Xcel Energy Annual Report 2019

FY2019 Annual Report · Xcel Energy

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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

THE FUTURE
IN SIGHT

2019 ANNUAL REPORT

FIFTEEN YEARS OF EARNINGS EXCELLENCE

It’s a 15th anniversary of providing excellent shareholder value worth celebrating.

Xcel Energy achieved its earnings target once again in 2019, marking the
15th consecutive year of meeting or exceeding our earnings guidance.

“It’s an outstanding track record that few companies in our peer group can
match,” said Bob Frenzel, Xcel Energy’s President and Chief Operating Officer.
“Shareholders have been — and continue to be — attracted to our story of solid,
dependable earnings growth. Our capital investment strategy that is driving the
clean energy transition continues to pay dividends for our shareholders.”

The company’s 15-year Total Shareholder Return is 531% compared to 378% for
our peer group. We also increased your dividend in 2019, extending the streak
of dividend growth to 16 consecutive years. The combination of solid dividends
and strong earnings growth has driven our Total Shareholder Return, significantly
outpacing our peer group.

FINANCIAL HIGHLIGHTS

EARNINGS PER SHARE

2018

2019

Dollars per share (diluted)

Total GAAP earnings per share

2.47

2.64

Ongoing earnings per share

2.47

2.64

5
2
.
2

0
3
.
2

7
4
.
2

4
6
.
2

Dividends annualized

1.52

1.62

Stock price (close)

49.27

63.49

Assets (millions)

45,987

50,448

2017*

2018

2019

GAAP (generally accepted accounting
principles) earnings per share

Ongoing earnings per share

* A reconciliation to GAAP earnings per share
is located in Item 7 of the 2017 Form 10-K.

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 3.6 million electricity customers and 2 million natural gas 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 appears 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 2019. It has also filed with the New
York Stock Exchange the CEO certification for 2019 required by section
303A.12(a) of the New York Stock Exchange’s rules relating to compliance
with the New York Stock Exchange’s corporate governance listing standards.

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.

The Xcel Energy Board of Directors (from left to right): Tim Wolf, Richard Davis, David
Westerlund, Lynn Casey, Chris Policinski, David Owens, Ben Fowke, Kim Williams,
Richard O’Brien, Daniel Yohannes, Jim Prokopanko, James Sheppard and Pat
Sampson. Not pictured are new board members: Netha Johnson and George Kehl.

XCEL ENERGY BOARD OF DIRECTORS
Lynn Casey 3,4
Retired Chair and CEO, Padilla

Richard K. Davis 2,3
President and CEO,
Make-A-Wish Foundation

Ben Fowke
Chairman and CEO,
Xcel Energy Inc.

Netha Johnson 4
President, Bromine Specialties
and Global IT, Albemarle Corporation

George Kehl 1
Retired Managing Partner, KPMG

Richard T. O’Brien 1,4
Independent Consultant

David K. Owens 3,4
Retired Executive,
Edison Electric Institute

Christopher J. Policinski 2
Lead Independent Director
Retired President and CEO,
Land O’ Lakes, Inc.

James Prokopanko 2,4
Retired President and CEO,
The Mosaic Company

A. Patricia Sampson 1,3
CEO, President and Owner,
The Sampson Group, Inc.

James J. Sheppard 3,4
Independent Consultant

David A. Westerlund 1,2
Retired Executive Vice President,
Administration and Corporate Secretary,
Ball Corporation

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

Timothy V. Wolf 1,4
President,
Wolf Interests, Inc.

Daniel Yohannes 1,3
Former United States Ambassador
to the Organization for Economic
Cooperation and Development

Board Committees:
1. Audit
2. Governance, Compensation

and Nominating

3. Finance
4. Operations, Nuclear,

Environmental and Safety

DEAR FELLOW
SHAREHOLDERS:

Ben Fowke
Chairman and
Chief Executive Officer

ANNUAL REPORT 2019THE FUTURE IN SIGHTOutstanding financial results and strong operational performance are on the long list of 2019 accomplishments for Xcel Energy. The company made significant strides in several areas — enhancing the customer experience, driving continuous improvement, embracing innovation and, of course, leading the clean energy transition. In late 2018, we became the first U.S. electricity company to announce a vision to produce 100% carbon-free electricity by 2050. Since our announcement, several public utilities have declared similar goals, indicating the industry has a strong appetite to prepare for a carbon-free future. This year we made good progress toward our interim goal of reducing carbon emissions 80% by 2030 — we’re more than halfway there — and expect to achieve that goal by retiring coal plants early, adding more wind and solar, extending the license of our Monticello Nuclear Generating Station, using natural gas to ensure reliability, and expanding energy efficiency programs. New dispatchable carbon-free technologies need to be developed to remove the last 20% of carbon, and Xcel Energy is leading the industry’s efforts to advocate for research and development. We chose “The Future In Sight” as the theme for the report because we’ve set plans in place to move away from coal while taking care of impacted employees — through retraining and reassignments — and impacted communities by driving economic development opportunities. The future is also in sight as we transform the customer experience, from modernizing the electrical grid to developing electricity pricing, infrastructure and charging programs to make it easy for customers to switch to electric vehicles.Of course, those efforts to build the future supplement our core responsibility to deliver safe, reliable, affordable and clean energy to our customers and the outstanding performance that our shareholders have come to expect.OUTSTANDING FINANCIAL PERFORMANCEFor the 15th consecutive year, we met or exceeded our earnings guidance. We delivered 2019 earnings of $2.64 per share, at the top end of our original earnings guidance range, compared to $2.47 per share in 2018. Xcel Energy also increased your dividend by 6.6%, or 10 cents annually in 2019, extending our streak of dividend growth to 16 consecutive years. We maintained our earnings and dividend objective of 5 to 7% annual growth, which reflects our confidence in our long-term financial plan. As a result of our continued strong performance, our one-year total shareholder return exceeded 32% in 2019, outpacing our peer group. We also compare favorably to our peer group for three-, five- and 10-year performance results. In addition, our stock price (ticker: XEL) closed at an all-time high of $65.82 in September and has subsequently set several new all-time highs in early 2020, closing above $71 per share.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 shareholders in 2020 and beyond.3

ANNUAL REPORT 2019STEEL FOR FUEL EXECUTIONAs part of our Steel for Fuel growth strategy, we continue to build carbon-free wind farms that save money for our customers by avoiding future fuel costs. In 2019, we added more than 700 megawatts of company-owned wind capacity through the completion of three wind farms: Hale in Texas, Foxtail in North Dakota and Lake Benton in Minnesota. Developing — and owning — wind projects has become a core competency that provides excellent investment opportunities for our shareholders. These projects also stimulate the economy in rural areas through jobs, tax base and landowner lease payments (see story on pages 5-6).Additionally, seven company-owned wind projects continue in various stages of construction. Six of these projects are on pace to be completed before the end of 2020 to take full advantage of the federal production tax credit before it begins to phase down. Our ability to forecast wind energy for optimum efficiency allows us to save money for our customers. We’re also executing our Steel for Fuel strategy by acquiring expiring wind energy PPAs (power purchase agreements) and rebuilding those wind farms with the latest advanced wind technology. Lake Benton was a PPA acquisition, and we received regulatory approval for the Jeffers and Community Wind North repowering projects in southern Minnesota. We anticipate more repowering acquisition opportunities in 2020 and beyond as numerous PPA contracts expire during the next decade. We plan to make significant investments in large-scale solar starting in the mid-2020s. By the end of 2021, we expect to grow our wind ownership by fivefold compared to 2016. While our wind portfolio continues to expand, our carbon emissions continue to fall — declining 10% last year, the largest one-year reduction (5.6 million tons) since the clean energy transition began. At the end of 2019, we had lowered our carbon emissions from the electricity serving customers 44% since 2005. DEVELOPING AN INNOVATIVE SPIRITWe know we can’t achieve our vision to produce 100% carbon-free electricity by 2050 without the development of technologies that either don’t yet exist or aren’t commercially viable today. Although we are taking an agnostic approach to technology — letting the best ideas rise to the top — it doesn’t mean we are simply waiting for others to do the heavy lifting.A cross-functional team of Xcel Energy employees has collected data and prioritized 34 emerging technologies into five categories. Some of the promising dispatchable carbon-free options include the next generation of nuclear technology, carbon capture at fossil plants, advanced renewable and storage options and using hydrogen in applications both in the utility industry and across the economy. We are partnering with the Idaho National Lab on a pilot program at one of our generating stations to use carbon-free nuclear energy to produce hydrogen. We are also working closely with EPRI, our industry research and development consortium, to support promising technologies, and have implemented flexible operations at our nuclear and coal facilities, using them less often on high renewable output days to reduce carbon and save customers money.Developing new technologies is critical for our entire industry and for the nation as we transition away from carbon. In my role as incoming chairman for the Edison Electric Institute, our industry trade association, making significant progress on this issue will be a key part of my platform.Innovation has been a focus of our organization for the last few years. Our employees have led the charge to find new and innovative ways to drive continuous improvement throughout our business. This cultural mindset is now ingrained in how we systematically approach our work. These ideas have led to $170 million of ongoing savings with more to come.TRANSFORMING THE CUSTOMER EXPERIENCEAn innovative spirit also permeates our approach to transforming the customer experience. Competition continues to rise, and when our customers face a choice, we want them to choose us. Last year, we kicked off our plans to transform the customer experience and completed foundational work in several areas.We partnered with industry leader Itron to develop state-of-the-art smart meters to build the energy grid of the future that will improve reliability and offer customers real-time information to manage their energy use (see page 11). We also advanced foundational work to improve the experience when new customers sign up for service, expanded our electric vehicle program with new filings in several states (see pages 9-10) and developed more coverage options for our HomeSmart® appliance repair plan.Customers appreciate the opportunity to make choices, both in terms of choosing their energy supply mix and the way they engage with us. More than 200,000 customers participated in renewable programs in 2019, and we sold out our Solar*Connect Community program in Wisconsin. Improvement to our customers’ digital experience is evidenced by our automated phone system that handled more than 60% of customer calls with high customer satisfaction. At the end of 2019, more than 625,000 customers had downloaded our mobile app that provides outage information and the opportunity for customers to pay their bill and communicate with us.DELIVERING ON THE FUNDAMENTALSAlthough we focus a great deal of time and energy on our strategic priorities, we never lose sight of our core 4

THE FUTURE IN SIGHTmission to provide the safe, reliable and affordable electricity and natural gas you count on every day.Electric system reliability was second quartile and exceeded 99.9%, improving on last year’s strong performance. In recognition of our track record of restoring service to customers quickly, we received two EEI Emergency Recovery Awards for our efforts following the Colorado bomb cyclone in March and a South Dakota tornado in September.By adding staff and using GPS technology to better assign our crews, we delivered our best-ever performance in natural gas emergency response times for the fifth consecutive year — a 6% improvement over 2018, and a 25% improvement since 2014. Xcel Energy recently joined ONE Future, a consortium of natural gas companies working to voluntarily reduce methane emissions below 1%, by 2025. Ensuring public safety is a critical aspect of our work, one that is important to all stakeholders, and we are positioned to build on this performance. We also reevaluated our employee safety program with a growing focus to prevent life-altering injuries.Our nuclear performance was industry leading in 2019, with both generating stations receiving the highest ratings available from regulators. Last year, despite our national leadership in renewable energy, our nuclear fleet provided nearly half of the company’s carbon-free electricity, and the fleet produced the second-highest generation output in its history, all while reducing costs for the fourth consecutive year. REGULATORY PROGRESSStrong nuclear performance is paramount and positions us favorably as we request a 10-year license extension for our Monticello Nuclear Generating Station as part of our proposed plan to achieve our 80% carbon-reduction goal. Nuclear energy is essential to achieve our clean energy plans, and our plants have never performed better. The Minnesota commission is reviewing our proposal that also includes the early retirement of all coal in Minnesota by 2030, the addition of wind and solar and the utilization of natural gas to enhance system reliability.In early 2020, the company closed on a $650 million transaction to purchase the Mankato Energy Center — a 760-megawatt natural gas combined-cycle facility in southern Minnesota — from Southern Power as a non-regulated asset. We believe the agreement will help ensure reliability as we retire our coal fleet and allows us to integrate more renewable energy on our system. Although this investment is not included in rate base, it is expected to generate “utility like” returns over its life. In Colorado, we continue to implement the Colorado Energy Plan and moved forward with our newest wind project in the state, the 500-megawatt Cheyenne Ridge Wind Farm that will be completed this year to earn the full production tax credit. Another significant accomplishment was getting transmission access for the 522-megawatt Sagamore Wind Farm in New Mexico — scheduled to be completed in 2020 — despite significant logistical challenges. We also achieved constructive rate case outcomes in most jurisdictions, the result of successful stakeholder outreach.EMPLOYEES LEAD THE WAYSuccessful outcomes don’t just happen, they are the result of thousands of hours of effort from our teams of dedicated employees. I’m proud to lead a team of more than 11,000 strong, committed to delivering for our stakeholders. We bring an innovative spirit to work each day and understand the importance of powering the lives of millions of residential and business customers. These efforts are gaining national recognition. We were named as one of Fortune magazine’s “World’s Most Admired” companies for the seventh consecutive year, one of Corporate Responsibility Magazine’s 100 Best Corporate Citizens and among Newsweek’s Most Responsible Companies. Recent honors include the S&P Global Award of Excellence and 2020 Climate Leadership Award for our clean energy leadership and progress in reducing carbon emissions.Working for a values-based organization is important to our employees. Earlier this year, Ethisphere named us one of 2020’s World’s Most Ethical Companies®. That award reflects a clear understanding of our values — Safe, Trustworthy, Connected and Committed — and our commitment to our recently refreshed Code of Conduct that guides our decision-making principles. Just as doing the right thing every day is important, giving back to communities is also ingrained in our DNA. Last year our employees, boosted by matching dollars from the Xcel Energy Foundation, donated more than $3.4 million and 73,000 volunteer hours to community organizations that they care about.On multiple fronts — from our carbon-free vision to our customer experience transformation to preparing for a world when electric vehicles gain significant market share — the future is clearly in sight. It’s a future we strive for every day, while never losing sight of our obligation to deliver safe, clean, reliable and affordable energy today. We enter the 2020s with momentum, optimism and appreciation. Thanks for your continued partnership and the trust you place in us.Sincerely, Ben Fowke Chairman and Chief Executive Officer WIND FARMS
DRIVE RURAL
ECONOMIC
DEVELOPMENT

NORTH DAKOTA PROJECT WILL GENERATE
$30 MILLION OF LANDOWNER LEASE
PAYMENTS AND PROVIDE TAX BENEFITS
FOR STATE AND LOCAL GOVERNMENTS

ANNUAL REPORT 2019ANNUAL REPORT 2019

Geraldine and Willis Blumhardt are among a
group of 35 landowners in Dickey County,
North Dakota who supported the building
of Xcel Energy’s Foxtail Wind Farm that was
completed in December under budget.

THE FUTURE IN SIGHTGROWING UP ON her family farm outside of Ellendale, North Dakota, Geraldine Blumhardt spent her formative years helping with chores while her parents tended to the cattle and a variety of crops — mostly wheat, small grains and hay.Fast forward five decades. Geraldine’s family no longer farms the land but generates income by renting it to local ranchers and farmers. Geraldine and her sister Violet Rasch, who co-owns the property, never expected their farmland would generate additional income from a non-farming source like wind energy.Geraldine and her sister are among a group of 35 landowners in Dickey County who came together to support the development of Foxtail Wind Farm, Xcel Energy’s newest wind project that will generate more than $30 million in landowner lease payments over the life of the project and produce enough carbon-free renewable energy to power 80,000 average-sized homes annually. “We negotiated a fair price,” Geraldine said about her decision to allow Xcel Energy to build eight of the 75 wind towers on 1,200 acres of her property. “We’re not big spenders — we will probably invest the proceeds somehow.”Preliminary work for the project including substation construction and building access roads and tower foundations began in 2018, but all tower assembly took place during the last eight months of 2019. “I was surprised by how big the wind tower components are and how fast they could be assembled,” she said.The landowners aren’t the only ones who are benefitting financially from the wind project, which created 100 construction jobs and 10 full-time operational positions. Foxtail is expected to provide more than $20 million of additional revenue for state and local governments and the nearby school district, and generate significant customer savings.“Our wind projects provide significant economic and environmental benefits,” said Sean Lawler, a Siting and Land Rights Agent who led communication efforts with landowners during the construction of Foxtail and continues to lead outreach efforts. “The county, local businesses and the school district have all benefitted from Foxtail and will continue to do so for decades.”Foxtail is the first Xcel Energy wind project that will feature an Aircraft Detection Lighting System that activates red blinking lights on the wind towers only when an aircraft is in the immediate area, otherwise keeping the night skies dark.Xcel Energy is currently developing the largest multi-state wind expansion in the country — with approximately 15 projects that have been completed or are under construction. This includes building new farms and repowering older farms with new technology. By the end of 2021, we will own 73% of the 4,800 megawatts of wind capacity on our system. Wind energy plays an important role in our efforts to reduce carbon emissions 80% by 2030 and produce 100% carbon-free electricity by 2050. 7

ANNUAL REPORT 2019IN 2018 XCEL ENERGY became the first major electricity provider in the country to announce a vision to produce 100% carbon-free electricity by 2050. On the path to carbon-free energy, we also announced an interim goal of achieving an 80% carbon reduction from 2005 levels by 2030 while enhancing reliability and ensuring affordability.“Our carbon-free vision has been well received by our stakeholders. One of the benefits of being the first company to announce our vision is that we have a seat at the table and can help shape public policy, which will play an important role in our success,” said Ben Fowke, Xcel Energy’s Chairman and CEO. “Several other public utilities have followed our lead and have announced similar goals.”Company engineers believe we can achieve the 80% interim goal by 2030 using existing technologies. Removing the last 20% of carbon will require carbon-free dispatchable resources that currently don’t exist or are not commercially viable. A cross-functional Xcel Energy team has studied 34 technologies in five priority areas in our efforts to partner with our industry peers to develop and promote solutions that work for all of us. Possible solutions could include longer-term battery storage, advanced nuclear, hydrogen or carbon capture at natural gas facilities.To achieve our 2030 goal, we expect to take a balanced approach to our energy supply. Our Upper Midwest Energy Plan proposal in front of the Minnesota Public Utilities Commission includes expanding energy efficiency programs, retiring all coal plants in Minnesota by 2030, adding 5,000 megawatts of wind and solar energy, extending the operating license for our Monticello Nuclear Generating Station by a decade — from 2030 to 2040 — and adding natural gas and battery storage.“Nuclear energy is an important part of the equation because it’s the only 24x7 carbon-free dispatchable resource available. Natural gas provides important qualities for grid health. It’s an important fuel source that allows us to integrate more renewable energy and continue to deliver the reliability our customers expect,” Fowke said. Natural gas produces approximately half the carbon output as coal plants. After receiving approval through an unregulated subsidiary in early 2020, we closed on the acquisition of the $650 million Mankato Energy Center, a 760-megawatt natural gas facility in southern Minnesota that helps ensure reliability and allows us to integrate more renewable energy on our system.“The Mankato Energy Center acquisition provides long-term value to our customers and shareholders, especially as we accelerate the retirement of coal plants,” said Paul Johnson, Vice President, Investor Relations, noting the facility is the largest natural gas operation in the company’s portfolio.The company continues to develop resource plans in all the territories we serve. We expect to file a Colorado resource plan in late 2020 or early 2021. A BALANCED
APPROACH

MIX OF RENEWABLE ENERGY SOURCES,
COMBINED WITH NUCLEAR AND NATURAL GAS,
KEY TO ACHIEVING 80% CARBON REDUCTION

The Cherokee Generating
Station is a natural gas
combined-cycle plant in
Denver, Colorado. Natural
gas allows us to incorporate
more renewables and
ensure reliability.

THE FUTURE IN SIGHTXcel Energy employees
Barb Jerhoff and Tom
Santori visit along Metro
Transit’s new C Line
in Minneapolis that is
supported by electric
buses. Barb manages
the relationship between
Xcel Energy and Metro
Transit and Tom develops
new programs to support
electric vehicles.

ANNUAL REPORT 2019ANNUAL REPORT 2019

ELECTRIC BUSES
ARRIVE IN
MINNEAPOLIS

COMPANY DEVELOPING ELECTRIC VEHICLE PROGRAMS
IN MULTIPLE STATES TO SUPPORT HOME CHARGING,
PUBLIC CHARGING AND FLEET ELECTRIFICATION

THE FUTURE IN SIGHTTHE FIRST ELECTRIC BUSES manufactured in Minnesota are quietly transporting passengers in the Twin Cities using electricity supplied by Xcel Energy.Metro Transit purchased eight New Flyer electric buses that were built in St. Cloud, Minnesota at a manufacturing facility powered by Xcel Energy natural gas. The 60-foot buses charge overnight at a Metro Transit garage in the Twin Cities but can also charge at an outdoor charging station if they need to be topped off during the day.“The rollout of electric buses in the state is another visible sign that electric vehicles continue to gain traction in Minnesota and across our service territory,” said Tom Santori, who develops programs to support the company’s EV efforts. “Electric buses are much more quiet than traditional buses, and the feedback from riders and neighbors on the C Line electric bus route has been overwhelmingly positive. It’s a better experience for everyone.”Xcel Energy is working closely with our regulators to develop electric vehicle programs to serve our customers who are looking for ways to save money on gas and maintenance and simultaneously reduce their carbon footprint. Electric vehicles that charge overnight during off-peak hours cost less than the equivalent of $1 per gallon of gas, and their carbon emissions are one-third lower than gasoline-powered vehicles. Those emissions will continue to drop as Xcel Energy strives to reduce carbon emissions 80% by 2030.“In addition to Minnesota, we have plans for electric vehicle programs in Colorado, New Mexico and Wisconsin,” Santori said. “We completed significant foundational work in 2019 and expect 2020 will be a big year for EVs and Xcel Energy.”The company is focusing its EV efforts in three areas: home charging, public charging and fleet electrification. In January 2020, the company rolled out a pilot home charging subscription service. The first 100 customers who signed up with one of our auto dealer partners received an advanced level 2 charger installed in their garages and have unlimited overnight charging in their homes for approximately $44 a month. “We are providing innovative solutions for our customers,” said Kevin Schwain, director of Xcel Energy’s EV program. “We want to make the experience of charging your car as easy and affordable as possible.”Several communities and businesses are partnering with Xcel Energy to evaluate the costs and benefits of converting at least part — if not all — of their fleets to electric vehicles.“Companies want to lower their fuel costs, but many are concerned about their carbon footprint and view converting their fleets to electric vehicles an important part of their sustainability program,” Schwain said. INNOVATION
AT THE HEART
OF ADVANCED
GRID INITIATIVE

SMART METERS WILL LEAPFROG EXISTING TECHNOLOGY,
HELP CUSTOMERS MANAGE ENERGY CONSUMPTION AND
SAVE MONEY ON THEIR MONTHLY ENERGY BILLS

ANNUAL REPORT 2019OF ALL THE TRANSFORMATIVE Xcel Energy projects under development, nothing dovetails with the theme of this report — The Future In Sight — better than our Advanced Grid Intelligence and Security initiative.Advanced Grid is an extensive, multi-year project to modernize the electric power grid with a series of new capabilities that will improve outage restoration, provide customers real-time data to better manage their energy use and give employees new tools to more effectively work with customers and efficiently manage and protect the grid.Some parts of the original electric grid — an interconnected series of substations, transmission lines and distribution wires that deliver electricity from power plants to customers — are more than 100 years old. Foundational work to modernize the grid is underway in Colorado and Minnesota. Early learnings from Colorado were used to develop a proposal that is currently under review by the Minnesota Public Utilities Commission.Colorado customers began to see benefits from Advanced Grid with the installation of the Advanced Distribution Management System in 2020. Additional benefits will begin in 2021 when the first “smart meters” are installed in a rollout that will wrap up in 2024. The new meters developed by our strategic partner Itron — an industry leader — will leapfrog existing technology and pave the way for customers to better understand and control their energy usage and save money.Itron meters, for example, may have the ability to show customers exactly how much money they can save by running their appliances at night after peak demand has declined instead of right after supper when electricity prices are higher. You may also be able to tell your teenagers exactly how much money they are wasting by leaving their electronics on.Our customers will also appreciate the ability for Xcel Energy to better isolate outages when storms disrupt the grid. Advanced Grid communications technology will greatly minimize the number of consumers affected by an outage by utilizing automatic restoration technology. The smaller number of customers who lose power should expect faster restoration times as the modern grid will better isolate the issue so our employees can start and complete repairs sooner.Employees will enjoy new tools to help them balance the system and more efficiently distribute power. One new technology, called Integrated Volt Var Optimization, will help reduce energy consumption from the first customer adjacent to a substation to the last customer at the end of the line, saving customers money.Private, two-way wireless communication is a key tenet of the modern grid and must be protected by a robust cybersecurity platform. The Advanced Grid system is designed to integrate several layers of cyber protection to ensure reliability and protect customer data.“The future is indeed within sight — as early as this year in Colorado, and we expect it will arrive in Minnesota next year,” said Brett Carter, EVP and Chief Customer and Innovation Officer. “Advanced Grid will be our largest customer experience transformation in the near term, but the customer benefits will last for decades.”A DECADE OF
PROGRESS

Carbon reduction

2009

10%

2019

44%

Wind ownership

124 MW

2,121 MW

Ongoing EPS per share

$1.50

$21.22

$2.64

$63.49

Stock price

Market cap

* Year-end numbers

$9.7 billion

$33.3 billion

THE FUTURE IN SIGHTNOT ONLY WAS 2019 an excellent year for Xcel Energy, it wrapped up an excellent decade — a decade of progress. By numerous measurements, Xcel Energy delivered outstanding results in the 2010s. Leading the clean energy transition delivered significant economic and environmental benefits. When the decade began, large-scale wind energy was still a nascent technology. At the end of 2009, wind accounted for less than 10% of our energy mix, and we only owned a tiny fraction — 124 megawatts. By the end of 2019, our wind ownership portfolio — an outcome of our Steel for Fuel growth strategy to deliver low-cost wind energy to our customers and provide investment opportunities for shareholders — had grown to approximately 2,100 megawatts, a 20-fold increase. Building large infrastructure projects, like wind farms and the transmission lines needed to bring wind energy to market, requires capital. Fortunately, thanks to our track record of strong financial performance, generating capital has not been a challenge for this organization. “The tripling of our stock price and corresponding 243% growth in market capitalization during the 2010s reinforce the fact that shareholders like our story of dependable earnings and dividend growth and support our strategy to make significant investments to lead the clean energy transition,” said Ben Fowke, Chairman and CEO.Our efforts to transition away from fossil fuels to renewable energy — primarily wind and solar — also delivered environmental benefits. By the end of 2019, we had reduced carbon emissions 44% from a 2005 baseline. At the start of the decade, that number was only 10%.And through all of our work to provide safe, reliable and affordable electricity every day, we made a sizeable economic impact in our communities. More than 60% of the $35 billion we spent in the last decade was with companies based in our service territory, and $3.6 billion was with diverse suppliers. Giving back to our communities that we are privileged to serve is just as important. In the last 10 years, our foundation granted more than $73 million to charitable organizations. And that number does not include the countless volunteer hours we gave to our communities.“It’s exciting to look back on our progress, but I’m even more optimistic about the future and progress we will make in the next decade,” Fowke said.PROTECTING
POLLINATORS

Schoolchildren from Kulm,
North Dakota help plant
pollinator-friendly milkweed
at the Foxtail Wind Farm in
Dickey County.

UNDER THE MASSIVE wind towers
on the North Dakota plains, you can find a smaller,
more subtle energy source that is also important
for the environment.

owned right-of-way acreage. The pollinator gardens
and native prairie habitats are located under
transmission lines, near substations and other
power-generating facilities or office buildings.

When Xcel Energy built the Foxtail Wind Farm in
2019, the company made sure that pollinators living
in the area have plenty of milkweed and pollinator-
friendly vegetation to help our crops thrive.
Children from the Kulm School District in Dickey
County helped Xcel Energy team members plant
the pollinator garden at the Foxtail Wind Farm.

Although Foxtail is the first example of planting
pollinator habitat at an Xcel Energy wind farm,
we’ve been helping pollinators for close to a
decade. We’ve created more than 2,100 acres of
pollinator habitat in Minnesota, North Dakota and
Wisconsin — with plans to keep planting. Our 45
pollinator sites range from as little as one acre
to 800 acres on Xcel Energy land and company-

According to the U.S. Fish and Wildlife Service,
more than 75% of our food crops rely on pollinators
to survive. Pollinators including bees, butterflies,
some birds and even bats are vital to flowering
plant reproduction for producing most fruits and
vegetables, and their population is shrinking.

“Our pollinator program is a partnership with state
and federal agencies, communities and non-
profit organizations,” said Pam Rasmussen, who
manages the program for Xcel Energy. “We see
opportunities for educating and engaging interested
customers and landowners who are also eager to
make a difference by creating pollinator habitat in
their own backyards.”

ANNUAL REPORT 2019UNITED 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

For the fiscal year ended December 31, 2019 or

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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)

Securities registered pursuant to Section 12(b) of the Act:

612 330-5500

(Registrant’s Telephone Number, Including Area Code)

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 is a shell company (as defined in Rule 12b-2 of the Act). ☐ Yes ☒ No

As of June 28, 2019, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $30,629,347,167 and there were
514,865,476 shares of common stock outstanding.

As of Feb. 13, 2020, there were 524,669,024 shares of common stock outstanding, $2.50 par value.

The Registrant’s definitive Proxy Statement for its 2020 Annual Meeting of Shareholders is 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
Forward-Looking Statements
Where to Find More Information
Company Overview
Electric Operations
Natural Gas Operations
General
Public Utility Regulation
Environmental
Capital Spending and Financing
Employees
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 —
Item 9 —
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
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 — Exhibits, Financial Statement Schedules
Item 16 — Form 10-K Summary

Signatures

1
1
2
2
3
7
10
11
11
11
12
12
12
13
18
18
19
19

19
20
20
38
38
75
75
75

75
75
75
75
75

76
82

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

OAG

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

Minnesota Office of the Attorney General

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
Electric, Purchased Gas and Resource Adjustment Clauses

CIP

DCRF
DCRF

DSM

DSMCA
DSMCA

ECA

EECRF
EECRF

FCA

FPPCAC
FPPCAC
GCA

GUIC
GUIC

Conservation improvement program

Distribution cost recovery factor
Distribution cost recovery factor

Demand side management

Demand side management cost adjustment
Demand side management cost adjustment

Retail electric commodity adjustment

Energy efficiency cost recovery factor
Energy efficiency cost recovery factor

Fuel clause adjustment

Fuel and purchased power cost adjustment clause
Fuel and purchased power cost adjustment clause
Gas cost adjustment

Gas utility infrastructure cost rider
Gas utility infrastructure cost rider

PCCA

PCRF
PCRF
PGA

PSIA
PSIA
RDF

RER
RER
RES

RESA
RESA
SCA

SEP
SEP
TCA
TCR
TCR
TCRF

Other

ADIT

AFUDC
ARO

ASC

ASU

BART

Boulder

C&I

CACJA

CAISO

CapX2020

CBA

CCR

CCR Rule

CDD

CEO

CFO

CEP

CIG

CPCN

CWA

CWIP

DECON

DRC

DRIP

EEI

ELG

Purchased capacity cost adjustment

Power cost recovery factor
Power cost recovery factor
Purchased gas adjustment

Pipeline system integrity adjustment
Pipeline system integrity adjustment
Renewable development fund

Renewable energy rider
Renewable energy rider
Renewable energy standard

Renewable energy standard adjustment
Renewable energy standard adjustment
Steam cost adjustment

State energy policy rider
State energy policy rider
Transmission cost adjustment
Transmission cost recovery adjustment
Transmission cost recovery adjustment
Transmission cost recovery factor

Accumulated deferred income taxes
Allowance for funds used during construction

Asset retirement obligation

FASB Accounting Standards Codification

FASB Accounting Standards Update

Best available retrofit technology

City of Boulder, CO

Commercial and Industrial

Clean Air Clean Jobs Act

California Independent System Operator

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

Collective-bargaining agreement

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 Energy Plan

Colorado Interstate Gas Company, LLC

Certificate of public convenience and necessity

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.

Development Recovery Company

Dividend Reinvestment Program

Edison Electric Institute

Effluent limitations guidelines

EMANI

European Mutual Association for Nuclear Insurance

Earnings per share

Extended power uprate

Effective tax rate

Financial Accounting Standards Board

Financial transmission right

Generally accepted accounting principles

General Electric

Greenhouse gas

EPS

EPU

ETR

FASB

FTR

GAAP

GHG

HDD

IPP

IRP

ITC
JOA

Heating degree-days

Integrated market

Independent power producing entity

Integrated Resource Plan
Investment Tax Credit
Joint operating agreement

LSP Transmission LSP Transmission Holdings, LLC

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

Net asset value

Nuclear Electric Insurance Ltd.

Notice of Inquiry

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 Ratings Services

Supplemental executive retirement plan

Southern Minnesota Municipal Power Agency

Sulfur dioxide

Southwest Power Pool, Inc.

Texas Competitive Energy Holdings

MDL

MEC

MGP

MISO

Moody’s

NAAQS

Native load

NAV

NEIL

NOI

NOL

O&M

OATT

Post-65

PPA

Pre-65

PTC

REC

ROE

ROFR

ROU

RPS

RTO

Standard &
Poor’s

SERP

SMMPA

SO2

SPP

TCEH

TCJA

THI

TOs

Temperature-humidity index

Transmission owners

TransCo

Transmission-only subsidiary

TSR

VaR

VIE

Total shareholder return

Value at Risk

Variable interest entity

WOTUS

Waters of the U.S.

Measurements

Bcf

KWh

MMBtu
MW

MWh

Billion cubic feet

Kilovolts

Kilowatt hours
Million British thermal units

Megawatts

Megawatt hours

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 2020 EPS guidance, long-term EPS and dividend growth rate,
as well as assumptions and other statements are intended to be identified in
this document by the words “anticipate,” “believe,” “could,” “estimate,”
“expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,”
“potential,” “should,” “will,” “would” and similar expressions. Actual results may
vary materially. Forward-looking statements speak only as of the date they
are made, and we expressly disclaim any obligation to update any forward-
looking information.

The following factors, in addition to those discussed elsewhere in this Annual
Report on Form 10-K for the fiscal year ended Dec. 31, 2019 (including the
items described under Factors Affecting Results of Operations; and the other
risk factors listed from time to time by Xcel Energy Inc. in reports filed with
the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form
10-K hereto), could cause actual results to differ materially from management
expectations as suggested by such forward-looking information: 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.

Xcel Energy’s website address is www.xcelenergy.com. Xcel Energy makes
available, free of charge through its website, its annual report on Form 10-K,
quarterly reports on Form 10-Q, current reports on Form 8-K and all
amendments to those reports filed or furnished pursuant to Section 13(a) or
15(d) of the Securities Exchange Act of 1934 as soon as reasonably
practicable after the reports are electronically filed with or furnished to the
SEC. The SEC maintains an internet site that contains reports, proxy and
information statements, and other information regarding issuers that file
electronically at http://www.sec.gov.

2017 federal tax reform enacted as Public Law No: 115-97, commonly
referred to as the Tax Cuts and Jobs Act

Where to Find More Information

Overview

Xcel Energy is a major U.S. regulated electric and natural gas delivery company headquartered in Minneapolis, Minnesota (incorporated in Minnesota in 1909).
The Company serves customers in eight 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. The Company’s significant nonregulated
subsidiaries are Eloigne, Capital Services and Nicollet Holdings.

Utility Subsidiaries’ Service Territory

Electric customers

Natural gas customers

Total assets

Electric generating capacity

3.7 million

2.1 million

$50.4 billion

18,730 MW

Electric transmission lines (conductor miles)

108,238 miles

Electric distribution lines (conductor miles)

207,524 miles

Natural gas transmission lines

Natural gas distribution lines

Natural gas storage capacity

2,177 miles

35,624 miles

53.4 Bcf

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

Strategic Priorities

Lead the Clean
Energy Transition

Enhance the
Customer
Experience

Keep Bills Low

Deliver a competitive total return proposition to shareholders

Lead the Clean Energy Transition

For more than a decade, Xcel Energy has proactively managed the risk of
climate change and increasing customer demand for renewable energy
through a clean energy strategy that consistently seeks to reduce carbon
emissions and aims to transition our operations for the future. We have
successfully reduced our carbon emissions from generation serving our
customers by nearly 44% from 2005 to 2019 and we are on track to reach
60% renewable generation by 2030. We expect to reduce our carbon footprint
by 80% by 2030 (over 2005 levels) and aspire to serve all customers with
100% carbon-free electricity by 2050.

We are also in the process of transforming our electric grid to accommodate
resources and
increased
corresponding data growth, while maintaining high levels of reliability and
security.

renewables, distributed energy

levels of

We have partnered with policymakers, state agencies and innovative
companies to develop nation-leading electric vehicle solutions for our
customers. We are preparing for a substantial amount of electric vehicles on
roads across our service territory by 2030 and are focused on providing helpful
information, making installations simple and keeping customer bills affordable
through new rates and programs. We anticipate offering innovative programs
for electric vehicle customers in Minnesota, Wisconsin, and Colorado this
year. We are filing comprehensive Transportation Electrification Plans in both
Colorado and New Mexico in the coming year.

We continue to develop and deliver new renewable energy solutions for our
residential and C&I customers who want more directly sourced energy.
Through programs such as Renewable*Connect® and Windsource®, we
match our customers’ needs without them needing to add expensive or on‑site
equipment.

Energy Mix – 80% Carbon Reduction by 2030

Keep Bills Low

60%

56%

■ Coal
■ Natural Gas
■ Nuclear
■ Renewables

23%

12%

46%

33%

26%

28%

13%

19% 21%

12%

15% 15%

10%

2005*

2019*

2027E*

2030E**

* Remaining includes hydro, biomass and other sources; future-year estimates dependent on various factors
** Potential scenarios that achieve carbon reduction goal

In addition to increasing our renewable generation, Xcel Energy is transitioning
how we produce, deliver and encourage the efficient use of energy by:

•
•
•

Offering energy efficiency programs;
Retiring coal units and modernizing generating plants; and
Advancing power grid capabilities.

We are working to add over 4,700 MW of wind energy to our system by 2021,
including 3,500 MW of owned wind and 1,200 MW of PPAs. Of the 3,500 MW
of owned wind, 1,300 MW are now in service and 2,200 MW are under
development or construction. This will bring our total wind capacity to over
11,000 MW by 2021.

Our long-term plan includes the addition of approximately 5,000 MW of solar
energy by the early 2030s, 275 MW of battery storage and a potential ten-
year extension of our Monticello nuclear plant. It also includes the retirement
of multiple coal units totaling approximately 2,000 MW. Xcel Energy plans to
continue to evaluate its coal fleet for other potential early retirements as part
of state resource plans or other regulatory proceedings.

Enhance the Customer Experience

Customers’ energy expectations continue to evolve and Xcel Energy is
committed to providing the options and solutions they want and value.

Xcel Energy continues to expand its renewable energy production and
offerings, and further develop and promote DSM and conservation programs.
Over the past decade, the Company has spent over $2.1 billion on these
programs.

Affordability is critical part of our customers’ experience. We are focused on
the impact our operations, regulation and legislation have on their bills. Our
objective is to keep bill increases at or below the rate of inflation.

Our utility service territories benefit from the geographic concentration of
favorable renewable resources. Strong wind and high solar generation
capacity factors lower the lifetime cost of these resources. This, coupled with
renewable tax credits and avoided fuel costs, enables us to invest in more
renewable generation, in which the capital costs are largely or completely
offset by fuel savings. We call this our “Steel for Fuel” strategy.

Steel for Fuel not only expands the Company’s renewable portfolio, but allows
delivery of carbon-free energy without raising customer bills through
replacement of fossil fuel generation or fuel-free wind and solar.

Changing Composition of Wind Capacity

Retired ~2,100 MW of Coal 2007-2019
~40% Wind Ownership by 2021

Steel for Fuel

11,100

10,300

6,600

6,700

8,000

7,300

5,700

4,900

5,100

2,900

3,200

2,700

4,100

3,400

■ PPA
■ Owned

1,100

1,300

2005

2007

2009

2011

2013

2015

2017

2019

2021E

Xcel Energy is working to keep long-term O&M expense relatively flat without
compromising reliability or safety. We intend to accomplish this objective by
continually
technology, proactively
managing risk and maintaining a workforce prepared to meet the needs of
our business today and tomorrow.

improving processes,

leveraging

O&M declined 0.6% in 2019 even as we took the opportunity to invest more
in key strategic and operational areas, including reducing operational risks
and enhancing our customers’ experience. While Xcel Energy continues to
invest prudently in appropriate areas, we remain committed to our long-term
objective of improving operating efficiencies and taking costs out of the
business.

Deliver a Competitive Total Return to Investors and Maintain Strong
Investment Grade Credit Rating

Successful execution of our strategic objectives should allow Xcel Energy to
continue to deliver a competitive total return for our shareholders.

Through our disciplined approach to business growth, financial investment,
operations and safety, we are well positioned to continue delivering on our
value proposition.

5-7%
EPS Growth

~2.5%
Dividend Yield
5-7%
CAGR

8-10%
Total Shareholder Return

60-70%
Payout Ratio

We have consistently achieved our financial objectives, meeting or exceeding
our initial earnings guidance range for fifteen consecutive years and delivering
dividend growth for sixteen consecutive years.

Our ongoing earnings have grown 6.1% annually since 2005 and our dividend
has grown 6.3% annually from 2013-2019. We work 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.

• We retained Evraz Steel in Colorado, a major Pueblo employer, by
partnering with the company and community to create an affordable solar
solution to meet their needs.

Xcel Energy is an active community member. We recognize and carefully
evaluate the broader potential economic impacts of our decisions and work
to proactively support the people and economic health of our communities.
In 2019, we spent $3.1 billion locally, donated nearly $11 million to local
charities, continued to offer employees 40 hours of volunteer paid time off
annually and our employees served on over 500 non-profit boards. Donations
include Xcel Energy employee and Xcel Energy Foundation gifts.

As a member of diverse communities, we value and celebrate diversity and
inclusion. For example:

•

Xcel Energy has offered domestic partner benefits since 1995;

The Company’s CEO has signed the Action for Diversity & Inclusion
Pledge, for the advancement of diversity and inclusion within the
workplace, and Xcel Energy has an employee-led Diversity & Inclusion
Council;

• We have been selected among the nation’s top corporations for lesbian,
gay, bisexual, transgender, and queer equality by earning a perfect score
on the Human Rights Campaign’s 2019 Corporate Equality Index for the
past 4 years; and

•

Xcel Energy was named to the 2019 Military Times Best for Vets
Employers rankings for the sixth straight year and currently employs
more than 1,000 veterans, nearly 10% of our workforce.

Environmental, Social and Governance Leadership

Governance

Xcel Energy has a diverse and qualified Board of Directors committed to
effective governance.

Xcel Energy has consistently demonstrated industry leadership in mitigating
climate, operational and financial risks, while remaining committed to our
customers, communities, employees and investors. We have delivered
tangible environmental, social and governance results in alignment with our
four corporate values - committed, connected, safe and trustworthy.

Environmental

Xcel Energy has been the number one U.S. wind provider for 12 of the past
14 years.

We continue to lead the industry with one of the most aggressive carbon
reduction goals among our peers. Our plans to achieve 80% reduction by
2030 are aligned with Paris Accord goals and have been independently
validated by an Intergovernmental Panel on Climate Change expert.

■ Male
■ Female
■ Minority
■ Female/Minority

1 Executive
12 Independent
38% Female/Minority
9 Years Avg. Tenure

• Retirement age and tenure limit
• Lead independent director elected annually
• Independent committee chairs
• Board and committee performance evaluations
• No supermajority approval provisions
• Proxy access adopted
• Annual advisory vote on compensation
• Tenure and overboarding policies

In December 2018, Xcel Energy became the first major electric utility in the
country to announce an aspiration to produce 100% carbon-free electricity for
customers by 2050.

The Company first adopted an environmental policy and instituted Board of
Directors’ oversight of environmental performance in 2000, followed by
publication of our corporate responsibility report in 2005.

Social

Xcel Energy works to mitigate the employee and community impacts of early
plant retirements. We provide affected employees with advanced notice and
offer retraining and relocation opportunities. Through these efforts and natural
attrition, Xcel Energy has had no layoffs as a result of plant retirements.

We have also worked to foster economic sustainability and continued
affordability
through partnering with communities, policymakers and
customers impacted by coal plant retirements, to build facilities and attract
new businesses. Examples include:

•

Near our Sherco plant, scheduled to close by 2030, we are partnering
with local leadership and a major data center to locate a $600 million
data center. Additionally, Xcel Energy actively worked to relocate a metal
recycling plant near our plant; and

We consistently set aggressive goals and hold ourselves accountable, to our
customers, our communities and our investors. Additionally, Xcel Energy was
among the first U.S. utilities to tie carbon reduction directly to executive
compensation over fifteen years ago and is one of three peer utilities who do
so today.

We are also focused on safety for our employees and our communities. In
2019, 60% of annual incentive pay was tied to safety and system reliability.
Employees at every level have “stop work authority” and are instrumental in
keeping each other and our surrounding communities safe.

Utility Subsidiaries

NSP-Minnesota

Electric customers
Natural gas customers

Consolidated earnings contribution

Total assets

Rate Base

ROE

Electric generating capacity

Gas storage capacity

1.5 million
0.6 million

35% to 45%

$19.9 billion

$11.2 billion

9.31%

7,712 MW

17.1 Bcf

Electric transmission lines (conductor miles)

33,528 miles

PIERRE

Electric distribution lines (conductor miles)

80,186 miles

Natural gas transmission lines

Natural gas distribution lines

86 miles

10,518 miles

MINOT

GRAND FORKS

DICKINSON

BISMARCK

FARGO

DULUTH

BRAINERD

ST. CLOUD

DELANO

MINNEAPOLIS & ST. PAUL

RED WING

FARIBAULT

MANKATO

WINONA

SIOUX FALLS

the

generation,

NSP-Minnesota conducts business
in
Minnesota, North Dakota and South Dakota
and has electric operations in all three states
including
purchase,
transmission, distribution and sale of
electricity. NSP-Minnesota and NSP-
Wisconsin electric operations are managed
on the NSP System. NSP-Minnesota also
purchases, transports, distributes and sells
natural gas to retail customers and transports
customer-owned natural gas in Minnesota
and North Dakota.

NSP-Wisconsin

Electric customers

Natural gas customers

Consolidated earnings contribution

Total assets

Rate Base

ROE

Electric generating capacity

Gas storage capacity

0.3 million

0.1 million

5% to 10%

$2.8 billion

$1.7 billion

8.27%

548 MW

3.8 Bcf

Electric transmission lines (conductor miles)

12,285 miles

Electric distribution lines (conductor miles)

27,504 miles

Natural gas transmission lines

Natural gas distribution lines

3 miles

2,473 miles

PSCo

Electric customers
Natural gas customers

Consolidated earnings contribution

Total assets

Rate Base

ROE

Electric generating capacity

1.5 million
1.4 million

35% to 45%

$19.0 billion

$12.4 billion

8.69%

5,666 MW

Gas storage capacity
Electric transmission lines (conductor miles)

32.5 Bcf
24,008 miles

Electric distribution lines (conductor miles)

78,023 miles

Natural gas transmission lines

Natural gas distribution lines

2,057miles

22,633 miles

SPS

Electric customers
Consolidated earnings contribution

Total assets

Rate base

ROE

Electric generating capacity

Electric transmission lines

Electric distribution lines

0.4 million
15% to 20%

$7.9 billion

$4.9 billion

9.71%

4,804 MW

38,418 miles

21,810 miles

ASHLAND

HUDSON

EAU CLAIRE

LA CROSSE

MADISON

NSP-Wisconsin conducts business
in
Wisconsin and Michigan and generates,
transmits, distributes and sells electricity.
NSP-Minnesota and NSP-Wisconsin electric
the NSP
operations are managed on
System. NSP-Wisconsin also purchases,
transports, distributes and sells natural gas
to retail customers and transports customer-
owned natural gas.

RIFLE

VAIL

CARBONDALE

LEADVILLE

GRAND
JUNCTION

GREELEY

FT. COLLINS

ESTES
PARK

BOULDER

STERLING

BRUSH

DENVER

PUEBLO

ALAMOSA

PSCo conducts business in Colorado and
generates, purchases, transmits, distributes
and sells electricity. PSCo also purchases,
transports, distributes and sells natural gas
to retail customers and transports customer-
owned natural gas.

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

generates,

and

SANTA FE

DALHART

ALBUQUERQUE TUCUMCARI
40

BORGER
40
AMARILLO

HEREFORD

CLOVIS

PLAINVIEW

ROSWELL

LUBBOCK

CARLSBAD

LEVELLAND

HOBBS

DALLAS

AUSTIN

SAN ANTONIO

Operations Overview

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

Electric Operations

Electric operations consist of energy supply, generation, transmission and distribution activities across all four operating companies. Xcel Energy had
electric sales volume of 116,317 (millions of KWh), 3,662,701 customers and electric revenues of $9,575 (millions of dollars) for 2019.

Sales Volume

Number of Customers

Revenues

Other: 1%

Sales for
Resale: 22%

Residential:
22%

C&I: 55%

Residential:
3,150,748

C&I: 441,680

Other: 70,273

C&I: 53%

Other:
16%

Residential:
31%

Sales/Revenue Statistics

Owned and Purchased Energy Generation — 2019

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

2019

2018

24,712

25,263

$2,244

$ 2,257

11.97¢

11.78¢

5.96¢

9.43¢

9.08¢

5.91¢

9.21¢

8.93¢

100%

32%

100%

25%

100%

30%

100%

49%

68%

75%

70%

51%

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, 2019:

Xcel Energy

NSP System

PSCo

SPS

Renewable:
28%

Coal: 26%

Nuclear:
13%

Natural Gas: 33%

Re
Renewable:
26%

Coal: 23%

Nuclear: 28%
N

Natural Gas:
23%

Renewable:
30%

Coal: 33%

Renewable:
28%

Coal: 25%

Natural Gas: 37%

Natural Gas: 47%

*Distributed generation from the Solar*Rewards® program is not included (approximately 538 million KWh for 2019)

Renewable Energy Sources

Xcel Energy’s renewable energy portfolio includes wind, hydroelectric,
biomass and solar power from both owned generating facilities and PPAs.
Renewable percentages will vary year over year based on system additions,
weather, system demand and transmission constraints.

See Item 2 — Properties for further information.

Renewable energy as a percentage of total energy for 2019:

30%
2%

28%
2%

28%

26%

21%

15%

25%

26%

Xcel Energy Inc.

NSP System

PSCo

SPS

■ Wind ■ Solar ■ Other (a)

(a)

Includes biomass and hydroelectric

Wind Energy Sources

Owned — Owned and operated wind farms with corresponding capacity:

2019

2018

Utility Subsidiary

Wind Farms

Capacity

Wind Farms

Capacity

NSP System

PSCo

SPS

1,090 MW

600 MW

478 MW

—

840 MW

600 MW

—

PPAs — Number of PPAs with range:

Utility
Subsidiary

NSP System

PSCo

SPS

PPAs

131

2019

Range

0.7 MW — 205.5 MW

2.0 MW — 300.5 MW

0.7 MW — 250.0 MW

PPAs

132

2018

Range

0.7 MW - 205.5 MW

2.0 MW - 300.5 MW

0.7 MW - 250.0 MW

Capacity — Wind capacity:

Utility Subsidiary

NSP System

PSCo

SPS

2019

2,780 MW

3,165 MW

2,045 MW

2018

2,550 MW

3,160 MW

1,565 MW

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

Utility Subsidiary (a)

NSP System

PSCo

2019

2018

—

(a)

The table reflects owned wind sites that were in commercial operation for the full calendar
year. The Hale wind farm for SPS was put into service in June 2019 and the Rush Creek
wind farm was put into service in December 2018.

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

Utility Subsidiary

NSP System

PSCo

SPS

2019

2018

Wind Energy Development

Xcel Energy is executing the largest multi-state wind investment in the nation
and placed approximately 1,300 MW of owned wind and approximately 300
MW of PPAs into service during 2018-2019:

Project

Utility Subsidiary

Rush Creek

Hale

Foxtail

Lake Benton
Various PPAs

PSCo

SPS

NSP-Minnesota

NSP-Minnesota
Various

Capacity

582 MW

460 MW

150 MW

99 MW
~300 MW

As part of the multi-state wind investment, Xcel Energy currently has
approximately 2,200 MW of owned wind under development or construction
and approximately 900 MW of planned PPAs with an estimated completion
date of 2021 or earlier:

Utility Subsidiary

Capacity

Estimated
Completion

Project

Freeborn

Blazing Star 1

Blazing Star 2

Crowned Ridge (a)

Jeffers (b)

NSP-Minnesota

Community Wind North(b)

NSP-Minnesota

Dakota Range

Cheyenne Ridge

Sagamore

Various PPAs

NSP-Minnesota

PSCo

SPS

Various

(a)

(b)

Build-own-transfer project.

Repowering project.

Solar Energy Sources

Solar energy PPA(s):

200 MW

44 MW

26 MW

300 MW

500 MW

522 MW

2020

2021

2020

~900 MW

2020 - 2021

Type

Distributed Generation

Utility-Scale

Distributed Generation

Utility-Scale

Distributed Generation

Utility-Scale

Utility Subsidiary

Capacity

NSP System

PSCo

SPS

736 MW

266 MW

557 MW

305 MW

10 MW

191 MW

Other Carbon-Free Energy Sources

Coal Fuel Cost

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

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

See Item 2 — Properties for further information.

Nuclear Energy Sources

Xcel Energy has two nuclear plants with approximately 1,700 MW of total
2019 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.

The Company secures contracts for uranium concentrates, uranium
conversion, uranium enrichment and fuel fabrication to operate its nuclear
plants. The contract strategy involves a portfolio of spot purchases and
medium and long-term contracts for uranium concentrates, conversion
services and enrichment services with multiple producers and with a focus on
diversification and alternate sources 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

2019

2018

Nuclear

Cost

Percent

0.81

0.80

45%

Utility Subsidiary
NSP System

2019

2018

PSCo

2019

2018

SPS

2019

2018

Coal (a)

Cost

Percent

2.02

2.13

1.45

2.19

2.04

36%

(a)

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

Natural Gas Energy Sources

Xcel Energy has 22 natural gas plants with approximately 7,900 MW of total
2019 net summer dependable capacity.

Natural gas supplies, transportation and storage services for power plants are
procured to provide an adequate supply of fuel. Remaining requirements are
procured through a liquid spot market. Generally, natural gas supply contracts
have variable pricing that is tied to natural gas indices. Natural gas supply
and transportation agreements include obligations for the purchase and/or
delivery of specified volumes or payments in lieu of delivery.

Fossil Fuel Energy Sources

Natural Gas Cost

Xcel Energy’s fossil fuel energy portfolio includes coal and natural gas power
from both owned generating facilities and PPAs.

Delivered cost per MMBtu of natural gas consumed for owned electric
generation and percentage of total fuel requirements:

See Item 2 — Properties for further information.

Coal Energy Sources

Xcel Energy owns and operates nine coal plants with approximately 6,500
MW of total 2019 net summer dependable capacity.

Our operating companies have embarked on an industry-leading coal
retirement program with permission from its key regulatory bodies.

Approved and proposed coal plant retirements:

Approved (2019 to 2027)

Year

Utility Subsidiary

Plant

PSCo

Comanche 1

NSP-Minnesota

Sherco 2

PSCo

NSP-Minnesota

Comanche 2

Craig 1

Sherco 1

Proposed (2028 to 2030)

Year

Utility Subsidiary

Plant

NSP-Minnesota

A.S King

Sherco 3

2022

2023

2025

2026

2028

2030

Capacity

325 MW

682 MW

335 MW

42 MW

680 MW

Capacity

511 MW

517 MW

Utility Subsidiary
NSP System

2019

2018

PSCo

2019

2018

SPS

2019

2018

Natural Gas

Cost

Percent

3.09

3.87

3.27

3.74

1.14

2.24

19%

Capacity and Demand

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

Utility Subsidiary
NSP System
PSCo

SPS

Transmission

System Peak Demand (in MW)

2019

8,774

7,111

4,261

July 19

Aug. 5

2018

8,927

6,718

4,648

June 29

July 10

July 19

Transmission lines deliver electricity over long 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 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 2019 include:

Distribution

Project

Maple River-Red River

Nelson-Wabasha

Pawnee-Daniels Park

Thornton Substation

TUCO-Yoakum-Hobbs

NEF-Cardinal

Potash Junction-Livingston Ridge

Mustang-Shell

North Loving-South Loving

Cunningham-Monument Tap

Notable upcoming projects:

Utility Subsidiary

Miles

Size

NSP-Minnesota

NSP-Wisconsin

PSCo

SPS

125

115 KV

69 KV

345 KV

115 KV

345 KV

115 KV

Project

Utility Subsidiary Miles

Size

Completion Date

Huntley-Wilmarth

NSP-Minnesota

Bayfield Second Circuit

NSP-Wisconsin

Cheyenne Ridge

TUCO-Yoakum-Hobbs

Eddy-Kiowa

PSCo

SPS

106

345 KV

35 KV

345 KV

See Item 2 - Properties for further information.

2021

2022

2020

Natural Gas Operations

Distribution lines allow electricity to travel from substations directly to homes
and businesses in neighborhoods and cities around the country. Xcel Energy
has a vast distribution network, owning and operating thousands of miles of
distribution lines across our eight-state service territory, both above ground
and underground.

To continue providing reliable, affordable electric service and enable more
flexibility for customers, we are working to digitize the distribution grid, while
at the same time keeping it secure. Over the next five years, the Company
will invest $1.4 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.

In 2019, Xcel Energy implemented foundational software and completed our
initial smart meter deployment in Colorado as planned, with full-scale
implementation to follow. We also requested approval to expand our advanced
grid program to benefit our Minnesota customers and expect a Commission
decision in late 2020. We plan to have smart meters implemented across our
Colorado and Minnesota service territories by the end of 2024.

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 463,185 (thousands of MMBtu), 2,068,129 customers and natural gas revenues of $1,868
(millions of dollars) for 2019.

Deliveries

Number of Customers

Revenues

Transportation and
Other: 42%

C&I: 22%

Residential: 35%

C&I: 159,223

Transportation and
Other: 8,383

Residential: 1,900,523

Residential:
62%

C&I: 32%

Transportation and
Other: 6%

Sales/Revenue Statistics

Capability and Demand

MMBtu sales per retail customer

Revenue per retail customer

Residential revenue per MMBtu

C&I revenue per MMBtu

Transportation and other revenue per MMBtu

2019

2018

129.31

120.51

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

851.94

785.86

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

7.14

5.73

0.57

7.01

5.76

0.80

2019

2018

Utility Subsidiary

MMBtu

Date

MMBtu

Date

NSP-Minnesota

NSP-Wisconsin

PSCo

897,615 (a)

166,009 (a)

2,139,420 (a)

Feb. 25

Jan. 30

March 3

786,751

159,700

1,903,878

Jan. 12

Jan. 5

Feb. 20

(a)

Increase in maximum MMBtu output due to colder winter temperatures in 2019.

Natural Gas Supply and Cost

Xcel Energy actively seeks natural gas supply, transportation and storage
alternatives to yield a diversified portfolio, which provides increased flexibility,
decreased interruption and financial risk, and economic customer rates. In
addition, the utility subsidiaries conduct natural gas price hedging activities
approved by their state commissions.

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

Utility Subsidiary

NSP-Minnesota

NSP-Wisconsin

PSCo

2019

2018

3.71

3.49

2.95

4.03

3.84

3.20

FERC Order No. 1000 established competition for construction and operation
of certain new electric transmission facilities. State utilities commissions have
also created resource planning programs that promote competition for
electricity 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.

NSP-Minnesota, NSP-Wisconsin and PSCo have natural gas supply
transportation and storage agreements that include obligations for purchase
and/or delivery of specified volumes or to make payments in lieu of delivery.

Environmental

Environmental Regulation

See Item 2 - Properties for further information.

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 its results of
operations, future growth or ability to raise capital resulting from a sustained
general slowdown in economic growth or a significant increase in interest
rates.

Seasonality

Demand for electric power and natural gas is affected by seasonal differences
in the weather. In general, peak sales of electricity occur in the summer months
and peak sales of natural gas occur in the winter months. As a result, the
overall operating results may fluctuate substantially on a seasonal basis.
Additionally, Xcel Energy’s operations have historically generated less
revenues and income when weather conditions are milder in the winter and
cooler in the summer.

Competition

The Company 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.

Our facilities are regulated by federal and state agencies that have jurisdiction
over air emissions, water quality, wastewater discharges, solid wastes and
hazardous substances. Various company 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 have been designed and constructed to operate in compliance
with applicable environmental standards and related monitoring and reporting
requirements. However, it is not possible to determine when or to what extent
additional facilities or modifications of existing or planned facilities will be
required as a result of changes to regulations, interpretations or enforcement
policies or what effect future laws or regulations may have. We may be required
to incur expenditures in the future for remediation of MGP and other sites if it
is determined that prior compliance efforts are not sufficient.

In Minnesota, Texas and Wisconsin, Xcel Energy must comply with emission
budgets that require the purchase of emission allowances from other utilities.
The Denver North Front Range Nonattainment 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 present/future 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. If future environmental regulations do
not take into consideration investments already made or if additional initiatives
or emission reductions are required, substantial costs may be incurred.

In July 2019, the EPA adopted the Affordable Clean Energy rule, which
requires states to develop plans for GHG reductions from coal-fired power
plants. The state plans, due to the EPA in July 2022, will evaluate and
potentially require heat rate improvements at existing coal-fired plants. It is
not yet known how these state plans will affect our existing coal plants, but
they could require substantial additional investment, even in plants slated for
retirement. Xcel Energy believes, based on prior state commission practice,
the cost of these initiatives or replacement generation would be recoverable
through rates.

In 2019, Xcel Energy estimates that it reduced the carbon emissions
associated with the electric generating resources, both owned and under
PPAs, used to serve its customers by approximately 44% from 2005 levels.

Environmental Costs

Environmental costs include accruals 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:

•
•
•

$345 million in 2019;
$335 million in 2018; and
$315 million in 2017.

Capital expenditures for environmental improvements were approximately:

•
•
•

$30 million in 2019;
$50 million in 2018; and
$60 million in 2017.

See Item 7 — Capital Requirements for further discussion.

Capital Spending and Financing

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

Employees

As of Dec. 31, 2019, Xcel Energy had 11,273 full-time employees and 44
part-time employees, of which 5,091 were covered under CBAs.

Average annual expense of approximately $400 million from 2020 – 2024 is
estimated for similar costs. The precise timing and amount of environmental
costs, including those for site remediation and disposal of hazardous
materials, are unknown. Additionally, the extent to which environmental costs
will be included in and recovered through rates may fluctuate.

NSP-Minnesota

NSP-Wisconsin

PSCo

SPS

XES

Total

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

Name
Ben Fowke (c)

Current and Recent Positions

Chairman of the Board, President and Chief Executive Officer and Director, Xcel Energy Inc.

Chief Executive Officer, NSP-Minnesota, NSP-Wisconsin, PSCo, and SPS

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

Senior Vice President and Chief Operating Officer, Bank of America

Senior Vice President and Chief Distribution Officer, Duke Energy Co., an electric power company

President and Director, NSP-Minnesota

Executive Vice President and Group President, Utilities, Xcel Energy Inc.

President and Director, PSCo

Employees
Covered by CBAs

Total Employees

2,036

392

1,884

779

—

5,091

3,203

538

2,369

1,158

4,005

11,273

Time in Position

August 2011 — Present

January 2015 — Present

May 2018 — Present

October 2015 — May 2018

March 2015 — October 2015

February 2013 — March 2015

January 2015 — Present

March 2018 — Present

January 2015 — February 2018

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

May 2018 — Present

Senior Vice President, Human Resources and Employee Services, Xcel Energy Inc.

Vice President, Human Resources, Xcel Energy Inc.

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

May 2015 — May 2018

February 2010 — May 2015

May 2016 — Present

Senior Vice President and Chief Financial Officer, Luminant, a subsidiary of Energy Future Holdings Corp. (e)

February 2012 — April 2016

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 and Group President Operations, Xcel Energy Inc.

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

Senior Vice President, Corporate Secretary and Executive Services, Xcel Energy Inc.

Senior Vice President, Controller, Xcel Energy Inc.

President and Director, NSP-Wisconsin

Executive Vice President, General Counsel, Xcel Energy Inc.

January 2015 — Present

May 2018 — Present

November 2016 — May 2018

November 2013 — November 2016

January 2015 — Present

February 2013 — Present

January 2015 — Present

Brett C. Carter

Christopher B. Clark

David L. Eves (d)

Darla Figoli

Robert C. Frenzel (c)

David T. Hudson

Alice Jackson

Kent T. Larson (f)

Timothy O’Connor (g)

Judy M. Poferl (h)

Jeffrey S. Savage

Mark E. Stoering

Scott M. Wilensky

(a)

(b)

(c)

(d)

No family relationships exist between any of the executive officers or directors.
Ages as of Dec. 31, 2019.

Effective March 31, 2020, Mr. Fowke will cease to serve as President and Mr. Frenzel will
become President and Chief Operating Officer of Xcel Energy Inc. At the same time, Brian
J. Van Abel will become Executive Vice President, Chief Financial Officer of Xcel Energy
Inc.

Effective May 1, 2020, Mr. Eves will be retiring from the Company after retiring from his
executive officer positions effective March 30, 2020.

(e)

(f)

(g)

(h)

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.

Effective May 31, 2020, Mr. Larson will be leaving the Company after ceasing to serve in
his executive officer positions effective March 30, 2020.

Effective March 31, 2020, Mr. O’Connor will become Executive Vice President, Chief
Generation Officer.

Effective March 31, 2020, Ms. Poferl will be retiring from the Company. Frank Prager has
been elected to serve with the title of Senior Vice President, Strategy and Planning and
External Affairs effective March 1, 2020.

ITEM 1A — RISK FACTORS

Xcel Energy is subject to a variety of risks, many of which are beyond our
control. Risks that may adversely affect the business, financial condition,
results of operations or cash flows are described below. These risks should
be carefully considered together with the other information set forth in this
report and future reports that we file with the SEC.

Oversight of Risk and Related Processes

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

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

Management identifies and analyzes risks to determine materiality and other
attributes such as timing, probability and controllability. Identification and risk
analysis occurs formally through risk assessment conducted by senior
management, the financial disclosure process, hazard risk procedures,
internal audit and compliance with financial and operational controls.

Management also identifies and analyzes risk through the business planning
process, development of goals and establishment of key performance
indicators, including identification of barriers to implementing the Company’s
strategy. The business planning process also identifies likelihood and
mitigating factors to prevent the assumption of inappropriate risk to meet goals.

Management communicates regularly with the Board of Directors and key
stakeholders regarding risk. Senior management presents and communicates
a periodic risk assessment to the Board of Directors, providing information on
the risks that management believes are material, including financial impact,
timing, likelihood and mitigating factors. The Board of Directors regularly
reviews management’s key risk assessments, which includes areas of existing
and future macroeconomic, financial, operational, policy, environmental and
security risks.

The oversight, management and mitigation of risk is an integral and continuous
part of the Board of Directors’ governance of Xcel Energy. The Board of
Directors assigns oversight of critical risks to each of its four committees to
ensure these risks are well understood and given appropriate focus.

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

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

Risks Associated with Our Business

Operational Risks

Our natural gas and electric transmission and distribution operations
involve numerous risks that may result in accidents and other operating
risks and costs.

Our natural gas transmission and distribution activities include inherent
hazards and operating risks, such as leaks, explosions, outages and
mechanical problems. Our electric generation, transmission and distribution
activities include inherent hazards and operating risks such as contact, fire
and outages. These risks could result in loss of life, significant property
damage, environmental pollution, impairment of our operations and
substantial financial losses. We maintain insurance against most, but not all,
of these risks and losses. The occurrence of these events, if not fully covered
by insurance, could have a material effect on our financial condition, results
of operations and cash flows.

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

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

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

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

In addition, the long-term nature of both our planning and our asset lives are
subject to risk. The electric utility sector is undergoing a period of significant
change. For example, increases in energy efficiency, wider adoption of lower
cost renewable generation, distributed generation and shifts away from coal
generation to decrease carbon emissions and increasing use of natural gas
in electric generation driven by lower natural gas prices. Customer adoption
of these technologies and increased energy efficiency could result in excess
transmission and generation resources, downward pressure on sales growth,
as well as 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. Evolving stakeholder preference for lower emission
generation sources may pressure our investments in natural gas generation
and delivery.

The magnitude and timing of resource additions and changes in customer
demand may not coincide while customer preference for resource generation
may change, which introduces further uncertainty into long-term planning.
Additionally, multiple states may not agree as to the appropriate resource mix,
which may lead to costs to comply with one jurisdiction that are not recoverable
across all jurisdictions served by the same assets.

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

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

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

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.

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

Certain specialized knowledge is required of our technical employees for
construction and operation of transmission, generation and distribution assets.
The Company’s business strategy is dependent on our ability to recruit, retain
and motivate employees. Competition for skilled employees is high in the
areas of business operations. 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. We have
seen a tightening of supply for engineers and skilled laborers in certain markets
and are implementing plans to retain these employees. Inability to attract and
retain these employees could adversely impact our results of operations,
financial condition or cash flows.

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

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

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

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

•

Hazards associated with the use of radioactive material in energy
production, including management, handling, storage and disposal;
Limitations on insurance available to cover losses that may arise in
connection with nuclear operations, as well as obligations to contribute
to an insurance pool in the event of damages at a covered U.S. reactor;
and
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. Revised NRC
safety requirements could necessitate substantial capital expenditures or an
increase in operating expenses. In addition, the Institute for Nuclear Power
Operations reviews NSP-Minnesota’s nuclear operations and nuclear
generation facilities. Compliance with the Institute for Nuclear Power
Operations’ recommendations could result in substantial capital expenditures
or a substantial increase in operating expenses.

If an incident did occur, it could have a material impact on our results of
operations, financial condition or cash flows. Furthermore, non-compliance
or the occurrence of a serious incident at other nuclear facilities could result
in increased industry regulation, which may increase NSP-Minnesota’s
compliance costs.

NSP-Wisconsin’s production and transmission system is operated on an
integrated basis with NSP-Minnesota and may be subject to risks associated
with NSP-Minnesota’s nuclear generation.

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 (e.g., wind projects) 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 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 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, significantly 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 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 of applicable contracts
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. Capital markets are global and
impacted by issues and events throughout the world. 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 overall economy and local economies in the geographic
areas we serve, including local unemployment rates. Credit risk also includes
the risk that various counterparties that owe us money or product will become
insolvent and may breach their obligations. Should the counterparties fail to
perform, we may be forced to enter into alternative arrangements. In that
event, our financial results could be adversely affected and incur losses.

The Company may at times 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, such as CAISO, 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 in the form of letters of credit
provided as security by power suppliers under various purchased power
contracts. If any of the credit ratings of the letter of credit issuers were to drop
below investment grade, the supplier would need to replace that security with
an acceptable substitute. If the security were not replaced, the party could be
in default under the contract.

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

We have defined benefit pension and postretirement plans that cover most
of our employees. Assumptions related to future costs, return on investments,
interest rates and other actuarial assumptions have a significant impact on
our funding requirements related to these plans. Estimates and assumptions
may change. In addition, the Pension Protection Act changed the minimum
funding requirements for defined benefit pension plans. Therefore, our funding
requirements and related 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
subsidiaries.

Federal tax law may significantly impact our business.

Our utility subsidiaries collect through regulated rates estimated federal, state
and local tax payments. 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. There could be timing delays before
regulated rates provide for realization of tax changes 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.

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 storm, 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 disruption of work force within
our operating systems (or on a neighboring system).

The recent coronavirus outbreak in China is an example of how major
catastrophic events throughout the world may disrupt our business. While we
are a domestic company, the Company participates in a global supply chain,
which includes materials and components that are sourced from China. A
prolonged disruption could result in the delay of equipment and materials that
may impact our ability to reliably serve our customers.

Disruption due to events such as those noted above 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 biennial 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
sophisticated
technology, control systems and network
infrastructure. In addition, we use our systems and infrastructure to create,
collect, use, disclose, store, dispose of and otherwise process sensitive
information, including company data, customer energy usage data, and
personal information regarding customers, employees and their dependents,
contractors, shareholders and other individuals.

The Company’s generation, transmission, distribution and fuel storage
facilities, information technology systems and other infrastructure or physical
assets, as well as information processed in our systems (e.g., information
regarding our customers, employees, operations, infrastructure and assets)
could be affected by cyber security incidents, including those caused by
human error. The utility industry has been the target of several attacks on
operational systems and has seen an increased volume and sophistication
of cyber security incidents from international activist organizations, Nation
States and individuals. Cyber security incidents could harm our businesses
by limiting our generating, transmitting and distributing capabilities, delaying
our development and construction of new facilities or capital improvement
projects to existing facilities, disrupting our customer operations or causing
the release of customer information, all of which would likely receive state and
federal regulatory scrutiny and could expose us to liability.

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

Our supply chain for procurement of digital equipment 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 and new
interpretations of existing laws create financial risk as our facilities may be
subject to additional regulation at either the state or federal level in the future.
Such regulations could impose substantial costs.

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.

Although the United States has not adopted any international or federal GHG
emission reduction targets, many states and localities may continue to pursue
climate policies in the absence of federal mandates. 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. While those actions likely would
have put Xcel Energy in a good position to meet federal or international
standards being discussed, the lack of federal action does not adversely
impact these state-endorsed actions and plans.

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 have become more active
in pursuing penalties. Certain states additionally 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. Environmental regulations
may also lead to shutdown of existing facilities. 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 (i.e., clean-up) sites
where our past activities, or the activities of other parties, caused
environmental contamination.

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 the 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 a region’s economy, which could impact our sales
and revenues. The price of energy has an impact on the economic health of
our communities. The cost of additional regulatory requirements, such as
regulation of GHG, could impact the availability of goods and prices charged
by our suppliers which would normally be borne by consumers through higher
prices for energy and purchased goods. To the extent financial markets view
climate change and emissions of GHGs as a financial risk, this could negatively
affect our ability to access capital markets or cause us to receive less than
ideal terms and conditions.

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

Fuel

Installed

MW (a)

NSP-Wisconsin
Station, Location and Unit

Steam:
Bay Front-Ashland, WI, 2 Units

Coal/Wood/Natural Gas

1948 - 1956

French Island-La Crosse, WI, 2 Units

Wood/Refuse

1940 - 1948

Combustion Turbine:
French Island-La Crosse, WI, 2 Units

Oil

Wheaton-Eau Claire, WI, 5 Units

Natural Gas/Oil

Hydro:

Various locations, 63 Units

Hydro

(a)

(b)

Summer 2019 net dependable capacity.
Refuse-derived fuel is made from municipal solid waste.

1974

1973

Various

Total

16 (b)

122

234

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

Pawnee-Brush, CO, 1 Unit

Fuel

Installed

MW (a)

1973

1975

2010

1979 - 1980

1965 - 1976

325

335

500 (c)

82 (e)

233 (f)

Coal

Cherokee-Denver, CO, 1 Unit

Natural Gas

Combustion Turbine:

Blue Spruce-Aurora, CO, 2 Units

Cherokee-Denver, CO, 3 Units

Natural Gas

Fort St. Vrain-Platteville, CO, 6 Units

Natural Gas

1972 - 2009

Rocky Mountain-Keenesburg, CO, 3 Units

Natural Gas

Various locations, 6 Units

Natural Gas

Hydro:

Pumped Storage, 2 Units

Various locations, 8 Units

Wind:

Rush Creek, CO, 300 units

Hydro

Wind

1981

1968

2003

2015

2004

Various

1967

Various

2018

Total

505

310

264

576

968

580

171

210

582 (g)

5,666

(a)

(b)

(c)

(d)

(e)

(f)

(g)

Summer 2019 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 is expected to be retired early in 2025.

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 maximum generation levels for these wind units. Capacity is
attainable only when wind conditions are sufficiently available (on-demand net dependable
capacity is zero).

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 units and increase the price paid 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 first mortgage bond indentures.

NSP-Minnesota
Station, Location and Unit

Steam:

A.S. King-Bayport, MN, 1 Unit

Sherco-Becker, MN

Unit 1

Unit 2

Unit 3

Monticello, MN, 1 Unit

PI-Welch, MN

Unit 1

Unit 2

Various locations, 4 Units

Combustion Turbine:

Fuel

Installed

MW (a)

Coal

Nuclear

1968

1976

1977

1987

1971

1973

1974

511

680

682

517 (b)

617

521

519

Angus Anson-Sioux Falls, SD, 3 Units

Natural Gas

1994 - 2005

Black Dog-Burnsville, MN, 3 Units

Natural Gas

1987 - 2018

Blue Lake-Shakopee, MN, 6 Units

Natural Gas

1974 - 2005

High Bridge-St. Paul, MN, 3 Units

Natural Gas

Inver Hills-Inver Grove Heights, MN, 6 Units

Natural Gas

Riverside-Minneapolis, MN, 3 Units

Natural Gas

2008

1972

2009

Various locations, 7 Units

Natural Gas

Various

327

494

453

530

282

454

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

Wind

2015

2016

2019

2008

2019

2010

2015

Total

148 (d)

190 (d)

150 (d)

99 (d)

197 (d)

196 (d)

7,712

(a)

(b)

(c)

(d)

Summer 2019 net dependable capacity.
Based on NSP-Minnesota’s ownership of 59%.

Refuse-derived fuel is made from municipal solid waste.

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).

Wood/Refuse

Various

36 (c)

Cabin Creek-Georgetown, CO

SPS
Station, Location and Unit

Steam:

Fuel

Installed

MW (a)

Cunningham-Hobbs, NM, 2 Units

Natural Gas

1957 - 1965

189

Harrington-Amarillo, TX, 3 Units

Coal

1976 - 1980

1,018

Jones-Lubbock, TX, 2 Units

Maddox-Hobbs, NM, 1 Unit

Nichols-Amarillo, TX, 3 Units

Plant X-Earth, TX, 4 Units

Tolk-Muleshoe, TX, 2 Units

Combustion Turbine:

Natural Gas

1971 - 1974

Natural Gas

1967

Natural Gas

1960 - 1968

Natural Gas

1952 - 1964

486

112

457

411

Coal

1982 - 1985

1,067

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

209

334

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

Cunningham-Hobbs, NM, 2 Units

Natural Gas

1997

Jones-Lubbock, TX, 2 Units

Maddox-Hobbs, NM, 1 Unit

Wind:

Natural Gas

2011 - 2013

Natural Gas

1963 - 1976

Hale-Plainview, TX, 239 Units

Wind

2019

Total

460 (b)

4,804

(a)

(b)

Summer 2019 net dependable capacity.
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).

Electric utility overhead and underground transmission and distribution lines
(measured in conductor miles) at Dec. 31, 2019:

Conductor Miles

NSP-Minnesota

NSP-Wisconsin

PSCo

SPS

500 KV

345 KV

230 KV

161 KV

138 KV

115 KV

Less than 115 KV

2,917

13,133

2,203

673

—

8,045

86,743

—

3,337

—

1,821

—

1,815

32,816

—

5,036

12,108

—

5,055

79,740

—

9,566

9,784

—

14,662

26,216

Electric utility transmission and distribution substations at Dec. 31, 2019:

NSP-Minnesota

NSP-Wisconsin

PSCo

SPS

Quantity

346

204

233

452

Natural gas utility mains at Dec. 31, 2019:

Miles

NSP-Minnesota

NSP-Wisconsin

PSCo

SPS

WGI

Transmission

Distribution

10,518

2,057

2,473

22,633

—

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.

Stock Data

Xcel Energy Inc.’s common stock was listed on the New York Stock Exchange
(NYSE) in 2017, but moved to the Nasdaq Global Select Market (Nasdaq) in
2018. The trading symbol is XEL. The number of common stockholders of
record as of Feb. 19, 2020 was approximately 54,543.

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

The EEI Investor-Owned Electrics Index (market capitalization-weighted)
included 40 companies at year-end and is a broad measure of industry
performance.

Comparison of Five Year Cumulative Total Return*

$220

$200

$180

$160

$140

$120

$100

$80

2014

2015

2016

2017

2018

2019

Xcel Energy Inc.

EEI Electrics

S&P 500

* $100 invested on Dec. 31, 2014 in stock or index — including reinvestment

of dividends. Fiscal years ended Dec. 31.

Securities Authorized for Issuance Under Equity Compensation Plans

Information required under Item 5 — Securities Authorized for Issuance under
Equity Compensation Plans is contained in Xcel Energy’s Proxy Statement
for its 2020 Annual Meeting of Shareholders, which is incorporated by
reference.

Purchases of Equity Securities by Issuer and Affiliated Purchasers

For the quarter ended Dec. 31, 2019, no equity securities that are registered
by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of
1934 were purchased by or on behalf of us or any of our affiliated purchasers.

ITEM 6 — SELECTED FINANCIAL DATA

Selected financial data for Xcel Energy related to the five most recent years ended Dec. 31:

(Millions of Dollars, Millions of Shares, Except Per Share Data)

2019

2018

2017

2016

2015

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 (b) (c)

Long-term debt (c) (d)

11,529

11,537

11,404

11,107

9,425

1,372

2.64

1.62

50,448

17,407

9,572

1,261

2.47

1.52

45,987

15,803

9,181

1,148

2.25

1.44

43,030

14,520

8,867

1,123

2.21

1.36

41,155

14,195

11,024

9,024

984

1.94

1.28

38,821

12,399

(a)

(b)

(c)

(d)

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 ASU No. 2015-17 (Balance Sheet Classification of Deferred Taxes, Topic 740), $140 million of current deferred income taxes was retrospectively reclassified to long-
term deferred income tax liabilities on the consolidated balance sheet as of Dec. 31, 2015.
As a result of adopting ASU No. 2015-03 (Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30), $92 million of deferred debt issuance costs was retrospectively reclassified
from other noncurrent assets to long-term debt on the consolidated balance sheet as of Dec. 31, 2015.
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.

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

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, 2019 and Dec. 31, 2018, there were no such adjustments to GAAP
earnings and therefore GAAP earnings equal ongoing earnings.

Non-GAAP Financial Measures

financial

includes

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.

Results of Operations

Diluted EPS for Xcel Energy at Dec. 31:

Xcel Energy Inc. and other — Xcel Energy Inc. and other primarily includes
financing costs at the holding company.

Changes in Diluted EPS

Diluted Earnings (Loss) Per Share

GAAP and
Ongoing Diluted
EPS

2019 vs. 2018

2019

2018

Components significantly contributing to changes in EPS:

PSCo

NSP-Minnesota

SPS

NSP-Wisconsin

Equity earnings of unconsolidated subsidiaries (a)

Regulated utility (b)

Xcel Energy Inc. and other

Total (b)

(a)

(b)

Includes income taxes.

Amounts may not add due to rounding.

1.11

1.04

0.51

0.15

0.05

2.86

(0.22)

2.64

1.08

0.96

0.42

0.19

0.04

2.69

(0.22)

2.47

Xcel Energy’s management believes
that ongoing earnings reflects
management’s performance in operating the Company 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.

2019 Comparison with 2018

Xcel Energy — GAAP and ongoing earnings increased $0.17 per share.
Earnings increased as a result of higher electric margins primarily due to non-
fuel riders and regulatory rate outcomes, higher natural gas margins and lower
O&M expenses, primarily offset by lower AFUDC, increased depreciation and
interest expenses.

Utility Subsidiaries 2019 GAAP and Ongoing Diluted EPS

NSP-Minnesota 37%

PSCo 40%

NSP-Wisconsin 5%

SPS 18%

PSCo — Earnings increased $0.03 per share for 2019, reflecting higher
electric margin due primarily to capital riders and increased natural gas margin
attributable to capital riders, weather and sales growth, partially offset by lower
AFUDC driven by the Rush Creek wind project that was placed in service in
2018 and higher depreciation, interest and O&M.

NSP-Minnesota — Earnings increased $0.08 per share for 2019, reflecting
higher electric margin resulting from regulatory rate outcomes and capital
riders and lower O&M, partially offset by increased depreciation.

SPS — Earnings increased $0.09 per share, reflecting higher electric margin
attributable to purchased capacity costs, regulatory rate outcomes and
demand revenue and higher AFUDC, partially offset by increased interest and
depreciation.

NSP-Wisconsin — Earnings decreased $0.04 per share, reflecting lower
electric margin, primarily related to sales decline and the impact of unfavorable
weather, higher depreciation and lower AFUDC.

Diluted Earnings (Loss) Per Share
GAAP and ongoing diluted EPS - 2018

Components of change — 2019 vs. 2018

Higher electric margins

Lower ETR (a)

Higher natural gas margins

Lower O&M

Higher depreciation and amortization

Higher interest

Lower AFUDC

Dec. 31

2.47

0.29

0.15

0.08

0.02

(0.18)

(0.11)

(0.08)

2.64

GAAP and ongoing diluted EPS — 2019

(a)

Includes PTCs and timing of tax reform regulatory decisions, which are primarily offset in
electric margin.

ROE for Xcel Energy and its utility subsidiaries at Dec. 31:

ROE

PSCo

NSP-Minnesota

SPS

NSP-Wisconsin

Operating Companies

Xcel Energy

2019

2018

GAAP and Ongoing ROE

8.69%

9.31

9.71

8.27

9.06

10.78

9.10%

8.91

9.14

10.77

9.14

10.65

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 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.

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

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

HDD

CDD

THI

2019 vs.
Normal

2018 vs.
Normal

2019 vs.
2018

10.4%

5.4

(8.8)

2.2%

26.7

37.3

6.8%

(15.5)

(33.2)

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

•

NSP-Minnesota — Flat residential sales reflect lower use per customer
offset by customer additions. The decline in C&I sales was a result of
customer growth being offset by lower use per customer, and certain
customers moving to co-generation. Decreased sales to C&I customers
were driven by the energy and manufacturing sectors;
SPS — Residential sales grew largely due to an increase in customers
and higher use per customer. C&I sales grew based on higher use per
small C&I customer and an overall increase in the number of C&I
customers. In addition, the increase in C&I sales was driven by the oil
and natural gas industry in the Southeastern New Mexico, Permian Basin
area; and
NSP-Wisconsin — Residential sales growth was primarily attributable to
customer additions and more use per customer. The decline in C&I sales
was largely due to lower use per customer and decreased sales to the
frac sand mining, food and manufacturing sectors, which was partially
offset by customer additions.

Weather-normalized 2019 Natural Gas Sales Growth

2019 vs.
Normal

2018 vs.
Normal

2019 vs.
2018

•

Retail electric

Firm natural gas

Total (excluding decoupling)

Decoupling — Minnesota electric

Total (adjusted for recovery from decoupling)

0.040

0.027

0.067

—

0.067

0.114

0.007

0.121

(0.051)

0.070

(0.074)

0.020

(0.054)

0.051

(0.003)

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

2019 vs. 2018

PSCo

NSP-
Minnesota

SPS

NSP-
Wisconsin

Xcel
Energy

Actual

Electric
residential

Electric C&I

Total retail
electric sales

Firm natural gas
sales

0.1%

(0.6)

(0.3)

12.9

(3.5)%

(4.0)

(3.9)

3.6

0.3%

3.5

2.8

N/A

2019 vs. 2018

(1.8)%

(3.2)

(2.8)

(2.0)

(1.5)%

(1.1)

(1.2)

8.8

PSCo

NSP-
Minnesota

SPS

NSP-
Wisconsin

Xcel
Energy

Weather-normalized

Electric
residential

Electric C&I

Total retail
electric sales

Firm natural gas
sales

(0.1)%

(0.6)

(0.3)

4.1

0.1%

(3.0)

(2.1)

1.1

1.9%

3.8

3.4

N/A

1.1%

(2.6)

(1.6)

(2.5)

0.4%

(0.5)

(0.3)

2.7

Weather-normalized 2019 Electric Sales Growth (Decline)

•

PSCo — Residential sales declined due to lower use per customer,
partially offset by an increased number of customers. The decline in C&I
was mainly due to lower use per customer, primarily led by customers
in the food products and service industries, partially offset by growth in
the metal mining and fabricated metal and industries. The decrease in
customer use was partially offset by an increase in the number of C&I
customers;

Overall natural gas sales reflect an increase in the number of customers
combined with higher customer use, particularly C&I at PSCo. This was
partially offset by a decline in C&I sales at NSP-Wisconsin, driven by the
frac sand mining industry.

Weather-normalized sales for 2020 are projected to increase ~1% over 2019
levels for retail electric and natural gas customers, including the impact of
leap year.

Electric Margin

Electric revenues and fuel and purchased power expenses are impacted by
fluctuations in the price of natural gas, coal and uranium used in the generation
of electricity. However, these price fluctuations have minimal impact on electric
margin due to fuel recovery mechanisms that recover fuel expenses. In
addition, electric customers receive a credit for PTCs generated in a particular
period.

Electric Margin

(Millions of Dollars)

Non-fuel riders (a)

2019 vs. 2018

107

Regulatory rate outcomes (Minnesota, New Mexico, North and South
Dakota)

Implementation of lease accounting standard (offset in interest
expense and amortization)

Purchased capacity costs

Demand revenue

Wholesale transmission revenue (net)

Timing of tax reform regulatory decisions (offset in income tax and
amortization)

Estimated impact of weather (net of Minnesota decoupling)

Firm wholesale generation

Sales declines (excluding weather impact)

Other (net)

Total increase in electric margin

(37)

(25)

(20)

(18)

200

(a)

Includes approximately $60 million of additional PTC benefit (grossed-up for tax) as
compared to 2018, which are credited to customers through various regulatory
mechanisms.

Natural Gas Margin

Xcel Energy Inc. and Other Results

Total natural gas expense varies with changing sales requirements and the
cost of natural gas. However, fluctuations in the cost of natural gas has minimal
impact on natural gas margin due to cost recovery mechanisms.

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

Natural Gas Margin

(Millions of Dollars)

Infrastructure and integrity riders

Estimated impact of weather

Transport sales

Retail sales growth

Other (net)

Total increase in natural gas margin

2019 vs. 2018

Xcel Energy Inc. financing costs

Eloigne (a)

Xcel Energy Inc. taxes and other results

Total Xcel Energy Inc. and other costs

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses decreased $14 million, or 0.6%, for 2019.
Significant changes are summarized below:

Xcel Energy Inc. financing costs

Eloigne (a)

Xcel Energy Inc. taxes and other results

Total Xcel Energy Inc. and other costs

Contribution (Millions of Dollars)

2019

2018

(128) $

(115) $

(110)

—

(5)

(115)

Contribution (Diluted Earnings
(Loss) Per Share)

2019

2018

(0.21) $

—

(0.01)

(0.22) $

(0.21)

—

(0.01)

(0.22)

2019 vs. 2018

(a)

Amounts include gains or losses associated with sales of properties held by Eloigne.

(Millions of Dollars)

Plant generation

Nuclear plant operations and amortization

Transmission

Distribution

Other (net)

Total decrease in O&M expenses

(20)

(8)

(7)

(14)

•

Plant generation, transmission and distribution costs were lower due
to timing of maintenance activities;
Nuclear plant operations and amortization were lower largely reflecting
improved operating efficiencies and reduced refueling outage costs;
and
Distribution expenses in 2019 were higher than 2018 due to storms,
labor and overtime incurred primarily in the first six months of 2019.

Depreciation and Amortization — Depreciation and amortization increased
$123 million, or 7%, for 2019. The increase was primarily driven by the Rush
Creek, Hale, Foxtail and Lake Benton wind farms going into service, natural
gas and distribution/transmission replacements, and various software
solutions. These increases were partially offset by higher levels of accelerated
amortization of PSCo’s prepaid pension asset in 2018.

Taxes (Other than Income Taxes) — Taxes (other than income taxes)
increased $13 million, or 2.3%, for 2019. The increase was primarily due to
higher property taxes in Colorado and Minnesota (net of deferred amounts).

AFUDC, Equity and Debt — AFUDC decreased $42 million for 2019. The
decrease was primarily due to the Rush Creek wind project being placed in-
service in 2018, partially offset by the Hale wind project, which went into service
in June 2019, and other capital investments.

Interest Charges — Interest charges increased $73 million, or 10.4%, for
2019. The increase was primarily due to higher debt levels to fund capital
investments, changes in short-term interest rates and implementation of lease
accounting standard (offset in electric margin).

Income Taxes — Income taxes decreased $53 million for 2019, primarily
driven by an increase in wind PTCs. Wind PTCs are credited to customers
(recorded as a reduction to revenue) and do not have a material impact on
net income. These were partially offset by higher pretax earnings in 2019 and
ITCs in 2018. The ETR was 8.5% for 2019 compared with 12.6% for the same
period in 2018, largely due to the adjustments above.

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

2018 Comparison with 2017

A discussion of changes in Xcel Energy’s results of operations and liquidity
and capital resources from the year ended Dec. 31, 2017 to Dec. 31, 2018
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 2018, which was filed with the SEC on Feb. 22, 2019.
However, such discussion is not incorporated by reference into, and does not
constitute a part of, this Annual Report on Form 10-K.

Public Utility Regulation

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

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

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

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

NSP-Minnesota

Summary of Regulatory Agencies / RTO and Areas of Jurisdiction

Regulatory Body / RTO

Additional Information

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 (a)

Certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV in Minnesota.

Reviews and approves natural gas supply plans.

Pipeline safety compliance.

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

NDPSC (a)

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.

SDPUC

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

FERC

MISO

DOT

Minnesota Office of Pipeline
Safety

Pipeline safety compliance.

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

NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale markets. NSP-Minnesota makes wholesale
sales in other RTO markets at market-based rates. NSP-Minnesota and NSP-Wisconsin also make wholesale electric sales at market-based prices to customers
outside of their balancing authority as jointly authorized by the FERC.

Pipeline safety compliance.

(a)

Jurisdictional Cost Recovery Allocation — In December 2016, NSP-Minnesota filed a resource treatment framework with the NDPSC and MPUC to allow NSP-Minnesota’s operations in North
Dakota and Minnesota to gradually become more independent of one another. The filing identified two options: a legal separation, creating a separate North Dakota operating company; or a
pseudo-separation, which maintains the current corporate structure but directly assigns costs and benefits of each resource to the jurisdiction that supports it. Docket remains under consideration
by the NDPSC.

Recovery Mechanisms

Mechanism

CIP Rider (a)

EIR

RDF

RES

RER

SEP

TCR

Recovers costs of conservation and DSM programs.

Recovers costs of environmental improvement projects.

Additional Information

Allocates money collected from customers to support research and development of emerging renewable energy projects and technologies.

Recovers cost of renewable generation in Minnesota.

Recovers the cost of renewable generation in North Dakota.

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

Recovers costs for investments in electric transmission and distribution grid modernization.

Infrastructure Rider

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

FCA (b)

PGA

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 actuals costs.

GUIC Rider

Recovers costs for transmission and distribution pipeline integrity management programs, including: funding for pipeline assessments, deferred costs for sewer
separation and pipeline integrity management programs.

(a)

(b)

Minnesota state law requires NSP-Minnesota to invest 2% of its state electric revenues and 0.5% of its state gas revenues in CIP. These costs are recovered through an annual cost-recovery
mechanism.

In 2017, the MPUC changed the FCA process in Minnesota, which will implemented in 2020. Under the new process, each month utilities would collect amounts equal to the baseline cost of
energy set at the start of the plan year (base would be reset annually). Monthly variations to the baseline costs would be tracked and netted over a 12-month period. Utilities would issue refunds
above the baseline costs and could seek recovery of any overage.

Pending and Recently Concluded Regulatory Proceedings

Mechanism

Utility
Service

Amount
Requested (in
millions)

Filing
Date

Approval

MPUC

Additional Information

2018 TCR

Electric

2020 TCR

Electric

2019 GUIC

2020 GUIC

Natural
Gas

2018 RES

Electric

$98

$82

$29

$21

$23

November 2017

Received

In November 2019, the MPUC issued an order setting an ROE of 9.06% and recovery of 2017-2018
expenses related to advanced grid investments.

November 2019

Pending

In November 2019, NSP-Minnesota filed the 2020 TCR Rider. The filing included an ROE of 9.06%. Timing
of an MPUC ruling is uncertain.

November 2018

Pending

In November 2018, NSP-Minnesota filed the 2019 GUIC Rider with the MPUC. The filing included an ROE
of 10.25%. Timing of an MPUC ruling is uncertain.

November 2019

Pending

In November 2019, NSP-Minnesota filed the 2020 GUIC Rider with the MPUC. The filing included an ROE
of 9.04%. Timing of an MPUC ruling is uncertain.

November 2017

Received

In November 2019, the MPUC approved an order setting an ROE of 9.06%.

2020 RES

Electric

$102

November 2019

Pending

In November 2019, NSP-Minnesota filed the 2020 RES Rider with the MPUC. 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%. Timing of an MPUC ruling is uncertain.

Minnesota Electric Rate Case and Alternative Petition — In November 2019,
NSP-Minnesota filed a three-year electric rate case with the MPUC. The
proposed electric rates reflect a three-year increase in revenues of
approximately $201.4 million (6.5%) in 2020, with subsequent incremental
increases of $146.4 million (4.8%) in 2021 and $118.3 million (3.9%) in 2022.
The rate case is based on a requested ROE of 10.2%, a 52.5% equity ratio,
an average electric rate base of $9.0 billion for 2020, $9.3 billion for 2021 and
$9.8 billion for 2022.

In addition, NSP-Minnesota requested interim rates, subject to refund, of
$122.0 million to be implemented in January 2020 and an incremental $144.0
million to be implemented in January 2021.

NSP-Minnesota also filed a stay-out petition, in which NSP-Minnesota would
withdraw its electric rate case and refrain from filing another rate case for one
year if the MPUC were to approve an extension of true-up mechanisms for
sales, capital and property taxes. NSP-Minnesota also requested that the
MPUC delay any increase to the Nuclear Decommissioning Trust annual
accrual until 2021.

In December 2019, the MPUC verbally approved the stay-out petition including
extension of the sales, capital and property tax true-up mechanisms and the
delay of any increase to the Nuclear Decommissioning Trust annual accrual
until Jan. 1, 2021.

MEC Acquisition — In November 2018, NSP-Minnesota reached an
agreement with Southern Power Company (a subsidiary of Southern
Company) to purchase MEC, a 760 MW natural gas combined cycle facility,
for approximately $650 million.

In September 2019, the MPUC denied NSP-Minnesota's request to purchase
MEC as a rate base asset. In January 2020, the MPUC approved Xcel Energy’s
plan to acquire MEC as a non-regulated investment and step into the terms
of the existing PPAs with NSP-Minnesota. A newly formed non-regulated
subsidiary of Xcel Energy completed the transaction to purchase MEC on Jan.
17, 2020.

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 preferred plan
includes the following:

•

Extends the life of the Monticello nuclear plant from 2030 to 2040;

Continues to run PI through current end of life (2033 and 2034);

Includes the MEC acquisition and construction of the Sherco
combined cycle natural gas plant;

Includes the early retirement of the King coal plant (511 MW) in 2028
and the Sherco 3 coal plant (517 MW) in 2030;

Adds approximately 1,700 MW of firm peaking (combustion turbine,
pumped hydro, battery storage, demand response, etc.);

Adds approximately 1,200 MW of wind replacement; and

Adds approximately 4,000 MW of solar.

Intervening parties will provide recommendations and comments on the
resource plan. Following the MPUC’s denial of its request to purchase MEC,
NSP-Minnesota will provide updates to remove its ownership of MEC from
the preferred plan. The MPUC required NSP-Minnesota to update its filing to
address issues related to its decision on MEC, including certain new modeling
scenarios. An updated filing is required by April 1, 2020. The MPUC is
anticipated to make a final decision on the resource plan in the first half of
2021.

Jeffers Wind and Community Wind North Repowering Acquisition — In
October 2019, the MPUC approved NSP-Minnesota’s request to acquire the
Jeffers and Community Wind North wind facilities in western Minnesota from
Longroad Energy. The wind farms will have approximately 70 MW of capacity
after being repowered. The repowering is expected to be completed by
December 2020 and qualify for the full PTC. The $135 million asset acquisition
is projected to provide customer savings of approximately $7 million over the
life of the facilities.

Nuclear Power Operations and Waste Disposal

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 of-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. The
federal government has been evaluating a nuclear geologic repository at
Yucca Mountain, Nevada for many years. Currently, there are no definitive
plans for a permanent federal storage facility site.

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

Wholesale and Commodity Marketing Operations

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

Mower Wind Facility — In August 2019, NSP-Minnesota filed a petition with
the MPUC to acquire the Mower wind facility from affiliates of NextEra Energy,
Inc. for an undisclosed amount. The Mower facility is located in southeastern
Minnesota and is currently contracted under a PPA with NSP-Minnesota
through 2026. Mower is expected to continue to have approximately 99 MW
of capacity following a planned repowering. The acquisition would occur after
repowering, which is expected to be complete in 2020 and qualify for the full
PTC. NSP-Minnesota will need approval from both the MPUC and FERC to
complete the transaction. NSP-Minnesota filed reply comments addressing
the DOC’s concerns with the transaction in February 2020.Timing of MPUC
and FERC decisions are uncertain.

Purchased Power Arrangements and Transmission Service Provider

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

Purchased Power — NSP-Minnesota has contracts to purchase power from
other utilities and IPPs. Long-term purchased power contracts for dispatchable
resources typically require a capacity and an energy charge. NSP-Minnesota
makes short-term purchases to meet system requirements, replace company
owned generation, meet operating reserve obligations or obtain energy at a
lower cost.

PPA Terminations and Amendments — In June 2018, NSP-Minnesota
terminated the Benson and Laurentian PPAs, and purchased the Benson
biomass facility. As a result, a $103 million regulatory asset was recognized
for the costs of the Benson transaction. For Laurentian, a regulatory asset of
$109 million was recognized for annual termination payments/obligations.
Regulatory approvals provide for recovery of the Benson regulatory asset over
10 years and Laurentian termination payments as they occur (over six years).
Termination of the PPAs is expected to save customers over $600 million
throughout the next 10 years.

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

Minnesota State ROFR Statute Complaint — In September 2017, LSP
Transmission filed a complaint in the Minnesota District Court against the
Minnesota Attorney General, MPUC and DOC. The complaint was in response
to MISO assigning NSP-Minnesota and ITC Midwest, LLC to jointly own a
new 345 KV transmission line from Mankato to Winnebago, Minnesota.

The project was estimated to cost $108 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. The Minnesota state agencies
and NSP-Minnesota filed motions to dismiss.

In June 2018, the Minnesota District Court granted the defendants’ motions
to dismiss with prejudice. LSP Transmission filed an appeal in July 2018. In
September 2019, the estimate was updated to approximately $140 million,
due to various changes in build plans. In October 2019, oral arguments were
held with the Eighth Circuit Court of Appeals. A decision is expected in the
first or second quarter of 2020.

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.

PSCW

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.

Pipeline safety compliance.

FERC

MISO

DOT

Recovery Mechanisms

Mechanism

Annual Fuel Cost Plan (a)

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

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

Pipeline safety compliance.

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.

Additional Information

Power Supply Cost
Recovery Factors

Wisconsin Energy
Efficiency Program

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.

PGA

NSP-Wisconsin has a retail PGA cost-recovery mechanism for Wisconsin to recover the actual cost of natural gas and transportation and storage services.

Natural Gas Cost-Recovery
Factor (MI)

NSP-Wisconsin’s natural gas rates for Michigan customers include a natural gas cost-recovery factor, based on 12-month projections and trued-up to actual amounts
on an annual basis.

(a)

NSP-Wisconsin’s electric fuel costs were lower than authorized in rates and outside the 2% annual tolerance band in 2019. Under the fuel cost recovery rules, NSP-Wisconsin retained the $3.3
million of over-recovered fuel costs (amounts within annual tolerance band) and deferred $9.7 million (amounts in excess of annual tolerance band) as a regulatory liability. NSP-Wisconsin
plans to file a reconciliation of 2019 fuel costs with the PSCW by March 2020.

Pending and Recently Concluded Regulatory Proceedings

Mechanism

Utility
Service

Amount
Requested (in
millions)

Filing
Date

Approval

Rate Case

Electric &
Natural
Gas

N/A

May 2019

Received

PSCW

Additional Information

In May 2019, NSP-Wisconsin filed an application with the PSCW seeking no change to base electric rates
through Dec. 31, 2021; and a $3.2 million (4.6%) decrease to base natural gas rates, effective Jan. 1,
2020, and no additional changes to base natural gas rates through Dec. 31, 2021. The settlement is based
on an ROE of 10.0% and an equity ratio of 52.5%. In September 2019, the PSCW issued an interim order
approving the settlement agreement as filed with one minor modification, to remove the deferral of pension
settlement accounting costs for 2021. A final order was received in December 2019.

Purchased Power and Transmission Services

Wholesale and Commodity Marketing Operations

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

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.

PSCo

Summary of Regulatory Agencies / RTO and Areas of Jurisdiction

Regulatory Body / RTO

Additional Information

CPUC

FERC

RTO

DOT

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

Pipeline safety compliance.

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

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

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

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

Pipeline safety compliance.

Recovery Mechanisms

Mechanism

ECA

PCCA

SCA

DSMCA

RESA

WCA

TCA

CACJA

FCA

GCA

PSIA

Additional Information

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 difference between actual fuel costs and costs recovered under steam service rates. The SCA rate is revised quarterly.

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

Recovers the incremental costs of compliance with the RES with a maximum of 2% of the customer’s bill.

Recovers costs for customers who choose renewable resources.

Recovers costs for transmission investment outside of rate cases.

Recovers costs associated with the CACJA.

PSCo recovers fuel and purchased energy costs from wholesale electric customers through a fuel cost adjustment clause approved by the FERC. Wholesale
customers pay production costs through a forecasted formula rate subject to true-up.

Recovers costs of purchased natural gas and transportation and is revised quarterly to allow for changes in natural gas rates.

Recovers costs for transmission and distribution pipeline integrity management programs.

Pending and Recently Concluded Regulatory Proceedings

Mechanism

Utility
Service

Amount
Requested (in
millions)

Filing
Date

Approval

Rate Case

Steam

January 2019

Received

Rate Case
Appeal

Natural
Gas

N/A

April 2019

Pending

CPUC

Additional Information

In September 2019, the CPUC approved PSCo’s Settlement Agreement with CPUC Staff and the City of
Denver. The settlement reflects an ROE of 9.67% for AFUDC purposes, an equity ratio of 56.04% and
utilization of tax reform benefits. The first stepped increase went into effect Oct. 1, 2019, with full rates
effective Oct. 1, 2020.

In April 2019, PSCo filed an appeal seeking judicial review of the CPUC’s prior ruling regarding PSCo’s
last natural gas rate case (approved in December 2018). Appeal requests review of the following: denial
of a return on the prepaid pension and retiree medical assets; the use of a capital structure that is not
based on the actual historical test year level; and the use of an average rate base methodology rather than
a year-end rate base methodology. Timeline on a final ruling is unknown.

DSM
Incentive

Electric &
Natural
Gas

$12

April 2019

Received

PSCo earned an electric and natural gas DSM incentive of $9 million and $3 million, respectively, for
achieving its 2018 savings goals.

PSCo — Electric Rate Case — In October 2019, PSCo filed rebuttal testimony
with the CPUC requesting a net rate increase of $108 million. This is based
on a $353 million increase offset by $245 million of previously authorized costs
currently recovered through various rider mechanisms. The request was
based on a ROE of 10.20%, an equity ratio of 55.61% and a current test year,
which includes certain forecasted plant additions through December 2019.

In December 2019, the CPUC held deliberations and on Feb. 11, 2020 issued
a written decision approving a current test year ended Aug. 31, 2019, a 9.3%
ROE, an equity ratio of 55.61%, implementation of decoupling in 2020 and
other items. This resulted in an estimated $35 million net base rate revenue
increase.

Revenue Request (Millions of Dollars)

2020

Company filed rebuttal
ROE

Impact of change in test year

Property tax expense

Rate base adjustments

Capital structure
Total proposed revenue change
Estimated impact of previously authorized costs (existing riders)

Net revenue change

353

(55)

(17)

(11)
(5)
280

245

Final rates are expected to be implemented in February 2020. PSCo currently
intends to file an application for rehearing/reconsideration in the first quarter
of 2020.

PSCo — Gas Rate Case — On Feb. 5, 2020, PSCo filed a request with the
CPUC seeking a net increase to retail gas rates of $127 million, reflecting a
$145 million increase in base rate revenue, which is partially offset by $18
million previously authorized through the PSIA rider mechanism. The request
is based on a test year that incorporates actual capital and expenses as of
Sept. 30, 2019, adjusted for known and measurable differences for the 12-
month period ended Sept. 30, 2020, a 9.95% ROE and an equity ratio of
55.81%. Proposed effective date is Nov. 1, 2020.

Revenue Request (Millions of Dollars)

Capital additions (through Sept. 30, 2019)

Forecasted capital additions (through Sept. 30, 2020)

Sales growth (includes amounts forecasted through Sept. 30, 2020)

Operations and maintenance, amortization and other expenses

Property tax expense

Cost of capital

Updated depreciation rates

Net increase to revenue

Previously authorized costs:

Transfer PSIA rider costs to base rates

Total base request

Expected year-end rate base

2020

(29)

127

145

2,236

The request reflects $1.3 billion of capital additions since the 2016 test year
used to set current rates. Capital investments are made to maintain the safety
and reliability of the natural gas system, along with investments to connect
new customers and perform mandated infrastructure relocation work.

Timing of a CPUC ruling is expected in the second half of 2020.

Resource Plan

CEP — In September 2018, the CPUC approved PSCo’s CEP portfolio, which
included the retirement of two coal-fired generation units, Comanche Unit 1
(in 2022) and Comanche Unit 2 (in 2025), and the following additions:

Wind generation

Solar generation

Battery storage

Natural gas generation

Total Capacity

PSCo's Ownership

1,100 MW

700 MW

275 MW

380 MW

500 MW

—

380 MW

PSCo’s investment is expected to be approximately $1 billion, including
transmission to support the increase in renewable generation.

CPCNs were granted by the CPUC for the Shortgrass Substation in February
2019, and for the 500 MW Cheyenne Ridge wind farm and 345 KV generation
tie line in April 2019.

A CPCN for the acquisitions of the Valmont and Manchief natural gas
generation facilities was filed in July 2019, and a settlement on those
acquisitions was reached with CPUC Staff and the Colorado Office of
Consumer Counsel in January 2020, pending a CPUC decision expected in
approximately the second quarter of 2020.

A CPCN for voltage control facilities was also filed with the CPUC in December
2019, with another expected to follow in approximately the first quarter of 2020
for network transmission upgrades required for the CEP portfolio.

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.

Purchased Transmission Services — In addition to using its own transmission
system, PSCo has contracts with regional transmission service providers to
deliver energy to its customers.

Boulder Municipalization

In 2011, Boulder passed a ballot measure authorizing the formation of an
electric municipal utility, subject to certain conditions. Subsequently, there
have been various legal proceedings in multiple venues with jurisdiction over
Boulder’s plan. In 2014, the Boulder City Council passed an ordinance to
establish an electric utility. PSCo challenged the formation of this utility and
the Colorado Court of Appeals ruled in PSCo’s favor, vacating a lower court
decision. In June 2018, the Colorado Supreme Court rejected Boulder’s
request to dismiss the case and remanded it to the Boulder District Court. The
case was then settled in June 2019 after Boulder agreed to repeal the
ordinance establishing the utility.

Boulder has filed multiple separation applications with the CPUC, which have
been challenged by PSCo and other intervenors. In September 2017, the
CPUC issued a written decision, agreeing with several key aspects of PSCo’s
position. The CPUC has approved the designation of some electrical
distribution assets for transfer, subject to Boulder completing certain filings.

In the fourth quarter of 2018, the Boulder City Council also adopted an
Ordinance authorizing Boulder to begin negotiations for the acquisition of
certain property or to otherwise condemn that property after Feb. 1, 2019. In
the first quarter of 2019, Boulder sent PSCo a notice of intent to acquire certain
electric distribution assets. In the third quarter of 2019, Boulder filed its
condemnation litigation, which was later dismissed by the Boulder District
Court in September 2019 on the grounds that Boulder had not completed the
pre-requisite CPUC process and filings. Boulder is currently appealing this
order. In October 2019, the CPUC approved the subsequent filings regarding
asset transfers outside of substations, reaffirmed its 2017 decision on assets
outside of substations and closed the CPUC proceeding.

In December 2019, Boulder filed a new condemnation action despite its
ongoing appeal of the last condemnation case. PSCo subsequently filed a
motion to dismiss or stay the new condemnation action. In February 2020,
Boulder filed an application under section 210 of the Federal Power Act asking
FERC to order PSCo to interconnect its facilities with a future Boulder
municipal utility under Boulder’s preferred terms and conditions.

Wholesale and Commodity Marketing Operations

PSCo conducts various wholesale marketing operations, including the
purchase and sale of electric capacity, energy, ancillary services and energy
related products. PSCo uses physical and financial instruments to minimize
commodity price and credit risk and hedge sales and purchases. PSCo also
engages in trading activity unrelated to hedging. Sharing of any margin is
determined through state regulatory proceedings as well as the operation of
the FERC approved JOA.

SPS

Summary of Regulatory Agencies / RTO and Areas of Jurisdiction

Regulatory Body / RTO

Additional Information

PUCT

NMPRC

FERC

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.

SPP RTO and SPP IM
Wholesale Market

SPS is a transmission-owning member of the SPP RTO and operates within the SPP RTO and SPP IM wholesale market. SPS is authorized to make wholesale
electric sales at market-based prices.

Recovery Mechanisms

Mechanism

DCRF
EECRF

Recovers distribution costs not included in rates in Texas.
Recovers costs for energy efficiency programs in Texas.

Additional Information

Energy Efficiency Rider

Recovers costs for energy efficiency programs in New Mexico.

FPPCAC

PCRF

RPS

TCRF

Adjusts monthly to recover actual fuel and purchased power costs in New Mexico. In October 2019, SPS filed an application to the NMPRC to approve SPS’
continued use of its FPPCAC and for reconciliation of fuel costs for the period Sept. 1, 2015, through June 30, 2019, which will determine whether all fuel costs
incurred are eligible for recovery. No procedural schedule has yet been established for this matter.

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.

Fixed Fuel and Purchased
Recovery Factor

Provides for the over- or under-recovery of energy expenses. Regulations require refunding or surcharging over- or under- recovery amounts, including interest,
when they exceed 4% of the utility’s annual fuel and purchased energy costs on a rolling 12-month basis, if this condition is expected to continue.

Wholesale Fuel and
Purchased Energy Cost
Adjustment

SPS recovers fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased energy cost adjustment clause
accepted by the FERC. Wholesale customers also pay the jurisdictional allocation of production costs.

Pending and Recently Concluded Regulatory Proceedings

Mechanism

Utility
Service

Amount
Requested (in
millions)

Filing
Date

Approval

Rate Case

Electric

$51

July 2019

Pending

SPS (NMPRC)

Additional Information

In July 2019, SPS filed an electric rate case with the NMPRC seeking an increase in retail electric base
rates of approximately $51 million. The rate request is based on an ROE of 10.35%, an equity ratio of
54.77%, a rate base of approximately $1.3 billion and a historic test year with rate base additions through
Aug. 31, 2019. In December 2019, SPS revised its base rate increase request to approximately $47 million,
based on an ROE of 10.10% and updated information. The request also included an increase of $14.6
million for accelerated depreciation including the early retirement of the Tolk Coal Plant in 2032.

On Jan. 13, 2020, SPS and various parties filed an uncontested comprehensive stipulation. The stipulation
includes a base rate revenue increase of $31 million, based on an ROE of 9.45% and an equity ratio of
54.77%. The stipulation also includes an acceleration of depreciation on the Tolk Coal Plant to reflect early
retirement in 2037, which results in a total increase in depreciation expense of $8 million. The Signatories
will not oppose the full application of depreciation rates associated with the 2032 retirement date in SPS’
next base rate case. SPS anticipates final rates will go into effect in the second or third quarter of 2020.

SPS — Texas Electric Rate Case

Proposed modifications to SPS’ request:

In August 2019, SPS filed an electric rate case with the PUCT seeking an
increase in retail electric base rates of approximately $141 million. The filing
requests an ROE of 10.35%, a 54.65% equity ratio, a rate base of
approximately $2.6 billion and is built on a 12 month period that ended June
30, 2019. In September 2019, SPS filed an update to the electric rate case
and revised its requested increase to approximately $137 million.

On Feb. 10, 2020, the Alliance of Xcel Municipalities (AXM), Texas Industrial
Energy Consumers (TIEC), Office of Public Utility Counsel (OPUC) and
Department of Energy (DOE) filed testimony along with several other parties.

On Feb. 18, 2020, the PUCT Staff filed testimony that included certain
adjustments and various ring-fencing measures.

(Millions of Dollars)

SPS Direct Testimony

Staff

AXM

OPUC

TIEC

DOE

$ 137

137

$ 137

Recommended base rate adjustments:

ROE

Capital structure
Tolk/Harrington O&M disallowance

Distribution and Transmission
Capital Disallowances (a)
Depreciation expense

Excess ADIT unprotected plant
Income Tax Expense Differences

Other, net

Total Adjustments

(22)

(7)
—

(7)

(8)
—

(12)

(6)

(62)

(24)

(10)
(7)

—

(15)
—

—

(6)

(62)

(15)

—
—

—

(8)
(7)

—

(1)

(31)

(21)

(7)
—

—

(20)
—

—

(1)

(49)

(24)
(3)
—

—

—
—

—

(27)

Total proposed revenue change

106

$ 110

Recommended Position

Staff

AXM

OPUC (b)

TIEC

DOE

Natural Gas

ROE

Equity Ratio

9.1%

9.0%

—%

9.2%

9.0%

51.00% 50.00%

—% 51.00% 53.00%

(a)

(b)

Staff recommends exclusion of approximately $134 million in transmission, distribution,
and general plant in service in this rate case resulting in an approximate $7 million decrease
to the revenue requirement.

OPUC did not provide a recommendation for an ROE or equity ratio. For illustrative
purposes an ROE of 9.5% was used.

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

•
•

Rebuttal testimony — March 11, 2020; and

Public hearing begins — March 30, 2020

A PUCT decision and implementation of final rates is anticipated in the third
quarter of 2020.

Resource Plan

In December 2018, the NMPRC issued a final order accepting SPS’ IRP.

SPS is forecasting a surplus capacity of 382 MW in 2028, but a capacity deficit
of approximately 2,896 MW in 2038. SPS’ optimal resource plan for the
planning period incorporates the addition of wind, simple cycle combustion
turbine generation, combined cycle energy and entering PPAs. Various factors
may impact this IRP, which could potentially require updates to the action plan
and will be the subject of future IRPs, including:

•

New and revised environmental regulations;

Impacts of variability due to participation in the SPP;

Customer expectations;

Technological advances;

Groundwater aquifer depletion at SPS’s Tolk Station;

Aging generation fleet;

Load growth and gas price variability;

Changes to tax credits and incentives; and

Changes to renewable portfolio standard acquisitions.

SPS is required to file an IRP in New Mexico every three years and will file
its next IRP in July 2021.

Texas State ROFR

In May 2019, the Governor signed into law Senate Bill 1938, which grants
incumbent utilities a ROFR to build transmission infrastructure when it directly
interconnects to the utility’s existing facility. In June 2019, a complaint was
filed in the United States District Court for the Western District of Texas claiming
the new ROFR law to be unconstitutional. The Texas Attorney General has
made a motion to dismiss the federal court complaint. A ruling on the dismissal
motion is expected in the first quarter of 2020.

Purchased Power Arrangements and Transmission Service Providers

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

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

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

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.

Critical Accounting Policies and Estimates

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

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

Regulatory Accounting

Xcel Energy is subject to the accounting for Regulated Operations, which
provides that rate-regulated entities report assets and liabilities consistent
with the recovery of those incurred costs in rates, if it is probable that such
rates will be charged and collected. Our rates are derived through the
ratemaking process, which results in the recording of regulatory assets and
liabilities based on the probability of future cash flows. Regulatory assets
generally represent incurred or accrued costs that have been deferred
because future recovery from customers is probable. Regulatory liabilities
generally represent amounts that are expected to be refunded to customers
in future rates or amounts collected in current rates for future costs. In other
businesses or industries, regulatory assets and regulatory liabilities would
generally be charged to net income or other comprehensive income.

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

As of Dec. 31, 2019 and 2018, Xcel Energy recorded regulatory assets of
$3.4 billion and $3.8 billion, respectively, and regulatory liabilities of $5.5 billion
and $5.6 billion, respectively. Each subsidiary is subject to regulation that
varies from jurisdiction to jurisdiction. If future recovery of costs in any such
jurisdiction is no longer probable, Xcel Energy would be required to charge
these assets to current net income or other comprehensive income. 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. The tax accrual estimates are trued-up to the actual
amounts claimed on the tax returns and further adjusted after examinations
by taxing authorities, as needed.

In accordance with the interim period reporting guidance, income tax expense
for the first three quarters in a year is based on the forecasted annual ETR.
The forecasted ETR reflects a number of estimates, including forecasted
annual income, permanent tax adjustments and tax credits.

Valuation allowances are applied to deferred tax assets if it is more likely than
not that at least a portion may not be realized based on an evaluation of
expected future taxable income. Accounting for income taxes also requires
that only tax benefits that meet the more likely than not recognition threshold
can be recognized or continue to be recognized. We may adjust our
unrecognized tax benefits and interest accruals as disputes with the IRS and
state tax authorities are resolved, and as new developments occur. These
adjustments may increase or decrease earnings.

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

Employee Benefits

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

At Dec. 31, 2019, Xcel Energy set the rate of return on assets used to measure
pension costs at 6.87%, which is consistent with the rate set in 2018. The rate
of return used to measure postretirement health care costs is 4.50% at Dec.
31, 2019, which represents a 80 basis point decrease from 2018. 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
3.49% and postretirement health care obligations at 3.47% at Dec. 31, 2019.
This represents a 82 basis point and 85 basis point decrease, respectively,
from 2018. 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 2019 pension costs:

(Millions of Dollars)

Rate of return

Discount rate (a)

Pension Costs

+1%

-1%

(16) $

(5)

(a)

These costs include the effects of regulation.

Mortality rates are developed from actual and projected plan experience for
pension plan and postretirement benefits. Xcel Energy’s actuary conducts an
experience study periodically as part of the process 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, 2019, the initial medical trend cost claim assumptions for Pre-65
was 6.0% and Post-65 was 5.1%. The ultimate trend assumption remained
at 4.5% for both Pre-65 and Post-65 claims costs. Xcel Energy bases its
medical trend assumption on the long-term cost inflation expected in the health
care market, considering the levels projected and recommended by industry
experts, as well as recent actual medical cost experienced by Xcel Energy’s
retiree medical plan.

A 1% change in the assumed health care cost trend rate would have the
following effects on Xcel Energy:

Accumulated Postretirement
Benefit Obligation

Service and Interest
Components

(Millions of Dollars)

+1%

-1%

+1%

-1%

Health care cost trend

$51

$(43)

$(2)

Funding requirements in 2020 were $150 million and are expected to decline
in the following years. Investment returns exceeded assumed levels in 2017
and 2019 and were below assumed levels in 2018.

The pension cost calculation uses a market-related valuation of pension
assets. Xcel Energy uses a calculated value method to determine the market-
related value of the plan assets. The market-related value is determined by
adjusting the fair market value of assets at the beginning of the year to reflect
the investment gains and losses (the difference between the actual investment
return and the expected investment return on the market-related value) during
each of the previous five years at the rate of 20% per year. As differences
between actual and expected investment returns are incorporated into the
market-related value, amounts are recognized in pension cost over the
expected average remaining years of service for active employees
(approximately 12 years in 2019).

Xcel Energy currently projects the pension costs recognized for financial
reporting purposes will be $104 million in 2020 and $90 million in 2021, while
the actual pension costs were $115 million in 2019 and $141 million in 2018.
The expected decrease in 2020 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 2017 - 2020:

$150 million in January 2020;
$154 million in 2019;
$150 million in 2018; and
$162 million in 2017.

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

Xcel Energy contributed $15 million, $11 million and $20 million during 2019,
2018 and 2017, respectively, to the postretirement health care plans. Xcel
Energy expects to contribute approximately $10 million during 2020. Xcel
Energy recovers employee benefits costs in its utility operations consistent
with accounting guidance with the exception of the areas noted below.

•

in all

regulatory
recognizes pension expense
NSP-Minnesota
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 expense consistent with accounting guidance. 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; and
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.

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 the Company revises any
assumptions, it adjusts the carrying amount of both the ARO liability and
related long-lived asset. ARO liabilities are accreted to reflect the passage of
time using the interest method.

A significant portion of Xcel Energy’s AROs relates to the future
decommissioning of NSP-Minnesota’s nuclear
facilities. The nuclear
decommissioning obligation is funded by the external decommissioning trust
fund. Difference between regulatory funding (including depreciation expense
less returns from the external trust fund) and expense recognized is deferred
as a regulatory asset. The amounts recorded for AROs related to future nuclear
decommissioning were $2.1 billion in 2019 and $2.0 billion in 2018.

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 most recent triennial filing was approved by the MPUC in January 2019.
This approval did not result in a change to the ARO liability. In December 2019,
the MPUC ordered Xcel Energy to maintain the current accrual through 2020
to align with the approved one year stay out of the previously filed three-year
electric rate case. Xcel Energy will evaluate the scenarios and potentially
propose a new accrual starting in 2022 when it submits the next triennial filing
in December 2020.

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, which assumes prompt removal and
dismantlement. The use of the DECON method is required by the MPUC.
Decommissioning activities are expected to begin at the end of the license
date and be completed for both facilities by 2091.

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

Escalation Rates — Escalation rates represent projected cost increases due
to general inflation and increases in the cost of decommissioning activities.
NSP-Minnesota used an escalation rate of 3.4% in calculating the ARO for
nuclear decommissioning of its nuclear facilities, based on the 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 4% 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.

The Company 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, 2019.

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

Derivatives, Risk Management and Market Risk

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

Xcel Energy is also 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 certain credit
and non-performance risk.

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

Commodity Price Risk — We are exposed to commodity price risk in their
electric and natural gas operations. Commodity price risk is managed by
entering into long- and short-term physical purchase and sales contracts for
electric capacity, energy and energy-related products and fuels used in
generation and distribution activities. Commodity price risk is also managed
through the use of financial derivative instruments. Our risk management
policy allows it to manage commodity price risk within each rate-regulated
operation per commission approved hedge plans.

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

Fair value of net commodity trading contracts as of Dec. 31, 2019:

(Millions of Dollars)

NSP-Minnesota (a)

NSP-Minnesota (b)

PSCo (b)

Futures / Forwards Maturity

Less
Than
1 Year

1 to 3
Years

4 to 5
Years

Greater
Than
5 Years

Total
Fair Value

(1) $

(4)

(3)

(22)

(2)

(31)

(10)

—

(3) $

(23) $

(31) $

(7) $

(13)

(57)

(64)

(a)

(b)

Prices actively quoted or based on actively quoted prices.

Prices based on models and other valuation methods.

Options Maturity

(Millions of Dollars)

Less
Than
1 Year

1 to 3
Years

4 to 5
Years

Greater
Than
5 Years

Total Fair
Value

NSP-Minnesota (a)

— $

(a)

Prices based on models and other valuation methods.

Changes in the fair value of commodity trading contracts before the impacts
of margin-sharing for the years ended Dec. 31:

(Millions of Dollars)

2019

2018

Fair value of commodity trading net contract assets outstanding at Jan. 1

$ 17

$ 16

Contracts realized or settled during the period

Commodity trading contract additions and changes during the period

(22)

(54)

(10)

Fair value of commodity trading net contract assets outstanding at Dec.
31

$ (59) $ 17

At Dec. 31, 2019, a 10% increase in market prices for commodity trading
contracts would increase pretax income by approximately $10 million,
whereas a 10% decrease would decrease pretax income by approximately
$10 million. At Dec. 31, 2018, a 10% increase in market prices for commodity
trading contracts would increase pretax income by approximately $16 million,
whereas a 10% decrease would decrease pretax income by approximately
$16 million.

trading operations measure

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

The VaRs for the NSP-Minnesota and PSCo commodity trading operations,
excluding both non-derivative transactions and derivative transactions
designated as normal purchase, 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)

2019

2018

Year Ended
Dec. 31

VaR Limit

Average

High

Low

0.4

4.8

3.0

6.0

0.6

0.8

5.6

0.3

0.1

In November 2018, management temporarily increased the VaR limit to
accommodate a 10-year transaction. NSP-Minnesota systematically hedging
the transaction and the consolidated VaR returned below $3 million in early
January 2019.

Nuclear Fuel Supply — NSP-Minnesota has received all enriched nuclear
material for 2019 and has contracted for approximately 51% of its 2020
enriched nuclear material requirements from sources that could be impacted
by sanctions against entities doing business with Iran. Those sanctions may
impact the supply of enriched nuclear material supplied from Russia. Long-
term, through 2030, NSP-Minnesota is scheduled to take delivery of
approximately 29% of its average enriched nuclear material requirements
from these sources. Alternate potential sources provide the flexibility to
manage NSP-Minnesota’s nuclear fuel supply. NSP-Minnesota periodically
assesses if further actions are required to assure a secure supply of enriched
nuclear material.

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

Liquidity and Capital Resources

Cash Flows

(Millions of Dollars)

2019

2018

2017

Net cash provided by operating activities

3,263

3,122

3,126

Net cash provided by operating activities increased by $141 million for 2019
as compared to 2018. Increase was primarily due to additional net income
(excluding amounts related to non-cash operating activities (e.g., depreciation
and amortization and deferred tax expenses)), partially offset by increased
refunds associated with TCJA.

Net cash provided by operating activities decreased by $4 million for 2018 as
compared to 2017. Change was primarily due to refunds associated with the
TCJA and timing of certain electric and natural gas recovery mechanisms,
partially offset by the change in net income.

(Millions of Dollars)

2019

2018

2017

Net cash used in investing activities

(4,343) $

(3,986) $

(3,296)

Net cash used in investing activities increased by $357 million for 2019 as
compared to 2018. Increase was primarily attributable to additional capital
expenditures, primarily for wind projects.

Net cash used in investing activities increased by $690 million for 2018 as
compared to 2017. Increase was largely related to higher capital expenditures
for the Rush Creek, Foxtail and Hale wind generation facilities.

(Millions of Dollars)

2019

2018

2017

Net cash provided by financing activities

1,181

928

168

Net cash provided by financing activities increased by $253 million for 2019
as compared to 2018. Increase was primarily attributable to higher proceeds
from issuances of long-term debt and common stock (primarily due to the
forward equity agreement settling in August 2019), partially offset by higher
repayments of long-term debt and dividends paid.

Net cash provided by financing activities increased by $760 million for 2018
as compared to 2017. Increase was primarily due to lower repayments of
long-term debt, proceeds from the issuances of common stock and additional
debt financings, partially offset by lower short-term debt proceeds as
compared to 2017.

A 100 basis point change in the benchmark rate on Xcel Energy’s variable
rate debt would impact annual pretax interest expense by approximately
$6 million in 2019 and $10 million in 2018.

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. The Company maintains credit policies intended to
minimize overall credit risk and actively monitor these policies to reflect
changes and scope of operations.

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. At
Dec. 31, 2018, a 10% increase in commodity prices would have resulted in
an increase in credit exposure of $14 million, while a decrease in prices of
10% would have resulted in an increase in credit exposure of $3 million.

Xcel Energy conducts credit reviews for all counterparties and employs credit
risk controls, such as letters of credit, parental guarantees, master netting
agreements and termination provisions. Credit exposure is monitored, and
when necessary, the activity with a specific counterparty is limited until credit
enhancement is provided. Distress in the financial markets could increase our
credit risk.

Fair Value Measurements

Xcel Energy uses derivative contracts such as futures, forwards, interest rate
swaps, options and FTRs to manage commodity price and interest rate risk.
Derivative contracts, with the exception of those designated as normal
purchase-normal sale contracts, are reported at fair value. The Company’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, 2019.

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, 2019.

See Notes 10 and 11 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, 2019:

(Millions of Dollars)

Total

Less than 1 Year

1 to 3 Years

3 to 5 Years

After 5 Years

Long-term debt, principal and interest payments

$ 31,433

1,422

2,702

2,514

24,795

Payments Due by Period

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

271

2,116

5,831

680

442

595

262

1,302

442

595

520

1,940

—

469

1,178

—

207

865

1,411

468

—

$ 41,368

4,101

5,277

4,244

27,746

(a)

(b)

Included in operating lease obligations are $236 million, $463 million, $422 million and $750 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 — Current estimated base capital expenditures:

(Millions of Dollars)

By Subsidiary

NSP-Minnesota

PSCo

SPS

NSP-Wisconsin

Other (a)

2020

2021

2022

2023

2024

2020 - 2024 Total

Capital Forecast

2,025

1,580

1,670

1,800

1,845

1,415

1,025

250

(85)

1,445

1,720

1,565

1,530

530

320

(65)

700

345

750

350

800

425

8,920

7,675

3,805

1,690

(120)

21,970

Total capital expenditures

4,630

3,810

4,445

4,475

4,610

(a) Other category includes intercompany transfers for safe harbor wind turbines. The $650M non-regulated acquisition of MEC in 2020 is not included above.

(Millions of Dollars)

By Function

Renewables

Electric generation

Electric transmission

Electric distribution

Natural gas

Other

Total capital expenditures

2020

2021

2022

2023

2024

2020 - 2024 Total

Capital Forecast

1,760

480

625

885

520

360
4,630

315

595

835

1,140

450

475
3,810

— $

580

1,295

1,415

600

555
4,445

780

1,270

1,470

560

395
4,475

1,000

1,260

1,350

640

360
4,610

2,075

3,435

5,285

6,260

2,770

2,145
21,970

Xcel Energy’s capital expenditure program is subject to continuous review and modification. Actual capital expenditures may vary from estimates due to changes
in electric and natural gas projected load growth, regulatory decisions, legislative initiatives, reserve margin requirements, availability of purchased power,
alternative plans for meeting long-term energy needs, compliance with environmental requirements, RPS and mergers, acquisition and divestiture opportunities.

The Company 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.

Capital Sources

Short-Term Funding Sources — Xcel Energy uses a number of sources to
fulfill short-term funding needs, including operating cash flow, notes payable,
commercial paper and bank lines of credit. The amount and timing of short-
term funding needs depend on financing needs for construction expenditures,
working capital and dividend payments.

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

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

•
•
•
•
•

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

In addition, Xcel Energy Inc. borrowed $500 million under a 364-day term loan
agreement that expires Dec. 1, 2020. Xcel Energy has an option to request
an extension through Nov. 30, 2021.

Xcel Energy’s outstanding short-term debt:

(Amounts in Millions, Except Interest Rates)

Three Months Ended
Dec. 31, 2019

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

3,600

595

663

945

2.40%

2.34

(Amounts in Millions, Except
Interest Rates)

Year Ended
Dec. 31, 2019

Year Ended
Dec. 31, 2018

Year Ended
Dec. 31, 2017

Borrowing limit

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

595

1,115

1,780

2.72%

2.34

1,038

788

1,349

2.34%

2.97

814

644

1,247

1.35%

1.90

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 termination date for an additional one-year period. All extension
requests are subject to majority bank group approval.

Financing Capital Expenditures through 2024 — Xcel Energy issues debt
and equity securities to refinance retiring maturities, reduce short-term debt,
fund capital programs, infuse equity in subsidiaries, fund asset acquisitions
and for other general corporate purposes.

Current estimated financing plans for 2020 - 2024:

(Millions of Dollars)

Funding Capital Expenditures

Cash from operations (a)
New debt (b)

Equity through the DRIP and benefit program

Equity through the at-the-market program

Equity through forward equity agreements (c)

Base capital expenditures 2020 - 2024

Maturing Debt

13,905

6,665

400

250

750

21,970

3,245

(a) Net of dividends and pension funding.
(b) Reflects a combination of short and long-term debt; net of refinancing.
(c) Equity forward issued in 2019, but has not yet settled; settlement expected by Dec. 31,
2020

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 2020, Xcel Energy announced a
quarterly dividend of $0.43 per share, which represents an increase of 6.2%.

Xcel Energy’s dividend policy balances the following:

•
•
•
•

Projected cash generation;
Projected capital investment;
A reasonable rate of return on shareholder investment; and
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 system to declare dividends. Specifically, under the Federal Power
Act, a public utility may not pay dividends from any funds properly included
in a capital account. The utility subsidiaries’ dividends may be limited directly
or indirectly by state regulatory commissions or bond indenture covenants.

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

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

Funded status and pension assumptions:

(Millions of Dollars)

Fair value of pension assets

Projected pension obligation (a)

Funded status

Dec. 31, 2019

Dec. 31, 2018

3,184

3,701

(517) $

2,742

3,477

(735)

(a)

Excludes non-qualified plan of $39 million and $33 million at Dec. 31, 2019 and 2018,
respectively.

Pension Assumptions

Discount rate

Expected long-term rate of return

2019

2018

3.49%

6.87

4.31%

6.87

As of Feb. 18, 2020, Xcel Energy Inc. and its utility subsidiaries had the
following committed credit facilities available to meet liquidity needs:

(Millions of Dollars)

Facility

Drawn (a)

Available

Cash

Liquidity

Xcel Energy Inc.

1,250

759

$ — $

PSCo

NSP-Minnesota

SPS

NSP-Wisconsin

Total

700

500

150

123

491

651

490

377

—

491

652

491

378

3,100

1,003

2,097

2,100

(a)

Includes outstanding commercial paper, term loan borrowings 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, 2019 and 2018, the Company had approximately 525 million
shares and 514 million shares of common stock outstanding, respectively.

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

Planned Financing Activity — Xcel Energy’s 2020 financing plans reflect
the following:

•

Xcel Energy Inc. — approximately $700 million of senior unsecured
bonds and approximately $75 to $80 million of equity through the
DRIP and benefit programs;

NSP-Minnesota — approximately $550 million of first mortgage
bonds;

NSP-Wisconsin — approximately $100 million of first mortgage bonds

PSCo — approximately $750 million of first mortgage bonds; and

SPS — approximately $300 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 common stock. In August 2019, we
settled the forward equity agreements by physically delivering 9.4 million
shares of common equity for cash proceeds of $453 million.

In November 2019, Xcel Energy Inc. entered into forward equity agreements
for a $743 million public offering of 11.8 million shares of common stock.

Other Equity — Xcel Energy also plans to issue approximately $75 to $80
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.

Earnings Guidance

2020 GAAP and ongoing earnings guidance is a range of $2.73 to $2.83 per
share.(a)

Key assumptions:

•

Constructive outcomes in all rate case and regulatory proceedings.

Normal weather patterns.

• Weather-normalized retail electric sales are projected to increase

~1%, including impact of leap year.

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

increase ~1%, including impact of leap year.

•

(a)

Capital rider revenue is projected to increase $45 million to $55 million
(net of PTCs). PTCs are credited to customers, through capital riders
and reductions to electric margin.

O&M expenses are projected to increase approximately 1% to 2%.

Depreciation expense is projected to increase approximately $160
million to $170 million.

Property taxes are projected to increase approximately $35 million to
$45 million.
Interest expense (net of AFUDC — debt) is projected to increase $50
million to $60 million.
AFUDC — equity is projected to increase approximately $10 million to
$20 million.

The ETR is projected to be approximately 0%. The ETR reflects
benefits of PTCs which are credited to customers through electric
margin and will not impact 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.

ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK

See Item 7, incorporated by reference.

ITEM 8 — FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

Management Report on Internal Control Over Financial Reporting

The management of Xcel Energy Inc. is responsible for establishing and maintaining adequate internal control over financial reporting. Xcel Energy Inc.’s
internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s management and board of directors regarding the preparation
and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide
only reasonable assurance with respect to financial statement preparation and presentation.

Xcel Energy Inc. management assessed the effectiveness of Xcel Energy Inc.’s internal control over financial reporting as of Dec. 31, 2019. 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, 2019, 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, President, Chief Executive Officer and Director

Feb. 21, 2020

/s/ ROBERT C. FRENZEL
Robert C. Frenzel
Executive Vice President, Chief Financial Officer

Feb. 21, 2020

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, 2019 and 2018,
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, 2019, 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, 2019, 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, 2019
and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, 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, 2019, 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 accounting principles generally accepted in the United States of America. A
company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect
on the financial statements.

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

Critical Audit Matter

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

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

Critical Audit Matter Description

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

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

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

How the Critical Audit Matter Was Addressed in the Audit

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

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

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

• We read relevant regulatory orders issued by the Commissions for the Company, regulatory statutes, interpretations, procedural memorandums, filings
made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on
precedence 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 21, 2020

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

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

Operating revenues

Electric

Natural gas

Other

Total operating revenues

Operating expenses

Electric fuel and purchased power

Cost of natural gas sold and transported

Cost of sales — other

Operating and maintenance expenses

Conservation and demand side management program expenses

Depreciation and amortization

Taxes (other than income taxes)

Total operating expenses

Operating income

Other income (expense), 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 $26, $25 and $24, respectively

Allowance for funds used during construction — debt

Total interest charges and financing costs

Income before income taxes

Income taxes

Net income

Weighted average common shares outstanding:

Basic

Diluted

Earnings per average common share:

Basic

Diluted

Year Ended Dec. 31

2019

2018

2017

9,575

9,719

1,868

11,529

1,739

11,537

3,510

918

2,338

285

1,765

569

9,425

2,104

773

(37)

736

1,500

128

3,854

843

2,352

290

1,642

556

9,572

1,965

(14)

108

700

(48)

652

1,442

181

1,372

1,261

519

520

511

2.64

2.47

9,676

1,650

11,404

3,757

823

2,270

273

1,479

545

9,181

2,223

(10)

663

(35)

628

1,690

542

1,148

509

2.26

2.25

See Notes to Consolidated Financial Statements

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

Net income

Other comprehensive (loss) income

Defined pension and other postretirement benefits:

Net pension and retiree medical loss arising during the period, net of tax of $0, $(2) and $(2), respectively

Reclassification of loss to net income, net of tax of $1, $3 and $5, respectively

Derivative instruments:

Net fair value decrease, net of tax of $(8), $(2) and $0, respectively

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

Total other comprehensive (loss) income

Total comprehensive income

See Notes to Consolidated Financial Statements

Year Ended Dec. 31

2019

2018

2017

1,372

1,261

1,148

—

(23)

(17)

(6)

(5)

(3)

—

1,355

1,262

1,155

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

Utility capital/construction expenditures
Purchases 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 issuance 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, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period

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 and other asset transfers to property, plant and equipment
Operating lease right-of-use assets
Allowance for equity funds used during construction
Issuance of common stock for reinvested dividends and equity awards

See Notes to Consolidated Financial Statements

2019

Year Ended Dec. 31
2018

2017

1,372

1,261

1,148

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

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

101
147
248

(698) $
53

421
88
1,843
77
63

64
83
147

(633) $
27

388
129
—
108
67

1,495
114
640
(75)
(30)
41
39
57
2

(60)
(34)
(3)
9
43
(16)
(38)
(133)
(73)
3,126

(3,244)
(1,697)
1,669
(24)
(3,296)

422
1,518
(1,030)
—
(721)
(21)
168

(2)
85
83

(616)
44

464
63
—
75
31

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
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; 524,539,000 and 514,036,787 shares

outstanding at Dec. 31, 2019 and 2018, respectively

Additional paid in capital
Retained earnings
Accumulated other comprehensive loss
Total common stockholders’ equity

Total liabilities and equity

See Notes to Consolidated Financial Statements

Dec. 31

2019

2018

248
837
713
544
488
55
43
185
3,113

147
860
755
548
464
87
79
154
3,094

39,483

36,944

2,731
2,935
22
1,672
492
7,852
50,448

702
595
1,294
407
466
192
212
38
662
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

2,317
3,326
34
—
272
5,949
45,987

406
1,038
1,237
436
450
174
195
61
463
4,460

4,165
54
5,187
2,568
129
199
994
—
206
13,502

15,803

1,285

6,168
4,893
(124)
12,222
45,987

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
(amounts in millions, shares in thousands)

Common Stock Issued

Par Value

Additional
Paid In
Capital

Retained
Earnings

Accumulated
Other
Comprehensive
Loss

Total Common
Stockholders’
Equity

Balance at Dec. 31, 2016

507,223

1,268

5,881

3,982

(110) $

11,021

Net income

Other comprehensive loss

Dividends declared on common stock ($1.44 per share)

Issuances of common stock

Repurchases of common stock

Share-based compensation

Adoption of ASU No. 2018-02

Balance at Dec. 31, 2017

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 income

Dividends declared on common stock ($1.62 per share)

Issuances of common stock

Repurchases of common stock

Share-based compensation

Balance at Dec. 31, 2019

611

(71)

—

(3)

1,148

(736)

(3)

(22)

1,148

(736)

(3)

—

507,763

1,269

5,898

4,413

(125) $

11,455

6,296

(22)

—

254

(1)

1,261

(780)

(1)

1,261

(780)

270

(1)

514,037

1,285

6,168

4,893

(124) $

12,222

10,508

(6)

—

468

—

1,372

(846)

(6)

(17)

1,372

(17)

(846)

494

—

524,539

1,311

6,656

5,413

(141) $

13,239

See Notes to Consolidated Financial Statements

XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

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

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

Xcel Energy Inc.’s nonregulated subsidiaries include Eloigne, Capital Services
and the newly formed MEC Holdings LLC. 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. Xcel Energy Inc. owns the following additional direct subsidiaries,
some of which are intermediate holding companies with additional
subsidiaries: Xcel Energy Wholesale Group Inc., Xcel Energy Markets
Holdings Inc., Xcel Energy Ventures Inc., Xcel Energy Retail Holdings Inc.,
Xcel Energy Communications Group, Inc., Xcel Energy International Inc., Xcel
Energy Transmission Holding Company, LLC, Nicollet Holdings Company,
LLC, Nicollet Project Holdings LLC, Xcel Energy Venture Holdings Inc. and
Xcel Energy Services Inc. Xcel Energy Inc. and its subsidiaries collectively
are referred to as Xcel Energy.

Xcel Energy’s consolidated financial statements include its wholly-owned
subsidiaries and VIEs for which it is the primary beneficiary. All intercompany
transactions and balances are eliminated, unless a different treatment is
appropriate for rate regulated transactions.

Xcel Energy uses the equity method of accounting for its investment in WYCO.
Xcel Energy’s equity earnings in WYCO are included on the consolidated
statements of income as equity earnings of unconsolidated subsidiaries.

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

Xcel Energy’s consolidated financial statements are presented in accordance
with GAAP. All of the utility subsidiaries’ underlying accounting records also
conform to the FERC uniform system of accounts. Certain amounts in the
2018 and 2017 consolidated financial statements or notes have been
reclassified to conform to the 2019 presentation 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, 2019 up to the
date of issuance of these consolidated financial statements. These statements
contain all necessary adjustments and disclosures resulting from that
evaluation.

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

Estimates are used on items such as plant depreciable lives or potential
disallowances, AROs, certain regulatory assets and liabilities, tax provisions,
uncollectible amounts, environmental costs, unbilled revenues, jurisdictional
fuel and energy cost allocations and actuarially determined benefit costs.
Recorded estimates are revised when better information becomes available
or actual amounts can be determined. Revisions can affect operating results.

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

•

Certain costs, which would otherwise be charged to expense or other
comprehensive income, are deferred as regulatory assets based on the
expected ability to recover the costs in future rates; and
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
will be refundable to utility customers over the remaining life of the related
assets. A tax rate increase would result in the establishment of a similar
regulatory asset.

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

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

Xcel Energy reports interest and penalties related to income taxes within the
other income and interest charges in the consolidated statements of income.

Xcel Energy Inc. and its subsidiaries file consolidated federal income tax
returns as well as consolidated or separate state income tax returns. Federal
income taxes paid by Xcel Energy Inc. are allocated to its subsidiaries based
on separate company computations. A similar allocation is made for state
income taxes paid by Xcel Energy Inc. in connection with consolidated state
filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct
subsidiaries.

See Note 7 for further information.

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

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

Xcel Energy records depreciation expense using the straight-line method over
the plant’s useful life. Actuarial life studies are performed and submitted to the
state and federal commissions for review. Upon acceptance by the various
commissions, the resulting lives and net salvage rates are used to calculate
depreciation. Depreciation expense, expressed as a percentage of average
depreciable property, was approximately 3.3% for 2019, 3.1% for 2018 and
2017.

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. The utility subsidiaries also recover through rates certain
future plant removal costs in addition to AROs.

The accumulated removal costs for these obligations are reflected in the
consolidated balance sheets as a regulatory liability.

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.

For ratemaking purposes, 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
for nuclear
decommissioning as an ARO.

reporting purposes, NSP-Minnesota accounts

Restricted funds for the payment of future decommissioning expenditures for
NSP-Minnesota’s nuclear facilities are included in nuclear decommissioning
fund and other assets on the consolidated balance sheets.

See Note 10 and 12 for further information.

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

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

See Note 11 for further information.

Environmental Costs — Environmental costs are recorded when it is
probable Xcel Energy is liable for remediation costs and the liability can be
reasonably estimated. Costs are deferred as a regulatory asset if it is probable
that the costs will be recovered from customers in future rates. Otherwise, the
costs are expensed. If an environmental expense is related to facilities
currently in use, such as emission-control equipment, the cost is capitalized
and depreciated over the life of the plant.

Estimated remediation costs are regularly adjusted as estimates are revised
and remediation proceeds. If other participating potentially responsible parties
exist and acknowledge their potential involvement with a site, costs are
estimated and recorded only for Xcel Energy’s expected share of the cost.

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

See Note 12 for further information.

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

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

See Note 6 for further information.

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

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

At both Dec. 31, 2019 and 2018, the allowance for bad debts was $55 million.

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

(Millions of Dollars)
Inventories

Materials and supplies

Fuel

Natural gas

Total inventories

Dec. 31, 2019

Dec. 31, 2018

270

191

544

271

170

107

548

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

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

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

Gains or losses on commodity trading transactions are recorded as a
component of electric operating revenues; hedging transactions for vehicle
fuel costs are recorded as a component of capital projects and O&M costs;
and interest rate hedging transactions are recorded as a component of interest
expense.

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

See Note 10 for further information.

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

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

See Note 10 for further information.

Other Utility Items

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

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

See Notes 10 and 11 for further information.

See Note 6 for further information.

Derivative Instruments — Xcel Energy uses derivative instruments in
connection with its interest rate, utility commodity price, vehicle fuel 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.

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

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

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

RECs — Cost of RECs that are utilized for compliance is recorded as electric
fuel and purchased power expense. In certain jurisdictions, Xcel Energy
reduces recoverable fuel costs for the cost of RECs and records that cost as
a regulatory asset when the amount is recoverable in future rates.

Sales of RECs are recorded in electric revenues on a gross basis. The cost
of these RECs and amounts credited to customers under margin-sharing
mechanisms are recorded in electric fuel and purchased power expense.

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

2. Accounting Pronouncements

Recently Issued

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. ASC Topic 326 is
effective for interim and annual periods beginning on or after Dec. 15, 2019
and will be applied using a modified-retrospective approach, with a cumulative-
effect adjustment to retained earnings as of Jan. 1, 2020.

Xcel Energy expects the impact of adoption of the new standard to include
first-time recognition of expected credit losses (i.e., bad debt expense) on
unbilled revenues, with the initial allowance established at Jan. 1, 2020
charged to retained earnings. Recognition of this allowance and other impacts
of adoption are expected to be immaterial to the consolidated financial
statements.

Recently Adopted

Leases — In 2016, the FASB issued Leases, Topic 842 (ASC Topic 842),
which provides new accounting and disclosure guidance for leasing activities,
most significantly requiring that operating leases be recognized on the balance
sheet. Xcel Energy adopted the guidance on Jan. 1, 2019 utilizing the package
of transition practical expedients provided by the new standard, including
carrying forward prior conclusions on whether agreements existing before the
adoption date contain leases and whether existing leases are operating or
finance leases; ASC Topic 842 refers to capital leases as finance leases.

Specifically, for land easement contracts, Xcel Energy has elected the practical
expedient provided by ASU No. 2018-01 Leases: Land Easement Practical
Expedient for Transition to Topic 842, and as a result, only those easement
contracts entered on or after Jan. 1, 2019 will be evaluated to determine if
lease treatment is appropriate.

Xcel Energy also utilized the transition practical expedient offered by ASU No.
2018-11 Leases: Targeted Improvements to implement the standard on a
prospective basis. As a result, reporting periods in the consolidated financial
statements beginning Jan. 1, 2019 reflect the implementation of ASC Topic
842, while prior periods continue to be reported in accordance with Leases,
Topic 840 (ASC Topic 840). Other than first-time recognition of operating
leases on its consolidated balance sheet, the implementation of ASC Topic
842 did not have a significant impact on Xcel Energy’s consolidated financial
statements. Adoption resulted in recognition of approximately $1.7 billion of
operating lease ROU assets and current/noncurrent operating lease liabilities.

See Note 12 for leasing disclosures.

3. Property, Plant and Equipment

Major classes of property, plant and equipment

(Millions of Dollars)

Property, plant and equipment

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, 2019

Dec. 31, 2018

44,355

41,472

6,560

2,341

259

2,329

55,844

(16,735)

2,909

(2,535)

6,210

2,154

322

2,091

52,249

(15,659)

2,771

(2,417)

36,944

Property, plant and equipment, net

39,483

(a)

In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in
approximately 2022 and 2025, respectively. PSCo also expects Craig Unit 1 to be retired
early in 2025. Amounts are presented net of accumulated depreciation.

Joint Ownership of Generation, Transmission and Gas Facilities

The utility subsidiaries’ jointly owned assets as of Dec. 31, 2019:

Plant in
Service

Accumulated
Depreciation

CWIP

Percent
Owned

(Millions of Dollars)

NSP-Minnesota

Electric generation:

Sherco Unit 3

Sherco common facilities

Sherco substation

Electric transmission:

CapX2020

Grand Meadow

603

145

972

426

103

Total NSP-Minnesota

1,736

627

(Millions of Dollars)

NSP-Wisconsin
Electric transmission:

Plant in
Service

Accumulated
Depreciation

CWIP

La Crosse, WI to Madison, WI
CapX2020

Total NSP-Wisconsin

187
169
356

7
19
26

Plant in
Service

Accumulated
Depreciation

59%

Percent
Owned

37%
80

Percent
Owned

76%
37
53
10
7
67
82

Various

60
50

—

—
—
—

—
—
—
—
—
1
—

—
—
2

CWIP

81
71
22
41
22
149
3

7
1
459

(Millions of Dollars)

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:

152
149
41
81
39
887
29

174

Rifle, CO to Avon, CO
Gas transmission compressor

Total PSCo

22
9
1,583

Each company’s share of operating expenses and construction expenditures
is included in the applicable utility accounts. Respective owners are
responsible for providing their own financing.

4. Regulatory Assets and Liabilities

Regulatory assets and liabilities are created for amounts that regulators may allow to be collected or may require to be paid back to customers in future electric
and natural gas rates. Xcel Energy would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income
if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP.

Components of regulatory assets:

(Millions of Dollars)

Regulatory Assets
Pension and retiree medical obligations
Recoverable deferred taxes on AFUDC recorded in plant
Net AROs (a)
Excess deferred taxes — TCJA
Depreciation differences
Environmental remediation costs
Benson biomass PPA termination and asset purchase
Contract valuation adjustments (b)
Purchased power contract costs
Laurentian biomass PPA termination
PI extended power uprate
Losses on reacquired debt
State commission adjustments
Property tax
Conservation programs (c)
Nuclear refueling outage costs
Sales true-up and revenue decoupling
Renewable resources and environmental initiatives
Gas pipeline inspection and remediation costs
Deferred purchased natural gas and electric energy costs
Other

Total regulatory assets

See Note(s)

Remaining
Amortization Period

Dec. 31, 2019

Dec. 31, 2018

Current

Noncurrent

Current

Noncurrent

1, 12
7

1, 12

1, 10

Various
Plant lives
Plant lives
Various
One to twelve years
Various
Ten years
Term of related contract
Term of related contract
Five years
Sixteen years
Term of related debt
Plant lives
Various

1 One to two years
1 One to two years
One to two years
One to two years
One to two years
One to three years
Various

85
—
—
39
15
36
9
20
5
19
3
4
1
2
27
43
54
72
26
6
22
488

1,328
271
269
239
140
131
73
62
61
54
53
41
31
30
26
17
16
10
8
6
69
2,935

87
—
—
—
18
17
10
17
4
18
3
4
1
14
42
37
38
39
28
57
30
464

1,500
264
452
296
107
155
86
77
63
73
56
44
29
10
28
14
7
9
3
13
40
3,326

(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 (c)
Deferred electric, natural gas and steam production costs
Contract valuation adjustments (d)
Conservation programs (e)
DOE settlement
Other

Total regulatory liabilities (f)

See Note(s)

Remaining
Amortization Period

7
1, 12

1, 10
1

Various
Plant lives
Various
Various
Various
Less than one year
Less than one year
Less than one year
Less than one year
Various

Dec. 31, 2019

Dec. 31, 2018

Current

Noncurrent

Current

Noncurrent

75
—
—
—
—
138
19
37
37
101
407

3,523
1,217
196
45
38
—
—
—
—
58
5,077

157
—
—
9
—
102
26
36
19
87
436

3,715
1,175
137
54
40
—
—
—
—
66
5,187

(a)

(b)

(c)

(d)

(e)

(f)

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 impact of lower federal tax rate due to the TCJA.

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

Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

Revenue subject to refund of $28 million and $29 million for 2019 and 2018, respectively, is included in other current liabilities.

At Dec. 31, 2019 and 2018, Xcel Energy’s regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical
obligations, net AROs and Laurentian biomass PPA termination costs/obligations. In addition, regulatory assets included $544 million and $512 million at Dec.
31, 2019 and 2018, respectively, of past expenditures not earning a return. Amounts primarily related to funded pension obligations, sales true-up and revenue
decoupling, purchased natural gas and electric energy costs, various renewable resources and certain environmental initiatives.

5. Borrowings and Other Financing Instruments

Short-Term Borrowings

Short-Term Debt — Xcel Energy meets its short-term liquidity requirements
primarily through the issuance of commercial paper and borrowings under
their credit facilities and term loan agreements.

Commercial paper and term loan borrowings outstanding:

(Millions of Dollars, Except
Interest Rates)

Three Months
Ended Dec. 31,
2019

Year Ended Dec. 31

2019

2018

2017

Borrowing limit

3,600

$ 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

595

663

945

595

1,115

1,780

1,038

788

1,349

814

644

1,247

2.40%

2.72%

2.34%

1.35%

2.34

2.97

1.90

Term Loan Agreement — In December 2019, Xcel Energy Inc. entered into
a $500 million 364-Day Term Loan Agreement to pay down borrowings and
terminate the expiring $500 million term loan made to Xcel Energy under the
364-Day Term Loan Agreement dated as of Dec. 4, 2018. The loan is
unsecured and matures Dec. 1, 2020. Xcel Energy has an option to request
an extension through Nov. 30, 2021. Term loan includes one financial
covenant, requiring Xcel Energy’s consolidated funded debt to total
capitalization ratio to be less than or equal to 65 percent. Interest is at a rate
equal to either the Eurodollar rate, plus 50.0 basis points, or an alternate base
rate.

Term loan borrowings as of Dec. 31, 2019:

(Millions of Dollars)

Limit

Amount Used

Available

Xcel Energy Inc.

500

—

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.

As of Dec. 31, 2019, outstanding letters of credit under the Bilateral Credit
Agreement were as follows:

(Millions of Dollars)

Limit

Amount Used

Available

NSP-Minnesota

Letters of Credit — Xcel Energy uses letters of credit, typically with terms of
one year, to provide financial guarantees for certain operating obligations. As
of Dec. 31, 2019 and 2018, there were $20 million and $49 million of letters
of credit outstanding under the credit facilities. Amounts approximate their fair
value.

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

Amended 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 was increased to $3.1 billion, with the
following changes:

•

Maturity extended from June 2021 to June 2024;

Borrowing limit for Xcel Energy was increased from $1.0 billion to $1.25
billion;

Borrowing limit for SPS was increased from $400 million to $500 million;
and

Added swingline subfacility for Xcel Energy up to $75 million

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)

2019

2018

Xcel Energy Inc. (c)
NSP-Wisconsin
NSP-Minnesota
SPS
PSCo

58%
48
48
46
44

58% $
48
48
46
46

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. will
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, 2019, 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, 2019:

(Millions of Dollars)

Credit Facility (a)

Drawn (b)

Available

Xcel Energy Inc.
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin

Total

1,250
700
500
500
150
3,100

— $
9
2
40
65
116

1,250
691
498
460
85
2,984

(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 subsidiaries had no direct advances on facilities
outstanding as of Dec. 31, 2019 and 2018.

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.

NSP-Wisconsin

Interest
Rate

Maturity Date

2019

2018

6.00%

Nov 1, 2021

3.30

6.38

3.70

3.75

4.20

June 15, 2024

Sept. 1, 2038

Oct. 1, 2042

Dec. 1, 2047

Sept. 1, 2048

100

200

100

200

(3)

(8)

100

200

100

200

(3)

(9)

808

807

Financing Instrument

City of La Crosse resource
recovery bond

First mortgage bonds

First mortgage bonds (a)

Unamortized discount

Unamortized debt issuance cost

Total long-term debt

(a)

2018 financing.

Financing Instrument

PSCo

Interest
Rate

Maturity Date

2019

2018

First mortgage bonds (d)

5.13%

June 1, 2019

— $

3.20

2.25

2.50

2.90

3.70

6.25

6.50

4.75

3.60

3.95

4.30

3.55

3.80

4.10

4.05

3.20

Nov. 15, 2020

Sept. 15, 2022

March 15, 2023

May 15, 2025

June 15, 2028

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

11.20 -
14.30

2025 - 2060

First mortgage bonds

First mortgage bonds (b)

First mortgage bonds

First mortgage bonds (b)

First mortgage bonds (a)

Capital lease obligations (c)

Unamortized discount

Unamortized debt issuance cost

Current maturities

Total long-term debt

400

300

250

350

300

250

500

250

300

250

400

350

400

550

—

(24)

(41)

(400)

400

300

250

350

300

250

500

250

300

250

400

350

—

145

(14)

(33)

(406)

4,985

4,592

(a)

(b)

(c)

(d)

2019 financing.

2018 financing.
PSCo adopted ASC 842 on Jan. 1, 2019, which refers to capital leases as finance leases.
Under ASC 842, the present value of future finance lease payments is included in other
current liabilities and other noncurrent liabilities rather than debt.

Bond was redeemed on March 29, 2019.

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

2019

2018

Unsecured senior notes (d)

4.70%

May 15, 2020

— $

2.40

2.60

3.30

3.35

4.00

2.60

6.50

4.80

3.50

March 15, 2021

March 15, 2022

June 1, 2025

Dec. 1, 2026

June 15, 2028

Dec. 1, 2029

July 1, 2036

Sept. 15, 2041

Dec. 1, 2049

Unsecured senior notes

Unsecured senior notes (a)

Unsecured senior notes (b)

Unsecured senior notes (a)

Unsecured senior notes

Unsecured senior notes (a)

Elimination of PSCo capital
lease obligation with affiliates (c)

Unamortized discount

Unamortized debt issuance cost

Current maturities (capital lease
obligation) (c)

Total long-term debt

400

300

250

350

500

130

500

300

250

500

—

(5)

(28)

—

550

400

300

250

350

500

—

500

—

300

250

—

(60)

(5)

(21)

3,947

3,316

(a)

(b)

(c)

(d)

2019 financing.

2018 financing.
Xcel Energy adopted ASC 842 on Jan. 1, 2019, which refers to capital leases as finance
leases. Under ASC 842, the present value of future finance lease payments is included in
other current liabilities and other noncurrent liabilities rather than debt.

Note was redeemed on Dec. 23, 2019.

NSP-Minnesota

Financing Instrument

Interest
Rate

Maturity Date

2019

2018

First mortgage bonds

First mortgage bonds (a)

Unamortized discount

Unamortized debt issuance cost

Current maturities

Total long-term debt

(a)

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

2.90

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

300

400

250

150

250

400

350

300

250

500

300

350

600

(31)

(48)

(300)

300

400

250

150

250

400

350

300

250

500

300

350

600

—

(21)

(42)

—

5,221

4,937

Financing Instrument

SPS

Interest
Rate

Maturity Date

2019

2018

3.30%

June 15, 2024

3.30

6.00

4.50

3.40

3.70

4.40

3.75

June 15, 2024

Oct. 1, 2033

Oct. 1, 2036

Aug. 15, 2041

Aug. 15, 2046

Aug. 15, 2047

Nov. 15, 2048

June 15, 2049

150

200

100

250

200

100

300

450

300

(7)

(23)

150

200

100

250

200

100

300

450

300

—

(4)

(20)

The forward price used to determine amounts due at settlement is calculated
based on the November 2019 public offering price for Xcel Energy’s common
stock of $62.69, increased for the overnight bank funding rate, less a spread
of 0.75% and less expected dividends on Xcel Energy’s common stock during
the period the instruments are outstanding.

Xcel Energy may settle the agreements at any time up to the maturity date of
Dec. 31, 2020. Depending on settlement timing, cash proceeds are expected
to be approximately $730 million to $740 million.

Forward equity instruments were recognized within stockholders’ equity at fair
value at execution of the agreements and will not be subsequently adjusted
until settlement.

Other Equity — Xcel Energy issued $39 million of equity annually through
the DRIP program during the years ended Dec. 31, 2019 and 2018,
respectively. Program allows stockholders to elect dividend reinvestment in
Xcel Energy common stock through a non-cash transaction. See Note 8 for
equity items related to share based compensation.

2,420

2,126

Capital Stock — Preferred stock authorized/outstanding:

First mortgage bonds

Unsecured senior notes

First mortgage bonds

First mortgage bonds (b)

First mortgage bonds (a)

Unamortized discount

Unamortized debt issuance cost

Total long-term debt

(a)

(b)

2019 financing.

2018 financing.

Other Subsidiaries

Interest
Rate

0.00% -
6.90%

Financing Instrument

Various Eloigne affordable
housing project notes

Current maturities

Total long-term debt

Maturity Date

2019

2018

2020 — 2052

(2)

(1)

Maturities of long-term debt:

(Millions of Dollars)

2020
2021

2022

2023

2024

702

421

900

650

552

Deferred Financing Costs — Deferred financing costs of approximately $148
million and $126 million, net of amortization, are presented as a deduction
from the carrying amount of long-term debt as of Dec. 31, 2019 and 2018,
respectively.

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 physically
delivering 9.4 million shares of common equity for cash proceeds of $453
million.

In November 2019, Xcel Energy Inc. entered into forward equity agreements
in connection with a completed $743 million public offering of 11.8 million
shares of Xcel Energy common stock. The initial forward agreement was for
10.3 million shares with an additional agreement for 1.5 million shares
exercised at the option of the banking counterparty.

At Dec. 31, 2019, the forward agreements could have been settled with
physical delivery of 11.8 million common shares to the banking counterparty
in exchange for cash of $739 million. The forward instruments could also have
been settled at Dec. 31, 2019 with delivery of approximately $6 million of cash
or approximately 0.1 million shares of common stock to the counterparty, if
Xcel Energy unilaterally elected net cash or net share settlement, respectively.

Preferred Stock
Authorized
(Shares)

Par Value of
Preferred Stock

Preferred Stock
Outstanding (Shares)
2019 and 2018

Xcel Energy Inc.

7,000,000

PSCo

SPS

10,000,000

100

0.01

1.00

—

Xcel Energy Inc. had the following common stock authorized/outstanding:

Common Stock
Authorized
(Shares)

Par Value of
Common Stock

Common Stock
Outstanding
(Shares) as of
Dec. 31, 2019

Common Stock
Outstanding
(Shares) as of
Dec. 31, 2018

1,000,000,000

2.50

524,539,000

514,036,787

Dividend and Other Capital-Related Restrictions — Xcel Energy depends
on its subsidiaries to pay dividends. Xcel Energy Inc.’s utility subsidiaries’
dividends are subject to the FERC’s jurisdiction, which prohibits the payment
of dividends out of capital accounts. Dividends are solely to be paid from
retained earnings. Certain covenants also require Xcel Energy Inc. to be
current on interest payments prior to dividend disbursements.

State regulatory commissions impose dividend limitations for NSP-Minnesota,
NSP-Wisconsin and SPS, which are more restrictive than those imposed by
the FERC. Requirements and actuals as of Dec. 31, 2019:

Equity to Total
Capitalization Ratio
Required Range

Equity to Total
Capitalization Ratio
Actual

Low

High

2019

47.1%

51.5

45.0

57.5%

N/A

55.0

52.3%

51.8

54.4

NSP-Minnesota

NSP-Wisconsin

SPS (a)

(a)

Excludes short-term debt.

(Amounts in
Millions)

Unrestricted Retained
Earnings

Total
Capitalization

Limit on Total
Capitalization

NSP-Minnesota

1,147

11,634

12,700

NSP-Wisconsin (a)

SPS (b)

535

1,827

5,304

N/A

Cannot pay annual dividends in excess of approximately $55 million 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.

(a)

(b)

Issuance of securities by Xcel Energy Inc. generally is not 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, 2019:

(Millions of
Dollars)

Long-Term Debt

Short-Term Debt

NSP-Minnesota

52.93% of total capitalization (a) $

1,905 (a)

NSP-Wisconsin

SPS

PSCo

— (b)

— (c)

150

600

800

(a)

(b)

(c)

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.

NSP-Wisconsin filed for additional long-term debt authorization in December 2019.

SPS filed for additional long-term debt authorization in February 2020.

6. Revenues

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

7. Income Taxes

Federal Tax Reform — In 2017, the TCJA was signed into law. The key
provisions impacting Xcel Energy, generally beginning in 2018, included:

•

Corporate federal tax rate reduction from 35% to 21%;

Normalization of resulting plant-related excess deferred taxes;

Elimination of the corporate alternative minimum tax;

Continued interest expense deductibility and discontinued bonus
depreciation for regulated public utilities;

Limitations on certain executive compensation deductions;

Limitations on certain deductions for NOLs arising after Dec. 31, 2017
(limited to 80% of taxable income);

Repeal of the section 199 manufacturing deduction; and

Reduced deductions for meals and entertainment as well as state and
local lobbying.

Reductions in deferred tax assets and liabilities due to a decrease in corporate
federal tax rates typically result in a net tax benefit. However, the impacts are
primarily recognized as regulatory liabilities refundable to utility customers as
a result of IRS requirements and past regulatory treatment.

Year Ended Dec. 31, 2019

Estimated impacts of the new tax law in December 2017 included:

(Millions of Dollars)

Major revenue types

Electric

Natural
Gas

All Other

Total

Revenue from contracts with customers:

Residential

C&I

Other

Total retail

Wholesale

Transmission

Other

Total revenue from
contracts with customers

Alternative revenue and other

2,877

1,127

4,844

130

7,851

737

507

9,144

431

567

—

1,694

—

120

1,814

Total revenues

9,575

1,868

—

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

9,339

380

988

524

—

1,512

—

100

1,612

127

Total revenues

9,719

1,739

—

3,945

5,423

140

9,508

791

523

198

11,020

517

11,537

•

$2.7 billion ($3.8 billion grossed-up for tax) of reclassifications of plant-
related excess deferred taxes to regulatory liabilities upon valuation at
the new 21% federal rate. The regulatory liabilities will be amortized
consistent with IRS normalization requirements, resulting in customer
refunds over an estimated weighted average period of approximately 30
years;

$254 million and $174 million of reclassifications (grossed-up for tax) of
excess deferred taxes for non-plant related deferred tax assets and
liabilities, respectively, to regulatory assets and liabilities; and

$23 million of total estimated income tax expense related to the tax rate
change on certain non-plant deferred taxes and all other 2017 income
statement impacts of the federal tax reform.

Xcel Energy accounted for the state tax impacts of federal tax reform based
on enacted state tax laws. Any future state tax law changes related to the
TCJA will be accounted for in the periods state laws are enacted.

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

Tax Year(s)
2009 - 2013

2014 - 2016

Expiration
June 2020

September 2020

In 2015, the IRS commenced an examination of tax years 2012 and 2013. 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
filed a protest with the IRS. As of Dec. 31, 2019, the case has been forwarded
to the Office of Appeals and 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 2018, the IRS began an audit of tax years 2014 - 2016. As of Dec. 31, 2019,
no adjustments have been proposed.

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, 2019, 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

2014

•

In 2018, Wisconsin began an audit of tax years 2014 - 2016. As of
Dec. 31, 2019, 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, 2019.

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, 2019

Dec. 31, 2018

Unrecognized tax benefit — Permanent tax positions

Unrecognized tax benefit — Temporary tax positions

Total unrecognized tax benefit

Changes in unrecognized tax benefits:

(Millions of Dollars)

Balance at Jan. 1

Additions based on tax positions related to the current year

Reductions based on tax positions related to the current year

Additions for tax positions of prior years

Reductions for tax positions of prior years

Settlements with taxing authorities

Balance at Dec. 31

(4)

(5)

(4)

—

(4)

(105)

(7)

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

No amounts were accrued for penalties related to unrecognized tax benefits
as of Dec. 31, 2019, 2018 or 2017.

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

(Millions of Dollars)

Federal tax credit carryforwards

Valuation allowances for federal credit carryforwards
State NOL carryforwards
Valuation allowances for state NOL carryforwards

State tax credit carryforwards, net of federal detriment (a)

Valuation allowances for state credit carryforwards, net of federal
benefit (b)

2019

2018

639

—
937

(19)

(66)

553

(5)
1,104

(50)

(69)

(a)

(b)

State tax credit carryforwards are net of federal detriment of $24 million as of Dec. 31,
2019 and 2018.

Valuation allowances for state tax credit carryforwards were net of federal benefit of $17
million and $18 million as of Dec. 31, 2019 and 2018, respectively.

Federal carryforward periods expire between 2023 and 2039 and state
carryforward periods expire between 2020 and 2036.

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

Effective income tax rate for years ended Dec. 31:

Federal statutory rate

2019

2018 (a)

2017 (a)

21.0%

35.0%

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

4.9

5.0

4.1

Increases (decreases) in tax from:

Wind PTCs

Plant regulatory differences (b)

Tax reform

Other, net

Effective income tax rate

(9.4)

(5.8)

(1.7)

0.5

—

(1.0)

8.5%

(5.2)

(6.2)

(1.7)

0.4

—

(0.7)

12.6%

(4.7)

(0.8)

(1.0)

(0.6)

1.4

(1.3)

32.1%

(a)

(b)

Prior periods have been reclassified to conform to current year presentation.
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:

2019

2018

2017

Other tax credits, net of NOL & tax credit allowances

$ 134

Change in unrecognized tax benefits

(Millions of Dollars)

Dec. 31, 2019

Dec. 31, 2018

(Millions of Dollars)

2019

2018

2017

Current federal tax (benefit) expense

Current state tax expense (benefit)

Current change in unrecognized tax expense (benefit)

Deferred federal tax expense
Deferred state tax expense

Deferred change in unrecognized tax expense

Deferred ITCs

Total income tax expense

(16) $

(34) $

55
83

(5)

(6)
122

(5)

(11)

(83)
460

107

(5)

128

181

542

NOL and tax credit carryforwards

(40) $

(35)

Net deferred tax liability associated with the unrecognized tax benefit amounts
and related NOLs and tax credits carryforwards were $29 million and $24
million at Dec. 31, 2019 and Dec. 31, 2018, respectively.

As the IRS Appeals and federal and state audits progress and other state
audits resume, it is reasonably possible that the amount of unrecognized tax
benefit could decrease up to approximately $28 million in the next 12 months.

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

No amounts were payable for interest related to unrecognized tax benefits as
of Dec. 31, 2019, 2018 or 2017. No interest income related to unrecognized
tax benefits was recorded in 2019 or 2018, and $3 million was recorded in
2017.

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

Changes in nonvested restricted stock:

(Millions of Dollars)

2019

2018

2017

Deferred tax expense (benefit) excluding items below

344

320

$ (2,939)

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

Tax benefit (expense) allocated to other comprehensive
income, net of adoption of ASU No. 2018-02, and other

Deferred tax expense

(206)

(102)

3,583

—

(4)

143

218

640

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

(Millions of Dollars)

Deferred tax liabilities:

2019

2018 (a)

Differences between book and tax bases of property

$ 5,474

$ 5,082

Operating lease assets

Regulatory assets

Pension expense

Other

449

598

173

—

599

178

Total deferred tax liabilities

$ 6,764

$ 5,919

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

847

449

727

(67)

128

879

—

642

(79)

124

$ 2,255

$ 1,754

$ 4,509

$ 4,165

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

8. Share-Based Compensation

Incentive Plans Including Share-Based Compensation — Xcel Energy has
two incentive plans which include share-based payment elements. Plans and
authorized equity shares for awards:

•
•

Omnibus Incentive Plan - 7.0 million shares; and
Executive Annual Incentive Award Plan - 1.2 million shares.

Restricted Stock — The Executive Annual Incentive Award Plan and
Omnibus Incentive Plan allow 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)

2019

2018

2017

Granted shares

Grant date fair value

53.46

44.68

42.00

(Shares in Thousands)

Nonvested restricted stock at Jan. 1, 2019

Granted

Forfeited

Vested

Dividend equivalents

Nonvested restricted stock at Dec. 31, 2019

Weighted Average
Grant Date Fair Value

—

(19)

44.29

53.46

—

41.60

57.09

50.15

Other Equity Awards — Xcel Energy‘s Board of Directors has granted equity
awards under the 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 0.3 million time-based equity shares subject only to service conditions
were granted annually in 2019, 2018 and 2017, respectively.

The performance conditions for a portion of the awards granted from 2017 to
2019 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)

2019

2018

2017

Granted units

Weighted average grant date
fair value

Equity awards vested:

483

500

503

49.67

47.60

41.02

(Units in Thousands)

2019

2018

2017

Vested Units

Total Fair Value

464

475

29,432

23,393

467

22,459

Changes in the nonvested portion of equity award units:

(Units in Thousands)

Units

Nonvested Units at Jan. 1, 2019

Granted

Forfeited

Vested

Dividend equivalents

Nonvested Units at Dec. 31, 2019

Weighted Average
Grant Date Fair Value

939

483

(116)

(464)

880

44.30

49.67

50.19

41.09

45.22

48.20

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)

2019

2018

2017

Granted units

Weighted average grant date
fair value

58.44

45.44

46.05

Changes in stock equivalent units:

9. Earnings Per Share

(Units in Thousands)

Units

Weighted Average
Grant Date Fair Value

Stock equivalent units at Jan. 1, 2019
Granted

Units distributed

Dividend equivalents

Stock equivalent units at Dec. 31, 2019

688
29

(11)

725

30.93

58.44

32.56

57.28

32.72

TSR Liability Awards — Xcel Energy Inc.’s Board of Directors has granted
TSR liability awards under the 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 20
other utility members. Potential payouts of the awards range from zero to
200%.

TSR liability awards granted:

(In Thousands)
Awards granted

2019

2018

2017

225

239

240

TSR liability awards settled:

Basic EPS was computed by dividing the earnings available to common
shareholders by the weighted average number of common shares outstanding
during the period. Diluted EPS was computed by dividing the earnings
available to common shareholders by the diluted weighted average number
of common shares outstanding during the period. Diluted EPS reflects the
potential dilution that could occur if securities or other agreements to issue
common stock (i.e., common stock equivalents) were settled. The weighted
average number of potentially dilutive shares outstanding used to calculate
diluted EPS is calculated using the treasury stock method.

Common Stock Equivalents — Xcel Energy Inc. has common stock
equivalents related to forward equity agreements and certain equity awards
in share-based compensation arrangements. Common stock equivalents
include commitments to issue common stock related to time-based equity
compensation awards.

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

(In Thousands)

Awards settled

2019

2018

2017

466

482

454

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

Settlement amount (cash, common stock
and deferred amounts)

24,930

21,534

19,083

TSR liability awards of $21 million were settled in cash in 2019.

Share-Based Compensation Expense — Other than for restricted stock,
vesting of employee equity awards is typically predicated on the achievement
of a TSR or environmental measures target. Additionally, approximately 0.3
million of equity award units were granted annually in 2017 - 2019, with vesting
subject only to service conditions of three years.

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

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

Compensation costs related to share-based awards:

(Millions of Dollars)

2019

2018

2017

Compensation cost for share-based awards (a)

Tax benefit recognized in income

(a)

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

There was approximately $40 million in 2019 and $38 million in 2018 of total
to nonvested share-based
unrecognized compensation cost related
compensation awards. Xcel Energy expects to recognize the unrecognized
amount over a weighted average period of 1.6 years.

•

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; and
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
1.3 million, 0.5 million and 0.6 million shares for 2019, 2018 and 2017.

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; and
Level 3 — Significant inputs to pricing have little or no observability as
of the reporting date. The types of assets and liabilities included in Level
3 are those valued with models requiring significant management
judgment or estimation.

Specific valuation methods include:

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

Investments in equity securities and other funds — Equity securities are valued
using quoted prices in active markets. The fair values for commingled funds
are measured using NAVs. The investments in commingled funds may be
redeemed for NAV with proper notice. Private equity commingled fund
investments require approval of the fund for any unscheduled redemption,
and such redemptions may be approved or denied by the fund at its sole
discretion. Unscheduled distributions from real estate commingled funds
investments may be redeemed with proper notice, however, withdrawals may
be delayed or discounted as a result of fund illiquidity.

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

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

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

Electric commodity derivatives held by NSP-Minnesota and SPS include
transmission congestion instruments, generally referred to as FTRs. FTRs
purchased from a RTO are financial instruments that entitle or obligate the
holder to monthly revenues or charges based on transmission congestion
across a given transmission path.

The value of an FTR is derived from, and designed to offset, the cost of
transmission congestion. In addition to overall transmission load, congestion
is also influenced by the operating schedules of power plants and the
consumption of electricity pertinent to a given transmission path. Unplanned
plant outages, scheduled plant maintenance, changes in the relative costs of
fuels used in generation, weather and overall changes in demand for electricity
can each impact the operating schedules of the power plants on the
transmission grid and the value of an FTR.

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

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

Non-Derivative Fair Value Measurements

Nuclear Decommissioning Fund

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

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

Unrealized gains for the nuclear decommissioning fund were $706 million and
$450 million as of Dec. 31, 2019 and 2018, respectively, and unrealized losses
were $6 million and $45 million as of Dec. 31, 2019 and 2018, respectively.

Non-derivative instruments with recurring fair value measurements:

(Millions of Dollars)

Cost

Level 1

Level 2

Level 3

NAV

Total

Dec. 31, 2019

Fair Value

Nuclear
decommissioning
fund (a)

Cash equivalents

Commingled funds

Debt securities

Equity securities

733

489

485

Total

1,740

—

962

995

— $

—

495

497

—

935

—

935

508

964

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.

(Millions of Dollars)

Cost

Level 1

Level 2

Fair Value
Level 3

NAV

Total

Dec 31, 2018

Nuclear
decommissioning
fund (a)

Cash equivalents

Commingled funds

Debt securities

Equity securities

758

466

401

Total

1,649

—

697

800

— $

—

436

—

819

—

898

436

697

436

— $

819

2,055

(a)

Reported in nuclear decommissioning fund and other investments on the consolidated balance
sheet, which also includes $141 million of equity investments in unconsolidated subsidiaries and
$121 million of rabbi trust assets and miscellaneous investments.

For the years ended Dec. 31, 2019 and 2018, there were immaterial Level 3
nuclear decommissioning fund investments or transfer of amounts between
levels.

Contractual maturity dates of debt securities in the nuclear decommissioning
fund as of Dec. 31, 2019:

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

(7)

111

246

158

508

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:

December 31, 2019

Fair Value

(Millions of Dollars)

Cost

Level 1

Level 2

Level 3

Total

Rabbi Trusts (a)

Cash equivalents

Mutual funds

Total

— $

—

— $

(a) Reported in nuclear decommissioning fund and other investments on the consolidated

balance sheet.

Dec. 31, 2018

Fair Value

(Millions of Dollars)

Cost

Level 1

Level 2

Level 3

Total

Rabbi Trusts (a)

Cash equivalents

Mutual funds

Total

— $

—

— $

(a) Reported in nuclear decommissioning fund and other investments on the consolidated

balance sheet.

Derivative 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 interest payments on certain floating rate debt obligations
or 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.

As of Dec. 31, 2019, accumulated other comprehensive losses related to
interest rate derivatives included $5 million of net losses expected to be
reclassified into earnings during the next 12 months as the hedged
transactions impact earnings.

As of Dec. 31, 2019, Xcel Energy had no unsettled interest rate swaps
outstanding. These interest rate derivatives were designated as hedges, and
as such, changes in fair value are recorded to other comprehensive income.

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.

As of Dec. 31, 2019, Xcel Energy had no commodity derivative contracts
designated as cash flow hedges. 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.
Changes in the fair value of non-trading commodity derivative instruments are
recorded in other comprehensive income or deferred as a regulatory asset or
liability. The classification as a regulatory asset or liability is based on
commission approved regulatory recovery mechanisms. Immaterial amounts
to income related to the ineffectiveness of cash flow hedges were recorded
for the years ended Dec. 31, 2019 and 2018.

As of Dec. 31, 2019, there were no net gains related to commodity derivative
cash flow hedges recorded as a component of accumulated other
comprehensive losses or related amounts expected to be reclassified into
earnings during the next 12 months.

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 amount of commodity forwards, options and FTRs at Dec. 31:

(Millions of Dollars) (a) (b)

MWh of electricity

MMBtu of natural gas

2019

2018

110

(a)

(b)

Amounts are not reflective of net positions in the underlying commodities.
Notional amounts for options are 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 in 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, 2019, six of Xcel Energy’s 10 most significant counterparties
for these activities, comprising $154 million or 60% of this credit exposure,
had investment grade credit ratings from Standard & Poor’s, Moody’s Investor
Services or Fitch Ratings. Four of the 10 most significant counterparties,
comprising $37 million or 14% of this credit exposure, were not rated by these
external agencies, but based on Xcel Energy’s internal analysis, had credit
quality consistent with
these significant
counterparties are municipal or cooperative electric entities, RTOs or other
utilities.

investment grade. Nine of

Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate
and vehicle fuel 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)

2019

2018

2017

Accumulated other comprehensive loss related to cash flow
hedges at Jan. 1

(60) $

(58) $

(51)

After-tax net unrealized losses related to derivatives
accounted for as hedges

After-tax net realized losses on derivative transactions
reclassified into earnings

Adoption of ASU. 2018-02 (a)

(23)

—

(5)

—

(10)

Accumulated other comprehensive loss related to cash flow
hedges at Dec. 31

(80) $

(60) $

(58)

(a)

In 2017, Xcel Energy implemented ASU No 2018-02 related to TCJA, which resulted in
reclassification of certain credit balances within net accumulated other comprehensive loss
to retained earnings.

Impact of derivative activity:

Pre-Tax Fair Value
Gains (Losses) Recognized
During the Period in:

Accumulated
Other
Comprehensive
Loss

Regulatory
(Assets) and
Liabilities

(Millions of Dollars)

Year Ended Dec. 31, 2019
Derivatives designated as cash flow hedges

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

Year Ended Dec. 31, 2017

Other derivative instruments

Electric commodity

Natural gas commodity

Total

(30)

—

(7)

—

— $

—

(9)

(1)

—

(13)

(3)

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

4 (a) $

—

(5) (c)

2 (d)

(3)

—

(1) (c)

(6) (d)

(7)

—

(15) (c)

3 (d)

—

4 (a)

—

5 (a)

—

2 (b)

—

(7) (d)

(5)

—

14 (b)

—

(4) (d)

—

10 (b)

—

(6) (d)

(Millions of Dollars)

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

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

Year Ended Dec. 31, 2017

Derivatives designated
as cash flow hedges

Interest rate

Total

Other derivative
instruments

Commodity trading

Electric commodity

Natural gas commodity

Total

(12)

(a)

(b)

(c)

(d)

Amounts recorded to interest charges.
Amounts 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.

Amounts 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 year ended Dec. 31, 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 and gains for the years ended Dec. 31, 2018 and 2017
were $1 million and immaterial, respectively. Remaining settlement losses for the years
ended Dec. 31, 2019, 2018 and 2017 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, 2019, 2018 and 2017.

Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal
purchase-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, or for cross default contractual provisions if there was a failure under other financing arrangements related to payment terms or
other covenants. As of Dec. 31, 2019 and 2018, the amounts for derivative instruments in a liability position with such underlying contract provisions were
$7 million and none, respectively.

Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek
performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected
to be impaired. Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2019 and 2018.

Recurring Fair Value Measurements — Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis:

(Millions of Dollars)

Current derivative assets

Commodity trading

Electric commodity
Natural gas commodity

Total current derivative assets

PPAs (b)

Current derivative instruments

Noncurrent derivative assets

Other derivative instruments:

Commodity trading

Total noncurrent derivative assets

PPAs (b)

Noncurrent derivative instruments

(Millions of Dollars)

Current derivative liabilities

Derivatives designated as cash flow hedges:

Interest rate

Other derivative instruments:

Commodity trading

Electric commodity
Natural gas commodity

Total current derivative liabilities

PPAs (b)

Current derivative instruments

Noncurrent derivative liabilities

Other derivative instruments:

Commodity trading

Total noncurrent derivative liabilities

PPAs (b)

Noncurrent derivative instruments

Dec. 31, 2019

Dec. 31, 2018

Fair Value

Level
1

Level
2

Level
3

Fair Value
Total

Netting (a)

Total

Level
1

Level
2

Level
3

Fair Value
Total

Netting (a)

Total

—
—

—
6

21
—

21
6

(52) $
(1)
—

105

(53)

(45) $

(45)

26
20

4
—

—

92
—

2
25

—

98
25

127

(44) $
—

—

(44)

$ — $

(14) $

(14)

Dec. 31, 2019

Dec. 31, 2018

Fair Value

Level
1

Level
2

Level
3

Fair Value
Total

Netting (a)

Total

Level
1

Level
2

Level
3

Fair Value
Total

Netting (a)

Total

$ — $ — $ — $

— $

— $ — $

$ — $

— $

—
—

—
5

1
—

1
5

(63)
(1)
—

(64)

113

(13) $

(13)

15
—

100

175

4
—

—

88
—

—

2
—

—

94
—

—

101

(60)
—

—

(60)

$ — $

54
25

34
—

—

129

(a)

(b)

Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet 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, 2019 and 2018. At both Dec. 31, 2019 and 2018, derivative assets and liabilities included $32 million
of obligations to return cash collateral. At Dec. 31, 2019 and 2018, derivative assets and liabilities included rights to reclaim cash collateral of $11 million and $15 million, respectively. Counterparty
netting excludes 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, the contracts are no longer adjusted to fair value and the previous carrying
value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

Changes in Level 3 commodity derivatives:

(Millions of Dollars)

Balance at Jan. 1

Purchases

Settlements

Net transactions recorded during the period:

(Losses) gains recognized in earnings (a)

Net gains (losses) recognized as regulatory
assets and liabilities

Balance at Dec. 31

Year Ended Dec. 31

2019

2018

2017

(64)

(8)

(59)

(1)

(5)

(97)

(a)

Amounts relate to commodity derivatives held at the end of the period.

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 2017 - 2019.

Fair Value of Long-Term Debt

As of Dec. 31, other financial instruments for which the carrying amount did
not equal fair value:

(Millions of Dollars)

Long-term debt, including current
portion

2019

2018

Carrying
Amount

Fair
Value

Carrying
Amount

Fair
Value

18,109

$ 20,227

16,209

$ 16,755

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, 2019 and 2018, 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, defined benefit pension plans that
cover almost all employees. Generally, benefits are based on a combination
of years of service and average pay. 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
that were participants in the plan in 2008, when the SERP was closed to new
participants.

Plan Assets

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, 2019 and 2018
were $39 million and $33 million, respectively. Xcel Energy recognized net
benefit cost for the SERP and nonqualified plans of $4 million in 2019 and in
2018.

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 2019 were above the assumed level of 6.87%;

Investment returns in 2018 were below the assumed level of 6.87%;

Investment returns in 2017 were above the assumed level of 6.87%; and

In 2020, expected investment-return assumption is 6.87%.

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.

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, 2019 (a)

Dec. 31, 2018 (a)

Level 1

Level 2

Level 3

Measured
at NAV

Total

Level 1

Level 2

Level 3

145
1,408
—
86
(120)
1,519

— $
—
645
—
5
650

— $
—
4
—
—
4

— $

1,031
—
—
(20)
1,011

145
2,439
649
86
(135)
3,184

137
914
—
106
2
1,159

— $
—
621
—
5
626

Measured
at NAV

Total

— $
—
—
—
—
— $

— $

987
—
—
(30)
957

137
1,901
621
106
(23)
2,742

(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, 2019 (a)

Dec. 31, 2018 (a)

Level 1

Level 2

Level 3

Measured
at NAV

Total

Level 1

Level 2

Level 3

Measured
at NAV

Total

23
—
69
—
—
92

— $
51
—
228
1
280

— $
—
—
1
—
1

— $
—
76
—
—
76

23
51
145
229
1
449

19
—
133
—
—
152

— $
45
—
179
1
225

— $
—
—
—
—
— $

— $
—
40
—
—
40

19
45
173
179
1
417

(a)

See Note 10 for further information on fair value measurement inputs and methods.

Immaterial assets were transferred in or out of Level 3 for 2019. No assets were transferred in or out of Level 3 for 2018.

Funded Status — Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement
health care plans for Xcel Energy are as follows:

(Millions of Dollars)

Change in Benefit Obligation:

Obligation at Jan. 1
Service cost

Interest cost

Plan amendments

Actuarial loss (gain)

Plan participants’ contributions

Medicare subsidy reimbursements

Benefit payments (a)

Obligation at Dec. 31

Change in Fair Value of Plan Assets:

Fair value of plan assets at Jan. 1

Actual return on plan assets

Employer contributions

Plan participants’ contributions

Benefit payments

Fair value of plan assets at Dec. 31

Funded status of plans at Dec. 31

Amounts recognized in the Consolidated Balance Sheet at Dec. 31:

Noncurrent assets

Current liabilities
Noncurrent liabilities

Net amounts recognized

Pension Benefits

Postretirement Benefits

2019

2018

2019

2018

3,477
86

145

273

—

(281)

3,701

2,742

568

155

—

(281)

3,184

(517) $

— $

—
(517)

(517) $

3,828

542

133

—

(224)

—

(354)

3,477

3,088

(142)

150

—

(354)

2,742

(735) $

— $

—
(735)

(735) $

—

(47)

547

417

(47)

449

(98) $

(6)
(113)

(98) $

621

—

(62)

(50)

542

461

(13)

(50)

417

(125)

—
(7)
(118)

(125)

(a)

Includes approximately $20 million in 2019 and $198 million in 2018 of lump-sum benefit payments used in the determination of a settlement charge.

(Millions of Dollars)

Significant Assumptions Used to Measure Benefit Obligations:

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

Pension Benefits

Postretirement Benefits

2019

2018

2019

2018

3.49%

3.75

PRI-2012

N/A

4.31%

3.75

RP-2014

N/A

3.47%

N/A

PRI-2012

6.00%

5.10%

4.50%

4.32%

N/A

RP-2014

6.50%

5.30%

4.50%

Accumulated benefit obligation for the pension plan was $3,465 million and $3,275 million as of Dec. 31, 2019 and 2018, 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)

Costs not recognized due to effects of regulation

Net benefit cost (credit) recognized for financial reporting

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

4.31%

3.75

6.87

Pension Benefits

Postretirement Benefits

2019

2018

2017

2019

2018

2017

145

(203)

(5)

116

(1)

133

(209)

(5)

111

215

(75)

140

3.63%

3.75

6.87

147

(209)

(2)

107

218

(79)

139

4.13%

3.75

6.87

(21)

(10)

—

(2)

(1)

4.32%

—

4.50

(26)

(11)

—

(5)

(3)

3.62%

—

5.30

(25)

(11)

—

(3)

—

(3)

4.13%

—

5.80

(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 the 2019 and 2018 plan years, Xcel Energy recorded a total pension settlement charge of $6 million in 2019 and
$91 million in 2018, 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.

(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

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 2017 — 2020 to meet minimum funding
requirements.

Voluntary and required pension funding contributions:

•

$150 million in January 2020;

$154 million in 2019;

$150 million in 2018; and

$162 million in 2017.

Pension Benefits

Postretirement Benefits

2019

2018

2019

2018

1,447

(15)

1,432

1,285

—

1,633

(20)

1,613

1,446

—

(23)

— $

(1)

(12)

1,432

1,613

116

(33)

—

(1)

(10)

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2019

Dec. 31, 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:

•

$10 million during 2020;

$15 million during 2019;

$11 million during 2018; and

$20 million during 2017.

Targeted asset allocations:

12. Commitments and Contingencies

Pension Benefits

Postretirement
Benefits

Legal

Domestic and international equity
securities

Long-duration fixed income securities

Short-to-intermediate fixed income
securities

Alternative investments

Cash

Total

2019

2018

2019

2018

37%

36%

15%

18%

—

100%

Plan Amendments — The Xcel Energy Pension Plan and Xcel Energy Inc.
Nonbargaining Pension Plan (South) were amended in 2017 to reduce
supplemental benefits for non-bargaining participants as well as to allow the
transfer of a portion of non-qualified pension obligations into the qualified
plans.

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 plan amendments made in 2019 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

2020

2021

2022

2023

2024

278

263

262

260

255

2025-2029

1,205

Defined Contribution Plans

181

168

Xcel Energy maintains 401(k) and other defined contribution plans that cover
most employees. Total expense to these plans was approximately $39 million
in 2019, $38 million in 2018 and $37 million in 2017.

Multiemployer Plans

NSP-Minnesota and NSP-Wisconsin each contribute to several union
multiemployer pension and other postretirement benefit plans, none of which
are individually significant. These plans provide pension and postretirement
health care benefits to certain union employees who may perform services
for multiple employers and do not participate in the NSP-Minnesota and NSP-
Wisconsin sponsored pension and postretirement health care plans.

Contributing to these types of plans creates risk that differs from providing
benefits under NSP-Minnesota and NSP-Wisconsin sponsored plans, in that
if another participating employer ceases to contribute to a multiemployer plan,
additional unfunded obligations may need to be funded over time by remaining
participating employers.

Xcel Energy is involved in various litigation matters that are being defended
and handled in the ordinary course of business. Assessing whether a loss is
probable or a reasonable possibility, and whether the loss or a range of loss
is estimable, often involves complex judgments regarding future events.
Management maintains accruals for losses that are probable of being incurred
and subject to reasonable estimation.

Management may be unable to estimate an amount or range of a reasonably
possible loss in certain situations, including 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 the ultimate liabilities, if any,
arising from such current proceedings 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.

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 both remaining lawsuits.

Line Extension Disputes — In December 2015, the DRC filed a lawsuit
seeking monetary damages in the Denver District Court, stating PSCo failed
to award proper allowances and refunds for line extensions to new
developments pursuant to the terms of electric and gas service agreements.
The dispute involves claims by over fifty developers. In February 2018, the
Colorado Supreme Court denied DRC’s petition to appeal the Denver District
Court’s dismissal of the lawsuit, effectively terminating this litigation. However,
in January 2018, DRC filed a new lawsuit in Boulder County District Court,
asserting a single claim that PSCo was required to file its line extension
agreements with the CPUC but failed to do so.

This claim is similar to the arguments previously raised by the DRC. PSCo
filed a motion to dismiss this claim, which was granted in May 2018. The DRC
subsequently filed an appeal to the Colorado Court of Appeals. In November
2019, the Colorado Court of Appeals issued an opinion affirming dismissal of
the lawsuit based upon lack of subject matter jurisdiction. The Colorado Court
of Appeals did not address the second issue based upon issue preclusion.
Finally, the Colorado Court of Appeals remanded the case to the Boulder
District Court to consider PSCo’s request for an award of costs, which it
concluded does not include attorneys’ fees. The DRC did not file a petition for
a Writ of Certiorari to the Colorado Supreme Court by the Dec. 26, 2019
deadline, effectively terminating this litigation.

Rate Matters

Sherco — In NSP-Minnesota’s 2013 fuel reconciliation filing, the MPUC made
recovery of replacement power costs associated with the 2011 incident at its
Sherco Unit 3 plant provisional and subject to further review following
conclusion of litigation commenced by NSP-Minnesota, SMMPA (Co-owner
of Sherco Unit 3) and insurance companies against GE.

In 2018, NSP-Minnesota and SMMPA reached a settlement with GE. NSP-
Minnesota notified the MPUC of its proposal to refund the GE settlement
proceeds back to customers through the FCA. The insurance providers
continued their litigation against GE and the case went to trial.

In 2018, GE prevailed in the lawsuit with the insurance companies, however,
the jury found comparable fault, finding that GE was 52% and NSP-Minnesota
was 48% at fault. At that point in the litigation, NSP-Minnesota was no longer
involved in the case and was not present to make arguments about its role in
the event. The specific issue leading to the fault apportionment was also not
before the jury and not relevant to the outcome of the trial.

In January 2019, the DOC recommended that NSP-Minnesota refund $20
million of previously recovered purchased power costs to its customers, based
on the jury’s apportionment of fault. The OAG recommended the MPUC
withhold any decision until the underlying litigation by the insurance providers
(currently under appeal) is concluded. The DOC subsequently filed comments
agreeing with the OAG’s recommendation to withhold a decision pending the
outcome of any appeals. NSP-Minnesota filed reply comments arguing that
the DOC recommendations are without merit and that it acted prudently in
operating the plant and its settlement with GE was reasonable.

In March 2019, MPUC approved NSP-Minnesota’s proposal to refund the GE
settlement proceeds back to customers through the FCA. It also decided to
withhold any decision as to NSP-Minnesota’s prudence in connection with the
incident at Sherco Unit 3 until after conclusion of the pending litigation between
GE and NSP-Minnesota’s insurers.

MISO ROE Complaints — In November 2013 and February 2015, customers
filed complaints against MISO TOs including NSP-Minnesota and NSP-
Wisconsin.

The first complaint argued for a reduction in the base ROE in MISO
transmission formula rates from 12.38% to 9.15%, and removal of ROE adders
(including those for RTO membership). The second complaint sought to
reduce base ROE from 12.38% to 8.67%.

In September 2016, the FERC issued an order granting a 10.32% base ROE
(10.82% with the RTO adder) 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 FERC Opinion No. 531, which
had established the ROE methodology on which the September 2016 FERC
order was based.

On March 21, 2019, FERC announced a NOI seeking public comments on
whether, and if so how, to revise ROE policies in light of the D.C. Circuit Court
decision. FERC also initiated a NOI on whether to revise its policies on
the RTO
incentives
membership incentive. In November 2019, the FERC issued an order adopting
a new ROE methodology and settling the MISO base ROE at 9.88% (10.38%
with the RTO adder), effective Sept. 28, 2016 and for the Nov. 12, 2013 to
Feb. 11, 2015 refund period. The FERC also dismissed the second complaint.

investments,

transmission

for electric

including

In December 2019, MISO TOs filed a request for rehearing. Customers also
filed requests for rehearing claiming, among other points, that the FERC erred
by dismissing the second complaint without refunds. Xcel Energy has
recognized a liability for its best estimate of final refunds to customers. It is
uncertain when the FERC will act on the requests for rehearing or any other
pending matters related to the 2019 NOIs.

Texas Fuel Reconciliation — In December 2018, SPS filed an application
with the PUCT for reconciliation of fuel costs for the period Jan. 1, 2016,
through June 30, 2018, to determine whether all fuel costs incurred were
eligible for recovery. In December 2019, the PUCT issued an order disallowing
recovery of costs for Texas customers related to two specific solar PPAs.
These PPAs were previously approved by the NMPRC as reasonable,
necessary and economic. SPS recorded a total disallowance of approximately
$6 million in December 2019.

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

In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting
SPP the right to recover previously unbilled charges was remanded to the
FERC. In February 2019, the FERC reversed its 2016 decision and ordered
SPP to refund charges retroactively collected from its transmission customers,
including SPS, related to periods before September 2015. In April 2019,
several parties, including SPP, filed requests for a rehearing. Timing of a FERC
response to rehearing requests is uncertain. Any refunds received by SPS
are expected to be given back to SPS customers through future rates.

In October 2017, SPS filed a separate complaint against SPP asserting SPP
assessed upgrade charges to SPS in violation of the SPP OATT. The FERC
granted a rehearing for further consideration in May 2018. Timing of FERC
action on the SPS rehearing is uncertain. If SPS’ complaint results in additional
charges or refunds, SPS will seek to recover or refund the amounts through
future SPS customer rates.

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 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 are anticipated to be completed in 2020.
Groundwater treatment activities will continue for many years.

The current cost estimate for remediation and restoration of the entire site is
approximately $199 million. At Dec. 31, 2019 and 2018, NSP-Wisconsin had
a total liability of $23 million and $27 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. In its final December 2019 order approving 2020
and 2021 natural gas base rates, the PSCW authorized continued amortization
of costs and application of a 3% carrying charge to the regulatory asset.

MGP, Landfill or Disposal Sites — PSCo is cooperating with the City of Denver
on an environmental investigation of the Rice Yards Site in Denver, Colorado,
which had various historic industrial uses by multiple parties, including railroad,
maintenance shop, scrap metal yard, and MGP operations.

The area is being redeveloped into residential and commercial mixed uses,
and PSCo is in discussions with the current property owner regarding legal
claims related to the Rice Yards Site.

In addition, Xcel Energy is currently investigating or remediating 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 laws 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, where appropriate,
initiating the assessment of corrective measures and evaluating whether
corrective action is required at any CCR landfills or surface impoundments.
In 2019, groundwater monitoring consistent with the CCR Rule was
conducted. In NSP-Minnesota, no results above the groundwater protection
standards in the rule were identified. In PSCo, statistically significant increase
above background concentration was detected at
locations.
Subsequently, assessment monitoring samples were collected, and PSCo is
evaluating the results to determine whether corrective action is required. Until
PSCo completes its assessment, it is uncertain what impact, if any, there will
be on the operations, financial condition or cash flows.

four

In August 2018, the D.C. Circuit ruled that the EPA cannot allow utilities to
continue to use unlined impoundments (including clay lined impoundments)
for the storage or disposal of coal ash. In November 2019, the EPA proposed
rules in response to this decision.

If finalized in their current form, these rules would require NSP-Minnesota to
expedite closure plans for one impoundment at an estimated cost of $2 million
and the construction of a new impoundment at the cost of $9 million.

In 2019, Xcel Energy initiated the construction of this new impoundment, an
ash pond, expected to be in service in 2020. Upon placing the new ash pond
in service, the existing ash pond will be taken out of service, and closure
activities as prescribed by the CCR Rule and the facility’s National Pollutant
Discharge Elimination System permit will be initiated. In addition, the rules
proposed by the EPA may require PSCo to expedite the closure of one coal
ash impoundment.

Closure costs for existing impoundments are included in the calculation of the
ARO liability. See Note 12 for further information.

Federal CWA WOTUS Rule — In 2015, the EPA and U.S. Army Corps of
Engineers published a final rule that significantly broadened the scope of
waters under the CWA that are subject to federal jurisdiction, referred to as
“WOTUS”. In 2019, the EPA repealed the 2015 rule and published a draft
replacement rule. Until a final rule is issued, Xcel Energy cannot estimate
potential impacts, but anticipates costs will be recoverable through regulatory
mechanisms.

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 2017, the EPA delayed the compliance date for
flue gas desulfurization wastewater and bottom ash transport until November
2020. After 2020, Xcel Energy estimates that ELG compliance will cost
approximately $12 million to complete. The EPA, however, is conducting a
rulemaking process to revise certain effluent limitations and pretreatment
standards, which may impact compliance costs. Xcel Energy anticipates these
costs will be fully recoverable through regulatory mechanisms.

Federal CWA Section 316(b) — The federal CWA requires the EPA to regulate
cooling water intake structures to assure that these structures reflect the best
technology available for minimizing impingement and entrainment of aquatic
species. Xcel Energy estimates the likely cost for complying with impingement
and entrainment requirements is approximately $40 million, to be incurred
between 2020 and 2028. Xcel Energy believes six NSP-Minnesota plants and
two NSP-Wisconsin plants could be required by state regulators 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 approximately $198 million. Xcel Energy anticipates these costs will be
fully recoverable through regulatory mechanisms.

Environmental Requirements — Air

Regional Haze Rules — The regional haze program requires SO2, nitrogen
oxide and particulate matter emission controls at power plants to reduce
visibility impairment in national parks and wilderness areas. The program
includes BART and reasonable further progress. The requirements of the first
regional haze plans developed by Minnesota and Colorado have been
approved and implemented. Texas’ first regional haze plan has undergone
federal review as described below.

BART Determination for Texas: The EPA has issued a revised final rule
adopting a BART alternative Texas only SO2 trading program that applies to
all Harrington and Tolk units. Under the trading program, SPS expects the
allowance allocations to be sufficient for SO2 emissions. The anticipated costs
of compliance are not expected to have a material impact; and SPS believes
that compliance costs would be recoverable through regulatory mechanisms.

Several parties have challenged whether the final rule issued by the EPA
should be considered to have met the requirements imposed in a Consent
Decree entered by the United States District Court for the District of Columbia
that established deadlines for the EPA to take final action on state regional
haze plan submissions. The court has required status reports from the parties
while the EPA works on the reconsideration rulemaking.

In December 2017, the National Parks Conservation Association, Sierra Club,
and Environmental Defense Fund appealed the EPA’s 2017 final BART rule
to the Fifth Circuit and filed a petition for administrative reconsideration. In
January 2018, the court granted SPS’ motion to intervene in the Fifth Circuit
litigation in support of the EPA’s final rule. 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, which was supplemented
by an additional agency notice in November 2019. It is not known when the
EPA will make a final decision on this proposal.

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. The EPA has not announced a schedule for acting 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 is to
be monitored for three years and a final designation is expected to be made
by December 2020.

If the area near the Harrington plant is designated nonattainment in 2020, the
TCEQ will need to develop an implementation plan, designed to achieve the
NAAQS by 2025. The TCEQ could require additional SO2 controls at
Harrington as part of such a plan. Xcel Energy cannot evaluate the impacts
until the final designation is made and any required state plans are developed.

Xcel Energy believes that should SO2 control systems be required for a plant,
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 $2.4 billion and $2.1 billion for 2019 and
2018, respectively.

Xcel Energy’s AROs were as follows:

Jan.
1,
2019

Amounts
Incurred
(a)

Amounts
Settled
(b)

Cash Flow
Revisions
(c)

Dec.
31,
2019

Accretion

$1,968

— $

100

— $2,068

—

26
—

—

(5)

—
—

—

7
2

—

(6)
—

(7)

(24)

(1)

—

202

146
44

—

236

(5) $

128

(16) $2,701

Total liability

$2,568

(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. Changes
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 the cost estimates
to remediate ponds at production facilities. Changes in wind AROs were driven by new
dismantling studies.

Jan.
1,
2018

Amounts
Incurred
(a)

Amounts
Settled
(b)

Accretion

Cash Flow
Revisions
(c)

Dec.
31,
2018

$1,874

— $

— $ 1,968

(Millions
of Dollars)

Electric

Nuclear

Steam, hydro
and other
production

Wind

Distribution
Miscellaneous

Natural gas

Transmission
and distribution

Miscellaneous

Common

Miscellaneous

Non-utility

Miscellaneous

(Millions
of Dollars)

Electric

Nuclear

Steam, hydro
and other
production

Wind

Distribution

Miscellaneous

Natural gas

Transmission
and distribution

Miscellaneous

Common

Miscellaneous

Non-utility

Miscellaneous

177

119
42

249

192

282

—

(14)

—

(9)

(46)

—

177

119

249

(14) $

120

(26) $ 2,568

Total liability

$2,475

(a)

(b)

(c)

Amounts incurred related to the PSCo Rush Creek wind farm and Nicollet Projects
community solar gardens, which were placed in service in 2018.

Amounts settled related to asbestos abatement projects and closure of certain ash
containment facilities.

In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes
in gas transmission and distribution AROs were primarily related to increased gas line
mileage and number of services, which were more than offset by increased discount rates.
Changes in electric distribution AROs primarily related to increased labor costs.

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, 2019.
Therefore, an ARO was not recorded for these facilities.

Removal Costs — Xcel Energy records a regulatory liability for the plant
removal costs of its utility subsidiaries that are recovered currently in rates.
Removal costs have accumulated based on varying rates as authorized by
the appropriate regulatory entities. The utility subsidiaries have estimated the
amount of removal costs accumulated through historic depreciation expense
based on current factors used in the existing depreciation rates.

Accumulated balances by entity at Dec. 31:

(Millions of Dollars)

NSP-Minnesota

PSCo

SPS

NSP-Wisconsin

Total Xcel Energy

Nuclear Related

2019

2018

520

351

175

171

1,217

485

344

188

158

1,175

Nuclear Insurance — NSP-Minnesota’s public liability for claims from any
nuclear incident is limited to $13.9 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 $13.5 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 licensed 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 by the
NRC and state premium taxes. The NRC’s last adjustment was effective
November 2018.

insurance

NSP-Minnesota purchases
for property damage and site
decontamination cleanup costs from NEIL and EMANI. The coverage limits
are $2.7 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also
provides business interruption insurance coverage up to $350 million,
including the cost of replacement power during prolonged accidental outages
of nuclear generating units. Premiums are expensed over the policy term.

All companies insured with NEIL are subject to retroactive premium
adjustments if losses exceed accumulated reserve funds. Capital has been
accumulated in the reserve funds of NEIL and EMANI to the extent that NSP-
Minnesota would have no exposure for retroactive premium assessments in
case of a single incident under the business interruption and the property
damage insurance coverage.

NSP-Minnesota could be subject to annual maximum assessments of
approximately $12 million for business interruption insurance and $35 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 44 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 2091. NSP-
Minnesota’s current operating licenses allow continued use of its Monticello
nuclear plant until 2030 and its PI nuclear plant until 2033 for Unit 1 and 2034
for Unit 2.

Future decommissioning costs of nuclear facilities are estimated through
triennial periodic studies that assess the costs and timing of planned nuclear
decommissioning activities for each unit.

Obligations for decommissioning are expected to be funded 100% by the
external decommissioning trust fund. The cost study assumes the external
decommissioning fund will earn an after-tax return between 5.23% and 6.30%.
Realized and unrealized gains on fund investments are deferred as an offset
of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs.
Decommissioning costs are quantified in 2014 dollars. Escalation rates are
4.36% for plant removal activities and 3.36% for fuel management and site
restoration activities.

NSP-Minnesota had $2.4 billion of assets held in external decommissioning
trusts at Dec. 31, 2019. The following table summarizes the funded status of
NSP-Minnesota’s decommissioning obligation. Xcel Energy believes future
decommissioning costs will continue to be recovered in customer rates. The
following amounts were prepared on a regulatory basis and not directly
recorded in the financial statements as an ARO.

(Millions of Dollars)

Regulatory Basis

2019

2018

Estimated decommissioning cost obligation from most recently

approved study (in 2014 dollars)

3,012

Effect of escalating costs

Estimated decommissioning cost obligation (in current dollars)

Effect of escalating costs to payment date

688

3,700

7,505

539

3,551

7,654

Estimated future decommissioning costs (undiscounted)

11,205

Effect of discounting obligation (using average risk-free interest
rate of 2.39% and 3.33% for 2019 and 2018, respectively)

Discounted decommissioning cost obligation

Assets held in external decommissioning trust

(5,562)

(6,911)

5,643

2,440

4,294

2,055

Underfunding of external decommissioning fund compared to

the discounted decommissioning obligation

3,203

2,239

Calculations and data used by the regulator in approving NSP-Minnesota’s
rates are useful in assessing future cash flows. Regulatory basis information
is a means to reconcile amounts previously provided to the MPUC and utilized
for regulatory purposes to amounts used for financial reporting.

Reconciliation of the discounted decommissioning cost obligation - regulated
basis to the ARO recorded in accordance with GAAP:

(Millions of Dollars)

2019

2018

Discounted decommissioning cost obligation - regulated basis

5,643

4,294

Differences in discount rate and market risk premium

O&M costs not included for GAAP

(2,295)

(1,280)

(1,447)

(879)

Nuclear production decommissioning ARO - GAAP

2,068

1,968

Decommissioning expenses recognized as a result of regulation:

(Millions of Dollars)

2019

2018

2017

Annual decommissioning recorded as
depreciation expense: (a) (b)

(a)

(b)

Decommissioning expense does not include depreciation of the capitalized nuclear asset
retirement costs.

Decommissioning expenses in 2019, 2018 and 2017 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 2019, 2018 and 2017. The 2017 filing, effective
Jan. 1, 2019, has been approved by the MPUC. In December 2019, the MPUC
verbally approved for NSP-Minnesota to delay any increase to the annual
funding requirement until 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. Under ASC Topic 842, adopted by Xcel Energy on Jan. 1, 2019,
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. Starting in
2019, the present value of future operating lease payments are recognized
in other current liabilities and noncurrent operating lease liabilities. These
amounts, adjusted for any prepayments or incentives, are recognized as
operating lease ROU assets.

Most of Xcel Energy’s leases do not contain a readily determinable discount
rate. Therefore, the present value of future lease payments is generally
calculated using
the applicable Xcel Energy subsidiary’s estimated
incremental borrowing rate (weighted-average of 4.1%). Xcel Energy has
elected the practical expedient under which non-lease components, such as
asset maintenance costs included in payments, are not deducted from
minimum lease payments for the purposes of lease accounting and disclosure.

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

Operating lease ROU assets:

(Millions of Dollars)

PPAs

Other

Gross operating lease ROU assets

Accumulated amortization

Net operating lease ROU assets

Dec. 31, 2019

1,642

201

1,843

(171)

1,672

In 2019, 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. Prior to 2019, finance
leases were included in property, plant and equipment, the current portion of
long-term debt and long-term debt.

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

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

Finance lease ROU assets:

(Millions of Dollars)

Gas storage facilities

Gas pipeline

Gross finance lease ROU assets

Accumulated amortization

Net finance lease ROU assets

Components of lease expense:

(Millions of Dollars)

Operating leases

PPA capacity payments

Other operating leases (a)

Total operating lease expense (b)

Finance leases

Amortization of ROU assets

Interest expense on lease liability

Total finance lease expense

Dec. 31, 2019

Dec. 31, 2018

201

222

(83)

139

2019

2018

2017

221

255

210

248

201

222

(77)

145

210

246

(a)

(b)

Includes short-term lease expense of $5 million for 2019, 2018 and 2017.
PPA capacity payments are included in electric fuel and purchased power on the
consolidated statements of income. Expense for other operating leases is included in O&M
expense and electric fuel and purchased power.

Commitments under operating and finance leases as of Dec. 31, 2019:

(Millions of Dollars)

PPA (a) (b)
Operating
Leases

Other
Operating
Leases

Total
Operating
Leases

Finance
Leases (c)

236

238

225

214

208

750

1,871

(321)

1,550

2020

2021

2022

2023

2024

Thereafter

Total minimum obligation

Interest component of
obligation

Present value of minimum
obligation

Less current portion

Noncurrent operating and
finance lease liabilities

Weighted-average remaining
lease term in years

115

245

(52)

193

262

267

253

239

230

865

2,116

207

271

(373)

(190)

1,743

(194)

1,549

(4)

9.3

37.0

(a)

(b)

(c)

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

Operating lease liabilities at Dec. 31, 2019 include a present value of
approximately $400 million for MEC PPA capacity payments. In 2020, these
operating lease liabilities and related ROU assets will be eliminated from Xcel
Energy’s consolidated balance sheet following the completed January 2020
purchase of MEC by a newly formed non-regulated subsidiary of Xcel Energy.

Commitments under operating and finance leases as of Dec. 31, 2018:

Estimated minimum purchases under these contracts as of Dec. 31, 2019:

(Millions of Dollars)

PPA (a) (b)
Operating
Leases

Other
Operating
Leases

Total
Operating
Leases

Finance
Leases (c)

(Millions of Dollars)

Coal

Nuclear fuel

Natural gas
supply

Natural gas
supply and
transportation

2019

2020

2021

2022

2023

Thereafter

Total minimum obligation

Interest component of obligation

Present value of minimum obligation

207

208

210

197

186

883

239

234

235

221

208

154

1,037

220

286

(201)

(a)

(b)

(c)

Amounts do not include PPAs accounted for as executory contracts and/or contingent
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
2034 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 $102 million, $105 million
and $100 million in 2019, 2018 and 2017, respectively.

Included in electric fuel and purchased power expenses for PPAs accounted
for as executory contracts were payments for capacity of $86 million, $131
million and $168 million in 2019, 2018 and 2017, respectively.

Capacity and energy payments are contingent on the IPPs meeting contract
obligations, including plant availability requirements. Certain contractual
payments are adjusted based on market indices. The effects of price
adjustments on financial results are mitigated through purchased energy cost
recovery mechanisms.

At Dec. 31, 2019, the estimated future payments for capacity and energy that
the utility subsidiaries of Xcel Energy are obligated to purchase pursuant to
these executory contracts, subject to availability, were as follows:

(Millions of Dollars)

Capacity

Energy (a)

2020
2021
2022
2023
2024
Thereafter
Total

70
78
77
79
74
56
434

110
157
173
177
182
146
945

(a)

Excludes contingent energy payments for renewable energy PPAs.

Fuel Contracts — Xcel Energy has entered into various long-term
commitments for the purchase and delivery of a significant portion of its coal,
nuclear fuel and natural gas requirements. These contracts expire between
2020 and 2060. Xcel Energy is required to pay additional amounts depending
on actual quantities shipped under these agreements.

2020
2021
2022
2023
2024
Thereafter
Total

VIEs

430
222
135
58
24
74
943

54
103
85
103
74
275
694

343
254
104
53
3
—
757

295
283
269
198
153
860
2,058

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 3,986 MW and 3,770 MW of capacity
under long-term PPAs at Dec. 31, 2019 and 2018, respectively, with entities
that have been determined to be VIEs. Agreements have expiration dates
through 2041.

Fuel Contracts — SPS purchases all of its coal requirements for its Harrington
and Tolk plants from TUCO Inc. under contracts that will expire in December
2022. TUCO arranges for the purchase, receiving, transporting, unloading,
handling, crushing, weighing and delivery of coal to meet SPS’ requirements.
TUCO is responsible for negotiating and administering contracts with coal
suppliers, transporters and handlers.

SPS has not provided any significant financial support to TUCO, other than
contractual payments for delivered coal. However, the fuel contracts create a
variable interest in TUCO due to SPS’ reimbursement of fuel procurement
costs.

SPS has determined that TUCO is a VIE, however it has concluded that SPS
is not the primary beneficiary of TUCO because it does not have the power
to direct the activities that most significantly impact TUCO’s economic
performance.

Low-Income Housing Limited Partnerships — Eloigne and NSP-Wisconsin
have entered into limited partnerships for the construction and operation of
affordable rental housing developments which qualify for low-income housing
tax credits. Xcel Energy Inc. has determined Eloigne and NSP-Wisconsin’s
low-income housing partnerships to be VIEs primarily due to contractual
arrangements within each limited partnership that establish sharing of ongoing
voting control and profits and losses that does not align with the partners’
proportional equity ownership.

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, 2019 and 2018,
Xcel Energy Inc. and its subsidiaries had no assets held as collateral related
to their guarantees, bond indemnities and indemnification agreements.

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, 2019

Dec. 31, 2018

—

Technology Agreements — Xcel Energy has a contract that extends through
December 2022 with IBM for information technology services. The contract
is cancelable at Xcel Energy’s option, although Xcel Energy would be obligated
to pay 50% of the contract value for early termination. Xcel Energy capitalized
or expensed $46 million, $81 million and $98 million associated with the IBM
contract in 2019, 2018 and 2017, respectively.

Xcel Energy’s contract with Accenture for information technology services
extends through December 2020. The contract is cancelable at Xcel Energy’s
option, although there are financial penalties for early termination. Xcel Energy
capitalized or expensed $52 million, $46 million and $16 million associated
with the Accenture contract in 2019, 2018 and 2017, respectively.

During 2019, Xcel Energy executed a contract with Cognizant for information
technology services which extends through 2022. The contract is cancelable
at Xcel Energy’s option, although there are financial penalties for early
termination. Xcel Energy capitalized or expensed $3 million associated with
the Cognizant contract in 2019.

Committed minimum payments under these obligations:

(Millions of Dollars)

IBM Agreement

2020

2021

2022

2023

2024

Thereafter

—

Accenture
Agreement

Cognizant
Agreement

—

Guarantees and bond indemnities issued and outstanding for Xcel Energy
were $62 million and $69 million as of Dec. 31, 2019 and 2018.

13. Other Comprehensive Income

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

(Millions of Dollars)

Accumulated other comprehensive loss
at Jan. 1

Other comprehensive loss before
reclassifications (net of taxes of $(8)
and $0, respectively)

Losses reclassified from net
accumulated other comprehensive loss:

Interest rate derivatives (net of taxes
of $1 and $0, respectively)

Amortization of net actuarial loss (net
of taxes of $0 and $1, respectively)

Net current period other comprehensive
(loss) income

Accumulated other comprehensive loss
at Dec. 31

Gains and
Losses on
Cash Flow
Hedges

2019

Defined Benefit
Pension and
Postretirement
Items

Total

(60)

(64)

$ (124)

(23)

(a)

—

(20)

—

(b)

(23)

(17)

(80)

(61)

$ (141)

(a)

(b)

Included in interest charges.
Included in the computation of net periodic pension and postretirement benefit costs.
See Note 11 for further information.

(Millions of Dollars)

Accumulated other comprehensive loss
at Jan. 1

Other comprehensive loss before
reclassifications (net of taxes of $(2)
and $(2), respectively)

Losses reclassified from net
accumulated other comprehensive loss:

Interest rate derivatives (net of taxes
of $1 and $0, respectively)

Amortization of net actuarial loss (net
of taxes of $0 and $3, respectively)

Net current period other comprehensive
(loss) income

Accumulated other comprehensive loss
at Dec. 31

Gains and
Losses on
Cash Flow
Hedges

2018

Defined Benefit
Pension and
Postretirement
Items

Total

(58)

(67)

$ (125)

(5)

(6)

(11)

(a)

—

(2)

—

(b)

(60)

(64)

$ (124)

Included in interest charges.

Included in the computation of net periodic pension and postretirement benefit costs.
See Note 11 for further information.

(a)

(b)

14. Segments and Related Information

Xcel Energy evaluates performance by each utility subsidiary based on profit
or loss generated from the product or service provided, including the regulated
electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and
SPS, as well as the regulated natural gas utility operating results of NSP-
Minnesota, NSP-Wisconsin and PSCo. These segments are managed
separately because the revenue streams are dependent upon regulated rate
recovery, which is separately determined for each segment.

Xcel Energy has the following reportable segments:

•

Regulated Electric - The regulated electric utility segment generates,
transmits and distributes electricity in Minnesota, Wisconsin, Michigan,
North Dakota, South Dakota, Colorado, Texas and New Mexico. In
addition, this segment includes sales for resale and provides wholesale
transmission service to various entities in the United States. The
regulated electric utility segment also includes wholesale commodity and
trading operations; and

Regulated Natural Gas - The regulated natural gas utility segment
transports, stores and distributes natural gas primarily in portions of
Minnesota, Wisconsin, North Dakota, Michigan and Colorado.

Xcel Energy presents Other, which includes operating segments, with
revenues below the necessary quantitative thresholds. Those operating
segments primarily include steam revenue, appliance repair services, non-
utility real estate activities, revenues associated with processing solid waste
into refuse-derived fuel and investments in rental housing projects that qualify
for low-income housing tax credits.

Xcel Energy had equity investments in unconsolidated subsidiaries of
$155 million and $141 million as of Dec. 31, 2019 and 2018, respectively,
included in the natural gas utility and all other segments.

Asset and capital expenditure information is not provided for Xcel Energy’s
reportable segments. As an integrated electric and natural gas utility, Xcel
Energy operates significant assets that are not dedicated to a specific business
segment. Reporting assets and capital expenditures by business segment
would require arbitrary and potentially misleading allocations, which may not
necessarily reflect the assets that would be required for the operation of the
business segments on a stand-alone basis.

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

Xcel Energy’s segment information:

(Millions of Dollars)

Regulated Electric

Operating revenues from external customers

Intersegment revenue

Total revenues

Depreciation and amortization

Interest charges and financing costs

Income tax expense

Net income

Regulated Natural Gas

Operating revenues from external customers

Intersegment revenue

Total revenues

Depreciation and amortization

Interest charges and financing costs

Income tax expense

Net income

Other

Total operating revenue

Depreciation and amortization

Interest charges and financing costs

Income tax (benefit)

Net (loss)

Consolidated Total

Total revenue

Reconciling eliminations

Consolidated total revenue

Depreciation and amortization

Interest charges and financing costs

Income tax expense

Net income

2019

2018

2017

9,575

9,576

1,535

500

125

1,288

1,868

1,870

219

195

167

(45)

(111)

11,532

(3)

11,529

1,765

736

128

1,372

9,719

9,720

1,421

449

187

1,177

1,739

1,741

212

187

142

(34)
(103)

11,540

(3)

11,537

1,642

652

181

1,261

9,676

9,678

1,298

449

528

1,066

1,650

1,651

174

182

122

(9)
(100)

11,407

(3)

11,404

1,479

628

542

1,148

15. Summarized Quarterly Financial Data (Unaudited)

(Amounts in millions,
except per share data)
Operating revenues
Operating income

Net income
EPS total — basic

EPS total — diluted

Cash dividends declared per
common share

(Amounts in millions,
except per share data)
Operating revenues
Operating income (a)

Net income

EPS total — basic

EPS total — diluted

Cash dividends declared per
common share

Quarter Ended

March 31,
2019

June 30,
2019

Sept. 30,
2019

Dec. 31,
2019

3,141

2,577

3,013

2,798

486

315
0.61

0.61

410

238
0.46

0.46

758

527
1.02

1.01

450

292
0.56

0.56

0.405

Quarter Ended

March 31,
2018

June 30,
2018

Sept. 30,
2018

Dec. 31,
2018

2,951

2,658

3,048

2,880

480

291

0.57

450

265

0.52

696

491

0.96

339

214

0.42

0.380

(a)

In 2018, Xcel Energy implemented ASU No. 2017-07 related to net periodic benefit cost,
which resulted in retrospective reclassification of pension costs from O&M expense to other
income.

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

ITEM 9B — OTHER INFORMATION

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, 2019, 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, 2019 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.

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 2020
Annual Meeting of Shareholders, which is expected to occur on April 6, 2020,
incorporated by reference. Information with respect to Executive Officers is
included in Item 1 to this report.

ITEM 11 — EXECUTIVE COMPENSATION

Information required under this Item is set forth in Xcel Energy Inc.’s Proxy
Statement for its 2020 Annual Meeting of Shareholders, which is incorporated
by reference.

ITEM 12 — SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS

Information required under this Item is contained in Xcel Energy Inc.’s Proxy
Statement for its 2020 Annual Meeting of Shareholders, which is incorporated
by reference.

ITEM 13 —
TRANSACTIONS, AND DIRECTOR INDEPENDENCE

RELATIONSHIPS AND

CERTAIN

Information required under this Item is contained in Xcel Energy Inc.’s Proxy
Statement for its 2020 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
definitive Proxy Statement for its 2020 Annual Meeting of Shareholders, which
is incorporated by reference.

PART IV

ITEM 15 — EXHIBITS, FINANCIAL STATEMENT SCHEDULES

Consolidated Financial Statements

Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2019.

Report of Independent Registered Public Accounting Firm — Financial Statements

Report of Independent Registered Public Accounting Firm — Internal Controls Over Financial Reporting

Consolidated Statements of Income — For the three years ended Dec. 31, 2019, 2018, and 2017.

Consolidated Statements of Comprehensive Income — For the three years ended Dec. 31, 2019, 2018, and 2017.

Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2019, 2018, and 2017.

Consolidated Balance Sheets — As of Dec. 31, 2019 and 2018.

Consolidated Statements of Common Stockholders’ Equity — For the three years ended Dec. 31, 2019, 2018, and 2017.

Schedule I — Condensed Financial Information of Registrant.

Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2019, 2018 and 2017.

Exhibits

Indicates incorporation by reference

Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

3.01*

3.02*

4.01

4.02*

4.03*

4.04*

4.06*

4.07*

4.08*

4.09*

4.10*

4.11*

4.12*

Xcel Energy Inc.

Exhibit
Number

Description

Amended and Restated Articles of Incorporation of Xcel Energy Inc.

Bylaws of Xcel Energy Inc.

Description of Securities

Report or Registration Statement

SEC File or
Registration
Number

Exhibit
Reference

Xcel Energy Inc Form 8-K dated May 16, 2012 001-03034

Xcel Energy Inc Form 8-K dated Feb. 17,
2016

001-03034

3.01

Indenture dated Dec. 1, 2000 between Xcel Energy Inc. and Wells Fargo Bank Minnesota, National
Association, as Trustee

Xcel Energy Inc. Form 8-K dated Dec. 14,
2000

001-03034

4.01

Supplemental Indenture No. 3 dated June 1, 2006 between Xcel Energy Inc. and Wells Fargo Bank,
National Association, as Trustee

Xcel Energy Inc. Form 8-K dated June 6, 2006 001-03034

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

Xcel Energy Inc. Form 8-K dated Jan. 16,
2008

Supplemental Indenture dated as of May 1, 2010 between Xcel Energy Inc. and Wells Fargo Bank,
National Association, as Trustee

Xcel Energy Inc. Form 8-K dated May 10,
2010

Supplemental Indenture No. 6, dated as of Sept. 1, 2011 between Xcel Energy Inc. and Wells Fargo Bank,
National Association, as Trustee

Xcel Energy Inc. Form 8-K dated Sept. 12,
2011

001-03034

4.01

001-03034

4.03

001-03034

4.01

001-03034

4.01

Supplemental Indenture No. 8, dated as of June 1, 2015 between Xcel Energy Inc. and Wells Fargo Bank,
National Association, as Trustee

Xcel Energy Inc. Form 8-K dated June 1, 2015 001-03034

4.01

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

001-03034

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 001-03034

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

001-03034

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

Xcel Energy Inc. Form 8-K dated Nov. 7, 2019 001-03034

4.01

10.01*

Xcel Energy Inc. Nonqualified Pension Plan (2009 Restatement)

10.02*+

Xcel Energy Senior Executive Severance and Change-in-Control Policy (2009 Restatement)

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

10.03*+

Xcel Energy Inc. Non-Employee Directors Deferred Compensation Plan as amended and restated Jan. 1,
2009

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

001-03034

10.02

001-03034

10.05

001-03034

10.08

10.04*+

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

10.05*+

Xcel Energy Inc. Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009

10.06*+

First Amendment to Exhibit 10.02 dated Aug. 26, 2009

Xcel Energy Inc. Form U5B dated Nov. 16,
2000

001-03034

H-1

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

001-03034

10.17

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

001-03034

10.06

001-03034

10.08

001-03034

Appendix
A

001-03034

10.07

001-03034

10.17

001-03034

10.18

001-03034

10.01

001-03034

10.02

001-03034

10.22

001-03034

10.02

001-03034

10.01

001-03034

10.01

001-03034

10.1

001-03034

10.30

10.07*+

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

10.08*+

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

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

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

10.09*+

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

Xcel Energy Inc. Definitive Proxy Statement
dated April 5, 2011

10.10*+

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

10.11*+

First Amendment to Exhibit 10.10 effective Nov. 29, 2011

10.12*+

Second Amendment to Exhibit 10.02 dated Oct. 26, 2011

10.13*+

First Amendment to Exhibit 10.08 dated Feb. 20, 2013

10.14*+

Fourth Amendment to Exhibit 10.02 dated Feb. 20, 2013

10.15*+

Second Amendment to Exhibit 10.10 dated May 21, 2013

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 March 31, 2013

Xcel Energy Inc. Form 10-K for the year
ended Dec. 31, 2013

10.16*+

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

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

10.17*+

Fifth Amendment Exhibit 10.02 dated May 3, 2016

10.18*+

Third Amendment to Exhibit 10.10 dated Sept. 30, 2016

10.19*+

Fourth Amendment to Exhibit 10.10 dated Oct. 23, 2017

10.20*+

Sixth Amendment to Exhibit 10.02 dated Feb. 22, 2018

10.21*+

Seventh Amendment to Exhibit 10.02 dated May 7, 2018

Xcel Energy Inc. Form 10-Q for the quarter
ended June 30, 2016

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, 2017

Xcel Energy Inc. Form 10-Q for the quarter
ended June 30, 2018

001-03034

10.01

10.22*

10.23*

Forward Sale Agreement, dated Nov. 7, 2018, between Xcel Energy Inc. and Morgan Stanley &Co., LLC

Xcel Energy Inc. Form 8-K dated Nov. 7, 2018 001-03034

Amended and Restated 364-Day Term Loan Agreement dated as of Dec. 4, 2018 among Xcel Energy Inc.,
as Borrower, the several lenders from time to time parties thereto, and MUFG Bank, Ltd. as Administrative
Agent.

Xcel Energy Inc. Form 8-K dated Dec. 4, 2018 001-03034

10.01

99.01

10.24*+

Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan

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

10.25*+

10.26*+

Form of Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement Terms and Conditions under the
Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan

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

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

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

001-03034

10.34

001-03034

10.35

001-03034

10.36

10.27*+

Brett Carter’s Sign-On Bonus Terms

10.28*

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

10.29*

Forward Sale Agreement, dated Oct. 30, 2019, between Xcel Energy Inc. and Citibank, N.A.

10.30*

Additional Forward Sale Agreement, dated Nov. 1, 2019 between Xcel Energy Inc. and Citibank, N.A.

10.31*

364-Day Term Loan Agreement dated Dec. 3, 2019 among Xcel Energy Inc., as Borrower, the several
lenders from time to time parties thereto, and Canadian Imperial Bank of Commerce, New York Branch, as
Administrative Agent

10.32+

Form of Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement Terms and Conditions under the
Xcel Energy Inc. Amended and Restated 2015 Omnibus Incentive Plan

Xcel Energy Inc. Form 10-Q for the quarter
ended March 31, 2019

001-03034

10.01

Xcel Energy Inc. Form 8-K dated June 7, 2019 001-03034

99.01

Xcel Energy Inc. Form 8-K dated Oct. 30,
2019

001-03034

10.01

001-03034

10.02

Xcel Energy Inc. Form 8-K dated Dec. 3, 2019 001-03034

10.01

NSP-Minnesota

4.13*

4.14*

4.15*

Supplemental and Restated Trust Indenture, dated May 1, 1988, from NSP-Minnesota to Harris Trust and
Savings Bank, as Trustee, providing for the issuance of First Mortgage Bonds, Supplemental Indentures
between NSP-Minnesota and said Trustee

Xcel Energy Inc. Form S-3 dated April 18,
2018

001-03034

4(b)(3)

Supplemental Trust Indenture dated June 1, 1995, creating $250 million principal amount of 7.125% First
Mortgage Bonds, Series due 2025

Xcel Energy Inc. Form 10-K for the year
ended Dec. 31, 2017

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

001-03034

4.11

001-03034

4.12

4.16*

Supplemental Trust Indenture dated Aug. 1, 2000 (Assignment and Assumption of Trust Indenture)

NSP-Minnesota Form 10-12G dated Oct. 5,
2000

000-31709

4.51

4.17*

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

001-03034

4(b)(7)

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*

10.33*

10.34*

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

000-31709

4.63

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 001-31387

4.01

NSP-Minnesota Form 8-K dated May 18, 2006 001-31387

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

001-31387

4.01

001-31387

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

001-31387

4.01

NSP-Minnesota Form 8-K dated Aug. 13,
2012

001-31387

4.01

NSP-Minnesota Form 8-K dated May 20, 2013 001-31387

4.01

NSP-Minnesota Form 8-K dated May 13, 2014 001-31387

4.01

NSP-Minnesota Form 8-K dated Aug. 11,
2015

001-31387

4.01

NSP-Minnesota Form 8-K dated May 31, 2016 001-31387

4.01

NSP-Minnesota Form 8-K dated Sept. 13,
2017

001-31387

4.01

Supplemental Trust Indenture dated as of Sept. 1, 2019 between Northern States Power Company and the
Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $600 million principal
amount of 2.90% First Mortgage Bonds, Series due 2050

NSP-Minnesota Form 8-K dated Sept. 10,
2019

001-31387

4.01

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

NSP-Wisconsin Form S-4 dated Jan. 21, 2004 333-112033

10.01

Third Amended and Restated Credit Agreement, dated as of June 7, 2019 among NSP-Minnesota, as
Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as
Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, Wells Fargo
Bank, National Association, MUFG Bank, Ltd., and Citibank, N.A., as Documentation Agents

Xcel Energy Inc. Form 8-K dated June 7, 2019 001-03034

99.02

NSP-Wisconsin

4.31*

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

001-03034

4(c)(3)

4.32*

Trust Indenture dated Sept. 1, 2000 between NSP-Wisconsin and Firstar Bank, NA as Trustee

NSP-Wisconsin Form 8-K dated Sept. 25,
2000

Supplemental Trust Indenture dated as of Sept. 1, 2003 between NSP-Wisconsin and U.S. Bank National
Association, supplementing indentures dated April 1, 1947 and March 1, 1991

Xcel Energy Inc Form 10-Q for the quarter
ended Sept. 30, 2003

001-03140

4.01

001-03034

4.05

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

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

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

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

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. 3, 2008 001-03140

4.01

NSP-Wisconsin Form 8-K dated Oct. 10, 2012 001-03140

4.01

NSP-Wisconsin Form 8-K dated June 23,
2014

001-03140

4.01

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

001-03140

4.01

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

001-03034

4.01

10.35*

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

NSP-Wisconsin Form S-4 dated Jan. 21, 2004 333-112033

10.01

4.33*

4.34*

4.35*

4.36*

4.37*

4.38*

10.36*

PSCo

4.39*

4.40*

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*

10.37*

10.38*

SPS

4.55*

4.56*

4.57*

4.58*

4.59*

4.60*

4.61*

4.62*

4.63*

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 001-03034

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

001-03034

4(d)(3)

Indenture dated July 1, 1999, between PSCo and The Bank of New York, providing for the issuance of
Senior Debt Securities and First Supplemental Indenture dated July 14, 1999 between PSCo and the Bank
of New York

Supplemental Indenture, dated Aug. 1, 2007 between PSCo and U.S. Bank Trust National Association, as
successor Trustee

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 May 1, 2009 between PSCo and U.S. Bank Trust National Association,
as successor Trustee, creating $400 million principal amount of 5.125% First Mortgage Bonds, Series due
2019

Supplemental Indenture dated as of Nov. 1, 2010 between PSCo and U.S. Bank National Association, as
successor Trustee, creating $400 million principal amount of 3.20% First Mortgage Bonds, Series due 2020

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

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

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

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

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

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

Proposed Settlement Agreement, excerpts, as filed with the CPUC

Third Amended and Restated Credit Agreement, dated as of June 7, 2019 among PSCo, as Borrower, the
several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent,
Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, Wells Fargo Bank, National
Association, MUFG Bank, Ltd., and Citibank, N.A., as Documentation Agents

PSCo Form 8-K dated July 13, 1999

001-03280

4.1
4.2

PSCo Form 8-K dated Aug. 8, 2007

001-03280

4.01

PSCo Form 8-K dated Aug. 6, 2008

001-03280

4.01

PSCo Form 8-K dated May 28, 2009

001-03280

4.01

PSCo Form 8-K dated Nov. 8, 2010

001-03280

4.01

PSCo Form 8-K dated Aug. 9, 2011

001-03280

4.01

PSCo Form 8-K dated Sept. 11, 2012

001-03280

4.01

PSCo Form 8-K dated March 26, 2013

001-03280

4.01

PSCo Form 8-K dated March 10, 2014

001-03280

4.01

PSCo Form 8-K dated May 12, 2015

001-03280

4.01

PSCo Form 8-K dated June 13, 2016

001-03280

4.01

PSCo Form 8-K dated June 19, 2017

001-03280

4.01

PSCo Form 8-K dated June 21, 2018

001-03280

4.01

PSCo Form 8-K dated March 13, 2019

001-03280

4.01

PSCo Form 8-K dated August 13, 2019

001-03280

4.01

Xcel Energy Inc. Form 8-K dated Dec. 3, 2004 001-03034

Xcel Energy Inc. Form 8-K dated June 7, 2019 001-03034

99.02

99.03

Indenture dated Feb. 1, 1999 between SPS and the Chase Manhattan Bank

SPS Form 8-K dated Feb. 25, 1999

Supplemental Indenture dated Oct. 1, 2003 between SPS and JPMorgan Chase Bank, as successor
Trustee, creating $100 million principal amount of Series C and Series D Notes, 6% due 2033

Xcel Energy Inc. Form 10-Q for the quarter
ended Sept. 30, 2003

001-03789

001-03034

99.2

4.04

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

001-03789

4.01

Indenture dated as of Aug. 1, 2011 between SPS and U.S. Bank National Association, as Trustee

SPS Form 8-K dated Aug. 10, 2011

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

001-03789

4.01

4.02

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

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

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

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 June 9, 2014

001-03789

4.02

SPS Form 8-K dated Aug. 12, 2016

001-03789

4.02

SPS Form 8-K dated Aug 9. 2017

001-03789

4.02

SPS Form 8-K dated Nov. 5, 2018

001-03789

4.02

4.64*

10.39*

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

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

SPS Form 8-K dated June 18, 2019

001-03789

4.02

Xcel Energy Inc. Form 8-K dated June 7, 2019 001-03034

99.04

Xcel Energy Inc.

21.01

23.01

24.01

31.01

31.02

32.01

Subsidiaries of Xcel Energy Inc.

Consent of Independent Registered Public Accounting Firm

Powers of Attorney

Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS

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

101.SCH XBRL Schema

101.CAL XBRL Calculation

101.DEF XBRL Definition

101.LAB XBRL Label

101.PRE XBRL Presentation

104

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

SCHEDULE I

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

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

Year Ended Dec. 31
2018

2019

2017

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 $3, respectively

Derivative instruments, net of tax of $(7), $(1) and $2,

respectively

Other comprehensive income (loss)
Comprehensive income

Weighted average common shares outstanding:

Basic
Diluted

Earnings per average common share:

Basic
Diluted

$ 1,505
1,505

$ 1,393
1,393

$ 1,263
1,263

23
(9)
173
187
1,318
(54)
$ 1,372

24
(1)
149
172
1,221
(40)
$ 1,261

30
(6)
128
152
1,111
(37)
$ 1,148

(20)

(2)

(17)
$ 1,355

1
$ 1,262

7
$ 1,155

519
520

511
511

509
509

2.64
2.64

2.47
2.47

2.26
2.25

Assets

Cash and cash equivalents

Accounts receivable from subsidiaries

Other current assets

Total current assets

Investment in subsidiaries

Other assets

Total other assets

Total assets

Liabilities and Equity

Dividends payable

Short-term debt

Other current liabilities

Total current liabilities

Other liabilities

Total other liabilities

Commitments and contingencies

Capitalization

Long-term debt

Common stockholders’ equity

Total capitalization

Total liabilities and equity

Dec. 31

2019

2018

370

452

17,443

17,503

17,955

212

500

745

3,948

13,239

17,187

17,955

309

311

15,965

16,009

16,320

195

488

693

3,373

12,222

15,595

16,320

See Notes to Condensed Financial Statements

Notes to Condensed Financial Statements

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

Year Ended Dec. 31
2018

2019

2017

Operating activities

Net cash provided by operating activities

$ 1,389

$ 1,210

$ 1,208

Investing activities

Capital contributions to subsidiaries

Investments in the utility money pool
Return of investments in the utility money pool

Net cash used in investing activities

Financing activities

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

Proceeds from issuance of long-term debt

Repayment of long-term debt

Proceeds from issuance of common stock

Repurchase of common stock

Dividends paid

Other

Net cash (used in) 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

(1,594)

(1,054)
1,093

(1,555)

(809)

(2,578)
2,493

(894)

(849)

(1,258)
1,173

(934)

1,120

(550)

458

—

(791)

(14)

235

(295)

492

—

230
(1)
(730)

(12)

(316)

—

715

—

(250)

—

(3)
(721)

(14)

(273)

—

See 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, 2019 and 2018, 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,
2019:

(Millions of Dollars)

Guarantor

Guarantee of loan for Hiawatha
Collegiate High School (a)

Xcel Energy
Inc.

Guarantee
Amount

Current
Exposure

Triggering
Event

1.0

—

Guarantee performance and

payment of surety bonds for
Xcel Energy Inc.’s utility
subsidiaries (b)

Xcel Energy
Inc.

60.4

(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 and payable 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.

2019

2018

Accounts
Receivable

Accounts
Payable

Accounts
Receivable

Accounts
Payable

60
17
78
47
112
25

— $
—
—
—
—
—

—

117
3
29
39
96
13

370

— $

309

—
—
—
—
—
—

—

Money Pool — FERC approval was received to establish a utility money pool
arrangement with the utility subsidiaries, subject to receipt of required state
regulatory approvals. The utility money pool allows for short-term investments
in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make
investments in the utility subsidiaries at market-based interest rates; however,
the money pool arrangement does not allow the utility subsidiaries to make
investments in Xcel Energy Inc.

Money pool lending for Xcel Energy Inc.:

(Amounts in Millions, Except Interest Rates)

Three Months Ended
Dec. 31, 2019

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

39
35

125

1.67%

1.63%

1.47%

(Amounts in Millions, Except
Interest Rates)

Year Ended
Dec. 31, 2019

Year Ended
Dec. 31, 2018

Year Ended
Dec. 31, 2017

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

250

2.15%

1.63%

Money pool interest income

1.0

— $

243

226

1.95%

1.13%

N/A

1.4

1.18

0.4

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

(Millions of Dollars)

Balance at Jan. 1

Additions charged to
costs and expenses

Additions charged to
other accounts

Deductions from
reserves

Allowance for bad debts

NOL and tax credit valuation
allowances

2019

$ 55

2018

$ 52

2017

$ 51

2019

$ 79

2018

$ 77

16 (a)

11 (a)

10 (a)

—

2017

$ 58

22 (c)

(58) (b)

(50) (b)

(48) (b)

(21) (e)

(5) (e)

(12) (d)

Balance at Dec. 31

$ 55

$ 52

$ 67

$ 79

$ 77

(a)

(b)

(c)

(d)

(e)

Recovery of amounts previously written off.
Deductions related primarily to bad debt write-offs.
Accrual of valuation allowances for North Dakota ITC, net of federal income tax benefit,
that is offset to a regulatory liability and includes $14 million expense related to the
revaluation of federal benefit as a result of the TCJA.
Primarily the reductions to valuation allowances for North Dakota ITC carryforwards, net
of federal benefit, primarily due to a consolidated adjustment to the regulatory liability
accrual referenced above; the change includes $4 million of reduced expense related to
the revaluation of federal benefit as a result of TCJA.
Primarily the reductions to valuation allowances due to additional NOLs and tax credits
now forecasted to be used prior to expiration.

Dividends — Cash dividends paid to Xcel Energy Inc. by its subsidiaries were
$2,987 million, $1,097 million and $1,063 million for the years ended Dec. 31,
2019, 2018 and 2017, respectively. These cash receipts are included in
operating cash flows of the condensed statements of cash flows.

ITEM 16 — FORM 10-K SUMMARY

None.

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed
on its behalf by the undersigned thereunto duly authorized.

Feb. 21, 2020

XCEL ENERGY INC.

By:

/s/ ROBERT C. FRENZEL

Robert C. Frenzel

Executive Vice President, Chief Financial Officer

(Principal 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/ ROBERT C. FRENZEL
Robert C. Frenzel

/s/ JEFFREY S. SAVAGE
Jeffrey S. Savage

Lynn Casey

Richard K. Davis

Richard T. O’Brien

David K. Owens

Christopher J. Policinski

James Prokopanko

A. Patricia Sampson

James J. Sheppard

David A. Westerlund

Kim Williams

Timothy V. Wolf

Daniel Yohannes

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

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

Senior Vice President, Controller
(Principal Accounting Officer)

Director

*By:

/s/ ROBERT C. FRENZEL
Robert C. Frenzel

Attorney-in-Fact