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FISCAL AGENTS
XCEL ENERGY INC.
Transfer Agent, Registrar, Dividend
Distribution, Common Stock
EQ Shareowner Services,
1110 Centre Pointe Curve, Suite 101
Mendota Heights, MN 55120
Trustee–Bonds
Wells Fargo Bank, N.A.,
Corporate Trust Services
600 South 4th Street
Minneapolis, MN 55415
xcelenergy.com | © 2021 Xcel Energy Inc. | Xcel Energy is a
registered trademark of Xcel Energy Inc. | 21-02-126
FOWKE ADVOCATES FOR
RACIAL EQUITY AS EEI CHAIR
In June, Xcel Energy Chairman and CEO Ben Fowke was elected Chairman of Edison Electric Institute, our
industry trade association, after serving as Vice Chair last year. He originally planned to focus on the clean
energy transition and COVID-19 recovery, but two weeks before his one-year term began, Ben and most of
the country saw the footage of George Floyd’s death while in police custody in south Minneapolis.
Calling the incident that occurred only a few miles from Xcel Energy’s corporate headquarters “an awakening,”
Ben knew that addressing racial equity was too important to not include in his platform. Ben, who was named
2020 Executive of the Year by Utility Dive, quickly rallied the industry and gained commitments from 57 CEOs
to address racial equity in their companies and communities, starting with four core principles: 1) Ensuring
diversity, equity and inclusion efforts are driven from the top 2) Removing barriers to entry and broadening
talent pools 3) Establishing strong community connections, and 4) Developing infrastructure academies and
training programs.
Xcel Energy added a diversity, equity and inclusion corporate scorecard metric for 2021, tying executive
and employee compensation to demonstrate our commitment to diversity, equity and inclusion and
improved hiring and sponsorship practices. This metric is designed to create accountability in our
leadership team and the company as a whole to reduce the barriers to a diverse workforce.
FINANCIAL HIGHLIGHTS
EARNINGS PER SHARE
2019
2020
Dollars per share (diluted)
Total GAAP earnings per share
2.64
2.79
Ongoing earnings per share
2.64
2.79
7
4
.
2
7
4
.
2
4
6
.
2
4
6
.
2
9
7
.
2
9
7
.
2
Dividends annualized
1.62
1.72
Stock price (close)
63.49
66.67
Assets (millions)
50,448
53,957
COMPANY DESCRIPTION
Xcel Energy is a major U.S. electric and natural gas
company with annual revenues of $11.5 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.
2018
2019
2020
GAAP (generally accepted accounting
principles) earnings per share
Ongoing earnings per share
ON THE COVER:
Adolphus Ugeh, a member of our Transmission Field
Operations team, is pictured at a new transmission
substation near Golden, Colorado. He is one of
thousands of Xcel Energy essential workers responsible
for providing safe, reliable energy for our customers.
SHAREHOLDER INFORMATION
HEADQUARTERS
414 Nicollet Mall, Minneapolis, MN 55401
WEBSITE
xcelenergy.com
STOCK TRANSFER AGENT
EQ Shareowner Services
1110 Centre Pointe Curve, Suite 101
Mendota Heights, MN 55120
Telephone: 877-778-6786, toll free
REPORTS AVAILABLE ONLINE
Financial reports, including filings with the Securities and
Exchange Commission and 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, Corporate
Responsibility 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, Investor Relations, at 612-215-4535.
SHAREHOLDER SERVICES
Website: 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 2020.
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
Ben Fowke
Chairman 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
David Owens 2,4
Retired Executive,
Edison Electric Institute
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
James Sheppard 2,4
Independent Consultant
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
DEAR FELLOW
SHAREHOLDERS:
Ben Fowke
Chairman and
Chief Executive Officer
3
ESSENTIALANNUAL REPORT 20202020 was a year like no other, and I am proud to say the Xcel Energy team rose to the challenge. In the face of a global pandemic, a severe economic downturn and widespread civil unrest, we delivered on our financial and operational objectives while simultaneously mitigating the impacts of COVID-19 and supporting our communities like never before.We continue to lead the clean energy transition and make excellent progress toward our vision to provide 100% carbon-free electricity for our customers by 2050. At the end of 2020, 47% of the energy we produced came from carbon-free sources. That number will continue to climb as we execute our plans to retire coal plants, build large-scale renewable projects, preserve our high-performing nuclear fleet and maintain natural gas as a bridge and backup fuel. A diversified energy mix is critical during this transition to enhance reliability and keep customer bills low.We’ve reduced carbon emissions 51% since 2005 — halfway to our 2050 goal and ahead of schedule — and we are creating concrete pathways to reach our 80% reduction goal by 2030. I’m encouraged by the opportunity to take our increasingly green product and reduce carbon from the transportation sector. Last year, we announced a bold vision to power 1.5 million electric vehicles in our service areas by the end of 2030 (see story on pages 6-8) and launched a comprehensive strategy to lower greenhouse gas emissions from our natural gas business.For me, 2020 will always be remembered as the year that our employees delivered for our customers and communities in extraordinary times. We never take for granted the trust you place in us to power the homes and businesses of our customers all day, every day. It’s a tremendous responsibility that took on additional meaning during this global pandemic. 4
We chose “Essential” as the theme for this report because of the essential role we play in our communities and in our society. Electricity and natural gas are essential services provided by our essential workers who take great pride in their ability to deliver for their neighbors. We also play a vital role in driving economic development and giving back through the Xcel Energy Foundation. Last year, we earmarked $20 million in short- and long-term corporate giving, including support for COVID-19 recovery and racial justice (see story on pages 16-18).I take great pride in our team’s resiliency, determination and flexibility last year as we learned to work differently, keep each other safe and deliver for our customers, our communities and you, our valued shareholders.STRONG FINANCIAL PERFORMANCEFor the 16th consecutive year, we met or exceeded our earnings guidance. We delivered 2020 earnings of $2.79 per share, within our original earnings guidance range of $2.73-$2.83 per share, compared to $2.64 per share in 2019. Although electric sales declined approximately 3% due to the economic downturn, we successfully implemented continuous improvement initiatives and other cost control measures that reduced our O&M expenses by nearly 1%.Xcel Energy also increased your dividend by 6.2%, or 10 cents annually in 2020. We maintained our earnings and dividend growth objectives of 5% to 7% annually, reflecting our confidence in our long-term financial plan. In February 2021, we increased the dividend 6.4%, or 11 cents on an annual basis, extending our streak of dividend growth to 18 consecutive years.As a result of our continued strong performance, our one-year total shareholder return exceeded 7.8% in 2020, which was the second highest in our peer group. We also compare favorably to our peer group and the S&P 500 for three-, five- and 10-year performance results. Due to the sound execution of our strategic priorities — leading the clean energy transition, enhancing the customer experience and keeping bills low — we remain well positioned to deliver for our customers and shareholders in 2021 and beyond.STEEL FOR FUEL EXECUTIONOur Steel for Fuel growth strategy — building wind farms that deliver both economic and environmental benefits for our customers and stakeholders — continues to drive organic growth for the company. Under Steel for Fuel, we add carbon-free renewable energy — the “steel” — allowing our customers to avoid the cost of fuel that would otherwise be used to produce electricity in traditional generating plants. This strategy keeps customer bills low, drives economic development and generates an attractive shareholder return. In the last year, we added nearly 1,500 megawatts of company-owned wind to our system, including large self-build projects in Colorado, Minnesota and New Mexico. In 2021, we will complete the four remaining projects in our nation-leading multi-state wind expansion that began in 2017. With completion of those remaining projects, the total wind on our system will grow to approximately 11,000 megawatts, including nearly 4,500 megawatts of owned wind capacity (see story on pages 12-13). Our investments in wind will continue longer term, including wind repowering projects where we replace aging equipment with the latest technology to increase wind farm efficiency and save customers money. We completed two wind repowering projects in 2020 and received approval in December to repower four projects in the Upper Midwest to help stimulate the economy (see story on page 9). OPERATIONAL EXCELLENCEDelivering natural gas and electricity took on even greater prominence during the pandemic, and our workforce delivered while adjusting to enhanced safety precautions (see story on pages 14-15). We met or exceeded goals on all 2020 corporate scorecard metrics, including customer satisfaction, wind deployment, employee safety, public safety and electric system reliability.Operational highlights include our J.D. Power customer satisfaction score improving by 40 points to our highest rating ever. The Institute of Nuclear Power Operations rated our nuclear fleet as the best in the nation — we achieved a Ben Fowke
Chairman and Chief Executive Officer
ESSENTIAL
ANNUAL REPORT 2020
5
96% capacity factor and successfully executed a refueling at Prairie Island during the pandemic. And we began the pivotal evolution of our safety approach that focuses on eliminating serious injuries and fatalities. Under this “Safety Always” approach, we are developing a culture of enhanced trust and transparency with our employees, giving them the opportunity to learn from their experiences and continuously improve the safety of their work environment. REGULATORY PROGRESSWe achieved constructive outcomes in numerous regulatory proceedings in 2020, including rate case settlements in New Mexico, Texas and Colorado and approval of our proposal to avoid moving forward with a rate case in Minnesota when many customers are struggling financially. The Minnesota Public Utilities Commission continues to review our resource plan that will determine the future energy mix in the Upper Midwest, and we expect a decision in 2021. We recently filed a Colorado Clean Energy Plan that includes adding 5,500 MW of wind, solar and energy storage. It also proposes the early retirement or conversion to natural gas of our remaining coal plants in Colorado. If approved along with a supplemental filing to expand the transmission network in the state, we expect to generate approximately 80% of our energy from renewable sources in Colorado by 2030, reducing our carbon emissions by approximately 85% from 2005 levels while maintaining system reliability and customer affordability. We also came to a resolution with the City of Boulder for a new 20-year franchise agreement.To support our vision of powering 1.5 million electric vehicles in our service areas by 2030, we filed transportation electrification plans in Colorado, Minnesota, New Mexico and Wisconsin and gained approval for new home charging programs in Minnesota and Wisconsin. As we look to achieve our vision of producing 100% carbon-free electricity for our customers by 2050, we initiated the Carbon-free Technology Initiative. This working group stretches across all aspects of Xcel Energy, along with strategic partners such as Edison Electric Institute, other utilities, leading venture capital investors and environmental groups. The goal is to support the advancement, funding and policies supportive of technologies critical to achieving our carbon-free goals. As an example, in 2020 we entered into partnership with the Department of Energy to test the viability of producing carbon-free hydrogen at one of our nuclear plants. BEST IN THE BUSINESSResiliency and flexibility are characteristics that we seek in our generation assets, but this year those terms accurately describe our employees that I believe are the best in the business. It’s an honor and a privilege to lead this team that is so committed to serving our customers and living our values: Committed, Connected, Safe and Trustworthy.It shouldn’t come as a surprise that our employees continue to receive recognition for their efforts and our workplace culture. For the eighth consecutive year, we were selected for Fortune Magazine’s “World’s Most Admired” companies list. Ethisphere named us among the “2021 World’s Most Ethical Companies” — it’s the second consecutive year we received that honor. Our field crews received two EEI Emergency Recovery Awards for their efforts to restore service following Winter Storm Billy, an October ice storm that caused significant damage to the grid in Texas, and for restoring power to 135,000 Minnesota residents following a summer storm that rolled through the Twin Cities. As we look at 2021, we know that there are challenges ahead. We’ve already seen the impact of a historic cold snap, and although the rollout of vaccines provides renewed optimism that we can put COVID-19 in the rearview mirror, the pandemic is not over.But our performance in 2020 is a reason for optimism. Regardless of whatever new challenges arise, you can count on the Xcel Energy team to deliver for you. Sincerely, A BOLD
VISION FOR
ELECTRIC
VEHICLES
XCEL ENERGY AIMS TO POWER 1.5 MILLION EVs BY 2030
Shane Mahowald explains the benefits of driving an
electric vehicle to a customer at Eden Prairie Nissan.
AS ELECTRIC VEHICLES
(EVs) HAVE EVOLVED AND
GAINED PROMINENCE
DURING THE PAST DECADE,
SHANE MAHOWALD HAS
WITNESSED A NOTICEABLE
UPTICK IN THE NUMBER OF
CUSTOMERS INQUIRING
ABOUT THE BENEFITS
AND SUBSEQUENTLY
PURCHASING THEIR FIRST EV.
“The excitement level for EVs has risen
dramatically, especially in the last year,”
said Mahowald, the General Sales
Manager at Eden Prairie Nissan in
Minnesota. “A growing percentage of
customers want their next car purchase to
be an EV. That just wasn’t the case a few
years back. They see the trend and want
to take advantage of the economic and
environmental benefits.”
Those benefits include: no oil changes
or engine maintenance; low-cost
overnight charging instead of filling up
at the gas pump; reduced emissions;
generous rebates and tax credits; and
improved battery technology compared
to earlier models.
General Motors recently announced its
plans to phase out the production of gas
and diesel-powered vehicles by 2035,
and other automakers are expected to
announce similar goals.
“Electric vehicle adoption will grow
substantially in the coming years, and we
want to be at the leading edge of that
wave — powering the cars with our clean,
affordable energy, while also providing our
customers with the programs they
want — from innovative community
electric rideshare partnerships to installing
at-home chargers with an easy process,”
said Brett Carter, Chief Customer and
Innovation Officer at Xcel Energy. “That’s
why in August of 2020 we announced a
bold vision to power 1.5 million electric
vehicles in our service areas by the end of
the decade.”
That means about 20% of all cars on the
road in our service territory would be
electric, saving customers an estimated
$1 billion in annual fuel costs by 2030 and
removing approximately 5 million tons of
carbon annually by the same year.
Regulators in Colorado, Minnesota
and Wisconsin have approved various
programs to support EV adoption for
business and residential customers, with
more states expected to follow in 2021
and beyond.
“One of our key objectives is making the
EV purchasing experience and set-up
of home charging equipment as easy
as possible for our customers,” said
Nadia El Mallakh, Area Vice President of
Strategic Partnerships.
An example of how we are reaching
potential buyers is placing Xcel Energy
ESSENTIAL
ANNUAL REPORT 2020 7
EV educational pillars at car dealerships
like Eden Prairie Nissan, just outside
the Twin Cities. The kiosks offer digital
tools, a hands-on experience with
charging equipment and the ability for
our customers to sign up for a home
charging program.
Consumers in Minnesota and Wisconsin
can work with Xcel Energy to have a Level
2 fast charger installed at their homes. Our
customers can charge their EVs overnight
at off-peak rates for the equivalent of less
than $1 per gallon of gas. Over the course
of a year, those fuel savings can add up to
an average of $700.
EV adoption is tailor-made for Xcel Energy’s
three strategic priorities: leading the clean
energy transition, enhancing the customer
experience and keeping bills low for
customers. Charged on the increasingly
clean Xcel Energy system, electric
vehicles will have about 80% lower
carbon emissions than gas-powered cars
by 2030, amounting to about three tons of
annual carbon reduction per vehicle.
In addition to residential customers,
Xcel Energy is working with companies
and municipalities to help convert their
fleets to electric vehicles. We have also
invested $25 million in public charging
mobility hubs in the Twin Cities and are
supporting HOURCAR, a St. Paul-based
nonprofit ridesharing program to make
EVs accessible to lower-income residents.
Colorado regulators recently approved our
$110 million Transportation Electrification
Plan that will deploy approximately 20,000
EV charging ports at residential, business
and public sites across Colorado.
In New Mexico, our proposed
Transportation Electrification Plan
is specifically geared to support the
state’s developing marketplace, offering
education, incentives and infrastructure
needed to expand EV home charging,
public charging and fleet operations.
A customer gathers information about the benefits
of EVs at an Xcel Energy educational pillar.
8
PROJECTS
DRIVE
RECOVERY
Nobles Wind Farm in southern Minnesota is one of
four wind farms that will be repowered with new
technology to help jumpstart the economy.
EVERY YEAR, XCEL ENERGY
DRIVES SIGNIFICANT ECONOMIC
DEVELOPMENT ACROSS OUR
EIGHT-STATE FOOTPRINT THROUGH
CAPITAL INVESTMENT PROJECTS,
WAGES AND TAX BASE.
In 2020, the company spent $4.9 billion
through our supply chain vendors, with 71%
of those dollars supporting local companies
in our service territory.
So, it should come as no surprise that the
Minnesota Public Utilities Commission and the
Minnesota Department of Commerce asked us
and other industry peers for proposals to help
jumpstart the economy following the COVID-19
economic slowdown.
Our Minnesota Relief and Recovery Act
proposal included $3 billion of incremental and
accelerated investments to help the region’s
economic recovery from the impact of COVID-19
and accelerate the clean energy transition. The
proposal includes building a 460-megawatt large-
scale solar farm next to our Sherco Generating
Station, upgrading four company-owned wind
farms with the next generation of technology
and expanding conservation and energy
efficiency programs.
Upgrading the wind farms — which received
commission approval in December — will save
customers approximately $160 million in energy
costs over the next 25 years and create up to
700 local, union construction jobs, in addition to
the indirect jobs provided by suppliers. Following
construction, the wind farms will increase their
annual carbon-free energy output by approximately
20%, on average, compared to today.
Four of our owned wind farms — three in
southern Minnesota and one in eastern North
Dakota — will be repowered. The wind towers
will be rebuilt on the same foundation locations
with much larger blades and more efficient
turbines. Construction using union labor is
expected to begin in 2021.
ESSENTIAL
ANNUAL REPORT 2020
9
BISTRO VENDOME, A FRENCH
RESTAURANT LOCATED
IN LARIMER SQUARE IN
DOWNTOWN DENVER,
TRANSPORTS PATRONS FROM
THE SHADOWS OF THE ROCKIES
TO THE HEART OF PARIS.
From weekend brunches and business
lunches to romantic dates and family
gatherings, the eatery is normally bustling
with diners. However, the COVID-19
pandemic and subsequent shutdowns of
indoor dining have devastated restaurants
like Bistro Vendome. To keep their doors
open many Colorado eateries have
expanded or renovated their outdoor
spaces to provide patrons with a safe,
warm dining experience.
Bistro Vendome is one of nearly 400
restaurants in more than 30 Colorado
counties to receive a grant from the Winter
Outdoor Dining Fund, which the Xcel Energy
Foundation kickstarted with a pledge of
$750,000 and an initial gift of $500,000.
Launched in November 2020 in partnership
with the State of Colorado and the Colorado
Restaurant Association, the program awards
restaurants with grants of up to $10,000 to
winterize their outdoor spaces with igloos,
heaters, tents and more.
With the grant funds, Bistro Vendome
converted its cozy European courtyard
hidden by brick walls and shady trees into
a large, yet intimate insulated tent flecked
with string lights.
“We are grateful to Xcel Energy and other
partners for their efforts to help Colorado
restaurants survive this winter,” said Beth
Gruitch, co-partner of Crafted Concepts,
which owns Bistro Vendome. “With
COVID-19 restrictions, it would have been
difficult to stay open without the revenue
from our winterized outdoor dining area.”
“Powering the homes and businesses of our
communities and keeping our customers
warm this winter is not enough,” said
Hollie Velasquez Horvath, Senior Director,
State Affairs and Community Relations in
Colorado. “We hope this contribution will
help Colorado restaurants thrive, while also
providing customers a safe and fun dining
experience this winter and beyond.”
The economic shutdown caused by the
global pandemic has hurt many businesses,
especially in the hospitality industry. As a
company literally embedded in the communities
we are privileged to serve, Xcel Energy
created a strategy in 2020 to help our customers
weather the challenges as best as possible.
We were among the first companies in
the industry to suspend disconnections of
residential customers behind on their bills
and are partnering with customers to set
up repayment plans that work for them.
We also worked closely with business
customers to inform them about federal
government loan programs. In Minnesota,
the Public Utilities Commission agreed with
our recommendation to provide a temporary
electric rate discount for business customers
affected by the shutdowns.
Account Manager Sara Terrell received
a thank-you note from a large hotel in
downtown Minneapolis that said in part:
“Our business has suffered a $7 million
loss this year, and our staffing levels have
been reduced to the bare bones. So, when
I say we are grateful, I can’t find a way to
fully express that in words. But the savings
provided with this discounted electric rate
are helping to keep good people employed.”
Xcel Energy account managers were
in constant contact with their business
customers to offer our help.
“Our customers just wanted someone
in their corner to listen to their struggles
and lend a hand if possible,” said Chris
Conrad, Director of Account Management in
Minnesota. “Helping customers in big and
small ways is always important, and this past
year demonstrated that more than ever.”
10
HELPING
CUSTOMERS
WEATHER A
PANDEMIC
THE HOSPITALITY INDUSTRY WAS
ESPECIALLY HIT HARD BY COVID-19
ESSENTIAL
ANNUAL REPORT 2020
11
10,000
MEGAWATTS
AND COUNTING
COMPANY WRAPPING UP LARGEST MULTI-STATE
WIND INVESTMENT IN THE COUNTRY
12
DESPITE A GLOBAL PANDEMIC,
XCEL ENERGY CONTINUED TO
MAKE EXCELLENT PROGRESS IN
2020 ON OUR NATION-LEADING
MULTI-STATE WIND EXPANSION
THAT IS SCHEDULED TO WRAP
UP IN 2021.
The company added nearly 1,500 megawatts
of owned wind capacity on the system last
year, including the Sagamore Wind Farm
in New Mexico and Cheyenne Ridge Wind
Farm in Colorado. At approximately 500
megawatts each, these company-owned
and operated projects are two of the
largest on our system.
Our Steel for Fuel strategy delivers
significant environmental benefits, saves
customers hundreds of millions of dollars
in fuel costs over the life of the projects
and provides shareholder value. Our wind
ownership portfolio — where we earn an
investment return — has grown five-fold
in recent years.
“I’m really proud of the progress we
made in 2020. There was a lot of concern
the pandemic would slow down the
clean energy transition, but it actually
strengthened our resolve,” said Kim
Randolph, Xcel Energy’s Vice President
of Energy Supply Projects. “We never
lost sight of the importance of employee
safety and worked with our construction
partners to put these huge wind farms
into service.”
When all the 2020 wind projects were
tallied, Xcel Energy became one of the first
companies in the country to reach 10,000
megawatts of wind capacity on our system,
and we have more on the way. Four
additional wind farms will be completed
in 2021, adding 800 megawatts to our
system, and we also have another 650
megawatts of approved wind repowering
projects in the pipeline. Xcel Energy is
currently the second-largest utility wind
energy provider in the country.
Because of challenges due to COVID-19,
the U.S. Congress extended the full
production tax credit for an additional year,
meaning that wind projects completed
in 2021 will cost millions of dollars less,
which helps keep bills low for customers.
Xcel Energy has several expiring wind
power purchase agreements over the
next decade, which are a significant
opportunity to buy and repower older
wind farms using the latest technology
that is more efficient and will save
customers money even after those wind
farms are retrofitted.
Xcel Energy became the first power
company in the country to announce
a vision to provide 100% carbon-free
electricity for customers by 2050, and
an aggressive interim goal of reducing
carbon emissions 80% by the end of the
decade. By adding a significant amount
of large-scale renewable energy, retiring
coal units or operating them differently
and enhancing energy efficiency
programs, the company has reduced
carbon emissions 51% at the end of
2020 compared to 2005 levels.
ESSENTIAL
ANNUAL REPORT 2020
13
XCEL ENERGY EMPLOYEES
HAVE ALWAYS TAKEN PRIDE
IN THE IMPORTANT ROLE
OF POWERING THE HOMES
AND BUSINESSES OF OUR
COMMUNITIES.
It’s a job we do each and every day, but a global
pandemic put it in a different perspective.
In 2020, our role as essential workers was
heightened as grocery stores, hospitals
and health care centers relied on our
critical services, as did parents to make
sure children could participate in distance
learning. As our employees strove to
protect and keep our communities safe,
we doubled down this year in our efforts
to do the same for them.
First and foremost, we took action to
protect our mission-critical employees
through expanded personal protective
equipment and enhanced cleaning
procedures. Onsite workers performed
daily temperature checks, wore face
coverings and practiced social distancing.
We also implemented new procedures
for frontline workers such as staggered
schedules, a one-employee-per-vehicle
limit and safety meetings held at job sites
instead of service centers.
We shifted almost 7,000 people from
office buildings to work from home,
quickly rolled out new video conference
capabilities, and increased our network
bandwidth to stay connected and
productive while working remotely.
If an employee or contractor tested
positive for COVID-19 or was in close
contact to someone who did, we made
sure they self-quarantined based on
U.S. Centers for Disease Control and
Prevention guidance. We also immediately
jumped in to cover the cost of COVID-19
testing, screening and treatment for
employees and their families covered
under our health plans and added
resources to support mental health.
“It was critical to protect our employees
during this challenging pandemic, not
only for their personal well-being, but
also so they could continue to provide
the essential services that our customers
rely on,” said Darla Figoli, Xcel Energy’s
Chief Human Resources Officer. “Our
new approach to safety focuses on caring
for employees by creating an open,
transparent and trusting culture. Last year
that served us well as employees shared
experiences, learned from events and
collaborated to help protect themselves,
their coworkers and the public.”
14
KEEPING
ESSENTIAL
WORKERS
SAFE
PROTECTING OUR EMPLOYEES AND
THEIR FAMILIES WAS A TOP PRIORITY
ESSENTIAL
ANNUAL REPORT 2020
15
SUPPORTING OUR
COMMUNITIES HAS BEEN
A STAPLE AT XCEL ENERGY
FOR DECADES, BUT IT
TOOK ON UNPRECEDENTED
IMPORTANCE IN 2020 WITH THE
COMBINATION OF A GLOBAL
PANDEMIC, THE SUBSEQUENT
ECONOMIC DOWNTURN AND
CIVIL UNREST IN MANY OF
OUR COMMUNITIES.
Leadership can take several forms,
and Xcel Energy has demonstrated
community and industry leadership
through our quick actions and targeted
contributions of hours and dollars.
RACIAL EQUITY
The nation saw searing images of
civil unrest in communities across
the country in 2020, but among the
most notable were in the Twin Cities,
only a few miles from Xcel Energy’s
headquarters, following the death of
George Floyd in police custody. The
company has committed to help local
businesses rebuild with free energy
design assistance and double rebates on
qualifying energy efficient purchases such
as HVAC and lighting systems.
In early 2021, the Xcel Energy Foundation
announced $350,000 in grants to 14
nonprofit organizations to fund racial
equity programs and rebuild communities
in Minneapolis and St. Paul. That comes
on the heels of a $300,000 donation to
help fund North Star Learning Pods, an
innovative program to help reduce the
achievement gap for black and minority
students. Located at local churches and
community centers, learning pods feature
tutoring, enrichment experiences and
reliable internet connections for hundreds
of students to make distance learning
more effective in a school year disrupted
by the COVID-19 pandemic. We also
supported six nonprofits striving for racial
equity in Colorado in addition to efforts in
our other states.
As a company, we aim to create an
inclusive work culture where employees
are treated equitably, and diversity is not
only accepted but celebrated. Our CEO
and senior executives lead by example,
fostering an open and accepting work
environment through their communications
and interactions, which include holding
crucial conversations on race relations. We
provide enterprise-wide learnings such
as unconscious bias and microinequities
training, and we sponsor 10 business
resource groups to support employee
interests and assist the organization in
solving challenges and achieving goals.
However, our commitment goes beyond
programs, policies and practices — we
strive for diversity, equity and inclusion
(“DEI”) to be an integral part of who we
are, how we operate and how we see
our future. We are committed to progress
and will measure our progress through
corporate scorecard metrics that include,
among other things, employee feedback
on our engagement survey inclusion index,
the use of diverse hiring interview panels
and an executive sponsorship program.
COVID-19 RELIEF
To provide financial relief for communities
hard-hit by COVID-19, the company
donated $100,000 to six regional and
community foundations and three tribal
nations in Wisconsin, the first of several
contributions across our service territory.
In addition to our foundation monetary
16
DELIVERING
FOR OUR
COMMUNITIES
FOUNDATION DOLLARS SUPPORT
COVID-19 RELIEF, RACIAL EQUITY EFFORTS
ESSENTIAL
ANNUAL REPORT 2020 17
contribution, many employees donated
their time and used their ingenuity to
help make a difference.
Employees across the company sewed
and donated masks for family members,
friends, neighbors and health care
workers in their community. In addition,
three employees developed a solution
for the ear discomfort many people were
experiencing when wearing masks all day.
Using a 3-D printer, they created a simple
plastic extender that connects to a
mask’s elastic bands, eliminating the
discomfort. The trio initially made 1,900
for Xcel Energy employees, but after
hearing that the pieces are expensive
for the health care community, they
produced thousands of ear protectors a
week to donate to frontline health care
providers in the Upper Midwest.
THANKING HEALTH CARE WORKERS
One morning in the spring of 2020,
hospital workers at two St. Paul hospitals
— Regions and Bethesda — received
a unique thank you gesture from 60
Xcel Energy employees.
With dozens of bucket trucks and other
vehicles, our employees arrived for
the morning shift change to thank the
health care workers and first responders.
Banners with messages of support hung
from hoisted buckets, and company
employees lined the sidewalks to
applaud the medical workers who were
either arriving to start their day or just
finishing their shift.
“It was the most rewarding day of my
career. The raw emotion that we saw
and felt that day was awesome. I don’t
think I’ll see anything like that again,” said
Mitch Quinnell, an Operations Manager
based in St. Paul.
Megan Remark, President and CEO of
Regions Hospital, agreed. “I want you
to know that everywhere I walked at
Regions Hospital the following morning,
18
John Marshall,
Director of Community
Relations & Foundation,
delivers special
mask extenders to
M Fairview Hospital.
A trio of Xcel Energy
employees produced
them using a 3-D
printer. Overall, the
company donated
more than 300,000
masks to hospitals,
health care centers
and tribal communities.
I heard our teams talking about what an
amazing morale boost your Xcel Energy
team gave all of our caregivers,” she
wrote in an email. “As you know, essential
workers like your team and our team are
ready 24/7 to solve any problem and are
ready to be there for everyone who needs
us. Your grand gesture will live in the
minds of our caregivers forever.”
GIVING BACK
Our employees have always stepped up
to play a significant role in supporting our
communities, and that was especially true
during the pandemic. The Xcel Energy
Foundation encouraged employee giving
to their favorite nonprofits with a special
2-for-1 match, resulting in $450,000 of
contributions to organizations that needed
support more than ever. In total, our
employees and the Foundation invested
nearly $13 million in our communities in
2020. That includes another successful
United Way campaign in which employees
raised $2.5 million, exceeding the goal
despite having to pivot to virtual activities.
Employees also volunteered approximately
50,000 volunteer hours last year at events
like the 10th annual Xcel Energy Day of
Service (virtual and modified in-person
opportunities) and served on more than
500 nonprofit boards in our communities.
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, 2020 or
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
Trading Symbol
XEL
Name of each exchange on which registered
Nasdaq Stock Market LLC
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, 2020, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $32,825,311,125.
As of Feb. 11, 2021, there were 537,648,833 shares of common stock outstanding, $2.50 par value.
Portions of the Registrant’s definitive Proxy Statement for its 2021 Annual Meeting of Shareholders are incorporated by reference into Part III of this Form 10-K.
DOCUMENTS INCORPORATED BY REFERENCE
TABLE OF CONTENTS
PART I
Item 1 —
Business
Definitions of Abbreviations
Where to Find More Information
Forward-Looking Statements
Overview
Electric Operations
Natural Gas Operations
General
Public Utility Regulation
Environmental
Capital Spending and Financing
Information about our Executive Officers
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
Selected Financial Data
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
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
1
1
2
2
3
8
11
12
12
12
13
14
14
20
20
22
22
22
22
22
41
41
78
78
78
78
78
78
78
78
79
84
85
PART I
ITEM 1 — BUSINESS
Definitions of Abbreviations
Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
Capital Services
Capital Services, LLC
Eloigne
e prime
Eloigne Company
e prime inc.
NSP-Minnesota
Northern States Power Company, a Minnesota corporation
NSP System
The electric production and transmission system of NSP-Minnesota and
NSP-Wisconsin operated on an integrated basis and managed by NSP-
Minnesota
NSP-Wisconsin
Northern States Power Company, a Wisconsin corporation
Operating
companies
PSCo
SPS
NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
Public Service Company of Colorado
Southwestern Public Service Co.
Utility subsidiaries NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
WGI
WYCO
WestGas InterState, Inc.
WYCO Development, LLC
Xcel Energy
Xcel Energy Inc. and its subsidiaries
Federal and State Regulatory Agencies
CPUC
Colorado Public Utilities Commission
D.C. Circuit
United States Court of Appeals for the District of Columbia Circuit
DOC
DOE
DOT
EPA
FERC
Minnesota Department of Commerce
United States Department of Energy
United States Department of Transportation
United States Environmental Protection Agency
Federal Energy Regulatory Commission
Fifth Circuit
United States Court of Appeals for the Fifth Circuit
IRS
Internal Revenue Service
Minnesota District
Court
U.S. District Court for the District of Minnesota
MPSC
MPUC
NDPSC
NERC
NMPRC
NRC
PHMSA
PSCW
PUCT
SDPUC
SEC
TCEQ
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
South Dakota Public Utilities Commission
Securities and Exchange Commission
Texas Commission on Environmental Quality
Electric, Purchased Gas and Resource Adjustment Clauses
CEPA
CIP
DCRF
DSM
DSMCA
ECA
EECRF
EIR
FCA
Colorado Energy Plan Adjustment
Conservation improvement program
Distribution cost recovery factor
Demand side management
DSM cost adjustment
Retail electric commodity adjustment
Energy efficiency cost recovery factor
Environmental improvement rider
Fuel clause adjustment
FPPCAC
Fuel and purchased power cost adjustment clause
GCA
GUIC
PCCA
Gas cost adjustment
Gas utility infrastructure cost rider
Purchased capacity cost adjustment
PCRF
PGA
PSIA
RDF
RER
RES
RESA
SCA
SEP
TCA
TCR
TCRF
WCA
Other
ADIT
AFUDC
ALLETE
ARO
ASC
ASU
BART
Boulder
C&I
CAGR
CACJA
CapX2020
CCR
CCR Rule
CDD
CEO
CFO
CIG
Power cost recovery factor
Purchased gas adjustment
Pipeline system integrity adjustment
Renewable development fund
Renewable energy rider
Renewable energy standard
RES adjustment
Steam cost adjustment
State energy policy rider
Transmission cost adjustment
Transmission cost recovery adjustment
Transmission cost recovery factor
Wind cost adjustment
Accumulated deferred income taxes
Allowance for funds used during construction
ALLETE, Inc.
Asset retirement obligation
FASB Accounting Standards Codification
FASB Accounting Standards Update
Best available retrofit technology
City of Boulder, CO
Commercial and Industrial
Compound annual growth rate
Clean Air Clean Jobs Act
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
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
COVID-19
Novel coronavirus
Clean Water Act
Construction work in progress
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
Effluent limitations guidelines
European Mutual Association for Nuclear Insurance
Earnings per share
Effective tax rate
Financial Accounting Standards Board
Financial transmission right
Generally accepted accounting principles
General Electric
Greenhouse gas
Heating degree-days
Integrated market
Institute of Nuclear Power Operations
CWA
CWIP
DECON
DRIP
EEI
ELG
EMANI
EPS
ETR
FASB
FTR
GAAP
GE
GHG
HDD
IM
INPO
1
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
its website,
www.xcelenergy.com, as well as through press releases, filings with the
SEC, conference calls and webcasts.
financial performance
through
Forward-Looking Statements
Except for the historical statements contained in this report, the matters
discussed herein are forward-looking statements that are subject to certain
risks, uncertainties and assumptions. Such forward-looking statements,
including the 2021 EPS guidance, long-term EPS and dividend growth rate
objectives, future sales, future bad debt expense, future operating
performance, estimated base capital expenditures and financing plans,
projected capital additions and forecasted annual revenue requirements
with respect
filings, and expectations regarding regulatory
proceedings, as well as assumptions and other statements are intended to
be identified in this document by the words “anticipate,” “believe,” “could,”
“estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,”
“possible,” “potential,” “should,” “will,” “would” and similar expressions.
Actual results may vary materially. Forward-looking statements speak only
as of the date they are made, and we expressly disclaim any obligation to
update any forward-looking information.
to rider
The following factors, in addition to those discussed elsewhere in this
Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2020
(including risk factors listed from time to time by Xcel Energy Inc. in reports
filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report
on Form 10-K hereto), could cause actual results to differ materially from
forward-looking
management expectations as suggested by such
information: uncertainty around the impacts and duration of the COVID-19
pandemic; operational safety, including our nuclear generation facilities;
successful long-term operational planning; commodity risks associated with
energy markets and production; rising energy prices and fuel costs;
qualified employee work force and third-party contractor factors; ability to
recover costs; changes in regulation and subsidiaries’ ability to recover
costs from customers; reductions in our credit ratings and the cost of
maintaining certain contractual relationships; general economic conditions,
including inflation rates, monetary fluctuations and their impact on capital
expenditures and the ability of Xcel Energy Inc. and its subsidiaries to
obtain financing on favorable terms; availability or cost of capital; our
customers’ and counterparties’ ability to pay their debts to us; assumptions
and costs relating to funding our employee benefit plans and health care
benefits; our subsidiaries’ ability to make dividend payments; tax laws;
effects of geopolitical events, including war and acts of terrorism; cyber
security threats and data security breaches; seasonal weather patterns;
changes in environmental laws and regulations; climate change and other
weather; natural disaster and resource depletion, including compliance with
any accompanying legislative and regulatory changes; and costs of
potential regulatory penalties.
Independent power producing entity
Integrated Resource Plan
Investment Tax Credit
Joint operating agreement
IPP
IRP
ITC
JOA
LSP Transmission LSP Transmission Holdings, LLC
MDL
MEC
MGP
MISO
Moody’s
NAAQS
Native load
Multi-district litigation
Mankato Energy Center
Manufactured gas plant
Midcontinent Independent System Operator, Inc.
Moody’s Investor Services
National Ambient Air Quality Standard
Demand of retail and wholesale customers that a utility has an obligation
to serve under statute or contract
NAV
NEIL
NOL
O&M
OATT
PI
Post-65
PPA
Pre-65
PTC
REC
ROE
ROFR
ROU
RPS
RTO
S&P
SERP
SMMPA
SO2
SPP
TCEH
TCJA
THI
TOs
TSR
VaR
VIE
Net asset value
Nuclear Electric Insurance Ltd.
Net operating loss
Operating and maintenance
Open Access Transmission Tariff
Prairie Island nuclear generating plant
Post-Medicare
Purchased power agreement
Pre-Medicare
Production tax credit
Renewable energy credit
Return on equity
Right-of-first-refusal
Right-of-use
Renewable portfolio standards
Regional Transmission Organization
Standard & Poor’s Global Ratings
Supplemental executive retirement plan
Southern Minnesota Municipal Power Agency
Sulfur dioxide
Southwest Power Pool, Inc.
Texas Competitive Energy Holdings
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 owners
Total shareholder return
Value at Risk
Variable interest entity
WOTUS
Waters of the U.S.
Measurements
Bcf
KV
KWh
MMBtu
MW
MWh
Billion cubic feet
Kilovolts
Kilowatt hours
Million British thermal units
Megawatts
Megawatt hours
Where to Find More Information
Xcel Energy’s website address is www.xcelenergy.com. Xcel Energy
makes available, free of charge through its website, its annual report on
Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K
and all amendments to those reports filed or furnished pursuant to Section
13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as
reasonably practicable after the reports are electronically filed with or
furnished to the SEC.
2
Overview
Xcel Energy (the “Company”) is a major U.S. regulated electric and natural gas delivery company headquartered in Minneapolis, Minnesota (incorporated in
Minnesota in 1909). Xcel Energy serves customers in eight mid-western and western states, including portions of Colorado, Michigan, Minnesota, New
Mexico, North Dakota, South Dakota, Texas and Wisconsin. Xcel Energy provides a comprehensive portfolio of energy-related products and services to
approximately 3.7 million electric customers and 2.1 million natural gas customers through four utility subsidiaries (i.e., NSP-Minnesota, NSP-Wisconsin,
PSCo and SPS). Along with the utility subsidiaries, the transmission-only subsidiaries, WYCO (a joint venture formed with CIG to develop and lease natural
gas pipelines, storage and compression facilities) and WGI (an interstate natural gas pipeline company) comprise the regulated utility operations. Xcel
Energy’s nonregulated subsidiaries include Eloigne, Capital Services and Nicollet Project Holdings.
Utility Subsidiaries’ Service Territory
Electric customers
Natural gas customers
Total assets
Electric generating capacity
Natural gas storage capacity
3.7 million
2.1 million
$54 billion
20,140 MW
53.4 Bcf
Electric transmission lines (conductor miles)
110,353 miles
Electric distribution lines (conductor miles)
208,586 miles
Natural gas transmission lines
Natural gas distribution lines
2,172 miles
35,936 miles
Vision, Mission and Values
VISION To be the preferred and trusted provider of the energy our customers need
CONNECTED
Innovate together. Celebrate together.
Always put we before me – we win as a team.
Value the diversity that each of us brings – be inclusive.
COMMITTED
Act like an owner.
Never settle – be curious and find a better way.
Keep customers and communities the center of all we do.
OUR VALUES
One team powered by many
SAFE
Safety always – no exceptions.
Be responsible for each other’s safety.
Do your part to keep communities safe.
TRUSTWORTHY
Give respect, earn respect.
Keep your word – integrity matters.
Do the right thing – lead by example.
MISSION To provide our customers the safe, clean, reliable energy services they want and value at a competitive price
3
Strategy
Xcel Energy strives to be the preferred and trusted provider of the energy
to
total return
our customers need, while offering a competitive
shareholders. We deliver on our vision through three strategic priorities:
Lead the Clean Energy Transition
Reducing carbon emissions 80% by 2030; 100% carbon-free electricity by 2050
Enhance the Customer Experience
Conservation, renewable and electric vehicle offerings
Keep Bills Low
Average bill increases ≤ rate of inflation
Lead the Clean Energy Transition
For more than a decade, Xcel Energy has proactively managed the risk of
climate change and responded to increasing customer demand for
renewable energy. We reduced carbon emissions from generation serving
customers by 51% from 2005 to 2020 and are on track to reach 60%
renewable generation by 2030.
56%
■ Coal
■ Natural Gas
■ Nuclear
■ Renewables
23%
21%
12%
9%
Energy Mix
64%
50%
32%
34%
26%
13%
12%
12%
21%
12%
3%
2005
2020
2025E*
2030E*
* Potential scenarios that achieve carbon reduction goal
Our recently announced generation transition plans include:
•
•
•
•
•
•
•
Adding economic wind and solar resources.
Limiting coal generation through seasonal dispatch of coal facilities
where possible and early retirement of coal plants (e.g., Hayden and
Craig), including fully exiting coal in the upper Midwest by 2030 (e.g.,
Sherco).
Using natural gas as a means to ensure system reliability.
Extending the life of our Monticello nuclear plant.
Converting Harrington, our coal plant in Texas, to natural gas.
A proposal to close the Hayden coal plant, retiring Unit 2 by the end of
2027 and Unit 1 in 2028.
Retiring Craig coal plant with Unit 1 closing in 2025 and Unit 2 closing
in 2028.
Our March 2021 Colorado resource plan filing will outline a range of options
for us to achieve 80% carbon reduction by 2030 in the state, including:
•
•
•
Proposed plans for our remaining coal units (approximately 1,200
MW), such as early retirements and natural gas conversions.
Additional renewables and storage.
Transmission expansion.
We are confident we can achieve our 80% interim carbon reduction goal
with today’s technology. New carbon-free dispatchable technologies will be
required in order to achieve the remaining 20% carbon reduction.
Reliability, customer affordability and innovation remain paramount to a
successful transition.
Xcel Energy’s clean energy leadership extends to our natural gas
distribution system as we work to keep our methane emissions rate below
0.2%. Our plans include the following:
• Working with upstream suppliers on reducing emissions on their
•
•
system.
Reducing methane emissions from our own operations.
Designing programs that encourage customer conservation and
electrification where beneficial.
Enhance the Customer Experience
Xcel Energy is committed to providing programs that customers want and
value. We continue to expand renewable offerings and promote cost
savings and conservation programs, in which we have invested over $2
billion in the past decade.
Xcel Energy is transforming our electric grid to accommodate increased
levels of renewables and distributed energy resources and continues to
offer customers directly sourced renewable energy solutions. We are also
working to develop new programs for C&I customers who desire higher
than standard service reliability, with the goal being to make it both easy
and affordable for business customers to meet their resiliency needs.
Additionally, we have partnered with policymakers, state agencies and
innovative partners to develop nation-leading electric vehicle solutions for
our customers. Our electric vehicle plans include residential, fleet and
public charging offerings. In 2020, our residential, flat-fee subscription
service pilot won Public Utility Fortnightly’s Smartest Transportation
Electrification Project award. Xcel Energy has full or pilot electric vehicle
programs underway in Minnesota, Colorado and Wisconsin, including our
$110 million, three-year Colorado plan which was approved in December
2020.
In 2020, we set an ambitious goal to power 1.5 million electric vehicles
across our service territory by 2030, which is estimated to save customers
$1 billion in fueling costs and cut carbon emissions by nearly 5 million tons
annually by 2030.
Keep Bills Low
Affordability is foundational to our strategy. Our goal is to keep bill
increases at or below the rate of inflation. Xcel Energy has kept residential
bills relatively flat since 2013.
Our states benefit from strong wind and solar capacity factors. This
geographic advantage, coupled with renewable tax credits and avoided fuel
costs, enables Xcel Energy to increase its investment in renewables while
saving customers money. We call this our “Steel for Fuel” strategy. From
2017 to 2020, we added nearly 3,000 MW of wind to our system while
delivering approximately $430 million in fuel savings to our customers.
Xcel Energy continues to control O&M expense without compromising
reliability or safety. Since 2014, total O&M has remained flat and we expect
annual growth to remain below 1% through 2025 as declines in base O&M
offset approximately $100 million of incremental wind O&M. We are
continuing to prudently invest in appropriate areas and remain committed to
taking costs out of the business through ongoing improvements in
processes and technology.
Deliver a Competitive Total Return to Investors and Maintain Strong
Investment Grade Credit Rating
Successful execution of our strategy, along with our disciplined approach to
growth, investments, operations and management of environmental, social
and corporate governance issues, positions Xcel Energy to continue
delivering a competitive TSR.
4
CONSISTENT DELIVERY
TRANSPARENT GROWTH
LEADING ESG PROFILE
~8-10%
Total Shareholder Return
5-7%
EPS Growth
~2.5%
Dividend Yield
5-7%
Dividend CAGR
60-70%
Payout Ratio
We have consistently achieved our financial objectives, meeting or
exceeding our initial earnings guidance range for sixteen consecutive years
and delivering dividend growth for seventeen consecutive years.
GAAP and ongoing earnings have grown 5.6% and 6.1%, respectively,
annually since 2005 and our dividend grew 6.3% annually from 2013-2020.
Xcel Energy works to maintain senior secured debt credit ratings in the A
range and senior unsecured debt credit ratings in the BBB+ to A range. Our
current ratings are consistent with this objective.
Environmental, Social and Governance Leadership
Social
Community
We work to foster economic sustainability and continued affordability by
partnering with communities, policymakers and customers to build facilities,
foster job growth and attract new businesses. In 2020, Xcel Energy
completed 20 economic development projects across our service territory.
Additionally, 71% of Xcel Energy’s supply chain spend was local.
In addition to our annual giving, in 2020 Xcel Energy further supported our
communities by committing the net gain of nearly $20 million from our
Mankato plant sale to short and long-term corporate giving.
We work to mitigate the impacts of early plant retirements on our
employees and community, consistent with our Principles for a Responsible
Transition. We provide advanced notice, offer retraining and relocation
opportunities and have had no layoffs as a result of plant retirements. We
also seek to make investments in the communities in which our coal plants
are being shut down to offset the economic impact.
Sustainability is embedded in Xcel Energy’s strategy and our values:
Safety
Safety is embedded in our values and governance practices, and Xcel
Energy is focused on preventing life-altering injuries. All employees have
“stop work authority” to keep each other, our customers and the public safe.
Through our Safety Always approach, employees are encouraged to share
experiences and learn from events to help protect themselves, their
coworkers and the public.
Human Capital Management
Xcel Energy’s success depends on our ability to actively implement
programs to attract, hire, develop and retain skilled employees. Our
workforce strategy is designed to put the best talent in place, create a
culture that motivates employees to lead the way in achieving our clean
energy goals and deliver an exceptional customer experience.
Xcel Energy has implemented a strategic, data-driven approach to
workforce and succession planning, which includes best practices in
learning and development. Additionally, Xcel Energy partners with
educational and community organizations to attract and hire diverse
employees who reflect the communities we serve. Also, hiring veterans is a
key focus of our workforce strategy, with approximately 10% of employees
having served in the military. Xcel Energy offers its employees a
competitive benefits package which
includes: performance-based
compensation, healthcare benefits, recognition programs and an employee
development program that emphasizes ongoing coaching.
Xcel Energy views diversity, equity and inclusion as an integral part of who
we are, how we operate and how we see our future. We are committed to
an inclusive culture where diversity is celebrated and employees are
treated equitably. Our senior leadership team leads by example, fostering
an inclusive work environment, which recognizes the need for crucial
conversations on diversity. Additionally, Xcel Energy supports an inclusive
environment by offering company-wide trainings on topics addressing
microinequities and unconscious bias. We hold ourselves accountable and
measure our progress through corporate scorecard metrics that include,
among other things, employee feedback in our engagement survey
Inclusion Index.
Connected
Committed
Safe
Trustworthy
We are retiring coal plants, adding renewables, exploring new technologies
and helping to electrify other sectors, while keeping customer bills low. Xcel
Energy has demonstrated leadership in mitigating climate, operational and
financial risks, while remaining committed to customers, employees and
communities.
Environmental
Xcel Energy was the first major U.S. utility to establish a carbon-free vision,
targeting 100% carbon-free electricity by 2050 and an 80% carbon
reduction by 2030 (from 2005 levels). Our plans to achieve 80% carbon
reduction are aligned with targets of the Paris Accord, as validated by a
lead author for the Intergovernmental Panel on Climate Change.
Xcel Energy has provided a voluntary, third-party verified annual GHG
disclosure since 2005, longer than any other U.S. utility. We are a founding
member of The Climate Registry and a supporter of the Task Force on
Climate-Related Financial Disclosures. We have been the number one
provider of wind to customers for 12 of the past 15 years. Our wind capacity
is expected to reach 11,000 MW by the end of 2021, including nearly 4,500
MW of owned wind.
Changing Composition of Wind Capacity
~40% Wind Ownership by 2021
Steel for Fuel
11,200
10,100
6,600
6,700
6,700
8,000
7,300
5,700
4,900
5,100
2,900
3,200
2,700
4,100
3,400
MW
■ PPA
■ Owned
1,100
1,300
2005
2007
2009
2011
2013
2015
2017
2019
2021
As Xcel Energy transitions to cleaner sources, we expect to achieve a 70%
reduction in water consumed in electric generation by 2030 (from 2005
levels). Through 2020, we reduced our water consumption 34% (from 2005
levels).
5
In 2020, Xcel Energy received the following recognitions:
Governance
Xcel Energy has publicly confirmed our commitment to the advancement
and protection of human rights throughout our operations, consistent with
U.S. human rights laws and the general principles set forth in the
International Labour Organization Conventions. Xcel Energy requires
annual Code of Conduct training for all employees and members of the
Board of Directors. Xcel Energy does not tolerate discrimination, violations
of our Code of Conduct or other unacceptable behaviors. We offer
employees multiple avenues to raise concerns or report wrong-doing and
do not permit any retaliation for doing so.
We respect employees’ freedom of association and their right to collectively
organize. As of Dec. 31, 2020, Xcel Energy’s employees were as follows:
Employees Covered by
Collective Bargaining
Agreements
Total Full-Time
Employees
NSP-Minnesota
NSP-Wisconsin
PSCo
SPS
XES
Total
2,033
394
1,882
769
—
5,078
3,144
540
2,378
1,141
4,164
11,367
For decades, Xcel Energy has fostered a culture of compliance and ethical
conduct. Our Code of Conduct serves as the foundation that all employees,
contractors and the Board of Directors are expected to follow, along with
corporate policies that establish rules and guidelines in areas such as
safety, environmental leadership, diversity, community giving and political
contributions.
Xcel Energy has a diverse and qualified Board of Directors, with eight
members elected within the past five years.
1 Executive
14 Independent
40% Female/Diverse
6 Years Average Tenure
■ Male
■ Female
■ Diverse
Accountability and Incentive
We consistently set aggressive goals and hold ourselves accountable to
our customers, communities and investors. Xcel Energy instituted Board of
Directors oversight of environmental performance in 2000 and was among
the first U.S. utilities to tie carbon reduction directly to executive
compensation over fifteen years ago.
In 2020, 60% of annual incentive pay was tied to safety and system
reliability. In 2021, we added an incentive-based metric to reinforce our
commitment to diversity and inclusion. Xcel Energy has clear Board of
Directors committee oversight for safety and our human capital strategy,
including diversity and inclusion initiatives.
6
Utility Subsidiaries
NSP-Minnesota
Electric customers
Natural gas customers
Consolidated earnings contribution
Total assets
Rate Base (estimated)
1.5 million
0.6 million
35% to 45%
$21.1 billion
$12.4 billion
85
MINOT
83
29
GRAND FORKS
DICKINSON
94
BISMARCK
FARGO
94
ROE (net income / average stockholder's equity)
9.20%
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
Consolidated earnings contribution
Total assets
Rate Base (estimated)
8,137 MW
17.1 Bcf
33,660 miles
80,508 miles
80 miles
10,629 miles
0.3 million
0.1 million
5% to 10%
$2.9 billion
$1.8 billion
ROE (net income / average stockholder's equity)
10.52%
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
Consolidated earnings contribution
Total assets
Rate Base (estimated)
548 MW
3.8 Bcf
12,288 miles
27,611 miles
3 miles
2,492 miles
1.5 million
1.4 million
35% to 45%
$20.4 billion
$13.3 billion
ROE (net income / average stockholder's equity)
8.06%
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
Consolidated earnings contribution
Total assets
Rate Base (estimated)
6,223 MW
32.5 Bcf
24,386 miles
78,483 miles
2,058 miles
22,815 miles
0.4 million
15% to 20%
$8.9 billion
$5.4 billion
ROE (net income / average stockholder's equity)
9.54%
Electric generating capacity
Electric transmission lines (conductor miles)
Electric distribution lines (conductor miles)
5,232 MW
40,019 miles
21,984 miles
NSP-Minnesota conducts business
in
Minnesota, North Dakota and South Dakota
and has electric operations in all three
states including the generation, purchase,
transmission, distribution and sale of
electricity. NSP-Minnesota and NSP-
Wisconsin electric operations are managed
on the NSP System. NSP-Minnesota also
purchases, transports, distributes and sells
retail customers and
natural gas
transports customer-owned natural gas in
Minnesota and North Dakota.
to
in
NSP-Wisconsin conducts business
Wisconsin and Michigan and generates,
transmits, distributes and sells electricity.
NSP-Minnesota
NSP-Wisconsin
and
electric operations are managed on the
also
System. NSP-Wisconsin
NSP
purchases, transports, distributes and sells
natural gas
retail customers and
transports customer-owned natural gas.
to
PSCo conducts business in Colorado and
generates, purchases, transmits, distributes
and sells electricity. PSCo also purchases,
transports, distributes and sells natural gas
to
transports
customer-owned natural gas.
customers
retail
and
SPS conducts business in Texas and New
Mexico
purchases,
transmits, distributes and sells electricity.
generates,
and
DULUTH
BRAINERD
35
94
ST. CLOUD
29
DELANO
MINNEAPOLIS & ST. PAUL
90
PIERRE
E
90
SIOUX FALLS
90
35
RED WING
FARIBAULT
MANKATO
90
WINONA
25
GREELEY
FT. COLLINS
ESTES
PARK
BOULDER
STERLING
76
BRUSH
RIFLE
70
VAIL
CARBONDALE
LEADVILLE
DENVER
25
70
GRAND
JUNCTION
PUEBLO
25
ALAMOSA
SANTA FE
25
DALHART
40
ALBUQUERQUE TUCUMCARI
40
BORGER
40
AMARILLO
HEREFORD
27
CLOVIS
PLAINVIEW
ROSWELL
LUBBOCK
25
CARLSBAD
20
LEVELLAND
HOBBS
20
35
DALLAS
20
AUSTIN
SAN ANTONIO
35
7
Operations Overview
Utility operations are generally conducted as either electric or gas utilities in our four utility subsidiaries.
Electric Operations
Electric operations consist of energy supply, generation, transmission and distribution activities across all four operating companies. Xcel Energy had
electric sales volume of 104,731 (millions of KWh), 3.7 million customers and electric revenues of $9,802 (millions of dollars) for 2020.
Sales/Revenue Statistics (a)
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
2020
2019
23,910
24,712
$
2,199
$
2,244
12.12 ¢
11.97 ¢
5.78 ¢
9.56 ¢
9.20 ¢
5.96 ¢
9.43 ¢
9.08 ¢
35%
27%
36%
47%
65%
73%
64%
53%
(a)
See Note 6 to the consolidated financial statements for further information.
Xcel Energy
NSP System
PSCo
SPS
■ Owned ■ Purchased
Electric Energy Sources
Total electric generation by source (including energy market purchases) for the year ended Dec. 31, 2020:
Xcel Energy
NSP System
PSCo
SPS
Carbon-free
Energy*
47%
Coal 21%
Natural
Gas 32%
Coal 18%
Carbon-free
Energy
62%
Natural
Gas 20%
Coal 26%
Carbon-free
Energy
36%
Coal 19%
Carbon-free
Energy
34%
Natural Gas 38%
Natural Gas 47%
* Distributed generation from the Solar*Rewards® program is not included (approximately 675 million KWh for 2020).
8
Sales VolumeResidential25%C&I58%Sales for Resale16%Other 1%Number of CustomersC&I12%Other2%Residential86%RevenuesResidential33%C&I49%Other18%
Carbon-Free Energy
Xcel Energy’s carbon-free energy portfolio
includes wind, nuclear
hydroelectric, biomass and solar power from both owned generation
facilities and PPAs. Carbon-free percentages will vary year-over-year
based on system additions, weather, system demand and transmission
constraints.
Average Cost (PPAs) — Average cost per MWh of wind energy under
existing PPAs:
Utility Subsidiary
NSP System
PSCo
SPS
$
2020
2019
$
38
40
26
41
41
25
See Item 2 — Properties for further information.
Wind Development
Carbon-free energy as a percentage of total energy for 2020:
Xcel Energy placed approximately 1,450 MW of owned wind and
approximately 700 MW of PPAs into service during 2020:
62%
8%
30%
3%
21%
47%
4%
13%
3%
27%
Xcel Energy Inc.
NSP System
2%
36%
2%
3%
31%
PSCo
34%
2%
32%
SPS
■ Other*
■ Solar
■ Nuclear
■ Wind
Wind
Owned — Owned and operated wind farms with corresponding capacity:
2020
2019
Utility Subsidiary
Wind Farms
NSP System
PSCo
SPS
Total
11
2
2
15
Capacity (a) Wind Farms
1,540 MW
7
Capacity (b)
1,079 MW
1,059 MW
967 MW
3,566 MW
1
1
9
582 MW
460 MW
2,121 MW
(a)
Summer 2020 net dependable capacity.
(b)
Summer 2019 net dependable capacity.
PPAs — Number of PPAs with capacity range:
Utility
Subsidiary
NSP System
PSCo
SPS
PPAs
129
17
18
2020
Range
1 MW — 206 MW
23 MW — 301 MW
1 MW — 250MW
PPAs
131
20
18
2019
Range
1 MW — 206 MW
2 MW — 301 MW
1 MW — 250 MW
Capacity — Wind capacity:
Utility Subsidiary
NSP System
PSCo
SPS
2020
3,348 MW
4,085 MW
2,535 MW
2019
2,767 MW
3,145 MW
2,027 MW
Average Cost (Owned) — Average cost per MWh of wind energy from
owned generation:
Project
Utility Subsidiary
Blazing Star 1
Crowned Ridge 2
Community Wind North
Jeffers
Cheyenne Ridge
Sagamore
Various PPAs
(a)
NSP-Minnesota
NSP-Minnesota
NSP-Minnesota
NSP-Minnesota
PSCo
SPS
Various
Capacity
200 MW
(a)(b)
192 MW
(a)(b)
(a)(b)
26 MW
(a)(b)
43 MW
477 MW
(a)(b)
(a)(b)
507 MW
~700 MW (c)
Summer 2020 net dependable capacity.
(b)
Values disclosed are the maximum generation levels for these wind units. Capacity is
attainable only when wind conditions are sufficiently available (on-demand net
dependable capacity is zero).
Based on contracted capacity.
(c)
Xcel Energy currently has approximately 1,450 MW of owned wind under
development or construction. In addition, Xcel Energy expects to add
approximately 450 MW of planned PPAs.
Project
Dakota Range
Freeborn
Blazing Star 2
Nobles
Pleasant Valley
Border Winds
Grand Meadow
Mower
Various PPAs
Solar
Solar PPA(s):
Type
Distributed Generation
Utility-Scale
Distributed Generation
Utility-Scale
Distributed Generation
Utility-Scale
Total
Utility Subsidiary
Capacity
Estimated
Completion
NSP-Minnesota
NSP-Minnesota
NSP-Minnesota
NSP-Minnesota
NSP-Minnesota
NSP-Minnesota
NSP-Minnesota
NSP-Minnesota
Various
300 MW
200 MW
200 MW
200 MW
200 MW
150 MW
100 MW
99 MW
~450 MW
Utility Subsidiary
NSP System
NSP System
PSCo
PSCo
SPS
SPS
2021
2021
2021
2022
2024
2024
2023
2021
2021
Capacity
899 MW
268 MW
643 MW
306 MW
11 MW
190 MW
2,317 MW
Average Cost (PPAs) — Average cost per MWh of solar energy under
existing PPAs:
Utility Subsidiary
NSP System
PSCo
SPS
2020
2019
$
$
23
35
17
Utility Subsidiary
NSP System
PSCo
SPS
35
47
—
$
2020
2019
$
90
89
59
81
89
56
9
Solar Development
In October 2020, Xcel Energy filed a request with the PSCW to purchase a
74 MW, $100 million solar array in Pierce County, WI. A PSCW decision is
expected in the third quarter of 2021. Also, as part of the Minnesota
Recovery and Relief Recovery docket, NSP-Minnesota, proposed the
addition of 460 MW of solar facilities with an expected $550 million
incremental investment. An MPUC decision is expected in the second half
of 2021.
Additionally, Xcel Energy projects approximately 3,500 MW of solar through
2034 in our Minnesota resource plan and will be addressing solar energy
within its upcoming Colorado resource plan.
Nuclear
Xcel Energy has two nuclear plants with approximately 1,700 MW of total
2020 net summer dependable capacity that serves the NSP-System. Our
nuclear fleet has become one of the safest and well-run in the nation, as
rated by both the NRC and INPO. Xcel Energy secures contracts for
uranium concentrates, uranium conversion, uranium enrichment and fuel
fabrication to operate its nuclear plants. We use varying contract lengths as
well as multiple producers for uranium concentrates, conversion services
and enrichment services to minimize potential impacts caused by supply
interruptions due to geographical and world political issues.
Nuclear Fuel Cost
Delivered cost per MMBtu of nuclear fuel consumed for owned electric
generation and the percentage of total fuel requirements:
Utility Subsidiary
NSP System
2020
2019
Other Carbon-Free Energy
Nuclear
Cost
Percent
$
0.80
0.81
51 %
45
Xcel Energy’s other carbon-free energy portfolio includes hydro from owned
generating facilities.
See Item 2 — Properties for further information.
Fossil Fuel Energy
Xcel Energy’s fossil fuel energy portfolio includes coal and natural gas
power from both owned generating facilities and PPAs.
Coal
Xcel Energy owns and operates coal units with approximately 6,500 MW of
total 2020 net summer dependable capacity.
Approved and proposed early coal plant retirements:
Year
Utility Subsidiary
Plant Unit
Approved / Authorized
PSCo
NSP-Minnesota
SPS
PSCo
PSCo
NSP-Minnesota
PSCo
Comanche 1
Sherco 2
Harrington (a)
Comanche 2
Craig 1
Sherco 1
Craig 2
Capacity
325 MW
682 MW
1,018 MW
335 MW
42 MW (b)
680 MW
40 MW (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.
2022
2023
2024
2025
2025
2026
2028
(a)
(b)
Year
Utility Subsidiary
Plant Unit
Proposed
PSCo
PSCo
NSP-Minnesota
NSP-Minnesota
SPS
SPS
Hayden 2
Hayden 1
A.S. King
Sherco 3
Tolk 1
Tolk 2
Capacity
98 MW (a)
135 MW (b)
511 MW
517 MW (c)
532 MW
535 MW
Based on PSCo’s ownership of 37% of Unit 2.
Based on PSCo’s ownership of 76% of Unit 1.
Based on Xcel Energy’s ownership interest.
2027
2028
2028
2030
2032
2032
(a)
(b)
(c)
Plans for our remaining Colorado coal fleet will be outlined when PSCo
submits its 2021 resource plan, which is expected to be filed in March
2021.
Coal Fuel Cost
Delivered cost per MMBtu of coal consumed for owned electric generation
and percentage of fuel requirements:
Utility Subsidiary
NSP System
2020
2019
PSCo
2020
2019
SPS
2020
2019
(a)
Coal (a)
Cost
Percent
$
1.97
2.02
1.41
1.45
2.28
2.19
31 %
36
51
55
40
45
Includes refuse-derived fuel and wood for the NSP System.
Natural Gas
Xcel Energy has 22 natural gas plants with approximately 7,900 MW of
total 2020 net summer dependable capacity.
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 percentage of total fuel requirements:
Natural Gas
Cost
Percent
$
2.67
3.09
3.01
3.27
1.43
1.14
17 %
19
49
45
60
55
Utility Subsidiary
NSP System
2020
2019
PSCo
2020
2019
SPS
2020
2019
10
Capacity and Demand
Notable upcoming projects:
Uninterrupted system peak demand and occurrence date for the regulated
utilities:
System Peak Demand (in MW)
2020
8,571
6,899
4,195
July 8
Aug. 17
July 14
2019
8,774
7,111
4,261
July 19
July 19
Aug. 5
NSP System
PSCo
SPS
Transmission
Transmission lines deliver electricity at higher voltage and over longer
distances from power sources to transmission substations closer to homes
and businesses. A strong transmission system ensures continued reliable
and affordable service, ability to meet state and regional energy policy
goals, and support for a diverse generation mix, including renewable
energy. Xcel Energy owns more than 20,000 miles of transmission lines,
serving 22,000 MW of customer load.
Transmission projects completed in 2020 include:
Project
Hibbing Taconite
Relocation
Huntley-Wilmarth
Helena Scott County
Baytown to Long Lake
Centerville to Lincoln
County
Turtle Lake Almena
Bayfield Second Circuit
Roadrunner-China Draw
Utility Subsidiary
Miles
Size
Completion Date
NSP-Minnesota
NSP-Minnesota
NSP-Minnesota
NSP-Minnesota
NSP-Minnesota
NSP-Wisconsin
NSP-Wisconsin
SPS
3
50
16
9
14
4
19
41
500 KV
345 KV
345 KV
115 KV
69 KV
69 KV
35 KV
345 KV
2021
2021
2021
2022
2021
2021
2022
2021
See Item 2 - Properties for further information.
Distribution
to
lines allow electricity
Distribution
from
substations directly to homes and businesses. Xcel Energy has a vast
distribution network, owning and operating approximately 210,000
conductor miles of distribution lines across our eight-state service territory,
both above ground and underground.
lower voltages
travel at
Project
Maple River-Red River
Glenwood Douglas
Prentice to Structure
Lufkin to Naples
Belgrade to Ironwood
Cornucopia to Bayfield Phase 2
Pawnee-Daniels Park
Cheyenne Ridge
TUCO-Yoakum Co.
Eddy Co-Kiowa
Mustang-Seminole
Loving South-Phantom
Natural Gas Operations
Utility Subsidiary
NSP-Minnesota
NSP-Minnesota
NSP-Wisconsin
NSP-Wisconsin
NSP-Wisconsin
NSP-Wisconsin
PSCo
PSCo
SPS
SPS
SPS
SPS
Miles
4
20
8
13
13
5
113
73
107
34
20
21
Size
115 KV
69 KV
115 KV
69 KV
35 KV
35 KV
345 KV
345 KV
345 KV
345 KV
115 KV
115 KV
To continue providing reliable, affordable electric service and enable more
flexibility for customers, we are working to digitize the distribution grid, while
at the same time keeping it secure. Over the five year project, Xcel Energy
plans to invest approximately $1.8 billion implementing new network
infrastructure, smart meters, advanced software, equipment sensors and
related data analytics capabilities.
These investments will further improve reliability and reduce outage
restoration times for our customers, while at the same time enabling new
options and opportunities for increased efficiency savings. The new
capabilities will also enable integration of battery storage and other
distributed energy resources into the grid, including electric vehicles.
See Item 2 - Properties for further information.
Natural gas operations consist of purchase, transportation and distribution of natural gas to end-use residential, C&I and transport customers in NSP-
Minnesota, NSP-Wisconsin and PSCo. Xcel Energy had natural gas deliveries of 444,340 (thousands of MMBtu), 2.1 million customers and natural gas
revenues of $1,636 (millions of dollars) for 2020.
11
DeliveriesResidential:34%C&I: 21%Transportationand Other:45%Number of CustomersResidential: 91.9%C&I: 7.7%Transportationand Other:0.4%RevenuesResidential:62%C&I: 30%Transportationand Other:8%
Sales/Revenue Statistics (a)
MMBtu sales per retail customer
Revenue per retail customer
Residential revenue per MMBtu
C&I revenue per MMBtu
2020
2019
118.13
129.31
$
720.42
$
851.94
6.64
5.22
0.67
7.14
5.73
0.57
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:
2020
2019
Utility Subsidiary
MMBtu
Date
MMBtu
Date
NSP-Minnesota
NSP-Wisconsin
PSCo
871,921
150,320
Jan. 16
Dec. 24
897,615
166,009
1,931,888
Feb. 4
2,139,420
Feb. 25
Jan. 30
March 3
Natural Gas Supply and Cost
Xcel Energy seeks natural gas supply,
transportation and storage
alternatives to yield a diversified portfolio, which increase flexibility,
decrease interruption and financial risks and economic customer rates. In
addition, the utility subsidiaries conduct natural gas price hedging activities
approved by their states’ commissions.
Average delivered cost per MMBtu of natural gas for regulated retail
distribution:
Utility Subsidiary
NSP-Minnesota
NSP-Wisconsin
PSCo
$
2020
2019
$
3.32
3.08
2.52
3.71
3.49
2.95
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. Other events impact overall economic conditions and
management cannot predict the impact of fluctuating energy prices, terrorist
activity, war or the threat of war. We could experience a material impact to
our results of operations, future growth or ability to raise capital resulting
from a sustained general slowdown in economic growth or a significant
increase in interest rates.
Seasonality
Demand for electric power and natural gas is affected by seasonal
differences in the weather. In general, peak sales of electricity occur in the
summer months and peak sales of natural gas occur in the winter months.
As a result, the overall operating results may fluctuate substantially on a
seasonal basis. Additionally, Xcel Energy’s operations have historically
generated less revenues and income when weather conditions are milder in
the winter and cooler in the summer.
12
Competition
Xcel Energy is subject to public policies that promote competition and
development of energy markets. Xcel Energy’s industrial and large
commercial customers have the ability to generate their own electricity. In
addition, customers may have the option of substituting other fuels or
relocating their facilities to a lower cost region.
Customers have the opportunity to supply their own power with distributed
generation including solar generation and in most jurisdictions can currently
avoid paying for most of the fixed production, transmission and distribution
costs incurred to serve them.
Several states have incentives for the development of rooftop solar,
community solar gardens and other distributed energy resources.
Distributed generating resources are potential competitors to Xcel Energy’s
electric service business with these incentives and federal tax subsidies.
The FERC has continued to promote competitive wholesale markets
through open access transmission and other means. Xcel Energy’s
wholesale customers can purchase their output from generation resources
of competing suppliers or non-contracted quantities and use
the
transmission systems of the utility subsidiaries on a comparable basis to
serve their native load.
FERC Order No. 1000 established competition for construction and
operation of certain new electric transmission facilities. State utility
commissions have also created resource planning programs that promote
competition for electric generation resources used to provide service to
retail customers.
Xcel Energy Inc.’s utility subsidiaries have franchise agreements with cities
subject to periodic renewal; however, a city could seek alternative means to
access electric power or gas, such as municipalization.
While each utility subsidiary faces these challenges, Xcel Energy believes
their rates and services are competitive with alternatives currently available.
Public Utility Regulation
See Item 7 for discussion of public utility regulation.
Environmental
Environmental Regulation
Our facilities are regulated by federal and state agencies that have
jurisdiction over air emissions, water quality, wastewater discharges, solid
wastes and hazardous substances. Certain Xcel Energy activities require
registrations, permits, licenses, inspections and approvals from these
agencies. Xcel Energy has received necessary authorizations for the
construction and continued operation of its generation, transmission and
distribution systems. Our facilities operate in compliance with applicable
environmental
reporting
requirements. However, it is not possible to determine when or to what
extent additional facilities or modifications of existing or planned facilities
will be required as a result of changes to regulations, interpretations or
enforcement policies or what effect future laws or regulations may have.
We may be required to incur expenditures in the future for remediation of
MGP and other sites if it is determined that prior compliance efforts are not
sufficient.
related monitoring and
standards and
Environmental Costs
Environmental costs include amounts for nuclear plant decommissioning
and payments for storage of spent nuclear fuel, disposal of hazardous
materials and waste, remediation of contaminated sites, monitoring of
discharges to the environment and compliance with laws and permits with
respect to emissions.
Costs charged to operating expenses for nuclear decommissioning, spent
nuclear fuel disposal, environmental monitoring and remediation and
disposal of hazardous materials and waste were approximately:
•
•
•
$400 million in 2020.
$345 million in 2019.
$335 million in 2018.
for similar costs. The precise
Average annual expense of approximately $465 million from 2021 – 2025 is
estimated
timing and amount of
environmental costs, including those for site remediation and disposal of
hazardous materials, are unknown. Additionally, the extent to which
environmental costs will be included in and recovered through rates may
fluctuate.
Capital expenditures for environmental improvements were approximately:
•
•
•
$30 million in 2020.
$30 million in 2019.
$50 million in 2018.
Capital Spending and Financing
See Item 7 for discussion of capital expenditures and funding sources.
Xcel Energy must comply with emission levels in Minnesota, Texas and
Wisconsin that may require the purchase of emission allowances. The
Denver North Front Range Non-attainment Area does not meet either the
2008 or 2015 ozone NAAQS. Colorado will continue to consider further
reductions available in the non-attainment area as it develops plans to meet
ozone standards. Gas plants which operate in PSCo’s non-attainment area
may be required to improve or add controls, implement further work
practices and/or enhanced emissions monitoring as part of future Colorado
state plans.
There are significant environmental regulations to encourage use of clean
energy technologies and regulate emissions of GHGs. We have undertaken
numerous initiatives to meet current requirements and prepare for potential
future regulations, reduce GHG emissions and respond to state renewable
and energy efficiency goals. Future environmental regulations may result in
substantial costs.
In July 2019, the EPA adopted the Affordable Clean Energy rule, which
required states to develop plans by 2022 for GHG reductions from coal-
fired power plants. In a Jan. 19, 2021 decision, the U.S. Court of Appeals
for the D.C. Circuit issued a decision vacating and remanding the
Affordable Clean Energy rule. That decision, if not successfully appealed or
reconsidered, would allow the EPA to proceed with alternate regulation of
coal-fired power plants, either reviving the Clean Power Plan or proposing
additional regulation. It is too early to predict an outcome, but new rules
could require substantial additional investment, even in plants slated for
retirement. Xcel Energy believes, based on prior state commission
practices, the cost of these initiatives or replacement generation would be
recoverable through rates.
In October 2020, the TCEQ approved an agreement that ensures SPS will
convert the Harrington plant from coal to natural gas by Jan. 1, 2025. This
conversion is necessary to attain Federal Clean Air Act standards for
emissions of SO2.
Xcel Energy seeks to address climate change and potential climate change
regulation through efforts to reduce its GHG emissions in a balanced, cost-
effective manner.
In 2020, Xcel Energy estimates that it reduced carbon emissions
associated with electric generating resources, both owned and under
PPAs, used to serve its customers by approximately 51% from 2005 levels.
13
Time in Position
August 2011 — Present
January 2015 — Present
August 2011 — March 2020
March 2020 — Present
May 2016 — March 2020
February 2012 — April 2016
May 2018 — Present
October 2015 — May 2018
January 2015 — Present
Information about our Executive Officers (a)
Age (b)
62
Ben Fowke
Name
Chairman of the Board of Directors, Chief Executive Officer and Director, Xcel Energy Inc.
Current and Recent Positions
Chief Executive Officer, NSP-Minnesota, NSP-Wisconsin, PSCo, and SPS
President, Xcel Energy Inc.
Robert C. Frenzel
50
President and Chief Operating Officer, Xcel Energy Inc.
Brett C. Carter
Christopher B. Clark
Darla Figoli
David T. Hudson
Alice Jackson
Timothy O’Connor
Frank Prager
Amanda Rome
Jeffrey S. Savage
Mark E. Stoering
Brian J. Van Abel
54
54
58
60
42
61
58
40
49
60
39
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
President and Director, NSP-Minnesota
Executive Vice President, Human Resources & Employee Services, Chief Human Resources Officer, Xcel Energy Inc.
June 2020 — Present
Senior Vice President, Human Resources & Employee Services, Chief Human Resources Officer, Xcel Energy Inc.
May 2018 — June 2020
Senior Vice President, Human Resources and Employee Services, Xcel Energy Inc.
President and Director, SPS
President and Director, PSCo
Area Vice President, Strategic Revenue Initiatives, Xcel Energy Services Inc.
Regional Vice President, Rates and Regulatory Affairs, PSCo
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.
President and Director, NSP-Wisconsin
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.
May 2015 — May 2018
January 2015 — Present
May 2018 — Present
November 2016 — May 2018
November 2013 — November 2016
March 2020 — Present
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
January 2015 — Present
March 2020 — Present
September 2018 — March 2020
July 2015 — September 2018
(a)
(b)
(c)
No family relationships exist between any of the executive officers or directors.
Ages as of Feb. 17, 2021.
In April 2014, Energy Future Holdings Corp., the majority of its subsidiaries, including TCEH the parent company of Luminant, filed a voluntary bankruptcy petition under Chapter 11 of the
United States Bankruptcy Code. TCEH emerged from Chapter 11 in October 2016.
ITEM 1A — RISK FACTORS
Xcel Energy is subject to a variety of risks, many of which are beyond our
control. Risks that may adversely affect the business, financial condition,
results of operations or cash flows are described below. These risks should
be carefully considered together with the other information set forth in this
report and future reports that we file with the SEC.
Oversight of Risk and Related Processes
The Board of Directors is responsible for the oversight of material risk and
maintaining an effective risk monitoring process. Management and the
Board of Directors’ committees have responsibility for overseeing the
identification and mitigation of key risks and reporting its assessments and
activities to the full Board of Directors.
Xcel Energy maintains a robust compliance program and promotes a
culture of compliance beginning with the tone at the top. The risk mitigation
process includes adherence to our code of conduct and compliance
policies, operation of formal risk management structures and overall
business management. Xcel Energy further mitigates inherent risks through
formal risk committees and corporate functions such as internal audit, and
internal controls over financial reporting and legal.
Management identifies and analyzes risks to determine materiality and
other attributes such as timing, probability and controllability. Identification
and risk analysis occurs formally through risk assessment conducted by
senior management,
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.
14
The oversight, management and mitigation of risk is an integral and
continuous part of the Board of Directors’ governance of Xcel Energy. The
Board of Directors assigns oversight of critical risks to each of its four
these risks are well understood and given
committees
appropriate focus.
to ensure
The Audit Committee is responsible for reviewing the adequacy of the
committee’s risk oversight and affirming appropriate aggregate oversight
occurs. Committees regularly report on their oversight activities and certain
risk issues may be brought to the full Board of Directors for consideration
when deemed appropriate.
New risks are considered and assigned as appropriate during the annual
Board of Directors and committee evaluation process, resulting in updates
to the committee charters and annual work plans. Additionally, the Board
of Directors conducts an annual strategy session where Xcel Energy’s
future plans and initiatives are reviewed.
Risks Associated with Our Business
Operational Risks
Our natural gas and electric transmission and distribution operations
involve numerous risks that may result in accidents and other
operating risks and costs.
Our natural gas transmission and distribution activities include inherent
hazards and operating risks, such as leaks, explosions, outages and
mechanical problems. Our electric generation, transmission and distribution
activities include inherent hazards and operating risks such as contact, fire
and outages. These risks could result in loss of life, significant property
damage, environmental pollution, impairment of our operations and
substantial financial losses. We maintain insurance against most, but not
all, of these risks and losses. The occurrence of these events, if not fully
covered by insurance, could have a material effect on our financial
condition, results of operations and cash flows.
Other uncertainties and risks inherent in operating and maintaining Xcel
Energy's facilities include, but are not limited to:
•
•
•
•
•
•
•
•
•
•
Risks associated with facility start-up operations, such as whether the
facility will achieve projected operating performance on schedule and
otherwise as planned.
Failures in the availability, acquisition or transportation of fuel or other
necessary supplies.
The impact of unusual or adverse weather conditions and natural
disasters, including, but not limited to, tornadoes, icing events, floods
and droughts.
Performance below expected or contracted levels of output or
efficiency (e.g., performance guarantees).
Availability of replacement equipment.
Availability of adequate water resources and ability to satisfy water
intake and discharge requirements.
Inability to identify, manage properly or mitigate equipment defects.
Use of new or unproven technology.
Risks associated with dependence on a specific type of fuel or fuel
source, such as commodity price risk, availability of adequate fuel
supply and transportation and lack of available alternative fuel
sources.
Increased competition due to, among other factors, new facilities,
excess supply, shifting demand and regulatory changes.
Additionally, compliance with existing and potential new regulations related
to the operation and maintenance of our natural gas infrastructure could
result in significant costs. The PHMSA is responsible for administering the
DOT’s national regulatory program to assure the safe transportation of
natural gas, petroleum and other hazardous materials by pipelines. The
PHMSA continues to develop regulations and other approaches to risk
management to assure safety in design, construction, testing, operation,
response of natural gas pipeline
maintenance and emergency
infrastructure. We have programs in place to comply with these regulations
and systematically monitor and renew infrastructure over time, however, a
significant incident or material finding of non-compliance could result in
penalties and higher costs of operations.
Our natural gas and electric transmission and distribution operations are
dependent upon complex information technology systems and network
infrastructure, the failure of which could disrupt our normal business
operations, which could have a material adverse effect on our ability to
process transactions and provide services.
Our utility operations are subject to long-term planning and project
risks.
Most electric utility investments are planned to be used for decades.
Transmission and generation investments typically have long lead times
and are planned well in advance of in-service dates and typically subject to
long-term
resource plans. These plans are based on numerous
assumptions such as: sales growth, customer usage, commodity prices,
economic activity, costs, regulatory mechanisms, customer behavior,
available technology and public policy. Xcel Energy’s long-term resource
plan is dependent on our ability to obtain required approvals, develop
necessary technical expertise, allocate and coordinate sufficient resources
and adhere to budgets and timelines.
In addition, the long-term nature of both our planning and our asset lives
are subject to risk. The electric utility sector is undergoing significant
change (e.g. increases in energy efficiency, wider adoption of distributed
generation and shifts away from fossil fuel generation to renewable
generation). Customer adoption of these technologies and increased
energy efficiency could result in excess transmission and generation
resources, downward pressure on sales growth, and potentially stranded
costs if we are not able to fully recover costs and investments.
Changing customer expectations and technologies are requiring significant
investments in advanced grid infrastructure, which increases exposure to
technology obsolescence. Additionally, evolving stakeholder preference for
lower emissions from generation sources and end-uses, like heating, may
put pressure on our ability to recover capital investments in natural gas
generation and delivery.
The magnitude and timing of resource additions and changes in customer
demand may not coincide with evolving customer preference for generation
resources and end-uses, which introduces further uncertainty into long-term
planning. Efforts to electrify the transportation and building sectors to
reduce GHG emissions may result in higher electric demand and lower
natural gas demand over time. Additionally, multiple states may not agree
as to the appropriate resource mix, which may lead to costs to comply with
one jurisdiction that are not recoverable across all jurisdictions served by
the same assets.
We are subject to longer-term availability of inputs such as coal, natural
gas, uranium and water to cool our facilities. Lack of availability of these
resources could jeopardize long-term operations of our facilities or make
them uneconomic to operate.
15
We are subject to commodity risks and other risks associated with
energy markets and energy production.
Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear
generation.
In the event fuel costs increase, customer demand could decline and bad
debt expense may rise, which may have a material impact on our results of
operations. Despite existing fuel recovery mechanisms in most of our
states, higher fuel costs could significantly impact our results of operations
if costs are not recovered. Delays in the timing of the collection of fuel cost
recoveries could impact our cash flows and liquidity.
A significant disruption in supply could cause us to seek alternative supply
services at potentially higher costs and supply shortages may not be fully
resolved, which could cause disruptions in our ability to provide services to
our customers. Failure to provide service due to disruptions may also result
in fines, penalties or cost disallowances through the regulatory process.
Also, significantly higher energy or fuel costs relative to sales commitments
could negatively impact our cash flows and results of operations.
We also engage in wholesale sales and purchases of electric capacity,
energy and energy-related products as well as natural gas. In many
markets, emission allowances and/or RECs are also needed to comply with
various statutes and commission rulings. As a result, we are subject to
market supply and commodity price risk.
Commodity price changes can affect the value of our commodity trading
derivatives. We mark certain derivatives to estimated fair market value on a
daily basis. Settlements can vary significantly from estimated fair values
recorded and significant changes from the assumptions underlying our fair
value estimates could cause earnings variability. The management of risks
associated with hedging and trading is based, in part, on programs and
procedures which utilize historical prices and trends.
Due to the inherent uncertainty involved in price movements and potential
deviation from historical pricing, Xcel Energy is unable to fully assure that
its risk management programs and procedures would be effective to protect
against all significant adverse market deviations. In addition, Xcel Energy
cannot fully assure that its controls will be effective against all potential
risks, including, without limitation, employee misconduct. If such controls
are not effective, Xcel Energy’s results of operations, financial condition or
cash flows could be materially impacted.
Failure to attract and retain a qualified workforce could have an
adverse effect on operations.
technical employees
Specialized knowledge
for
is required of our
construction and operation of transmission, generation and distribution
assets. Xcel Energy’s business strategy is dependent on our ability to
recruit, retain and motivate employees. There is competition and a
tightening market for skilled employees. Failure to hire and adequately train
replacement employees, including the transfer of significant internal
historical knowledge and expertise to new employees or future availability
and cost of contract labor may adversely affect the ability to manage and
operate our business. Inability to attract and retain these employees could
adversely impact our results of operations, financial condition or cash flows.
Our operations use third-party contractors in addition to employees to
perform periodic and ongoing work.
We rely on third-party contractors to perform operations, maintenance and
construction work. Our contractual arrangements with these contractors
typically include performance standards, progress payments, insurance
requirements and security for performance. Poor vendor performance could
impact ongoing operations, restoration operations, our reputation and could
introduce financial risk or risks of fines.
16
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-
INPO’s
Minnesota’s nuclear operations. Compliance with
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
flows. Furthermore, non-
of operations,
compliance or the occurrence of a serious incident at other nuclear facilities
could result in increased industry regulation, which may increase NSP-
Minnesota’s compliance costs.
Financial Risks
Our profitability depends on the ability of our utility subsidiaries to
recover their costs and changes in regulation may impair the ability of
our utility subsidiaries to recover costs from their customers.
We are subject to comprehensive regulation by federal and state utility
regulatory agencies, including siting and construction of facilities, customer
service and the rates that we can charge customers.
The profitability of our utility operations is dependent on our ability to
recover the costs of providing energy and utility services and earning a
return on capital investment. Our rates are generally regulated and are
based on an analysis of the utility’s costs incurred in a test year. The utility
subsidiaries are subject to both future and historical test years depending
upon the regulatory jurisdiction. Thus, the rates a utility is allowed to charge
may or may not match its costs at any given time. Rate regulation is
premised on providing an opportunity to earn a reasonable rate of return on
invested capital.
There can also be no assurance that our regulatory commissions will judge
all the costs of our utility subsidiaries to be prudent, which could result in
disallowances, or that the regulatory process will always result in rates that
will produce full recovery.
Overall, management believes prudently incurred costs are recoverable
given the existing regulatory framework. However, there may be changes in
the regulatory environment that could impair the ability of our utility
subsidiaries to recover costs historically collected from customers, or these
subsidiaries could exceed caps on capital costs required by commissions
and result in less than full recovery.
Changes in the long-term cost-effectiveness or to the operating conditions
of our assets may result in early retirements of utility facilities. While
regulation typically provides cost recovery relief for these types of changes,
there is no assurance that regulators would allow full recovery of all
remaining costs.
In a continued low interest rate environment, there has been increased
downward pressure on allowed ROE. Conversely, higher than expected
inflation or tariffs may increase costs of construction and operations. Also,
rising fuel costs could increase the risk that our utility subsidiaries will not
be able to fully recover their fuel costs from their customers.
Adverse regulatory rulings or the imposition of additional regulations could
have an adverse impact on our results of operations and materially affect
our ability to meet our financial obligations, including debt payments and
the payment of dividends on common stock.
Any reductions in our credit ratings could increase our financing
costs and the cost of maintaining certain contractual relationships.
We cannot be assured that our current credit ratings or our subsidiaries’
ratings will remain in effect, or that a rating will not be lowered or withdrawn
by a rating agency. Significant events including disallowance of costs, lower
returns on equity, changes to equity ratios and impacts of tax policy may
impact our cash flows and credit metrics, potentially resulting in a change in
our credit ratings. In addition, our credit ratings may change as a result of
the differing methodologies or change in the methodologies used by the
various rating agencies.
Any credit ratings downgrade could lead to higher borrowing costs and
could impact our ability to access capital markets. Also, our utility
subsidiaries may enter into contracts that require posting of collateral or
settlement if credit ratings fall below investment grade.
We are subject to capital market and interest rate risks.
Utility operations require significant capital investment. As a result, we
frequently need to access capital markets. Any disruption in capital markets
could have a material impact on our ability to fund our operations. Capital
market disruption and financial market distress could prevent us from
issuing short-term commercial paper, issuing new securities or cause us to
issue securities with unfavorable terms and conditions, such as higher
interest rates. Higher interest rates on short-term borrowings with variable
interest rates could also have an adverse effect on our operating results.
The performance of capital markets impacts the value of assets held in
trusts to satisfy future obligations to decommission NSP-Minnesota’s
nuclear plants and satisfy our defined benefit pension and postretirement
benefit plan obligations. These assets are subject to market fluctuations
and yield uncertain returns, which may fall below expected returns. A
decline in the market value of these assets may increase funding
requirements. Additionally, the fair value of the debt securities held in the
nuclear decommissioning and/or pension trusts may be impacted by
changes in interest rates.
We are subject to credit risks.
Credit risk includes the risk that our customers will not pay their bills, which
may lead to a reduction in liquidity and an increase in bad debt expense.
Credit risk is comprised of numerous factors including the price of products
and services provided, the economy and unemployment rates. Credit risk
also includes the risk that counterparties that owe us money or product will
become
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.
insolvent and may breach
their obligations. Should
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.
to
We have defined benefit pension and postretirement plans that cover most
of our employees. Assumptions related
future costs, return on
investments, interest rates and other actuarial assumptions have a
significant impact on our funding requirements of these plans. Estimates
and assumptions may change. In addition, the Pension Protection Act sets
the minimum funding requirements for defined benefit pension plans.
Therefore, our funding requirements and contributions may change in the
future. Also, the payout of a significant percentage of pension plan liabilities
in a single year, due to high numbers of retirements or employees leaving,
would trigger settlement accounting and could require Xcel Energy to
recognize incremental pension expense related to unrecognized plan
losses in the year liabilities are paid. Changes in industry standards utilized
in key assumptions (e.g., mortality tables) could have a significant impact
on future obligations and benefit costs.
Increasing costs associated with health care plans may adversely
affect our results of operations.
Increasing levels of large individual health care claims and overall health
care claims could have an adverse impact on our results of operations,
financial condition or cash flows. Health care legislation could also
significantly impact our benefit programs and costs.
We must rely on cash from our subsidiaries to make dividend
payments.
Investments in our subsidiaries are our primary assets. Substantially all 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.
17
Federal tax law may significantly impact our business.
Our utility subsidiaries collect estimated federal, state and local tax
payments through their regulated rates. Changes to federal tax law may
benefit or adversely affect our earnings and customer costs. Tax
depreciable lives and the value of various tax credits or the timeliness of
their utilization may impact the economics or selection of resources. If tax
rates are increased, there could be timing delays before regulated rates
provide for recovery of such tax increases in revenues. In addition, certain
IRS tax policies, such as tax normalization, may impact our ability to
economically deliver certain types of resources relative to market prices.
Macroeconomic Risks
Economic conditions impact our business.
Xcel Energy’s operations are affected by local, national and worldwide
economic conditions, which correlates to customers/sales growth (decline).
Economic conditions may be impacted by insufficient financial sector
liquidity leading to potential increased unemployment, which may impact
customers’ ability to pay their bills, which could lead to additional bad debt
expense.
Our utility subsidiaries face competitive factors, which could have an
adverse impact on our financial condition, results of operations and cash
flows. Further, worldwide economic activity impacts the demand for basic
commodities necessary for utility infrastructure, which may inhibit our ability
to acquire sufficient supplies. We operate in a capital intensive industry and
federal trade policy could significantly impact the cost of materials we use.
There may be delays before these additional material costs can be
recovered in rates.
We face risks related to health epidemics and other outbreaks, which
may have a material effect on our financial condition, results of
operations and cash flows.
The global outbreak of COVID-19 is impacting countries, communities,
supply chains and markets. A high degree of uncertainty continues to exist
regarding
the duration and magnitude of business
restrictions, re-shut downs, if any, and the level and pace of economic
recovery. While we are implementing contingency plans, there are no
guarantees these plans will be sufficient to offset the impact of COVID-19.
the pandemic,
Although the impact of the pandemic to the 2020 results was largely
mitigated due to management’s actions, we cannot ultimately predict
whether it will have a material impact on our future liquidity, financial
condition or results of operations. Nor can we predict the impact of the virus
on the health of our employees, our supply chain or our ability to recover
higher costs associated with managing through the pandemic. The impact
of COVID-19 may exacerbate other risks discussed herein, which could
have a material effect on us. The situation is evolving and additional
impacts may arise.
Operations could be impacted by war, terrorism or other events.
Our generation plants, fuel storage facilities, transmission and distribution
facilities and information and control systems may be targets of terrorist
activities. Any disruption could impact operations or result in a decrease in
revenues and additional costs to repair and insure our assets. These
disruptions could have a material impact on our financial condition, results
of operations or cash flows.
The potential for terrorism has subjected our operations to increased risks
and could have a material effect on our business. We have already incurred
increased costs for security and capital expenditures in response to these
risks. The insurance industry has also been affected by these events and
the availability of insurance may decrease. In addition, insurance may have
higher deductibles, higher premiums and more restrictive policy terms.
A disruption of the regional electric transmission grid, interstate natural gas
pipeline infrastructure or other fuel sources, could negatively impact our
business, brand and reputation. Because our facilities are part of an
interconnected system, we face the risk of possible loss of business due to
a disruption caused by the actions of a neighboring utility.
We also face the risks of possible loss of business due to significant events
such as severe storms, severe temperature extremes, wildfires (particularly
in Colorado), widespread pandemic, generator or transmission facility
outage, pipeline rupture, railroad disruption, operator error, sudden and
significant increase or decrease in wind generation or a workforce
disruption.
In addition, major catastrophic events throughout the world may disrupt our
business. Xcel Energy participates in a global supply chain, which includes
materials and components that are globally sourced. A prolonged disruption
could result in the delay of equipment and materials that may impact our
ability to reliably serve our customers.
A major disruption could result in a significant decrease in revenues and
additional costs to repair assets, which could have a material impact on our
results of operations, financial condition or cash flows.
Xcel Energy participates in grid security and emergency response
exercises (GridEx). These efforts, led by the NERC, test and further
develop the coordination, threat sharing and interaction between utilities
and various government agencies relative to potential cyber and physical
threats against the nation’s electric grid.
A cyber incident or security breach could have a material effect on
our business.
information
We operate in an industry that requires the continued operation of
technology, control systems and network
sophisticated
infrastructure. In addition, we use our systems and infrastructure to create,
collect, use, disclose, store, dispose of and otherwise process sensitive
information, including company data, customer energy usage data, and
personal
their
dependents, contractors, shareholders and other individuals.
regarding customers, employees and
information
Xcel Energy’s generation, transmission, distribution and fuel storage
facilities, information technology systems and other infrastructure or
physical assets, as well as information processed in our systems (e.g.,
information regarding our customers, employees, operations, infrastructure
and assets) could be affected by cyber security incidents, including those
caused by human error. The utility industry has been the target of several
attacks on operational systems and has seen an increased volume and
international activist
sophistication of cyber security
organizations, Nation States and individuals.
incidents
from
Cyber security incidents could harm our businesses by limiting our
transmitting and distributing capabilities, delaying our
generating,
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.
18
Xcel Energy’s generation, transmission systems and natural gas pipelines
are part of an interconnected system. Therefore, a disruption caused by the
impact of a cyber security incident of the regional electric transmission grid,
natural gas pipeline infrastructure or other fuel sources of our third-party
service providers’ operations, could also negatively impact our business.
Our supply chain for procurement of digital equipment and services may
expose software or hardware to these risks and could result in a breach or
significant costs of remediation. We are unable to quantify the potential
impact of cyber security threats or subsequent related actions. Cyber
security incidents and regulatory action could result in a material decrease
in revenues and may cause significant additional costs (e.g., penalties,
third-party claims, repairs, insurance or compliance) and potentially disrupt
our supply and markets for natural gas, oil and other fuels.
We maintain security measures to protect our information technology and
control systems, network infrastructure and other assets. However, these
assets and the information they process may be vulnerable to cyber
security incidents, including asset failure or unauthorized access to assets
or information.
A failure or breach of our technology systems or those of our third-party
service providers could disrupt critical business functions and may
negatively impact our business, our brand, and our reputation. The cyber
security threat is dynamic and evolves continually, and our efforts to
prioritize network protection may not be effective given the constant
changes to threat vulnerability.
Our operating results may fluctuate on a seasonal and quarterly basis
and can be adversely affected by milder weather.
Our electric and natural gas utility businesses are seasonal and weather
patterns can have a material impact on our operating performance.
Demand for electricity is often greater in the summer and winter months
associated with cooling and heating. Because natural gas is heavily used
for residential and commercial heating, the demand depends heavily upon
weather patterns. A significant amount of natural gas revenues are
recognized in the first and fourth quarters related to the heating season.
Accordingly, our operations have historically generated less revenues and
income when weather conditions are milder in the winter and cooler in the
summer. Unusually mild winters and summers could have an adverse
effect on our financial condition, results of operations or cash flows.
Public Policy Risks
We may be subject to legislative and regulatory responses to climate
change, with which compliance could be difficult and costly.
Legislative and regulatory responses related to climate change may create
financial risk as our facilities may be subject to additional regulation at
either the state or federal level in the future. International agreements could
additionally lead to future federal or state regulations.
In 2015, the United Nations Framework Convention on Climate Change
reached consensus among 190 nations on an agreement (the Paris
Agreement) that establishes a framework for GHG mitigation actions by all
countries, with a goal of holding the increase in global average temperature
to below 2º Celsius above pre-industrial levels and an aspiration to limit the
increase to 1.5º Celsius. The Biden Administration will establish a new
nationally determined contribution for the United States. The Paris
Agreement could result in future additional GHG reductions in the United
States. In addition, the Biden Administration has announced plans to
implement new climate change programs, including potential regulation of
GHG emissions targeting the utility industry.
The Biden Administration has also announced a one year suspension of
new oil and natural gas drilling on federal lands to allow for a review of oil
and gas leasing regulations. The form of these regulations is uncertain, but,
depending on the requirements imposed in the short and long term, they
could impose substantial costs on our oil and gas customers or result in
substantial increases to the cost of fuel we use in our electricity and gas
businesses.
Many states and localities continue to pursue their own climate policies.
The steps Xcel Energy has taken to date to reduce GHG emissions,
including energy efficiency measures, adding renewable generation or
retiring or converting coal plants to natural gas, occurred under state-
endorsed resource plans, renewable energy standards and other state
policies.
We may be subject to climate change lawsuits. An adverse outcome could
require substantial capital expenditures and possibly require payment of
substantial penalties or damages. Defense costs associated with such
litigation can also be significant and could affect results of operations,
financial condition or cash flows if such costs are not recovered through
regulated rates.
If our regulators do not allow us to recover all or a part of the cost of capital
investment or the O&M costs incurred to comply with the mandates, it could
have a material effect on our results of operations, financial condition or
cash flows.
Increased risks of regulatory penalties could negatively impact our
business.
The Energy Act increased civil penalty authority for violation of FERC
statutes, rules and orders. The FERC can impose penalties of up to $1.3
million per violation per day, particularly as it relates to energy trading
activities for both electricity and natural gas. In addition, NERC electric
reliability standards and critical infrastructure protection requirements are
mandatory and subject to potential financial penalties. Also, the PHMSA,
Occupational Safety and Health Administration and other federal agencies
have the authority to assess penalties.
In the event of serious incidents, these agencies may pursue penalties. In
addition, certain states have the authority to impose substantial penalties. If
a serious reliability, cyber or safety incident did occur, it could have a
material effect on our results of operations, financial condition or cash
flows.
Environmental Risks
We are subject to environmental laws and regulations, with which
compliance could be difficult and costly.
We are subject to environmental laws and regulations that affect many
aspects of our operations,
including air emissions, water quality,
wastewater discharges and the generation, transport and disposal of solid
wastes and hazardous substances. Laws and regulations require us to
obtain permits, licenses, and approvals and to comply with a variety of
environmental requirements.
Environmental laws and regulations can also require us to restrict or limit
the output of facilities or the use of certain fuels, shift generation to lower-
emitting facilities, install pollution control equipment, clean up spills and
other contamination and correct environmental hazards. Failure to meet
requirements of environmental mandates may result in fines or penalties.
We may be required to pay all or a portion of the cost to remediate sites
where our past activities, or the activities of other parties, caused
environmental contamination.
19
Changes in environmental policies and regulations or regulatory decisions
may result in early retirements of our generation facilities. While regulation
typically provides relief for these types of changes, there is no assurance
that regulators would allow full recovery of all remaining costs.
We are subject to mandates to provide customers with clean energy,
renewable energy and energy conservation offerings. It could have a
material effect on our results of operations, financial condition or cash flows
if our regulators do not allow us to recover the cost of capital investment or
O&M costs incurred to comply with the requirements.
In addition, existing environmental laws or regulations may be revised and
new laws or regulations may be adopted. We may also incur additional
unanticipated obligations or liabilities under existing environmental laws
and regulations.
We are subject to physical and financial risks associated with climate
change and other weather, natural disaster and resource depletion
impacts.
Climate change can create physical and financial risk. Physical risks
include changes in weather conditions and extreme weather events. Our
customers’ energy needs vary with weather. To the extent weather
conditions are affected by climate change, customers’ energy use could
increase or decrease. Increased energy use due to weather changes may
require us to invest in generating assets, transmission and infrastructure.
Decreased energy use due to weather changes may result in decreased
revenues.
Climate change may impact the economy, which could impact our sales
and revenues. The price of energy has an impact on the economic health of
our communities. The cost of additional regulatory requirements, such as
regulation of GHG, could impact the availability of goods and prices
charged by our suppliers which would normally be borne by consumers
through higher prices for energy and purchased goods. To the extent
financial markets view climate change and emissions of GHGs as a
financial risk, this could negatively affect our ability to access capital
markets or cause us to receive less than ideal terms and conditions.
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. We may not
recover all costs related to mitigating these physical and financial risks.
ITEM 1B — UNRESOLVED STAFF COMMENTS
None.
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
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:
Fuel
Coal
Coal
Coal
Coal
Nuclear
Nuclear
Nuclear
Installed
MW (a)
1968
511
1976
1977
1987
1971
1973
1974
680
682
517
(b)
617
521
519
Wood/Refuse
Various
(c)
36
Angus Anson-Sioux Falls, SD, 3 Units
Natural Gas
1994 - 2005
327
Black Dog-Burnsville, MN, 3 Units
Natural Gas
1987 - 2018
494
Blue Lake-Shakopee, MN, 6 Units
Natural Gas
1974 - 2005
447
High Bridge-St. Paul, MN, 3 Units
Natural Gas
Inver Hills-Inver Grove Heights, MN, 6 Units
Natural Gas
Riverside-Minneapolis, MN, 3 Units
Natural Gas
2008
1972
2009
Various locations, 7 Units
Natural Gas
Various
530
252
454
10
Wind:
Border-Rolette County, ND, 75 Units
Courtenay Wind-Stutsman County, ND, 100
Units
Foxtail-Dickey County, ND, 75 Units
Grand Meadow-Mower County, MN, 67 Units
Lake Benton-Pipestone County, MN, 44 Units
Nobles-Nobles County, MN, 134 Units
Pleasant Valley-Mower County, MN, 100
Units
Blazing Star 1-Lincoln County, MN, 100 Units
Crowned Ridge 2-Grant County, SD, 88 Units
Community Wind North-Lincoln County, MN,
12 Units
Jeffers-Cottonwood County, MN, 20 Units
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
2015
148
2016
2019
2008
2019
2010
2015
2020
2020
2020
2020
Total
190
150
99
99
197
196
200
192
26
43
8,137
(d)
(d)
(d)
(d)
(d)
(d)
(d)
(d)
(d)
(d)
(d)
Summer 2020 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.
(a)
(b)
(c)
(d)
(e)
(f)
20
Fuel
Installed
MW (a)
Wind:
NSP-Wisconsin
Station, Location and Unit
Steam:
Fuel
Installed
MW (a)
Bay Front-Ashland, WI, 2 Units
Wood/Natural Gas
1948 - 1956
French Island-La Crosse, WI, 2 Units
Combustion Turbine:
Wood/Refuse
1940 - 1948
41
16
(b)
French Island-La Crosse, WI, 2 Units
Oil
Wheaton-Eau Claire, WI, 5 Units
Natural Gas/Oil
1974
1973
122
234
Hydro:
Various locations, 63 Units
Hydro
(a)
(b)
Summer 2020 net dependable capacity.
Refuse-derived fuel is made from municipal solid waste.
Various
Total
135
548
PSCo
Station, Location and Unit
Steam:
Comanche-Pueblo, CO (b)
Unit 1
Unit 2
Unit 3
Craig-Craig, CO, 2 Units (d)
Hayden-Hayden, CO, 2 Units (h)
Pawnee-Brush, CO, 1 Unit
Coal
Coal
Coal
Coal
Coal
Coal
1973
1975
2010
1979 - 1980
1965 - 1976
1981
1968
2003
2015
(c)
(e)
(f)
325
335
500
82
233
505
310
264
576
968
580
251
Cherokee-Denver, CO, 1 Unit
Natural Gas
Combustion Turbine:
Blue Spruce-Aurora, CO, 2 Units
Cherokee-Denver, CO, 3 Units
Natural Gas
Natural Gas
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
Hydro
Wind
Wind
1967
Various
210
25
2018
2020
Total
(g)
(g)
582
477
6,223
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
Summer 2020 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).
Hayden Unit 1 and 2 are expected to be retired in 2028 and 2027, respectively.
SPS
Station, Location and Unit
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:
Fuel
Installed
MW (a)
Natural Gas
1957 - 1965
225
Coal
1976 - 1980
1,018
Natural Gas
1971 - 1974
486
Natural Gas
1967
112
Natural Gas
1960 - 1968
457
Natural Gas
1952 - 1964
298
Coal
1982 - 1985
1,067
Cunningham-Hobbs, NM, 2 Units
Natural Gas
1997
207
Jones-Lubbock, TX, 2 Units
Maddox-Hobbs, NM, 1 Unit
Natural Gas
2011 - 2013
334
Natural Gas
1963 - 1976
61
Hale-Plainview, TX, 239 Units
Sagamore-Dora, NM, 240 Units
Wind
Wind
2019
2020
Total
(c)
(c)
460
507
5,232
(a)
(b)
Summer 2020 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 expected to be retired in 2032.
Electric utility overhead and underground transmission and distribution lines
(measured in conductor miles) at Dec. 31, 2020:
Conductor Miles
NSP-Minnesota
NSP-Wisconsin
PSCo
SPS
Transmission
500 KV
345 KV
230 KV
161 KV
138 KV
115 KV
Less than 115 KV
Total Transmission
Distribution
Less than 115 KV
2,918
13,151
2,301
674
—
8,060
6,556
33,660
—
3,337
—
1,823
—
1,822
5,306
—
5,389
12,131
—
92
5,092
1,682
12,288
24,386
—
11,019
9,795
—
—
14,830
4,375
40,019
80,508
27,611
78,483
21,984
Total
114,168
39,899
102,869
62,003
Electric utility transmission and distribution substations at Dec. 31, 2020:
NSP-Minnesota
NSP-Wisconsin
PSCo
SPS
Quantity
352
204
236
457
Natural gas utility mains at Dec. 31, 2020:
Miles
NSP-Minnesota
NSP-Wisconsin
PSCo
SPS
WGI
Transmission
Distribution
80
10,629
3
2,058
2,492
22,815
20
—
11
—
21
ITEM 3 — LEGAL PROCEEDINGS
Xcel Energy is involved in various litigation matters in the ordinary course of
business. The assessment of whether a loss is probable or is a reasonable
possibility, and whether the loss or a range of loss is estimable, often
involves a series of complex judgments about future events. Management
maintains accruals for losses probable of being incurred and subject to
reasonable estimation.Management is sometimes unable to estimate an
amount or range of a reasonably possible loss in certain situations,
including but not limited to when (1) the damages sought are indeterminate,
(2) the proceedings are in the early stages, or (3) the matters involve novel
or unsettled legal theories. In such cases, there is considerable uncertainty
regarding the timing or ultimate resolution of such matters, including a
possible eventual loss.
For current proceedings not specifically reported herein, management does
not anticipate that the ultimate liabilities, if any, would have a material effect
on Xcel Energy’s financial statements. Unless otherwise required by GAAP,
legal fees are expensed as incurred.
See Note 12 to the consolidated financial statements, Item 1 and Item 7 for
further information.
ITEM 4 — MINE SAFETY DISCLOSURES
None.
PART II
ITEM 5 — MARKET FOR REGISTRANT’S COMMON EQUITY,
RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES.
Stock Data
Xcel Energy Inc.’s common stock is listed on the Nasdaq Global Select
Market (Nasdaq). The trading symbol is XEL. The number of common
stockholders of record as of Feb. 12, 2021 was approximately 52,689.
ITEM 6 — SELECTED FINANCIAL DATA
The following compares our cumulative TSR on common stock with the
cumulative TSR of the EEI Investor-Owned Electrics Index and the S&P
500 Composite Stock Price Index over the last five years.
The EEI Investor-Owned Electrics Index (market capitalization-weighted)
included 39 companies at year-end and is a broad measure of industry
performance.
Comparison of Five Year Cumulative Total Return*
* $100 invested on Dec. 31, 2015 in stock or index — including
reinvestment of dividends. Fiscal years ended Dec. 31.
Purchases of Equity Securities by Issuer and Affiliated Purchasers
For the quarter ended Dec. 31, 2020, no equity securities that are
registered by Xcel Energy Inc. pursuant to Section 12 of the Securities
Exchange Act of 1934 were purchased by or on behalf of us or any of our
affiliated purchasers.
Selected financial data for Xcel Energy related to the five most recent years ended Dec. 31:
(Millions of Dollars, Millions of Shares, Except Per Share Data)
2020
2019
2018
2017
2016
Operating revenues
Operating expenses (a)
Net income
Earnings available to common shareholders
Diluted earnings per common share
Financial information
Dividends declared per common share
Total assets
Long-term debt (b)
$
11,526 $
11,529 $
11,537 $
11,404 $
9,410
1,473
1,473
2.79
1.72
53,957
19,645
9,425
1,372
1,372
2.64
1.62
50,448
17,407
9,572
1,261
1,261
2.47
1.52
45,987
15,803
9,181
1,148
1,148
2.25
1.44
43,030
14,520
11,107
8,867
1,123
1,123
2.21
1.36
41,155
14,195
(a)
(b)
As a result of adopting ASU No. 2017-07 (Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715), $33 million and $26 million of
pension costs were retrospectively reclassified from O&M expenses to other income, net on the consolidated statements of income for the years ended Dec. 31, 2017 and Dec. 31, 2016,
respectively.
As a result of adopting Leases, Topic 842, finance lease obligations of $77 million are included in other noncurrent liabilities on the consolidated balance sheet at Dec. 31, 2019. These
obligations were included in long-term debt prior to 2019.
22
Xcel Energy Inc.EEI ElectricsS&P 500201520162017201820192020$80$100$120$140$160$180$200$220
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, electric margin, natural gas margin, ongoing
earnings and ongoing diluted EPS. Generally, a non-GAAP financial
measure is a measure of a company’s financial performance, financial
position or cash flows that excludes (or includes) amounts that are adjusted
from measures calculated and presented in accordance with GAAP.
Xcel Energy’s management uses non-GAAP measures for financial
planning and analysis, for reporting of results to the Board of Directors, in
determining performance-based compensation, and communicating its
earnings outlook to analysts and investors. Non-GAAP financial measures
are intended to supplement investors’ understanding of our performance
and should not be considered alternatives for financial measures presented
in accordance with GAAP. These measures are discussed in more detail
below and may not be comparable to other companies’ similarly titled non-
GAAP financial measures.
Ongoing ROE
Ongoing ROE is calculated by dividing the net income or loss of Xcel
Energy or each subsidiary, adjusted for certain nonrecurring items, by each
entity’s average stockholder’s equity. We use these non-GAAP financial
measures to evaluate and provide details of earnings results.
Electric and Natural Gas Margins
Electric margin is presented as electric revenues less electric fuel and
purchased power expenses. Natural gas margin is presented as natural
gas revenues less the cost of natural gas sold and transported. Expenses
incurred for electric fuel and purchased power and the cost of natural gas
are generally recovered through various regulatory recovery mechanisms.
As a result, changes in these expenses are generally offset in operating
revenues. Management believes electric and natural gas margins provide
the most meaningful basis for evaluating our operations because they
exclude the revenue impact of fluctuations in these expenses.
These margins can be reconciled to operating income, a GAAP measure,
by including other operating revenues, cost of sales-other, O&M expenses,
conservation and DSM expenses, depreciation and amortization and taxes
(other than income taxes).
Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing
Diluted EPS)
GAAP diluted EPS reflects the potential dilution that could occur if
securities or other agreements to issue common stock (i.e., common stock
equivalents) were settled. The weighted average number of potentially
dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS
is calculated using the treasury stock method. Ongoing earnings reflect
adjustments to GAAP earnings (net income) for certain items. Ongoing
diluted EPS is calculated by dividing the net income or loss of each
subsidiary, adjusted for certain items, by the weighted average fully diluted
Xcel Energy Inc. common shares outstanding for the period. Ongoing
diluted EPS for each subsidiary is calculated by dividing the net income or
loss of such subsidiary, adjusted for certain items, by the weighted average
fully diluted Xcel Energy Inc. common shares outstanding for the period.
We use these non-GAAP financial measures to evaluate and provide
details of Xcel Energy’s core earnings and underlying performance. We
believe these measurements are useful to investors to evaluate the actual
and projected financial performance and contribution of our subsidiaries.
For the years ended Dec. 31, 2020 and 2019, there were no such
adjustments to GAAP earnings and therefore GAAP earnings equal
ongoing earnings.
Results of Operations
Diluted EPS for Xcel Energy at Dec. 31:
Diluted Earnings (Loss) Per Share
NSP-Minnesota
PSCo
SPS
NSP-Wisconsin
Equity earnings of unconsolidated subsidiaries
Regulated utility (a)
Xcel Energy Inc. and Other
Total (a)
(a)
Amounts may not add due to rounding.
2020
GAAP and
Ongoing Diluted
EPS
2019
GAAP and
Ongoing Diluted
EPS
$
$
$
1.12
1.11
0.56
0.20
0.05
3.04
(0.25)
2.79
$
1.04
1.11
0.51
0.15
0.05
2.86
(0.22)
2.64
that ongoing earnings reflects
Xcel Energy’s management believes
management’s performance in operating Xcel Energy and provides a
meaningful representation of the performance of Xcel Energy’s core
business. In addition, Xcel Energy’s management uses ongoing earnings
internally for financial planning and analysis, reporting results to the Board
of Directors and when communicating its earnings outlook to analysts and
investors.
2020 Comparison with 2019
Xcel Energy — GAAP and ongoing earnings increased $0.15 per share,
primarily reflecting higher electric margin (largely due to regulatory
outcomes which recover capital investment), higher AFUDC and lower
O&M expenses, which offset increased depreciation, interest expense and
declining sales primarily due to the impacts of COVID-19.
NSP-Minnesota — Earnings increased $0.08 per share for 2020, reflecting
higher electric margin (riders, wholesale transmission revenue and a sales
true-up mechanism, which recovers lower sales due to COVID-19) and
lower O&M expenses, partially offset by increased depreciation and lower
natural gas margin.
PSCo — Earnings were flat for 2020, reflecting higher electric margin
(wholesale transmission revenue and regulatory outcomes offset lower
sales due to COVID-19), increased AFUDC and higher natural gas margin,
offset by additional depreciation and taxes (other than income taxes).
SPS — Earnings increased $0.05 per share for 2020, reflecting higher
electric margin (wholesale transmission revenue and regulatory outcomes
offset lower sales due to COVID-19) and lower O&M expenses, partially
offset by increased depreciation, interest expense and taxes (other than
income taxes).
NSP-Wisconsin — Earnings increased $0.05 per share for 2020, reflecting
higher electric margin (regulatory outcomes offset lower sales due to
COVID-19) and lower O&M expenses, partially offset by increased
depreciation and lower natural gas margin.
Xcel Energy Inc. and Other — Primarily includes financing costs at the
holding company.
23
Changes in Diluted EPS
Components significantly contributing to changes in EPS:
2020 vs. 2019
Diluted Earnings (Loss) Per Share
GAAP and ongoing diluted EPS - 2019
Components of change — 2020 vs. 2019
Higher electric margins (a)
Lower ETR (b)
Higher AFUDC
Changes in O&M
Higher depreciation and amortization
Higher interest
Higher taxes (other than income taxes)
Changes in natural gas margins
Other (net)
GAAP and ongoing diluted EPS — 2020
$
Dec. 31
$
2.64
0.32
0.22
0.08
0.02
(0.26)
(0.10)
(0.06)
(0.01)
(0.06)
2.79
Change in electric margin was negatively impacted by reductions in sales and demand
due to COVID-19 and is detailed below. Sales decline excludes weather impact, net of
decoupling/sales true-up and reduction in demand revenue is net of sales true-up.
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:
Diluted Earnings (Loss) Per Share
Electric margin (excluding reductions in sales and demand)
Reductions in sales and demand
Higher electric margins
Twelve Months
Ended Dec. 31
$
$
0.41
(0.09)
0.32
HDD
CDD
THI
2020 vs.
Normal
2019 vs.
Normal
2020 vs. 2019
(3.1) %
22.2
6.3
10.4 %
5.4
(8.8)
(12.0) %
24.8
18.2
Includes PTCs and tax reform regulatory amounts, which are primarily offset in electric
margin.
ROE for Xcel Energy and its utility subsidiaries:
Weather — Estimated impact of temperature variations on EPS compared
with normal weather conditions:
(a)
(b)
ROE
NSP-Minnesota
PSCo
SPS
NSP-Wisconsin
Operating Companies
Xcel Energy
2020
2019
GAAP and Ongoing ROE
GAAP and Ongoing ROE
Retail electric
9.20 %
8.06
9.54
10.52
8.87
10.59
9.31 %
Decoupling and sales true-up
Total (excluding decoupling)
Firm natural gas
8.69
9.71
8.27
9.06
10.78
Statement of Income Analysis
The following summarizes the items that affected the individual revenue
and expense items reported in the consolidated statements of income.
Estimated Impact of Temperature Changes on Regulated Earnings —
Unusually hot summers or cold winters increase electric and natural gas
sales, while mild weather reduces electric and natural gas sales. The
estimated impact of weather on earnings is based on the number of
customers, temperature variances, the amount of natural gas or electricity
historically used per degree of temperature and excludes any incremental
related operating expenses that could result due to storm activity or
vegetation management requirements. As a result, weather deviations from
normal levels can affect Xcel Energy’s financial performance to the extent
there is not a decoupling or sales true-up mechanism in the state.
2020 vs.
Normal
2019 vs.
Normal
2020 vs.
2019
$
0.090
$
0.040
$
0.050
(0.041)
—
(0.041)
$
0.049
$
0.040
$
0.009
(0.011)
0.027
(0.038)
Total (adjusted for recovery from decoupling)
$
0.038
$
0.067
$
(0.029)
Sales — Sales growth (decline) for actual and weather-normalized sales:
2020 vs. 2019
PSCo
NSP-
Minnesota
SPS
NSP-
Wisconsin
Xcel
Energy
Actual (a)
Electric
residential
Electric C&I
Total retail
electric sales
Firm natural gas
sales
5.8 %
(4.1)
(1.1)
(6.8)
PSCo
Weather-normalized (a)
Electric
residential
Electric C&I
3.8 %
(4.5)
Total retail
electric sales
Firm natural gas
sales
(1.9)
0.5
5.0 %
(7.0)
(3.4)
(8.3)
3.6 %
(3.3)
(2.2)
n/a
2020 vs. 2019
2.4 %
(4.6)
(2.6)
(6.4)
4.9 %
(5.0)
(2.3)
(7.2)
NSP-
Minnesota
SPS
NSP-
Wisconsin
Xcel
Energy
3.7 %
(7.0)
(3.8)
1.9
1.6 %
(3.4)
(2.6)
n/a
2.6 %
(4.8)
(2.7)
5.1
3.3 %
(5.2)
(2.8)
1.3
24
PSCo
Weather-normalized (a)
Electric
residential
Electric C&I
3.6 %
(4.8)
Total retail
electric sales
Firm natural gas
sales
(2.2)
0.1
2020 vs. 2019 (Leap Year Adjusted)
NSP-
Wisconsin
NSP-
Minnesota
SPS
Xcel
Energy
3.4 %
(7.3)
(4.1)
1.4
1.3 %
(3.7)
(2.9)
n/a
2.3 %
(5.0)
(2.9)
4.6
3.1 %
(5.4)
(3.1)
0.7
(a) Higher residential sales and lower C&I sales were primarily attributable to COVID-19. The
increase in residential sales was partially driven by more customers working from home.
Weather-normalized and leap-year adjusted electric sales growth
(decline) — year-to-date (excluding leap day)
•
•
•
•
PSCo — Residential sales rose based on an increased number of
customers and higher use per customer. The decline in C&I sales was
primarily due to COVID-19, particularly within the manufacturing and
service industries, partially offset by an increase in the energy sector.
NSP-Minnesota — Residential sales rose based on an increased
number of customers and higher use per customer. The decline in C&I
sales was primarily due to COVID-19, particularly within the energy,
manufacturing and services sectors.
SPS — Residential sales rose based on an increased number of
customers and higher use per customer. The decline in C&I sales was
primarily due to COVID-19, particularly within the energy and
manufacturing sectors.
NSP-Wisconsin — Residential sales rose based on an increased
number of customers and higher use per customer. The decline in C&I
sales was primarily due to COVID-19, particularly within the energy
and manufacturing sectors.
Electric revenues and margin:
(Millions of Dollars)
Electric revenues
Electric fuel and purchased power
Electric margin
Changes in Electric Margin
2020
2019
$
$
9,802
$
(3,512)
6,290
$
9,575
(3,510)
6,065
(Millions of Dollars)
Regulatory rate outcomes (Colorado, Wisconsin, Texas
and New Mexico) (a)
Non-fuel riders
Wholesale transmission revenue (net)
MEC purchased capacity costs
Conservation incentive
2019 tax reform customer credits - Wisconsin (offset in income tax)
Estimated impact of weather (net of decoupling / sales true-up)
PTCs flowed back to customers (offset by lower ETR)
Sales and demand (b)
Other (net)
Total increase in electric margin
$
2020 vs. 2019
$
209
74
59
35
13
7
7
(119)
(66)
6
225
(a)
(b)
Includes approximately $70 million of revenue and margin due to the Texas rate case
outcome, which is largely offset by recognition of previously deferred costs.
Sales excludes weather impact, net of decoupling/sales true-up, and demand revenue is
net of sales true-up.
Natural Gas Margin
Natural gas expense varies with changing sales and cost of natural gas.
However, fluctuations in the cost of natural gas has minimal impact on
margin due to cost recovery mechanisms.
Natural gas revenues and margin:
Weather-normalized and leap-year adjusted natural gas sales growth
(decline) — year-to-date (excluding leap day)
(Millions of Dollars)
Natural gas revenues
2020
2019
$
$
1,636
$
(689)
947
$
1,868
(918)
950
•
Higher natural gas sales reflect an increase in the number of
customers combined with higher residential customer use, partially
offset by lower C&I customer use.
Electric Margin
Electric revenues and fuel and purchased power expenses are impacted by
fluctuations in the price of natural gas, coal and uranium. However, these
fuel recovery
fluctuations have minimal
mechanisms. In addition, electric customers receive a credit for PTCs
generated, which reduce electric revenue and margin (offset by lower tax
expense).
impact on margin due
to
2020 vs. 2019
$
$
(28)
16
8
2
(1)
(3)
Cost of natural gas sold and transported
Natural gas margin
Changes in Natural Gas Margin
(Millions of Dollars)
Estimated impact of weather
Regulatory rate outcomes (Colorado and Wisconsin)
Infrastructure and integrity riders
Retail sales growth
Other (net)
Total decrease in natural gas margin
25
Non-Fuel Operating Expenses and Other Items
Xcel Energy Inc. and Other Results
Net income and diluted EPS contributions of Xcel Energy Inc. and its
nonregulated businesses:
O&M Expenses — O&M expenses decreased $14 million, or 0.6%, for
2020, largely reflecting management actions to reduce costs to offset the
impact of lower sales from COVID-19.
Significant changes are as follows:
(Millions of Dollars)
Distribution
Generation
Transmission
Minnesota payment plan credit program
Information technology
Employee benefits
Texas rate case deferral
Other (net)
Total decrease in O&M expenses
2020 vs. 2019
$
$
(47)
(12)
(10)
18
14
12
8
3
(14)
•
•
•
•
•
•
Distribution declined due to cost mitigation/continuous improvement
efforts and timing of maintenance, partially offset by increased storm
impacts.
Generation was lower from timing of maintenance and overhauls at
power plants and cost mitigation/continuous improvement efforts,
partially offset by an increase in maintenance expenses from wind
expansion.
Transmission declined due to cost mitigation/continuous improvement
initiatives.
Minnesota payment plan credit program represents a commitment to
fund customer programs as agreed to in the NSP-Minnesota rate case
stay-out.
Information technology costs increased due to higher spending on
network and other infrastructure costs.
Employee benefits increased due primarily to postretirement costs and
lower deferred
other
compensation expense.
long-term benefits, partially offset by
Depreciation and Amortization — Depreciation and amortization
increased $183 million, or 10.4%, year-to-date. The increase was primarily
driven by the Hale, Cheyenne Ridge, Foxtail, Blazing Star I, Lake Benton,
Sagamore, Crowned Ridge, Community Wind North and Jeffers wind
facilities going into service, as well as normal system expansion. In
addition, new depreciation rates were implemented in Colorado, New
Mexico and Texas in 2020, increasing expense.
Taxes (Other than Income Taxes) — Taxes (other than income taxes)
increased $43 million, or 7.6%, year-to-date. The increase was primarily
due to higher property taxes in Colorado and Texas (net of deferred
amounts).
Other Income (Expense) — Other income (expense) decreased $22
million year-to-date. The decrease was largely due to the performance of
rabbi trust investments, primarily offset in O&M expenses.
AFUDC, Equity and Debt — AFUDC increased $43 million year-to-date.
The increase was primarily due to various wind projects under construction.
Interest Charges — Interest charges increased $67 million, or 8.7%, year-
to-date. The increase was largely due to higher debt levels to fund capital
investments, partially offset by lower long-term and short-term interest
rates.
Income Taxes — Income taxes decreased $134 million for 2020. The
decrease was primarily driven by an increase in wind PTCs and an
increase in plant-related regulatory differences.
26
Xcel Energy Inc. financing costs
MEC (a)
Eloigne (b)
Xcel Energy Inc. taxes and other results
Total Xcel Energy Inc. and other costs
Xcel Energy Inc. financing costs
MEC (a)
Eloigne (b)
Xcel Energy Inc. taxes and other results
Contribution (Millions of Dollars)
2020
2019
$
$
(147) $
(128)
15
1
(2)
—
1
12
(133) $
(115)
Contribution (Diluted Earnings
(Loss) Per Share)
2020
2019
$
(0.28) $
(0.21)
0.03
—
—
—
—
(0.01)
(0.22)
Total Xcel Energy Inc. and other costs
$
(0.25) $
MEC was sold in the third quarter of 2020.
(a)
(b)
Amounts include gains or losses associated with sales of properties held by Eloigne.
Xcel Energy Inc.’s results include interest charges, which are incurred at
Xcel Energy Inc. and are not directly assigned to individual subsidiaries.
2019 Comparison with 2018
A discussion of changes in Xcel Energy’s results of operations, cash flows
and liquidity and capital resources from the year ended Dec. 31, 2018 to
Dec. 31, 2019 can be found in Part II, “Item 7, Management’s Discussion
and Analysis of Financial Condition and Results of Operations” of our
Annual Report on Form 10-K for the fiscal year 2019, which was filed with
the SEC on Feb. 21, 2020. However, such discussion is not incorporated
by reference into, and does not constitute a part of, this Annual Report on
Form 10-K.
Public Utility Regulation
The FERC and various state and local regulatory commissions regulate
Xcel Energy Inc.’s utility subsidiaries and WGI. Xcel Energy is subject to
rate regulation by state utility regulatory agencies, which have jurisdiction
with respect to the rates of electric and natural gas distribution companies
in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado,
New Mexico, and Texas.
Rates are designed to recover plant investment, operating costs and an
allowed return on investment. Our utility subsidiaries request changes in
rates for utility services through filings with governing commissions.
Changes in operating costs can affect Xcel Energy’s financial results,
depending on the timing of rate case filings and implementation of final
rates. Other factors affecting rate filings are new investments, sales,
conservation and DSM efforts, and the cost of capital.
In addition, the regulatory commissions authorize the ROE, capital structure
and depreciation rates in rate proceedings. Decisions by these regulators
can significantly impact Xcel Energy’s results of operations.
See Rate Matters within Note 12 to the consolidated financial statements
for further information.
NSP-Minnesota
Recovery Mechanisms
Retail rates, services and other aspects of electric and natural
gas operations.
Infrastructure Rider
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Regulatory Body / RTO
Additional Information
Retail rates, services, security issuances, property transfers,
mergers, disposition of assets, affiliate transactions, and other
aspects of electric and natural gas operations.
Reviews and approves IRPs for meeting future energy needs.
MPUC
NDPSC
SDPUC
FERC
MISO
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.
Regulatory authority over generation and transmission facilities,
along with the siting and routing of new generation and
transmission facilities in North Dakota.
Pipeline safety compliance.
Retail rates, services and other aspects of electric operations.
Regulatory authority over generation and transmission facilities,
along with the siting and routing of new generation and
transmission facilities in South Dakota.
Pipeline safety compliance.
electric
operations,
Wholesale
licensing,
accounting practices, wholesale sales for resale, transmission of
electricity
interstate commerce, compliance with NERC
electric reliability standards, asset transfers and mergers, and
natural gas transactions in interstate commerce.
hydroelectric
in
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.
Mechanism
CIP Rider (a)
EIR
RDF
RES
RER
SEP
TCR
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.
Recovers costs related to various energy policies approved by the
Minnesota legislature.
for
investments
Recovers costs
distribution grid modernization.
Recovers costs for investments in generation and incremental
property taxes in South Dakota.
transmission and
in electric
FCA (b)
PGA
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 2021, NSP-Minnesota filed the 2020 sales true-up
compliance report, resulting in a total surcharge of $119 million. An
MPUC ruling is anticipated in the second quarter of 2021. The 2021
sales true-up mechanism, extended under the 2020 stay-out petition,
will operate similarly to the currently approved sales true-up and
apply to all customer classes. Under the stay-out petition, 2021 NSP-
Minnesota jurisdictional earnings will be capped at 9.06% ROE. Any
excess earnings will be refunded to customers.
(a)
(b)
Minnesota state law requires NSP-Minnesota to spend 2% of its state electric revenues
and 0.5% of its state natural gas revenues on CIP. These costs are recovered through
an annual cost-recovery mechanism.
The MPUC changed the FCA process in Minnesota (effective in 2020). Each month,
utilities collect amounts equal to baseline cost of energy set at the start of the plan year
(base would be reset annually). Monthly variations to baseline costs are tracked and
netted over a 12-month period. Utilities issue refunds above the baseline costs and can
seek recovery of any overage.
Pending and Recently Concluded Regulatory Proceedings
Proceeding
Amount
(in millions)
2020 North Dakota Electric Rate Case
2020 TCR Electric Rider
2020 GUIC Natural Gas Rider
2021 GUIC Natural Gas Rider
2020 RES Electric Rider
2021 RES Electric Rider
$22
82
21
27
102
189
Filing
Date
November
2020
November
2019
November
2019
October
2020
November
2019
November
2020
Approval
Pending
Pending
Pending
Pending
Pending
Pending
27
Additional Information:
2020 Minnesota Electric Rate Case and Stay-Out Alternative — In
November 2020, NSP-Minnesota filed an electric rate case seeking a $597
million revenue increase over three years with the MPUC. The rate case is
based on a requested ROE of 10.2% and a 52.5% equity ratio. NSP-
Minnesota also filed a stay-out alternative in which it would withdraw its rate
case filing.
In December 2020, the MPUC verbally approved the stay-out alternative
petition, which includes the extension of the sales, capital and property tax
true-up mechanisms and delays any
the Nuclear
Decommissioning Trust annual accrual until Jan. 1, 2022.
increase
to
Additionally, NSP-Minnesota agreed to not seek recovery of incremental
COVID-19 related expenses, including bad debt expense, and committed to
fund $18 million in a Residential Payment Plan Credit Program or other
similar customer relief programs, as directed by the MPUC. NSP-Minnesota
also agreed to an earnings test in which all earnings above an ROE of
9.06% in 2021 would be refunded to customers.
2020 North Dakota Electric Rate Case — In November 2020, NSP-
Minnesota filed a request with the NDPSC for an overall increase in annual
retail electric revenues of approximately $22 million, or an increase of
10.8%. The rate filing is based on a 2021 forecast test year, a requested
ROE of 10.2%, an equity ratio of 52.50% and an electric rate base of
refund, of
to
Interim
approximately $677 million.
approximately $16 million were implemented on Jan. 5, 2021.
rates, subject
2020 TCR Electric Rider — In November 2019, NSP-Minnesota filed the
TCR Rider based on an ROE of 9.06%. An MPUC decision is pending.
2020 GUIC Natural Gas Rider — In November 2019, NSP-Minnesota filed
the GUIC Rider based on an ROE of 9.04%. An MPUC decision is pending.
2021 GUIC Natural Gas Rider — In October 2020, NSP-Minnesota filed the
GUIC Rider based on an ROE of 9.04%. An MPUC decision is pending.
2020 RES Electric Rider — In November 2019, NSP-Minnesota filed the
RES Rider. The requested amount includes a true-up for the 2019 rider of
$38 million and the 2020 requested amount of $64 million. The filing
included an ROE of 9.06%. An MPUC decision is pending.
2021 RES Electric Rider — In November 2020, NSP-Minnesota filed the
RES Rider. The requested amount includes a true-up for the 2019 and
2020 rider of $96 million and the 2021 requested amount of $93 million.
The filing included an ROE of 9.06%. An MPUC decision is pending.
Minnesota Resource Plan — In July 2019, NSP-Minnesota filed its
Minnesota resource plan, which runs through 2034. The plan would result
in an 80% carbon reduction by 2030 (from 2005) and puts NSP-Minnesota
on a path to achieving its vision of being 100% carbon-free by 2050.
The updated preferred resource plan reflects the following:
•
Retirement of all coal generation by 2030 with reduced operations at
some units prior to retirement, including early retirement of the A.S.
King coal plant (511 MW) in 2028 and the Sherco 3 coal plant (517
MW) in 2030.
Extending the life of the Monticello nuclear plant from 2030 to 2040.
Continuing to run the PI through current end of life (2033 and 2034).
Construction of the Sherco combined cycle natural gas plant.
The addition of 3,500 MW of solar.
The addition of 2,250 MW of wind.
2,600 MW of firm peaking (combustion turbine, pumped hydro, battery
storage, demand response, etc.).
Achieving 780 GWh in energy efficiency savings annually through
2034.
Adding 400 MW of incremental demand response by 2023, and a total
of 1,500 MW of demand response by 2034.
•
•
•
•
•
•
•
•
Initial comments were submitted Feb. 11, 2021 and reply comments are
due April 12, 2021. The MPUC is anticipated to make a final decision
during 2021.
Minnesota Relief and Recovery — In 2020, the MPUC opened a docket
and invited utilities in the state to submit potential projects that would create
jobs and help jump start the economy to offset the impacts of COVID-19.
NSP-Minnesota’s proposal included the following:
•
•
•
•
•
Repower 651 MW of owned wind projects (capital investment of $750
million) as well as certain wind projects under PPAs.
Acquire 120 MW repowered wind farm and buy-out of the remaining
PPA from ALLETE for $210 million.
Add solar facilities of 460 MW with an incremental investment of $550
million.
Accelerate certain grid investment.
Provide $150 million of incremental electric vehicle rebates.
In December 2020, the MPUC verbally approved the repowering of owned
wind projects and 20 MW of wind projects under PPAs. These projects are
estimated to save customers approximately $160 million over the next 25
years. The MPUC is expected to address the solar facilities, ALLETE PPA
wind repowering acquisition and the electric vehicle proposal in the second
half of 2021.
Purchased Power Arrangements and Transmission Service Provider
NSP-Minnesota expects to use power plants, power purchases, CIP/DSM
options, new generation facilities and expansion of power plants to meet its
system capacity requirements.
Purchased Power — NSP-Minnesota has contracts to purchase power from
for
other utilities and
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.
28
Nuclear Power Operations
PSCW
Minnesota State ROFR Statute Complaint — In September 2017, LSP
Transmission filed a complaint in the Minnesota District Court against the
Minnesota Attorney General, MPUC and DOC. The complaint was in
response to MISO assigning NSP-Minnesota and ITC Midwest, LLC to
jointly own a new 345 KV transmission line from Mankato to Winnebago,
Minnesota. The project is estimated to cost approximately $120 million and
projected to be in-service by the end of 2021. It was assigned to NSP-
Minnesota and ITC Midwest as the incumbent utilities, consistent with a
Minnesota state ROFR statute.
The complaint challenged the constitutionality of the statute and is seeking
declaratory judgment that the statute violates the Commerce Clause of the
U.S. Constitution and should not be enforced. In June 2018, the Minnesota
District Court granted Minnesota state agencies and NSP-Minnesota’s
motions to dismiss with prejudice. In February 2020, the Eighth Circuit
Court of Appeals upheld the Minnesota District Court decision to dismiss. In
June 2020, the Eighth Circuit denied LSP Transmission’s petition for
rehearing. In November 2020, LSP Transmission petitioned the U.S.
Supreme Court to review its appeal. NSP-Minnesota filed a brief in
opposition to this petition on Jan. 25, 2021.
Nuclear power 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
if
Wholesale and Commodity Marketing Operations
NSP-Minnesota conducts wholesale marketing operations, including the
purchase and sale of electric capacity, energy, ancillary services and
energy-related products. NSP-Minnesota uses physical and financial
instruments to minimize commodity price and credit risk and to hedge sales
and purchases.
NSP-Minnesota also engages in trading activity unrelated to hedging.
Sharing of any margins is determined through state regulatory proceedings
as well as the operation of the FERC approved JOA. NSP-Minnesota does
not serve any wholesale requirements customers at cost-based regulated
rates.
NSP-Wisconsin
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Regulatory Body / RTO
Additional Information
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
jointly
market. NSP-Wisconsin and NSP-Minnesota are
authorized by the FERC to make wholesale electric sales at
market-based prices.
DOT
Pipeline safety compliance.
Recovery Mechanisms
Mechanism
Annual Fuel Cost Plan
Power Supply Cost
Recovery Factors
Wisconsin Energy
Efficiency Program
PGA
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.
29
Pending and Recently Concluded Regulatory Proceedings
Recovery Mechanisms
2021 Electric Fuel Cost Recovery — In December 2020, the PSCW
approved the NSP-Wisconsin application to update its 2021 fuel cost and
decrease retail electric rates for 2021 by approximately $12 million.
Request to Participate in Utility Money Pool — In October 2020, the
PSCW approved NSP-Wisconsin’s application to participate in the Money
Pool.
NSP-Wisconsin Solar Proposal — In October 2020, NSP-Wisconsin filed
for a 74 MW solar facility build-own-transfer in Wisconsin for approximately
$100 million. A PSCW decision is expected in the third quarter of 2021.
Purchased Power and Transmission Services
The NSP System expects to use power plants, power purchases,
conservation and DSM options, new generation facilities and expansion of
power plants to meet its system capacity requirements.
Purchased Power — Through the Interchange Agreement, NSP-Wisconsin
receives power purchased by NSP-Minnesota from other utilities and
independent power producers. Long-term purchased power contracts for
dispatchable resources typically require a capacity charge and an energy
charge. NSP-Minnesota makes short-term purchases to meet system
requirements, replace company owned generation, meet operating reserve
obligations or obtain energy at a lower cost.
Purchased Transmission Services — NSP-Minnesota and NSP-Wisconsin
have contracts with MISO and other regional transmission service providers
to deliver power and energy to their customers.
Wholesale and Commodity Marketing Operations
NSP-Wisconsin does not serve any wholesale requirements customers at
cost-based regulated rates.
PSCo
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Mechanism
Additional Information
ECA
PCCA
SCA
Recovers fuel and purchased energy costs. Short-term sales margins are
shared with customers through the ECA. The ECA is revised quarterly.
Recovers purchased capacity payments.
Recovers fuel costs to operate the steam system. The SCA rate is revised
quarterly.
DSMCA
Recovers electric and gas DSM, interruptible service costs and performance
initiatives for achieving energy savings goals.
RESA
CEPA
WCA
TCA
Recovers the incremental costs of compliance with the RES with a maximum
of 1% of the customer’s bill.
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.
Recovers costs for transmission investment between rate cases.
CACJA
Recovers costs associated with the CACJA.
FCA
GCA
PSIA
Decoupling
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.
transmission and distribution pipeline
Recovers costs of purchased natural gas and transportation and is revised
quarterly to allow for changes in natural gas rates.
for
Recovers costs
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. Represents approximately $51M for differences in sales to the
baseline amount. Amounts refunded or surcharged to customers may be
limited to a refund cap.
integrity
Pending and Recently Concluded Regulatory Proceedings
Proceeding
2020 Natural Gas Rate Case
2019 Electric Rate Case
2019 Natural Gas Rate Case Appeal
Amount
(in millions)
$77
108
N/A
325
Filing Date
February
2020
Approval
Received
May 2019
Received
April 2019
Pending
July 2020
Pending
Regulatory Body / RTO
Additional Information on Regulatory Authority
Wildfire Protection Rider
CPUC
FERC
RTO
DOT
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.
Transportation Electrification Plan Rider
110 - 138
May 2020
Received
Additional Information:
2020 Natural Gas Rate Case — In October 2020, the CPUC approved a
settlement resulting in a net increase of $77 million. This increase reflects a
$94 million increase in base rate revenue, partially offset by $17 million of
costs previously recovered through the Pipeline Integrity rider. Rates will be
implemented on April 1, 2021 (retroactive to November 2020).
2019 Electric Rate Case — In 2019, PSCo filed a request with the CPUC
seeking a net rate increase of approximately $108 million. In February
2020, the CPUC issued an initial decision for a net rate increase of $35
million. In July 2020, the CPUC’s final written decision on rehearing was
received and resulted in an additional increase of approximately $12 million
annually.
In December 2020, the CPUC denied PSCo’s request of a $5 million
surcharge for changes to the revenue increase from the effective date of
rates, based on the CPUC’s decision on rehearing. PSCo has appealed
this decision with the District Court of Denver County.
30
2019 Phase I Electric Rate Case Appeal — In August 2020, PSCo filed an
appeal with the Denver District Court seeking a review of CPUC decisions
on gain on sales and losses of assets, oil and gas royalty revenues and
Board of Director’s equity compensation. PSCo plans to seek consolidation
of this appeal with the appeal of the surcharge decision in this same
proceeding.
2019 Natural Gas Rate Case Appeal — In April 2019, PSCo filed an appeal
seeking judicial review of the CPUC’s prior ruling regarding PSCo’s natural
gas rate case (filed in June 2017 and approved in December 2018). The
appeal requested review of the following: denial of a return on the prepaid
pension and retiree medical assets; the use of a capital structure not based
on the actual historical test year; and use of an average rate base
methodology rather than a year-end rate base methodology.
In March 2020, The District Court of Denver County ruled in favor of
allowing the prepaid pension assets to be included in rate base; but upheld
the CPUC’s treatment of the retiree medical assets and capital structure
methodology. In March 2021, PSCo expects to file a motion to implement
the District Court’s decision on treatment of the prepaid pension asset for
the applicable period of Jan. 1, 2018 through Oct. 31, 2020.
Wildfire Protection Rider — In 2020, PSCo requested to establish a rider to
recover incremental costs associated with system investments to reduce
wildfire risk. The rider would be effective in June 2021 and continue through
2025. The Office of Consumer Counsel and CPUC Staff are supportive of
the wildfire mitigation program as proposed, but oppose rider recovery and
instead recommend deferral of certain costs with recovery in a future rate
case. A CPUC decision is expected in the second quarter of 2021.
Wildfire Protection capital investment is projected to be approximately $325
million. Forecasted annual revenue requirements from 2021 through 2025:
(Millions of Dollars)
2021
2022
2023
2024
2025
Forecasted annual revenue
requirement
$
17
$
24
$
29
$
32
$
34
Transportation Electrification Plan — In January 2021, the CPUC approved
PSCo's Transportation Electrification Plan, which authorizes rider recovery
of new electric vehicle utility programs for the residential, commercial, multi-
family and public charging sectors. The approval establishes utility-owned
charging infrastructure and chargers and amortization of rebates for electric
vehicles. The Transportation Electrification Plan approval authorizes
approximately $110 million in spending with flexibility up to approximately
$138 million over three years.
Advanced Grid Rider
In 2020, PSCo requested to establish a rider to recover incremental costs
associated with the Advanced Grid Intelligence and Security initiative. The
rider would be effective in May 2021 and continue through 2025. In October
2020, an ALJ issued The Recommended Decision granting the Office of
Consumer Counsel motion to dismiss the Advanced Grid Rider. PSCo has
chosen not to appeal the ALJ’s Recommended Decision.
The PSCo portion of the Advanced Grid Intelligence and Security capital
investment is projected to be approximately $850 million. Forecasted
annual revenue requirements from 2021 through 2025 are as follows:
(Millions of Dollars)
2021
2022
2023
2024
2025
Forecasted annual revenue
requirement
$
53
$
69
$
83
$
89
$
99
PSCo KEPCO Filing
In September 2020, PSCo filed with the CPUC for approval to terminate a
solar PPA with KEPCO Solar of Alamosa, Inc. and establish a regulatory
asset to recover transaction costs of approximately $41 million. By
terminating the PPA, customers would save approximately $38 million over
an 11-year period. A CPUC decision is expected in the second quarter of
2021.
Natural Gas LDC and Emission Reductions
In October 2020, the CPUC opened a docket to investigate topics related to
natural gas emissions in relation to statewide emission reduction goals. The
first meeting was held in November 2020, in which subject matter experts
discussed greenhouse emission reductions required from the natural gas
industry in regard to the statewide goals.
Resource Plan
PSCo is expected to file its next Electric Resource Plan on March 31, 2021.
The filing will propose the future of the remaining coal plants in Colorado
and PSCo’s plan to achieve it’s 80% carbon emissions reduction target by
2030. A CPUC decision is expected in 2022.
PSCo — Comanche Unit 3
PSCo is part owner and operator of Comanche Unit 3, a 750 MW, coal-
fueled electric generating unit. In January 2020, the unit experienced a
turbine failure causing the unit to be taken offline for repairs, which were
completed in June 2020. During start-up the unit experienced a loss of
turbine oil, which damaged the plant. Comanche Unit 3 recommenced
operations in January 2021. Replacement and repair of damaged systems
in excess of a $2 million deductible are expected to be recovered through
insurance policies. PSCo obtained
replacement power costs of
approximately $16 million during the outage. In October 2020, the CPUC
initiated a non-adjudicatory review of Comanche Unit 3’s performance. A
report on performance is expected to be issued in March 2021. At this
stage of the regulatory review, the resulting recommendations of the
CPUC’s staff cannot be determined.
Boulder Municipalization
In 2011, Boulder passed a ballot measure authorizing the formation of an
electric municipal utility. Subsequently, there have been various legal
proceedings in multiple venues.
In September 2020, the City Council voted to approve a settlement
between PSCo and Boulder officials to end the city’s municipalization effort.
The settlement resulted in a 20-year franchise arrangement (with multiple
opt-out conditions), an energy partnership and an undergrounding
agreement. It also established the municipalization process if Boulder
exercised an opt-out. In December 2020, PSCo filed the franchise
agreement with the CPUC and is currently awaiting a decision.
Purchased Power and Transmission Service Providers
PSCo expects to meet its system capacity requirements through electric
generating stations, power purchases, new generation facilities, DSM
options and expansion of generation plants.
Purchased Power — PSCo purchases power from other utilities and IPPs.
Long-term purchased power contracts for dispatchable resources typically
require capacity and energy charges. It also contracts to purchase power
for both wind and solar resources. PSCo makes short-term purchases to
meet system load and energy requirements, replace owned generation,
meet operating reserve obligations, or obtain energy at a lower cost.
31
Energy Markets — PSCo is working towards joining the Western Energy
Imbalance Market in 2022. This market was developed by the California
ISO and allows PSCo access to a real-time energy market. The Western
Energy Imbalance Market allows participants to buy and sell power close to
the time electricity is consumed and gives system operators real-time
visibility across neighboring grids. The result improves balancing supply
and demand at a lower cost.
its own
Purchased Transmission Services —
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 JOA.
SPS
Summary of Regulatory Agencies / RTO and Areas of Jurisdiction
Regulatory Body / RTO
PUCT
NMPRC
FERC
SPP RTO and SPP IM
Wholesale Market
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 the SPP RTO and SPP IM wholesale market.
SPS is authorized to make wholesale electric sales at market-
based prices.
Recovery Mechanisms
Mechanism
DCRF
Additional Information
Recovers distribution costs not included in rates in Texas.
EECRF
Energy Efficiency Rider
Recovers costs for energy efficiency programs in Texas.
Recovers costs for energy efficiency programs in New Mexico.
FPPCAC
Adjusts monthly to recover actual fuel and purchased power
costs in New Mexico.
PCRF
RPS
TCRF
Fixed Fuel and
Purchased Recovery
Factor
Wholesale Fuel and
Purchased Energy Cost
Adjustment
Allows recovery of purchased power costs not included in Texas
rates.
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
32
Pending and Recently Concluded Regulatory Proceedings
Proceeding
2019 New Mexico Electric
Rate Case
2019 Texas Electric Rate Case
2021 New Mexico Electric
Rate Case
2021 Texas Electric Rate Case
Additional Information:
Amount
(in millions)
$31
88
88
143
Filing Date
Approval
July 2019
Received
August 2019
Received
January 2021
February 2021
Pending
Pending
2019 New Mexico Electric Rate Case — In May 2020, the NMPRC
approved a settlement between SPS and intervening parties, which reflects
the following terms: a base rate increase of $31 million, an ROE of 9.45%
and an equity ratio of 54.77%. New rates and tariffs were effective in May
2020.
2019 Texas Electric Rate Case — In August 2020, the PUCT approved a
settlement between SPS and intervening parties, which reflects the
following terms: a rate increase of $88 million; ROE of 9.45% and equity
ratio of 54.62% for AFUDC purposes. In December 2020, SPS filed to
surcharge the final under-recovered amount, estimated to be approximately
$72 million, offset by the recognition of previously deferred costs.
2021 New Mexico Electric Rate Case — On Jan. 4, 2021, SPS filed an
electric rate case with the NMPRC seeking an increase in base rates of
approximately $88 million. SPS' net rate increase to New Mexico customers
is expected to be approximately $48 million, or 10%, as a result of offsetting
fuel cost reductions and PTCs attributable to wind energy provided by the
Sagamore wind project. PTCs are being credited to customers through the
fuel clause.
The request is based on a historic test year ended Sept. 30, 2020, including
expected capital additions through Feb. 28, 2021, a ROE of 10.35%, an
equity ratio of 54.72% and retail rate base of approximately $1.9 billion
(total company rate base of approximately $6.0 billion).
Additionally, the request includes the effect of approximately 400 MW of
reduced peak load in 2021 from a wholesale transmission customer and
changes to depreciation rates to reflect a reduction to the service lives of
SPS’ Tolk power plant (from 2037 to 2032) and the coal handling assets at
the Harrington facility (to 2024).
The NMPRC suspended new rates for nine months beyond the 30-day
notice period, consistent with historic practice.
The next steps in the procedural schedule are expected to be as follows:
•
•
•
•
•
Staff and intervenor testimony — May 17, 2021.
Rebuttal testimony — June 9, 2021.
Deadline to file stipulation — June 23, 2021.
Public hearing or hearing on stipulation — July 26 - Aug. 6, 2021.
End of nine month suspension — Nov. 3, 2021.
A NMPRC decision and implementation of final rates is anticipated in the
fourth quarter of 2021.
2021 Texas Rate Case — On Feb. 8, 2021, SPS filed an electric rate case
with the PUCT and its 81 municipalities with original rate jurisdiction
seeking an increase in base rates of approximately $143 million. SPS' net
rate increase to Texas customers is expected to be approximately $74
million, or 9.2%, as a result of offsetting $69 million in fuel cost reductions
and PTCs from the Sagamore wind project.
The request is primarily driven by additional capital investment in new and
upgraded electric facilities and equipment since SPS’ previous rate case in
2019, including the 522 MW Sagamore wind project.
The request is based on an ROE of 10.35%, an equity ratio of 54.60%
(based on actual capital structure), a Texas retail rate base of
approximately $3.3 billion and a historic test year based on the 12-month
period ended Dec. 31, 2020 (with the final three months based on
estimates). In March 2021, SPS will file to update estimates to actuals
through Dec. 31, 2020.
Additionally, the request includes the effect of approximately 400 MW from
a wholesale transmission customer and changes to depreciation rates to
reflect a reduction to the service lives of SPS’ Tolk power plant (from 2037
to 2032) and the coal handling assets of the Harrington facility (to 2024).
Summary of SPS’ request:
Rate Request (Millions of Dollars)
Sagamore wind project
Other capital investments
Cost of capital
Property taxes
Reduced sales, partially offset by changes in O&M
Allocator changes
Depreciation rate change
Other, net
Total rate request
Fuel cost reductions and PTCs — Sagamore wind project
Net rate increase
$
$
$
67
25
20
8
8
4
3
8
143
(69)
74
SPS is requesting the PUCT set current rates as temporary on March 15,
2021. Once final rates are approved, a surcharge will be requested from
March 15, 2021 through the effective date of new base rates. A PUCT
decision is expected in the first quarter of 2022.
Texas State ROFR Litigation — In May 2019, the Governor signed a ROFR
bill into law, which grants incumbent utilities a ROFR to build transmission
infrastructure when it directly interconnects to the utility’s existing facility. In
June 2019, a complaint was filed in the United States District Court for the
Western District of Texas claiming
to be
unconstitutional. In February 2020, the federal court complaint was
dismissed by the district court. In March 2020, the district court ruling was
appealed to the Fifth Circuit. A decision is pending.
the new ROFR
law
New Mexico FPPCAC Continuation — In December 2020, the Hearing
Examiner recommended the NMPRC approve SPS’ request for the
continued use of the FPPCAC and the reconciliation of its fuel costs for the
reporting period (September 2015 through June 2019). Additionally, the
Hearing Examiner recommended the NMPRC deny the proposed Annual
Deferred Fuel Balance True-Up. The proposed true-up is designed to
maintain the Deferred Fuel and Purchased Power balance within a
bandwidth of plus or minus 5% of annual New Mexico fuel and purchased
power costs. A decision is pending.
Resource Plan — SPS is required to file an IRP in New Mexico every three
years and will file its next IRP in July 2021.
Purchased Power Arrangements and Transmission Service Providers
SPS expects to use electric generating stations, power purchases, DSM
and new generation options to meet its system capacity requirements.
33
Purchased Power — SPS purchases power from other utilities and IPPs.
Long-term purchased power contracts typically require periodic capacity
and energy charges. SPS also makes short-term purchases to meet
system load and energy requirements to replace owned generation, meet
operating reserve obligations or obtain energy at a lower cost.
Purchased Transmission Services — SPS has contractual arrangements
with SPP and regional transmission service providers to deliver power and
energy to its native load customers.
Natural Gas
SPS does not provide retail natural gas service, but purchases and
transports natural gas for its generation facilities and operates natural gas
pipeline facilities connecting the generation facilities to interstate natural
gas pipelines. SPS is subject to the jurisdiction of the FERC with respect to
natural gas transactions in interstate commerce and the PHMSA and PUCT
for pipeline safety compliance.
Wholesale and Commodity Marketing Operations
SPS conducts various wholesale marketing operations, including the
purchase and sale of electric capacity, energy, ancillary services and
energy related products. SPS uses physical and financial instruments to
minimize commodity price and credit risk and to hedge sales and
purchases.
Critical Accounting Policies and Estimates
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.
At Dec. 31, 2020, Xcel Energy set the rate of return on assets used to
measure pension costs at 6.49%, which represents a 38 basis point
decrease from the rate set in 2019. The rate of return used to measure
postretirement health care costs is 4.10% at Dec. 31, 2020, which
represents a 40 basis point decrease from 2019.
Xcel Energy’s pension investment strategy is based on plan-specific
investments that seek to minimize investment and interest rate risk as a
plan’s funded status increases over time. This strategy results in a greater
percentage of interest rate sensitive securities being allocated to plans with
a higher funded status and a greater percentage of growth assets being
allocated to plans having a lower funded status ratios.
Xcel Energy set the discount rates used to value the pension obligations at
2.71% and postretirement health care obligations at 2.65% at Dec. 31,
2020. This represents a 78 basis point and 82 basis point decrease,
respectively, from 2019. Xcel Energy uses a bond matching study as its
primary basis for determining the discount rate used to value pension and
postretirement health care obligations. The bond matching study utilizes a
portfolio of high grade (Aa or higher) bonds that matches the expected cash
flows of Xcel Energy’s benefit plans in amount and duration.
The effective yield on this cash flow matched bond portfolio determines the
discount rate for the individual plans. The bond matching study is validated
for reasonableness against the Merrill Lynch Corporate 15+ Bond Index. In
addition, Xcel Energy reviews general actuarial survey data to assess the
reasonableness of the discount rate selected.
If Xcel Energy were to use alternative assumptions, a 1% change would
result in the following impact on 2020 pension costs:
(Millions of Dollars)
Rate of return
Discount rate (a)
Pension Costs
+1%
-1%
$
$
(16) $
(5) $
22
13
(a)
These cost include the effects of regulation.
Mortality rates are developed from actual and projected plan experience for
pension plan and postretirement benefits. Xcel Energy’s actuary conducts
an experience study periodically to determine an estimate of mortality. Xcel
Energy considers standard mortality tables, improvement factors and the
plans actual experience when selecting a best estimate.
As of Dec. 31, 2020, the initial medical trend cost claim assumptions for
Pre-65 was 5.5% and Post-65 was 5.0%. The ultimate trend assumption
remained at 4.5% for both Pre-65 and Post-65 claims costs. Xcel Energy
bases its medical trend assumption on the long-term cost inflation expected
in
levels projected and
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 $125 million and are expected to
decline in the following years. Investment returns exceeded assumed levels
in 2020 and 2019 and were below assumed levels in 2018.
Each reporting period we assess the probability of future recoveries and
obligations associated with regulatory assets and liabilities. Factors such as
the current regulatory environment, recently issued rate orders and
historical precedents are considered. Decisions made by regulatory
agencies can directly impact the amount and timing of cost recovery as well
as the rate of return on invested capital, and may materially impact our
results of operations, financial condition or cash flows.
As of Dec. 31, 2020 and 2019, Xcel Energy had regulatory assets of $3.4
billion and regulatory liabilities of $5.6 billion and $5.5 billion, respectively.
Each subsidiary is subject to regulation that varies from jurisdiction to
jurisdiction. If future recovery of costs in any such jurisdiction is no longer
probable, Xcel Energy would be required to charge these assets to current
net income or other comprehensive income. At Dec. 31, 2020, in assessing
the probability of recovery of recognized regulatory assets, Xcel Energy
noted no current or anticipated proposals or changes in the regulatory
environment that it expects will materially impact the probability of recovery
of the assets.
See Note 4 to the consolidated financial statements for further information.
Income Tax Accruals
Judgment, uncertainty and estimates are a significant aspect of the income
tax accrual process that accounts for the effects of current and deferred
income taxes. Uncertainty associated with the application of tax statutes
and regulations and outcomes of tax audits and appeals require that
judgment and estimates be made in the accrual process and in the
calculation of the ETR.
Changes in tax laws and rates may affect recorded deferred tax assets and
liabilities and our future ETR. ETR calculations are revised every quarter
based on best available year-end tax assumptions, adjusted in the following
year after returns are filed. Tax accrual estimates are trued-up to the actual
amounts claimed on the tax returns and further adjusted after examinations
by taxing authorities, as needed.
In accordance with the interim period reporting guidance, income tax
expense for the first three quarters in a year is based on the forecasted
annual ETR. The forecasted ETR reflects a number of estimates, including
forecasted annual income, permanent tax adjustments and tax credits.
Valuation allowances are applied to deferred tax assets if it is more likely
than not that at least a portion may not be realized based on an evaluation
of expected future taxable income. Accounting for income taxes also
requires that only tax benefits that meet the more likely than not recognition
threshold can be recognized or continue to be recognized. We may adjust
our unrecognized tax benefits and interest accruals as disputes with the
IRS and state tax authorities are resolved, and as new developments
occur. These adjustments may increase or decrease earnings.
See Note 7 to the consolidated financial statements for further information.
Employee Benefits
We sponsor several noncontributory, defined benefit pension plans and
other postretirement benefit plans that cover almost all employees and
certain retirees. Projected benefit costs are based on historical information
and actuarial calculations that include key assumptions (annual return level
on pension and postretirement health care investment assets, discount
rates, mortality rates and health care cost trend rates, etc.). In addition, the
pension cost calculation uses a methodology to reduce the volatility of
investment performance over time. Pension assumptions are continually
reviewed.
34
The pension cost calculation uses a market-related valuation of pension
assets. Xcel Energy uses a calculated value method to determine the
market-related value of the plan assets. The market-related value is
determined by adjusting the fair market value of assets at the beginning of
the year to reflect the investment gains and losses (the difference between
the actual investment return and the expected investment return on the
market-related value) during each of the previous five years at the rate of
20% per year. As differences between actual and expected investment
returns are incorporated into the market-related value, amounts are
recognized in pension cost over the expected average remaining years of
service for active employees (approximately 13 years in 2020).
Xcel Energy currently projects the pension costs recognized for financial
reporting purposes will be $106 million in 2021 and $83 million in 2022,
while the actual pension costs were $117 million in 2020 and $115 million
in 2019. The expected decrease in 2021 and future year costs is primarily
due to the reductions in loss amortizations.
Pension funding contributions across all four of Xcel Energy’s pension
plans, both voluntary and required, for 2018 - 2021:
•
•
•
•
$125 million in January 2021.
$150 million in 2020.
$154 million in 2019.
$150 million in 2018.
Future amounts may change based on actual market performance,
changes in interest rates and any changes in governmental regulations.
Therefore, additional contributions could be required in the future.
Xcel Energy contributed $11 million, $15 million and $11 million during
2020, 2019 and 2018, respectively, to the postretirement health care plans.
Xcel Energy expects to contribute approximately $10 million during 2021.
Xcel Energy recovers employee benefits costs in its utility operations
consistent with accounting guidance with the exception of the areas noted
below.
•
•
•
in all
NSP-Minnesota
regulatory
recognizes pension expense
jurisdictions using the aggregate normal cost actuarial method.
Differences between aggregate normal cost and expense as
calculated by pension accounting standards are deferred as a
regulatory liability.
In 2018, the PSCW approved NSP-Wisconsin’s request for deferred
accounting treatment of the 2018 pension settlement accounting
expense.
Regulatory Commissions in Colorado, Texas, New Mexico and FERC
jurisdictions allow the recovery of other postretirement benefit costs
only to the extent that recognized expense is matched by cash
contributions to an irrevocable trust. Xcel Energy has consistently
funded at a level to allow full recovery of costs in these jurisdictions.
PSCo and SPS recognize pension expense
in all regulatory
jurisdictions based on GAAP. The Texas and Colorado electric retail
jurisdictions and the Colorado gas retail jurisdiction, each record the
difference between annual recognized pension expense and the
annual amount of pension expense approved in their last respective
general rate case as a deferral to a regulatory asset.
In 2018, PSCo was required to create a regulatory liability to adjust
postretirement health care costs to zero in order to match the amounts
collected in rates in the Colorado Gas retail jurisdiction. In 2020, this
requirement was extended to the Colorado Electric retail jurisdiction.
See Note 11 to the consolidated financial statements for further information.
•
•
Nuclear Decommissioning
Xcel Energy recognizes liabilities for the expected cost of retiring tangible
long-lived assets for which a legal obligation exists. These AROs are
recognized at fair value as incurred and are capitalized as part of the cost
of the related long-lived assets. In the absence of quoted market prices,
Xcel Energy estimates the fair value of its AROs using present value
techniques, in which it makes assumptions including estimates of the
amounts and timing of future cash flows associated with retirement
activities, credit-adjusted risk free rates and cost escalation rates. When
Xcel Energy revises any assumptions, it adjusts the carrying amount of
both the ARO liability and related long-lived asset. ARO liabilities are
accreted to reflect the passage of time using the interest method.
A significant portion of Xcel Energy’s AROs relates to the future
decommissioning of NSP-Minnesota’s nuclear
facilities. The nuclear
decommissioning obligation is funded by the external decommissioning
trust fund. Difference between regulatory funding (including depreciation
expense less returns from the external trust fund) and expense recognized
is deferred as a regulatory asset. The amounts recorded for AROs related
to future nuclear decommissioning were $2.0 billion in 2020 and $2.1 billion
in 2019.
NSP-Minnesota obtains periodic independent cost studies in order to
estimate the cost and timing of planned nuclear decommissioning activities.
Estimates of future cash flows are highly uncertain and may vary
significantly from actual results. NSP-Minnesota is required to file a nuclear
decommissioning filing every three years. The filing covers all expenses for
the decommissioning of the nuclear plants, including decontamination and
removal of radioactive material.
The annual accrual (funding/recovery) set for 2019 and 2020 was based on
the 2014 nuclear decommissioning filing, approved in 2015. Although the
MPUC approved an increased accrual from the 2017 triennial filing in
January 2019, the MPUC subsequently ordered Xcel Energy to maintain
the accrual level (previously established via the 2014 filing) through 2020.
In December 2020, Xcel Energy submitted a 2020 triennial nuclear
decommissioning filing to the MPUC. The filing resulted in an updated
annual accrual of $33 million, or an increase of $19 million compared to the
currently approved funding level. In December 2020, the MPUC verbally
approved NSP-Minnesota to continue using the 2014 filing as the basis for
2021. The filing was also used to revise the estimated ARO liability as of
Dec. 31, 2020 ($216 million decrease).
The following assumptions have a significant effect on the estimated
nuclear obligation:
Timing — Decommissioning cost estimates are impacted by each facility’s
retirement date and timing of the actual decommissioning activities.
Estimated retirement dates coincide with the expiration of each unit’s
operating license with the NRC (i.e., 2030 for Monticello and 2033 and
2034 for PI’s Unit 1 and 2, respectively). The estimated timing of the
decommissioning activities is based upon the DECON method (required by
the MPUC), which assumes prompt
removal and dismantlement.
Decommissioning activities are expected to begin at the end of the license
date and be completed for both facilities by 2095.
Technology and Regulation — There is limited experience with actual
decommissioning of large nuclear facilities. Changes in technology,
experience and regulations could cause cost estimates
to change
significantly.
35
Escalation Rates — Escalation rates represent projected cost increases
due to general inflation and increases in the cost of decommissioning
activities. NSP-Minnesota applied escalation rates of 3.1% for PI and 3.2%
for Monticello in calculating the nuclear decommissioning AROs, based on
weighted averages of labor and non-labor escalation factors calculated by
Goldman Sachs Asset Management.
Discount Rates — Changes in timing or estimated cash flows that result in
upward revisions to the ARO are calculated using the then-current credit-
adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect
when the change occurs is used to discount the revised estimate of the
incremental expected cash flows of the retirement activity.
If the change in timing or estimated expected cash flows results in a
downward revision of the ARO, the undiscounted revised estimate of
expected cash flows is discounted using the credit-adjusted risk-free rate in
effect at the date of initial measurement and recognition of the original
ARO. Discount rates ranging from approximately 3% to 7% have been used
to calculate the net present value of the expected future cash flows over
time.
Significant uncertainties exist in estimating future costs including the
method to be utilized, ultimate costs to decommission and planned method
of disposing spent fuel. If different cost estimates, life assumptions or cost
escalation rates were utilized, the AROs could change materially.
However, changes in estimates have minimal impact on results of
operations as NSP-Minnesota expects to continue to recover all costs in
future rates.
Xcel Energy continually makes judgments and estimates related to these
critical accounting policy areas, based on an evaluation of the assumptions
and uncertainties for each area. The information and assumptions of these
judgments and estimates will be affected by events beyond the control of
Xcel Energy, or otherwise change over time. This may require adjustments
to recorded results to better reflect updated information that becomes
available. The accompanying financial statements reflect management’s
best estimates and judgments of the impact of these factors as of Dec. 31,
2020.
Commodity Price Risk — We are exposed to commodity price risk in our
electric and natural gas operations. Commodity price risk is managed by
entering into long- and short-term physical purchase and sales contracts for
electric capacity, energy and energy-related products and fuels used in
generation and distribution activities. Commodity price risk is also managed
through the use of financial derivative instruments. Our risk management
policy allows it to manage commodity price risk within each rate-regulated
operation per commission approved hedge plans.
Wholesale and Commodity Trading Risk — Xcel Energy conducts
various wholesale and commodity trading activities, including the purchase
and sale of electric capacity, energy, energy-related instruments and
risk
natural gas-related
management policy allows management to conduct these activities within
guidelines and limitations as approved by its risk management committee.
including derivatives. Our
instruments,
Fair value of net commodity trading contracts as of Dec. 31, 2020:
Futures / Forwards Maturity
(Millions of Dollars)
NSP-Minnesota (a)
NSP-Minnesota (b)
PSCo (a)
PSCo (b)
(Millions of Dollars)
NSP-Minnesota (b)
PSCo (b)
Less
Than
1 Year
1 to 3
Years
4 to 5
Years
$
(2) $
(3)
—
(25)
$
1
3
1
(39)
2
(7)
—
(13)
Greater
Than
5 Years
$
2
Total
Fair Value
3
$
(6)
—
—
(13)
1
(77)
(86)
$
(30) $
(34) $
(18) $
(4) $
Options Maturity
Less
Than
1 Year
1 to 3
Years
4 to 5
Years
$
$
1
$
13
14
$
—
16
16
$
$
—
1
1
Greater
Than
5 Years
$
1
—
1
$
Total Fair
Value
$
$
2
30
32
(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:
See Note 12 to the consolidated financial statements for further information.
(Millions of Dollars)
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.
Fair value of commodity trading net contracts outstanding at Jan. 1
Contracts realized or settled during the period
Commodity trading contract additions and changes during the period
2020
2019
$ (59) $ 17
(9)
14
(22)
(54)
Fair value of commodity trading net contracts outstanding at Dec. 31
$ (54) $ (59)
At Dec. 31, 2020, a 10% increase in market prices for commodity trading
contracts through the forward curve would increase pretax income from
continuing operations by approximately $13 million, whereas a 10%
decrease would decrease pretax income from continuing operations by
approximately $13 million. At Dec. 31, 2019, a 10% increase in market
prices for commodity trading contracts would increase pretax income from
continuing operations by approximately $10 million, whereas a 10%
decrease would decrease pretax income from continuing operations by
approximately $10 million. Market price movements can exceed 10% under
abnormal circumstances.
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.
36
Fair Value Measurements
Xcel Energy uses derivative contracts such as futures, forwards, interest
rate swaps, options and FTRs to manage commodity price and interest rate
risk. Derivative contracts, with the exception of those designated as normal
purchase and normal sale contracts, are reported at fair value.
Xcel Energy’s investments held in the nuclear decommissioning fund, rabbi
trusts, pension and other postretirement funds are also subject to fair value
accounting.
Commodity Derivatives — Xcel Energy monitors the creditworthiness of
the counterparties to its commodity derivative contracts and assesses each
counterparty’s ability to perform on the transactions. The impact of
discounting commodity derivative assets for counterparty credit risk was not
material to the fair value of commodity derivative assets at Dec. 31, 2020.
Adjustments to fair value for credit risk of commodity trading instruments
are recorded in electric revenues. Credit risk adjustments for other
commodity derivative instruments are recorded as other comprehensive
income or deferred as regulatory assets and liabilities. Classification as a
regulatory asset or liability is based on commission approved regulatory
recovery mechanisms. The impact of discounting commodity derivative
liabilities for credit risk was immaterial at Dec. 31, 2020.
See Notes 10 and 11 to the consolidated financial statements for further
information.
Liquidity and Capital Resources
Cash Flows
Operating Cash Flows
(Millions of Dollars)
Cash provided by operating activities — 2019
Components of change — 2020 vs. 2019
Higher net income
Non-cash transactions
(a)
Changes in working capital
Changes in net regulatory and other assets and liabilities
(b)
Twelve Months Ended
Dec. 31
$
3,263
101
(49)
(222)
(245)
2,848
Cash provided by operating activities — 2020
$
(a)
(b)
Non-cash transactions applicable to net income (e.g., depreciation and amortization,
nuclear fuel amortization, changes in deferred income taxes, allowance for equity funds
used during construction, etc.).
Working capital includes accounts receivable, accrued unbilled revenues, inventories,
accounts payable, other current assets and other current liabilities.
Net cash provided by operating activities decreased by $415 million for
2020 as compared to 2019. Decrease was primarily due to changes in
accounts receivable related to increased residential sales, timing of
regulatory asset recovery and inventory wind turbine purchases, which
were partially offset by an increase in net income.
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)
2020
2019
Year Ended
Dec. 31
$
VaR Limit
Average
High
Low
1
$
< 1
$
3
3
$
1
1
$
2
1
1
< 1
Nuclear Fuel Supply — NSP-Minnesota has contracted for approximately
11% of its 2021 enriched nuclear material requirements from sources that
could be impacted by sanctions against entities doing business with Iran.
Those sanctions may impact the supply of enriched nuclear material
supplied
is
scheduled to take delivery of approximately 28% of its average enriched
nuclear material requirements from these sources. NSP-Minnesota is able
to manage nuclear fuel supply with alternate potential sources. NSP-
Minnesota periodically assesses if further actions are required to assure a
secure supply of enriched nuclear material.
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
$6 million in 2020 and 2019, respectively.
NSP-Minnesota maintains a nuclear decommissioning fund, as required by
the NRC. The nuclear decommissioning fund is subject to interest rate risk
and equity price risk. The fund is invested in a diversified portfolio of cash
equivalents, debt securities, equity securities and other investments. These
investments may be used only for the purpose of decommissioning NSP-
Minnesota’s nuclear generating plants.
Realized and unrealized gains on the decommissioning fund investments
are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear
decommissioning costs. Fluctuations in equity prices or interest rates
affecting the nuclear decommissioning fund do not have a direct impact on
earnings due to the application of regulatory accounting.
Changes in discount rates and expected return on plan assets impact the
value of pension and postretirement plan assets and/or benefit costs.
Credit Risk — Xcel Energy is also exposed to credit risk. Credit risk relates
to the risk of loss resulting from counterparties’ nonperformance on their
contractual obligations. Xcel Energy maintains credit policies intended to
minimize overall credit risk and actively monitor these policies to reflect
changes and scope of operations.
At Dec. 31, 2020, a 10% increase in commodity prices would have resulted
in an increase in credit exposure of $11 million, while a decrease in prices
of 10% would have resulted in an immaterial increase in credit exposure. At
Dec. 31, 2019, a 10% increase in commodity prices would have resulted in
an increase in credit exposure of $19 million, while a decrease in prices of
10% would have resulted in an increase in credit exposure of $14 million.
Xcel Energy conducts credit reviews for all counterparties and employs
credit risk controls, such as letters of credit, parental guarantees, master
netting agreements and
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
37
Investing Cash Flows
Financing Cash Flows
(Millions of Dollars)
Cash used in investing activities — 2019
Components of change — 2020 vs. 2019
Increased capital expenditures
Sale of MEC
Other investing activities
Cash used in investing activities — 2020
Twelve Months Ended
Dec. 31
(Millions of Dollars)
$
$
(4,343)
Cash provided by financing activities — 2019
Components of change — 2020 vs. 2019
(1,144)
Higher debt issuances
684
63
Higher repayments of long-term debt
Higher proceeds from issuance of common stock
(4,740)
Higher dividends paid to shareholders
Net cash used in investing activities increased by $397 million for 2020 as
compared to 2019. Increase was primarily attributable to additional capital
expenditures, primarily for wind projects, including Sagamore, Cheyenne
Ridge, Blazing Star 1 and Crowned Ridge 2.
Twelve Months Ended
Dec. 31
$
1,181
452
(52)
269
(65)
(12)
Other financing activities
Cash provided by financing activities — 2020
$
1,773
Net cash provided by financing activities increased by $592 million for 2020
as compared to 2019. Increase was primarily attributable to higher
proceeds from issuances of long-term debt and common stock (due to
forward equity agreements settling in November 2020 and August 2019),
partially offset by higher repayments of long-term debt and dividends paid.
See Note 5 to the consolidated financial statements for further information.
Capital Requirements
Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other
securities to maintain desired capitalization ratios.
Contractual Obligations and Other Commitments — Xcel Energy has contractual obligations and other commitments that will need to be funded in the
future. Contractual obligations and other commercial commitments as of Dec. 31, 2020:
(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
Other short-term obligations
Short-term debt
Total contractual cash obligations
Payments Due by Period
Total
Less than 1 Year
1 to 3 Years
3 to 5 Years
After 5 Years
$
34,312
$
1,183
$
3,249
$
3,107
$
26,773
257
1,859
5,005
637
420
584
14
273
1,366
74
420
584
24
497
1,585
63
—
—
22
434
911
60
—
—
197
655
1,143
440
—
—
$
43,074
$
3,914
$
5,418
$
4,534
$
29,208
(a)
(b)
Included in operating lease obligations are $247 million, $446 million, $398 million and $561 million, for the less than 1 year, 1 - 3 years, 3 - 5 years and after 5 years categories, respectively,
pertaining to PPAs that were accounted for as operating leases.
Xcel Energy Inc. and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its fuel (nuclear, natural gas and coal) requirements. Additionally, the
utility subsidiaries of Xcel Energy Inc. have entered into non-lease purchase power agreements. Certain contractual purchase obligations are adjusted on indices. Effects of price changes
are mitigated through cost of energy adjustment mechanisms.
Capital Expenditures — The capital forecasts for Xcel Energy for 2021 through 2025 are detailed in the following tables. The base capital forecast has
been updated to reflect the MPUC’s approval of the $750 million wind repowering proposal. In addition, the base capital forecast reflects a change in the
timing of completion of a wind project from 2020 to 2021.
By Regulated Utility
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Other (a)
Actual
2020
2021
2022
2023
2024
2025
2021 - 2025 Total
Base Capital Forecast (Millions of Dollars)
$
1,600
$
1,700
$
1,835
$
1,750
$
1,695
$
1,655
$
1,955
1,180
235
(135)
1,930
1,785
1,785
1,915
1,890
505
360
(20)
710
430
(15)
770
395
10
735
515
10
675
470
10
8,635
9,305
3,395
2,170
(5)
23,500
Total base capital expenditures
$
4,835
$
4,475
$
4,745
$
4,710
$
4,870
$
4,700
$
(a)
Other category includes intercompany transfers for safe harbor wind turbines.
38
By Function
Electric distribution
Electric transmission
Electric generation
Natural gas
Other
Renewables
$
Actual
2020
980
695
445
580
345
1,790
2021
2022
2023
2024
2025
2021 - 2025 Total
Base Capital Forecast (Millions of Dollars)
$
1,205
$
1,440
$
1,550
$
1,505
$
1,475
$
870
630
615
545
610
1,285
1,285
1,270
1,290
575
615
575
255
560
665
485
165
750
670
405
270
975
625
335
—
Total base capital expenditures
$
4,835
$
4,475
$
4,745
$
4,710
$
4,870
$
4,700
$
7,175
6,000
3,490
3,190
2,345
1,300
23,500
NSP-Minnesota Proposal
Sherco solar
Wind PPA buyout
Total incremental capital
Incremental Capital Forecast (Millions of Dollars) (a)
2021
2022
2023
2024
2025
2021 - 2025 Total
$
$
30
25
55
$
$
200
185
385
$
$
320
$
—
320
$
—
—
—
$
$
—
—
—
$
$
550
210
760
(a)
Reflects potential capital investment under the Minnesota Relief and Recovery Plan, which will require MPUC approval. The incremental capital investment is not included in the base capital
forecast.
Xcel Energy’s capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to
changes in electric and natural gas projected load growth, safety and reliability needs, regulatory decisions, legislative initiatives, reserve requirements,
availability of purchased power, alternative plans for meeting long-term energy needs, environmental initiatives and regulation, and mergers, acquisition and
divestiture opportunities.
Financing Capital Expenditures through 2025 — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt,
fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes. Financing plans are subject to
change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies, and other factors.
Current estimated financing plans for 2021 - 2025:
(Millions of Dollars)
Funding Capital Expenditures
Cash from operations (a)
New debt (b)
Equity through the DRIP and benefit program
Other equity
Base capital expenditures 2021 - 2025
Maturing Debt
(a)
Net of dividends and pension funding.
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, 2020
Dec. 31, 2019
$
$
3,599
$
3,964
(365) $
3,184
3,701
(517)
$
$
$
15,000
7,490
410
600
23,500
3,820
(b)
Reflects a combination of short and long-term debt; net of refinancing.
(a)
Excludes non-qualified plan of $43 million and $39 million at Dec. 31, 2020 and 2019,
respectively.
Pension Assumptions
Discount rate
Expected long-term rate of return
Capital Sources
2020
2019
2.71 %
6.49
3.49 %
6.87
Short-Term Funding Sources — Xcel Energy generally funds short-term
needs, through operating cash flow, notes payable, commercial paper and
bank lines of credit. The amount and timing of short-term funding needs
depend on construction expenditures, working capital and dividend
payments.
Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-
Wisconsin, PSCo and SPS maintain cash and short-term investment
accounts.
The incremental renewable capital expenditures would be financed with
approximately 50% debt and 50% equity, if approved by the MPUC.
Common Stock Dividends — Future dividend levels will be dependent on
Xcel Energy’s results of operations, financial condition, cash flows,
reinvestment opportunities and other factors, and will be evaluated by the
Xcel Energy Inc. Board of Directors. In February 2021, Xcel Energy
announced a quarterly dividend of $0.4575 per share, which represents an
increase of 6.4%.
Xcel Energy’s dividend policy balances the following:
•
•
•
•
Projected cash generation.
Projected capital investment.
A reasonable rate of return on shareholder investment.
The impact on Xcel Energy’s capital structure and credit ratings.
In addition, there are certain statutory limitations that could affect dividend
levels. Federal law places limits on the ability of public utilities within a
holding company to declare dividends. Under the Federal Power Act, a
public utility may not pay dividends from any funds properly included in a
capital account. The utility subsidiaries’ dividends may be limited directly or
indirectly by state regulatory commissions or bond indenture covenants.
See Note 5 to the consolidated financial statements for further information.
39
Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin,
PSCo and SPS each have individual commercial paper programs.
Authorized levels for these commercial paper programs are:
•
•
•
•
•
$1.25 billion for Xcel Energy Inc.
$700 million for PSCo.
$500 million for NSP-Minnesota.
$500 million for SPS.
$150 million for NSP-Wisconsin.
In addition, in December 2020, Xcel Energy Inc. repaid its $500 million
Term Loan Agreement. In September 2020, Xcel Energy Inc. repaid its
$700 million Term Loan Agreement.
Xcel Energy’s outstanding short-term debt:
(Amounts in Millions, Except Interest Rates)
Three Months Ended
Dec. 31, 2020
Borrowing limit
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
584
415
613
0.60 %
0.23
(Amounts in Millions, Except
Interest Rates)
Year Ended
Dec. 31, 2020
Year Ended
Dec. 31, 2019
Year Ended
Dec. 31, 2018
Borrowing limit
$
3,100
$
3,600
$
3,250
Amount outstanding at period
end
Average amount outstanding
Maximum amount outstanding
Weighted average interest rate,
computed on a daily basis
Weighted average interest rate
at end of period
584
1,126
2,080
595
1,115
1,780
1,038
788
1,349
1.45 %
2.72 %
2.34 %
0.23
2.34
2.97
Credit Facility Agreements — Xcel Energy Inc., NSP-Minnesota, PSCo
and SPS each have the right to request an extension of the revolving credit
facility for two additional one-year periods beyond the June 2024
termination date. NSP-Wisconsin has the right to request an extension of
the revolving credit facility for an additional year. All extension requests are
subject to majority bank group approval.
As of Feb. 16, 2021, Xcel Energy Inc. and its utility subsidiaries had the
following committed credit facilities available to meet liquidity needs:
(Millions of Dollars)
Xcel Energy Inc.
Facility (a)
1,250
$
Drawn (b)
696
$
Available
Cash
Liquidity
$
$
554
558
371
159
150
$
2
2
2
1
5
556
560
373
160
155
700
500
500
150
142
129
341
—
$
3,100
$
1,308
$
1,792
$ 12
$
1,804
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Total
(a)
(b)
Credit facilities expire in June 2024.
Includes outstanding commercial paper and letters of credit.
Registration Statements — Xcel Energy Inc.’s Articles of Incorporation
authorize the issuance of one billion shares of $2.50 par value common
stock. As of Dec. 31, 2020 and 2019, Xcel Energy had approximately 537
million shares and 525 million shares of common stock outstanding,
respectively.
40
Xcel Energy Inc. and its utility subsidiaries have registration statements on
file with the SEC pursuant to which they may sell securities from time to
time. These registration statements, which are uncapped, permit Xcel
Energy Inc. and its utility subsidiaries to issue debt and other securities in
the future at amounts, prices and with terms to be determined at the time of
future offerings, and in the case of our utility subsidiaries, subject to
commission approval.
Planned Financing Activity — Xcel Energy’s 2021 financing plans reflect
the following:
•
•
•
•
•
Xcel Energy Inc. — approximately $1.2 billion in debt financing.
PSCo — approximately $750 million of first mortgage bonds.
SPS — approximately $250 million of first mortgage bonds.
NSP-Minnesota — approximately $850 million of first mortgage bonds.
NSP-Wisconsin — approximately $125 million of first mortgage bonds.
Forward Equity Agreements — In November 2018, Xcel Energy Inc.
entered into forward equity agreements in connection with a completed
$459 million public offering of 9.4 million shares of Xcel Energy common
stock. In August 2019, Xcel Energy settled the forward equity agreements
by delivering 9.4 million shares of common equity for cash proceeds of
$453 million.
Inc. entered
In November 2019, Xcel Energy
forward equity
agreements for a $743 million public offering of 11.8 million shares of Xcel
Energy common stock. In November 2020, Xcel Energy settled the forward
equity agreements by delivering 11.8 million shares of common equity for
cash proceeds of $721 million.
into
Equity through DRIP and Benefits Program — Xcel Energy also plans to
issue approximately $75 to $90 million of equity annually through the DRIP
and benefit programs during the five-year forecast time period.
Long-Term Borrowings and Other Financing Instruments — See Note
5 to the consolidated financial statements for further information.
Natural Gas Fuel and Electricity Purchases
In February 2021, the United States experienced winter storm Uri and
extreme cold temperatures in the central United States. This severe
weather event increased the demand for natural gas used in our electric
and natural gas businesses. Certain operational assets were impacted by
extreme cold temperatures and safety protocols and the cold further
impacted the availability of renewable generation across the region (which
typically acts as a hedge against commodity prices) contributing to
extremely high market prices for natural gas and electricity. As a result,
electric and natural gas fuel costs increased approximately $1.2 billion
(PSCo - $650 million, NSP-Minnesota - $300 million, SPS - $200 million
and NSP-Wisconsin - $45 million). These amounts are preliminary
estimates through Feb. 16, 2021 and are subject to final settlement.
Xcel Energy has fuel recovery mechanisms in all of its states to recover the
increased cost of natural gas and electricity. However, given the impact of
these higher costs to our customers during a pandemic, we expect our
regulators to undertake a heightened review and we intend to work with our
commissions to recover these costs over time to help mitigate the impacts
on customer bills. Xcel Energy is taking action to increase planned debt
issuances to ensure adequate liquidity for the timing difference between
fuel payments and revenue collection from customers and to address any
potential need to post collateral.
Earnings Guidance
2021 GAAP and ongoing earnings guidance is a range of $2.90 to $3.00
per share. (a)
Key assumptions as compared with 2020 levels unless noted:
Constructive outcomes in all rate case and regulatory proceedings.
Modest impacts from COVID-19.
Normal weather patterns for the remainder of the year.
•
•
•
• Weather-normalized retail electric sales are projected to increase
~1%.
• Weather-normalized retail firm natural gas sales are projected to be
•
•
•
•
•
•
•
(a)
relatively flat.
Capital rider revenue is projected to increase $105 million to $115
million (net of PTCs). The change reflects the deferral of advanced
grid costs, which were denied rider recovery. PTCs are credited to
customers, through capital riders, fuel clause or base rates and results
in a reduction to electric margin.
O&M expenses are projected to be relatively flat.
Depreciation expense is projected to increase approximately $195
million to $205 million.
Property taxes are projected to increase approximately $45 million to
$55 million.
Interest expense (net of AFUDC - debt) is projected to increase $0
million to $10 million.
AFUDC - equity is projected to decline approximately $45 million to
$55 million.
ETR is projected to be ~(9%). The ETR reflects benefits of PTCs
which are credited to customers through electric margin and will not
have a material impact on net income.
Ongoing earnings is calculated using net income and adjusting for certain nonrecurring
or infrequent items that are, in management’s view, not reflective of ongoing operations.
Ongoing earnings could differ from those prepared in accordance with GAAP for
unplanned and/or unknown adjustments. Xcel Energy is unable to forecast if any of
these items will occur or provide a quantitative reconciliation of the guidance for ongoing
EPS to corresponding GAAP EPS.
Off-Balance Sheet Arrangements
Xcel Energy does not have any off-balance-sheet arrangements, other than
those currently disclosed, that have or are reasonably likely to have a
current or future effect on financial condition, changes in financial condition,
revenues or expenses, results of operations, liquidity, capital expenditures
or capital resources that is material to investors.
There is continued uncertainty regarding COVID-19, the duration and
magnitude of business restrictions, re-shut downs and the level and pace of
economic recovery. Also, while we may implement contingency plans, there
are no guarantees these plans will be sufficient to offset the impact of the
pandemic, which could have a material impact on our results of operations,
financial condition or cash flow.
An overview of certain risk considerations or areas which have or could
significantly impact us, is as follows.
Sales — Xcel Energy has experienced and may continue to experience
higher residential sales and lower C&I sales as a result of COVID-19. Xcel
Energy has decoupling and sales true-up mechanisms in Minnesota (all
electric classes) and Colorado (residential and non-demand small C&I
electric classes), which mitigate the impact of changes to sales levels as
compared to a baseline.
Bad Debt — Bad debt expense could significantly increase due to
pandemic related economic impacts, customer hardship, federal or state
legislation and regulatory orders. However, several of our commissions
have approved the deferral of incremental COVID-19 related expense,
including bad debt expense.
Xcel Energy has received orders in Colorado, Wisconsin, Texas, New
Mexico, North Dakota, South Dakota and Michigan, allowing regulatory
deferral of incremental COVID-19 costs as a regulatory asset subject to
future determination of amount and timing of recovery. As part of NSP-
Minnesota’s stay-out alternative, NSP-Minnesota agreed to not seek
recovery of incremental COVID-19 related costs.
The majority of wholesale customers are subject to formula transmission
and production rates, which true-up rates to actual costs to serve.
Supply Chain and Capital Expenditures — Xcel Energy’s ability to meet
customer energy requirements, respond to storm-related disruptions and
execute our capital expenditure program are dependent on maintaining an
efficient supply chain. During 2020, Xcel Energy did not experience supply
chain, contractor or employee disruptions with the exception of delays in
certain wind projects.
Liquidity — Xcel Energy took steps to enhance its liquidity in 2020 and
believes it has more than adequate liquidity. Xcel Energy will take steps to
enhance liquidity in 2021 if needed.
ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
COVID-19
See Item 7, incorporated by reference.
Although the COVID-19 pandemic has led to numerous challenges, Xcel
including business
its risk management program,
Energy believes
continuity and disaster recovery planning, will continue to allow us to
proactively manage and successfully navigate challenges, risks and
uncertainties.
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.
41
Management Report on Internal Control Over Financial Reporting
The management of Xcel Energy Inc. is responsible for establishing and maintaining adequate internal control over financial reporting. Xcel Energy Inc.’s
internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s management and Board of Directors regarding the preparation
and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide
only reasonable assurance with respect to financial statement preparation and presentation.
Xcel Energy Inc. management assessed the effectiveness of Xcel Energy Inc.’s internal control over financial reporting as of Dec. 31, 2020. In making this
assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control —
Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2020, Xcel Energy Inc.’s internal control over financial reporting is
effective at the reasonable assurance level based on those criteria.
Xcel Energy Inc.’s independent registered public accounting firm has issued an audit report on Xcel Energy Inc.’s internal control over financial reporting. Its
report appears herein.
/s/ BEN FOWKE
Ben Fowke
Chairman, Chief Executive Officer and Director
Feb. 17, 2021
/s/ BRIAN J. VAN ABEL
Brian J. Van Abel
Executive Vice President, Chief Financial Officer
Feb. 17, 2021
42
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of Xcel Energy Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Xcel Energy Inc. and subsidiaries (the "Company") as of December 31, 2020 and 2019,
the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows, for each of the three years in the period ended
December 31, 2020, and the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the "financial statements"). We also
have audited the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated
Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31,
2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with
accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by
COSO.
Basis for Opinions
The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its
assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Controls over
Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial
reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB)
and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations
of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain
reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal
control over financial reporting was maintained in all material respects.
Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due
to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the
amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included
obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the
design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we
considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control
over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial
statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required
to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our
especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial
statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or
on the accounts or disclosures to which it relates.
43
Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements — Refer to Notes 4 and 12 to the consolidated financial
statements
Critical Audit Matter Description
The Company is subject to rate regulation by state utility regulatory agencies, which have jurisdiction with respect to the rates of electric and natural gas
distribution companies in Minnesota, North Dakota, South Dakota, Wisconsin, Michigan, Colorado, New Mexico, and Texas. The Company is also subject to
the jurisdiction of the Federal Energy Regulatory Commission for its wholesale electric operations, hydroelectric generation licensing, accounting practices,
wholesale sales for resale, transmission of electricity in interstate commerce, compliance with North American Electric Reliability Corporation standards,
asset transactions and mergers and natural gas transactions in interstate commerce, (collectively with state utility regulatory agencies, the “Commissions”).
Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its
financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation
affects multiple financial statement line items and disclosures, including property, plant and equipment, regulatory assets and liabilities, operating revenues
and expenses, and income taxes.
The Company is subject to regulatory rate setting processes. Rates are determined and approved in regulatory proceedings based on an analysis of the
Company’s costs to provide utility service and a return on, and recovery of, the Company’s investment in assets required to deliver services to customers.
Accounting for the Company’s regulated operations provides that rate-regulated entities report assets and liabilities consistent with the recovery of those
incurred costs in rates, if it is probable that such rates will be charged and collected. The Commissions’ regulation of rates is premised on the full recovery of
incurred costs and a reasonable rate of return on invested capital. Decisions by the Commissions in the future will impact the accounting for regulated
operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. In
the rate setting process, the Company’s rates result in the recording of regulatory assets and liabilities based on the probability of future cash flows.
Regulatory assets generally represent incurred or accrued costs that have been deferred because future recovery from customers is probable. Regulatory
liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about
impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial
statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of
recently completed plant, and 3) a refund due to customers. Given that management’s accounting judgements are based on assumptions about the
outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate
setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
• We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs deferred as
regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of
management’s controls over the recognition of regulatory assets or liabilities and the monitoring and evaluation of regulatory developments that may
affect the likelihood of recovering costs in future rates or of a future reduction in rates.
• We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
• We read relevant regulatory orders issued by the Commissions for the Company, regulatory statutes, interpretations, procedural memorandums, filings
made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based
on precedents of the Commissions’ treatment of similar costs under similar circumstances. We also evaluated regulatory filings for any evidence that
intervenors are challenging full recovery of the cost of any capital projects. If the full recovery of project costs is being challenged by intervenors, we
evaluated management’s assessment of the probability of a disallowance. We evaluated the external information and compared to the Company’s
recorded regulatory assets and liabilities for completeness.
• We obtained management’s analysis and correspondence from counsel, as appropriate, regarding regulatory assets or liabilities not yet addressed in a
regulatory order to assess management’s assertion that amounts are probable of recovery or a future reduction in rates.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 17, 2021
We have served as the Company’s auditor since 2002.
44
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(amounts in millions, except per share data)
Operating revenues
Electric
Natural gas
Other
Total operating revenues
Operating expenses
Electric fuel and purchased power
Cost of natural gas sold and transported
Cost of sales — other
Operating and maintenance expenses
Conservation and demand side management expenses
Depreciation and amortization
Taxes (other than income taxes)
Total operating expenses
Operating income
Other (expense) income, net
Equity earnings of unconsolidated subsidiaries
Allowance for funds used during construction — equity
Interest charges and financing costs
Interest charges — includes other financing costs of $28, $26 and $25, 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
2020
2019
2018
$
9,802
$
9,575
$
1,636
88
11,526
1,868
86
11,529
3,512
689
37
2,324
288
1,948
612
9,410
2,116
(6)
40
115
840
(42)
798
1,467
(6)
3,510
918
40
2,338
285
1,765
569
9,425
2,104
16
39
77
773
(37)
736
1,500
128
$
1,473
$
1,372
$
527
528
519
520
$
2.79
$
2.79
2.64
$
2.64
9,719
1,739
79
11,537
3,854
843
35
2,352
290
1,642
556
9,572
1,965
(14)
35
108
700
(48)
652
1,442
181
1,261
511
511
2.47
2.47
See Notes to Consolidated Financial Statements
45
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(amounts in millions)
Net income
Other comprehensive (loss) income
Pension and retiree medical benefits:
Net pension and retiree medical losses arising during the period, net of tax of $(2), $— and $(2), respectively
Reclassification of losses to net income, net of tax of $3, $1 and $3, respectively
Derivative instruments:
Net fair value decrease, net of tax of $(3), $(8) and $(2), respectively
Reclassification of losses to net income, net of tax of $2, $1 and $1, respectively
Total other comprehensive (loss) income
Total comprehensive income
Year Ended Dec. 31
2020
2019
2018
$
1,473
$
1,372
$
1,261
(5)
10
(10)
5
—
—
3
(23)
3
(17)
(6)
9
(5)
3
1
1,262
See Notes to Consolidated Financial Statements
$
1,473
$
1,355
$
46
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
Equity earnings of unconsolidated subsidiaries
Dividends from unconsolidated subsidiaries
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
(Repayments of) proceeds from 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 and cash equivalents at beginning of period
Cash and cash equivalents at end of period
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)
Cash 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 equity awards
See Notes to Consolidated Financial Statements
47
2020
Year Ended Dec. 31
2019
2018
$
1,473
$
1,372
$
1,261
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
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
$
$
$
(119)
248
129
$
101
147
248
$
(758) $
12
(698) $
53
$
400
275
369
115
67
$
421
88
1,843
77
63
1,659
122
218
(108)
(35)
37
42
45
22
(105)
9
(65)
18
90
223
(61)
(179)
(71)
3,122
(3,957)
—
(853)
833
(9)
(3,986)
225
1,675
(452)
230
(730)
(20)
928
64
83
147
(633)
27
388
129
—
108
67
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in millions, except share and per share)
Assets
Current assets
Cash and cash equivalents
Accounts receivable, net
Accrued unbilled revenues
Inventories
Regulatory assets
Derivative instruments
Prepaid taxes
Prepayments and other
Total current assets
Property, plant and equipment, net
Other assets
Nuclear decommissioning fund and other investments
Regulatory assets
Derivative instruments
Operating lease right-of-use assets
Other
Total other assets
Total assets
Liabilities and Equity
Current liabilities
Current portion of long-term debt
Short-term debt
Accounts payable
Regulatory liabilities
Taxes accrued
Accrued interest
Dividends payable
Derivative instruments
Operating lease liabilities
Other
Total current liabilities
Deferred credits and other liabilities
Deferred income taxes
Deferred investment tax credits
Regulatory liabilities
Asset retirement obligations
Derivative instruments
Customer advances
Pension and employee benefit obligations
Operating lease liabilities
Other
Total deferred credits and other liabilities
Commitments and contingencies
Capitalization
Long-term debt
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 537,438,394 and 524,539,000 shares outstanding at Dec. 31, 2020
and Dec. 31, 2019, 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
48
Dec. 31
2020
2019
$
129
916
714
535
640
49
42
250
3,275
248
837
713
544
488
55
43
185
3,113
42,950
39,483
$
$
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
$
2,731
2,935
22
1,672
492
7,852
50,448
702
595
1,294
407
466
192
212
38
194
468
4,568
4,509
49
5,077
2,701
175
203
785
1,549
186
15,234
17,407
1,311
6,656
5,413
(141)
13,239
50,448
$
$
$
$
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
(amounts in millions, shares in thousands)
Common Stock Issued
Shares
Par Value
Additional Paid
In Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Loss
Total Common
Stockholders’
Equity
Balance at Dec. 31, 2017
507,763
$
1,269
$
5,898
$
4,413
$
(125) $
11,455
Net income
Other comprehensive income
Dividends declared on common stock ($1.52 per share)
Issuances of common stock
Repurchases of common stock
Share-based compensation
Balance at Dec. 31, 2018
Net Income
Other comprehensive loss
Dividends declared on common stock ($1.62 per share)
Issuances of common stock
Repurchase 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
6,296
(22)
16
—
254
(1)
17
1,261
(780)
(1)
1
1,261
1
(780)
270
(1)
16
514,037
$
1,285
$
6,168
$
4,893
$
(124) $
12,222
10,508
(6)
26
—
468
—
20
1,372
(846)
(6)
(17)
1,372
(17)
(846)
494
—
14
524,539
$
1,311
$
6,656
$
5,413
$
(141) $
13,239
12,954
(55)
33
—
731
(4)
21
1,473
(909)
(7)
(2)
1,473
(909)
764
(4)
14
(2)
537,438
$
1,344
$
7,404
$
5,968
$
(141) $
14,575
See Notes to Consolidated Financial Statements
49
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 on 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
regulatory approval.
XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
General — Xcel Energy Inc.’s utility subsidiaries are engaged in the
regulated generation, purchase, transmission, distribution and sale of
electricity and in the regulated purchase, transportation, distribution and
sale of natural gas.
Xcel Energy’s regulated operations include the activities of NSP-Minnesota,
NSP-Wisconsin, PSCo and SPS. These utility subsidiaries serve electric
and natural gas customers in portions of Colorado, Michigan, Minnesota,
New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Also
included in regulated operations are WGI, an interstate natural gas pipeline
company, and WYCO, a joint venture with CIG to develop and lease natural
gas pipeline, storage and compression facilities.
Xcel Energy Inc.’s nonregulated subsidiaries include Eloigne, Capital
Services and Nicollet Project Holdings. Eloigne invests in rental housing
projects that qualify for low-income housing tax credits. Capital Services
procures equipment for construction of renewable generation facilities at
other subsidiaries. Nicollet Project Holdings invests in nonregulated assets
such as the MEC generating facility (through July 2020) and Minnesota
community solar gardens. Xcel Energy Inc. owns the following additional
direct subsidiaries, some of which are intermediate holding companies with
additional subsidiaries: Xcel Energy Wholesale Group Inc., Xcel Energy
Markets Holdings Inc., Xcel Energy Ventures Inc., Xcel Energy Retail
Holdings Inc., Xcel Energy Communications Group, Inc., Xcel Energy
International Inc., Xcel Energy Transmission Holding Company, LLC,
Nicollet Holdings Company, LLC, Nicollet Project Holdings LLC, Xcel
Energy Venture Holdings Inc. and Xcel Energy Services Inc. Xcel Energy
Inc. and its subsidiaries collectively are referred to as Xcel Energy.
Xcel Energy’s consolidated financial statements include its wholly-owned
subsidiaries and VIEs
the primary beneficiary. All
it
intercompany transactions and balances are eliminated, unless a different
treatment is appropriate for rate regulated transactions.
for which
is
Xcel Energy uses the equity method of accounting for its investment in
WYCO. Xcel Energy’s equity earnings in WYCO are included on the
consolidated statements of income as equity earnings of unconsolidated
subsidiaries.
Xcel Energy has investments in certain plants and transmission facilities
jointly owned with nonaffiliated utilities. Xcel Energy’s proportionate share
of jointly owned facilities is recorded as property, plant and equipment on
the consolidated balance sheets, and Xcel Energy’s proportionate share of
the operating costs associated with these facilities is included in its
consolidated statements of income.
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, 2020 up to the
date of issuance of these consolidated financial statements. These
statements contain all necessary adjustments and disclosures resulting
from that evaluation.
50
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.
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
in
Xcel Energy reports interest and penalties related to income taxes within
other (expense) income or interest charges in the consolidated statements
of income, based on the underlying nature of the transaction.
Xcel Energy Inc. and its subsidiaries file consolidated federal income tax
returns as well as consolidated or separate state income tax returns.
Federal income taxes paid by Xcel Energy Inc. are allocated to its
subsidiaries based on separate company computations. A similar allocation
is made for state income taxes paid by Xcel Energy Inc. in connection with
consolidated state filings. Xcel Energy Inc. also allocates its own income
tax benefits to its direct subsidiaries.
See Note 7 for further information.
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.
51
to
the state and
federal commissions
Xcel Energy records depreciation expense using the straight-line method
over the plant’s useful life. Actuarial life studies are performed and
submitted
for review. Upon
acceptance by the various commissions, the resulting lives and net salvage
rates are used to calculate depreciation. Plant removal costs of Xcel
Energy’s utility subsidiaries are recovered in rates as authorized by the
appropriate regulatory entities. The amount of removal costs are based on
current factors used in existing depreciation rates. Accumulated removal
costs are reflected in the consolidated balance sheet as a regulatory
liability. Depreciation expense, expressed as a percentage of average
depreciable property, was approximately 3.4% for 2020, 3.3% for 2019 and
3.1% for 2018.
See Note 3 for further information.
AROs — Xcel Energy accounts for AROs under accounting guidance that
requires a liability for the fair value of an ARO to be recognized in the
period in which it is incurred if it can be reasonably estimated, with the
offsetting associated asset retirement costs capitalized as a long-lived
asset. The liability is generally increased over time by applying the effective
interest method of accretion, and the capitalized costs are depreciated over
the useful life of the long-lived asset. Changes resulting from revisions to
the timing or amount of expected asset retirement cash flows are
recognized as an increase or a decrease in the ARO.
See Note 12 for further information.
Nuclear Decommissioning — Nuclear decommissioning studies that
estimate NSP-Minnesota’s costs of decommissioning its nuclear power
plants are performed at least every three years and submitted to the state
commissions for approval.
NSP-Minnesota recovers regulator-approved decommissioning costs of its
nuclear power plants over each facility’s expected service life, typically
based on the triennial decommissioning studies. The studies consider
estimated future costs of decommissioning and the market value of
investments in trust funds and recommend annual funding amounts.
Amounts collected in rates are deposited in the trust funds. For financial
reporting purposes, NSP-Minnesota accounts for nuclear decommissioning
as an ARO.
Restricted funds for the payment of future decommissioning expenditures
for NSP-Minnesota’s nuclear
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. If an environmental expense is related
to facilities currently in use, such as emission-control equipment, the cost is
capitalized and depreciated over the life of the plant.
Estimated remediation costs are regularly adjusted as estimates are
revised and remediation proceeds.
If other participating potentially
responsible parties exist and acknowledge their potential involvement with
a site, costs are estimated and recorded only for Xcel Energy’s expected
share of the cost.
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,
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.
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 Note 12 for further information.
See Notes 10 and 11 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
for uncollectible
bad debts. Xcel Energy establishes an allowance
receivables based on a policy that reflects its expected exposure to the
credit risk of customers.
As of Dec. 31, 2020 and 2019, the allowance for bad debts was $79 million
and $55 million, respectively.
Derivative Instruments — Xcel Energy uses derivative instruments in
connection with its interest rate, utility commodity price and commodity
trading activities, including forward contracts, futures, swaps and options.
Any derivative instruments not qualifying for the normal purchases and
normal sales exception are recorded on the consolidated balance sheets at
fair value as derivative instruments. Classification of changes in fair value
for those derivative instruments is dependent on the designation of a
qualifying hedging relationship. Changes in fair value of derivative
instruments not designated in a qualifying hedging relationship are reflected
in current earnings or as a regulatory asset or liability. Classification as a
regulatory asset or liability is based on commission approved regulatory
recovery mechanisms.
Gains or losses on commodity trading transactions are recorded as a
component of electric operating revenues and interest rate hedging
transactions are recorded as a component of interest expense.
Normal Purchases and Normal Sales — Xcel Energy enters into
contracts for purchases and sales of commodities for use in its operations.
At inception, contracts are evaluated to determine whether a derivative
exists and/or whether an instrument may be exempted from derivative
accounting if designated as a normal purchase or normal sale.
See Note 10 for further information.
Commodity Trading Operations — All applicable gains and losses
related to commodity trading activities are shown on a net basis in electric
operating revenues in the consolidated statements of income.
Commodity trading activities are not associated with energy produced from
Xcel Energy’s generation assets or energy and capacity purchased to serve
native load. Commodity trading contracts are recorded at fair market value
and commodity trading results include the impact of all margin-sharing
mechanisms.
Inventory — Inventory is recorded at average cost and consisted of the
following:
See Note 10 for further information.
Other Utility Items
(Millions of Dollars)
Inventories
Materials and supplies
Fuel
Natural gas
Total inventories
Dec. 31, 2020
Dec. 31, 2019
$
$
$
275
176
84
535
$
270
191
83
544
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.
52
Alternative Revenue — Certain rate rider mechanisms (including
decoupling and CIP/DSM programs) qualify as alternative revenue
programs. These mechanisms arise from costs imposed upon the utility by
action of a regulator or legislative body related to an environmental, public
safety or other mandate. When certain criteria are met, including expected
collection within 24 months, revenue is recognized equal to the revenue
requirement, which may include incentives and return on rate base items.
Billing amounts are revised periodically for differences between total
amount collected and revenue earned, which may increase or decrease the
level of revenue collected from customers. Alternative revenues arising
from these programs are presented on a gross basis and disclosed
separately from revenue from contracts with customers.
See Note 6 for further information.
Conservation Programs — Costs incurred for DSM and CIP programs are
deferred if it is probable future revenue will recover the incurred cost.
Revenues recognized for incentive programs for the recovery of lost
margins and/or conservation performance incentives are limited to amounts
expected to be collected within 24 months from the year they are earned.
Regulatory assets are recognized to reflect the amount of costs or earned
incentives that have not yet been collected from customers.
Emission Allowances — Emission allowances are recorded at cost,
including broker commission fees. The inventory accounting model is
utilized for all emission allowances and sales of these allowances are
included in electric revenues.
Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and
amortization method for nuclear refueling costs. This method amortizes
costs over the period between refueling outages consistent with rate
recovery.
RECs — Cost of RECs that are utilized for compliance is recorded as
electric fuel and purchased power expense. In certain jurisdictions, Xcel
Energy reduces recoverable fuel costs for the cost of RECs and records
that cost as a regulatory asset when the amount is recoverable in future
rates.
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, 2020
Dec. 31, 2019
$
47,104
7,135
2,503
677
1,877
59,296
(16,657)
2,970
(2,659)
42,950
$
$
44,355
6,560
2,341
259
2,329
55,844
(16,735)
2,909
(2,535)
39,483
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 and 2 for NSP-Minnesota. Also includes SPS’
expected retirement of Tolk and conversion of Harrington to natural gas, and PSCo’s
planned retirement of jointly owned Craig Unit 2.
Joint Ownership of Generation, Transmission and Gas Facilities
The utility subsidiaries’ jointly owned assets as of Dec. 31, 2020:
Plant in
Service
Accumulated
Depreciation
CWIP
Percent
Owned
(Millions of Dollars, Except
Percent Owned)
NSP-Minnesota
Electric generation:
Sherco Unit 3
Sherco common facilities
Sherco substation
Electric transmission:
Grand Meadow
CapX2020
Total NSP-Minnesota
$
$
601
149
5
11
954
1,720
$
$
435
108
3
3
108
657
$
$
2
5
—
—
33
40
59 %
80
59
50
51
(Millions of Dollars, Except
Percent Owned)
NSP-Wisconsin
Electric transmission:
Plant in
Service
Accumulated
Depreciation
CWIP
Percent
Owned
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.
La Crosse, WI to Madison, WI
CapX2020
Total NSP-Wisconsin
$
$
188
169
357
$
$
12
23
35
$
$
—
—
—
37 %
80
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.
Plant in
Service
Accumulated
Depreciation
CWIP
Percent
Owned
(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:
$
$
153
150
42
81
39
899
25
176
Rifle, CO to Avon, CO
Gas transmission compressor
Total PSCo
22
8
1,595
$
$
92
73
25
44
24
137
2
59
8
1
465
$
—
—
—
—
—
16
—
76 %
37
53
10
7
67
82
2
Various
—
—
18
$
60
50
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.
53
4. Regulatory Assets and Liabilities
Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future
electric and natural gas rates. Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in net income or other
comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP.
Components of regulatory assets:
(Millions of Dollars)
Regulatory Assets
Pension and retiree medical obligations
Recoverable deferred taxes on AFUDC
Excess deferred taxes — TCJA
Depreciation differences
Net AROs (a)
Environmental remediation costs
Benson biomass PPA termination and asset purchase
Purchased power contract costs
PI extended power uprate
Contract valuation adjustments (b)
Losses on reacquired debt
Laurentian biomass PPA termination
Conservation programs (c)
State commission adjustments
Sales true-up and revenue decoupling
Property tax
Deferred purchased natural gas and electric energy costs
Texas revenue surcharge
Renewable resources and environmental initiatives
Nuclear refueling outage costs
Gas pipeline inspection and remediation costs
Other
Total regulatory assets
See Note(s)
Remaining Amortization
Period
Dec. 31, 2020
Dec. 31, 2019
Current
Noncurrent
Current
Noncurrent
11
1, 12
1, 12
1, 10
7
Various
Plant lives
Various
One to 11 years
Various
Various
Nine years
Term of related contract
14 years
Term of related contract
Term of related debt
Three years
1 One to two years
Plant lives
One to two years
Various
One to two years
One to two years
One to two years
1 One to two years
One to two years
Various
$
$
82
—
16
16
—
16
10
7
3
23
4
18
26
1
101
16
14
54
129
28
26
50
640
$
$
1,268
283
229
154
139
113
65
54
49
48
38
36
36
32
28
21
18
17
12
10
9
78
2,737
$
$
85
—
39
15
—
36
9
5
3
20
4
19
27
1
54
2
6
2
72
43
26
20
488
$
$
1,328
271
239
140
269
131
73
61
53
62
41
54
26
31
16
30
6
—
10
17
8
69
2,935
(a)
Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
(b)
Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
(c)
Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
Components of regulatory liabilities:
(Millions of Dollars)
Regulatory Liabilities
Deferred income tax adjustments and TCJA refunds (a)
Plant removal costs
Effects of regulation on employee benefit costs (b)
Renewable resources and environmental initiatives
ITC deferrals
Revenue decoupling
Deferred electric, natural gas and steam production costs
Conservation programs (c)
DOE settlement
Contract valuation adjustments (d)
Other
Total regulatory liabilities (e)
See Note(s)
Remaining Amortization
Period
7
1, 12
1
1
1, 10
Various
Various
Various
Various
Various
One to two years
Less than one year
Less than one year
Less than one year
Less than one year
Various
Dec. 31, 2020
Dec. 31, 2019
Current
Noncurrent
Current
Noncurrent
$
$
20
—
—
5
—
10
84
49
23
19
101
311
$
$
3,368
1,520
221
59
51
41
—
—
—
—
42
5,302
$
$
75
—
—
—
—
—
138
37
37
19
101
407
$
$
3,523
1,217
196
45
38
—
—
—
—
—
58
5,077
(a)
(b)
(c)
(d)
(e)
Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.
Includes regulatory amortization and certain 2018 TCJA benefits approved by the CPUC to offset the PSCo prepaid pension asset.
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.
Revenue subject to refund of $17 million and $28 million for 2020 and 2019, respectively, is included in other current liabilities.
At Dec. 31, 2020 and 2019, Xcel Energy’s regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical
obligations and net AROs. In addition, regulatory assets included $812 million and $544 million at Dec. 31, 2020 and 2019, respectively, of past
expenditures not earning a return. Amounts are related to funded pension obligations, sales true-up and revenue decoupling, purchased natural gas and
electric energy costs, various renewable resources and certain environmental initiatives.
54
5. Borrowings and Other Financing Instruments
Short-Term Borrowings
liquidity
Short-Term Debt — Xcel Energy meets
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,
2020
Year Ended Dec. 31
2020
2019
2018
Borrowing limit
$
3,100
$ 3,100
$ 3,600
$ 3,250
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
584
415
613
584
1,126
2,080
595
1,115
1,780
1,038
788
1,349
0.60 %
1.45 %
2.72 %
2.34 %
0.23
0.23
2.34
2.97
Term Loan Agreements — In December 2020, Xcel Energy Inc. repaid its
$500 million Term Loan Agreement that was entered into December 2018.
In September 2020, Xcel Energy Inc. repaid its $700 million Term Loan
Agreement that was entered into March 2020. As of Dec. 31, 2020, Xcel
Energy Inc. has no open loan agreement.
Bilateral Credit Agreement — In March 2019, NSP-Minnesota entered
into a one-year uncommitted bilateral credit agreement. The agreement is
limited in use to support letters of credit. In March 2020, NSP-Minnesota
renewed its bilateral credit agreement for an additional one-year term.
As of Dec. 31, 2020, outstanding letters of credit under the Bilateral Credit
Agreement were as follows:
(Millions of Dollars)
Limit
Amount
Outstanding
Available
NSP-Minnesota
$
75
$
49
$
26
to provide
Letters of Credit — Xcel Energy uses letters of credit, typically with terms
for certain operating
of one year,
obligations. As of Dec. 31, 2020 and 2019, there were $20 million of letters
of credit outstanding under the credit facilities. Amounts approximate their
fair value.
financial guarantees
Credit Facilities — In order to use commercial paper programs to fulfill
short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must
have revolving credit facilities in place at least equal to the amount of their
respective commercial paper borrowing limits and cannot issue commercial
paper in an aggregate amount exceeding available capacity under these
credit facilities. The lines of credit provide short-term financing in the form
of notes payable to banks, letters of credit and back-up support for
commercial paper borrowings.
Terms of Credit Agreements — In June 2019, Xcel Energy Inc., NSP-
Minnesota, NSP-Wisconsin, PSCo and SPS entered into amended five-
year credit agreements with a syndicate of banks. The total borrowing limit
under the amended credit agreements is $3.1 billion, with a swingline
subfacility for Xcel Energy up to $75 million. The amended credit
agreements mature in June 2024.
Features of the credit facilities:
Amount
Facility May Be
Increased
(millions)
Additional Periods
for Which a One-Year
Extension May Be
Requested (b)
Debt-to-Total
Capitalization Ratio(a)
2020
2019
Xcel Energy Inc. (c)
NSP-Wisconsin
NSP-Minnesota
SPS
PSCo
59 %
46
47
48
44
58 % $
48
48
46
44
200
N/A
100
50
100
2
1
2
2
2
(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, 2020, Xcel Energy Inc. and its subsidiaries were in
compliance with all financial covenants.
Xcel Energy Inc. and its utility subsidiaries had the following committed
credit facilities available as of Dec. 31, 2020:
(Millions of Dollars)
Xcel Energy Inc.
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Total
Credit Facility (a)
1,250
$
700
500
500
150
3,100
$
$
$
Drawn (b)
Available
—
144
189
252
19
604
$
$
1,250
556
311
248
131
2,496
(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, 2020 and 2019.
Long-Term Borrowings and Other Financing Instruments
Generally, all property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
are subject to the liens of their first mortgage indentures. Debt premiums,
discounts and expenses are amortized over the life of the related debt. The
premiums, discounts and expenses for refinanced debt are deferred and
amortized over the life of the new issuance.
55
NSP-Wisconsin
Interest
Rate
Maturity Date
2020
2019
6.00 %
Nov 1, 2021
$
19
$
3.30
3.30
6.38
3.70
3.75
4.20
3.05
June 15, 2024
June 15, 2024
Sept. 1, 2038
Oct. 1, 2042
Dec. 1, 2047
Sept. 1, 2048
May 1, 2051
100
100
200
100
100
200
100
(4)
(9)
(19)
19
100
100
200
100
100
200
—
(3)
(8)
—
$
887
$
808
Financing Instrument
City of La Crosse resource
recovery bond
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds (a)
Unamortized discount
Unamortized debt issuance cost
Current maturities
Total long-term debt
(a)
2020 financing.
Financing Instrument
PSCo
Interest
Rate
Maturity Date
2020
2019
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds (a)
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds (b)
First mortgage bonds (b)
First mortgage bonds (a)
Unamortized discount
Unamortized debt issuance cost
Current maturities
Total long-term debt
(a)
2020 financing.
(b)
2019 financing.
3.20 %
Nov. 15, 2020
$
—
$
2.25
2.50
2.90
3.70
1.90
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. 15, 2022
March 15, 2023
May 15, 2025
June 15, 2028
Jan. 15, 2031
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
300
250
250
350
375
350
300
250
500
250
300
250
400
350
400
550
375
(30)
(46)
—
400
300
250
250
350
—
350
300
250
500
250
300
250
400
350
400
550
—
(24)
(41)
(400)
$
5,724
$
4,985
Long-term debt obligations for Xcel Energy Inc. and its utility subsidiaries
as of Dec. 31 (Millions of Dollars):
Xcel Energy Inc.
Financing Instrument
Interest
Rate
Maturity Date
2020
2019
2.40 % March 15, 2021
$
400
$
2.60
0.50
3.30
3.30
3.35
4.00
4.00
2.60
3.40
6.50
4.80
3.50
March 15, 2022
Oct. 15, 2023
June 1, 2025
June 1, 2025
Dec. 1, 2026
June 15, 2028
June 15, 2028
Dec. 1, 2029
June 1, 2030
July 1, 2036
Sept. 15, 2041
Dec. 1, 2049
—
500
250
350
500
130
500
500
600
300
250
500
(7)
(32)
(400)
400
300
—
250
350
500
130
500
500
—
300
250
500
(5)
(28)
—
$
4,341
$
3,947
Unsecured senior notes
Unsecured senior notes (c)
Unsecured senior notes (a)
Unsecured senior notes
Unsecured senior notes
Unsecured senior notes
Unsecured senior notes (b)
Unsecured senior notes
Unsecured senior notes (b)
Unsecured senior notes (a)
Unsecured senior notes
Unsecured senior notes
Unsecured senior notes (b)
Unamortized discount
Unamortized debt issuance cost
Current maturities
Total long-term debt
(a)
2020 financing.
(b)
(c)
2019 financing.
Note was redeemed on Dec. 1, 2020.
NSP-Minnesota
Financing Instrument
Interest
Rate
Maturity Date
2020
2019
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds (b)
First mortgage bonds (a)
Unamortized discount
Unamortized debt issuance cost
Current maturities
Total long-term debt
(a)
2020 financing.
(b)
2019 financing.
2.20 %
Aug. 15, 2020
$
—
$
2.15
2.60
7.13
6.50
5.25
6.25
6.20
5.35
4.85
3.40
4.13
4.00
3.60
3.60
2.90
2.60
Aug. 15, 2022
May 15, 2023
July 1, 2025
March 1, 2028
July 15, 2035
June 1, 2036
July 1, 2037
Nov. 1, 2039
Aug. 15, 2040
Aug. 15, 2042
May 15, 2044
Aug. 15, 2045
May 15, 2046
Sept. 15, 2047
March 1, 2050
June 1, 2051
300
400
250
150
250
400
350
300
250
500
300
300
350
600
600
700
300
300
400
250
150
250
400
350
300
250
500
300
300
350
600
600
—
(42)
(54)
—
5,904
$
(31)
(48)
(300)
$
5,221
56
Financing Instrument
SPS
Interest
Rate
Maturity Date
2020
2019
First mortgage bonds
First mortgage bonds
Unsecured senior notes
Unsecured senior notes
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds
First mortgage bonds (b)
First mortgage bonds (a)
Unamortized discount
Unamortized debt issuance cost
Total long-term debt
(a)
(b)
2020 financing.
2019 financing.
3.30 %
June 15, 2024
$
150
$
3.30
6.00
6.00
4.50
4.50
4.50
3.40
3.70
4.40
3.75
3.15
June 15, 2024
Oct. 1, 2033
Oct. 1, 2036
Aug. 15, 2041
Aug. 15, 2041
Aug. 15, 2041
Aug. 15, 2046
Aug. 15, 2047
Nov. 15, 2048
June 15, 2049
May 1, 2050
200
100
250
200
100
100
300
450
300
300
350
(10)
(26)
150
200
100
250
200
100
100
300
450
300
300
—
(7)
(23)
$
2,764
$
2,420
Other Subsidiaries
Interest
Rate
0.00% -
6.90%
Financing Instrument
Various Eloigne affordable
housing project notes
Current maturities
Total long-term debt
Maturities of long-term debt:
(Millions of Dollars)
2021
2022
2023
2024
2025
Maturity Date
2020
2019
2021 — 2054
$
27
$
(2)
$
25
$
$
28
(2)
26
421
601
1,151
552
1,102
Deferred Financing Costs — Deferred financing costs of approximately
$167 million and $148 million, net of amortization, are presented as a
deduction from the carrying amount of long-term debt as of Dec. 31, 2020
and 2019, respectively.
Forward Equity Agreements — In November 2018, Xcel Energy Inc.
entered into forward equity agreements for a $459 million public offering of
9.4 million shares of Xcel Energy common stock. In August 2019, Xcel
Energy settled the forward equity agreements by delivering 9.4 million
shares of common equity for cash proceeds of $453 million.
Inc. entered
In November 2019, Xcel Energy
forward equity
agreements for a $743 million public offering of 11.8 million shares of Xcel
Energy common stock. In November 2020, Xcel Energy settled the forward
equity agreements by delivering 11.8 million shares of common equity for
cash proceeds of $721 million.
into
Other Equity — Xcel Energy issued $40 million and $39 million of equity
annually through the DRIP program during the years ended Dec. 31, 2020
and 2019 respectively. The program allows stockholders to elect dividend
through a non-cash
reinvestment
to share based
transaction. See Note 8
compensation.
in Xcel Energy common stock
items related
for equity
Capital Stock — Preferred stock authorized/outstanding:
Preferred Stock
Authorized
(Shares)
Par Value of
Preferred Stock
Preferred Stock
Outstanding (Shares)
2020 and 2019
Xcel Energy Inc.
7,000,000
$
PSCo
SPS
10,000,000
10,000,000
100
0.01
1.00
—
—
—
Xcel Energy Inc. had the following common stock authorized/outstanding:
Common Stock
Authorized (Shares)
Par Value of
Common Stock
Common Stock
Outstanding
(Shares) as of
Dec. 31, 2020
Common Stock
Outstanding
(Shares) as of
Dec. 31, 2019
1,000,000,000
$
2.50
537,438,394
524,539,000
Dividend and Other Capital-Related Restrictions — Xcel Energy
depends on its utility subsidiaries to pay dividends. Xcel Energy Inc.’s utility
subsidiaries’ dividends are subject to the FERC’s jurisdiction, which
prohibits the payment of dividends out of capital accounts. Dividends are
solely to be paid from retained earnings. Certain covenants also require
Xcel Energy Inc. to be current on interest payments prior to dividend
disbursements.
State regulatory commissions
for NSP-
Minnesota, NSP-Wisconsin and SPS, which are more restrictive than those
imposed by the FERC. Requirements and actuals as of Dec. 31, 2020:
impose dividend
limitations
Equity to Total
Capitalization Ratio
Required Range
Equity to Total
Capitalization Ratio
Actual
Low
High
2020
47.1 %
52.5
45.0
57.5 %
N/A
55.0
52.7 %
52.8
54.4
NSP-Minnesota
NSP-Wisconsin
SPS (a)
(a)
Excludes short-term debt.
(Amounts in
Millions)
NSP-Minnesota
NSP-Wisconsin (a)
SPS (b)
Unrestricted Retained
Earnings
Total
Capitalization
Limit on Total
Capitalization
$
1,356
$
12,853
$
13,200
7
510
1,940
6,062
N/A
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, 2020:
(Millions of Dollars)
Long-Term Debt
Short-Term Debt
NSP-Minnesota
NSP-Wisconsin
SPS
$
52.93% of total
capitalization
(a)
$
250
—
(b)
1,450
(a)
1,980
150
600
800
NSP-Minnesota has authorization to issue long-term securities provided the equity-to-
total capitalization remains within the required range, and to issue short-term debt
provided it does not exceed 15% of total capitalization.
SPS filed for additional long-term debt authorization in December 2020.
PSCo
(a)
(b)
57
6. Revenues
7. Income Taxes
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, 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
$
4,596
125
7,787
759
579
73
9,198
604
$
975
462
—
1,437
—
—
137
1,574
62
Total revenues
$
9,802
$
1,636
$
42
27
6
75
—
—
—
75
13
88
$
4,083
5,085
131
9,299
759
579
210
10,847
679
$ 11,526
Federal Loss Carryback Claims - In 2020, Xcel Energy identified certain
expense related to tax years 2009 - 2011 that qualify for an extended
carryback claim. As a result, a tax benefit of approximately $13 million was
recognized in 2020.
Federal Audit — Statute of limitations applicable to Xcel Energy’s
consolidated federal income tax returns:
Tax Year(s)
2014 - 2016
Expiration
July 2021
Additionally, the statute of limitations related to the federal tax loss
carryback claim referenced above has been extended. Xcel Energy has
recognized its best estimate of income tax expense that will result from a
final resolution of this issue; however, the outcome and timing of a
resolution is unknown.
In 2017, the IRS concluded the audit of tax years 2012 and 2013 and
proposed an adjustment that would impact Xcel Energy’s NOL and ETR.
Xcel Energy file a protest with the IRS. In April 2020, Xcel Energy and
Appeals reached an agreement and no material adjustments were required.
Year Ended Dec. 31, 2019
Electric
Natural
Gas
All Other
Total
In 2018, the IRS began an audit of tax years 2014 - 2016. In July 2020,
Xcel Energy and the IRS reached an agreement and the related benefit
was recognized.
(Millions of Dollars)
Major revenue types
Revenue from contracts with customers:
Residential
C&I
Other
Total retail
Wholesale
Transmission
Other
Total revenue from
contracts with customers
Alternative revenue and other
$
2,877
$
1,127
$
4,844
130
7,851
737
507
49
9,144
431
567
—
1,694
—
—
120
1,814
54
Total revenues
$
9,575
$
1,868
$
41
29
4
74
—
—
—
74
12
86
$
4,045
5,440
134
9,619
737
507
169
11,032
497
$ 11,529
(Millions of Dollars)
Major revenue types
Year Ended Dec. 31, 2018
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
$
2,919
$
4,874
134
7,927
791
523
98
9,339
380
$
988
524
—
1,512
—
—
100
1,612
127
Total revenues
$
9,719
$
1,739
$
38
25
6
69
—
—
—
69
10
79
$
3,945
5,423
140
9,508
791
523
198
11,020
517
$ 11,537
State Audits — Xcel Energy files consolidated state tax returns based on
income in its major operating jurisdictions and various other state income-
based tax returns.
As of Dec. 31, 2020, Xcel Energy’s earliest open tax years (subject to
examination by state taxing authorities in its major operating jurisdictions)
were as follows:
State
Colorado
Minnesota
Texas
Wisconsin
Year
2009
2009
2012
2014
•
•
•
In 2018, Wisconsin began an audit of tax years 2014 - 2016. As of
Dec. 31, 2020, no material adjustments have been proposed.
In July 2020, Minnesota began a review of the 2015 - 2018 Research
and Experimentation Credits. As of Dec. 31, 2020, no material
adjustments have been proposed.
Xcel Energy had no other state income tax audits in progress for its
major operating jurisdictions as of Dec. 31, 2020.
Unrecognized Tax Benefits — Unrecognized tax benefit balance includes
permanent tax positions, which if recognized would affect the annual ETR.
In addition, the unrecognized tax benefit balance includes temporary tax
positions for which the ultimate deductibility is highly certain, but for which
there is uncertainty about the timing of such deductibility. A change in the
period of deductibility would not affect the ETR but would accelerate the
payment to the taxing authority to an earlier period.
Unrecognized tax benefits - permanent vs. temporary:
(Millions of Dollars)
Dec. 31, 2020
Dec. 31, 2019
Unrecognized tax benefit — Permanent tax positions
Unrecognized tax benefit — Temporary tax positions
Total unrecognized tax benefit
$
$
41
11
52
$
$
35
9
44
58
2020
2019
2018
21.0 %
21.0 %
21.0 %
4.9
4.9
5.0
(15.7)
(7.6)
(1.2)
(0.9)
0.5
(1.4)
(0.4) %
(9.4)
(5.8)
(1.7)
—
0.5
(1.0)
8.5 %
(5.2)
(6.2)
(1.7)
—
0.4
(0.7)
12.6 %
Changes in unrecognized tax benefits:
Effective income tax rate for years ended Dec. 31:
(Millions of Dollars)
Balance at Jan. 1
2020
2019
2018
$ 44
$ 37
$ 39
Federal statutory rate
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
Settlements with taxing authorities
Balance at Dec. 31
9
(2)
35
10
(4)
1
(34)
—
—
—
9
(4)
2
(4)
(5)
$ 52
$ 44
$ 37
State income tax on pretax income, net of federal tax
effect
Increases (decreases) in tax from:
Wind PTCs
Plant regulatory differences (a)
Other tax credits, net NOL & tax credit allowances
Unrecognized tax benefits were reduced by tax benefits associated with
NOL and tax credit carryforwards:
(Millions of Dollars)
Dec. 31, 2020
Dec. 31, 2019
NOL and tax credit carryforwards
$
(31) $
(40)
Net deferred tax liability associated with the unrecognized tax benefit
amounts and related NOLs and tax credits carryforwards were $19 million
and $29 million at Dec. 31, 2020 and Dec. 31, 2019, respectively.
As the IRS audit resumes and state audits progress, it is reasonably
possible that the amount of unrecognized tax benefit could decrease up to
approximately $27 million in the next 12 months.
Payable for interest related to unrecognized tax benefits is partially offset
by the interest benefit associated with NOL and tax credit carryforwards.
Interest payable related to unrecognized tax benefits:
NOL Carryback
Change in unrecognized tax benefits
Other, net
Effective income tax rate
(a)
Regulatory differences for income tax primarily relate to the credit of excess deferred
taxes to customers through the average rate assumption method. Income tax benefits
associated with the credit of excess deferred credits are offset by corresponding
revenue reductions and additional prepaid pension asset amortization.
Components of income tax expense for years ended Dec. 31:
(Millions of Dollars)
Current federal tax benefit
Current state tax expense
Current change in unrecognized tax expense (benefit)
Deferred federal tax (benefit) expense
Deferred state tax expense
Deferred change in unrecognized tax (benefit) expense
2020
2019
2018
$
(13) $
(16) $
(34)
2
18
(89)
91
(10)
(5)
4
2
55
83
5
(5)
8
(6)
122
85
11
(5)
(Millions of Dollars)
2020
2019
2018
Deferred ITCs
Payable for interest related to unrecognized
tax benefits at Jan. 1
Interest expense related to unrecognized tax
benefits
$
—
$
—
$
(3)
—
Payable for interest related to unrecognized
tax benefits at Dec. 31
$
(3) $
—
$
—
—
—
No amounts were accrued for penalties related to unrecognized tax
benefits as of Dec. 31, 2020, 2019 or 2018.
Other Income Tax Matters — NOL amounts represent the tax loss that is
carried forward and tax credits represent the deferred tax asset. NOL and
tax credit carryforwards as of Dec. 31:
Total income tax (benefit) expense
$
(6) $
128
$
181
Components of deferred income tax expense as of Dec. 31:
(Millions of Dollars)
2020
2019
2018
Deferred tax expense excluding items below
$
237
$
344
$
320
Amortization and adjustments to deferred income taxes
on income tax regulatory assets and liabilities
Tax expense allocated to other comprehensive income,
adoption of ASC Topic 326, adoption of ASU No.
2018-02, and other
Deferred tax (benefit) expense
(247)
(206)
(102)
2
5
—
$
(8) $
143
$
218
(Millions of Dollars)
Federal tax credit carryforwards
State NOL carryforwards
Valuation allowances for state NOL carryforwards
State tax credit carryforwards, net of federal detriment (a)
2020
2019
$
$
791
839
(4)
89
639
937
(19)
89
(64)
(66)
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,
2020 and 2019.
(b)
Valuation allowances for state tax credit carryforwards were net of federal benefit of $17
million as of Dec. 31, 2020 and 2019.
Federal carryforward periods expire between 2031 and 2040 and state
carryforward periods expire starting 2021.
Total income tax expense from operations differs from the amount
computed by applying the statutory federal income tax rate to income
before income tax expense.
59
Components of net deferred tax liability as of Dec. 31:
(Millions of Dollars)
Deferred tax liabilities:
Differences between book and tax bases of property
Operating lease assets
Regulatory assets
Pension expense
Other
Total deferred tax liabilities
Deferred tax assets:
Regulatory liabilities
Operating lease liabilities
Tax credit carryforward
NOL carryforward
NOL and tax credit valuation allowances
Other employee benefits
Deferred ITCs
Rate refund
Other
Total deferred tax assets
Net deferred tax liability
8. Share-Based Compensation
2020
2019
$ 5,810
400
603
176
74
$ 7,063
$ 5,474
449
598
173
70
$ 6,764
$ 806
400
880
37
(64)
141
13
16
88
$ 2,317
$ 4,746
$
847
449
727
38
(67)
128
14
26
93
$ 2,255
$ 4,509
Incentive Plan Including Share-Based Compensation — Xcel Energy
has an incentive plan which includes share-based payment elements, the
Amended and Restated 2015 Omnibus Incentive Plan with 7.0 million
equity shares authorized.
Restricted Stock — The Amended and Restated 2015 Omnibus Incentive
Plan allows certain employees to elect to receive shares of common or
restricted stock. Restricted stock is treated as an equity award and vests
and settles in equal annual installments over a three-year period. Restricted
stock has a fair value equal to the market trading price of Xcel Energy stock
at the grant date.
Shares of restricted stock granted at Dec. 31:
(Shares in Thousands)
Granted shares
Grant date fair value
2020
2019
2018
$
1
70.26
$
13
53.46
$
18
44.68
Changes in nonvested restricted stock:
(Shares in Thousands)
Nonvested restricted stock at Jan. 1, 2020
Granted
Forfeited
Vested
Dividend equivalents
Nonvested restricted stock at Dec. 31, 2020
Shares
Weighted Average
Grant Date Fair Value
$
31
1
(3)
(15)
1
15
50.15
70.26
44.68
46.41
66.96
56.68
Other Equity Awards — Xcel Energy‘s Board of Directors has granted
equity awards under the Amended and Restated 2015 Omnibus Incentive
Plan, which includes various vesting conditions and performance goals. At
the end of the restricted period, such grants will be awarded if vesting
conditions and/or performance goals are met.
Certain employees are granted equity awards with a portion subject only to
service conditions, and the other portion subject to performance conditions.
A total of 0.2 million, 0.3 million, and 0.3 million time-based equity shares
subject only to service conditions were granted annually in 2020, 2019 and
2018, respectively.
The performance conditions for a portion of the awards granted from 2018
to 2020 are based on relative TSR and environmental goals. Equity awards
with performance conditions will be settled or forfeited after three years,
with payouts ranging from zero to 200 percent depending on achievement.
Equity award units granted to employees (excluding restricted stock):
(Units in Thousands)
2020
2019
2018
Granted units
411
483
500
Weighted average grant date
fair value
Equity awards vested:
(Units in Thousands, Fair
Value in Millions)
$
62.92
$
49.67
$
47.60
2020
2019
2018
Vested Units
Total Fair Value
$
442
29
$
464
29
$
475
23
Changes in the nonvested portion of equity award units:
(Units in Thousands)
Units
Nonvested Units at Jan. 1, 2020
880
$
Granted
Forfeited
Vested
Dividend equivalents
Nonvested Units at Dec. 31, 2020
411
(101)
(442)
32
780
Weighted Average
Grant Date Fair Value
48.20
62.92
53.87
47.63
51.56
55.68
Stock Equivalent Units — Non-employee members of Xcel Energy‘s
Board of Directors may elect to receive their annual equity grant as stock
equivalent units in lieu of common stock. Each unit’s value is equal to one
share of common stock. The annual equity grant is vested as of the date of
each member’s election to the Board of Directors; there is no further
service or other condition. Directors may also elect to receive their cash
fees as stock equivalent units in lieu of cash. Stock equivalent units are
payable as a distribution of common stock upon a director’s termination of
service.
Stock equivalent units granted:
(Units in Thousands)
2020
2019
2018
Granted units
Weighted average grant date
fair value
33
29
36
$
61.61
$
58.44
$
45.44
Changes in stock equivalent units:
(Units in Thousands)
Stock equivalent units at Jan. 1, 2020
Granted
Units distributed
Dividend equivalents
Stock equivalent units at Dec. 31, 2020
Units
Weighted Average
Grant Date Fair Value
$
725
33
(146)
18
630
32.72
61.61
28.16
67.44
36.28
TSR Liability Awards — Xcel Energy Inc.’s Board of Directors has granted
TSR liability awards under the Amended and Restated 2015 Omnibus
Incentive Plan. This plan allows Xcel Energy to attach various performance
goals to the awards granted. The liability awards have been historically
dependent on relative TSR measured over a three-year period. Xcel
Energy Inc.’s TSR is compared to a peer group of other utility companies.
Potential payouts of the awards range from zero to 200%.
60
TSR liability awards granted:
(In Thousands)
Awards granted
2020
2019
2018
212
225
239
TSR liability awards settled:
(Units In Thousands, Settlement
Amount in Millions)
Awards settled
Settlement amount (cash, common stock
and deferred amounts)
2020
2019
2018
476
466
$
33
$
25
$
482
22
TSR liability awards of $27 million were settled in cash in 2020.
Share-Based Compensation Expense — Other than for restricted stock,
vesting of employee equity awards
the
achievement of a TSR or environmental measures target. Additionally,
approximately 0.2 million, 0.3 million, and 0.3 million of equity award units
were granted in 2020, 2019, and 2018, respectively, with vesting subject
only to service conditions of three years.
typically predicated on
is
Generally, these instruments are considered to be equity awards as the
award settlement determination (shares or cash) is made by Xcel Energy,
not the participants. In addition, these awards have not been previously
settled in cash and Xcel Energy plans to continue electing share
settlement.
Grant date fair value of equity awards is expensed over the service period.
TSR liability awards have been historically settled partially in cash, and do
not qualify as equity awards, but rather are accounted for as liabilities. As
liability awards, the fair value on which ratable expense is based, as
employees vest in their rights to those awards, is remeasured each period
based on the current stock price and performance achievement, and final
expense is based on the market value of the shares on the date the award
is settled.
Compensation costs related to share-based awards:
(Millions of Dollars)
Compensation cost for share-based awards (a)
Tax benefit recognized in income
(a)
2020
2019
2018
$
$
73
19
$
58
15
45
12
Compensation costs for share-based payments are included in O&M expense.
There was approximately $51 million in 2020 and $40 million in 2019 of
total unrecognized compensation cost related to nonvested share-based
compensation awards. Xcel Energy expects to recognize the unrecognized
amount over a weighted average period of 1.7 years.
9. Earnings Per Share
Basic EPS was computed by dividing the earnings available to common
shareholders by the weighted average number of common shares
outstanding during the period. Diluted EPS was computed by dividing the
earnings available to common shareholders by the diluted weighted
average number of common shares outstanding during the period. Diluted
EPS reflects the potential dilution that could occur if securities or other
agreements to issue common stock (i.e., common stock equivalents) were
settled. The weighted average number of potentially dilutive shares
outstanding used to calculate diluted EPS is calculated using the treasury
stock method.
Common Stock Equivalents — Xcel Energy Inc. has common stock
equivalents related to forward equity agreements and certain equity awards
in share-based compensation arrangements. Common stock equivalents
include commitments to issue common stock related to time-based equity
compensation awards.
61
Stock equivalent units granted to Xcel Energy’s Board of Directors are
included in common shares outstanding upon grant date as there is no
further service, performance or market condition associated with these.
Restricted stock issued to employees under the Executive Annual Incentive
Award Plan is included in common shares outstanding when granted.
Share-based compensation arrangements for which there is currently no
dilutive impact to EPS include the following:
•
•
Equity awards subject to a performance condition; included in
common shares outstanding when all necessary conditions for
settlement have been satisfied by the end of the reporting period.
Liability awards subject to a performance condition; any portions
settled in shares are included in common shares outstanding upon
settlement.
Diluted common shares outstanding included common stock equivalents of
1.1 million, 1.3 million and 0.5 million shares for 2020, 2019 and 2018,
respectively.
10. Fair Value of Financial Assets and Liabilities
Fair Value Measurements
Accounting guidance for fair value measurements and disclosures provides
a single definition of fair value and requires disclosures about assets and
liabilities measured at fair value. A hierarchical framework for disclosing the
observability of the inputs utilized in measuring assets and liabilities at fair
value is established by this guidance.
•
•
•
Level 1 — Quoted prices are available in active markets for identical
assets or liabilities as of the reporting date. The types of assets and
liabilities included in Level 1 are highly liquid and actively traded
instruments with quoted prices.
Level 2 — Pricing inputs are other than quoted prices in active
markets but are either directly or indirectly observable as of the
reporting date. The types of assets and liabilities included in Level 2
are typically either comparable to actively traded securities or
contracts or priced with models using highly observable inputs.
Level 3 — Significant inputs to pricing have little or no observability as
of the reporting date. The types of assets and liabilities included in
Level 3 are
requiring significant
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
NSP-Minnesota recognizes the costs of funding the decommissioning over
the lives of the nuclear plants, assuming rate recovery of all costs. Realized
and unrealized gains on fund investments over the life of the fund are
deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear
decommissioning costs. Consequently, any realized and unrealized gains
and losses on securities in the nuclear decommissioning fund are deferred
as a component of the regulatory asset.
Unrealized gains for the nuclear decommissioning fund were $981 million
and $706 million as of Dec. 31, 2020 and 2019, respectively, and
unrealized losses were $5 million and $6 million as of Dec. 31, 2020 and
2019, respectively.
Non-derivative instruments with recurring fair value measurements:
Dec. 31, 2020
Fair Value
(Millions of Dollars)
Nuclear decommissioning fund (a)
Cost
Level 1
Level 2
Level 3
NAV
Total
$ —
$ —
$ —
$
40
Cash equivalents
$
40
$
Commingled funds
Debt securities
787
528
40
—
—
Equity securities
446
1,109
—
572
2
—
13
—
13
1,041
—
—
1,041
585
1,111
$ 1,041
$ 2,777
Total
$ 1,801
$ 1,149
$
574
$
(a)
Reported in nuclear decommissioning fund and other investments on the consolidated
balance sheet, which also includes $165 million of equity investments in unconsolidated
subsidiaries and $154 million of rabbi trust assets and miscellaneous investments.
Dec. 31, 2019
Fair Value
(Millions of Dollars)
Nuclear decommissioning fund (a)
Cost
Level 1
Level 2
Level 3
NAV
Total
Cash equivalents
$
33
$
Commingled funds
Debt securities
Equity securities
733
489
485
33
—
—
962
—
495
2
$ —
$ —
$ —
$
33
935
508
964
935
—
—
—
13
—
13
Total
$ 1,740
$
995
$
497
$
$
935
$ 2,440
(a)
Reported in nuclear decommissioning fund and other investments on the consolidated
balance sheet, which also includes $155 million of equity investments in unconsolidated
subsidiaries and $136 million of rabbi trust assets and miscellaneous investments.
For the years ended Dec. 31, 2020 and 2019, there were immaterial Level
3 nuclear decommissioning fund investments or transfer of amounts
between levels.
Contractual maturity dates of debt securities
decommissioning fund as of Dec. 31, 2020:
in
the nuclear
Final Contractual Maturity
(Millions of Dollars)
Due in 1
year or
Less
Due in 1 to
5 Years
Due in 5 to
10 Years
Due after
10 years
Total
Debt securities
$
1
$
116
$
211
$
257
$
585
Investments in debt securities — Fair values for debt securities are
determined by a third-party pricing service using recent trades and
observable spreads from benchmark interest rates for similar securities.
Interest rate derivatives — Fair values of interest rate derivatives are
based on broker quotes that utilize current market interest rate forecasts.
Commodity derivatives — Methods used to measure the fair value of
commodity derivative forwards and options utilize forward prices and
volatilities, as well as pricing adjustments for specific delivery locations, and
are generally assigned a Level 2 classification. When contractual
settlements relate to inactive delivery locations or extend to periods beyond
those readily observable on active exchanges or quoted by brokers, the
significance of the use of less observable forecasts of forward prices and
volatilities on a valuation is evaluated and may result in Level 3
classification.
Electric commodity derivatives held by NSP-Minnesota and SPS include
transmission congestion instruments, generally referred to as FTRs. FTRs
purchased from a RTO are financial instruments that entitle or obligate the
holder to monthly revenues or charges based on transmission congestion
across a given transmission path.
to overall
In addition
The value of an FTR is derived from, and designed to offset, the cost of
transmission congestion.
load,
congestion is also influenced by the operating schedules of power plants
and the consumption of electricity pertinent to a given transmission path.
Unplanned plant outages, scheduled plant maintenance, changes in the
relative costs of fuels used in generation, weather and overall changes in
demand for electricity can each impact the operating schedules of the
power plants on the transmission grid and the value of an FTR.
transmission
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.
62
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, 2020
Fair Value
Cost
Level 1
Level 2
Level 3
Total
$
$
32
60
92
$
$
$
32
70
102
$
—
—
—
$
$
—
—
—
$
$
32
70
102
(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, 2019
Fair Value
Cost
Level 1
Level 2
Level 3
Total
$
$
17
57
74
$
$
17
65
82
$
$
—
—
—
$
$
—
—
—
$
$
17
65
82
(a)
Reported in nuclear decommissioning fund and other investments on the consolidated
balance sheet.
Derivative Instruments Fair Value Measurements
Xcel Energy enters into derivative instruments, including forward contracts,
futures, swaps and options, for trading purposes and to manage risk in
connection with changes in interest rates, utility commodity prices and
vehicle fuel prices.
Interest Rate Derivatives — Xcel Energy enters into various instruments
that effectively fix the yield or price on a specified benchmark interest rate
for an anticipated debt issuance for a specific period. These derivative
instruments are generally designated as cash flow hedges for accounting
purposes, with changes in fair value prior to settlement recorded as other
comprehensive income.
As of Dec. 31, 2020, accumulated other comprehensive loss related to
settled interest rate derivatives included $6 million of net losses expected to
be reclassified into earnings during the next 12 months as the hedged
transactions impact earnings. As of Dec. 31, 2020, Xcel Energy had no
unsettled interest rate derivatives.
Wholesale and Commodity Trading Risk — Xcel Energy Inc.’s utility
subsidiaries conduct various wholesale and commodity trading activities,
including the purchase and sale of electric capacity, energy, energy-related
instruments and natural gas-related instruments, including derivatives. Xcel
Energy is allowed to conduct these activities within guidelines and
limitations as approved by its risk management committee, comprised of
management personnel not directly involved in activities governed by this
policy.
Commodity Derivatives — Xcel Energy enters into derivative instruments
to manage variability of future cash flows from changes in commodity
prices in its electric and natural gas operations, as well as for trading
purposes. This could include the purchase or sale of energy or energy-
related products, natural gas to generate electric energy, natural gas for
resale, FTRs, vehicle fuel and weather derivatives.
63
Xcel Energy may enter into derivative instruments that mitigate commodity
price risk on behalf of electric and natural gas customers but may not be
designated as qualifying hedging transactions. The classification as a
regulatory asset or liability, if applicable, is based on approved regulatory
recovery mechanisms.
As of Dec. 31, 2020, Xcel Energy had no commodity contracts designated
as cash flow hedges.
Xcel Energy enters into commodity derivative instruments for trading
purposes not directly related to commodity price risks associated with
serving its electric and natural gas customers. Changes in the fair value of
these commodity derivatives are recorded in electric operating revenues,
net of amounts credited to customers under margin-sharing mechanisms.
Gross notional amounts of commodity forwards, options and FTRs:
(Amounts in Millions)
(a)(b)
MWh of electricity
MMBtu of natural gas
(a)
Dec. 31, 2020
Dec. 31, 2019
87
175
95
110
Not reflective of net positions in the underlying commodities.
(b)
Notional amounts for options included on a gross basis but weighted for the probability
of exercise.
Consideration of Credit Risk and Concentrations — Xcel Energy
continuously monitors the creditworthiness of counterparties to its interest
rate derivatives and commodity derivative contracts prior to settlement and
assesses each counterparty’s ability to perform on the transactions set forth
in the contracts. Impact of credit risk was immaterial to the fair value of
unsettled commodity derivatives presented on the consolidated balance
sheets.
Xcel Energy’s utility subsidiaries’ most significant concentrations of credit
risk with particular entities or industries are contracts with counterparties to
their wholesale, trading and non-trading commodity activities.
As of Dec. 31, 2020, six of Xcel Energy’s 10 most significant counterparties
for these activities, comprising $130 million or 54% of this credit exposure,
had investment grade credit ratings from S&P, Moody’s or Fitch Ratings.
Three of the 10 most significant counterparties, comprising $32 million or
13% of this credit exposure, were not rated by these external agencies, but
based on Xcel Energy’s internal analysis, had credit quality consistent with
investment grade. One of these significant counterparties, comprising $17
million or 7% of this credit exposure, had credit quality less than investment
grade, based on internal analysis. Eight of these significant counterparties
are municipal or cooperative electric entities, RTOs or other utilities.
Qualifying Cash Flow Hedges — Financial impact of qualifying interest
rate cash flow hedges on Xcel Energy’s accumulated other comprehensive
loss, included in the consolidated statements of common stockholders’
equity and in the consolidated statements of comprehensive income:
(Millions of Dollars)
2020
2019
2018
Accumulated other comprehensive loss related to cash flow
hedges at Jan. 1
$
(80) $
(60) $
(58)
After-tax net unrealized losses related to derivatives
accounted for as hedges
After-tax net realized losses on derivative transactions
reclassified into earnings
(10)
(23)
5
3
(5)
3
Accumulated other comprehensive loss related to cash flow
hedges at Dec. 31
$
(85) $
(80) $
(60)
Impact of derivative activity:
(Millions of Dollars)
Year Ended Dec. 31, 2020
Derivatives designated as cash flow hedges
Pre-Tax Fair Value
Gains (Losses) Recognized
During the Period in:
Accumulated
Other
Comprehensive
Loss
Regulatory
(Assets) and
Liabilities
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
Year Ended Dec. 31, 2018
Interest rate
Total
Other derivative instruments
Electric commodity
Natural gas commodity
Total
$
$
$
$
$
$
$
$
$
$
$
$
(13)
(13)
—
—
—
(30)
(30)
—
—
—
(7)
(7)
—
—
—
$
$
$
$
$
$
$
$
$
$
$
$
—
—
(5)
(13)
(18)
—
—
8
(9)
(1)
—
—
1
10
11
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, 2020
Derivatives designated as cash flow hedges
Interest rate
Total
Other derivative instruments
Commodity trading
Electric commodity
Natural gas commodity
Total
$
$
$
$
7
7
—
—
—
—
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
$
$
$
$
4
4
—
—
—
—
Year Ended Dec. 31, 2018
Derivatives designated as cash flow hedges
Interest rate
Total
Other derivative instruments
Commodity trading
Electric commodity
Natural gas commodity
Total
$
$
$
$
4
4
—
—
—
—
(a)
(a)
(a)
$
$
$
$
$
$
$
$
$
$
$
$
—
—
(c)
(d)
—
(3)
10
7
—
—
—
(5)
2
(3)
—
—
—
(1)
(6)
(7)
(c)
(d)
(c)
(d)
$
$
$
$
$
$
$
$
$
$
$
$
—
—
(b)
(d)
(1)
—
(13)
(14)
(b)
(d)
—
—
2
—
(7)
(5)
—
—
(b)
(d)
14
—
(4)
10
(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.
Amounts for the years ended Dec. 31, 2020 and 2019 included no settlement losses on
derivatives entered to mitigate natural gas price risk for electric generation recorded to
electric
fuel and purchased power, subject
to cost-recovery mechanisms and
reclassified to a regulatory asset, as appropriate. Such losses for the year ended Dec.
31, 2018, was $1 million. Remaining settlement losses for the years ended Dec. 31,
2020, 2019 and 2018 related to natural gas operations and were recorded to cost of
natural gas sold and
transported. These
losses are subject
to cost-recovery
mechanisms and reclassified out of income to a regulatory asset, as appropriate.
Xcel Energy had no derivative instruments designated as fair value hedges
during the years ended Dec. 31, 2020, 2019 and 2018.
64
Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as
normal purchase and normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or
settlement of the contracts for various reasons, including if the applicable utility subsidiary’s credit ratings are downgraded below its investment grade credit
rating by any of the major credit rating agencies. As of Dec. 31, 2020 and 2019, there were $4 million and $7 million of derivative instruments in a liability
position with such underlying contract provisions, respectively. Certain contracts also contain cross default provisions that may require the posting of
collateral or settlement of the contracts if there was a failure under the other financing arrangements related to payment terms or other covenants. As of
Dec. 31, 2020, there were approximately $60 million of derivative instruments in a liability position with such underlying contract provisions.
Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. Provisions allow counterparties to seek
performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected
to be impaired. Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2020 and 2019.
Recurring Fair Value Measurements — Derivative assets and liabilities measured at fair value on a recurring basis were as follows:
Dec. 31, 2020
Dec. 31, 2019
Fair Value
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
$
2
$ 67
$
1
$
—
—
20
—
9
—
70
20
9
$
(52) $
$
(52) $
18
19
$
3
$ 51
$ 24
$
—
—
21
9
—
6
—
78
21
6
Total current derivative assets
$
2
$ 76
$ 21
$
99
$
46
$
3
$ 57
$ 45
$
105
$
(Millions of Dollars)
Current derivative assets
Other derivative instruments:
Commodity trading
Electric commodity
Natural gas commodity
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
PPAs (b)
Current derivative instruments
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading
Total noncurrent derivative liabilities
PPAs (b)
$
$
8
8
$ 66
$ 66
$
$
8
8
$
$
82
82
$
$
(62) $
(62)
$
Dec. 31, 2020
Fair Value
Level
2
Level
1
Level
3
Fair Value
Total
Netting (a)
Total
$
4
$ 64
$ 17
$
85
$
(58) $
$
$
9
9
$ 38
$ 38
$
$
7
7
$
$
54
54
$
$
(45) $
(45)
$
Dec. 31, 2019
Fair Value
Level
2
Level
1
Level
3
Fair Value
Total
(a)
Netting
Total
—
—
1
—
9
—
1
9
—
—
1
9
—
5
—
1
5
$
4
$ 59
$ 15
$
78
$
(63) $
Total current derivative liabilities
$
4
$ 73
$ 18
$
95
$
$
4
$ 64
$ 16
$
84
$
$
$
3
3
$ 58
$ 60
$ 58
$ 60
$
$
121
121
$
$
(47) $
(47)
$
$
2
2
$ 79
$ 32
$ 79
$ 32
$
$
113
113
$
$
(13) $
(13)
Noncurrent derivative instruments
$
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, 2020 and 2019. At Dec. 31, 2020 and 2019, derivative assets and liabilities include $15
million and $32 million of obligations to return cash collateral, respectively. At Dec. 31, 2020 and 2019, derivative assets and liabilities include rights to reclaim cash collateral of $6 million
and $11 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master
netting agreements.
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.
65
(1)
—
(53)
$
(1)
—
(64)
$
26
20
6
52
3
55
9
9
13
22
15
—
5
20
18
38
100
100
75
175
(1)
—
(53)
$
(1)
—
(59)
$
3
49
20
20
10
30
27
—
36
17
53
74
74
57
The nonqualified pension plan provides benefits for compensation that is in
excess of the limits applicable to the qualified pension plans, with
distributions funded by Xcel Energy’s consolidated operating cash flows.
Obligations of the SERP and nonqualified plan as of Dec. 31, 2020 and
2019 were $43 million and $39 million, respectively. Xcel Energy
recognized net benefit cost for the SERP and nonqualified plans of $6
million in 2020 and $4 million in 2019.
Xcel Energy bases the investment-return assumption on expected long-
term performance for each of the asset classes in its pension and
postretirement health care portfolios. For pension assets, Xcel Energy
considers the historical returns achieved by its asset portfolio over the past
20 years or longer period, as well as long-term projected return levels.
Pension cost determination assumes a forecasted mix of investment types
over the long-term.
•
•
•
•
Investment returns in 2020 were above the assumed level of 6.87%.
Investment returns in 2019 were above the assumed level of 6.87%.
Investment returns in 2018 were below the assumed level of 6.87%.
In 2021, expected investment-return assumption is 6.49%.
Pension plan and postretirement benefit assets are invested in a portfolio
according to Xcel Energy’s return, liquidity and diversification objectives to
provide a source of funding for plan obligations and minimize contributions
to the plan, within appropriate levels of risk. The principal mechanism for
achieving these objectives is the asset allocation given the long-term risk,
return, correlation and liquidity characteristics of each particular asset
class. There were no significant concentrations of risk in any industry,
index, or entity. Market volatility can impact even well-diversified portfolios
and significantly affect the return levels achieved by the assets in any year.
State agencies also have issued guidelines to the funding of postretirement
benefit costs. SPS is required to fund postretirement benefit costs for Texas
and New Mexico amounts collected in rates. PSCo is required to fund
postretirement benefit costs in irrevocable external trusts that are dedicated
to the payment of these postretirement benefits. These assets are invested
in a manner consistent with the investment strategy for the pension plan.
Xcel Energy’s ongoing investment strategy is based on plan-specific
investment recommendations that seek to minimize potential investment
and interest rate risk as a plan’s funded status increases over time. The
investment recommendations result in a greater percentage of long-
duration fixed income securities being allocated to specific plans having
relatively higher funded status ratios and a greater percentage of growth
assets being allocated to plans having relatively lower funded status ratios.
Changes in Level 3 commodity derivatives:
(Millions of Dollars)
Balance at Jan. 1
Purchases
Settlements
Net transactions recorded during the period:
Losses recognized in earnings (a)
Net gains (losses) recognized as regulatory
assets and liabilities
Balance at Dec. 31
(a)
Year Ended Dec. 31
2020
2019
2018
$
4
$
51
(73)
$
29
44
(64)
(39)
(8)
8
$
(49) $
3
4
$
35
59
(59)
(1)
(5)
29
Level 3 losses recognized in earnings are subject to offsetting gains of derivative
instruments categorized as levels 1 and 2 in the income statement.
Xcel Energy recognizes transfers between levels as of the beginning of
each period. There were no transfers of amounts between levels for
derivative instruments for Dec. 31, 2020, 2019 and 2018.
Fair Value of Long-Term Debt
As of Dec. 31, other financial instruments for which the carrying amount did
not equal fair value:
(Millions of Dollars)
Long-term debt, including current
portion
2020
2019
Carrying
Amount
Fair
Value
Carrying
Amount
Fair
Value
$
20,066
$ 24,412
$
18,109
$ 20,227
Fair value of Xcel Energy’s long-term debt is estimated based on recent
trades and observable spreads from benchmark interest rates for similar
securities. Fair value estimates are based on information available to
management as of Dec. 31, 2020 and 2019, and given the observability of
the inputs, fair values presented for long-term debt were assigned as Level
2.
11. Benefit Plans and Other Postretirement Benefits
Pension and Postretirement Health Care Benefits
Xcel Energy has several noncontributory, qualified, defined benefit pension
plans that cover almost all employees. All newly hired or rehired employees
participate under the Cash Balance formula, which is based on pay credits
using a percentage of annual eligible pay and annual interest credits. The
average annual interest crediting rates for these plans was 1.89, 2.82 and
3.62 percent in 2020, 2019, and 2018, respectively. Some employees may
participate under legacy formulas such as the traditional final average pay
or pension equity. Xcel Energy’s policy is to fully fund into an external trust
the actuarially determined pension costs subject to the limitations of
applicable employee benefit and tax laws.
In addition to the qualified pension plans, Xcel Energy maintains a SERP
and a nonqualified pension plan. The SERP is maintained for certain
executives who participated in the plan in 2008, when the SERP was
closed to new participants.
66
Plan Assets
For each of the fair value hierarchy levels, Xcel Energy’s pension plan assets measured at fair value:
(Millions of Dollars)
Cash equivalents
Commingled funds
Debt securities
Equity securities
Other
Total
Dec. 31, 2020 (a)
Dec. 31, 2019 (a)
Level 1
Level 2
Level 3
Measured at
NAV
Total
Level 1
Level 2
Level 3
$
$
209
1,462
—
77
13
1,761
$
$
—
—
714
—
5
719
$
$
—
—
4
—
—
4
$
$
—
1,115
—
—
—
1,115
$
$
209
2,577
718
77
18
3,599
$
$
145
1,408
—
86
(120)
1,519
$
$
—
—
645
—
5
650
$
$
Measured at
NAV
Total
—
—
4
—
—
4
$
$
—
1,031
—
—
(20)
1,011
$
$
145
2,439
649
86
(135)
3,184
(a)
See Note 10 for further information regarding fair value measurement inputs and methods.
For each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that were measured at fair value:
(Millions of Dollars)
Cash equivalents
Insurance contracts
Commingled funds
Debt securities
Other
Total
Dec. 31, 2020 (a)
Dec. 31, 2019 (a)
Level 1
Level 2
Level 3
Measured at
NAV
Total
Level 1
Level 2
Level 3
Measured at
NAV
Total
$
$
27
—
72
—
—
99
$
$
—
50
—
232
2
284
$
$
—
—
—
—
—
—
$
$
—
—
69
—
—
69
$
$
27
50
141
232
2
452
$
$
23
—
69
—
—
92
$
$
—
51
—
228
1
280
$
$
—
—
—
1
—
1
$
$
—
—
76
—
—
76
$
$
23
51
145
229
1
449
(a)
See Note 10 for further information on fair value measurement inputs and methods.
No assets were transferred in or out of Level 3 for 2020. Immaterial assets were transferred in or out of Level 3 for 2019.
Funded Status — Benefit obligations for both pension and postretirement plans increased from Dec. 31, 2019 to Dec. 31, 2020, due primarily to decreases
in discount rates used in actuarial valuations. Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the
pension and postretirement health care plans for Xcel Energy are as follows:
(Millions of Dollars)
Change in Benefit Obligation:
Obligation at Jan. 1
Service cost
Interest cost
Plan amendments
Actuarial 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
2020
2019
2020
2019
$
3,701
$
3,477
$
547
$
95
125
—
328
—
—
86
145
1
273
—
—
1
18
—
50
8
1
(285)
3,964
$
(281)
3,701
$
(51)
574
$
3,184
$
2,742
$
449
$
550
150
—
(285)
3,599
$
(365) $
$
—
—
(365)
(365) $
568
155
—
(281)
3,184
$
(517) $
$
—
—
(517)
(517) $
35
11
8
(51)
452
$
(122) $
6
$
(7)
(121)
(122) $
$
$
$
$
$
$
542
2
22
—
19
8
1
(47)
547
417
56
15
8
(47)
449
(98)
21
(6)
(113)
(98)
(a)
Includes approximately $0 million in 2020 and $20 million in 2019 of lump-sum benefit payments used in the determination of a settlement charge.
67
Significant Assumptions Used to Measure Benefit Obligations:
2020
2019
2020
2019
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
2.71 %
3.75
PRI-2012
N/A
N/A
N/A
N/A
N/A
3.49 %
3.75
PRI-2012
N/A
N/A
N/A
N/A
N/A
2.65 %
N/A
PRI-2012
5.50 %
5.00 %
4.50 %
4.50 %
5
3.47 %
N/A
PRI-2012
6.00 %
5.10 %
4.50 %
4.50 %
3
Accumulated benefit obligation for the pension plan was $3,693 million and $3,465 million as of Dec. 31, 2020 and 2019, respectively.
Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit), other than the service cost component, is included in other income in the
consolidated statements of income.
Components of net periodic benefit cost (credit) and amounts recognized in other comprehensive income and regulatory assets and liabilities:
(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
Pension Benefits
Postretirement Benefits
2020
2019
2018
2020
2019
2018
$
$
95
125
(208)
(4)
100
—
108
9
$
86
145
(203)
(5)
87
6
116
(1)
$
$
94
133
(209)
(5)
111
91
215
(75)
140
3.63 %
3.75
6.87
1
18
(19)
(8)
4
—
(4)
3
(1)
$
$
2
22
(21)
(10)
5
—
(2)
1
(1)
$
$
2
22
(26)
(11)
8
—
(5)
2
(3)
3.47 %
—
4.50
4.32 %
—
4.50
3.62 %
—
5.30
Net benefit cost (credit) recognized for financial reporting
$
117
$
115
$
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
3.49 %
3.75
6.87
4.31 %
3.75
6.87
(a)
A settlement charge is required when the amount of all lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic
pension cost. In 2019 and 2018, as a result of lump-sum distributions during each plan year, Xcel Energy recorded a total pension settlement charge of $6 million and $91 million,
respectively, the majority of which was not recognized due to the effects of regulation. A total of $1 million and $11 million was recorded in the consolidated statements of income in 2019 and
2018, respectively. There were no settlement charges recorded for the qualified pension plans in 2020.
(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
2020
2019
2020
2019
$
$
$
1,333
$
(11)
1,322
$
1,447
$
(15)
1,432
$
82
$
1,181
78
$
1,285
—
—
15
44
—
—
18
51
126
$
(15)
111
$
—
$
125
(1)
(18)
1
4
$
1,322
$
1,432
$
111
$
95
(23)
72
—
80
(1)
(12)
1
4
72
Dec. 31, 2020
Dec. 31, 2019
Dec. 31, 2020
Dec. 31, 2019
68
Cash Flows — Funding requirements can be impacted by changes to
actuarial assumptions, actual asset levels and other calculations prescribed
by the requirements of income tax and other pension-related regulations.
Required contributions were made in 2018 — 2021 to meet minimum
funding requirements.
Voluntary and required pension funding contributions:
•
•
•
•
$125 million in January 2021.
$150 million in 2020.
$154 million in 2019.
$150 million in 2018.
The postretirement health care plans have no funding requirements other
than fulfilling benefit payment obligations, when claims are presented and
approved. Additional cash funding requirements are prescribed by certain
state and federal rate regulatory authorities.
Voluntary postretirement funding contributions:
•
•
•
•
Expects to contribute approximately $10 million during 2021.
$11 million during 2020.
$15 million during 2019.
$11 million during 2018.
Targeted asset allocations:
Domestic and international equity
securities
Long-duration fixed income securities
Short-to-intermediate fixed income
securities
Alternative investments
Cash
Total
Pension Benefits
Postretirement
Benefits
2020
2019
2020
2019
35 %
37 %
15 %
15 %
35
13
15
2
30
14
17
2
—
72
9
4
—
72
9
4
100 %
100 %
100 %
100 %
The asset allocations above reflect target allocations approved in the
calendar year to take effect in the subsequent year.
Plan Amendments — In 2018, the PSCo postretirement plan was
amended to add the 5% cash balance formula.
In 2019, the Pension Protection Act measurement concept was extended
beyond 2019 for NSP bargaining terminations and retirements to Dec. 31,
2022.
There were no significant plan amendments made in 2020 which affected
the postretirement benefit obligation.
Projected Benefit Payments
Xcel Energy’s projected benefit payments:
(Millions of Dollars)
Projected
Pension
Benefit
Payments
Gross Projected
Postretirement
Health Care
Benefit Payments
Expected
Medicare Part
D
Subsidies
Net Projected
Postretirement
Health Care
Benefit Payments
2021
2022
2023
2024
2025
2026-2030
$
$
304
282
274
265
259
1,193
$
44
43
42
41
39
175
$
2
2
2
2
2
12
42
41
40
39
37
163
Defined Contribution Plans
Xcel Energy maintains 401(k) and other defined contribution plans that
cover most employees. Total expense to these plans was approximately
$42 million in 2020, $39 million in 2019 and $38 million in 2018.
Multiemployer Plans
NSP-Minnesota and NSP-Wisconsin each contribute to several union
multiemployer pension and other postretirement benefit plans, none of
which are individually significant. These plans provide pension and
postretirement health care benefits to certain union employees who may
perform services for multiple employers and do not participate in the NSP-
Minnesota and NSP-Wisconsin sponsored pension and postretirement
health care plans.
Contributing to these types of plans creates risk that differs from providing
benefits under NSP-Minnesota and NSP-Wisconsin sponsored plans, in
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 of such matters, including a possible eventual loss. For
current proceedings not specifically reported, management does not
anticipate that the ultimate liabilities, if any, would have a material effect on
Xcel Energy’s financial statements. Unless otherwise required by GAAP,
legal fees are expensed as incurred.
Gas Trading Litigation — e prime is a wholly owned subsidiary of
Xcel Energy. e prime was in the business of natural gas trading and
marketing but has not engaged in natural gas trading or marketing activities
since 2003. Multiple lawsuits involving multiple plaintiffs seeking monetary
damages were commenced against e prime and its affiliates, including
Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive
activities in conspiring to restrain the trade of natural gas and manipulate
natural gas prices. Cases were all consolidated in the U.S. District Court in
Nevada.
Two cases remain active which include an MDL matter consisting of a
Colorado purported class (Breckenridge) and a Wisconsin purported class
(Arandell Corp.).
Breckenridge/Colorado — In February 2019, the MDL panel remanded
Breckenridge back to the U.S. District Court in Colorado. In December
2020, a settlement in principle was reached for approximately $3 million.
The parties have sought and are awaiting court approval of settlement.
Arandell Corp. — In February 2019, the case was remanded back to the
U.S. District Court in Wisconsin.
Xcel Energy has concluded that a loss is remote for the remaining lawsuit.
69
Rate Matters and Other
MEC Acquisition and Disposition — In January 2020, Xcel Energy, Inc.
purchased MEC, a 760 MW natural gas combined cycle facility, for
approximately $650 million from Southern Power Company.
In July 2020, Xcel Energy sold MEC to Southwest Generation for $684
million. The gain on sale of approximately $20 million, which was offset by
charitable giving, including COVID-19 relief efforts, had no material impact
on earnings.
Sherco — In 2018, NSP-Minnesota and SMMPA (Co-owner of Sherco Unit
3) reached a settlement with GE related to a 2011 incident, which damaged
the turbine at Sherco Unit 3 and resulted in an extended outage for repair.
NSP-Minnesota notified the MPUC of its proposal to refund settlement
proceeds to customers through the FCA.
In March 2019, the MPUC approved NSP-Minnesota’s refund proposal.
Additionally, the MPUC decided to withhold any decision as to NSP-
Minnesota’s prudence in connection with the incident at Sherco Unit 3 until
after conclusion of an appeal pending between GE and NSP-Minnesota’s
insurers. In February 2020, the Minnesota Court of Appeals affirmed the
district court’s judgment in favor of GE. In March 2020, NSP-Minnesota’s
insurers filed a petition seeking additional review by the Minnesota
Supreme Court.
In April 2020, the Minnesota Supreme Court denied the insurers’ petition for
further review, ending the litigation. In accordance with a prior MPUC order,
NSP-Minnesota made a compliance filing in August 2020 detailing all costs
that resulted from the outage and all insurance recoveries received by
NSP-Minnesota in connection with the outage.
In January 2021, the Minnesota Office of the Attorney General and DOC
filed comments recommending that NSP-Minnesota refund approximately
$17 million of replacement power costs previously recovered through the
FCA. On Jan. 27, 2021, NSP-Minnesota filed its response, asserting that it
acted prudently in connection with the Sherco Unit 3 outage, the MPUC has
previously disallowed $22 million of related costs and no additional refund
or disallowance is appropriate. A final decision by the MPUC is pending. A
loss related to this matter is deemed remote.
insurers
In November 2014,
Westmoreland Arbitration —
for
Westmoreland Coal Company filed an arbitration demand against NSP-
Minnesota, SMMPA and Western Fuels Association, seeking recovery of
alleged business losses due to a turbine failure at Sherco Unit 3. The
Westmoreland insurers claim NSP-Minnesota’s invocation of the force
majeure clause to stop the supply of coal was improper because the
incident was allegedly caused by NSP-Minnesota’s failure to conform to
industry maintenance standards. Westmoreland’s insurers quantified their
losses as approximately $36 million.
Arbitration was delayed pending resolution of a separate lawsuit brought by
NSP-Minnesota, SMMPA, and their insurers against various GE entities
based on the inspection and maintenance advice GE provided for Sherco
Unit 3. In July 2020, following the conclusion of the appeal that fully
resolved the GE litigation, Westmoreland’s insurers served notice, which
triggered the arbitration to resume.
NSP-Minnesota denies the claims asserted by the Westmoreland insurers
and believes it properly stopped the supply of coal based upon the force
majeure provision. It is uncertain when a final resolution will occur, but it is
unlikely an arbitration hearing will take place before the fourth quarter 2021.
At this stage of the proceeding, before any discovery has been conducted/
completed, a reasonable estimate of damages or range of damages cannot
be determined.
70
MISO ROE Complaints — In November 2013 and February 2015,
customer groups filed two ROE complaints against MISO TOs, which
includes NSP-Minnesota and NSP-Wisconsin. The
first complaint
requested a reduction in base ROE transmission formula rates from
12.38% to 9.15% for the time period of Nov. 12, 2013 to Feb. 11, 2015, and
removal of ROE adders (including those for RTO membership). The second
complaint requested, for a subsequent time period, a base ROE reduction
from 12.38% to 8.67%.
In September 2016, the FERC issued an order (Opinion No. 551) granting
a 10.32% base ROE effective for the first complaint period of Nov. 12, 2013
to Feb. 11, 2015 and subsequent to the date of the order. The D.C Circuit
subsequently vacated and remanded the FERC Opinion.
In November 2019, the FERC issued an order (Opinion No. 569), which set
the MISO base ROE at 9.88%, effective Sept. 28, 2016 and for the first
complaint period. The FERC also dismissed the second complaint. In
December 2019, MISO TOs filed a request for rehearing regarding the new
ROE methodology announced in Opinion No. 569. Customers also filed
requests for rehearing claiming, among other points, that the FERC erred
by dismissing the second complaint without refunds.
In May 2020, the FERC issued an order (Opinion No. 569-A) which granted
rehearing in part to Opinion 569 and further refined the FERC’s ROE
methodology, most significantly to incorporate the risk premium model (in
addition to the discounted cash flow and capital asset pricing models),
resulting in a new base ROE of 10.02%, effective Sept. 28, 2016 and for
the first complaint period. The FERC also affirmed its decision in Opinion
No. 569 to dismiss the second complaint.
In June 2020, various parties filed requests for rehearing of Opinion 569-A
with the FERC. In November 2020, the FERC issued an order (Opinion No.
569-B) in response to the rehearing requests. The FERC corrected certain
inputs to its ROE calculation model, did not change the ROE for the first
MISO complaint period and upheld its decision to deny refunds for the
second complaint period. Each 10 basis point reduction in the allowed base
ROE for the first complaint and second complaint would reduce net income
by $2 million and $1 million, respectively.
Various parties have filed petitions for review of Opinion Nos. 569, 569-A
and 569-B at the D.C. Circuit. These appeals remain pending.
recovered
SPP OATT Upgrade Costs — Under the SPP OATT, costs of transmission
upgrades may be
from other SPP customers whose
transmission service depends on capacity enabled by the upgrade. SPP
had not been charging its customers for these upgrades, even though the
SPP OATT had allowed SPP to do so since 2008. In 2016, the FERC
granted SPP’s request to recover these previously unbilled charges and
SPP subsequently billed SPS approximately $13 million.
In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings
granting SPP the right to recover previously unbilled charges was
remanded to the FERC. In February 2019, the FERC reversed its 2016
decision and ordered SPP to refund charges retroactively collected from its
transmission customers,
to periods before
September 2015. In March 2020, SPP and Oklahoma Gas & Electric
separately filed petitions for review of the FERC’s orders at the D.C. Circuit.
SPS has intervened in both appeals in support of the FERC. Any refunds
received by SPS are expected to be given back to SPS customers through
future rates.
including SPS,
related
In October 2017, SPS filed a separate related complaint asserting SPP
assessed upgrade charges to SPS in violation of the SPP OATT. In March
2018, the FERC issued an order denying the SPS complaint. SPS filed a
request for rehearing in April 2018. The FERC issued a tolling order
granting a rehearing for further consideration in May 2018. If SPS’
complaint results in additional charges or refunds, SPS will seek to recover
or refund the amount through future SPS customer rates. In October 2020,
SPS filed a petition for review of the FERC’s March 2018 order and May
2018 tolling order at the D.C. Circuit. This appeal is stayed pending the
outcome of the separate appeal initiated in 2020 by Oklahoma Gas &
Electric and SPP.
Wind Operating Commitments — PUCT and NMPRC orders related to
the Hale and Sagamore wind projects included certain operating and
savings minimums. In general, annual generation must exceed a net
capacity factor of 48%. If annual generation is below the guaranteed level,
SPS would be obligated to refund an amount equal to foregone PTCs and
fuel savings. Additionally, retail customer savings must exceed project
costs included in base rates over the first ten years of operations. SPS
would be required to refund excess costs, if any, after ten years of
operations. As of Dec. 31, 2020, SPS does not expect refunds to be
probable under either of these commitments.
Contract Termination — SPS and Lubbock Power & Light are parties to a
25-year, 170 MW partial requirements contract. In October 2020, Lubbock
Power & Light initiated discussions concerning the interpretation of
contractual terms related to early termination and default. If the parties are
unable to reach resolution, the contract calls for the matter to proceed to
arbitration. The amount of any damages depends on multiple factors and is
currently unknown.
Environmental
New and changing federal and state environmental mandates can create
financial liabilities for Xcel Energy, which are normally recovered through
the regulated rate process.
Site Remediation
Various federal and state environmental laws impose liability where
hazardous substances or other regulated materials have been released to
the environment. Xcel Energy Inc.’s subsidiaries may sometimes pay all or
a portion of the cost to remediate sites where past activities of their
predecessors or other parties have caused environmental contamination.
Environmental contingencies could arise from various situations, including
sites of former MGPs; and third-party sites, such as landfills, for which one
or more of Xcel Energy Inc.’s subsidiaries are alleged to have sent wastes
to that site.
MGP, Landfill and Disposal Sites
Ashland MGP Site — NSP-Wisconsin was named a responsible party for
contamination at the Ashland/Northern States Power Lakefront Superfund
Site (the Site) in Ashland, Wisconsin. Remediation was completed in 2019
and restoration activities were completed in 2020. Groundwater treatment
activities will continue for many years.
The cost estimate for remediation and restoration of the entire site is
approximately $199 million. At Dec. 31, 2020 and 2019, NSP-Wisconsin
had a total liability of $19 million and $23 million, respectively, for the entire
site.
NSP-Wisconsin has deferred the unrecovered portion of the estimated Site
remediation and restoration costs as a regulatory asset. The PSCW has
authorized NSP-Wisconsin rate recovery for all remediation and restoration
costs incurred at the Site and application of a 3% carrying charge to the
regulatory asset.
In January 2021, the EPA confirmed that NSP-Wisconsin completed its
work on the soils and sediments at the Site and all that remains is the long-
term groundwater pump and treat program.
Xcel Energy is currently investigating, remediating or performing post-
closure actions at 12 other MGP, landfill or other disposal sites across its
service territories.
Xcel Energy has recognized its best estimate of costs/liabilities that will
result from final resolution of these issues, however, the outcome and
timing is unknown. In addition, there may be insurance recovery and/or
recovery from other potentially responsible parties, offsetting a portion of
costs incurred.
Environmental Requirements — Water and Waste
Coal Ash Regulation — Xcel Energy’s operations are subject to federal and
state regulations that impose requirements for handling, storage, treatment
and disposal of solid waste. Under the CCR Rule, utilities are required to
complete groundwater sampling around their CCR landfills and surface
impoundments. Currently, Xcel Energy has nine regulated ash units in
operation.
Xcel Energy is conducting groundwater sampling and monitoring and
implementing assessment of corrective measures at certain CCR landfills
and surface impoundments. In NSP-Minnesota, no results above the
groundwater protection standards in the rule were identified. In PSCo,
statistically significant increases above background concentrations were
detected at four locations. Subsequently, assessment monitoring samples
were collected at these locations and, based on the results, PSCo is
evaluating options for corrective action at two locations, one of which
indicates potential offsite impacts to groundwater. Until PSCo completes its
assessments, it is uncertain what impact, if any, there will be on the
operations, financial condition or cash flows.
In August 2020, the EPA published its final rule to implement a cease
receipt and initiate a closure date of April 2021 for all CCR impoundments
affected by the August 2018 D.C. Circuit ruling. The D.C. Circuit concluded
that the EPA cannot allow utilities to continue to use unlined impoundments
(including clay lined impoundments) for the storage or disposal of coal ash.
This final rule required Xcel Energy to expedite closure plans for two
impoundments.
In October 2020, NSP-Minnesota completed construction and placed in
service a new impoundment to replace the clay lined impoundment at a
cost of $9 million. With the new ash pond in service, NSP-Minnesota has
initiated closure activities for the existing ash pond at an estimated cost of
$4 million. NSP-Minnesota has five years to complete closure activities.
PSCo is pursuing options to build an alternative bottom ash collection
system that will be constructed and in service in advance of the April 11,
2021 deadline. Once the alternative bottom ash system is operational, the
existing impoundment will initiate closure per the CCR Rule.
Closure costs for existing impoundments are included in the calculation of
the ARO.
71
In December 2017, the National Parks Conservation Association, Sierra
Club, and Environmental Defense Fund appealed the EPA’s 2017 final
BART rule to the Fifth Circuit and filed a petition for administrative
reconsideration. The court has held the litigation in abeyance while the EPA
decided whether to reconsider the rule. In August 2018, the EPA started a
reconsideration rulemaking. The EPA reaffirmed the rule in August 2020
with minor changes.
The 2020 EPA Action has been challenged. All pending actions could be
consolidated, and may proceed in the Fifth Circuit or the D.C. Circuit, where
a parallel challenge has been filed. The timing of final decisions is unclear.
Reasonable Progress Rule: In 2016, the EPA adopted a final rule
establishing a federal implementation plan for reasonable further progress
under the regional haze program for the state of Texas. The rule imposes
SO2 emission limitations that would require the installation of dry scrubbers
on Tolk Units 1 and 2, with compliance required by February 2021.
Investment costs associated with dry scrubbers could be $600 million. SPS
appealed the EPA’s decision and obtained a stay of the final rule.
In March 2017, the Fifth Circuit remanded the rule to the EPA for
reconsideration, leaving the stay in effect. In a future rulemaking, the EPA
will address whether SO2 emission reductions beyond those required in the
BART alternative rule are needed at Tolk under the “reasonable progress”
requirements. As states are now proceeding with the second regional haze
planning period, the EPA may choose not to act on the remanded rule.
Implementation of the NAAQS for SO2 — The EPA has designated all
areas near SPS’ generating plants as attaining the SO2 NAAQS with an
exception. The EPA issued final designations, which found the area near
the SPS Harrington plant as “unclassifiable.” The area near the Harrington
plant was monitored for the three years ending in 2019 and the monitoring
showed the area to be exceeding the standard.
To address this issue, SPS negotiated an order with the TCEQ providing
for the end of coal combustion and the conversion of the Harrington plant to
a natural gas fueled facility by Jan. 1, 2025.
Xcel Energy believes compliance costs or the costs of alternative cost-
effective generation will be recoverable through regulatory mechanisms
and therefore does not expect a material impact on results of operations,
financial condition or cash flows.
AROs — AROs have been recorded for Xcel Energy’s assets. For nuclear
assets, the ARO is associated with the decommissioning of NSP-Minnesota
nuclear generating plants.
Aggregate fair value of NSP-Minnesota’s legally restricted assets, for
funding future nuclear decommissioning was $2.8 billion and $2.4 billion for
2020 and 2019, respectively.
Federal CWA WOTUS Rule — In April 2020, the EPA and U.S. Army Corps
of Engineers (“Agencies”) replaced the 2015 WOTUS rule and narrowed
the definition of WOTUS (“2020 WOTUS Rule”). The new definition
simplifies the process whether waters are subject to CWA jurisdiction and
streamlines the permitting process. In June 2020, the U.S. District Court for
the District of Colorado stayed the effective date of the 2020 WOTUS Rule
in Colorado, where the pre-2015 definition of WOTUS is now in effect.
Regardless of which definition is applicable in the states in which we
operate, Xcel Energy does not anticipate that compliance costs will be
material.
Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power
plants that discharge treated effluent to surface waters as well as utility-
owned landfills that receive CCRs. In October 2020, the EPA published a
final rule revising the regulations.
The retirement of units affected by the final ELG rule is subject to regulatory
approval. The exact total cost of ELG compliance is therefore uncertain but
Xcel Energy does not anticipate that compliance costs will be material.
Federal CWA Section 316(b) — The federal CWA requires the EPA to
regulate cooling water intake structures to assure that these structures
reflect the best technology available for minimizing impingement and
entrainment of aquatic species. Xcel Energy estimates the likely cost for
complying with
is
impingement and entrainment
approximately $41 million, to be incurred between 2021 and 2028. Xcel
Energy believes six NSP-Minnesota plants and two NSP-Wisconsin plants
could be required to make improvements to reduce impingement and
entrainment. The exact total cost of the impingement and entrainment
improvements is uncertain but could be up to $191 million. Xcel Energy
anticipates these costs will be fully recoverable through regulatory
mechanisms.
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
the allowance allocations
for SO2 emissions. The
to be sufficient
anticipated costs of compliance are not expected to have a material impact;
and SPS believes that compliance costs would be recoverable through
regulatory mechanisms.
Several parties have challenged whether the final rule issued by the EPA
should be considered to have met the requirements imposed in a Consent
Decree entered by the United States District Court for the District of
Columbia that established deadlines for the EPA to take final action on
state regional haze plan submissions. The court has required status reports
from the parties while the EPA works on the reconsideration rulemaking.
72
(Millions
of Dollars)
Electric
Nuclear
Xcel Energy’s AROs were as follows:
Jan.
1,
2020
Amounts
Incurred
(a)
Amounts
Settled
(b)
Accretion
Cash Flow
Revisions
(c)
Dec.
31,
2020
Indeterminate AROs — Other plants or buildings may contain asbestos
due to the age of many of Xcel Energy’s facilities, but no confirmation or
measurement of the cost of removal could be determined as of Dec. 31,
2020. Therefore, an ARO was not recorded for these facilities.
$ 2,068 $
—
$
—
$
105
$
(216) $ 1,957
Nuclear Related
Steam, hydro and
other production
Wind
Distribution
Natural gas
202
146
44
Transmission and
distribution
236
Miscellaneous
Common
Miscellaneous
Non-utility
Miscellaneous
3
1
1
—
149
—
—
—
—
—
(5)
(3)
—
—
—
—
—
9
8
2
10
—
—
—
58
60
—
6
—
—
—
264
360
46
252
3
1
1
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.
(Millions
of Dollars)
Electric
Nuclear
Jan.
1,
2019
Amounts
Incurred
(a)
Amounts
Settled
(b)
Accretion
Cash Flow
Revisions
(c)
Dec.
31,
2019
$ 1,968 $
—
$
—
$
100
$
—
$ 2,068
Steam, hydro and
other production
Wind
Distribution
Miscellaneous
Natural gas
177
119
42
7
Transmission and
distribution
Miscellaneous
249
4
Common
Miscellaneous
Non-utility
Miscellaneous
1
1
Total liability
$ 2,568 $
—
26
—
—
—
—
—
—
26
(5)
—
—
—
—
—
—
—
8
7
2
—
11
—
—
—
22
(6)
—
202
146
44
(7)
—
(24)
(1)
236
3
—
—
1
1
$
(5) $
128
$
(16) $ 2,701
(a)
(b)
(c)
Amounts incurred related to the wind farms placed in service in 2019 for NSP-Minnesota
(Lake Benton and Foxtail) and SPS (Hale).
Amounts settled related to asbestos abatement projects and closure of certain ash
containment facilities.
In 2019, AROs were revised for changes in timing and estimates of cash flows.
Revisions in gas transmission and distribution AROs were primarily related to increased
gas line mileage and number of services, which were more than offset by decreased
inflation rates. Changes in steam, hydro and other production AROs primarily related to
changes in cost estimates to remediate ponds at production facilities. Revisions in wind
AROs were driven by new dismantling studies.
Nuclear Insurance — NSP-Minnesota’s public liability for claims from any
nuclear incident is limited to $13.8 billion under the Price-Anderson
amendment to the Atomic Energy Act. NSP-Minnesota has secured $450
million of coverage for its public liability exposure with a pool of insurance
companies. The remaining $13.3 billion of exposure is funded by the
Secondary Financial Protection Program available from assessments by
the federal government.
NSP-Minnesota is subject to assessments of up to $138 million per reactor-
incident for each of its three reactors, for public liability arising from a
nuclear incident at any licensed nuclear facility in the United States. The
maximum funding requirement is $21 million per reactor-incident during any
one year. Maximum assessments are subject to inflation adjustments.
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 $34 million for property
damage insurance if losses exceed accumulated reserve funds.
Nuclear Fuel Disposal — NSP-Minnesota is responsible for temporarily
storing spent nuclear fuel from its nuclear plants. The DOE is responsible
for permanently storing spent fuel from U.S. nuclear plants, but no such
facility is yet available.
NSP-Minnesota owns temporary on-site storage facilities for spent fuel at
its Monticello and PI nuclear plants, which consist of storage pools and dry
cask facilities. The Monticello dry-cask storage facility currently stores all 30
of the authorized canisters. The PI dry-cask storage facility currently stores
47 of the 64 authorized casks. Monticello’s future spent fuel will continue to
be placed in its spent fuel pool. The decommissioning plan addresses the
disposition of spent fuel at the end of the licensed life.
Regulatory Plant Decommissioning Recovery — Decommissioning
activities for NSP-Minnesota’s nuclear facilities are planned to begin at the
end of each unit’s operating license and be completed by 2095. NSP-
Minnesota’s current operating licenses allow continued use of its Monticello
nuclear plant until 2030 and its PI nuclear plant until 2033 for Unit 1 and
2034 for Unit 2.
Future decommissioning costs of nuclear facilities are estimated through
triennial periodic studies that assess the costs and timing of planned
nuclear decommissioning activities for each unit.
73
Obligations for decommissioning are expected to be funded 100% by the
external decommissioning trust fund. The cost study assumes the external
decommissioning fund will earn an after-tax return between 5.23% and
6.30%. Realized and unrealized gains on fund investments are deferred as
an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning
costs. Decommissioning costs are quantified in 2014 dollars. Escalation
rates are 4.36% for plant removal activities and 3.36% for fuel management
and site restoration activities.
NSP-Minnesota had $2.8 billion of assets held in external decommissioning
trusts at Dec. 31, 2020. The following table summarizes the funded status
of NSP-Minnesota’s decommissioning obligation. Xcel Energy believes
future decommissioning costs will continue to be recovered in customer
rates. The following amounts were prepared on a regulatory basis and not
directly recorded in the financial statements as an ARO.
(Millions of Dollars)
Estimated decommissioning cost obligation from most recently
approved study (in 2014 dollars)
Effect of escalating costs
Estimated decommissioning cost obligation (in current dollars)
Effect of escalating costs to payment date
Regulatory Basis
2020
2019
$
3,012
$
3,012
844
3,856
7,349
688
3,700
7,505
Estimated future decommissioning costs (undiscounted)
11,205
11,205
Effect of discounting obligation (using average risk-free interest
rate of 1.64% and 2.39% for 2020 and 2019, respectively)
Discounted decommissioning cost obligation
Assets held in external decommissioning trust
(4,181)
(5,562)
$
$
7,024
2,777
$
$
5,643
2,440
Underfunding of external decommissioning fund compared to the
discounted decommissioning obligation
4,247
3,203
Calculations and data used by the regulator in approving NSP-Minnesota’s
rates are useful
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
Reconciliation of
regulated basis to the ARO recorded in accordance with GAAP:
the discounted decommissioning cost obligation -
(Millions of Dollars)
2020
2019
Discounted decommissioning cost obligation - regulated basis
$
7,024
$
5,643
Differences in discount rate and market risk premium
O&M costs not included for GAAP
ARO differences between 2020 and 2014 cost studies
Nuclear production decommissioning ARO - GAAP
(2,628)
(1,734)
(705)
1,957
$
(2,295)
(1,280)
—
2,068
$
Decommissioning expenses recognized as a result of regulation:
(Millions of Dollars)
Annual decommissioning recorded as depreciation expense: (a) (b)
(a)
2020
2019
2018
$ 20
$ 20
$ 20
Decommissioning expense does not include depreciation of the capitalized nuclear
asset retirement costs.
(b)
Decommissioning expenses in 2020, 2019 and 2018 include Minnesota’s retail
jurisdiction annual funding requirement of approximately $14 million.
The 2014 nuclear decommissioning filing, approved in 2015, was used for
regulatory presentation in 2020, 2019 and 2018. Although there was a
nuclear triennial filing in 2017, the MPUC continued to approve the 2014
triennial filing as the regulatory basis in 2020, 2019 and 2018. In December
2020, the MPUC verbally approved NSP-Minnesota to continue using the
2014 filing as the basis for 2021.
Leases
Xcel Energy evaluates contracts that may contain leases, including PPAs
and arrangements for the use of office space and other facilities, vehicles
and equipment. A contract contains a lease if it conveys the exclusive right
to control the use of a specific asset. A contract determined to contain a
lease is evaluated further to determine if the arrangement is a finance
lease.
ROU assets represent Xcel Energy's rights to use leased assets. The
present value of future operating lease payments are recognized in other
current liabilities and noncurrent operating lease liabilities. These amounts,
adjusted for any prepayments or incentives, are recognized as operating
lease ROU assets.
Most of Xcel Energy’s leases do not contain a readily determinable
discount rate. Therefore, the present value of future lease payments is
the applicable Xcel Energy subsidiary’s
generally calculated using
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)
PPAs
Other
Gross operating lease ROU assets
Accumulated amortization
Net operating lease ROU assets
Dec. 31, 2020
(a)
Dec. 31, 2019
$
$
1,650 $
212
1,862
(372)
1,490 $
1,642
201
1,843
(171)
1,672
(a)
In 2020, Xcel Energy purchased MEC, which was subsequently sold. During the period
of ownership, the MEC PPA was not accounted for as an operating lease. Xcel Energy
reestablished the operating lease ROU asset of approximately $350 million upon the
sale of MEC to a third party.
ROU assets for finance leases are included in other noncurrent assets, and
the present value of future finance lease payments is included in other
current liabilities and other noncurrent liabilities.
Xcel Energy’s most significant finance lease activities are related to WYCO,
a joint venture with CIG, to develop and lease natural gas pipeline, storage
and compression facilities. Xcel Energy Inc. has a 50% ownership interest
in WYCO. WYCO leases its facilities to CIG, and CIG operates the
facilities, providing natural gas storage and transportation services to PSCo
under separate service agreements.
PSCo accounts for its Totem natural gas storage service and Front Range
pipeline arrangements with CIG and WYCO, respectively, as finance
leases. Xcel Energy Inc. eliminates 50% of the finance lease obligation
related to WYCO in the consolidated balance sheet along with an equal
amount of Xcel Energy Inc.’s equity investment in WYCO.
Finance lease ROU assets:
(Millions of Dollars)
Gas storage facilities
Gas pipeline
Gross finance lease ROU assets
Accumulated amortization
Net finance lease ROU assets
74
Dec. 31, 2020
Dec. 31, 2019
$
$
201
$
21
222
(90)
132
$
201
21
222
(83)
139
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
$
$
$
$
2020
2019
2018
238
$
221
$
26
34
264
$
255
$
7
$
18
25
$
6
$
19
25
$
210
38
248
6
19
25
(a)
(b)
Includes short-term lease expense of $5 million for 2020, 2019 and 2018.
At Dec. 31, 2020, the estimated future payments for capacity and energy
that the utility subsidiaries of Xcel Energy are obligated to purchase
pursuant to these executory contracts, subject to availability, were as
follows:
(Millions of Dollars)
2021
2022
2023
2024
2025
Thereafter
Total
Capacity
Energy (a)
$
$
71
75
77
72
29
24
348
$
$
156
172
176
181
60
85
830
PPA capacity payments are included in electric fuel and purchased power on the
(a)
consolidated statements of income. Expense for other operating leases is included in
Excludes contingent energy payments for renewable energy PPAs.
O&M expense and electric fuel and purchased power.
Commitments under operating and finance leases as of Dec. 31, 2020:
(a) (b)
PPA
Operating
Leases
Other
Operating
Leases
Total
Operating
Leases
Finance
Leases
(c)
(Millions of Dollars)
2021
2022
2023
2024
2025
Thereafter
$
$
247
228
218
209
189
561
Total minimum obligation
Interest component of obligation
1,652
(262)
Present value of minimum
obligation
Less current portion
Noncurrent operating and
finance lease liabilities
$
1,390
$
26
30
21
21
15
94
207
(39)
168
$
273
258
239
230
204
655
1,859
(301)
1,558
(214)
$
1,344
$
14
12
12
12
10
197
257
(180)
77
(4)
73
8.5
36.5
Weighted-average remaining
lease term in years
(a)
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 2033.
Excludes certain amounts related to Xcel Energy’s 50% ownership interest in WYCO.
PPAs and Fuel Contracts
Non-Lease PPAs — NSP Minnesota, PSCo and SPS have entered into
PPAs with other utilities and energy suppliers with various expiration dates
through 2033 for purchased power to meet system load and energy
requirements, operating reserve obligations and as part of wholesale and
commodity trading activities. In general, these agreements provide for
energy payments, based on actual energy delivered and capacity
payments. Certain PPAs accounted for as executory contracts contain
minimum energy purchase commitments, and total energy payments on
those contracts were $112 million, $102 million and $105 million in 2020,
2019 and 2018, respectively.
Included in electric fuel and purchased power expenses for PPAs
accounted for as executory contracts were payments for capacity of $75
million, $86 million and $131 million in 2020, 2019 and 2018, respectively.
Capacity and energy payments are contingent on the IPPs meeting
contract obligations, including plant availability requirements. Certain
contractual payments are adjusted based on market indices. The effects of
price adjustments on financial results are mitigated through purchased
energy cost recovery mechanisms.
75
Fuel Contracts — Xcel Energy has entered into various long-term
commitments for the purchase and delivery of a significant portion of its
coal, nuclear fuel and natural gas requirements. These contracts expire
between 2021 and 2060. Xcel Energy is required to pay additional amounts
depending on actual quantities shipped under these agreements.
Estimated minimum purchases under these contracts as of Dec. 31, 2020:
(Millions of Dollars)
2021
2022
2023
2024
2025
Thereafter
Total
$
$
Coal
Nuclear fuel
101
$
87
103
83
121
274
769
$
298
165
58
24
24
52
621
Natural gas
supply
$
$
453
120
55
3
—
—
631
VIEs
$
Natural gas
supply and
transportation
$
287
280
217
165
149
708
1,806
PPAs — Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase
power from IPPs for which the utility subsidiaries are required to reimburse
fuel costs, or to participate in tolling arrangements under which the utility
subsidiaries procure the natural gas required to produce the energy that
they purchase. Xcel Energy has determined that certain IPPs are VIEs.
Xcel Energy is not subject to risk of loss from the operations of these
entities, and no significant financial support is required other than
contractual payments for energy and capacity.
In addition, certain solar PPAs provide an option to purchase emission
allowances or sharing provisions related to production credits generated by
the solar facility under contract. These specific PPAs create a variable
interest in the IPP.
Xcel Energy evaluated each of these VIEs for possible consolidation,
including review of qualitative factors such as the length and terms of the
contract, control over O&M, control over dispatch of electricity, historical
and estimated future fuel and electricity prices, and financing activities. Xcel
Energy concluded that these entities are not required to be consolidated in
its consolidated financial statements because it does not have the power to
direct the activities that most significantly impact the entities’ economic
performance.
The utility subsidiaries had approximately 4,062 MW and 3,986 MW of
capacity under long-term PPAs at Dec. 31, 2020 and 2019, respectively,
with entities that have been determined to be VIEs. Agreements have
expiration dates through 2041.
Fuel Contracts — SPS purchases all of its coal requirements for its
Harrington and Tolk plants from TUCO Inc. under contracts that will expire
in December 2022. TUCO arranges
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
Other
Dec. 31, 2020
Dec. 31, 2019
$
$
$
$
7
$
38
1
46
8
25
1
$
$
34
$
7
41
1
49
8
26
—
34
Technology Agreements — Xcel Energy has several contracts for
information technology services that extend through 2022. The contracts
are cancelable, although there are financial penalties for early termination.
Xcel Energy capitalized or expensed $110 million, $101 million and $127
million associated with
in 2020, 2019 and 2018,
respectively.
these contracts
Committed minimum payments under these obligations are $33 million in
2021 and $15 million in 2022.
Guarantees and Bond Indemnifications — Xcel Energy Inc. and its
subsidiaries provide guarantees and bond indemnities, which guarantee
payment or performance. Xcel Energy Inc.’s exposure is based upon the
net liability under the specified agreements or transactions. Most of the
guarantees and bond indemnities issued by Xcel Energy Inc. and its
subsidiaries have a stated maximum amount.
As of Dec. 31, 2020 and 2019, Xcel Energy Inc. and its subsidiaries had no
assets held as collateral related to their guarantees, bond indemnities and
indemnification agreements. Guarantees and bond indemnities issued and
outstanding for Xcel Energy were $62 million at both Dec. 31, 2020 and
2019.
Inc. and
Indemnification Agreements — Xcel Energy
its
Other
subsidiaries provide indemnifications through various contracts. These are
primarily indemnifications against adverse litigation outcomes in connection
with underwriting agreements, as well as breaches of representations and
warranties, including corporate existence, transaction authorization and
income tax matters with respect to assets sold. 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
2020
Defined Benefit
Pension and
Postretirement
Items
Total
$
(80)
$
(61)
$ (141)
(10)
(5)
(15)
(a)
5
—
(5)
(b)
—
10
5
5
10
—
$
(85)
$
(56)
$ (141)
(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.
Included in the computation of net periodic pension and postretirement benefit costs.
See Note 11 for further information.
(b)
76
Gains and
Losses on
Cash Flow
Hedges
2019
Defined Benefit
Pension and
Postretirement
Items
Total
$
(60)
$
(64)
$ (124)
Certain costs, such as common depreciation, common O&M expenses and
interest expense are allocated based on cost causation allocators across
each segment. In addition, a general allocator is used for certain general
and administrative expenses, including office supplies, rent, property
insurance and general advertising.
Xcel Energy’s segment information:
(Millions of Dollars)
Accumulated other comprehensive loss
at Jan. 1
Other comprehensive loss before
reclassifications (net of taxes of $(8)
and $—, respectively)
Losses reclassified from net
accumulated other comprehensive loss:
Interest rate derivatives (net of taxes
of $1 and $—, respectively)
Amortization of net actuarial loss (net
of taxes of $— and $1, respectively)
Net current period other comprehensive
(loss) income
Accumulated other comprehensive loss
at Dec. 31
(a)
Included in interest charges.
(b)
See Note 11 for further information.
14. Segment Information
(a)
(23)
3
—
(20)
—
(23)
(Millions of Dollars)
Regulated Electric
(b)
—
3
3
3
3
(17)
$
(80)
$
(61)
$ (141)
Included in the computation of net periodic pension and postretirement benefit costs.
Operating revenues - external
Operating revenues - external
Intersegment revenue
Total revenues
Depreciation and amortization
Interest charges and financing costs
Income tax expense
Net income
Regulated Natural Gas
Intersegment revenue
Total revenues
Depreciation and amortization
Interest charges and financing costs
Income tax expense
Total revenues
Depreciation and amortization
Interest charges and financing costs
Income tax benefit
Net loss
Consolidated Total
Total revenues
Reconciling eliminations
Total operating revenues
Depreciation and amortization
Interest charges and financing costs
Income tax (benefit) expense
Net income
2020
2019
2018
$
$
$
$
$
9,802
$
9,575
$
9,719
2
1
9,804
$
9,576
$
1,673
534
1
1,407
1,535
500
125
1,288
1
9,720
1,421
449
187
1,177
1,636
$
1,868
$
1,739
1
2
2
1,637
$
1,870
$
1,741
252
71
17
190
219
69
48
195
$
88
23
$
86
11
193
(24)
(124)
167
(45)
(111)
212
61
28
187
79
9
142
(34)
(103)
$
11,529
$
11,532
$
11,540
(3)
(3)
(3)
$
11,526
$
11,529
$
11,537
1,948
798
(6)
1,473
1,765
736
128
1,372
1,642
652
181
1,261
15. Summarized Quarterly Financial Data (Unaudited)
(Amounts in millions, except
per share data)
March 31,
2020
June 30,
2020
Sept. 30,
2020
Dec. 31,
2020
Quarter Ended
Operating revenues
Operating income
Net income
EPS total — basic
$
2,811 $
2,586 $
3,182 $
2,947
455
295
422
287
813
603
$
0.56 $
0.54 $
1.15 $
EPS total — diluted
Cash dividends declared per
common share
0.56
0.43
0.54
0.43
1.14
0.43
426
288
0.54
0.54
0.43
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
of NSP-Minnesota,
Net income
All Other
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.
Xcel Energy had equity investments in unconsolidated subsidiaries of
$165 million and $155 million as of Dec. 31, 2020 and 2019, respectively,
included in the natural gas utility and all other segments.
Asset and capital expenditure information is not provided for Xcel Energy’s
reportable segments. As an integrated electric and natural gas utility, Xcel
Energy operates significant assets that are not dedicated to a specific
business segment. Reporting assets and capital expenditures by business
segment would require arbitrary and potentially misleading allocations,
which may not necessarily reflect the assets that would be required for the
operation of the business segments on a stand-alone basis.
77
Quarter Ended
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 2021 Annual Meeting of Shareholders, which is expected to occur on
April 6, 2021, incorporated by reference. Information with respect to
Executive Officers is included in Item 1 to this report.
ITEM 11 — EXECUTIVE COMPENSATION
Information required under this Item is set forth in Xcel Energy Inc.’s Proxy
is
for
Statement
incorporated by reference.
its 2021 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 2021 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 2021 Annual Meeting of Shareholders, which is
incorporated by reference.
ITEM 14 — PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information required under this Item is contained in Xcel Energy Inc.’s
Proxy Statement for its 2021 Annual Meeting of Shareholders, which is
incorporated by reference.
(Amounts in millions, except
per share data)
March 31,
2019
June 30,
2019
Sept. 30,
2019
Dec. 31,
2019
Operating revenues
Operating income
Net income
EPS total — basic
$
3,141 $
2,577 $
3,013 $
2,798
486
315
410
238
758
527
$
0.61 $
0.46 $
1.02 $
EPS total — diluted
Cash dividends declared per
common share
0.61
0.405
0.46
0.405
1.01
0.405
450
292
0.56
0.56
0.405
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, 2020, based on an evaluation carried out under the
supervision and with the participation of Xcel Energy’s management,
including the CEO and CFO, of the effectiveness of its disclosure controls
and procedures, the CEO and CFO have concluded that Xcel Energy’s
disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
No changes in Xcel Energy’s internal control over financial reporting
occurred during the most recent fiscal quarter that materially affected, or
are reasonably likely to materially affect, Xcel Energy’s internal control over
financial reporting. Xcel Energy maintains internal control over financial
reporting to provide reasonable assurance regarding the reliability of the
financial reporting. Xcel Energy has evaluated and documented its controls
in process activities, general computer activities, and on an entity-wide
level.
During the year and in preparation for issuing its report for the year ended
Dec. 31, 2020 on internal controls under section 404 of the Sarbanes-Oxley
Act of 2002, Xcel Energy conducted testing and monitoring of its internal
control over financial reporting. Based on the control evaluation, testing and
remediation performed, Xcel Energy did not identify any material control
weaknesses, as defined under the standards and rules issued by the Public
Company Accounting Oversight Board, as approved by the SEC and as
indicated in Xcel Energy’s Management Report on Internal Controls over
Financial Reporting, which is contained in Item 8 herein.
78
PART IV
ITEM 15 — EXHIBIT AND FINANCIAL STATEMENT SCHEDULES
1
2
3
*
+
Consolidated Financial Statements
Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2020.
Report of Independent Registered Public Accounting Firm — Financial Statements and Internal Controls Over Financial Reporting
Consolidated Statements of Income — For each of the three years ended Dec. 31, 2020, 2019, and 2018.
Consolidated Statements of Comprehensive Income — For each of the three years ended Dec. 31, 2020, 2019, and 2018.
Consolidated Statements of Cash Flows — For each of the three years ended Dec. 31, 2020, 2019, and 2018.
Consolidated Balance Sheets — As of Dec. 31, 2020 and 2019.
Consolidated Statements of Common Stockholders’ Equity — For each of the three years ended Dec. 31, 2020, 2019, and 2018.
Schedule I — Condensed Financial Information of Registrant.
Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2020, 2019 and 2018.
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.
Bylaws of Xcel Energy Inc. as Amended on April 3, 2020
Description of Securities
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
Report or Registration Statement
Xcel Energy Inc. Form 8-K dated May 16,
2012
Xcel Energy Inc. Form 8-K dated April 3, 2020
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2019
Exhibit
Reference
3.01
3.01
4.01
Xcel Energy Inc. Form 8-K dated Dec. 14,
2000
Xcel Energy Inc. Form 8-K dated June 6, 2006 4.01
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
4.01
4.03
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
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. 9, dated as of March 1, 2016, by and between Xcel Energy Inc. and Wells Fargo Bank,
National Association, as Trustee
Xcel Energy Inc. Form 8-K dated March 8,
2016
4.02
Supplemental Indenture No. 10, dated as of Dec. 1, 2016, by and between Xcel Energy Inc. and Wells Fargo Bank,
National Association, as Trustee
Xcel Energy Inc. Form 8-K dated Dec. 1, 2016 4.01
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 2029 and 3.50% Senior Notes, Series due
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 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
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
79
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
4.01
10.02
10.05
10.18
10.01
10.01
10.02
10.01
10.17
Appendix
A
10.01
3.02*
4.01*
4.02*
4.03*
4.04*
4.06*
4.07*
4.08*
4.09*
4.10*
4.11*
4.12*
4.13*
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-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
dated April 5, 2011
Xcel Energy Inc. Form 8-K dated May 20,
2015
10.08
10.07
10.17
10.22
10.01
10.1
10.34
10.35
10.32
Appendix
A
10.02
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2018
Xcel Energy Inc. Form U5B dated Nov. 16,
2000
Xcel Energy Inc. Form 8-K dated June 7, 2019 99.01
10.36
H-1
Xcel Energy Inc. Form S-3 dated April 18,
2018
4(b)(3)
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2017
4.11
4.12
4.51
4(b)(7)
4.63
10.18*+
10.19*+
10.20*+
10.21*+
10.22+
10.23*+
10.24*+
10.25*
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*
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 Award Agreement 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 Sept. 1, 2019
Stock Program for Non-Employee Directors of Xcel Energy Inc. as Amended and Restated on Dec. 12, 2017 under the
2015 Omnibus Incentive Plan
Form of Services Agreement between Xcel Energy Services Inc. and utility companies
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
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 2025
Supplemental Trust Indenture dated March 1, 1998, creating $150 million principal amount of 6.5% First Mortgage
Bonds, Series due 2028
Xcel Energy Inc. Form 10-K for the year ended
Dec. 31, 2017
4.17*
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 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 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 2039
NSP-Minnesota Form 8-K dated Nov. 16,
2009
4.01
4.01
Supplemental Trust Indenture dated as of Aug. 1, 2010 between NSP-Minnesota and the Bank of New York Mellon Trust
Company, NA, as successor Trustee, creating $250 million principal amount of 1.95% First Mortgage Bonds, Series due
2015 and $250 principal amount of 4.85% First Mortgage Bonds, Series due 2040
Supplemental Trust Indenture dated as of Aug. 1, 2012 between NSP-Minnesota and the Bank of New York Mellon Trust
Company, NA, as successor Trustee, creating $300 million principal amount of 2.15% First Mortgage Bonds, Series due
2022 and $500 million principal amount of 3.40% First Mortgage Bonds, Series due 2042
Supplemental Trust Indenture dated as of May 1, 2013 between NSP-Minnesota and the Bank of New York Mellon Trust
Company, N.A., as successor Trustee, creating $400 million principal amount of 2.60% First Mortgage Bonds, Series
due 2023
Supplemental Trust Indenture dated as of May 1, 2014 between NSP-Minnesota and the Bank of New York Mellon Trust
Company, N.A., as successor Trustee, creating $300 million principal amount of 4.125% First Mortgage Bonds, Series
due 2044
Supplemental Trust Indenture dated as of Aug. 1, 2015 between NSP-Minnesota and the Bank of New York Mellon
Company, N.A., as successor Trustee, creating $300 million principal amount of 2.20% First Mortgage Bonds, Series
due 2020 and $300 million principal amount of 4.00% First Mortgage Bonds, Series due 2045
Supplemental Trust Indenture dated as of May 1, 2016 between NSP-Minnesota and the Bank of NY Mellon Trust
Company, N.A., as successor Trustee, creating $350 million principal amount of 3.60% First Mortgage Bonds, Series
due 2046
Supplemental Trust Indenture dated as of Sept. 1, 2017 between NSP-Minnesota and The Bank of New York Mellon
Trust Company, N.A., as successor Trustee, creating $600 million principal amount of 3.60% First Mortgage Bonds,
Series due 2047
NSP-Minnesota Form 8-K dated 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
4.01
80
4.31*
4.32*
10.26*
10.27*
Supplemental Trust Indenture dated as of Sept. 1, 2019 between Northern States Power Company and the Bank of New
York Mellon Trust Company, N.A., as successor Trustee, creating $600 million principal amount of 2.90% First Mortgage
Bonds, Series due 2050
Supplemental Indenture dated as of June 8, 2020 between NSP-Minnesota and the Bank of New York Mellon Trust
Company, N.A., as successor Trustee, creating $700 million principal amount of 2.60% First Mortgage Bonds, Series
due 2051
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 Sept. 10,
2019
4.01
NSP-Minnesota 8-K dated June 15, 2020
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
NSP-Wisconsin
4.33*
Supplemental and Restated Trust Indenture, dated March 1, 1991, between NSP-Wisconsin and First Wisconsin Trust
Company, providing for the issuance of First Mortgage Bonds
Xcel Energy Inc. Form S-3 dated April 18,
2018
4.34*
Trust Indenture dated Sept. 1, 2000 between NSP-Wisconsin and Firstar Bank, NA as Trustee
NSP-Wisconsin Form 8-K dated Sept. 25,
2000
4(c)(3)
4.01
4.35*
4.36*
4.37*
4.38*
4.39*
4.40*
10.28*
10.29*
PSCo
4.41*
4.42*
4.43*
4.44*
4.45*
4.46*
4.47*
4.48*
4.49*
4.50*
4.51*
4.52*
4.53*
4.54*
10.30*
Supplemental Trust Indenture dated as of Sept. 1, 2008 between NSP-Wisconsin and U.S. Bank National Association,
as successor Trustee, creating $200 million principal amount of 6.375% First Mortgage Bonds, Series due 2038
NSP-Wisconsin Form 8-K dated Sept. 3, 2008
4.01
Supplemental Trust Indenture dated as of Oct. 1, 2012 between NSP-Wisconsin and U.S. Bank National Association, as
successor Trustee, creating $100 million principal amount of 3.70% First Mortgage Bonds, Series due 2042
NSP-Wisconsin Form 8-K dated Oct. 10, 2012 4.01
Supplemental Trust Indenture dated as of June 1, 2014 between NSP-Wisconsin and U.S. Bank National Association,
as successor Trustee, creating $100 million principal amount of 3.30% First Mortgage Bonds, Series due 2024
NSP-Wisconsin Form 8-K dated June 23,
2014
4.01
Supplemental Trust Indenture dated as of Nov 1, 2017 between NSP-Wisconsin and U.S. Bank National Association, as
successor Trustee, creating $100 million principal amount of 3.75% First Mortgage Bonds, Series due 2047
NSP-Wisconsin Form 8-K dated Dec. 4, 2017
4.01
Supplemental Indenture dated as of Sept. 1, 2018 between NSP-Wisconsin and U.S. Bank National Association, as
successor Trustee, creating $200 million principal amount of 4.20% First Mortgage Bonds, Series due 2048
NSP-Wisconsin Form 8-K dated Sept. 12,
2018
4.01
Supplemental Indenture dated as of May 18, 2020 between NSP-Wisconsin and U.S. Bank National Association, as
Trustee, creating $100 million principal amount of 3.05% First Mortgage Bonds, Series due 2051
NSP-Wisconsin Form 8-K dated May 26, 2020 4.01
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
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
4.01
4.01
4.01
4.01
4.01
4.01
4.01
4.01
4.01
4.01
4.01
4.01
PSCo Form 8-K dated May 15, 2020
Xcel Energy Inc. Form 8-K dated Dec. 3, 2004 99.02
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
Proposed Settlement Agreement, excerpts, as filed with the CPUC
81
10.31*
Third Amended and Restated Credit Agreement, dated as of June 7, 2019 among PSCo, as Borrower, the several
lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A.
and Barclays Bank Plc, as Syndication Agents, Wells Fargo Bank, National Association, MUFG Bank, Ltd., and Citibank,
N.A., as Documentation Agents
Xcel Energy Inc. Form 8-K dated June 7, 2019 99.03
SPS
4.55*
4.56*
4.57*
4.58*
4.59*
4.60*
4.61*
4.62*
4.63*
4.64*
4.65*
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
Indenture dated as of Aug. 1, 2011 between SPS and U.S. Bank National Association, as Trustee
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
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 $350 million principal amount of 3.15% First Mortgage Bonds, Series due 2050
SPS Form 8-K dated May 18, 2020
99.2
4.04
4.01
4.01
4.02
4.02
4.02
4.02
4.02
4.02
4.02
10.32*
Third Amended and Restated Credit Agreement, dated as of June 7, 2019 among SPS, as Borrower, the several lenders
from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and
Barclays Bank Plc, as Syndication Agents, Wells Fargo Bank, National Association, MUFG Bank, Ltd., and Citibank,
N.A., as Documentation Agents
Xcel Energy Inc. Form 8-K dated June 7, 2019 99.04
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
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
Xcel Energy Inc.
21.01
23.01
24.01
31.01
31.02
32.01
101.INS
101.SCH Inline XBRL Schema
101.CAL
101.DEF Inline XBRL Definition
101.LAB Inline XBRL Label
101.PRE Inline XBRL Presentation
104
Inline XBRL Calculation
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
82
SCHEDULE I
XCEL ENERGY INC.
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(amounts in millions, except per share data)
XCEL ENERGY INC.
CONDENSED BALANCE SHEETS
(amounts in millions)
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
Pension and retiree medical benefits, net of tax of $ 1,
$1 and $1, respectively
Derivative instruments, net of tax of $(1), $(7) and $(1),
respectively
Other comprehensive income (loss)
Comprehensive income
Weighted average common shares outstanding:
Basic
Diluted
Earnings per average common share:
Basic
Diluted
Year Ended Dec. 31
2019
2018
2020
$ 1,646
1,646
$ 1,505
1,505
$ 1,393
1,393
Cash and cash equivalents
Accounts receivable from subsidiaries
Assets
43
(4)
198
237
1,409
(64)
$ 1,473
23
(9)
173
187
1,318
(54)
$ 1,372
24
(1)
149
172
1,221
(40)
$ 1,261
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
$
5
$
3
$
3
Other current liabilities
(5)
—
$ 1,473
(20)
(17)
$ 1,355
(2)
1
$ 1,262
527
528
519
520
511
511
$ 2.79
2.79
$ 2.64
2.64
$ 2.47
2.47
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
2020
2019
$
14
$
424
6
444
19,102
40
19,142
$
19,586
$
400
231
—
21
652
17
17
4,342
14,575
18,917
$
19,586
$
70
370
12
452
17,443
60
17,503
17,955
—
212
500
33
745
23
23
3,948
13,239
17,187
17,955
See Notes to Condensed Financial Statements
XCEL ENERGY INC.
CONDENSED STATEMENTS OF CASH FLOWS
(amounts in millions)
Year Ended Dec. 31
2020
2019
2018
Operating activities
Net cash provided by operating activities
$ 2,377
$ 1,389
$ 1,210
Investing activities
Capital contributions to subsidiaries
(2,553)
(1,594)
(809)
Net (investments) return in the utility money pool
Other, net
(18)
(1)
39
—
(85)
—
Net cash used in investing activities
(2,572)
(1,555)
(894)
Financing activities
(Repayment of) proceeds from short-term borrowings,
net
(500)
12
(295)
Proceeds from issuance of long-term debt
1,089
1,120
Repayment of long-term debt
Proceeds from issuance of common stock
Repurchase of common stock
Dividends paid
Other
Net cash provided by (used in) financing activities
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
$
(300)
727
(4)
(856)
(17)
139
(56)
70
14
(550)
458
—
(791)
(14)
235
69
1
$
70
$
See Notes to Condensed Financial Statements
492
—
230
(1)
(730)
(12)
(316)
—
1
1
83
See Notes to Condensed Financial Statements
Notes to Condensed Financial Statements
Incorporated by reference are Xcel Energy’s consolidated statements of
common stockholders’ equity and other comprehensive income in Part II,
Item 8.
Basis of Presentation — The condensed financial information of Xcel
Energy Inc. is presented to comply with Rule 12-04 of Regulation S-X. Xcel
Energy Inc.’s investments in subsidiaries are presented under the equity
method of accounting. Under this method, the assets and liabilities of
subsidiaries are not consolidated. The investments in net assets of the
subsidiaries are recorded in the balance sheets. The income from
operations of the subsidiaries is reported on a net basis as equity in income
of subsidiaries.
As a holding company with no business operations, Xcel Energy Inc.’s
assets consist primarily of investments in its utility subsidiaries. Xcel Energy
Inc.’s material cash inflows are only from dividends and other payments
received from its utility subsidiaries and the proceeds raised from the sale
of debt and equity securities. The ability of its utility subsidiaries to make
dividend and other payments is subject to the availability of funds after
taking into account their respective funding requirements, the terms of their
respective indebtedness, the regulations of the FERC under the Federal
Power Act, and applicable state laws. Management does not expect
maintaining these requirements to have an impact on Xcel Energy Inc.’s
ability to pay dividends at the current level in the foreseeable future. Each
of its utility subsidiaries, however, is legally distinct and has no obligation,
contingent or otherwise, to make funds available to Xcel Energy Inc.
Guarantees and Indemnifications
Xcel Energy Inc. provides guarantees and bond indemnities under specified
agreements or transactions, which guarantee payment or performance.
Xcel Energy Inc.’s exposure is based upon the net liability of the relevant
subsidiary under the specified agreements or transactions. Most of the
guarantees and bond indemnities issued by Xcel Energy Inc. limit the
exposure to a maximum stated amount. As of Dec. 31, 2020 and 2019,
Xcel Energy Inc. had no assets held as collateral related to guarantees,
bond indemnities and indemnification agreements.
Guarantees and bond indemnities issued and outstanding as of Dec. 31,
2020:
(Millions of Dollars)
Guarantor
Guarantee 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.
Xcel Energy
Inc.
Guarantee
Amount
Current
Exposure
Triggering
Event
$
1
—
60
(e)
(c)
(d)
(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
companies, surety companies have the discretion to demand that collateral be posted.
Due to the magnitude of projects associated with the surety bonds, the total current
exposure of this indemnification cannot be determined. Xcel Energy Inc. believes the
exposure to be significantly less than the total amount of the outstanding bonds.
Indemnification Agreements
Xcel Energy Inc. provides indemnifications through contracts entered into in
the normal course of business. Indemnifications are primarily against
adverse litigation outcomes in connection with underwriting agreements,
breaches of representations and warranties, including corporate existence,
transaction authorization and certain income tax matters. Obligations under
these agreements may be limited in terms of duration or amount. Maximum
future payments under these indemnifications cannot be reasonably
estimated as the dollar amounts are often not explicitly stated.
Related Party Transactions — Xcel Energy Inc. presents related party
receivables net of payables. Accounts receivable net of payables with
affiliates at Dec. 31:
(Millions of Dollars)
NSP-Minnesota
NSP-Wisconsin
PSCo
SPS
Xcel Energy Services Inc.
Xcel Energy Ventures Inc.
Other subsidiaries of Xcel Energy Inc.
$
$
2020
2019
81
9
98
55
159
—
22
424
$
$
60
17
78
47
112
25
31
370
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
Weighted average interest rate at end of period
Money pool interest income
Three Months Ended
Dec. 31, 2020
$
$
57
185
318
0.08 %
0.07 %
—
(Amounts in Millions, Except
Interest Rates)
Year Ended
Dec. 31, 2020
Year Ended
Dec. 31, 2019
Year Ended
Dec. 31, 2018
Loan outstanding at period end
$
Average loan outstanding
Maximum loan outstanding
Weighted average interest rate,
computed on a daily basis
Weighted average interest rate at
end of period
$
57
104
350
0.60 %
0.07 %
$
39
47
250
2.15 %
1.63 %
Money pool interest income
$
1
$
1
$
—
71
243
1.95 %
N/A
1
See notes to the consolidated financial statements in Part II, Item 8.
SCHEDULE II
Xcel Energy Inc. and Subsidiaries Valuation and Qualifying Accounts
Years Ended Dec. 31
Allowance for bad debts
NOL and tax credit valuation
allowances
(Millions of Dollars)
Balance at Jan. 1
2020
$ 55
2019
$ 55
2018
$ 52
2020
$ 67
2019
$ 79
2018
$ 77
Additions charged to
costs and expenses
Additions charged to
other accounts
Deductions from
reserves
60
42
42
6
9
7
12
(a)
16
(a)
11
(a)
—
—
—
(48) (b)
(58) (b)
(50) (b)
(9) (c)
(21) (d)
(5) (d)
Balance at Dec. 31
$ 79
$ 55
$ 55
$ 64
$ 67
$ 79
(a)
(b)
(c)
(d)
Recovery of amounts previously written-off.
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
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 $2,527 million, $2,987 million and $1,097 million for the years ended
Dec. 31, 2020, 2019 and 2018, respectively. These cash receipts are
included in operating cash flows of the condensed statements of cash
flows.
None.
84
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. 17, 2021
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/ BEN FOWKE
Ben Fowke
/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
David K. Owens
Charles Pardee
Christopher J. Policinski
James Prokopanko
James J. Sheppard
David A. Westerlund
Kim Williams
Timothy V. Wolf
Daniel Yohannes
*
*
*
*
*
*
*
*
*
*
*
*
*
*
Chairman, 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
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
*By:
/s/ BRIAN J. VAN ABEL
Brian J. Van Abel
Attorney-in-Fact
85
FOWKE ADVOCATES FOR
RACIAL EQUITY AS EEI CHAIR
In June, Xcel Energy Chairman and CEO Ben Fowke was elected Chairman of Edison Electric Institute, our
industry trade association, after serving as Vice Chair last year. He originally planned to focus on the clean
energy transition and COVID-19 recovery, but two weeks before his one-year term began, Ben and most of
the country saw the footage of George Floyd’s death while in police custody in south Minneapolis.
Calling the incident that occurred only a few miles from Xcel Energy’s corporate headquarters “an awakening,”
Ben knew that addressing racial equity was too important to not include in his platform. Ben, who was named
2020 Executive of the Year by Utility Dive, quickly rallied the industry and gained commitments from 57 CEOs
to address racial equity in their companies and communities, starting with four core principles: 1) Ensuring
diversity, equity and inclusion efforts are driven from the top 2) Removing barriers to entry and broadening
talent pools 3) Establishing strong community connections, and 4) Developing infrastructure academies and
training programs.
Xcel Energy added a diversity, equity and inclusion corporate scorecard metric for 2021, tying executive
and employee compensation to demonstrate our commitment to diversity, equity and inclusion and
improved hiring and sponsorship practices. This metric is designed to create accountability in our
leadership team and the company as a whole to reduce the barriers to a diverse workforce.
FINANCIAL HIGHLIGHTS
EARNINGS PER SHARE
2019
2020
Dollars per share (diluted)
Total GAAP earnings per share
2.64
2.79
Ongoing earnings per share
2.64
2.79
7
4
.
2
7
4
.
2
4
6
.
2
4
6
.
2
9
7
.
2
9
7
.
2
Dividends annualized
1.62
1.72
Stock price (close)
63.49
66.67
Assets (millions)
50,448
53,957
COMPANY DESCRIPTION
Xcel Energy is a major U.S. electric and natural gas
company with annual revenues of $11.5 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.
2018
2019
2020
GAAP (generally accepted accounting
principles) earnings per share
Ongoing earnings per share
ON THE COVER:
Adolphus Ugeh, a member of our Transmission Field
Operations team, is pictured at a new transmission
substation near Golden, Colorado. He is one of
thousands of Xcel Energy essential workers responsible
for providing safe, reliable energy for our customers.
SHAREHOLDER INFORMATION
HEADQUARTERS
414 Nicollet Mall, Minneapolis, MN 55401
WEBSITE
xcelenergy.com
STOCK TRANSFER AGENT
EQ Shareowner Services
1110 Centre Pointe Curve, Suite 101
Mendota Heights, MN 55120
Telephone: 877-778-6786, toll free
REPORTS AVAILABLE ONLINE
Financial reports, including filings with the Securities and
Exchange Commission and 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, Corporate
Responsibility 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, Investor Relations, at 612-215-4535.
SHAREHOLDER SERVICES
Website: 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 2020.
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
Ben Fowke
Chairman 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
David Owens 2,4
Retired Executive,
Edison Electric Institute
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
James Sheppard 2,4
Independent Consultant
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
X
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FISCAL AGENTS
XCEL ENERGY INC.
Transfer Agent, Registrar, Dividend
Distribution, Common Stock
EQ Shareowner Services,
1110 Centre Pointe Curve, Suite 101
Mendota Heights, MN 55120
Trustee–Bonds
Wells Fargo Bank, N.A.,
Corporate Trust Services
600 South 4th Street
Minneapolis, MN 55415
xcelenergy.com | © 2021 Xcel Energy Inc. | Xcel Energy is a
registered trademark of Xcel Energy Inc. | 21-02-126