guidance to measure and
disclose uncertain tax positions that it has taken or expects to take in its
income
its
consolidated financial statements when it is more likely than not that the
position will be sustained upon examination based on the technical merits
of the position. Recognition of changes in uncertain tax positions are
reflected as a component of income tax expense.

tax position

Xcel Energy reports interest and penalties related to income taxes 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.

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

Property, plant and equipment is tested for impairment when it is
determined that the carrying value of the assets may not be recoverable. A
loss is recognized in the current period if it becomes probable that part of a
cost of a plant under construction or recently completed plant will be
disallowed for recovery from customers and a reasonable estimate of the
disallowance can be made. For investments in property, plant and
equipment that are abandoned and not expected to go into service,
incurred costs and related deferred tax amounts are compared to the
discounted estimated future rate recovery, and a loss is recognized, if
necessary.

See Note 3 for further information.

AROs — Xcel Energy accounts for AROs under accounting guidance that
requires a liability for the fair value of an ARO to be recognized in the
period in which it is incurred if it can be reasonably estimated, with the
offsetting associated asset retirement costs capitalized as a long-lived
asset. The liability is generally increased over time by applying the effective
interest method of accretion, and the capitalized costs are depreciated over
the useful life of the long-lived asset. Changes resulting from revisions to
the timing or amount of expected asset retirement cash flows are
recognized as an increase or a decrease in the ARO.

See Note 12 for further information.

Nuclear Decommissioning — Nuclear decommissioning studies that
estimate NSP-Minnesota’s costs of decommissioning its nuclear power
plants are performed at least every three years and submitted to the state
commissions for approval.

NSP-Minnesota recovers regulator-approved decommissioning costs of its
nuclear power plants over each facility’s expected service life, typically
based on the triennial decommissioning studies. The studies consider
estimated future costs of decommissioning and the market value of
investments in trust funds and recommend annual funding amounts.
Amounts collected in rates are deposited in the trust funds. For financial
reporting purposes, NSP-Minnesota accounts for nuclear decommissioning
as an ARO.

Restricted funds for the payment of future decommissioning expenditures
for NSP-Minnesota’s nuclear
in 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 liability can be
reasonably estimated. Costs are deferred as a regulatory asset if it is
probable that the costs will be recovered from customers in future rates.
Otherwise, the costs are expensed. 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 proceeds.
If other participating potentially
responsible parties exist and acknowledge their potential involvement with
a site, costs are estimated and recorded only for Xcel Energy’s expected
share of the cost.

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

See Note 12 for further information.

Revenue from Contracts with Customers — Performance obligations
related to the sale of energy are satisfied as energy is delivered to
customers. Xcel Energy recognizes revenue that corresponds to the price
of the energy delivered to the customer. The measurement of energy sales
to customers is generally based on the reading of their meters, which
occurs systematically throughout the month. At the end of each month,
amounts of energy delivered to customers since the date of the last meter
reading are estimated, and
is
recognized.

the corresponding unbilled revenue

Xcel Energy does not recognize a separate financing component of its
collections from customers as contract terms are short-term in nature. Xcel
Energy presents its revenues net of any excise or sales taxes or fees. The
utility subsidiaries recognize physical sales to customers (native load and
wholesale) on a gross basis in electric revenues and cost of sales.
Revenues and charges for short-term physical wholesale sales of excess
energy transacted through RTOs are also recorded on a gross basis. Other
revenues and charges settled/facilitated through an RTO are recorded on a
net basis in cost of sales.

See Note 6 for further information.

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

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

Equity Method Investments — The equity method of accounting is used
for investments in WYCO and EIP funds, which results in Xcel Energy’s
recognition of its share of these investees’ GAAP pretax earnings, based
on Xcel Energy’s proportional ownership interest. For investments in EIP
funds, this includes Xcel Energy’s share of fund expenses and realized
gains and losses, as well as unrealized gains and losses resulting from
valuations of the funds’ investments in emerging energy technology
companies.

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

derivatives,

derivatives

rate

and

to establish

Cash equivalents are recorded at cost plus accrued interest; money market
funds are measured using quoted NAVs. For interest rate derivatives,
quoted prices based primarily on observable market interest rate curves are
the most
used
observable inputs available are generally used to determine the fair value
of each contract. In the absence of a quoted price, Xcel Energy may use
quoted prices for similar contracts or internally prepared valuation models
to determine fair value.

fair value. For commodity derivatives,

the pension and postretirement plan assets and nuclear
For
decommissioning
trading data and pricing models,
generally using the most observable inputs available, are utilized to
estimate 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 interest rate, utility commodity price and commodity
trading activities, including forward contracts, futures, swaps and options.
Any derivative instruments not qualifying for the normal purchases and
normal sales exception are recorded on the consolidated balance sheets at
fair value as derivative instruments. Classification of changes in fair value
for those derivative instruments is dependent on the designation of a
qualifying hedging relationship. Changes in fair value of derivative
instruments not designated in a qualifying hedging relationship are reflected
in current earnings or as a regulatory asset or liability. Classification as a
regulatory asset or liability is based on commission approved regulatory
recovery mechanisms.

Gains or losses on commodity trading transactions are recorded as a
component of electric operating revenues and interest rate hedging
transactions are recorded as a component of interest expense.

Normal Purchases and Normal Sales — Xcel Energy enters into
contracts for purchases and sales of commodities for use in its operations.
At inception, contracts are evaluated to determine whether a derivative
exists and/or whether an instrument may be exempted from derivative
accounting if designated as a normal purchase or normal sale.

As of Dec. 31, 2021 and 2020, the allowance for bad debts was $106
million and $79 million, respectively.

See Note 10 for further information.

Inventory — Inventory is recorded at average cost and consisted of the
following:

(Millions of Dollars)

Inventories

Materials and supplies

Fuel

Natural gas

Total inventories

Dec. 31, 2021

Dec. 31, 2020

289

182

160

631

275

176

535

Commodity Trading Operations — All applicable gains and losses
related to commodity trading activities are shown on a net basis in electric
operating revenues in the consolidated statements of income.

Commodity trading activities are not associated with energy produced from
Xcel Energy’s generation assets or energy and capacity purchased to serve
native load. Commodity trading contracts are recorded at fair market value
and commodity trading results include the impact of all margin-sharing
mechanisms.

See Note 10 for further information.

Other Utility Items

AFUDC — AFUDC represents the cost of capital used to finance utility
construction activity. AFUDC is computed by applying a composite
financing rate to qualified CWIP. The amount of AFUDC capitalized as a
utility construction cost is credited to other nonoperating income (for equity
capital) and interest charges (for debt capital). AFUDC amounts capitalized
are included in Xcel Energy’s rate base for establishing utility rates.

legislative body related

Alternative Revenue — Certain rate rider mechanisms (including
decoupling/sales true up and CIP/DSM programs) qualify as alternative
revenue programs. These mechanisms arise from costs imposed upon the
utility by action of a regulator or
to an
environmental, public safety or other mandate or from other instances
where the regulator authorizes a future surcharge in response to past
activities or completed events. When certain criteria are met, including
expected collection within 24 months, revenue is recognized equal to the
revenue requirement, which may include incentives and return on rate base
items. Billing amounts are revised periodically for differences between total
amount collected and revenue earned, which may increase or decrease the
level of revenue collected from customers. Alternative revenues arising
from these programs are presented on a gross basis and disclosed
separately from revenue from contracts with customers.

See Note 6 for further information.

Conservation Programs — Costs incurred for DSM and CIP programs are
deferred if it is probable future revenue will recover the incurred cost.
Revenues recognized for incentive programs for the recovery of lost
margins and/or conservation performance incentives are limited to amounts
expected to be collected within 24 months from the year they are earned.
Regulatory assets are recognized to reflect the amount of costs or earned
incentives that have not yet been collected from customers.

Emission Allowances — Emission allowances are recorded at cost,
including broker commission fees. The inventory accounting model is
utilized for all emission allowances and sales of these allowances are
included in electric revenues.

Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and
amortization method for nuclear refueling costs. This method amortizes
costs over the period between refueling outages consistent with rate
recovery.

RECs — Cost of RECs that are utilized for compliance is recorded as
electric fuel and purchased power expense. In certain jurisdictions, Xcel
Energy reduces recoverable fuel and purchased power costs for the cost of
RECs received. An inventory accounting model is used to account for
RECs recognized on the consolidated balance sheets, 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 shown
on a net basis in electric operating revenues in the consolidated statements
of income.

2. Accounting Pronouncements

Recently Adopted

Credit Losses — In 2016, the FASB issued Financial Instruments - Credit
Losses, Topic 326 (ASC Topic 326), which changes how entities account
for losses on receivables and certain other assets. The guidance requires
use of a current expected credit loss model, which may result in earlier
recognition of credit losses than under previous accounting standards.

Xcel Energy implemented the guidance using a modified-retrospective
approach, recognizing a cumulative effect charge of $2 million (after tax) to
retained earnings on Jan. 1, 2020. Other than first-time recognition of an
allowance for bad debts on accrued unbilled revenues, the Jan. 1, 2020,
adoption of ASC Topic 326 did not have a significant impact on Xcel
Energy’s consolidated financial statements.

3. Property, Plant and Equipment

Major classes of property, plant and equipment

(Millions of Dollars)
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

Dec. 31, 2021

Dec. 31, 2020

48,680
7,758
2,602
1,200
1,969
62,209
(17,060)
3,081
(2,773)
45,457

47,104
7,135
2,503
677
1,877
59,296
(16,657)
2,970
(2,659)
42,950

Property, plant and equipment, net

(a)

Includes regulator-approved retirements of Comanche Units 1 and 2 and jointly owned

Craig Unit 1 for PSCo, and Sherco Units 1, 2 and 3 and A.S. King for NSP-Minnesota.

Also includes SPS’ expected retirement of Tolk and conversion of Harrington to natural

gas, and PSCo’s planned retirement of jointly owned Craig Unit 2.

Joint Ownership of Generation, Transmission and Gas Facilities

The utility subsidiaries’ jointly owned assets as of Dec. 31, 2021:

(Millions of Dollars, Except Percent Owned)
NSP-Minnesota
Electric generation:
Sherco Unit 3
Sherco common facilities
Sherco substation
Electric transmission:
Grand Meadow
Huntley Wilmarth
CapX2020

Total NSP-Minnesota

(a)

Plant in
Service

Accumulated
Depreciation

Percent
Owned

620
178
5

11
48
952

1,814

451
108
4

3
1
127

694

59 %
80
59

50
50
51

(a)

Projects additionally include $7 million in CWIP.

(Millions of Dollars, Except Percent Owned)
NSP-Wisconsin
Electric transmission:

Plant in
Service

Accumulated
Depreciation

Percent
Owned

La Crosse, WI to Madison, WI
CapX2020

Total NSP-Wisconsin

(a)

177
169

346

15
28

37 %
80

(a)

Projects additionally include $2 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.

156
151
42
81
39
917
28

182

22
8

1,626

99
78
27
48
25
154
2

76 %
37
53
10
7
67
82

Various

60
50

8
2

506

(a)

Projects additionally include $4 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

See Note(s)

Remaining Amortization
Period

Dec. 31, 2021

Dec. 31, 2020

Current

Noncurrent

Current

Noncurrent

Pension and retiree medical obligations

Various

944

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

Texas revenue surcharges

Sales true-up and revenue decoupling

Benson biomass PPA termination and asset purchase

Renewable resources and environmental initiatives

PI extended power uprate

Purchased power contract costs
Conservation programs (a)
Losses on reacquired debt
Contract valuation adjustments (b)
State commission adjustments

Laurentian biomass PPA termination

Nuclear refueling outage costs

Property tax

Gas pipeline inspection and remediation costs
Net AROs (c)
Other

Total regulatory assets

Plant lives

Various

One to 10 years

1, 12

Various

One to two years

Eight years

One to two years

13 years

Term of related contract

1 One to two years

Term of related debt

1, 10

Term of related contract

Plant lives

Two years

1 One to two years

Various

One to two years

1, 12

Various

504

—

170

—

543

289

219

173

(112)

—

101

129

—

1,268

283

229

154

113

139

1,106

2,738

640

2,737

(a)

(b)

(c)

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.

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

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 (b)
Renewable resources and environmental initiatives

(a)

ITC deferrals

Revenue decoupling

(c)

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

Other
Total regulatory liabilities (e)

See Note(s)

Remaining Amortization
Period

Dec. 31, 2021

Dec. 31, 2020

Current

Noncurrent

Current

Noncurrent

Various

1, 12

Various

One to two years

1, 10 One to three years

Less than one year

Various

—

3,230

1,655

235

101

—

101

3,368

1,520

221

—

271

5,405

311

5,302

(a)

(b)

(c)

(d)

(e)

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 certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
Revenue subject to refund of $17 million for both 2021 and 2020 is included in other current liabilities.

At Dec. 31, 2021 and 2020, Xcel Energy’s regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical
obligations and net AROs. In addition, regulatory assets included $1,718 million and $812 million at Dec. 31, 2021 and 2020, respectively, of past
expenditures not earning a return. Amounts are related to funded pension obligations, sales true-up and revenue decoupling, purchased natural gas and
electric energy costs (including those related to Winter Storm Uri), various renewable resources and certain environmental initiatives.

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 term loan borrowings outstanding:

(Millions of Dollars, Except
Interest Rates)

Three Months
Ended Dec. 31,
2021

Borrowing limit

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

Year Ended Dec. 31

2021

2020

2019

$ 3,100

$ 3,600

1,005

1,399

2,054

584

1,126

2,080

595

1,115

1,780

3,100

1,005

1,200

1,774

0.54 %

0.57 %

1.45 %

2.72 %

0.31

0.23

2.34

Credit Facilities — In order to use commercial paper programs to fulfill
short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must
have revolving credit facilities in place at least equal to the amount of their
respective commercial paper borrowing limits and cannot issue commercial
paper exceeding available capacity under these credit facilities. The lines of
credit provide short-term financing in the form of notes payable to banks,
letters of credit and back-up support for commercial paper borrowings.

Terms of Credit Agreements — Xcel Energy Inc., NSP-Minnesota, NSP-
Wisconsin, PSCo and SPS entered five-year credit agreements with a
syndicate of banks. The total borrowing limit under the amended credit
agreements is $3.1 billion, with a swingline subfacility for Xcel Energy up to
$75 million. The amended credit agreements mature in June 2024.

Features of the credit facilities:

Amount
Facility May Be
Increased
(millions of
dollars)

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

Debt-to-Total

Capitalization Ratio
2020

2021

(a)

Term Loan Agreements — In the fourth quarter of 2021, Xcel Energy
repaid its $1.2 billion 364-Day Term Loan Agreement.

In April 2021, NSP-Minnesota’s
Bilateral Credit Agreement —
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, 2021, NSP-Minnesota had $45 million outstanding letters of
credit under the $75 million the Bilateral Credit Agreement.

to provide

Letters of Credit — Xcel Energy uses letters of credit, typically with terms
of one year,
for certain operating
obligations. As of Dec. 31, 2021 and 2020, there were $19 million and $20
million of letters of credit outstanding under the credit facilities, respectively.
Amounts approximate their fair value.

financial guarantees

(c)

Xcel Energy Inc.
NSP-Wisconsin

NSP-Minnesota

SPS

PSCo

60 %

59 % $

250

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, 2021, Xcel Energy Inc. and its subsidiaries were in
compliance with all financial covenants.

Xcel Energy Inc. and its utility subsidiaries had the following committed
credit facilities available as of Dec. 31, 2021:

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

Total

Credit Facility (a)
1,250
$
700
500
500
150
3,100

Drawn (b)

Available

638
155
9
139
83
1,024

612
545
491
361
67
2,076

(a)

(b)

These credit facilities mature in June 2024.

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, 2021 and 2020.

Long-Term Borrowings and Other Financing Instruments

Generally, all property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
are subject to the liens of their first mortgage indentures. Debt premiums,
discounts and expenses are amortized over the life of the related debt. The
premiums, discounts and expenses for refinanced debt are deferred and
amortized over the life of the new issuance.

Long-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

2021

2020

Unsecured senior notes

(b)

Unsecured senior notes

(a)

Unsecured senior notes

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

Unsecured senior notes

Unamortized discount

Unamortized debt issuance cost

Current maturities

Total long-term debt
(a)

2021 financing.

(b)

2020 financing.

2.40 % March 15, 2021

—

0.50

3.30

3.35

1.75

4.00

2.60

3.40

2.35

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

July 1, 2036

Sep. 15, 2041

Dec. 1, 2049

500

250

350

500

130

500

600

300

250

500

(8)

(33)

—

400

500

250

350

500

—

130

500

600

—

300

250

500

(7)

(32)

(400)

5,139

4,341

NSP-Minnesota

Financing Instrument

Interest
Rate

Maturity Date

2021

2020

2.15 %

Aug. 15, 2022

300

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

Aug. 15, 2045

May 15, 2046

Sep. 15, 2047

March 1, 2050

June 1, 2051

April 1,2052

400

250

150

425

250

400

350

300

250

500

300

350

600

700

425

(44)

(62)

(300)

300

400

250

150

—

250

400

350

300

250

500

300

350

600

700

—

(42)

(54)

—

6,447

5,904

NSP-Wisconsin

Interest
Rate

Maturity Date

2021

2020

6.00 %

Nov. 1, 2021

—

3.30

6.375

3.70

3.75

4.20

3.05

2.82

June 15, 2024

Sept. 1, 2038

Oct. 1, 2042

Dec. 1, 2047

Sept. 1, 2048

May 1, 2051

100

200

100

200

100

(4)

(10)

—

987

100

200

100

200

100

—

(4)

(9)

(19)

887

First mortgage bonds

(a)

First mortgage bonds

(b)

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

Unamortized discount

Unamortized debt issuance cost

Current maturities

Total long-term debt
(a)

2021 financing.

(b)

2020 financing.

Financing Instrument

City of La Crosse resource
recovery bond

First mortgage bonds

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

Unamortized discount

Unamortized debt issuance cost

Current maturities

Total long-term debt
(a)

2021 financing.
2020 financing.

(b)

Financing Instrument

PSCo

Interest
Rate

Maturity Date

2021

2020

(Millions of Dollars)

Maturities of long-term debt:

2.25 %

Sept. 15, 2022

300

Unamortized debt issuance cost

Current maturities

Total long-term debt
(a)

2021 financing.

(b)

2020 financing.

Financing Instrument

SPS

Interest
Rate

6,167

5,724

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, 2021

Common Stock
Outstanding
(Shares) as of
Dec. 31, 2020

Maturity Date

2021

2020

1,000,000,000

2.50

544,025,269

537,438,394

3.30 %

June 15, 2024

150

300

250

350

375

—

350

300

250

500

250

300

250

400

350

400

550

375

(30)

(46)

—

2022

2023

2024

2025

2026

601

1,150

552

1,102

501

Deferred Financing Costs — Deferred financing costs of approximately
$184 million and $167 million, net of amortization, are presented as a
deduction from the carrying amount of long-term debt as of Dec. 31, 2021
and 2020, respectively.

ATM Equity Offering — In November 2021, Xcel Energy Inc. filed a
prospectus supplement under which it may sell up to $800 million of its
common stock through an ATM program. As of Dec. 31, 2021, Xcel Energy
Inc. had issued 5.33 million shares of common stock with net proceeds of
$347 million through the ATM program.

Capital Stock — Preferred stock authorized/outstanding:

Preferred Stock
Authorized
(Shares)

Par Value of
Preferred Stock

Preferred Stock

Outstanding (Shares)

2021 and 2020

Xcel Energy Inc.

7,000,000

PSCo

SPS

10,000,000

100

0.01

1.00

—

150

200

100

250

200

100

300

450

300

350

—

(10)

(26)

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. Requirements and actuals as of Dec. 31, 2021:

impose dividend

limitations

Equity to Total
Capitalization Ratio
Required Range

Equity to Total
Capitalization Ratio
Actual

Low

High

2021

47.2 %

52.5

45.0

57.6 %

N/A

55.0

52.9 %

52.8

54.5

NSP-Minnesota

NSP-Wisconsin
SPS (a)
(a)

Excludes short-term debt.

First mortgage bonds

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

First mortgage bonds

First mortgage bonds
First mortgage bonds (b)
Unamortized discount

First mortgage bonds

Unsecured senior notes

First mortgage bonds

First mortgage bonds
First mortgage bonds (b)
First mortgage bonds (a)
Unamortized discount

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

6.25

6.50

4.75

3.60

3.95

4.30

3.55

3.80

4.10

4.05

3.20

2.70

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

3.30

6.00

4.50

3.40

3.70

4.40

3.75

3.15

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

250

350

375

750

350

300

250

500

250

300

250

400

350

400

550

375

(33)

(50)

(300)

200

100

250

200

100

300

450

300

350

250

(9)

(28)

Unamortized debt issuance cost

Total long-term debt
(a)

2020 financing re-opened in 2021.

(b)

2020 financing.

3,013

2,764

Other Subsidiaries

Interest
Rate

0.00% -
6.50%

Financing Instrument

Various Eloigne affordable
housing project notes

Current maturities

Total long-term debt

Maturity Date

2021

2020

2022 — 2055

(1)

(2)

(Amounts in
Millions)

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

Unrestricted Retained
Earnings

Total
Capitalization

Limit on Total
Capitalization

1,558

14,321

15,332

513

2,091

6,615

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, 2021:

(Millions of Dollars)

Long-Term Debt

Short-Term Debt

NSP-Minnesota

NSP-Wisconsin

SPS

52.8% of total
capitalization

(a)

150

—

700

(b)

(a)

2,300

150

600

800

PSCo
(a)

(b)

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.
PSCo filed for additional long-term debt authorization in December 2021.

6. Revenues

Revenue is classified by the type of goods/services rendered and market/
customer type. Xcel Energy’s operating revenues consisted of the
following:

(Millions of Dollars)

Major revenue types

Year Ended Dec. 31, 2021

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

3,194

1,222

5,050

127

8,371

1,540

604

10,576

629

640

—

1,862

—

148

2,010

122

Total revenues

$ 11,205

2,132

—

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

(Millions of Dollars)

Major revenue types

Year Ended Dec. 31, 2019

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

2,877

1,127

4,844

130

7,851

737

507

9,144

431

567

—

1,694

—

120

1,814

Total revenues

9,575

1,868

7. Income Taxes

—

4,045

5,440

134

9,619

737

507

169

11,032

497

$ 11,529

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

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

Tax Year(s)

2014 - 2016

2018

Expiration

December 2022

September 2022

Additionally, the statute of limitations related to the federal tax credit
carryforwards will remain open until those credits are utilized in subsequent
returns. Further, the statute of limitations related to the additional federal
tax loss carryback claim 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, 2021, Xcel Energy’s earliest open tax years (subject to
examination by state taxing authorities in its major operating jurisdictions)
were as follows:

State

Colorado

Minnesota

Texas

Wisconsin

Year

2014

2016

•

In April 2021, Texas began an audit of tax years 2016-2019. As of
Dec. 31, 2021, no material adjustments have been proposed.
In March 2021, Wisconsin began an audit of tax years 2016 - 2019. As
of Dec. 31, 2021, no material adjustments have been proposed.
In July 2020, Minnesota began an audit of tax years 2015 - 2018. As
of Dec. 31, 2021, no material adjustments have been proposed.
No other state income tax audits in progress for its major operating
jurisdictions as of Dec. 31, 2021.

Unrecognized Tax Benefits — 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, 2021

Dec. 31, 2020

Unrecognized tax benefit — Permanent tax positions

Unrecognized tax benefit — Temporary tax positions

Total unrecognized tax benefit

Changes in unrecognized tax benefits:

Interest payable related to unrecognized tax benefits:

(Millions of Dollars)

2021

2020

2019

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) $

—

(3)

(3) $

—

No penalties were accrued related to unrecognized tax benefits as of Dec.
31, 2021, 2020 or 2019.

Other Income Tax Matters — NOL amounts represent the tax loss that is
carried forward and tax credits represent the deferred tax asset. NOL and
tax credit carryforwards as of Dec. 31:

(Millions of Dollars)

Federal NOL carryforward

Federal tax credit carryforwards

State NOL carryforwards

2021

2020

765

1,172

1,648

(3)

—

791

839

(4)

(64)

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 $24 million as of Dec. 31,

2021 and 2020.

(b)

Valuation allowances for state tax credit carryforwards were net of federal benefit of $17

million as of Dec. 31, 2021 and 2020.

Federal carryforward periods expire between 2031 and 2041 and state
carryforward periods expire starting 2022.

Total income tax expense from operations differs from the amount
computed by applying the statutory federal income tax rate to income
before income tax expense.

Effective income tax rate for years ended Dec. 31:

Federal statutory rate

2021

2020

2019

21.0 %

(Millions of Dollars)

Balance at Jan. 1

2021

2020

2019

$ 52

$ 44

$ 37

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

5.0

4.9

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

Balance at Dec. 31

(2)

(4)

(34)

—

(Decreases) increases in tax from:

Wind PTCs
Plant regulatory differences (a)
Other tax credits, net NOL & tax credit allowances

(1)

$ 58

$ 52

$ 44

NOL Carryback

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

(Millions of Dollars)

Dec. 31, 2021

Dec. 31, 2020

Change in unrecognized tax benefits

Other, net

Effective income tax rate
(a)

(23.4)

(15.7)

(6.2)

(1.1)

—

0.4

(0.3)

(4.6) %

(7.6)

(1.2)

(0.9)

0.5

(1.4)

(0.4) %

(9.4)

(5.8)

(1.7)

—

0.5

(1.0)

8.5 %

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

NOL and tax credit carryforwards

(36) $

(31)

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

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 $28 million in
the next 12 months.

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

associated with the credit of excess deferred credits are offset by corresponding

revenue reductions and additional prepaid pension asset amortization.

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

Shares of restricted stock granted at Dec. 31:

(Millions of Dollars)

Current federal tax expense (benefit)

Current state tax (benefit) expense

Current change in unrecognized tax expense

Deferred federal tax (benefit) expense

Deferred state tax expense

Deferred change in unrecognized tax expense (benefit)

Deferred ITCs

2021

2020

2019

(Shares in Thousands)

2021

2020

2019

(13) $

(16)

Granted shares

(2)

(183)

(5)

(89)

(10)

(5)

Grant date fair value

61.54

70.26

Changes in nonvested restricted stock:

(Shares in Thousands)

Weighted Average
Grant Date Fair Value

Nonvested restricted stock at Jan. 1, 2021

Total income tax (benefit) expense

(70) $

(6) $

128

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

Granted

Forfeited

Vested

53.46

56.68

61.54

70.26

49.71

66.73

67.26

(Millions of Dollars)

2021

2020

2019

Deferred tax expense excluding items below

148

237

344

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

Tax (benefit) expense allocated to other comprehensive
income, adoption of ASC Topic 326, and other

Deferred tax (benefit) expense

(221)

(247)

(206)

(6)

(79) $

(8) $

143

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

(Millions of Dollars)

Deferred tax liabilities:

2021

(a)

2020

Differences between book and tax bases of property

$ 6,231

$ 5,810

Operating lease assets

Regulatory assets

Deferred fuel costs

Pension expense

Other

351

598

262

175

400

603

(6)

176

Total deferred tax liabilities

$ 7,710

$ 7,057

—

(9)

—

Dividend equivalents

Nonvested restricted stock at Dec. 31, 2021

Other Equity Awards — Xcel Energy‘s Board of Directors has granted
equity awards under the Amended and Restated 2015 Omnibus Incentive
Plan, which includes various vesting conditions and performance goals. At
the end of the restricted period, such grants will be awarded if vesting
conditions and/or performance goals are met.

Certain employees are granted equity awards with a portion subject only to
service conditions, and the other portion subject to performance conditions.
A total of 0.2 million, 0.2 million, and 0.3 million time-based equity shares
subject only to service conditions were granted annually in 2021, 2020 and
2019, respectively.

The performance conditions for a portion of the awards granted from 2019
to 2021 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 (excluding restricted stock):

(Units in Thousands)

2021

2020

2019

Granted units

421

411

483

Deferred tax assets:

Regulatory liabilities

Operating lease liabilities

Tax credit carryforward

NOL carryforward

NOL and tax credit valuation allowances

Other employee benefits

Deferred ITCs

Other

Total deferred tax assets

Net deferred tax liability

$ 780

351

1,261

247

(64)

119

107

806

400

880

(64)

141

Weighted average grant date
fair value

Equity awards vested:

(Units in Thousands, Fair
Value in Millions)

$ 2,816

$ 2,311

$ 4,894

$ 4,746

Vested Units

Total Fair Value

66.03

62.92

49.67

2021

2020

2019

392

442

464

(a) Prior periods have been reclassified to conform to current year presentation.

Changes in the nonvested portion of equity award units:

(Units in Thousands)

Units

Nonvested Units at Jan. 1, 2021

780

Granted

Forfeited

Vested

Dividend equivalents

Nonvested Units at Dec. 31, 2021

421

(146)

(392)

695

Weighted Average
Grant Date Fair Value

55.68

66.03

61.76

48.91

58.00

64.59

8. Share-Based Compensation

Incentive Plan Including Share-Based Compensation — Xcel Energy
has an incentive plan which includes share-based payment elements, the
Amended and Restated 2015 Omnibus Incentive Plan with 7.0 million
equity shares authorized.

Restricted Stock — The Amended and Restated 2015 Omnibus Incentive
Plan allows certain employees to elect to receive shares of common or
restricted stock. Restricted stock is treated as an equity award and vests
and settles in equal annual installments over a three-year period. Restricted
stock has a fair value equal to the market trading price of Xcel Energy stock
at the grant date.

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.

Grant date fair value of equity awards is expensed over the service period.
TSR liability awards have been historically settled partially in cash, and do
not qualify as equity awards, but rather are accounted for as liabilities. As
liability awards, the fair value on which ratable expense is based, as
employees vest in their rights to those awards, is remeasured each period
based on the current stock price and performance achievement, and final
expense is based on the market value of the shares on the date the award
is settled.

Compensation costs related to share-based awards:

Stock equivalent units granted:

(Units in Thousands)

2021

2020

2019

Granted units

Weighted average grant date
fair value

68.15

61.61

58.44

Changes in stock equivalent units:

(Units in Thousands)

Units

Stock equivalent units at Jan. 1, 2021

630

Granted

Units distributed

Dividend equivalents

Stock equivalent units at Dec. 31, 2021

(73)

604

Weighted Average
Grant Date Fair Value

36.28

68.15

31.47

66.98

39.27

TSR Liability Awards — Xcel Energy Inc.’s Board of Directors has granted
TSR liability awards under the Amended and Restated 2015 Omnibus
Incentive Plan. This plan allows Xcel Energy to attach various performance
goals to the awards granted. The liability awards have been historically
dependent on relative TSR measured over a three-year period. Xcel
Energy Inc.’s TSR is compared to a peer group of other utility companies.
Potential payouts of the awards range from zero to 200%.

TSR liability awards granted:

(In Thousands)

Awards granted

TSR liability awards settled:

(Units In Thousands, Settlement
Amount in Millions)

2021

2020

2019

221

212

225

2021

2020

2019

Awards settled

446

476

Settlement amount (cash, common stock
and deferred amounts)

466

TSR liability awards of $22 million were settled in cash in 2021.

Share-Based Compensation Expense — Other than for restricted stock,
vesting of employee equity awards
the
achievement of a TSR or environmental measures target. Additionally,
approximately 0.2 million, 0.2 million, and 0.3 million of equity award units
were granted in 2021, 2020, and 2019, respectively, with vesting subject
only to service conditions of three years.

typically predicated on

Generally, these instruments are considered to be equity awards as the
award settlement determination (shares or cash) is made by Xcel Energy,
not the participants. In addition, these awards have not been previously
settled in cash and Xcel Energy plans to continue electing share
settlement.

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

2021

2020

2019

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

There was approximately $28 million in 2021 and $51 million in 2020 of
total unrecognized compensation cost related to nonvested share-based
compensation awards. Xcel Energy expects to recognize the unrecognized
amount over a weighted average period of 1.6 years.

9. Earnings Per Share

Basic EPS was computed by dividing the earnings available to common
shareholders by the weighted average number of common shares
outstanding. 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 — Xcel Energy Inc. has common stock
equivalents related to forward equity agreements and certain equity awards
in share-based compensation arrangements. Common stock equivalents
include commitments to issue common stock related to time-based equity
compensation awards.

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

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

•

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

Common shares outstanding used
computation:

the basic and diluted EPS

(Shares in Millions)

2021

2020

2019

Basic

(a)

Diluted

539

540

527

528

519

520

(a)

Diluted common shares outstanding included common stock equivalents of 0.3 million,
1.1 million and 1.3 million shares for 2021, 2020 and 2019, respectively.

The value of an FTR is derived from, and designed to offset, the cost of
transmission congestion. If forecasted costs of electric transmission
congestion increase or decrease for a given FTR path, the value of that
particular FTR instrument will likewise increase or decrease. Given the
limited observability of certain inputs to the value of FTRs between auction
processes, including expected plant operating schedules and retail and
wholesale demand, fair value measurements for FTRs have been assigned
a Level 3.

Non-trading monthly FTR settlements are included in fuel and purchased
energy cost recovery mechanisms as applicable in each jurisdiction, and
therefore changes in the fair value of the yet to be settled portions of most
FTRs are deferred as a regulatory asset or liability. Given this regulatory
treatment and the limited magnitude of FTRs relative to the electric utility
operations of NSP-Minnesota and SPS, the numerous unobservable
quantitative inputs pertinent to the value of FTRs are immaterial to the
consolidated financial statements.

Non-Derivative Fair Value Measurements

Nuclear Decommissioning Fund

The NRC requires NSP-Minnesota to maintain a portfolio of investments to
fund the costs of decommissioning its nuclear generating plants. Assets of
the nuclear decommissioning fund are legally restricted for the purpose of
decommissioning these facilities. The fund contains cash equivalents, debt
securities, equity securities and other investments. NSP-Minnesota uses
the MPUC approved asset allocation for the investment targets by asset
class for the qualified trust.

NSP-Minnesota recognizes the costs of funding the decommissioning over
the lives of the nuclear plants, assuming rate recovery of all costs. Realized
and unrealized gains on fund investments over the life of the fund are
deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear
decommissioning costs. Consequently, any realized and unrealized gains
and losses on securities in the nuclear decommissioning fund are deferred
as a component of the regulatory asset.

Unrealized gains for the nuclear decommissioning fund were $1.3 billion
and $981 million as of Dec. 31, 2021 and 2020, respectively, and
unrealized losses were $7 million and $5 million as of Dec. 31, 2021 and
2020, respectively.

Non-derivative instruments with recurring fair value measurements:

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

856

631

—

Equity securities

411

1,222

$ —

—

666

—

1,294

—

1,294

675

1,223

Total

$ 1,962

$ 1,286

667

$ 1,294

$ 3,256

(a)

Reported in nuclear decommissioning fund and other investments on the consolidated

balance sheet, which also includes $208 million of equity investments in unconsolidated

subsidiaries and $164 million of rabbi trust assets and miscellaneous investments.

10. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

Accounting guidance for fair value measurements and disclosures provides
a single definition of fair value and requires disclosures about assets and
liabilities measured at fair value. A hierarchical framework for disclosing the
observability of the inputs utilized in measuring assets and liabilities at fair
value is established by this guidance.

•

Level 1 — Quoted prices are available in active markets for identical
assets or liabilities as of the reporting date. The types of assets and
liabilities included in Level 1 are highly liquid and actively traded
instruments with quoted prices.
Level 2 — Pricing inputs are other than quoted prices in active
markets but are either directly or indirectly observable as of the
reporting date. The types of assets and liabilities included in Level 2
are typically either comparable to actively traded securities or
contracts or priced with models using highly observable inputs.
Level 3 — Significant inputs to pricing have little or no observability as
of the reporting date. The types of assets and liabilities included in
requiring significant
Level 3 are
management judgment or estimation.

those valued with models

Specific valuation methods include:

Cash equivalents — The fair values of cash equivalents are generally
based on cost plus accrued interest; money market funds are measured
using quoted NAV.

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
commingled
in
commingled funds may be redeemed for NAV with proper notice. Private
equity commingled fund investments require approval of the fund for any
unscheduled redemption, and such redemptions may be approved or
denied by the fund at its sole discretion. Unscheduled distributions from
real estate commingled fund investments may be redeemed with proper
notice, however, withdrawals may be delayed or discounted as a result of
fund illiquidity.

investments

Investments in debt securities — Fair values for debt securities are
determined by a third-party pricing service using recent trades and
observable spreads from benchmark interest rates for similar securities.

Interest rate derivatives — Fair values of interest rate derivatives are
based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives — Methods used to measure the fair value of
commodity derivative forwards and options utilize forward prices and
volatilities, as well as pricing adjustments for specific delivery locations, and
are generally assigned a Level 2 classification. When contractual
settlements relate to inactive delivery locations or extend to periods beyond
those readily observable on active exchanges or quoted by brokers, the
significance of the use of less observable forecasts of forward prices and
volatilities on a valuation is evaluated and may result in Level 3
classification.

Electric commodity derivatives held by NSP-Minnesota and SPS include
transmission congestion instruments, generally referred to as FTRs. FTRs
purchased from 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.

Dec. 31, 2020

Fair Value

(Millions of Dollars)
Nuclear decommissioning fund (a)

Cost

Level 1

Level 2

Level 3

NAV

Total

$ —

Cash equivalents

Commingled funds

Debt securities

787

528

—

Equity securities

446

1,109

—

572

Total

$ 1,801

$ 1,149

574

—

1,041

—

1,041

585

1,111

$ 1,041

$ 2,777

(a)

Reported in nuclear decommissioning fund and other investments on the consolidated

balance sheet, which also includes $165 million of equity investments in unconsolidated

subsidiaries and $154 million of rabbi trust assets and miscellaneous investments.

For the years ended Dec. 31, 2021 and 2020, 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, 2021:

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

149

208

314

675

Rabbi Trusts

Xcel Energy has established rabbi trusts to provide partial funding for future
distributions of its SERP and deferred compensation plan.

Cost and fair value of assets held in rabbi trusts:

(Millions of Dollars)

Rabbi Trusts

(a)

Cash equivalents

Mutual funds

Total

Dec. 31, 2021

Fair Value

Cost

Level 1

Level 2

Level 3

Total

109

—

109

(a)

Reported in nuclear decommissioning fund and other investments on the consolidated
balance sheet.

(Millions of Dollars)

Rabbi Trusts

(a)

Cash equivalents

Mutual funds

Total

Dec. 31, 2020

Fair Value

Cost

Level 1

Level 2

Level 3

Total

102

—

102

(a)

Reported in nuclear decommissioning fund and other investments on the consolidated
balance sheet.

Derivative Instruments Fair Value Measurements

Xcel Energy enters into derivative instruments, including forward contracts,
futures, swaps and options, for trading purposes and to manage risk in
connection with changes in interest rates, utility commodity prices and
vehicle fuel prices.

Interest Rate Derivatives — Xcel Energy enters into various instruments
that effectively fix the yield or price on a specified benchmark interest rate
for an anticipated debt issuance for a specific period. These derivative
instruments are generally designated as cash flow hedges for accounting
purposes, with changes in fair value prior to settlement recorded as other
comprehensive income.

As of Dec. 31, 2021, accumulated other comprehensive loss related to
settled interest rate derivatives included $5 million of net losses expected to
be reclassified into earnings during the next 12 months as the hedged
transactions impact earnings. As of Dec. 31, 2021, Xcel Energy had no
unsettled interest rate derivatives.

Wholesale and Commodity Trading Risk — Xcel Energy Inc.’s utility
subsidiaries conduct various wholesale and commodity trading activities,
including the purchase and sale of electric capacity, energy, energy-related
instruments and natural gas-related instruments, including derivatives. Xcel
Energy is allowed to conduct these activities within guidelines and
limitations as approved by its risk management committee, comprised of
management personnel not directly involved in activities governed by this
policy.

Commodity Derivatives — Xcel Energy enters into derivative instruments
to manage variability of future cash flows from changes in commodity
prices in its electric and natural gas operations, as well as for trading
purposes. This could include the purchase or sale of energy or energy-
related products, natural gas to generate electric energy, natural gas for
resale, FTRs, vehicle fuel and weather derivatives.

Xcel Energy may enter into derivative instruments that mitigate commodity
price risk on behalf of electric and natural gas customers but may not be
transactions. The classification of
designated as qualifying hedging
unrealized losses or gains on these instruments as a regulatory asset or
liability,
recovery
mechanisms.

is based on approved

if applicable,

regulatory

As of Dec. 31, 2021, Xcel Energy had no commodity contracts designated
as cash flow hedges.

Xcel Energy enters into commodity derivative instruments for trading
purposes not directly related to commodity price risks associated with
serving its electric and natural gas customers. Changes in the fair value of
these commodity derivatives are recorded in electric operating revenues,
net of amounts credited to customers under margin-sharing mechanisms.

Gross notional amounts of commodity forwards, options and FTRs:

(Amounts in Millions)

(a)(b)

MWh of electricity

MMBtu of natural gas
(a)

Dec. 31, 2021

Dec. 31, 2020

156

175

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, 2021, six of Xcel Energy’s 10 most significant counterparties
for these activities, comprising $83 million or 38% of this credit exposure,
had investment grade credit ratings from S&P, Moody’s Investor Services
the 10 most significant counterparties,
or Fitch Ratings. Three of
comprising $44 million or 20% of this credit exposure, were not rated by
these external agencies, but based on Xcel Energy’s internal analysis, had
credit quality consistent with investment grade. One of these significant
counterparties, comprising $38 million or 18% of this credit exposure, had
credit quality less than investment grade, based on internal analysis. Eight
of these significant counterparties are municipal or cooperative electric
entities, RTOs or other utilities.

Qualifying Cash Flow Hedges — Financial impact of qualifying interest
rate cash flow hedges on Xcel Energy’s accumulated other comprehensive
loss, included in the consolidated statements of common stockholders’
equity and in the consolidated statements of comprehensive income:

(Millions of Dollars)

2021

2020

2019

Accumulated other comprehensive loss related to cash flow
hedges at Jan. 1

After-tax net unrealized gains (losses) related to derivatives
accounted for as hedges

After-tax net realized losses on derivative transactions
reclassified into earnings

Accumulated other comprehensive loss related to cash flow
hedges at Dec. 31

Impact of derivative activity:

(85) $

(80) $

(60)

Interest rate

Total

(10)

(23)

Other derivative instruments

Commodity trading

Electric commodity

(75) $

(85) $

(80)

Natural gas commodity

Total

—

Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from:

Accumulated
Other
Comprehensive
Loss

Regulatory
Assets and
(Liabilities)

Pre-Tax Gains
(Losses)
Recognized
During the
Period in
Income

(Millions of Dollars)

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

Year Ended Dec. 31, 2019

Derivatives designated as cash flow hedges

Interest rate

Total

Other derivative instruments

Commodity trading

Electric commodity

Natural gas commodity

Total

—

(a)

—

(23)

(c)

(d)

(18)

—

(c)

(d)

—

(3)

—

(5)

(3)

(c)

(d)

—

(b)

(d)

(22)

—

(b)

(d)

(1)

—

(13)

(14)

—

(7)

(5)

(b)

(d)

(a)

(b)

(c)

(d)

Recorded to interest charges.

Recorded to electric operating revenues. Portions of these gains and losses are subject

to sharing with electric customers through margin-sharing mechanisms and deducted

from gross revenue, as appropriate.

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.

Settlement losses related to natural gas operations are recorded to cost of natural gas

sold and transported. These losses are subject to cost-recovery mechanisms and

reclassified out of income to a regulatory asset, as appropriate.

Xcel Energy had no derivative instruments designated as fair value hedges
during the years ended Dec. 31, 2021, 2020 and 2019.

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, 2021

Derivatives designated as cash flow hedges

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

Year Ended Dec. 31, 2019

Interest rate

Total

Other derivative instruments

Electric commodity

Natural gas commodity

Total

—

(13)

—

(30)

—

(4)

—

(5)

(13)

(18)

—

(9)

(1)

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, 2021
and 2020, there were $3 million and $4 million of derivative instruments in a
liability position with such underlying contract provisions, respectively.
Certain contracts also contain cross default provisions that may require the
posting of collateral or settlement of the contracts if there was a failure
under the other financing arrangements related to payment terms or other
covenants.

As of Dec. 31, 2021 and 2020, there were approximately $64 million and
$60 million of derivative instruments in a liability position with such
underlying contract provisions, respectively.

Certain derivative instruments are also subject to contract provisions that
contain adequate assurance clauses. Provisions allow counterparties to
seek performance assurance, including cash collateral, in the event that a
given utility subsidiary’s ability to fulfill its contractual obligations is
reasonably expected to be impaired. Xcel Energy had no collateral posted
related to adequate assurance clauses in derivative contracts as of Dec.
31, 2021 and 2020.

Recurring Fair Value Measurements — Derivative assets and liabilities measured at fair value on a recurring basis were as follows:

Dec. 31, 2021

Dec. 31, 2020

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

$ 22
—
—
$ 22

$ 137
—
18
$ 155

$ 21
57
—
$ 78

180
57
18
255

(134) $
(1)
—
(135)

$ 16
$ 16

$ 63
$ 63

$ 89
$ 89

$
$

168
168

$
$

(107) $
(107)

46
56
18
120
3
123

61
61
6
67

2
$
—
—
2
$

$ 67
—
9
$ 76

1
20
—
$ 21

70
20
9
99

(52) $
(1)
—
(53)

$
$

8
8

$ 66
$ 66

$
$

8
8

$
$

82
82

$
$

(62) $
(62)

Dec. 31, 2021

Dec. 31, 2020

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

(Millions of Dollars)
Current derivative assets
Other derivative instruments:

Commodity trading
Electric commodity
Natural gas commodity

Total current derivative assets

PPAs (b)

Current derivative instruments

Noncurrent derivative assets
Other derivative instruments:

Commodity trading

Total noncurrent derivative assets

PPAs (b)

Noncurrent derivative instruments

(Millions of Dollars)
Current derivative liabilities

Other derivative instruments:

Commodity trading

Electric commodity

Natural gas commodity

$ 19

$ 148

$ 20

187

(143) $

—

(1)

—

$ 64

$ 17

(58) $

—

$ 73

$ 18

(1)

—

(59)

Total current derivative liabilities

$ 19

$ 156

$ 21

196

(144)

PPAs (b)

Current derivative instruments

Noncurrent derivative liabilities

Other derivative instruments:

Commodity trading

$ 18

$ 48

$ 127

Total noncurrent derivative liabilities

$ 18

$ 48

$ 127

193

(128) $

(128)

PPAs (b)

$ 58

$ 60

$ 58

$ 60

121

(47) $

(47)

Noncurrent derivative instruments

105

131

(a)

(b)

Xcel Energy nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement and all derivative

instruments and related collateral amounts were subject to master netting agreements as of Dec. 31, 2021 and 2020. At Dec. 31, 2021, derivative assets and liabilities include no obligations
to return cash collateral. At Dec. 31, 2020, derivative assets and liabilities include $15 million of obligations to return cash collateral. At Dec. 31, 2021 and 2020, derivative assets and

liabilities include rights to reclaim cash collateral of $30 million and $6 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-

derivative amounts that may be subject to the same master netting agreements.

During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, contracts are no longer adjusted to fair value and the previous carrying

value of these contracts is being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

18
19
9
46
3
49

20
20
10
30

—

Year Ended Dec. 31

2021

2020

2019

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.

(64)

Obligations of the SERP and nonqualified plan as of Dec. 31, 2021 and
2020 were $43 million and $43 million, respectively. Xcel Energy
recognized net benefit cost for the SERP and nonqualified plans of $4
million in 2021 and $6 million in 2020.

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
long-term projected return levels.

Pension cost determination assumes a forecasted mix of investment types
over the long-term.

•
•
•
•

Investment returns in 2021 were above the assumed level of 6.49%.
Investment returns in 2020 were above the assumed level of 6.87%.
Investment returns in 2019 were above the assumed level of 6.87%.
In 2022, expected investment-return assumption is 6.49%.

Pension plan and postretirement benefit assets are invested in a portfolio
according to Xcel Energy’s return, liquidity and diversification objectives to
provide a source of funding for plan obligations and minimize contributions
to the plan, within appropriate levels of risk. The principal mechanism for
achieving these objectives is the asset allocation given the long-term risk,
return, correlation and liquidity characteristics of each particular asset
class.

There were no significant concentrations of risk in any industry, index, or
entity. Market volatility can impact even well-diversified portfolios and
significantly affect the return levels achieved by the assets in any year.

State agencies also have issued guidelines to the funding of postretirement
benefit costs. SPS is required to fund postretirement benefit costs for Texas
and New Mexico amounts collected in rates. PSCo is required to fund
postretirement benefit costs in irrevocable external trusts that are dedicated
to the payment of these postretirement benefits. These assets are invested
in a manner consistent with the investment strategy for the pension plan.

Xcel Energy’s ongoing investment strategy is based on plan-specific
investment recommendations that seek to minimize potential investment
and interest rate risk as a plan’s funded status increases over time. The
investment recommendations consider many factors and generally result in
a greater percentage of long-duration fixed income securities being
allocated to specific plans having relatively higher funded status ratios and
a greater percentage of growth assets being allocated to plans having
relatively lower funded status ratios.

Changes in Level 3 commodity derivatives:

(Millions of Dollars)

Balance at Jan. 1

Purchases

Settlements

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

Balance at Dec. 31
(a)

(49) $

(158)

112

(73)

(39)

(8)

(49) $

Level 3 losses recognized in earnings are subject to offsetting gains of derivative

instruments categorized as levels 1 and 2 in the income statement.

Xcel Energy recognizes transfers between levels as of the beginning of
each period. There were no transfers of amounts between levels for
derivative instruments for Dec. 31, 2021, 2020 and 2019.

Fair Value of Long-Term Debt

As of Dec. 31, other financial instruments for which the carrying amount did
not equal fair value:

(Millions of Dollars)

Long-term debt, including current
portion

2021

2020

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value

22,380

$ 25,232

20,066

$ 24,412

Fair value of Xcel Energy’s long-term debt is estimated based on recent
trades and observable spreads from benchmark interest rates for similar
securities. Fair value estimates are based on information available to
management as of Dec. 31, 2021 and 2020, and given the observability of
the inputs, fair values presented for long-term debt were assigned as Level
2.

11. Benefit Plans and Other Postretirement Benefits

Pension and Postretirement Health Care Benefits

Xcel Energy has several noncontributory, qualified, defined benefit pension
plans that cover almost all employees. All newly hired or rehired employees
participate under the Cash Balance formula, which is based on pay credits
using a percentage of annual eligible pay and annual interest credits. The
average annual interest crediting rates for these plans was 2.03, 1.89 and
2.82% in 2021, 2020, and 2019, respectively. Some employees may
participate under legacy formulas such as the traditional final average pay
or pension equity. Xcel Energy’s policy is to fully fund into an external trust
the actuarially determined pension costs subject to the limitations of
applicable employee benefit and tax laws.

In addition to the qualified pension plans, Xcel Energy maintains a SERP
and a nonqualified pension plan. The SERP is maintained for certain
executives 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, 2021 (a)

Dec. 31, 2020 (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

133

1,324

—

959

—

133

209

1,143

—

2,467

964

1,462

—

714

—

1,115

—

209

2,577

718

1,524

966

1,175

3,670

1,761

719

1,115

3,599

(a)

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

For each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that were measured at fair value:
Dec. 31, 2021 (a)

Dec. 31, 2020

(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

—

218

—

272

—

141

219

442

—

232

284

—

141

232

452

(a)

See Note 10 for further information on fair value measurement inputs and methods.

No assets were transferred in or out of Level 3 for 2021 or 2020.

Funded Status — Benefit obligations for both pension and postretirement plans decreased from Dec. 31, 2020 to Dec. 31, 2021, due primarily to benefit
payments and increases in discount rates used in actuarial valuations. Comparisons of the actuarially computed benefit obligation, changes in plan assets
and funded status of the pension and postretirement health care plans for Xcel Energy are as follows:

(Millions of Dollars)

Change in Benefit Obligation:

Obligation at Jan. 1

Service cost

Interest cost

Plan amendments

Actuarial (gain) loss

Plan participants’ contributions

Medicare subsidy reimbursements
Benefit payments (a)

Obligation at Dec. 31

Change in Fair Value of Plan Assets:

Fair value of plan assets at Jan. 1

Actual return on plan assets

Employer contributions

Plan participants’ contributions

Benefit payments

Fair value of plan assets at Dec. 31

Funded status of plans at Dec. 31

Amounts recognized in the Consolidated Balance Sheet at Dec. 31:

Noncurrent assets

Current liabilities

Noncurrent liabilities

Net amounts recognized

Pension Benefits

Postretirement Benefits

2021

2020

2021

2020

3,964

3,701

574

104

(94)

—

(365)

3,718

125

—

328

—

(285)

3,964

—

(41)

(49)

511

3,599

3,184

452

305

131

—

(365)

3,670

(48) $

—

(67)

(48) $

550

150

—

(285)

3,599

(365) $

—

(365)

(365) $

(49)

442

(69) $

(4)

(98)

(69) $

547

—

(51)

574

449

(51)

452

(122)

(7)

(121)

(122)

(a)

Includes approximately $197 million in 2021 and $0 million in 2020 of lump-sum benefit payments used in the determination of a settlement charge.

Significant Assumptions Used to Measure Benefit Obligations:

2021

2020

2021

2020

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

3.08 %

3.75

PRI-2012

N/A

2.71 %

3.75

PRI-2012

N/A

3.09 %

N/A

PRI-2012

5.30 %

4.90 %

4.50 %

2.65 %

N/A

PRI-2012

5.50 %

5.00 %

4.50 %

Accumulated benefit obligation for the pension plan was $3,469 million and $3,693 million as of Dec. 31, 2021 and 2020, respectively.

Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other income (expense) in the
consolidated statements of income.

Components of net periodic benefit cost (credit) and amounts recognized in other comprehensive income and regulatory assets and liabilities:

(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

2021

2020

2019

2021

2020

2019

104

(206)

(1)

107

167

(46)

121

2.71 %

3.75

6.49

125

(208)

(4)

100

—

108

145

(203)

(5)

116

(1)

117

115

(18)

(8)

—

(4)

(2)

(19)

(8)

—

(4)

(1)

(21)

(10)

—

(2)

(1)

3.49 %

3.75

6.87

4.31 %

3.75

6.87

2.65 %

—

4.10

3.47 %

—

4.50

4.32 %

—

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 2021 and 2019, as a result of lump-sum distributions during each plan year, Xcel Energy recorded a total pension settlement charge of $59 million and $6 million,

respectively, the majority of which was not recognized due to the effects of regulation. A total of $7 million and $1 million was recorded in the consolidated statements of income in 2021 and

2019, respectively. There were 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

2021

2020

2021

2020

978

(9)

969

846

—

1,333

(11)

1,322

1,181

—

(7)

—

(1)

(19)

969

1,322

126

(15)

111

—

125

(1)

(18)

111

Dec. 31, 2021

Dec. 31, 2020

Dec. 31, 2021

Dec. 31, 2020

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 2019 - 2022 to meet minimum funding
requirements.

Voluntary and required pension funding contributions:

•
•
•
•

$50 million in January 2022.
$131 million in 2021.
$150 million in 2020.
$154 million in 2019.

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

Voluntary postretirement funding contributions:

•
•
•
•

Expects to contribute approximately $9 million during 2022.
$15 million during 2021.
$11 million during 2020.
$15 million during 2019.

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

2021

2020

2021

2020

33 %

35 %

15 %

—

100 %

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

Plan Amendments —

In 2019, the Pension Protection Act measurement concept was extended
beyond 2019 for NSP bargaining terminations and retirements to Dec. 31,
2022.

There were no significant plan amendments made in 2020 which affected
the postretirement benefit obligation.

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

Projected Benefit Payments

Xcel Energy’s projected benefit payments:

(Millions of Dollars)

Projected
Pension
Benefit
Payments

Gross Projected
Postretirement
Health Care
Benefit Payments

Expected
Medicare Part
D
Subsidies

Net Projected
Postretirement
Health Care
Benefit Payments

2022

2023

2024

2025

2026

2027-2031

323

257

253

251

245

1,156

165

152

Defined Contribution Plans

Xcel Energy maintains 401(k) and other defined contribution plans that
cover most employees. Total expense to these plans was approximately
$43 million in 2021, $42 million in 2020 and $39 million in 2019.

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

Xcel Energy is involved in various litigation matters in the ordinary course of
business. The assessment of whether a loss is probable or is a reasonable
possibility, and whether the loss or a range of loss is estimable, often
involves a series of complex judgments about future events. Management
maintains accruals for losses probable of being incurred and subject to
reasonable estimation. Management is sometimes unable to estimate an
amount or range of a reasonably possible loss in certain situations,
including but not limited to when (1) the damages sought are indeterminate,
(2) the proceedings are in the early stages, or (3) the matters involve novel
or unsettled legal theories.

In such cases, there is considerable uncertainty regarding the timing or
ultimate resolution,
loss. For current
including a possible eventual
proceedings not specifically reported herein, management does not
anticipate that the ultimate liabilities, if any, would have a material effect on
Xcel Energy’s consolidated financial statements. Legal fees are generally
expensed as incurred.

Gas Trading Litigation — e prime is a wholly owned subsidiary of
Xcel Energy. e prime was in the business of natural gas trading and
marketing but has not engaged in natural gas trading or marketing activities
since 2003. Multiple lawsuits involving multiple plaintiffs seeking monetary
damages were commenced against e prime and its affiliates, including
Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive
activities in conspiring to restrain the trade of natural gas and manipulate
natural gas prices. Cases were all consolidated in the U.S. District Court in
Nevada.

One case remains active which includes a multi-district litigation matter
consisting of a Wisconsin purported class (Arandell Corp.).

Arandell Corp. — The trial has been vacated and will be rescheduled after
the court rules on the pending motions for reconsideration and for class
certification. Xcel Energy has concluded that a loss is remote for the
remaining lawsuit.

Breckenridge/Colorado — In February 2019, the MDL panel remanded
Breckenridge back to the U.S. District Court in Colorado. Settlement of
approximately $3 million was reached in February 2021. In July 2021, the
settlement was approved.

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.

Minnesota Winter Storm Uri Costs — In its Minnesota jurisdiction, NSP-
Minnesota is participating in a contested case regarding the prudency of
incremental natural gas costs incurred during Winter Storm Uri. Other
parties to the case have recommended significant cost disallowances, and
while ultimate resolution of the matter is uncertain, it is reasonably possible
that the MPUC could disallow certain deferred costs, resulting in earnings
losses. The OAG recommended the MPUC deny recovery of up to
$179 million, the largest recommendation among the intervenor positions.

NSP-Minnesota strongly disagrees with the recommendations of the DOC,
OAG and CUB, and believes that it acted prudently and according to MPUC
its customers and
approved procedures
stakeholders.

interest of

the best

for

NSP-Minnesota filed rebuttal testimony in January 2022 detailing its
position that the disallowances recommended by other parties lack any
merit in the prudency review given the pertinent facts regarding NSP-
Minnesota’s actions before, during and after the storm event. An MPUC
decision is expected in the summer of 2022.

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 FCA.

In March 2019, the MPUC approved NSP-Minnesota’s settlement refund
proposal. Additionally, the MPUC decided to withhold any decision as to
NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3
until after conclusion of an appeal pending between GE and NSP-
Minnesota’s insurers. In February 2020, the Minnesota Court of Appeals
affirmed the district court’s judgment in favor of GE. In March 2020, NSP-
Minnesota’s insurers filed a petition seeking additional review by the
Minnesota Supreme Court.

In April 2020, the Minnesota Supreme Court denied the insurers’ petition for
further review, ending the litigation.

through

the FCA. NSP-Minnesota subsequently

In January 2021, the OAG and DOC recommended that NSP-Minnesota
refund approximately $17 million of replacement power costs previously
recovered
its
response, asserting that it acted prudently in connection with the Sherco
Unit 3 outage, the MPUC has previously disallowed $22 million of related
costs and no additional refund or disallowance is appropriate. A final
decision by the MPUC is pending. A loss related to this matter is deemed
remote.

filed

insurers of

In November 2014,

Westmoreland Arbitration —
the
Westmoreland Coal Company filed an arbitration demand against NSP-
Minnesota, Southern Minnesota Municipal Power Agency and Western
Fuels Association, seeking recovery of alleged $36 million of business
losses due to a turbine failure at Sherco Unit 3. The Westmoreland insurers
claim NSP-Minnesota’s invocation of the force majeure clause to stop the
supply of coal was improper because the incident was allegedly caused by
NSP-Minnesota’s failure to conform to industry maintenance standards.

NSP-Minnesota denies the claims asserted by the Westmoreland insurers
and believes it properly stopped the supply of coal based upon the force
majeure provision. A final hearing has been scheduled for October 2022.
The parties are also required to participate in mediation, which has been
scheduled for the first quarter of 2022. At this stage of the proceeding, a
reasonable estimate of damages or range of damages cannot be
determined.

MISO ROE Complaints — In November 2013 and February 2015,
customer groups filed two ROE complaints against MISO TOs, which
includes NSP-Minnesota and NSP-Wisconsin. The
first complaint
requested a reduction in base ROE transmission formula rates from
12.38% to 9.15% for the time period of Nov. 12, 2013 to Feb. 11, 2015, and
removal of ROE adders (including those for RTO membership). The second
complaint requested, for a subsequent time period, a base ROE reduction
from 12.38% to 8.67%.

In September 2016, the FERC issued an order (Opinion No. 551) granting
a 10.32% base ROE effective for the first complaint period of Nov. 12, 2013
to Feb. 11, 2015 and subsequent to the date of the order. The D.C Circuit
subsequently vacated and remanded Opinion No. 551.

In November 2019, the FERC issued an order (Opinion No. 569), which set
the MISO base ROE at 9.88%, effective Sept. 28, 2016 and for the first
complaint period. The FERC also dismissed the second complaint. In
December 2019, MISO TOs filed a request for rehearing regarding the new
ROE methodology announced in Opinion No. 569. Customers also filed
requests for rehearing claiming, among other points, that the FERC erred
by dismissing the second complaint without refunds.

In May 2020, the FERC issued an order (Opinion No. 569-A) which granted
rehearing in part to Opinion 569 and further refined the FERC’s ROE
methodology, most significantly to incorporate the risk premium model (in
addition to the discounted cash flow and capital asset pricing models),
resulting in a new base ROE of 10.02%, effective Sept. 28, 2016 and for
the first complaint period. The FERC also affirmed its decision in Opinion
No. 569 to dismiss the second complaint.

In November 2020, the FERC issued an order (Opinion No. 569-B) in
response to rehearing requests. The FERC corrected certain inputs to its
ROE calculation model, did not change the ROE effective Sept. 28, 2016,
and for the first MISO complaint period and upheld its decision to deny
refunds for the second complaint period. NSP-Minnesota has recognized a
liability for its best estimate of final refunds to customers. Each 10 basis
point reduction in ROE for the first complaint period, second complaint
period and subsequent period relative to amounts accrued would reduce
Xcel Energy’s net income by $1 million, $1 million and $2 million,
respectively.

The MISO TOs and various parties have filed petitions for review of Opinion
Nos. 569, 569-A and 569-B at the D.C. Circuit. Oral arguments were held in
late 2021 and a decision is expected by the end of the third quarter of 2022.

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 July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings
granting SPP the right to recover previously unbilled charges was
remanded to the FERC. In February 2019, the FERC reversed its 2016
decision and ordered SPP to refund charges retroactively collected from its
to periods before
transmission customers,
September 2015.

including SPS,

In March 2020, SPP and Oklahoma Gas & Electric separately filed petitions
for review of the FERC’s orders at the D.C. Circuit. In August 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. The timing of these refunds is uncertain.

In October 2017, SPS filed a separate related complaint asserting SPP
assessed upgrade charges to SPS in violation of the SPP OATT. In March
2018, the FERC issued an order denying the SPS complaint. SPS filed a
request for rehearing in April 2018. The FERC issued a tolling order
granting a rehearing for further consideration in May 2018. If SPS’
complaint results in additional charges or refunds, SPS will seek to recover
or refund the amount through future SPS customer rates. In October 2020,
SPS filed a petition for review of the FERC’s March 2018 order and May
2018 tolling order at the D.C. Circuit. FERC has asked that this appeal be
stayed until early 2022, in order to provide FERC with time to issue an
order on SPS’ April 2018 rehearing request. FERC’s order is expected in
the first quarter of 2022. The D.C. Circuit appeal may resume after that
FERC order is issued.

Wind Operating Commitments — PUCT and NMPRC orders related to
the Hale and Sagamore wind projects included certain operating and
savings minimums. In general, annual generation must exceed a net
capacity factor of 48%. If annual generation is below the guaranteed level,
SPS would be obligated to refund an amount equal to foregone PTCs and
fuel savings. Additionally, retail customer savings must exceed project
costs included in base rates over the first ten years of operations. SPS
would be required to refund excess costs, if any, after ten years of
operations. As of Dec. 31, 2021, the full-year net capacity factor was
48.4%, resulting in no refund liability for 2021.

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

Comanche Unit 3 Litigation — In February 2021, the joint owners of
Comanche Unit 3 (CORE Electric Cooperative, formerly known as
Intermountain Rural Electrical Association, and Holy Cross Electric) served
PSCo with a notice of claim related to Comanche Unit 3's operation and
availability.

In September 2021, CORE Electric Cooperative filed a lawsuit in Colorado
state court seeking an unspecified amount of damages. CORE Electric
Cooperative alleges PSCo breached ownership agreement terms by failing
to operate Comanche Unit 3 in accordance with prudent utility practices.
PSCo filed a Motion to Dismiss several of CORE’s claims. In January 2022
the Court granted PSCo’s Motion to Dismiss CORE’s claim for damages for
replacement power costs, claims for unjust enrichment and declaratory
judgment. CORE’s claims for breach of contract, breach of the duty of good
faith and fair dealing, and waste remain pending.

In November 2021, PSCo resolved all differences with Holy Cross Electric
related to their claim.

Environmental

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

Site Remediation

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

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

Historical MGP, Landfill and Disposal Sites

Xcel Energy is currently investigating, remediating or performing post-
closure actions at 16 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

Coal Ash Regulation — Xcel Energy’s operations are subject to federal and
state regulations that impose requirements for handling, storage, treatment
and disposal of solid waste. Under the CCR Rule, utilities are required to
complete groundwater sampling around their CCR landfills and surface
impoundments. Currently, Xcel Energy has eight regulated ash units in
operation.

Xcel Energy is conducting groundwater sampling and monitoring and
implementing assessment of corrective measures at certain CCR landfills
and surface impoundments. In NSP-Minnesota, no results above the
groundwater protection standards in the rule were identified. In PSCo,
increases above background concentrations were detected at
four
locations. Based on further assessments, PSCo is evaluating options for
corrective action at two locations, one of which indicates potential offsite
impacts to groundwater. The total cost is uncertain, but could be up to
$35 million. PSCo is continuing to assess the financial and regulatory
impacts.

In August 2020, the EPA published its final rule to implement closure by
April 2021 for all CCR impoundments affected by the August 2018 D.C.
Circuit ruling. This final rule required Xcel Energy to expedite closure plans
for two impoundments.

In October 2020, NSP-Minnesota completed construction and placed in
service a new impoundment to replace the clay lined impoundment. With
the new ash pond in service, NSP-Minnesota has initiated closure activities
for the existing ash pond at an estimated cost of $4 million. NSP-Minnesota
has five years to complete closure activities.

PSCo also built an alternative collection and treatment system to remove
the Comanche Station bottom ash pond from service. The total cost of the
alternate treatment system is approximately $25 million. PSCo worked
expeditiously to meet the April 11, 2021 deadline, but was not able to
remove the pond from service until June 18, 2021. PSCo expects to
negotiate a compliance order with the EPA addressing the closure deadline
as well as other potential issues. PSCo will also now proceed with closure
of the pond, at an estimated cost of $3 million.

Closure costs for existing impoundments are included in the calculation of
the ARO.

Federal CWA Waters of the U.S. Rule — Xcel Energy is monitoring
ongoing changes to the definition of Waters of the U.S. under the CWA.
Regardless of which definition is applicable in the states in which we
operate, Xcel Energy does not anticipate that compliance costs will be
material.

Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power
plants that discharge treated effluent to surface waters as well as utility-
owned landfills that receive CCRs. In October 2020, the EPA published a
final rule revising the regulations.

The retirement of units affected by the final ELG rule is subject to regulatory
approval. The exact total cost of ELG compliance is therefore uncertain but
Xcel Energy does not anticipate that compliance costs will be material.

impingement and entrainment

Federal CWA Section 316(b) — The federal CWA requires the EPA to
regulate cooling water intake structures to assure that these structures
reflect the best technology available for minimizing impingement and
entrainment of aquatic species. Xcel Energy estimates the likely future cost
for complying with
is
approximately $39 million, to be incurred between 2022 and 2028. Xcel
Energy believes six NSP-Minnesota plants and two NSP-Wisconsin plants
could be required to make improvements to reduce impingement and
entrainment. The exact total cost of the impingement and entrainment
improvements is uncertain, but could be up to $192 million. Xcel Energy
anticipates these costs will be fully recoverable through regulatory
mechanisms.

requirements

Environmental Requirements — Air

Regional Haze Rules — The regional haze program requires SO2, nitrogen
oxide and particulate matter emission controls at power plants to reduce
visibility impairment in national parks and wilderness areas. The program
includes BART and reasonable further progress. The regional haze first
planning period requirements developed by Minnesota and Colorado were
approved by the EPA in 2012 and implemented by 2014 and 2016,
respectively. Texas’ first regional haze plan has undergone federal review.

All states are now subject to a second round of regional haze planning/
rulemaking, focusing on additional reductions to meet reasonable progress
requirements. Any additional impacts to Xcel Energy facilities are expected
to be minimal.

BART Determination for Texas: The EPA has issued a revised final rule
adopting a BART alternative Texas only SO2 trading program that applies
to all Harrington and Tolk units. Under the trading program, SPS expects
for SO2 emissions. The
to be sufficient
the allowance allocations
anticipated costs of compliance are not expected to have a material impact;
and SPS believes that compliance costs would be recoverable through
regulatory mechanisms.

Several parties have challenged whether the final rule issued by the EPA
should be considered to have met the requirements imposed in a Consent
Decree entered by the D.C. Circuit that established deadlines for the EPA
to take final action on state regional haze plan submissions. The court has
required status reports from the parties while the EPA works on the
reconsideration rulemaking.

In December 2017, the National Parks Conservation Association, Sierra
Club, and Environmental Defense Fund appealed the EPA’s 2017 final
BART rule to the Fifth Circuit and filed a petition for administrative
reconsideration. The court has held the litigation in abeyance while the EPA
decided whether to reconsider the rule. In August 2018, the EPA started a
reconsideration rulemaking. The EPA reaffirmed the rule in August 2020
with minor changes.

The 2020 EPA Action has been challenged. All pending actions could be
consolidated and may proceed in the Fifth Circuit or the D.C. Circuit, where
a parallel challenge has been filed. The timing of final decisions is unclear.

Reasonable Progress Rule: In 2016, the EPA adopted a final rule
establishing a federal implementation plan for reasonable further progress
under the regional haze program for the state of Texas. The rule imposes
SO2 emission limitations that would require the installation of dry scrubbers
on Tolk Units 1 and 2; compliance would have been required by February
2021. Investment costs associated with dry scrubbers could be $600
million. SPS appealed the EPA’s decision and obtained a stay of the final
rule.

In March 2017, the Fifth Circuit remanded the rule to the EPA for
reconsideration, leaving the stay in effect. In a future rulemaking, the EPA
will address whether SO2 emission reductions beyond those required in the
BART alternative rule referenced above are needed at Tolk under the
“reasonable progress” requirements. As states are now proceeding with the
second regional haze planning period, the EPA may choose not to act on
the remanded rule.

Implementation of the NAAQS for SO2 — The EPA has designated all
areas near SPS’ generating plants as attaining the SO2 NAAQS with one
exception. The EPA issued final designations, which found the area near
the SPS Harrington plant as “unclassifiable.” The area near the Harrington
plant was monitored for the three years ending in 2019 and the monitoring
showed the area to be exceeding the standard.

To address this issue, SPS negotiated an order with the TCEQ providing
for the end of coal combustion and the conversion of the Harrington plant to
a natural gas fueled facility by Jan. 1, 2025.

Xcel Energy believes compliance costs or the costs of alternative cost-
effective generation will be recoverable through regulatory mechanisms
and therefore does not expect a material impact on results of operations,
financial condition or cash flows.

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

Aggregate fair value of NSP-Minnesota’s legally restricted assets, for
funding future nuclear decommissioning was $3.3 billion and $2.8 billion for
2021 and 2020, respectively.

Xcel Energy’s AROs were as follows:

Indeterminate AROs — Other plants or buildings may contain asbestos
due to the age of many of Xcel Energy’s facilities, but no confirmation or
measurement of the cost of removal could be determined as of Dec. 31,
2021. Therefore, an ARO was not recorded for these facilities.

(Millions
of Dollars)

Electric

Nuclear

Wind

Steam, hydro and
other production

Distribution

Natural gas

Transmission and
distribution

Miscellaneous

Common

Miscellaneous

Non-utility

Miscellaneous

Amounts
Incurred
(a)

Accretion

Cash Flow
Revisions
(b)

Dec. 31, 2021
(c)

Jan. 1, 2021

1,957

—

360

264

252

101

—

2,056

478

288

271

3,151

Total liability

2,884

107

138

(a)

(b)

(c)

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.

There were no ARO amounts settled in 2021.

(Millions
of Dollars)

Electric

Nuclear

Jan.
1,
2020

Amounts
Incurred
(a)

Amounts
Settled
(b)

Accretion

Cash Flow
Revisions
(c)

Dec.
31,
2020

$ 2,068 $

—

105

(216) $ 1,957

Steam, hydro and
other production

Wind

Distribution

Natural gas

202

146

Transmission and
distribution

236

Miscellaneous

Common

Miscellaneous

Non-utility

Miscellaneous

—

149

—

(5)

(3)

—

264

360

252

Total liability

$ 2,701 $

149

(8) $

134

(92) $ 2,884

(a)

(b)

(c)

Amounts incurred related to the wind farms placed in service in 2020 for NSP-Minnesota

(Blazing Star 1, Crowned Ridge 2, Jeffers and Community Wind North), PSCo

(Cheyenne Ridge) and SPS (Sagamore).

Amounts settled primarily related to closure of certain ash containment facilities, removal
of wind facilities and asbestos abatement projects.

In 2020, AROs were revised for changes in timing and estimates of cash flows.

Revisions in the nuclear AROs were driven by reductions in spent fuel cooling time

requirements in the nuclear triennial filing coupled with decreasing interest rates.

Changes in wind AROs were driven by new dismantling studies. Revisions in steam,

hydro and other production AROs were primarily related to changes in cost estimates for

remediation of ash containment facilities.

Nuclear

Nuclear Insurance — NSP-Minnesota’s public liability for claims from any
nuclear incident is limited to $13.5 billion under the Price-Anderson
amendment to the Atomic Energy Act. NSP-Minnesota has secured $450
million of coverage for its public liability exposure with a pool of insurance
companies. The remaining $13.0 billion of exposure is funded by the
Secondary Financial Protection Program available from assessments by
the federal government.

NSP-Minnesota is subject to assessments of up to $138 million per reactor-
incident for each of its three reactors, for public liability arising from a
nuclear incident at any licensed nuclear facility in the United States. The
maximum funding requirement is $21 million per reactor-incident during any
one year. Maximum assessments are subject to inflation adjustments.

insurance

NSP-Minnesota purchases
for property damage and site
decontamination cleanup costs from NEIL and EMANI. The coverage limits
are $2.8 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL
also provides business interruption insurance coverage up to $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 $11
million for business interruption insurance and $33 million for property
damage insurance if losses exceed accumulated reserve funds.

Nuclear Fuel Disposal — NSP-Minnesota is responsible for temporarily
storing spent nuclear fuel from its nuclear plants. The DOE is responsible
for permanently storing spent fuel from U.S. nuclear plants, but no such
facility is yet available.

NSP-Minnesota owns temporary on-site storage facilities for spent fuel at
its Monticello and PI nuclear plants, which consist of storage pools and dry
cask facilities. The Monticello dry-cask storage facility currently stores all 30
of the authorized canisters. The PI dry-cask storage facility currently stores
47 of the 64 authorized casks. Monticello’s future spent fuel will continue to
be placed in its spent fuel pool. The decommissioning plan addresses the
disposition of spent fuel at the end of the licensed life. A CON for additional
storage at the Monticello site has been filed with the MPUC, to support
possible life extension. NSP-Minnesota expects a decision by year-end
2023.

Regulatory Plant Decommissioning Recovery — Decommissioning
activities for NSP-Minnesota’s nuclear facilities are planned to begin at the
end of each unit’s operating license and be completed by 2091. NSP-
Minnesota’s current operating licenses allow continued use of its Monticello
nuclear plant until 2030 and its PI nuclear plant until 2033 for Unit 1 and
2034 for Unit 2.

Future decommissioning costs of nuclear facilities are estimated through
triennial periodic studies that assess the costs and timing of planned
nuclear decommissioning activities for each unit.

Obligations for decommissioning are expected to be funded 100% by the
external decommissioning trust fund. The cost study assumes the external
decommissioning fund will earn an after-tax return between 5.23% and
6.30%.

Realized and unrealized gains on fund investments are deferred as an
offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning
costs. Decommissioning costs are quantified in 2014 dollars. Escalation
rates are 4.36% for plant removal activities and 3.36% for fuel management
and site restoration activities.

NSP-Minnesota had $3.3 billion of assets held in external decommissioning
trusts at Dec. 31, 2021. The following table summarizes the funded status
of NSP-Minnesota’s decommissioning obligation. Xcel Energy believes
future decommissioning costs will continue to be recovered in customer
rates. The following amounts were prepared on a regulatory basis and not
directly recorded in the financial statements as an ARO.

(Millions of Dollars)

Regulatory Basis

2021

2020

Estimated decommissioning cost obligation from most recently

approved study (in 2014 dollars)

3,012

Effect of escalating costs

Estimated decommissioning cost obligation (in current dollars)

Effect of escalating costs to payment date

1,006

4,018

7,187

844

3,856

7,349

Estimated future decommissioning costs (undiscounted)

11,205

Effect of discounting obligation (using average risk-free interest
rate of 1.96% and 1.64% for 2021 and 2020, respectively)

Discounted decommissioning cost obligation

Assets held in external decommissioning trust

(4,651)

(4,181)

6,554

3,256

7,024

2,777

Underfunding of external decommissioning fund compared to the

discounted decommissioning obligation

3,298

4,247

Calculations and data used by the regulator in approving NSP-Minnesota’s
rates are useful
flows. Regulatory basis
information is a means to reconcile amounts previously provided to the
MPUC and utilized for regulatory purposes to amounts used for financial
reporting.

in assessing

future cash

The 2017 nuclear decommissioning filing, effective Jan. 1, 2019, has been
approved by the MPUC. In March 2020, the MPUC approved for NSP-
Minnesota to delay any increase to the annual funding requirement until
2021. In December 2020, the MPUC verbally approved for NSP-Minnesota
to delay any increase to the annual funding requirement until 2022. In
December 2021, NSP-Minnesota submitted a Petition for approval of the
2022
- 2024 Nuclear Decommissioning Study and Assumptions.
Contemplated but not proposed in this filing, was the 10-year extension of
the license to operate the Monticello Plant, moving the planned retirement
date from 2030 to 2040. The 2019 Preferred Integrated Resource Plan
Supplement does include a 10-year extension of the license. On Feb. 8,
2022, the MPUC approved the 10-year extension.

Leases

Xcel Energy evaluates contracts that may contain leases, including PPAs
and arrangements for the use of office space and other facilities, vehicles
and equipment. 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 4.0%). Xcel
Energy has elected the practical expedient under which non-lease
components, such as asset maintenance costs included in payments, are
not deducted from minimum lease payments for the purposes of lease
accounting and disclosure.

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

Operating lease ROU assets:

(Millions of Dollars)

Dec. 31, 2021

Dec. 31, 2020

Reconciliation of
regulated basis to the ARO recorded in accordance with GAAP:

the discounted decommissioning cost obligation -

PPAs

Other

(Millions of Dollars)

2021

2020

Gross operating lease ROU assets

Accumulated amortization

Net operating lease ROU assets

1,656 $

225

1,881

(590)

1,291 $

1,650

212

1,862

(372)

1,490

Discounted decommissioning cost obligation - regulated basis

6,554

7,024

Differences in discount rate and market risk premium

O&M costs not included for GAAP

ARO differences between 2020 and 2014 cost studies

(2,209)

(1,584)

(705)

(2,628)

(1,734)

(705)

Nuclear production decommissioning ARO - GAAP

2,056

1,957

Decommissioning expenses recognized as a result of regulation:

(Millions of Dollars)
Annual decommissioning recorded as depreciation expense: (a) (b)
(a)

2021

2020

2019

$ 22

$ 20

Decommissioning expense does not include depreciation of the capitalized nuclear

asset retirement costs.

(b)

Decommissioning expenses in 2021, 2020 and 2019 include Minnesota’s retail

jurisdiction annual funding requirement of approximately $14 million.

ROU assets for finance leases are included in other noncurrent assets, and
the present value of future finance lease payments is included in other
current liabilities and other noncurrent liabilities.

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

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

Finance lease ROU assets:

(Millions of Dollars)
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, 2021

Dec. 31, 2020

201
21
222
(97)
125

201
21
222
(90)
132

2021

2020

2019

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, 2021, the estimated future payments for capacity and energy
that the utility subsidiaries of Xcel Energy are obligated to purchase
pursuant to these executory contracts, subject to availability, were as
follows:

251

238

287

264

7
17
24

7
18
25

221

255

6
19
25

(Millions of Dollars)
2022
2023
2024
2025
2026
Thereafter
Total

Capacity

Energy (a)

75
77
72
29
12
12
277

165
169
174
53
10
38
609

(a)

(b)

Includes short-term lease expense of $5 million for 2021, 2020 and 2019.

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

consolidated statements of income. Expense for other operating leases is included in
O&M expense and electric fuel and purchased power.

Commitments under operating and finance leases as of Dec. 31, 2021:
(a) (b)

(Millions of Dollars)
2022
2023
2024
2025
2026
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

229
221
209
189
146
416
1,410
(209)

1,201

27
26
22
16
12
81
184
(34)

150

256
247
231
205
158
497
1,594
(243)

1,351

(205)

(c)

Finance
Leases
$

12
12
12
10
9
187
242
(170)

(3)

1,146

8.9

36.1

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

(b)

(c)

payments, such as energy payments on renewable PPAs.

PPA operating leases contractually expire at various dates through 2039.

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

PPAs and Fuel Contracts

Non-Lease PPAs — NSP-Minnesota, PSCo and SPS have entered into
PPAs with other utilities and energy suppliers 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 $149 million, $112 million and $102 million in 2021, 2020
and 2019, respectively.

Included in electric fuel and purchased power expenses for PPAs
accounted for as executory contracts were payments for capacity of
$69 million, $75 million and $86 million in 2021, 2020 and 2019,
respectively.

(a)

Excludes contingent energy payments for renewable energy PPAs.

Fuel Contracts — Xcel Energy has entered into various long-term
commitments for the purchase and delivery of a significant portion of its
coal, nuclear fuel and natural gas requirements. These contracts expire
between 2022 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, 2021:

(Millions of Dollars)
2022
2023
2024
2025
2026
Thereafter
Total

Coal

620
233
147
29
31
34
1,094

Nuclear fuel
89
$
109
82
119
29
309
737

Natural gas
supply

477
75
4
—
—
—
556

VIEs

Natural gas
supply and
transportation
$

292
224
172
156
149
571
1,564

PPAs — Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase
power from IPPs for which the utility subsidiaries are required to reimburse
fuel costs, or to participate in tolling arrangements under which the utility
subsidiaries procure the natural gas required to produce the energy that
they purchase. Xcel Energy has determined that certain IPPs are VIEs.
Xcel Energy is not subject to risk of loss from the operations of these
entities, and no significant financial support is required other than
contractual payments for energy and capacity.

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

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

The utility subsidiaries had approximately 4,062 MW of capacity under
long-term PPAs at both Dec. 31, 2021 and 2020 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 2022. TUCO arranges
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.

the purchase,

for

SPS has not provided any significant financial support to TUCO, other than
contractual payments for delivered coal. However, the fuel contracts create
a variable interest in TUCO due to SPS’ reimbursement of fuel procurement
costs.

SPS has determined that TUCO is a VIE, however it has concluded that
SPS is not the primary beneficiary of TUCO because it does not have the
power to direct the activities that most significantly impact TUCO’s
economic performance.

Low-Income Housing Limited Partnerships — Eloigne and NSP-
Wisconsin have entered into limited partnerships for the construction and
operation of affordable rental housing developments which qualify for low-
income housing tax credits. Xcel Energy Inc. has determined Eloigne and
NSP-Wisconsin’s low-income housing partnerships to be VIEs primarily due
to contractual arrangements within each limited partnership that establish
sharing of ongoing voting control and profits and losses that does not align
with the partners’ proportional equity ownership.

Eloigne and NSP-Wisconsin have the power to direct the activities that
most significantly impact these entities’ economic performance. Therefore,
Xcel Energy Inc. consolidates these limited partnerships in its consolidated
financial statements. Xcel Energy’s risk of loss for these partnerships is
limited to its capital contributions, adjusted for any distributions and its
share of undistributed profits and losses; no significant additional financial
support has been, or is required to be, provided to the limited partnerships
by Eloigne or NSP-Wisconsin.

Amounts reflected in Xcel Energy’s consolidated balance sheets for the
Eloigne and NSP-Wisconsin low-income housing limited partnerships:

(Millions of Dollars)

Current assets

Property, plant and equipment, net

Other noncurrent assets

Total assets

Current liabilities

Mortgages and other long-term debt payable

Other noncurrent liabilities

Total liabilities

Dec. 31, 2021

Dec. 31, 2020

Other

Technology Agreements — Xcel Energy has several contracts for
information technology services that extend through 2022. The contracts
are cancelable, although there are financial penalties for early termination.
Xcel Energy capitalized or expensed $103 million, $110 million and
$101 million associated with these contracts in 2021, 2020 and 2019,
respectively.

Committed minimum payments under these obligations are $15 million in
2022.

Guarantees and Bond Indemnifications — Xcel Energy Inc. and its
subsidiaries provide guarantees and bond indemnities, which guarantee
payment or performance. Xcel Energy Inc.’s exposure is based upon the
net liability under the specified agreements or transactions. Most of the
guarantees and bond indemnities issued by Xcel Energy Inc. and its
subsidiaries have a stated maximum amount.

As of Dec. 31, 2021 and 2020, 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 $60 million and $62 million at Dec. 31,
2021 and 2020 respectively.

Inc. and

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. Xcel Energy Inc.’s and its
subsidiaries’ obligations under these agreements may be limited in terms of
duration and amount. Maximum
these
indemnifications cannot be reasonably estimated as the dollar amounts are
often not explicitly stated.

future payments under

13. Other Comprehensive Income

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

Gains and
Losses on
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 loss before
reclassifications (net of taxes of $1
and $—, respectively)

Losses reclassified from net
accumulated other comprehensive loss:

Interest rate derivatives (net of taxes
of $2 and $—, respectively)

Amortization of net actuarial loss (net
of taxes of $— and $3, respectively)

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.

of NSP-Minnesota,

Income tax expense

Net income

Gains and
Losses on
Cash Flow
Hedges

2020

Defined Benefit
Pension and
Postretirement
Items

Total

(80)

(61)

$ (141)

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:

(10)

(5)

(15)

(Millions of Dollars)

Regulated Electric

2021

2020

2019

Operating revenues — external

11,205

9,802

9,575

(Millions of Dollars)
Accumulated other comprehensive loss
at Jan. 1

Other comprehensive loss before
reclassifications (net of taxes of $(3)
and $(2), respectively)
Losses reclassified from net
accumulated other comprehensive loss:
Interest rate derivatives (net of taxes
of $2 and $—, respectively)
Amortization of net actuarial loss (net
of taxes of $— and $3, respectively)
Net current period other comprehensive
(loss) income
Accumulated other comprehensive loss
at Dec. 31
(a)

Included in interest charges.

(a)

—

(5)

(b)

—

(85)

(56)

$ (141)

(b)

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

See Note 11 for further information.

14. Segment Information

utility

electric

Xcel Energy evaluates performance by each utility subsidiary based on
profit or loss generated from the product or service provided, including the
regulated
NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility
operating results of NSP-Minnesota, NSP-Wisconsin and PSCo. These
segments are managed separately because the revenue streams are
dependent upon regulated rate recovery, which is separately determined
for each segment.

operating

results

Xcel Energy has the following reportable segments:

•

transmits and distributes electricity

regulated electric utility segment
Regulated Electric — The
in Minnesota,
generates,
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.

investments of $208 million and
Xcel Energy had equity method
$165 million as of Dec. 31, 2021 and 2020, respectively, included in the
natural gas utility and all other segments.

Asset and capital expenditure information is not provided for Xcel Energy’s
reportable segments. As an integrated electric and natural gas utility, Xcel
Energy operates significant assets that are not dedicated to a specific
business segment. Reporting assets and capital expenditures by business
segment would require arbitrary and potentially misleading allocations,
which may not necessarily reflect the assets that would be required for the
operation of the business segments on a stand-alone basis.

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

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

11,207

9,804

1,855

568

(96)

1,478

1,673

534

1,407

9,576

1,535

500

125

1,288

2,132

1,636

1,868

2,134

1,637

1,870

254

231

252

190

173

(28)

(112)

193

(24)

(124)

219

195

167

(45)

(111)

13,435

11,529

11,532

(4)

(3)

13,431

11,526

11,529

Depreciation and amortization

2,121

1,948

Interest charges and financing costs

Income tax (benefit) expense

Net income

816

(70)

798

(6)

1,597

1,473

1,765

736

128

1,372

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

None.

ITEM 9A — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Xcel Energy maintains a set of disclosure controls and procedures
designed to ensure that information required to be disclosed in reports that
it files or submits under the Securities Exchange Act of 1934 is recorded,
processed, summarized, and reported within the time periods specified in
SEC rules and forms. In addition, the disclosure controls and procedures
ensure that information required to be disclosed is accumulated and
communicated to management, including the CEO and CFO, allowing
timely decisions regarding required disclosure.

As of Dec. 31, 2021, based on an evaluation carried out under the
supervision and with the participation of Xcel Energy’s management,
including the CEO and CFO, of the effectiveness of its disclosure controls
and procedures, the CEO and CFO have concluded that Xcel Energy’s
disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No changes in Xcel Energy’s internal control over financial reporting
occurred during the most recent fiscal quarter ended Dec. 31, 2021 that
materially affected, or are reasonably likely to materially affect, Xcel
Energy’s internal control over financial reporting. Xcel Energy maintains
internal control over financial reporting to provide reasonable assurance
regarding the reliability of the financial reporting. Xcel Energy has evaluated
and documented its controls in process activities, general computer
activities, and on an entity-wide level.

During the year and in preparation for issuing its report for the year ended
Dec. 31, 2021 on internal controls under section 404 of the Sarbanes-Oxley
Act of 2002, Xcel Energy conducted testing and monitoring of its internal
control over financial reporting. Based on the control evaluation, testing and
remediation performed, Xcel Energy did not identify any material control
weaknesses, as defined under the standards and rules issued by the Public
Company Accounting Oversight Board, as approved by the SEC and as
indicated in Xcel Energy’s Management Report on Internal Controls over
Financial Reporting, which is contained in Item 8 herein.

ITEM 9B — OTHER INFORMATION

None.

PART III

ITEM 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 2022 Annual Meeting of Shareholders, which is expected to occur on
April 5, 2022, incorporated by reference. Information with respect to
Executive Officers is included in Item 1 to this report.

ITEM 11 — EXECUTIVE COMPENSATION

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

its 2022 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 2022 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 2022 Annual Meeting of Shareholders, which is
incorporated by reference.

ITEM 9C — DISCLOSURE REGARDING FOREIGN JURISDICTIONS
THAT PREVENT INSPECTIONS

ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES

Not applicable.

PART IV

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 2022 Annual
Meeting of Shareholders, which is incorporated by reference.

ITEM 15 — EXHIBIT AND FINANCIAL STATEMENT SCHEDULES

3
*
+

Consolidated Financial Statements
Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2021.
Report of Independent Registered Public Accounting Firm — Financial Statements and Internal Controls Over Financial Reporting
Consolidated Statements of Income — For each of the three years ended Dec. 31, 2021, 2020, and 2019.
Consolidated Statements of Comprehensive Income — For each of the three years ended Dec. 31, 2021, 2020, and 2019.
Consolidated Statements of Cash Flows — For each of the three years ended Dec. 31, 2021, 2020, and 2019.
Consolidated Balance Sheets — As of Dec. 31, 2021 and 2020.
Consolidated Statements of Common Stockholders’ Equity — For each of the three years ended Dec. 31, 2021, 2020, and 2019.

Schedule I — Condensed Financial Information of Registrant.
Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2021, 2020, and 2019.

Exhibits
Indicates incorporation by reference
Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

Xcel Energy Inc.
Exhibit
Number Description
3.01*

Amended and Restated Articles of Incorporation of Xcel Energy Inc.

3.02*
4.01*

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

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

4.02*

4.03*

4.04*

4.06*

4.07*

4.08*

4.09*

4.10*

4.11*

4.12*

4.13*

Indenture dated Dec. 1, 2000 between Xcel Energy Inc. and Wells Fargo Bank Minnesota, National Association, as
Trustee
Supplemental Indenture No. 3 dated June 1, 2006 between Xcel Energy Inc. and Wells Fargo Bank, National
Association, as Trustee

Xcel Energy Inc. Form 8-K dated Dec. 14,
2000
Xcel Energy Inc. Form 8-K dated June 6, 2006 4.01

4.01

Junior Subordinated Indenture, dated as of Jan. 1, 2008, by and between Xcel Energy Inc. and Wells Fargo Bank,
National Association, as Trustee

Xcel Energy Inc. Form 8-K dated Jan. 16,
2008

4.05*

Replacement Capital Covenant, dated Jan. 16, 2008

4.01

4.03

4.01

Xcel Energy Inc. Form 8-K dated Jan. 16,
2008
Xcel Energy Inc. Form 8-K dated Sept. 12,
2011

Xcel Energy Inc. Form 8-K dated June 1, 2015 4.01

Xcel Energy Inc. Form 8-K dated Dec. 1, 2016 4.01

Supplemental Indenture No. 6, dated as of Sept. 1, 2011 between Xcel Energy Inc. and Wells Fargo Bank, National
Association, as Trustee

Supplemental Indenture No. 8, dated as of June 1, 2015 between Xcel Energy Inc. and Wells Fargo Bank, National
Association, as Trustee

Supplemental Indenture No. 10, dated as of Dec. 1, 2016, by and between Xcel Energy Inc. and Wells Fargo Bank,
National Association, as Trustee

Supplemental Indenture No. 11, dated as of June 25, 2018, by and between Xcel Energy Inc. and Wells Fargo Bank,
National Association, as Trustee

Xcel Energy Inc. Form 8-K dated June 25,
2018

4.01

Supplemental Indenture No. 12, dated as of Nov. 7, 2019 by and between Xcel Energy Inc. and Wells Fargo Bank,
National Association, as Trustee, creating 2.60% Senior Notes, Series due Dec 1. 2029 and 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 Wells Fargo Bank,
National Association as Trustee creating $600 million principal amount of 3.40% Senior Notes, Series due June 1, 2030

Xcel Energy Inc. Form 8-K dated Nov. 7, 2019 4.01

Xcel Energy Inc. Form 8-K dated April 1, 2020

4.01

Supplemental Indenture No. 14, dated as of Sept. 25, 2020 between Xcel Energy Inc. and Wells Fargo Bank, National
Association as Trustee, creating $500 million principal amount of 0.50% Senior Notes, Series due Oct. 15, 2023

Xcel Energy Inc. Form 8-K dated Sept. 25,
2020

4.01

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 principal
amount of 1.75% Senior Notes, Series due March 15, 2027 and $300 million principal amount of 2.35% Senior Notes,
Series due Nov. 15, 2031

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

10.01*

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 Inc. Form 10-K for the year ended
Dec. 31, 2008
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2008
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2011
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
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2008
Xcel Energy Inc. Definitive Proxy Statement
dated April 6, 2010
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
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2008
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2011
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2013
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
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2018
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2018
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2019

10.02

10.05

10.18

10.01

10.02

10.01

10.17

Appendix
A
10.01

10.08

10.07

10.17

10.22

10.01

10.1

10.34

10.35

10.32

Appendix
A
10.02

10.01

10.18*+

10.19*+

10.20*+

10.21*+

10.22*+

10.23*+

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
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
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

Stock Equivalent Program for Non-Employee Directors of Xcel Energy Inc. under the Xcel Energy Inc. 2015 Omnibus
Incentive Plan
Summary of Non-Employee Director Compensation, effective as of Oct. 1, 2021

dated April 5, 2011
Xcel Energy Inc. Form 8-K dated May 20,
2015
Xcel Energy Inc. Form 10-Q for the quarter
ended September 30, 2021

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

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

10.36

10.24*+

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

Xcel Energy Inc. Form U5B dated Nov. 16,
2000

H-1

4.11

4.12

4.51

4(b)(7)

4.63

4.01

10.25*

10.26*

10.27*+

Third Amended and Restated Credit Agreement, dated as of June 7, 2019 among Xcel Energy Inc., as Borrower, the
several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of
America, N.A. and Barclays Bank Plc, as Syndication Agents, Wells Fargo Bank, National Association, MUFG Bank,
Ltd., and Citibank, N.A., as Documentation Agents

Xcel Energy Inc. Form 8-K dated June 7, 2019 99.01

364-Day Term Loan Agreement dated as of February 18, 2021 among Xcel Energy Inc., as Borrower, the several
lenders from time to time parties thereto, and U.S. Bank National Association, as Administrative Agent.

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 February 18,
2021
Xcel Energy Inc. Form 8-K dated December
10, 2021

10.01

NSP-Minnesota

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 June 1, 1995, creating $250 million 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 March 1, 1998, creating $150 million 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

4.17*

Supplemental Trust Indenture dated Aug. 1, 2000 (Assignment and Assumption of Trust Indenture)

NSP-Minnesota Form 10-12G dated Oct. 5,
2000

Indenture, dated July 1, 1999, between NSP-Minnesota and Norwest Bank Minnesota, NA, as Trustee, providing for the
issuance of Sr. Debt Securities

Xcel Energy Inc. Form S-3 dated April 18,
2018

Supplemental Indenture, dated Aug. 18, 2000, supplemental to the Indenture dated July 1, 1999, among Xcel Energy,
NSP-Minnesota and Wells Fargo Bank Minnesota, NA, as Trustee

NSP-Minnesota Form 10-12G dated Oct. 5,
2000

Supplemental Trust Indenture dated July 1, 2005 between NSP-Minnesota and BNY Midwest Trust Company, as
successor Trustee, creating $250 million principal amount of 5.25% First Mortgage Bonds, Series due July 15, 2035

Supplemental Trust Indenture dated May 1, 2006 between NSP-Minnesota and BNY Midwest Trust Company, as
successor Trustee, creating $400 million principal amount of 6.25% First Mortgage Bonds, Series due June 1, 2036

NSP-Minnesota Form 8-K dated July 14, 2005 4.01

NSP-Minnesota Form 8-K dated May 18, 2006 4.01

Supplemental Trust Indenture, dated June 1, 2007, between NSP-Minnesota and BNY Midwest Trust Company, as
successor Trustee

NSP-Minnesota Form 8-K dated June 19,
2007

Supplemental Trust Indenture dated as of Nov. 1, 2009 between NSP-Minnesota and the Bank of New York Mellon Trust
Co., NA, as successor Trustee, creating $300 million principal amount of 5.35% First Mortgage Bonds, Series due Nov.
1, 2039
Supplemental Trust Indenture dated as of Aug. 1, 2010 between NSP-Minnesota and the Bank of New York Mellon Trust
Company, NA, as successor Trustee, creating $250 million principal amount of 1.95% First Mortgage Bonds, Series due
Aug, 15, 2015 and $250 principal amount of 4.85% First Mortgage Bonds, Series due Aug. 15, 2040
Supplemental Trust Indenture dated as of Aug. 1, 2012 between NSP-Minnesota and the Bank of New York Mellon Trust
Company, NA, as successor Trustee, creating $300 million principal amount of 2.15% First Mortgage Bonds, Series due
Aug. 15, 2022 and $500 million principal amount of 3.40% First Mortgage Bonds, Series due Aug. 15, 2042
Supplemental Trust Indenture dated as of May 1, 2013 between NSP-Minnesota and the Bank of New York Mellon Trust
Company, N.A., as successor Trustee, creating $400 million principal amount of 2.60% First Mortgage Bonds, Series
due May 15, 2023
Supplemental Trust Indenture dated as of May 1, 2014 between NSP-Minnesota and the Bank of New York Mellon Trust
Company, N.A., as successor Trustee, creating $300 million principal amount of 4.125% First Mortgage Bonds, Series
due May 15, 2044
Supplemental Trust Indenture dated as of Aug. 1, 2015 between NSP-Minnesota and the Bank of New York Mellon
Company, N.A., as successor Trustee, creating $300 million principal amount of 2.20% First Mortgage Bonds, Series
due Aug. 15, 2020 and $300 million principal amount of 4.00% First Mortgage Bonds, Series due Aug. 15, 2045
Supplemental Trust Indenture dated as of May 1, 2016 between NSP-Minnesota and the Bank of NY Mellon Trust
Company, N.A., as successor Trustee, creating $350 million principal amount of 3.60% First Mortgage Bonds, Series
due May 15, 2046
Supplemental Trust Indenture dated as of Sept. 1, 2017 between NSP-Minnesota and The Bank of New York Mellon
Trust Company, N.A., as successor Trustee, creating $600 million principal amount of 3.60% First Mortgage Bonds,
Series due Sept. 15, 2047
Supplemental Trust Indenture dated as of Sept. 1, 2019 between NSP-Minnesota and the Bank of New York Mellon
Trust Company, N.A., as successor Trustee, creating $600 million principal amount of 2.90% First Mortgage Bonds,
Series due March 1, 2050
Supplemental Indenture dated as of June 8, 2020 between NSP-Minnesota and the Bank of New York Mellon Trust
Company, N.A., as successor Trustee, creating $700 million principal amount of 2.60% First Mortgage Bonds, Series
due June 1, 2051
Supplemental Indenture dated as of March 1, 2021 between NSP-Minnesota and the Bank of New York Mellon Trust
Company, N.A., as successor 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
Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota

Third Amended and Restated Credit Agreement, dated as of June 7, 2019 among NSP-Minnesota, as Borrower, the
several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of
America, N.A. and Barclays Bank Plc, as Syndication Agents, Wells Fargo Bank, National Association, MUFG Bank,
Ltd., and Citibank, N.A., as Documentation Agents

NSP-Minnesota Form 8-K dated Nov. 16,
2009

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

Xcel Energy Inc. Form 8-K dated June 7, 2019 99.02

4.14*

4.15*

4.16*

4.18*

4.19*

4.20*

4.21*

4.22*

4.23*

4.24*

4.25*

4.26*

4.27*

4.28*

4.29*

4.30*

4.31*

4.32*

4.33*

10.28*

10.29*

NSP-Wisconsin

4.34*

Supplemental and Restated Trust Indenture, dated March 1, 1991, between NSP-Wisconsin and First Wisconsin Trust
Company, providing for the issuance of First Mortgage Bonds

Xcel Energy Inc. Form S-3 dated April 18,
2018

4.35*

Trust Indenture dated Sept. 1, 2000 between NSP-Wisconsin and Firstar Bank, NA as Trustee

NSP-Wisconsin Form 8-K dated Sept. 25,
2000

4(c)(3)

4.01

4.36*

4.37*

4.38*

4.39*

4.40*

4.41*

4.42*

10.30*

10.31*

Supplemental Trust Indenture dated as of Sept. 1, 2008 between NSP-Wisconsin and U.S. Bank National Association,
as successor Trustee, creating $200 million principal amount of 6.375% First Mortgage Bonds, Series due Sept. 1, 2038

NSP-Wisconsin Form 8-K dated Sept. 3, 2008

4.01

Supplemental Trust Indenture dated as of Oct. 1, 2012 between NSP-Wisconsin and U.S. Bank National Association, as
successor Trustee, creating $100 million principal amount of 3.70% First Mortgage Bonds, Series due Oct. 1, 2042

NSP-Wisconsin Form 8-K dated Oct. 10, 2012 4.01

Supplemental Trust Indenture dated as of June 1, 2014 between NSP-Wisconsin and U.S. Bank National Association,
as successor Trustee, creating $100 million principal amount of 3.30% First Mortgage Bonds, Series due June 1, 2024

NSP-Wisconsin Form 8-K dated June 23,
2014

4.01

Supplemental Trust Indenture dated as of Nov 1, 2017 between NSP-Wisconsin and U.S. Bank National Association, as
successor Trustee, creating $100 million principal amount of 3.75% First Mortgage Bonds, Series due Dec. 1, 2047

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

4.01

Supplemental Indenture dated as of Sept. 1, 2018 between NSP-Wisconsin and U.S. Bank National Association, as
successor Trustee, creating $200 million principal amount of 4.20% First Mortgage Bonds, Series due Sept. 1, 2048

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

4.01

Supplemental Indenture dated as of May 18, 2020 between NSP-Wisconsin and U.S. Bank National Association, as
Trustee, creating $100 million principal amount of 3.05% First Mortgage Bonds, Series due May 1, 2051

Supplemental Indenture dated as of July 19, 2021 between NSP-Wisconsin and U.S. Bank National Association, as
Trustee, creating $100 million principal amount of 2.82% First Mortgage Bonds, Series due May 1, 2051

NSP-Wisconsin Form 8-K dated May 26, 2020 4.01

NSP-Wisconsin Form 8-K dated July 20, 2021

4.01

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

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

Third Amended and Restated Credit Agreement, dated as of June 7, 2019 among NSP-Wisconsin, as Borrower, the
several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of
America, N.A. and Barclays Bank Plc, as Syndication Agents, Wells Fargo Bank, National Association, MUFG Bank,
Ltd., and Citibank, N.A., as Documentation Agents

Xcel Energy Inc. Form 8-K dated June 7, 2019 99.05

10.32*

Bond Purchase Agreement, dated July 19, 2021, among NSP-Wisconsin and the several purchasers listed in Schedule
B thereto

NSP-Wisconsin Form 8-K dated July 20, 2021

1.01

Indenture, dated as of Oct. 1, 1993 between PSCo and Morgan Guaranty Trust Company of New York, as Trustee,
providing for the issuance of First Collateral Trust Bonds

Xcel Energy Inc. Form S-3 dated April 18,
2018

4(d)(3)

Supplemental Indenture, dated Aug. 1, 2007 between PSCo and U.S. Bank Trust National Association, as successor
Trustee

PSCo Form 8-K dated Aug. 8, 2007

Supplemental Indenture dated as of Aug. 1, 2008 between PSCo and U.S. Bank Trust National Association, as
successor Trustee, creating $300 million principal amount of 5.80% First Mortgage Bonds, Series due 2018 and $300
million principal amount of 6.50% First Mortgage Bonds, Series due 2038
Supplemental Indenture dated as of Aug. 1, 2011 between PSCo and U.S. Bank National Association, as successor
Trustee, creating $250 million principal amount of 4.75% First Mortgage Bonds, Series due 2041

Supplemental Indenture dated as of Sept. 1, 2012 between PSCo and U.S. Bank National Association, as successor
Trustee, creating $300 million principal amount of 2.25% First Mortgage Bonds, Series due 2022 and $500 million
principal amount of 3.60% First Mortgage Bonds, Series due 2042
Supplemental Indenture dated as of March 1, 2013 between PSCo and U.S. Bank National Association, as successor
Trustee, creating $250 million principal amount of 2.50% First Mortgage Bonds, Series due 2023 and $250 million
principal amount of 3.95% First Mortgage Bonds, Series due 2043
Supplemental Indenture dated as of March 1, 2014 between PSCo and U.S. Bank National Association, as successor
Trustee, creating $300 million principal amount of 4.30% First Mortgage Bonds, Series due 2044

PSCo Form 8-K dated Aug. 6, 2008

PSCo Form 8-K dated Aug. 9, 2011

PSCo Form 8-K dated Sept. 11, 2012

PSCo Form 8-K dated March 26, 2013

4.01

PSCo Form 8-K dated March 10, 2014

Supplemental Indenture dated as of May 1, 2015 between PSCo and U.S. Bank National Association, as successor
Trustee, creating $250 million principal amount of 2.90% First Mortgage Bonds, Series due 2025

PSCo Form 8-K dated May 12, 2015

Supplemental Indenture dated as of June 1, 2016 between PSCo and U.S. Bank National Association, as successor
Trustee, creating $250 million principal amount of 3.55% First Mortgage Bonds, Series due 2046

PSCo Form 8-K dated June 13, 2016

Supplemental Indenture dated as of June 1, 2017 between PSCo and U.S. Bank National Association, as successor
Trustee, creating $400 million principal amount of 3.80% First Mortgage Bonds, Series due 2047

PSCo Form 8-K dated June 19, 2017

Supplemental Indenture dated as of June 1, 2018 between PSCo and U.S. Bank National Association, as successor
Trustee, creating $350 million principal amount of 3.70% First Mortgage Bonds, Series due 2028, and $350 million
principal amount of 4.10% First Mortgage Bonds, Series due 2048
Supplemental Indenture dated as of March 1, 2019 between PSCo and U.S. Bank National Association, as successor
Trustee, creating $400 million principal amount of 4.05% First Mortgage Bonds, Series due 2049

PSCo Form 8-K dated June 21, 2018

PSCo Form 8-K dated March 13, 2019

Supplemental Indenture dated as of Aug. 1, 2019 between PSCo and U.S. Bank National Association, as successor
Trustee, creating $550 million principal amount of 3.20% First Mortgage Bonds, Series due 2050

PSCo Form 8-K dated August 13, 2019

Supplemental Indenture dated as of May 1, 2020 between PSCo and U.S. Bank National Association, as successor
Trustee, creating $375 million principal of 2.70% First Mortgage Bonds, Series No. 35 due 2051 and $375 million
principal amount of 1.90% First Mortgage Bonds, Series No. 36 due 2031
Supplemental Indenture dated as of February 1, 2021 between PSCo and U.S. Bank National Association, as successor
Trustee, creating $750 million principal of 1.875% First Mortgage Bonds, Series No. 37 due 2031

PSCo Form 8-K dated May 15, 2020

PSCo Form 8-K dated March 1, 2021

Proposed Settlement Agreement, excerpts, as filed with the CPUC

Third Amended and Restated Credit Agreement, dated as of June 7, 2019 among PSCo, as Borrower, the several
lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A.
and Barclays Bank Plc, as Syndication Agents, Wells Fargo Bank, National Association, MUFG Bank, Ltd., and Citibank,
N.A., as Documentation Agents

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

Xcel Energy Inc. Form 8-K dated June 7, 2019 99.03

Indenture dated Feb. 1, 1999 between SPS and the Chase Manhattan Bank
Supplemental Indenture dated Oct. 1, 2003 between SPS and JPMorgan Chase Bank, as successor Trustee, creating
$100 million principal amount of Series C and Series D Notes, 6% due 2033

SPS Form 8-K dated Feb. 25, 1999
Xcel Energy Inc. Form 10-Q for the quarter
ended Sept. 30, 2003

Supplemental Indenture dated Oct. 1, 2006 between SPS and the Bank of New York, as successor Trustee, creating
$200 million principal amount of 5.6% Series E Notes due 2016 and $250 million principal amount of 6% Series F Notes
due 2036

SPS Form 8-K dated Oct. 3, 2006

4.61*

Indenture dated as of Aug. 1, 2011 between SPS and U.S. Bank National Association, as Trustee

SPS Form 8-K dated Aug. 10, 2011

PSCo

4.43*

4.44*

4.45*

4.46*

4.47*

4.48*

4.49*

4.50*

4.51*

4.52*

4.53*

4.54*

4.55*

4.56*

4.57*

10.33*

10.34*

SPS
4.58*
4.59*

4.60*

4.01

99.2
4.04

4.01

4.62*

4.63*

4.64*

4.65*

4.66*

4.67*

4.68*

10.35*

Supplemental Indenture dated as of Aug. 3, 2011 between SPS and U.S. Bank National Association, as Trustee,
creating $200 million principal amount of 4.50% First Mortgage Bonds, Series due 2041

SPS Form 8-K dated Aug. 10, 2011

Supplemental Indenture dated as of June 1, 2014 between SPS and U.S. Bank National Association, as Trustee,
creating $150 million principal amount of 3.30% First Mortgage Bonds, Series due 2024

SPS Form 8-K dated June 9, 2014

Supplemental Indenture dated as of Aug. 1, 2016 between SPS and U.S. Bank National Association, as Trustee,
creating $300 million principal amount of 3.40% First Mortgage Bonds, Series due 2046

SPS Form 8-K dated Aug. 12, 2016

Supplemental Indenture dated as of Aug. 1, 2017 between SPS and U.S. Bank National Association, as Trustee,
creating $450 million principal amount of 3.70% First Mortgage Bonds, Series due 2047

SPS Form 8-K dated Aug 9. 2017

Supplemental Indenture dated as of Oct. 1, 2018 between SPS and U.S. Bank National Association, as Trustee, creating
$300 million principal amount of 4.40% First Mortgage Bonds, Series due 2048

SPS Form 8-K dated Nov. 5, 2018

Supplemental Indenture dated as of June 1, 2019 between SPS and U.S. Bank National Association, as Trustee,
creating $300 million principal amount of 3.75% First Mortgage Bonds, Series due 2049

SPS Form 8-K dated June 18, 2019

Supplemental Indenture No. 8, dated as of May 1, 2020 between SPS and U.S. Bank National Association, as Trustee,
creating $600 million principal amount of 3.15% First Mortgage Bonds, Series due 2050

SPS Form 8-K dated May 18, 2020

4.02

Third Amended and Restated Credit Agreement, dated as of June 7, 2019 among SPS, as Borrower, the several lenders
from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and
Barclays Bank Plc, as Syndication Agents, Wells Fargo Bank, National Association, MUFG Bank, Ltd., and Citibank,
N.A., as Documentation Agents

Xcel Energy Inc. Form 8-K dated June 7, 2019 99.04

Xcel Energy Inc.

21.01

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
2020

2019

2021

Income

Equity earnings of subsidiaries

Total income

Expenses and other deductions

Operating expenses
Other income
Interest charges and financing costs

Total expenses and other deductions

Income before income taxes
Income tax benefit
Net income

Other Comprehensive Income

$ 1,744
1,744

$ 1,646
1,646

$ 1,505
1,505

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

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

23
(9)
173
187
1,318
(54)
$ 1,372

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 (loss)
Comprehensive income

10
18
$ 1,615

(5)
—
$ 1,473

(20)
(17)
$ 1,355

Weighted average common shares outstanding:

Basic
Diluted

Earnings per average common share:

Basic
Diluted

539
540

527
528

519
520

$ 2.96
2.96

$ 2.79
2.79

$ 2.64
2.64

See Notes to Condensed Financial Statements

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

Year Ended Dec. 31

2021

2020

2019

Operating activities

Net cash provided by operating activities

$ 1,147

$ 2,377

$ 1,389

Investing activities

Capital contributions to subsidiaries

(1,661)

(2,553)

(1,594)

Net return (investments) in the utility money pool

(18)

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

—
(1,604)

(1)
(2,572)

—
(1,555)

638

791

(400)

366

—

(935)

(16)
444

(13)

(500)

1,089

1,120

(300)

727

(4)

(856)

(17)
139

(56)

(550)

458

—

(791)

(14)
235

See Notes to Condensed Financial Statements

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

Assets

Cash and cash equivalents

Accounts receivable from subsidiaries

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

2021

2020

430

437

21,167

21,238

21,675

—

249

638

916

5,137

15,612

20,749

21,675

424

444

19,102

19,142

19,586

400

231

—

652

4,342

14,575

18,917

19,586

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, 2021 and 2020,
Xcel Energy Inc. had no assets held as collateral related to guarantees,
bond indemnities and indemnification agreements.

Guarantees and bond indemnities issued and outstanding as of Dec. 31,
2021:

(Millions of Dollars)

Guarantor

Guarantee
Amount

Current
Exposure

Triggering
Event

Guarantee of loan for
Hiawatha Collegiate High
School (a)
Guarantee performance and
payment of surety bonds for
Xcel Energy Inc.’s utility
subsidiaries (b)

Xcel Energy
Inc.

—

(e)

Money Pool — FERC approval was received to establish a utility money
pool arrangement with the utility subsidiaries, subject to receipt of required
state regulatory approvals. The utility money pool allows for short-term
investments in and borrowings between the utility subsidiaries. Xcel Energy
Inc. may make investments in the utility subsidiaries at market-based
interest rates; however, the money pool arrangement does not allow the
utility subsidiaries to make investments in Xcel Energy Inc.

Money pool lending for Xcel Energy Inc.:

(Amounts in Millions, Except Interest Rates)

Loan outstanding at period end

Average loan outstanding

Maximum loan outstanding

Weighted average interest rate, computed on a daily basis

(c)

Weighted average interest rate at end of period

Money pool interest income

Three Months Ended
Dec. 31, 2021

—

N/A

—

(d)

(Amounts in Millions, Except
Interest Rates)

Year Ended
Dec. 31, 2021

Year Ended
Dec. 31, 2020

Year Ended
Dec. 31, 2019

(a)

(b)

(c)

(d)

(e)

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

Nonperformance and/or nonpayment.

Per the indemnity agreement between Xcel Energy Inc. and the various surety

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

—

439

0.08 %

N/A

104

350

0.60 %

0.07 %

companies, surety companies have the discretion to demand that collateral be posted.

Money pool interest income

—

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

exposure of this indemnification cannot be determined. Xcel Energy Inc. believes the

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

exposure to be significantly less than the total amount of the outstanding bonds.

SCHEDULE II

250

2.15 %

1.63

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.

104
25
91
58
125

81
9
98
55
159

2020

2021

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)

2021

Balance at Jan. 1

$ 79

2020

$ 55

2019

$ 55

2021

$ 64

2020

$ 67

2019

$ 79

Additions charged to
costs and expenses

Additions charged to
other accounts

Deductions from
reserves

Balance at Dec. 31
(a)

(a)

(b)

(47)

(a)

(b)

(48)

(a)

(b)

(58)

—

(d)

(5)

(c)

(9)

(d)

(21)

$ 106

$ 79

$ 55

$ 64

$ 67

Recovery of amounts previously written-off.

(b)

(c)

(d)

Deductions related primarily to bad debt write-offs.

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.

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

Other subsidiaries of Xcel Energy Inc.

27
430

22
424

forecasted to be used prior to expiration.

ITEM 16 — FORM 10-K SUMMARY

Dividends — Cash dividends paid to Xcel Energy Inc. by its subsidiaries
were $1,344 million, $2,527 million and $2,987 million for the years ended
Dec. 31, 2021, 2020 and 2019, respectively. These cash receipts are
included in operating cash flows of the condensed statements of cash
flows.

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, 2022

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

/s/ JEFFREY S. SAVAGE
Jeffrey S. Savage

Lynn Casey

Netha N. Johnson

Patricia L. Kampling

George J. Kehl

Richard T. O’Brien

Charles Pardee

Christopher J. Policinski

James Prokopanko

David A. Westerlund

Kim Williams

Timothy V. Wolf

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

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

Senior Vice President, Controller
(Principal Accounting Officer)

Director

Daniel Yohannes

*By:

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

Attorney-in-Fact

SHAREHOLDER INFORMATION

Headquarters
414 Nicollet Mall, Minneapolis, MN 55401

Website
investors.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 Xcel Energy’s Report to
Shareholders, are available online at xcelenergy.com; click
on Investor Relations. 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: 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,
Senior Analyst, 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 2021.

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.

XCEL ENERGY BOARD OF DIRECTORS
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
and Global IT, Albemarle Corporation

Patricia Kampling 2,3
Retired Chairman and Chief Executive
Officer, Alliant Energy Corporation

George Kehl 1,2
Retired 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

David Westerlund 1,3
Retired Executive Vice President,
Administration and Corporate Secretary,
Ball Corporation

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

Timothy Wolf 1,4
President,
Wolf Interests, Inc.

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

HORIZON BOUND
ANNUAL REPORT 2021

HORIZON BOUNDANNUAL REPORT 2021FISCAL 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