Fiscal Agents
XCEL ENERGY INC.
Transfer Agent, Registrar, Dividend
Distribution, Common Stock
Wells Fargo Shareowner Services,
1110 Centre Pointe Curve, Suite 101
Mendota Heights, MN 55120
Trustee – Bonds
Wells Fargo Bank, N.A., Corporate Trust Services
150 East 42nd Street, 40th Floor,
New York, NY 10017
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2016 Annual Report
ALWAYS DELIVERING.
xcelenergy.com | © 2017 Xcel Energy Inc. | Xcel Energy is a
registered trademark of Xcel Energy Inc. | 17-02-102
1 Xcel Energy | 2016
On the Cover
Wind towers twirl over the corn fields surrounding the Courtenay Wind Farm in North
Dakota. This is the first company-owned wind farm that Xcel Energy has built from the
ground up. The project generates electricity to power more than 100,000 homes and brought
significant economic development to Courtenay, North Dakota and the surrounding area.
Company Description
Xcel Energy is a major U.S. electric and natural gas company with annual revenues of
$11 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.
Financial Highlights
Xcel Energy Earnings Per Share
Dollars per share (diluted)
2015
2016
Total GAAP earnings per share
1.94
2.21
Ongoing earnings per share
2.09
2.21
Dividends annualized
1.28
1.36
Stock price (close)
35.91
40.70
Assets (millions)
38,821
41,155
Book value per common share
20.89
21.73
3
0
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2
3
0
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2
4
9
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1
9
0
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2
1
2
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2
1
2
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2
2014
2015
2016
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 Form 10-K.
Some sections in this annual report, including the letter to shareholders, contain forward-looking statements. For a discussion of factors
that could affect operating results, please see management’s discussion and analysis listed in the table of contents of the Form 10-K.
2 Xcel Energy | 2016
Shareholder Information
Headquarters
414 Nicollet Mall, Minneapolis, MN 55401
Website
xcelenergy.com
Stock Transfer Agent
Wells Fargo 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 New York Stock Exchange (NYSE) 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 Tara Stoffel, assistant corporate secretary,
at 612.215.5391 or email tara.m.heine@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 2016. It has also filed with the
New York Stock Exchange the CEO certification for 2016 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.
Xcel Energy Board of Directors
Gail Koziara Boudreaux 2, 4
CEO and Founder, GKB Global Health, LLC
Richard K. Davis 2,3
Chairman and CEO, U.S. Bancorp
Ben Fowke
Chairman, President and CEO
Xcel Energy Inc.
Richard T. O’Brien 1, 4
Independent Consultant
Christopher J. Policinski 3
Lead Independent Director
President and CEO
Land O’ Lakes, Inc.
James Prokopanko 1, 4
Retired President and CEO
The Mosaic Company
A. Patricia Sampson 1, 3
CEO, President and Owner
The Sampson Group, Inc.
James J. Sheppard 2, 4
Independent Consultant
David A. Westerlund 2, 3
Retired Executive Vice President,
Administration and Corporate Secretary
Ball Corporation
Kim Williams 1, 3
Retired Partner
Wellington Management Company LLP
Timothy V. Wolf 1, 4
President
Wolf Interests, Inc.
Daniel Yohannes*
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
* Joined board on March 1, 2017
Letter to Shareholders
Ben Fowke
Chairman, President and CEO
Ben Fowke is pictured in front of
Xcel Energy’s downtown Minneapolis
campus. The 401 Nicollet building (left
foreground) is a nine-story, energy-efficient
office space that opened in 2016.
Dear Fellow Shareholders:
Xcel Energy delivered excellent results in 2016
— financially, strategically and operationally.
Our performance continues the long tradition
of delivering value for our shareholders and
positions us for continued success in 2017
and beyond.
I am proud to work for this company and with
such dedicated and talented employees. The
phrase “Always Delivering” is one that rings
true throughout Xcel Energy, encapsulating
the important role we play powering millions
of business and residential customers every
day. It also reflects our deep commitment
to providing outstanding service to our
customers. We deliver safe, clean, reliable
energy at a competitive price. We respond to
our customers’ needs with new products and
solutions to help manage their energy use. We
quickly restore power when storms strike our
communities and damage the energy grid. And
we leverage technology to create efficiencies
and keep costs in check.
One measure of our success is financial
performance, and we delivered again in 2016,
continuing to provide strong shareholder
value. Xcel Energy delivered 2016 GAAP
and ongoing earnings of $2.21 per share,
compared with GAAP earnings of $1.94
per share, and ongoing earnings of $2.09
per share, in 2015, which marks the 12th
consecutive year we have met or exceeded
our ongoing earnings guidance.
Xcel Energy also increased your dividend 6.3
percent in 2016, marking the 13th consecutive
year of dividend growth. We maintained our
dividend growth guidance in the 5 to 7 percent
range, reflecting the ongoing confidence we
have in our ability to deliver for you.
Total shareholder return is another way we
measure performance; we posted a 17.1
percent return in 2016. Our three-year total
shareholder return is 62 percent, which
compares favorably to the overall utility sector.
With another successful year behind us and
strong momentum in place, we initiated 2017
earnings guidance of $2.25 to $2.35 per share.
As we kept close focus on the company’s
financial performance, Xcel Energy united
around a set of key priorities that matter most
to our stakeholders.
Delivering Long-Term Growth
During 2016, we continued to execute our
“steel for fuel” growth strategy, which locks
in long-term fuel savings for our customers
by building and owning wind farms at a time
when tax credits make this a significant value.
The approach takes advantage of the wind-
rich resources that are available in our service
territory and provides billions of dollars in fuel
savings, which offset the capital costs to build
Xcel Energy | 2016 3
the new wind generation and accompanying
transmission to bring renewable energy to
the marketplace.
Steel for fuel offers impressive economic and
environmental benefits that appeal to our
customers and shareholders and strengthens
our position as a low-cost energy provider. It is
a prudent way to reduce our carbon footprint
and transform our energy supply mix from fossil
fuels without raising prices for customers,
while simultaneously providing growth
opportunities for the company.
We made tremendous strides in 2016. Just
15 months after construction began, our
Courtenay Wind Farm in North Dakota became
fully operational. It is a testament to our ability
to successfully develop and construct wind
projects. In Colorado, we gained approval for
the Rush Creek Wind Project, a 600 megawatt
wind farm — one of the largest in the state —
that will break ground this year and will go into
service in 2018.
Over the next five years we are pursuing
several capital investment projects — including
a significant amount of large-scale renewables
— that would grow our rate base by 5.5
percent. To enhance reliability, we will continue
to invest in the electrical grid and be vigilant in
our efforts to protect it from cyber and physical
threats. An example is our Advanced Grid
Intelligence and Security proposal in Colorado
that will upgrade our communications platform,
improve security and reliability, and leverage
smart meters to provide customers more
choices in how they manage their energy use.
Our investments play a key role in driving
economic development through good jobs,
tax base and lease payments to land owners.
They also contribute growth opportunities for
you, our valued shareholders.
Engaging Stakeholders
We took our stakeholder engagement
efforts to new levels in 2016, resulting in
ground-breaking agreements in Colorado and
Over the next five years we are pursuing several
capital investment projects — including a significant
amount of large-scale renewables — that would
grow our rate base by 5.5 percent.
Minnesota. The company
is poised to implement one
of the state’s first multi-
year electric rate plans in
Minnesota and is testing
updated pricing designs
in Colorado. Through an
industry-leading resource plan
approved in Minnesota, Xcel
Xcel Energy entered into a supplier agreement
with Vestas, one of the largest wind turbine
manufacturers in the world. The partnership
ensures we have access to the “steel” needed
to fulfill our wind commitments and provides
additional tax credits for our customers. We
also announced plans to add 1,550 megawatts
of wind in the Upper Midwest and propose to
own approximately two-thirds of that capacity.
In addition, we are pursuing the potential
to add more than 1,000 megawatts of wind
power in Texas and New Mexico.
Energy will more than double its wind and
solar resources while retiring two coal-fueled
units, which would result in a 63 percent
carbon-free energy mix to the region by 2030.
Xcel Energy will launch a new customer
option, Renewable*Connect, in Minnesota
and Colorado to provide up to 100 percent
renewable energy that is certified. And finally,
a wide-reaching agreement was secured with
22 stakeholder groups in Colorado that will
expand the company’s rooftop and community
solar offerings and position the company
for ongoing stakeholder collaboration. The
agreement is one of the largest of its kind in
the state’s history.
Operational Excellence
and Industry Leadership
Fundamental to our business is providing
reliable service for our customers. We
continue to deliver on that promise, meeting
our energy reliability goals and delivering
industry-leading storm response when
customers need us the most. Xcel Energy was
recognized by the Edison Electric Institute
for our emergency response and power
restoration after a massive winter storm
struck communities in Texas and New Mexico
and interrupted service to tens of thousands
of our customers in December of 2015.
The Edison Electric Institute is an industry
association that represents all U.S. investor-
owned electric companies, which collectively
serve 220 million Americans.
Our public safety commitment is a
responsibility we take seriously. Our work
is especially visible as we upgrade natural
gas infrastructure and make repairs to our
power grid in the communities we serve.
Perhaps less visible, but just as important, is
our behind-the-scenes work as we employ
multi-faceted efforts to protect the electrical
grid from physical and cyber attacks. In 2016,
I was honored to be appointed to the National
Infrastructure Advisory Council, a group of
government, business and industry leaders
convened to advise the U.S. President and
government agencies on policies and strategies
that help to ensure our nation’s critical
infrastructure is secure.
Our employees and customers take pride
in Xcel Energy’s long-standing wind energy
leadership, and that continued in 2016 when
we were named the nation’s No. 1 utility wind
energy provider for the 12th consecutive year
by the American Wind Energy Association.
4 Xcel Energy | 2016
This achievement is a component of our efforts
to significantly reduce our carbon footprint by
increasing our large-scale renewable portfolio,
repowering existing facilities with more
carbon-friendly natural gas and maintaining
our nuclear, hydro and biomass operations.
Always Delivering
It is what we do: 24 hours a day, seven days
a week, 365 days a year.
We are proud to power the lives of millions
of people and to give back to the communities
we serve. Our record-setting United Way
campaign raised more than $3 million and
brought thousands of volunteer hours to
nonprofits throughout our service territory.
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We are unwavering in our commitment to
partner with stakeholders to build value —
whether it is delivering renewable energy,
expanding customer choices or making it
easier than ever to do business with us.
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We know that our business continues to evolve
and are well-positioned to deliver long-term
value regardless of the challenges triggered
by the rapid pace of change.
60
Once again, we appreciate the trust you place
in Xcel Energy. We don’t take it for granted as
we strive to deliver exceptional value for you
today and tomorrow. With your partnership,
our future is indeed very bright.
40
Sincerely,
2009
2016
Ben Fowke
Chairman, President and
Chief Executive Officer
THE ENVIRONMENT
New carbon target:
60 percent reduction by 2030
Xcel Energy’s carbon reduction story keeps getting better and better. Our
preliminary emissions reporting shows that we achieved a significant
milestone at the end of 2016, reducing our carbon emissions 30 percent
(from a 2005 baseline) four years ahead of schedule. Our latest projections,
based on proposed plans and projects in development, indicate that we will
achieve at least a 45 percent reduction in carbon emissions system wide
by 2021. Looking out further, we believe we can achieve a new target: a
60 percent system-wide carbon reduction by 2030. This goal is based on
our experience with emissions reductions, but will depend on favorable
economics and a supportive regulatory environment.
Xcel Energy’s successful carbon-reduction blueprint includes repowering
existing facilities with more carbon-friendly natural gas, adding significant
amounts of low-cost wind and solar energy and encouraging energy
efficiency through programs that saved more than a terawatt-hour of
electricity last year and generated more than $71 million in rebates for
business and residential customers.
We are now emitting significantly fewer carbon emissions — 27 million
tons per year — than we did in 2005. That’s the equivalent of removing
five million cars from the road for a year. As we transform our energy
portfolio, perhaps the most important part of the story is our ability to
reduce carbon emissions without adding costs. Overall, our energy supply
is more diverse and better for the environment at a competitive price for
our customers.
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By the end of this year, we will have retired 25 percent of the coal-fueled
generation we owned in 2005. Others are taking notice. In 2016, the
EPA, Center for Climate and Energy Solutions and The Climate Registry
presented Xcel Energy its Climate Leadership Award for excellence in
greenhouse gas management for our commitment and progress in reducing
carbon emissions.
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2010
2014
2011
30% Reduction in Carbon Emissions
2005-2016
2012
2013
2015
2016
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Xcel Energy | 2016 5
GROWTH STRATEGY
Wind investments provide
benefits for all stakeholders
According to the most recent census, only 45
people live in Courtenay, North Dakota, located
30 miles northeast of Jamestown. Despite its
small size, Courtenay is making a huge impact
on our efforts to deliver low-cost wind energy
to customers in the Upper Midwest.
Taking advantage of strong wind resources
in our backyard, in December we completed
construction of the Courtenay Wind Farm —
100 wind towers spinning above the farmland
surrounding Courtenay are now delivering
enough clean, renewable energy to power
100,000 average-sized homes annually.
carbon emissions, a successful journey we
started in 2005.
Construction of the wind farm also provided
significant economic development for the
area, including 200 construction jobs, eight
permanent jobs and $850,000 in annual
tax revenue. Participating landowners will
collectively receive $26.5 million in lease
payments over the next 20 years.
By completing Courtenay and bringing online
the Odell Wind Farm, a third-party development
in southwestern Minnesota, we met our
commitment to increase wind capacity 42
By completing Courtenay and bringing online the Odell
Wind Farm, we met our 2013 commitment to increase
wind capacity 42 percent in the Upper Midwest by the
end of 2016.
percent in the Upper Midwest
by the end of 2016. Both
projects take advantage of the
CapX2020 transmission system
upgrade to deliver renewable
energy to the marketplace.
We’ve enjoyed our leadership
position as the nation’s No. 1
utility wind energy provider for
12 consecutive years and have approved plans
to grow our wind portfolio. Among the biggest
success stories in 2016 was the speed at
which we gained approval for the Rush Creek
Wind Project in Colorado, taking advantage
of federal production tax credits before they
begin to phase out in 2017. This effort required
significant stakeholder outreach, planning and
execution by a large team. Construction of the
600-megawatt project — one of the largest
in Colorado — will begin this year. When
completed in 2018, Rush Creek will deliver
enough energy to power 325,000 homes.
In addition to Rush Creek, we filed plans
to add 1,550 megawatts of wind capacity
in the Upper Midwest, two-thirds of which
we plan to own. In Texas and New Mexico,
we have proposed adding more than 1,000
megawatts of wind energy.
Historically, the source of most of our
wind energy was through power purchase
agreements with independent wind farms.
We also acquired four wind projects that were
developed, constructed and commissioned by
a third party before the ownership transferred
to us. The Courtenay Wind Farm is significant
because we managed the project through
construction as part of our “steel for fuel”
growth strategy.
We are delivering excellent value by providing
shareholder growth opportunities and locking
in low wind prices for years to come, saving our
customers billions of dollars. Those fuel savings
more than offset the capital costs to build the
wind farms and associated transmission lines,
which positions us to transition from fossil
fuels to renewable energy at no extra cost
to our customers. Finally, adding more wind
resources is what our customers expect and
is part of our blueprint to significantly reduce
6 Xcel Energy | 2016
Wind forecasting expertise
Integrating wind energy onto our system requires sophisticated wind
forecasting expertise that we developed in conjunction with the National
Center for Atmospheric Research and its affiliate company, Global Weather
Corp. We rely on forecasting to more accurately predict the energy produced
at our wind farms each hour of every day. These forecasts allow us to ensure
reliability and even power down fossil fuel plants on windy days, which
benefits the environment and saves money. Since 2009, our wind forecast
integration strategy has generated more than $60 million in fuel savings
for our customers.
Project Engineer Zach Smith, one of eight full-time
employees who work at the Courtenay Wind Farm,
inspects a wind tower. The 200-megawatt wind farm
was fully operational in December.
Xcel Energy | 2016 7
More than 450,000 solar panels
harvest the sun near Pueblo, Colorado.
Comanche Solar, one of five universal
solar projects brought online in 2016,
is the largest solar project east of
the Rockies.
SOLAR ENERGY
Large-scale solar projects deliver the best customer value
Perhaps the most visibly striking example of
our changing energy supply mix lies outside
Pueblo, Colorado. On a large parcel of land
south of the city, traditional and renewable
energy sources sit side by side against the
backdrop of the Rocky Mountains.
the sun’s energy as it crosses the sky. The
facility, which was completed and connected
to the energy grid in 2016, provides 120
megawatts of energy, enough to power
31,000 homes. Xcel Energy has an agreement
to purchase solar energy from the facility
We expect to add more large-scale solar and quadruple
our solar portfolio over the next four years.
for the next 25 years.
Comanche Solar showcases
our commitment to pursue
large-scale solar projects
that take advantage of
For decades, the site has been the home to
Comanche Station, a three-unit, coal-fueled
power plant and accompanying substation
that provides electricity to approximately one-
third of our Colorado communities. Comanche
now has a new neighbor occupying 900 acres.
Not just any neighbor, but the largest solar
project east of the Rockies. Row after row of
solar panels — more than 450,000 in total —
move in tandem at Comanche Solar to harvest
economies of scale to deliver the best value
for our customers. In 2016, we brought
five large-scale solar projects online: two
in Minnesota, two in New Mexico and
Comanche in Colorado. Those five projects
take advantage of strong solar resources
in our service territories and generate 462
megawatts of energy for our customers. In
contrast, our large-scale solar portfolio was
192 megawatts at the end of 2015.
8 Xcel Energy | 2016
As the price of solar continues to fall, we
expect to add more large-scale solar and
quadruple our solar portfolio over the next four
years. We also provide programs that support
rooftop solar for customers and partner with
community solar garden developers to provide
options for customers who can’t or don’t want
to invest in rooftop solar.
In 2016, we launched Solar*Connect
CommunitySM, a new solar garden program
in Wisconsin that gives businesses and
residents the ability to subscribe to the
program at various levels and receive a
credit on their Xcel Energy bill. The Wisconsin
commission approved our proposal to build
two community solar gardens, one in the
greater La Crosse area and the other in
Eau Claire, across the street from our
Wisconsin office on the site of a former
landfill. Both solar gardens have nearly sold
out; construction will begin in 2017.
NUCLEAR ENERGY
In continual pursuit of operational excellence
Our plans to generate at least 50 percent
carbon-free energy by 2021 are contingent
upon adding significant amounts of renewable
energy, repowering aging coal plants with
natural gas and maintaining our nuclear fleet.
Nuclear energy remains the most reliable
24/7/365, carbon-free energy source available
to us, accounting for about 13 percent of our
energy mix at the end of 2016.
We are committed to operating our
Minnesota-based nuclear facilities at Prairie
Island and Monticello through their licensing
periods, which expire in the early 2030s. We
are participating in ongoing dialogue with our
state regulators about the long-term future of
these generating plants and their importance
in achieving our carbon-reduction targets.
The best way to prove value to our regulators
is to operate our nuclear fleet effectively
and efficiently. In 2016, we saw improved
performance at both locations.
Monticello broke a generation
record last year, proving
the value of our 2015 plant
expansion, and received an
“exemplary” rating from the
Institute of Nuclear Power Operations, an
independent verification of our safety and
operational excellence.
At Prairie Island, we completed a safe and
successful refueling of Unit 1. It was the 30th
refueling of the unit overall and the fastest
in 25 years. This major undertaking, which
included several simultaneous infrastructure
upgrades, was a well-orchestrated, 36-day
project that included 95,000 work hours
logged by employees and contractors.
Monticello broke a generation record last year,
proving the value of our 2015 plant expansion.
By achieving operational excellence on a daily
basis and especially during planned refueling
outages, we are keeping costs in check,
which delivers value for our shareholders and
complements the reliability our customers
have come to expect.
In 2016, we completed the fastest, most-successful
refueling of Prairie Island Unit 1 in 25 years. Pictured
is the inside of the empty reactor core, filled with
water and ready to be refueled. This huge undertaking
brought hundreds of specialized workers on site and
packed 95,000 work hours into just over a month’s
time. Refueling required excellent coordination and
stimulated economic development in and around
Red Wing, Minnesota.
Xcel Energy | 2016 9
John Marshall, Community and Government Relations
manager (left), stands by the new gas regulator station
at Lexington Parkway in St. Paul. He is joined by Kathy
Lantry, director of Public Works for the city, council
members Rebecca Noecker and Dai Thao (right), and
Bill Marka (blue shirt), who worked on the project.
Xcel Energy partnered with the city to save 181
mature boulevard trees, pictured in the background.
Xcel Energy will construct a building around the
regulator station to blend in with the neighborhood.
Above: This pipeline is part of an 11.5-mile upgrade to
enhance reliability and public safety.
10 Xcel Energy | 2016
NATURAL GAS
Partnering with stakeholders to
keep our cities safe and beautiful
“Every time Xcel Energy works on an
infrastructure project, they leave the city in a
better place than when they started working.”
That’s the assessment from Kathy Lantry,
director of Public Works for the city of
St. Paul. She was particularly pleased
with Xcel Energy’s efforts to save 181
mature boulevard trees from demolition
during a major project to upgrade part of
the city’s natural gas infrastructure, which
serves about 400,000 people.
Xcel Energy’s Community and Government
Relations manager for the city. “We do
everything possible to over communicate
and make sure the experience is the least
disruptive for the city, its businesses and
residents. The affected residents appreciated
the community meetings, mailings, personal
updates and the extra special touches, like
delivering their mail. Some of the residents
even made cookies and meals for our workers
to show their appreciation.”
“ Ensuring the safety of the public and our employees
is our number one priority,” said Cheryl Campbell,
senior vice president, Natural Gas. “I’m really proud
of how our team members worked together to
get the job done for our communities and ensure
reliability for years to come.”
As part of the East Metro
project to replace the original
pipeline installed in the 1940s
and ‘50s, we installed 11.5
miles of 20-inch natural gas
pipeline through the heart
of the capital city — a tall
order considering the tight
deadline and nearly constant
traffic flow in a dense urban
area where a majority of the
construction work was needed.
Before the construction phase began and
throughout the project, we conducted
extensive outreach with numerous
stakeholders, including city management
staff and council members, business owners
and residents. Goals for the project were
enhanced public safety, limited traffic and
business disruption and a creative solution
to save century-old honey locust trees on
Lexington Parkway from being uprooted during
the construction of a nearby regulator station.
To enhance public safety, the project took
advantage of two new technologies: in-line
inspection capability and remote-controlled
valves that enable the company to proactively
make needed repairs in the future.
“The city of St. Paul is one of our oldest and
largest customers,” said John Marshall,
West Main Upgrade
In 2016, we also completed a large, multi-year
infrastructure upgrade in northern Colorado
called the West Main project, which replaced
aging pipeline to meet expansive growth and
provide the reliable service our customers
have come to expect. The project replaced
approximately 95 miles of 1920s-vintage
transmission pipeline in similar challenging
areas. Our team worked collaboratively with
local communities to minimize negative
impacts from the project and received similar
positive feedback from those communities.
“Ensuring the safety of the public and our
employees is our number one priority,”
said Cheryl Campbell, senior vice president,
Natural Gas. “I’m really proud of how our
team members worked together to get the
job done for our communities and ensure
reliability for years to come.”
Xcel Energy | 2016 11
Xcel Energy is partnering with
Panasonic to test battery storage
capabilities. Energy collected from
solar panels on the carport rooftop
is stored in a large battery system
on site. In the event of a grid outage,
the batteries will form a microgrid to
power essential Panasonic systems.
INNOVATIVE SOLUTIONS
Panasonic partnership testing battery storage capabilities
As the price of battery storage continues to
fall, we are closely studying this emerging
technology to determine the best ways to
Enterprise Solutions Company agreed to
relocate its headquarters to Denver with the
goal of developing a showcase sustainable
We entered into a unique partnership to study how batteries
can help integrate renewable energy into the grid.
community. Xcel Energy
and Panasonic formed a
partnership to study the
multiple ways in which the
electric grid can benefit from
battery storage, including the integration of
a high penetration of distributed renewable
energy production, peak demand reduction
and voltage irregularity mitigation.
Xcel Energy will own and operate a battery
storage system at Panasonic’s headquarters
building near Pena Station, a transit hub
close to DIA. The system will be “grid tied,”
connected on the utility’s side of the meter. The
lithium ion battery system will help with the
integration of a 1.3-megawatt solar installation.
A compelling feature of the project is the
system’s ability to form a microgrid. In the
event of a grid outage, the Panasonic building
will be disconnected or “islanded” from the
grid. The battery system will then provide
power directly to the building, enabling
the continued operation of critical loads.
Panasonic’s own rooftop solar array can then
continue to power the building and recharge
the battery with any excess generation.
The two-year Panasonic battery demonstration
project is a Colorado Innovative Clean
Technology program approved by the Colorado
Public Utilities Commission that encourages us
to test emerging energy technologies that can
potentially lower greenhouse gas emissions
and provide other environmental benefits.
The pilot will determine if the program is cost
effective and ready to be deployed more widely.
utilize batteries to manage the electrical
grid, enhance service and maximize value
for our customers.
In 2016, we entered into a unique partnership
with two customers, Panasonic and Denver
International Airport (DIA), to study how
batteries can help integrate renewable energy
into the grid and provide critical backup power
during a grid outage.
As part of an economic development
package for the city of Denver, Panasonic
12 Xcel Energy | 2016
EMERGING TECHNOLOGY
Drones: The sky’s the limit with FAA partnership
Imagine a future when unmanned aircraft
systems fly in the aftermath of severe storms
to assess utility infrastructure damage and
improve disaster response times. That exciting
future is on our radar.
We are participating in an industry-leading
research study with the University of North
Dakota and several strategic partners to
prove to the Federal Aviation Administration,
industry trade groups and other regulators that
unmanned aircraft systems, commonly called
drones, can be effective tools to enhance
safety, reduce outage restoration times and
deliver value and efficiencies for our customers.
A key component in the research study is the
Hermes 450, a fixed-wing unmanned aircraft
with a 35-foot wingspan operated by Elbit
Systems of America. Equipped with lights so
it can record data at night, the large drone can
inspect up to 25,000 acres an hour and remain
in flight for 17 hours.
The Hermes 450 and a smaller drone, both
equipped with multiple sensors, cameras
and the ability to send live video to our
operations headquarters, successfully
located downed utility poles during multiple
test flights near Mayville, North Dakota.
We are integrating the simulated data
into our computer systems with the goal
of achieving much-faster storm response
times. The data will tell us exactly how much
damage has occurred so we can deploy the
proper resources to the exact locations,
which will speed up the restoration process.
We began using drone technology in 2013
to inspect boilers, heat recovery steam
generators and scrubber
modules in our electric
generating plants. The use of
drones expanded with several
proof of concept missions
outdoors. In February 2016,
we became the first utility in the country to
receive FAA approval to fly drones beyond
line of sight to inspect a transmission line
northwest of Amarillo, Texas.
As a result of early missions, employee
involvement, executive support and a collective
vision established in the formation of our
Unmanned Aircraft Systems Program Office,
We have used drone technology to inspect everything
from natural gas pipelines to wind turbines.
together with the FAA, we announced in early
2017 a first-of-its-kind “Partnership for Safety
Plan.” The partnership establishes a working
relationship that will facilitate the use of
unmanned aircraft systems in the National
Airspace System. We plan to use drones to
inspect 20,000 miles of transmission lines
throughout our geographically diverse service
territory. This collaborative partnership will help
us safeguard the energy grid and help shape
future rules and regulations for other utilities.
We have used drone technology to inspect
everything from natural gas pipelines to wind
turbines. Regardless of the application, the
use of drones has consistently been faster,
safer and less expensive than traditional
inspections. The program is part of our efforts
to implement technology at the speed of value
to benefit our customers.
Xcel Energy is participating in a
research study with the University
of North Dakota and other partners
to test the use of drones to improve
disaster response times. The Hermes
450 is shown during a test flight near
Mayville, North Dakota.
Xcel Energy | 2016 13
High-tech simulators and outdoor training yards
are helping employees prepare for real-life
job scenarios. As part of our commitment to
employee safety and development, Xcel Energy
recently upgraded and expanded the Amarillo
Technical Center, a Texas facility that trains line
workers, electricians, substation technicians
and heavy equipment operators.
A safe and supportive workplace
A Commitment to Veterans
Like many companies, Xcel Energy is seeing
its workforce transition as baby boomers
are reaching retirement age. To meet this
workforce challenge, Xcel Energy is turning to
our military veterans. Military veterans bring
the values and commitment to the workforce
that we need — leadership, teamwork and
dedication. Our military veteran hiring strategy
continues to gain traction. In 2016, 14 percent
of our external hires were military veterans,
essentially double the result of two years prior.
At Amarillo, and similar facilities across our
service territories, we provide 144 hours of
training per apprentice every year and ongoing
training for experienced journeyman workers.
The expanded Amarillo Technical Center
teaches job skills and employee safety
using outdoor equipment and high-tech
simulators.
“Safety is the most important value for our
employees — it’s embedded in our culture,”
said Gary Lakey, vice president, Safety and
Workforce Relations.
Nearly a decade ago, Xcel Energy embarked
on our “Journey to Zero,” an ongoing effort to
eliminate workplace injuries. We continue to
make strong progress — 2016 was the second-
best safety year in the history of the company.
Xcel Energy is recognized each year for our
strong military culture. In December, G.I. Jobs
magazine awarded us the Military Friendly
Employer “Gold Status.” The Employer Support
of the Guard and Reserves bestowed its
highest state-level honor, the Pro Patria award,
for excellent support of military veterans and
active-duty employees who continue to serve
our country. We were the only large company
based in Minnesota to win the award in 2016.
A tradition of community support
At Xcel Energy, the cities and towns we serve
represent more than just our service territory.
It’s where our employees live and work, raise
their families and give back to the community.
Our employees have a strong tradition of
volunteerism and charitable giving.
Xcel Energy collectively contributed nearly
50,000 volunteer hours in 2016, delivering
meals for homebound seniors, stocking food
shelves, mentoring students, building houses
and so much more. Xcel Energy encourages
volunteerism by offering employees the ability
to take paid time off to volunteer at a charity
and by organizing events. In a single day in
September, our employees once again rallied
for our annual Day of Service and collectively
contributed more than 10,000 volunteer hours.
Thanks to the generosity of our employees
in eight states, Xcel Energy delivered a
record-breaking United Way campaign in
2016, topping the $3 million threshold for
the first time. Those contributions, boosted
by the company campaign match, will provide
nearly a $6 million impact to strengthen
our communities.
14 Xcel Energy | 2016
The company also supports many nonprofit
organizations committed to improving
our communities through the Xcel Energy
Foundation and other giving programs. Last
year the foundation distributed $3.9 million in
grants to approximately 350 nonprofits, and
our employees donated nearly $700,000 to
support 1,100 nonprofit organizations. Another
$640,000 was contributed by Xcel Energy
through our matching gifts program.
One of those grants is helping to drive
economic development in downtown Eau
Claire, Wisconsin. In conjunction with our 2016
Annual Meeting, the Xcel Energy Foundation
presented a unique, one-time $250,000 gift to
fund the economic development in downtown
Eau Claire. The Confluence project will feature
a performing arts center shared by the city and
the University of Wisconsin-Eau Claire. Our
roots in the community date back to 1872.
A team of Xcel Energy United Way volunteers.
Photo by J.L. “Bob” Zaragoza
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2016
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 001-3034
Xcel Energy Inc.
(Exact name of registrant as specified in its charter)
Minnesota
(State or other jurisdiction of incorporation or organization)
41-0448030
(I.R.S. Employer Identification No.)
414 Nicollet Mall
Minneapolis, MN 55401
(Address of principal executive offices)
Registrant’s telephone number, including area code: 612-330-5500
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, $2.50 par value per share
Securities registered pursuant to section 12(g) of the Act: None
Title of each class
Name of each exchange on which registered
New York Stock Exchange
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 and posted on its corporate Website, if any, every Interactive
Data File required to be submitted and posted pursuant to Rule 405 and 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 and post such files).
Yes
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained
herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference
in Part III of this Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller
reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act.
Smaller Reporting Company
Non-accelerated filer (Do not check if a smaller reporting company)
Large accelerated filer
Accelerated filer
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes
No
As of June 30, 2016, the aggregate market value of the voting common stock held by non-affiliates of the Registrants was
$22,746,126,160 and there were 507,952,795 shares of common stock outstanding.
As of Feb. 20, 2017, there were 507,222,795 shares of common stock outstanding, $2.50 par value.
DOCUMENTS INCORPORATED BY REFERENCE
The Registrant’s Definitive Proxy Statement for its 2017 Annual Meeting of Shareholders is incorporated by reference into Part III of this
Form 10-K.
Index
TABLE OF CONTENTS
PART I
Item 1 — Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
COMPANY OVERVIEW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ELECTRIC UTILITY OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NSP-Minnesota. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NSP-Wisconsin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PSCo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Summary of Recent Federal Regulatory Developments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Electric Operating Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NATURAL GAS UTILITY OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NSP-Minnesota. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NSP-Wisconsin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PSCo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural Gas Operating Statistics. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
GENERAL. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ENVIRONMENTAL MATTERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CAPITAL SPENDING AND FINANCING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EMPLOYEES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EXECUTIVE OFFICERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1A — Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1B — Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 2 — Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 3 — Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 4 — Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART II
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 6 — Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . .
Item 7A — Quantitative and Qualitative Disclosures About Market Risk. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 8 — Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
1
5
7
7
13
14
19
23
25
26
27
28
29
30
31
31
32
32
32
33
34
42
43
45
45
45
47
48
75
75
146
146
146
146
146
146
147
147
147
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
160
Item 1 — Business
PART I
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
Capital Services . . . . . . . . . . . Capital Services, LLC
Eloigne . . . . . . . . . . . . . . . . . . Eloigne Company
NCE . . . . . . . . . . . . . . . . . . . . New Century Energies, 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 . . . . . . . NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
PSCo. . . . . . . . . . . . . . . . . . . . Public Service Company of Colorado
SPS . . . . . . . . . . . . . . . . . . . . . Southwestern Public Service Co.
Utility subsidiaries . . . . . . . . . NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
WGI . . . . . . . . . . . . . . . . . . . . WestGas InterState, Inc.
WYCO . . . . . . . . . . . . . . . . . . WYCO Development, LLC
Xcel Energy . . . . . . . . . . . . . . Xcel Energy Inc. and its subsidiaries
XETD . . . . . . . . . . . . . . . . . . . Xcel Energy Transmission Development Company, LLC
XEST . . . . . . . . . . . . . . . . . . . Xcel Energy Southwest Transmission Company, LLC
XEWT . . . . . . . . . . . . . . . . . . Xcel Energy West Transmission Company, LLC
Federal and State Regulatory Agencies
ASLB . . . . . . . . . . . . . . . . . . . Atomic Safety and Licensing Board
CFTC . . . . . . . . . . . . . . . . . . . Commodity Futures Trading Commission
CPUC . . . . . . . . . . . . . . . . . . . Colorado Public Utilities Commission
D.C. Circuit . . . . . . . . . . . . . . United States Court of Appeals for the District of Columbia Circuit
DOC . . . . . . . . . . . . . . . . . . . . Minnesota Department of Commerce
DOE . . . . . . . . . . . . . . . . . . . . United States Department of Energy
DOT . . . . . . . . . . . . . . . . . . . . United States Department of Transportation
EPA. . . . . . . . . . . . . . . . . . . . . United States Environmental Protection Agency
FERC . . . . . . . . . . . . . . . . . . . Federal Energy Regulatory Commission
IRS . . . . . . . . . . . . . . . . . . . . . Internal Revenue Service
MPCA. . . . . . . . . . . . . . . . . . . Minnesota Pollution Control Agency
MPSC . . . . . . . . . . . . . . . . . . . Michigan Public Service Commission
MPUC. . . . . . . . . . . . . . . . . . . Minnesota Public Utilities Commission
NDPSC . . . . . . . . . . . . . . . . . . North Dakota Public Service Commission
NERC . . . . . . . . . . . . . . . . . . . North American Electric Reliability Corporation
NMPRC . . . . . . . . . . . . . . . . . New Mexico Public Regulation Commission
NRC . . . . . . . . . . . . . . . . . . . . Nuclear Regulatory Commission
PHMSA . . . . . . . . . . . . . . . . . Pipeline and Hazardous Materials Safety Administration
PNM . . . . . . . . . . . . . . . . . . . . Public Service Company of New Mexico
PSCW . . . . . . . . . . . . . . . . . . . Public Service Commission of Wisconsin
PUCT . . . . . . . . . . . . . . . . . . . Public Utility Commission of Texas
SDPUC . . . . . . . . . . . . . . . . . . South Dakota Public Utilities Commission
SEC. . . . . . . . . . . . . . . . . . . . . Securities and Exchange Commission
1
Electric, Purchased Gas and Resource Adjustment Clauses
CIP . . . . . . . . . . . . . . . . . . . . . Conservation improvement program
DCRF . . . . . . . . . . . . . . . . . . . Distribution cost recovery factor
DSM . . . . . . . . . . . . . . . . . . . . Demand side management
DSMCA . . . . . . . . . . . . . . . . . Demand side management cost adjustment
ECA . . . . . . . . . . . . . . . . . . . . Retail electric commodity adjustment
EE . . . . . . . . . . . . . . . . . . . . . . Energy efficiency
EECRF . . . . . . . . . . . . . . . . . . Energy efficiency cost recovery factor
EIR . . . . . . . . . . . . . . . . . . . . . Environmental improvement rider (recovers the costs associated with investments in
environmental improvements to fossil fuel generation plants)
EPU . . . . . . . . . . . . . . . . . . . . Extended power uprate
ERP. . . . . . . . . . . . . . . . . . . . . Electric resource plan
FCA . . . . . . . . . . . . . . . . . . . . Fuel clause adjustment
FPPCAC . . . . . . . . . . . . . . . . . Fuel and purchased power cost adjustment clause
GCA . . . . . . . . . . . . . . . . . . . . Gas cost adjustment
GUIC . . . . . . . . . . . . . . . . . . . Gas utility infrastructure cost rider
PCCA . . . . . . . . . . . . . . . . . . . Purchased capacity cost adjustment
PCRF . . . . . . . . . . . . . . . . . . . Power cost recovery factor (recovers the costs of certain purchased power costs)
PGA . . . . . . . . . . . . . . . . . . . . Purchased gas adjustment
QSP. . . . . . . . . . . . . . . . . . . . . Quality of service plan
RDF . . . . . . . . . . . . . . . . . . . . Renewable development fund
RER . . . . . . . . . . . . . . . . . . . . Renewable energy rider
RES. . . . . . . . . . . . . . . . . . . . . Renewable energy standard (recovers the costs of new renewable generation)
RESA . . . . . . . . . . . . . . . . . . . Renewable energy standard adjustment
SCA . . . . . . . . . . . . . . . . . . . . Steam cost adjustment
TCA . . . . . . . . . . . . . . . . . . . . Transmission cost adjustment
TCR . . . . . . . . . . . . . . . . . . . . Transmission cost recovery adjustment
TCRF . . . . . . . . . . . . . . . . . . . Transmission cost recovery factor (recovers transmission infrastructure improvement costs
and changes in wholesale transmission charges)
Other Terms and Abbreviations
AFUDC . . . . . . . . . . . . . . . . . Allowance for funds used during construction
ATM . . . . . . . . . . . . . . . . . . . . At-the-market
ALJ . . . . . . . . . . . . . . . . . . . . . Administrative law judge
APBO . . . . . . . . . . . . . . . . . . . Accumulated postretirement benefit obligation
ARO . . . . . . . . . . . . . . . . . . . . Asset retirement obligation
ASU . . . . . . . . . . . . . . . . . . . . FASB Accounting Standards Update
BART . . . . . . . . . . . . . . . . . . . Best available retrofit technology
C&I. . . . . . . . . . . . . . . . . . . . . Commercial and Industrial
CAA . . . . . . . . . . . . . . . . . . . . Clean Air Act
CACJA . . . . . . . . . . . . . . . . . . Clean Air Clean Jobs Act
CAIR . . . . . . . . . . . . . . . . . . . Clean Air Interstate Rule
CapX2020. . . . . . . . . . . . . . . . Alliance of electric cooperatives, municipals and investor-owned utilities in the upper
Midwest involved in a joint transmission line planning and construction effort
CCN . . . . . . . . . . . . . . . . . . . . Certificate of convenience and necessity
CIG . . . . . . . . . . . . . . . . . . . . . Colorado Interstate Gas Company, LLC
CO2 . . . . . . . . . . . . . . . . . . . . . Carbon dioxide
2
CON . . . . . . . . . . . . . . . . . . . . Certificate of need
CPCN . . . . . . . . . . . . . . . . . . . Certificate of public convenience and necessity
CPP. . . . . . . . . . . . . . . . . . . . . Clean Power Plan
CSAPR . . . . . . . . . . . . . . . . . . Cross-State Air Pollution Rule
CWIP . . . . . . . . . . . . . . . . . . . Construction work in progress
EEI . . . . . . . . . . . . . . . . . . . . . Edison Electric Institute
EGU . . . . . . . . . . . . . . . . . . . . Electric generating unit
EPS . . . . . . . . . . . . . . . . . . . . . Earnings per share
ERCOT. . . . . . . . . . . . . . . . . . Electric Reliability Council of Texas
ETR . . . . . . . . . . . . . . . . . . . . Effective tax rate
FASB . . . . . . . . . . . . . . . . . . . Financial Accounting Standards Board
FIP . . . . . . . . . . . . . . . . . . . . . Federal implementation plan
FTR. . . . . . . . . . . . . . . . . . . . . Financial transmission right
GAAP . . . . . . . . . . . . . . . . . . . Generally accepted accounting principles
GHG . . . . . . . . . . . . . . . . . . . . Greenhouse gas
Golden Spread . . . . . . . . . . . . Golden Spread Electric Cooperative, Inc.
HTY . . . . . . . . . . . . . . . . . . . . Historic test year
IM . . . . . . . . . . . . . . . . . . . . . . Integrated market
IPP . . . . . . . . . . . . . . . . . . . . . Independent power producers
ISFSI. . . . . . . . . . . . . . . . . . . . Independent Spent Fuel Storage Installation
ITC . . . . . . . . . . . . . . . . . . . . . Investment Tax Credit
LCM . . . . . . . . . . . . . . . . . . . . Life cycle management
LLW . . . . . . . . . . . . . . . . . . . . Low-level radioactive waste
LNG . . . . . . . . . . . . . . . . . . . . Liquefied natural gas
MGP . . . . . . . . . . . . . . . . . . . . Manufactured gas plant
MISO . . . . . . . . . . . . . . . . . . . Midcontinent Independent System Operator, Inc.
Moody’s . . . . . . . . . . . . . . . . . Moody’s Investor Services
MYP . . . . . . . . . . . . . . . . . . . . Multi-year plan
NAAQS . . . . . . . . . . . . . . . . . National Ambient Air Quality Standard
Native load . . . . . . . . . . . . . . . Customer demand of retail and wholesale customers that a utility has an obligation to serve
under statute or long-term contract
NAV . . . . . . . . . . . . . . . . . . . . Net asset value
NOL . . . . . . . . . . . . . . . . . . . . Net operating loss
NOx . . . . . . . . . . . . . . . . . . . . Nitrogen oxide
NOV . . . . . . . . . . . . . . . . . . . . Notice of violation
NTC . . . . . . . . . . . . . . . . . . . . Notifications to construct
NYISO . . . . . . . . . . . . . . . . . . New York Independent System Operator
O&M . . . . . . . . . . . . . . . . . . . Operating and maintenance
OCC . . . . . . . . . . . . . . . . . . . . Office of Consumer Counsel
OCI . . . . . . . . . . . . . . . . . . . . . Other comprehensive income
PCB . . . . . . . . . . . . . . . . . . . . Polychlorinated biphenyl
PFS . . . . . . . . . . . . . . . . . . . . . Private Fuel Storage, LLC
PI . . . . . . . . . . . . . . . . . . . . . . Prairie Island nuclear generating plant
PJM. . . . . . . . . . . . . . . . . . . . . PJM Interconnection, LLC
PM . . . . . . . . . . . . . . . . . . . . . Particulate matter
PPA. . . . . . . . . . . . . . . . . . . . . Purchased power agreement
PRP. . . . . . . . . . . . . . . . . . . . . Potentially responsible party
PTC. . . . . . . . . . . . . . . . . . . . . Production tax credit
PV. . . . . . . . . . . . . . . . . . . . . . Photovoltaic
QF. . . . . . . . . . . . . . . . . . . . . . Qualifying facilities
R&E . . . . . . . . . . . . . . . . . . . . Research and experimentation
REC . . . . . . . . . . . . . . . . . . . . Renewable energy credit
3
RFP. . . . . . . . . . . . . . . . . . . . . Request for proposal
ROE . . . . . . . . . . . . . . . . . . . . Return on equity
RPS. . . . . . . . . . . . . . . . . . . . . Renewable portfolio standards
RTO . . . . . . . . . . . . . . . . . . . . Regional Transmission Organization
SIP . . . . . . . . . . . . . . . . . . . . . State implementation plan
SO2 . . . . . . . . . . . . . . . . . . . . . Sulfur dioxide
SPP . . . . . . . . . . . . . . . . . . . . . Southwest Power Pool, Inc.
S&P . . . . . . . . . . . . . . . . . . . . Standard & Poor’s Ratings Services
TO. . . . . . . . . . . . . . . . . . . . . . Transmission owner
TransCo . . . . . . . . . . . . . . . . . Transmission-only subsidiary
TSR. . . . . . . . . . . . . . . . . . . . . Total shareholder return
Measurements
Bcf . . . . . . . . . . . . . . . . . . . . . Billion cubic feet
GWh . . . . . . . . . . . . . . . . . . . . Gigawatt hours
KV . . . . . . . . . . . . . . . . . . . . . Kilovolts
KWh . . . . . . . . . . . . . . . . . . . . Kilowatt hours
Mcf . . . . . . . . . . . . . . . . . . . . . Thousand cubic feet
MMBtu . . . . . . . . . . . . . . . . . . Million British thermal units
MW. . . . . . . . . . . . . . . . . . . . . Megawatts
MWh. . . . . . . . . . . . . . . . . . . . Megawatt hours
4
COMPANY OVERVIEW
Xcel Energy Inc. is a holding company with subsidiaries engaged primarily in the utility business. In 2016, Xcel Energy Inc.’s
continuing operations included the activity of four wholly owned utility subsidiaries that serve electric and natural gas customers in
eight states. These utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, and serve customers in portions of
Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Along with 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, these companies comprise the regulated utility operations.
Xcel Energy Inc. was incorporated under the laws of Minnesota in 1909. Xcel Energy’s executive offices are located at 414 Nicollet
Mall, Minneapolis, Minn. 55401. Its 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 public may read and copy any materials that Xcel Energy
files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain
information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an
internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically
with the SEC at http://www.sec.gov.
NSP-Minnesota
NSP-Minnesota is a utility primarily engaged in the generation, purchase, transmission, distribution and sale of electricity in
Minnesota, North Dakota and South Dakota. The wholesale customers served by NSP-Minnesota comprised approximately 13
percent of its total KWh sold in 2016. 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-Minnesota provides electric utility service to
approximately 1.5 million customers and natural gas utility service to approximately 0.5 million customers. Approximately 88 percent
of NSP-Minnesota’s retail electric operating revenues were derived from operations in Minnesota during 2016 and 2015. Although
NSP-Minnesota’s large C&I electric retail customers are comprised of many diversified industries, a significant portion of NSP-
Minnesota’s large C&I electric sales include the following industries: petroleum, coal and food products. For small C&I customers,
significant electric retail sales include the following industries: real estate and educational services. Generally, NSP-Minnesota’s
earnings contribute approximately 35 percent to 45 percent of Xcel Energy’s consolidated net income.
The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. A FERC-
approved Interchange Agreement between the two companies provides for the sharing of all generation and transmission costs of the
NSP System.
NSP-Minnesota owns the following direct subsidiary: United Power and Land Company, which holds real estate.
NSP-Wisconsin
NSP-Wisconsin is a utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of
northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan. NSP-Wisconsin purchases, transports,
distributes and sells natural gas to retail customers and transports customer-owned natural gas in this service territory. NSP-Wisconsin
provides electric utility service to approximately 257,000 customers and natural gas utility service to approximately 113,000
customers. Approximately 98 percent of NSP-Wisconsin’s retail electric operating revenues were derived from operations in
Wisconsin during 2016 and 2015. Although NSP-Wisconsin’s large C&I electric retail customers are comprised of many diversified
industries, a significant portion of NSP-Wisconsin’s large C&I electric sales include the following industries: food products, paper,
allied products and petroleum pipelines. For small C&I customers, significant electric retail sales include the following industries:
grocery and dining establishments, educational services and health services. Generally, NSP-Wisconsin’s earnings contribute
approximately five percent to 10 percent of Xcel Energy’s consolidated net income.
The management of the electric production and transmission system of NSP-Wisconsin is integrated with NSP-Minnesota.
NSP-Wisconsin owns the following direct subsidiaries: Chippewa and Flambeau Improvement Co., which operates hydro reservoirs;
Clearwater Investments Inc., which owns interests in affordable housing; and NSP Lands, Inc., which holds real estate.
5
PSCo
PSCo is a utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity in Colorado. The
wholesale customers served by PSCo comprised approximately 14 percent of its total KWh sold in 2016. PSCo also purchases,
transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas. PSCo provides electric
utility service to approximately 1.4 million customers and natural gas utility service to approximately 1.4 million customers. All of
PSCo’s retail electric operating revenues were derived from operations in Colorado during 2016. Although PSCo’s large C&I electric
retail customers are comprised of many diversified industries, a significant portion of PSCo’s large C&I electric sales include the
following industries: fabricated metal products, communications and health services. For small C&I customers, significant electric
retail sales include the following industries: real estate and dining establishments. Generally, PSCo’s earnings contribute
approximately 35 percent to 45 percent of Xcel Energy’s consolidated net income.
PSCo owns the following direct subsidiaries: 1480 Welton, Inc. and United Water Company, both of which own certain real estate
interests; and Green and Clear Lakes Company, which owns water rights and certain real estate interests. PSCo also holds a
controlling interest in several other relatively small ditch and water companies.
SPS
SPS is a utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity in portions of Texas and
New Mexico. The wholesale customers served by SPS comprised approximately 31 percent of its total KWh sold in 2016. SPS
provides electric utility service to approximately 389,000 retail customers in Texas and New Mexico. Approximately 71 percent of
SPS’ retail electric operating revenues were derived from operations in Texas during 2016 and 2015. Although SPS’ large C&I
electric retail customers are comprised of many diversified industries, a significant portion of SPS’ large C&I electric sales include the
following industries: oil and gas extraction, as well as petroleum and natural gas products. For small C&I customers, significant
electric retail sales include the following industries: oil and gas extraction, grocery and dining establishments. Generally, SPS’
earnings contribute approximately 10 percent to 15 percent of Xcel Energy’s consolidated net income.
Other Subsidiaries
WGI is a small interstate natural gas pipeline company engaged in transporting natural gas from the PSCo system near Chalk Bluffs,
Colo., to Cheyenne, Wyo.
WYCO was formed as a joint venture with CIG to develop and lease natural gas pipeline, storage, and compression facilities. Xcel
Energy has a 50 percent ownership interest in WYCO. The gas pipeline and storage facilities are leased under a FERC-approved
agreement to CIG.
Xcel Energy Services Inc. is the service company for Xcel Energy Inc.
XETD and XEST are transmission-only subsidiaries that will, respectively, participate in MISO and SPP competitive bidding
processes for transmission projects. XEWT is a transmission-only subsidiary formed to competitively bid on transmission projects in
the western United States.
Xcel Energy Inc.’s nonregulated subsidiaries are Eloigne and Capital Services. Eloigne invests in rental housing projects that qualify
for low-income housing tax credits, and Capital Services procures equipment for construction of renewable generation facilities at
other subsidiaries.
Xcel Energy conducts its utility business in the following reportable segments: regulated electric utility, regulated natural gas utility
and all other. See Note 17 to the consolidated financial statements for further discussion relating to comparative segment revenues,
income from operations and related financial information.
6
Public Utility Regulation
ELECTRIC UTILITY OPERATIONS
NSP-Minnesota
Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s
operations are regulated by the MPUC, the NDPSC and the SDPUC within their respective states. The MPUC also has regulatory
authority over security issuances, property transfers, mergers, dispositions of assets and transactions between NSP-Minnesota and its
affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s ERPs for meeting customers’ future energy needs. The
MPUC also certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV that will
be located within the state. No large power plant or transmission line may be constructed in Minnesota except on a site or route
designated by the MPUC. The NDPSC and SDPUC have regulatory authority over generation and transmission facilities, along with
the siting and routing of new generation and transmission facilities in North Dakota and South Dakota, respectively.
NSP-Minnesota is subject to the jurisdiction of the FERC with respect to its 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 operates within
the MISO RTO and MISO wholesale market and is authorized to make wholesale electric sales at market-based prices. NSP-
Minnesota is a transmission owning member of the MISO RTO.
Fuel, Purchased Energy and Conservation Cost-Recovery Mechanisms — NSP-Minnesota has several retail adjustment clauses that
recover fuel, purchased energy and other resource costs:
• CIP — Recovers the costs of conservation and demand-side management programs that help customers save energy.
• EIR — Recovers the costs of environmental improvement projects.
• RDF — Allocates money collected from retail customers to support the research and development of emerging renewable
energy projects and technologies.
• RES — Recovers the cost of renewable generation in Minnesota.
• RER — Recovers the cost of renewable generation in North Dakota.
•
•
•
SEP — Recovers costs related to various energy policies approved by the Minnesota legislature.
TCR — Recovers costs associated with investments in electric transmission and distribution grid modernization costs.
Infrastructure rider — Recovers costs for investments in generation and incremental property taxes in South Dakota.
NSP-Minnesota’s retail electric rates in 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. In general, capacity costs are recovered
through base rates and are not recovered through the FCA. In addition, costs associated with MISO are generally recovered through
either the FCA or base rates.
Minnesota state law requires NSP-Minnesota to invest two percent of its state electric revenues and half a percent of its state gas
revenues in CIP. These costs are recovered through an annual cost-recovery mechanism for electric conservation and energy
management program expenditures. Minnesota state law also requires NSP-Minnesota to submit a CIP plan at least every three years.
CIP Triennial Plan — In 2016, the DOC approved NSP-Minnesota’s 2017 through 2019 CIP Triennial Plan, which maintained the
energy savings goals and allowed for slight budget increases over the previous plan. The plan sets an annual energy savings goal for
electric of saving the equivalent of 1.5 percent of the volume of electric energy sales and an annual natural gas goal of saving 1.0
percent of the volume of gas energy sales.
Capacity and Demand
Uninterrupted system peak demand for the NSP System’s electric utility for each of the last three years and the forecast for 2017,
assuming normal weather conditions, is as follows:
NSP System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8,848
8,621
9,002
9,179
System Peak Demand (in MW)
2014
2015
2016
2017 Forecast
The peak demand for the NSP System typically occurs in the summer. The 2016 system peak demand for the NSP System occurred on
July 20, 2016. The 2016 system peak demand increased from the previous year due to customer growth and warmer summer weather.
The 2017 forecast assumes normal peak day weather, which would be warmer than 2016.
7
Energy Sources and Related Transmission Initiatives
NSP-Minnesota expects to use existing power plants, power purchases, CIP options, new generation facilities and expansion of
existing power plants to meet its system capacity requirements.
Purchased Power — NSP-Minnesota has contracts to purchase power from other utilities and independent power producers.
Generally, long-term dispatchable purchased power contracts require a periodic capacity payment and a charge for the delivered
associated energy. Some long-term purchased power contracts only contain a charge for the purchased energy. NSP-Minnesota also
makes short-term purchases to meet system load and energy requirements, to replace generation from company-owned units under
maintenance or during outages, to meet operating reserve obligations, or to 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.
Courtenay Wind Farm — In November 2016, NSP-Minnesota placed into service the Courtenay wind farm, a 200 MW NSP-
Minnesota owned project in North Dakota. In July and August 2015, the MPUC and NDPSC, respectively, approved the Courtenay
wind farm with recovery up to $300 million of capital costs. Total project costs were approximately $286 million, which were
included in the Minnesota RES rider and the North Dakota RER.
NSP System Resource Plans — In January 2017, the MPUC approved NSP-Minnesota’s Integrated Resource Plan that includes:
• Retirement of Sherco Unit 2 in 2023 and Sherco Unit 1 in 2026. The resulting need for 750 MW of capacity in 2026 will be
addressed in a future CON proceeding;
• Acquisition of at least 1,000 MW of wind by 2019 and possibly as much as 1,500 MW dependent on price, bidder
qualifications, rate impact, transmission availability and location. The mix of purchased power and owned facilities was not
specified;
• Acquisition of 650 MW of solar by 2021 either through the community solar gardens program or other cost-effective
resources. The mix of purchased power and owned facilities was not specified;
• Acquisition of at least 400 MW of additional demand response by 2023, and a study of the technical and economic
achievability of 1,000 MW of additional demand response in total by 2025; and
• Achievement of at least 444 GWh of energy efficiency in all planning years.
In 2016, Minnesota legislators introduced a bill which would allow NSP-Minnesota to build a natural gas combined-cycle power plant
at NSP-Minnesota’s Sherco site. The bill passed the House and Senate in February 2017 but will require approval from the Governor
to become effective. A final resolution is expected later in 2017 and cost recovery would be subject to MPUC approval.
Request for Proposal (RFP) — In September 2016, NSP-Minnesota issued a RFP for 1,500 MW of wind generation. The RFP
requests both PPAs and build-own-transfer proposals.
In October 2016, NSP-Minnesota submitted a petition for approval to the MPUC of a 750 MW self-build wind farm portfolio. RFP
bids were received in October 2016 and have been evaluated in conjunction with the self-build proposal.
In January 2017, NSP-Minnesota completed the bid evaluation process. NSP-Minnesota evaluated the bid proposals based on a
completeness review, a levelized cost of electricity economic evaluation and a non-price qualitative review. NSP-Minnesota believes
its self-build wind projects were competitive and should complement the RFP portfolio.
An overview of the anticipated RFP schedule is as follows:
Project proposal selection and negotiation during the first quarter of 2017;
•
• NSP-Minnesota’s recommendation for proposed wind additions to the MPUC later in the first quarter of 2017; and
• MPUC approval is expected by July 2017.
Jurisdictional Cost Recovery Allocation — In December 2016, NSP-Minnesota filed a resource treatment framework with the
NDPSC and MPUC. The filing proposed a framework to allow North Dakota and Minnesota to gradually become more independent
of one another with respect to future generation resource selection while also identifying a path for cost sharing of current resources.
NSP-Minnesota’s 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 the costs and benefits of each resource to the
jurisdiction that supports it. The annual costs for a legal separation and pseudo separation are estimated to be approximately $3
million and $1 million, respectively. A one-time cost of approximately $10 million would also be incurred to establish a North Dakota
operating company under legal separation. Costs are not expected to be incurred until 2020 and are anticipated to be recoverable
through rates. The filing proposed a procedural schedule that considers an order in mid-2018.
8
CapX2020 — The estimated cost of the five major CapX2020 transmission projects listed below is $2 billion. NSP-Minnesota and
NSP-Wisconsin are responsible for approximately $1.06 billion of the total investment and the majority of this investment has
occurred. The projects are as follows:
• Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. 161/345 KV transmission lines — The final 161 KV and 345 KV
segments of the project went into service in January 2016 and September 2016, respectively;
• Brookings County, S.D. to Hampton, Minn. 345 KV transmission line — The project was placed in service in March 2015;
• Bemidji, Minn. to Grand Rapids, Minn. 230 KV transmission line — The project was placed in service in September 2012;
• Monticello, Minn. to Fargo, N.D. 345 KV transmission line — The final portion of the project was placed in service in April
2015; and
• Big Stone South to Brookings County, S.D. 345 KV transmission line — Construction of the line began in September 2015,
with completion anticipated in September 2017.
Nuclear Power Operations and Waste Disposal
NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the PI plant. Nuclear power plant operations produce
gaseous, liquid and solid radioactive wastes which are controlled by federal regulation. High-level radioactive wastes primarily
include used nuclear fuel. LLW consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that
have become contaminated through use in a plant.
NRC Regulation — The NRC regulates the nuclear operations of NSP-Minnesota. Decisions by the NRC can significantly impact the
operations of the nuclear generating plants. The costs of complying with NRC orders and requirements can affect both operating
expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs in customer rates,
and expects the costs associated with compliance will continue to be recoverable from customers. Estimates of the future nuclear
capital expenditures related to costs of NRC compliance are included in Xcel Energy’s capital forecast for electric generation. See
Item 7 for further discussion of capital requirements.
Nuclear Regulatory Performance — The NRC has a Reactor Oversight Process that classifies U.S. nuclear reactors into various
categories (referred to as Columns, from 1 to 5). Issues are evaluated as either green, white, yellow, or red based on their safety
significance, with green representing the least safety concern and red representing the most concern.
At Dec. 31, 2016, PI Units 1 and 2 were in Column 1 (licensee response) with all green performance indicators and no greater than
green findings or violations. Plants in Column 1 are subject to only a pre-defined set of basic NRC inspections.
In the fourth quarter of 2016, Monticello moved from Column 1 to Column 2 (regulatory response) due to a white performance
indicator related to an oil leak in a backup cooling system in 2016. Plants in Column 2 are subject to special NRC inspections to
review and validate that performance issues or inspection findings have been properly addressed. Monticello has addressed the issues
leading to the finding and will be eligible to return to Column 1 once the NRC completes an inspection to close the issue. NSP-
Minnesota currently expects the inspection to occur, and Monticello to return to Column 1 in mid-2017.
Monticello Spent Fuel Storage - Dry Shielded Canisters — In 2013, NSP-Minnesota’s Monticello nuclear generating plant
conducted a spent fuel loading campaign which resulted in five storage canisters being loaded and placed in the ISFSI and a sixth one
being loaded but remaining in the plant pending resolution of weld inspection issues. Successful pressure and leak testing
demonstrated the safety and integrity of all six canisters involved. The NRC conducted an investigation and determined that two
contractor technicians at Monticello deliberately violated NRC requirements and failed to follow procedure in performing Non-
Destructive Examinations (NDE) on the six spent fuel storage canisters (Dry Shielded Canisters #11-16) in accordance with
procedural requirements and falsified records when recording the NDE results. NSP-Minnesota took several actions to assure that
compliance with the NRC’s regulations and Monticello’s storage license can be demonstrated.
In December 2016, the NRC issued a confirmatory order formally approving a settlement in which NSP-Minnesota agreed to a
timeline for attaining compliance on all six canisters as well as additional training and communications. As a result, the NRC will not
issue a notice of violation or impose a civil penalty to NSP-Minnesota and will consider the terms of its order as an escalated
enforcement action for a period of one year. During 2016, the NRC approved an exemption request for the completion of the final
canister #16. That canister is now considered in compliance, and was placed in the ISFSI during 2016.
Costs attributable to Monticello canisters #11-15 achieving full regulatory compliance within five years, as agreed to in the settlement,
are currently being evaluated. No public safety issues have been raised, or are believed to exist, related to handling of spent nuclear
fuel at Monticello in regard to this matter.
9
LLW Disposal — LLW from NSP-Minnesota’s Monticello and PI nuclear plants is currently disposed at the Clive facility located in
Utah and Waste Control Specialists facility located in Texas. If off-site LLW disposal facilities become unavailable, NSP-Minnesota
has storage capacity available on-site at PI and Monticello that would allow both plants to continue to operate until the end of their
current licensed lives.
High-Level Radioactive Waste Disposal — The federal government has the responsibility to permanently dispose of 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. At this time,
there are no definitive plans for a permanent federal storage site at Yucca Mountain or any other site.
Nuclear Spent Fuel Storage
NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. As of Dec. 31,
2016, there were 40 casks loaded and stored at the PI plant and 16 canisters loaded and stored at the Monticello plant. An additional
24 casks for PI and 14 canisters for Monticello have been authorized by the State of Minnesota. This currently 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 begin operation of a consolidated interim storage
installation.
NRC Waste Confidence Decision (WCD) — In 2014, the NRC published a Generic Environmental Impact Statement and revised
WCD rule, now called the Continued Storage Rule (CSR) on the temporary on-site storage of spent nuclear fuel. The CSR assesses
how long temporary on-site storage can remain safe and when facilities for the disposal of nuclear waste will become available.
Issuance of the CSR now allows the NRC to proceed with final license decisions regarding the new and renewed plant and ISFSI
operating licenses without the need to litigate contentions related to the continued storage of spent nuclear fuel on-site. This may
facilitate potential future spent fuel licensing needs for NSP-Minnesota. The CSR was challenged before the U.S. Court of Appeals
for the D.C. Circuit on the grounds that the environmental impact statement is inadequate to satisfy the National Environmental Policy
Act. In June 2016, the D.C. Circuit’s decision upheld the CSR.
See Note 14 to the consolidated financial statements for further discussion regarding nuclear related items.
Energy Source Statistics
NSP System
Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wind (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . .
Hydroelectric. . . . . . . . . . . . . . . . . . . . . . . . .
Other (b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Owned generation . . . . . . . . . . . . . . . . . . . . .
Purchased generation . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016
Year Ended Dec. 31
2015
2014
Millions of
KWh
Percent of
Generation
Millions of
KWh
Percent of
Generation
Millions of
KWh
Percent of
Generation
14,191
13,681
7,897
7,810
3,203
1,480
48,262
36,381
11,881
48,262
30%
28
16
16
7
3
100%
75%
25
100%
12,425
15,961
6,235
6,689
3,326
1,083
45,719
33,818
11,901
45,719
27%
35
14
15
7
2
100%
74%
26
100%
13,434
18,079
6,243
3,402
3,560
1,417
46,135
33,641
12,494
46,135
29%
39
14
7
8
3
100%
73%
27
100%
(a)
(b)
This category includes wind energy de-bundled from RECs and also includes Windsource
requirements and may sell surplus RECs.
®
RECs. The NSP System uses RECs to meet or exceed state resource
Includes energy from other sources, including solar, biomass, oil and refuse. Distributed generation from the Solar*Rewards
approximately 21, eight and seven million net KWh for 2016, 2015, and 2014, respectively.
®
program is not included, and was
10
Fuel Supply and Costs
The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for owned electric generation,
the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.
NSP System Generating Plants
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(a)
Includes refuse-derived fuel and wood.
(a)
Coal
Nuclear
Natural Gas
Cost
Percent
Cost
Percent
Cost
Percent
Weighted
Average
Owned Fuel
Cost
2.03
2.15
2.23
42% $
47
52
0.80
0.83
0.89
44% $
40
42
3.30
3.89
6.27
14% $
13
6
1.67
1.85
1.94
The cost of natural gas in 2016 decreased due to lower wholesale commodity prices.
See Items 1A and 7 for further discussion of fuel supply and costs.
Fuel Sources
Nuclear — NSP-Minnesota 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 to
minimize potential impacts caused by supply interruptions due to geographical and world political issues.
• Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2019 and approximately
53 percent of the requirements for 2020 through 2030;
• Current contracts for conversion services cover 100 percent of the requirements through 2021 and approximately 49 percent of
the requirements for 2022 through 2030; and
• Current enrichment service contracts cover 100 percent of the requirements through 2025 and approximately 28 percent of the
requirements for 2026 through 2030.
Fabrication services for Monticello and PI are 100 percent committed through 2030 and 2019, respectively.
NSP-Minnesota expects sufficient uranium concentrates, conversion services and enrichment services to be available for the total fuel
requirements of its nuclear generating plants. Some exposure to market price volatility will remain due to index-based pricing
structures contained in certain supply contracts.
Coal — The NSP System normally maintains approximately 41 days of coal inventory. Coal supply inventories at Dec. 31, 2016 and
2015 were approximately 55 and 67 days of usage, respectively. At Dec. 31, 2016, milder weather, purchase commitments and
relatively low natural gas prices resulted in coal inventories being above optimal levels. NSP-Minnesota’s generation stations use
low-sulfur western coal purchased primarily under contracts with suppliers operating in Wyoming and Montana. During 2016 and
2015, coal requirements for the NSP System’s major coal-fired generating plants were approximately 7.5 million tons and 8.3 million
tons, respectively. Coal requirements for 2016 decreased primarily due to relatively low natural gas prices during the year. The
estimated coal requirements for 2017 are approximately 8.9 million tons. The increase is primarily due to higher expected natural gas
prices in 2017.
NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 74 percent of their estimated coal requirements in
2017 and a declining percentage of the requirements in subsequent years. The NSP System’s general coal purchasing objective is to
contract for approximately 80 percent of requirements for the first year, 50 percent of requirements in year two and 25 percent of
requirements in year three. Remaining requirements will be filled through the procurement process or over-the-counter transactions.
NSP-Minnesota and NSP-Wisconsin have a number of coal transportation contracts that provide for delivery of 100 percent of their
coal requirements in 2017 and 2018. Coal delivery may be subject to interruptions or reductions due to operation of the mines,
transportation problems, weather and availability of equipment.
11
Natural gas — The NSP System uses both firm and interruptible natural gas supply and standby oil in combustion turbines and certain
boilers. Natural gas supplies, transportation and storage services for power plants are procured under contracts to provide an adequate
supply of fuel. However, as natural gas primarily serves intermediate and peak demand, remaining forecasted requirements are able to
be procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to various natural
gas indices. Most transportation contract pricing is based on FERC approved transportation tariff rates. Certain natural gas supply
and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make
payments in lieu of delivery. At Dec. 31, 2016 and 2015, the NSP System did not have any commitments related to gas supply
contracts; however commitments related to gas transportation and storage contracts were approximately $382 million and $276
million, respectively. Commitments related to gas transportation and storage contracts expire in various years from 2017 to 2028.
The NSP System also has limited on-site fuel oil storage facilities and primarily relies on the spot market for incremental supplies.
Renewable Energy Sources
The NSP System’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating
facilities and PPAs. As of Dec. 31, 2016, the NSP System was in compliance with mandated RPS, which require generation from
renewable resources of 18.0 percent and 12.9 percent of NSP-Minnesota and NSP-Wisconsin electric retail sales, respectively.
• Renewable energy comprised 26.1 percent and 23.3 percent of the NSP System’s total energy for 2016 and 2015,
respectively;
• Wind energy comprised 16.4 percent and 13.6 percent of the total energy for 2016 and 2015, respectively;
• Hydroelectric energy comprised 6.6 percent and 7.3 percent of the total energy for 2016 and 2015, respectively; and
• Biomass and solar power comprised approximately 3.1 percent and 2.4 percent of the total energy for 2016 and 2015,
respectively.
The NSP System also offers customer-focused renewable energy initiatives. Windsource allows customers in Minnesota, Wisconsin
and Michigan to purchase a portion or all of their electricity from renewable sources. In 2016, the number of customers utilizing
Windsource increased to approximately 54,000 from 50,000 in 2015.
Additionally, to encourage the growth of solar energy on the system, customers are offered incentives to install solar panels on their
homes and businesses under the Solar*Rewards program. Over 2,063 PV systems with approximately 25.2 MW of aggregate capacity
have been installed in Minnesota as of Dec. 31, 2016 and over 1,458 PV systems with approximately 18.3 MW of aggregate capacity
have been installed as of Dec. 31, 2015. The community solar gardens program is another option made available to encourage use of
solar energy in Minnesota. This program allows for offsite development of solar and bill credits to customers based on an approved
tariffed rate. Although very few MW came on line in 2016, an increase in the MW supplied through this program is expected in 2017.
Wind — The NSP System acquires the majority of its wind energy from PPAs with wind farm owners, primarily located in
Southwestern Minnesota. Currently, the NSP System has more than 125 of these agreements in place, with facilities ranging in size
from under one MW to more than 200 MW. The NSP System owns and operates five wind farms which have the capacity to generate
852 MW.
• The NSP System had approximately 2,602 and 2,210 MW of wind energy on its system at the end of 2016 and 2015,
respectively. In addition to receiving purchased wind energy under these agreements, the NSP System also typically receives
wind RECs, which are used to meet state renewable resource requirements.
• The average cost per MWh of wind energy under existing contracts was approximately $43 and $42 for 2016 and 2015,
respectively. The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including
regulation, state-specific renewable resource requirements and the year of contract execution. Generally, contracts executed
in 2016 continued to benefit from improvements in technology, excess capacity among manufacturers and motivation to
commence new construction prior to the anticipated expiration of the federal PTCs. In December 2015, the federal PTCs
were extended through 2019 with a phase down beginning in 2017.
Hydroelectric — The NSP System acquires its hydroelectric energy from both owned generation and PPAs. The NSP System owns 20
hydroelectric plants throughout Wisconsin and Minnesota which provide 277.5 MW of capacity. For 2016, PPAs provided
approximately 34 MW of hydroelectric capacity. Additionally, the NSP System purchases approximately 725 MW of generation from
Manitoba Hydro, which is sourced primarily from its fleet of hydroelectric facilities.
12
Wholesale and Commodity Marketing Operations
NSP-Minnesota conducts various 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 and sharing of
any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating
agreement. NSP-Minnesota does not serve any wholesale requirements customers at cost-based regulated rates. See Item 7 for further
discussion.
Public Utility Regulation
NSP-Wisconsin
Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Wisconsin’s
operations are regulated by the PSCW and the MPSC, within their respective states. In addition, each of the state commissions
certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built. NSP-Wisconsin
is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, hydroelectric generation licensing,
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. NSP-Wisconsin and NSP-
Minnesota have been granted continued joint authorization from the FERC to make wholesale electric sales at market-based prices.
NSP-Wisconsin is a transmission owning member of the MISO RTO.
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. In recent years, NSP-Wisconsin has been submitting rate filings each year.
Fuel and Purchased Energy Cost Recovery Mechanisms — NSP-Wisconsin does not have an automatic electric fuel adjustment
clause for Wisconsin retail customers. Instead, under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the
PSCW for approval. Once the PSCW approves the fuel cost plan, utilities defer the amount of any fuel cost under-collection or over-
collection in excess of a two percent 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 after an opportunity for a hearing. Rate recovery
of deferred fuel cost is subject to an earnings test based on the utility’s most recently authorized ROE. Fuel cost under-collections that
exceed the two percent annual tolerance band for a calendar year may not be recovered if the utility earnings for that year exceed the
authorized ROE.
NSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, which are based on
12-month projections. After each 12-month period, a reconciliation is submitted whereby over-collections are refunded and any
under-collections are collected from the customers over the subsequent 12-month period.
Wisconsin Energy Efficiency Program — In Wisconsin, the primary energy efficiency program is funded by the state’s utilities, but
operated by independent contractors subject to oversight by the PSCW and the utilities. NSP-Wisconsin recovers these costs in rates
charged to Wisconsin retail customers.
Capacity and Demand
NSP-Wisconsin operates an integrated system with NSP-Minnesota. See NSP-Minnesota Capacity and Demand.
Energy Sources and Related Transmission Initiatives
NSP-Wisconsin operates an integrated system with NSP-Minnesota. See NSP-Minnesota Energy Sources and Related Transmission
Initiatives.
NSP-Wisconsin / American Transmission Company, LLC (ATC) - La Crosse to Madison, Wis. Transmission Line — In 2013, NSP-
Wisconsin and ATC jointly filed an application with the PSCW for a CPCN for a new 345 KV transmission line that would extend
from La Crosse, Wis. to Madison, Wis. NSP-Wisconsin’s half of the line will be shared with three co-owners, Dairyland Power
Cooperative, WPPI Energy and Southern Minnesota Municipal Power Agency-Wisconsin.
13
In 2015, the PSCW issued its order approving a CPCN and route for the project. Subsequently, the PSCW denied two requests for
rehearing. Two groups have appealed the CPCN Order to county circuit court. Court action is pending in one remaining appeal and
the CPCN remains in full effect unless one of the parties seeks and receives a stay from the court and posts a bond to cover damages
the utilities may incur due to delay. The 180-mile project is expected to cost approximately $541 million. NSP-Wisconsin’s portion
of the investment, which includes AFUDC, is estimated to be approximately $200 million. Updated forecast costs are primarily due to
better material pricing than originally anticipated. Construction on the line began in January 2016, with completion anticipated by late
2018.
2016 Electric Fuel Cost Recovery — NSP-Wisconsin’s electric fuel costs for the year ended Dec. 31, 2016 were lower than
authorized in rates and outside the two percent annual tolerance band established in the Wisconsin fuel cost recovery rules, primarily
due to lower sales volume and lower purchased power costs coupled with moderate weather. Under the fuel cost recovery rules, NSP-
Wisconsin may retain the amount of over-recovery up to two percent of authorized annual fuel costs, or approximately $3.4 million.
However, NSP-Wisconsin must defer the amount of over-recovery in excess of the two percent annual tolerance band for future refund
to customers. Accordingly, NSP-Wisconsin recorded a deferral of approximately $9.8 million through Dec. 31, 2016. In March 2017
NSP-Wisconsin will file a reconciliation of 2016 fuel costs with the PSCW. The amount of any potential refund is subject to review
and approval by the PSCW, which is not expected until mid-2017.
Fuel Supply and Costs
NSP-Wisconsin operates an integrated system with NSP-Minnesota. See NSP-Minnesota Fuel Supply and Costs.
Wholesale and Commodity Marketing Operations
NSP-Wisconsin operates an integrated system with NSP-Minnesota. NSP-Wisconsin does not serve any wholesale requirements
customers at cost-based regulated rates. See NSP-Minnesota Wholesale and Commodity Marketing Operations.
Public Utility Regulation
PSCo
Summary of Regulatory Agencies and Areas of Jurisdiction — PSCo is regulated by the CPUC with respect to its facilities, rates,
accounts, services and issuance of securities. PSCo is regulated by the FERC with respect to its wholesale electric operations,
accounting practices, hydroelectric licensing, wholesale sales for resale, the transmission of electricity in interstate commerce,
compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate
commerce. PSCo is authorized to make wholesale electric sales at market-based prices to customers outside its balancing authority
area.
Fuel, Purchased Energy and Conservation Cost-Recovery Mechanisms — PSCo has several retail adjustment clauses that recover
fuel, purchased energy and other resource costs:
• ECA — Recovers fuel and purchased energy costs. Short-term sales margins are shared with retail customers through the ECA.
The ECA is revised quarterly.
• PCCA — Recovers purchased capacity payments.
•
SCA — Recovers the difference between PSCo’s actual cost of fuel and the amount of these costs recovered under its base
steam service rates. The SCA rate is revised on a quarterly basis.
• DSMCA — Recovers DSM, interruptible service option credit costs and performance initiatives for achieving various energy
savings goals.
• RESA — Recovers the incremental costs of compliance with the RES with a maximum of two percent of the customer’s total
bill.
• Wind Energy Service — Premium service for customers who choose to pay an additional charge for renewable resources.
•
• CACJA — Recovers costs associated with implementing its compliance plan under the CACJA.
TCA — Recovers costs associated with transmission investment outside of rate cases.
PSCo recovers fuel and purchased energy costs from its wholesale electric customers through a fuel cost adjustment clause approved
by the FERC. PSCo’s wholesale customers have agreed to pay the full cost of certain renewable energy purchase and generation costs
through a fuel clause and in exchange receive RECs associated with those resources. The wholesale customers pay their jurisdictional
allocation of production costs through a fully forecasted formula rate with true-up.
QSP Requirements — The CPUC established an electric QSP that provides for bill credits to customers if PSCo does not achieve
certain performance targets relating to electric reliability and customer service. PSCo monitors and records, as necessary, an estimated
customer refund obligation under the QSP. The CPUC extended the terms of the current QSP through 2018.
14
Capacity and Demand
Uninterrupted system peak demand for PSCo’s electric utility for each of the last three years and the forecast for 2017, assuming
normal weather conditions, is as follows:
PSCo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,152
6,284
6,585
6,439
System Peak Demand (in MW)
2014
2015
2016
2017 Forecast
The peak demand for PSCo’s system typically occurs in the summer. The 2016 system peak demand for PSCo occurred on Aug. 3,
2016. The 2016 system peak demand was higher due to Comanche Unit 3 not running at full capacity, which increased PSCo’s system
load for the backup power provided by PSCo to the joint owners. The forecast of system peak assumes normal weather conditions.
Energy Sources and Related Transmission Initiatives
PSCo expects to meet its system capacity requirements through existing electric generating stations, power purchases, new generation
facilities, DSM options and phased expansion of existing generation at select power plants.
Purchased Power — PSCo has contracts to purchase power from other utilities and independent power producers. Long-term
purchased power contracts typically require a periodic capacity charge and an energy charge for energy actually purchased. PSCo also
makes short-term purchases to meet system load and energy requirements, to replace generation from company-owned units under
maintenance or during outages, to meet operating reserve obligations, or to 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 PSCo’s customers.
Rush Creek Wind Ownership Proposal — In 2016, PSCo filed an application for a CPCN to build, own and operate a 600 MW wind
generation facility at Rush Creek for a cost of approximately $1 billion, including transmission investment.
In 2016, the CPUC approved a settlement between PSCo and various parties and granted a CPCN, which allows PSCo to commence
the project on a timely basis and capture the full PTC benefit for customers.
Key terms of the settlement are listed below:
• The Rush Creek project satisfies the reasonable cost standard and is in the public interest;
• The project should be placed in service by Oct. 31, 2018;
• The useful life of the project should be set at 25 years;
• A hard cost-cap on the $1.096 billion investment (which includes the capital investment and AFUDC);
• A capital cost sharing mechanism for every $10 million below the cost-cap, with 82.5 percent retained by customers and 17.5
percent retained by PSCo on a net present value basis over the life of the project;
• Amounts retained by PSCo under the capital cost sharing mechanism as well as overall facility revenue requirements may
each be reduced for lower than projected long term generating output (i.e., higher degradation);
• The Pawnee-Daniels transmission line (estimated project cost of $178 million) should be accelerated and operations are
•
expected to begin by October 2019; and
PSCo committed to develop a rate for third-party access to available capacity in the Rush Creek transmission line to be filed
at the FERC.
Colorado 2016 ERP — In May 2016, PSCo filed its 2016 ERP which identified approximately 600 MW of additional resource needs
by the summer of 2023; the level of resource need is driven by load growth, retiring generation facilities, expiring purchased power
contracts and the impacts of customer-facing programs. In its initial filing, PSCo proposed a competitive acquisition process in which
all generation resources, except coal-fired generation, could compete. PSCo has expressed an interest in owning incremental
generation through self-build proposals, purchase of existing assets some of which are currently subject to PPAs or through build-own-
transfer projects. In February 2017, the CPUC held hearings regarding PSCo’s proposal and an initial decision is anticipated by
March 2017. The actual range of need to be filled in the competitive acquisition process will be determined once a final decision is
received from the CPUC and prior to the beginning of the competitive acquisition phase of the ERP process.
Brush to Castle Pines 345 KV Transmission Line — In 2015, the CPUC granted a CPCN to construct a new 345 KV transmission
line originating from Pawnee generating station, near Brush, CO to the Daniels Park substation, near Castle Pines, CO to be placed in
service by May 2022. The estimated project cost is $178.3 million. The CPUC granted the parties’ requests for consolidation with the
Rush Creek project and approved for construction to begin in the first half of 2017.
15
PSCo Global Settlement Agreement — In August 2016, PSCo and various intervenors entered into a global settlement agreement
regarding three pending filings with the CPUC, including the Phase II electric rate case (which is related to the rate design portion of
the 2015 Electric rate case), the Renewable*Connect proposal and the 2017 Renewable Energy Plan. Key terms of the agreement
include that participating customers in the proposed Renewable*Connect program would pay ordinary tariff electric rates in addition
to a voluntary tariff solar charge, and receive bill credits related to avoided cost savings for a new 50 MW solar resource. It was also
agreed that PSCo’s 2017 Renewable Energy Plan would include 2017 to 2019 acquisition of a total of 225 MW of renewable energy
from sources including rooftop solar, solar gardens and recycled energy.
In December 2016, the CPUC approved the global settlement agreement. In January 2017, PSCo began implementing the terms of the
settlement.
Joint Dispatch Agreement (JDA) — In February 2016, the FERC approved a JDA between PSCo, Black Hills/Colorado Electric
Utility Company, LP and Platte River Power Authority. Through the JDA, energy is dispatched to economically serve the combined
electric customer loads of the three systems. In circumstances where PSCo is the lowest cost producer, it will sell its excess
generation to other JDA counterparties. The agreement results in a reduction in total energy costs for the parties, of which
approximately $1.4 million would be allocated to PSCo’s customers. As part of the agreement, PSCo will earn a management fee to
administer the JDA. In January 2017, the CPUC approved the JDA.
Advanced Grid Intelligence and Security — In August 2016, PSCo filed a request with the CPUC to approve a CPCN for
implementation of its advanced grid initiative. The project incorporates installing advanced meters, implementing a combination of
hardware and software applications to allow the distribution system to operate at a lower voltage (integrated volt-var optimization) and
installing necessary communications infrastructure to implement this hardware. These major projects are expected to improve
customer experience, enhance grid reliability and enable the implementation of new and innovative programs and rate structures. The
estimated capital investment for the project is approximately $500 million. PSCo anticipates a CPUC decision by mid-2017. If
approval is received, the project is expected to be completed by 2021.
Decoupling Filing — In July 2016, PSCo filed a request with the CPUC to approve a partial decoupling mechanism for a five-year
period, effective Jan. 1, 2017. The proposed decoupling adjustment would allow PSCo to adjust annual revenues based on changes in
weather normalized average use per customer for the residential and small C&I classes. The proposed decoupling mechanism is
symmetric and may result in potential refunds to customers if there were an increase in average use per customer. PSCo did not
request that revenue be adjusted as a result of weather related sales fluctuations.
In January 2017, the CPUC Staff (Staff) and various intervenors, including the OCC, filed direct testimony.
• The Staff recommended a portion of PSCo’s request be approved and suggested the CPUC should lower PSCo’s ROE by 30
basis points to account for lower risk associated with annual revenues, if the full proposal were approved;
• The OCC opposed PSCo’s decoupling request; and
• Other intervening parties generally supported PSCo’s proposal, but recommended various modifications, such as the use of
actual sales data instead of weather-normalized sales.
A CPUC decision is expected in April 2017.
Boulder, Colo. Municipalization — In 2011, a ballot measure was passed which authorized the formation and operation of a
municipal utility and the issuance of enterprise revenue bonds. In 2014, the City of Boulder (Boulder) City Council passed an
ordinance to establish an electric utility. PSCo challenged the formation of this utility as premature because costs and system
separation plans were not final, but the case was dismissed. PSCo appealed this decision and in September 2016, the Colorado Court
of Appeals preserved PSCo’s ability to challenge the utility while vacating the lower court’s decision.
In 2013, the CPUC ruled that Boulder may not be the retail service provider to any PSCo customers located outside Boulder city limits
unless Boulder can establish that PSCo is unwilling or unable to serve those customers. The CPUC also ruled that it has jurisdiction
over the transfer of any facilities to Boulder that currently serve any customers located outside Boulder city limits and will determine
separation matters. The CPUC has declared that Boulder must receive CPUC transfer approval prior to any eminent domain actions.
Boulder appealed this ruling to the Boulder District Court. In January 2015, the Boulder District Court affirmed the CPUC decision.
The Boulder District Court also dismissed a condemnation action that Boulder had filed. The CPUC must complete the separation
plan proceeding before Boulder may refile a condemnation proceeding.
In July 2015, Boulder filed an application with the CPUC requesting approval of its proposed separation plan. In August 2015, PSCo
filed a motion to dismiss Boulder’s separation proposal, arguing Boulder’s request was not permissible under Colorado law. In
December 2015, the CPUC granted the motion to dismiss the application in part, holding that Boulder had no right to acquire PSCo
facilities used exclusively to serve customers located outside Boulder city limits. Other portions of Boulder’s application were not
dismissed, but were stayed until Boulder supplemented its application. Boulder filed its amended application in September 2016.
16
In February 2017, PSCo and other intervenors filed answer testimony which addressed several legal issues posed by the CPUC.
Overall, PSCo believes that Boulder’s plan is not consistent with and cannot be effectively administered under Colorado law and that
from a reliability perspective it is an inappropriate way to separate the two distribution systems and poses significant risks to PSCo
and its remaining customers. The remaining key dates in the procedural schedule are as follows:
• Rebuttal testimony — March 30, 2017;
• Hearings — April 26 through May 5, 2017;
Statements of position — May 17, 2017; and
•
Final decision — June 15, 2017.
•
Depreciation and Amortization Proceeding — In April 2016, PSCo filed for approval of depreciation rates and amortization
schedules for its electric and common plant. In January 2017, the CPUC approved a comprehensive settlement agreement. The new
depreciation and amortization rates are expected to be implemented in conjunction with PSCo’s next rate case or through a separate
proceeding in 2018, with an expected annual increase of approximately $33 million.
RES Compliance Plan — Colorado law mandates that at least 20 percent of PSCo’s energy sales are supplied by renewable energy
through 2019, with the percentage increasing to 30 percent by 2020 and includes a distributed generation standard. PSCo was in
compliance with the RES as of Dec. 31, 2016.
Energy Source Statistics
PSCo
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . .
Wind (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hydroelectric. . . . . . . . . . . . . . . . . . . . . . . . .
Other (b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Owned generation . . . . . . . . . . . . . . . . . . . . .
Purchased generation . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016
Year Ended Dec. 31
2015
2014
Millions of
KWh
Percent of
Generation
Millions of
KWh
Percent of
Generation
Millions of
KWh
Percent of
Generation
15,895
8,632
8,106
1,179
393
34,205
22,753
11,452
34,205
47%
25
24
3
1
100%
67%
33
100%
18,601
7,948
6,699
662
705
34,615
22,981
11,634
34,615
54%
23
19
2
2
100%
66%
34
100%
18,274
8,601
6,472
617
294
34,258
23,023
11,235
34,258
53%
25
19
2
1
100%
67%
33
100%
(a)
(b)
This category includes wind energy de-bundled from RECs and also includes Windsource RECs. PSCo uses RECs to meet or exceed state resource requirements
and may sell surplus RECs.
Distributed generation from the Solar*Rewards program is not included, and was approximately 396, 245 and 197 million net KWh for 2016, 2015, and 2014,
respectively.
Fuel Supply and Costs
The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for owned electric generation,
the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.
PSCo Generating Plants
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Coal
Natural Gas
Cost
Percent
Cost
Percent
Weighted Average
Owned Fuel Cost
1.75
1.75
1.82
72% $
75
75
3.79
3.89
5.32
28% $
25
25
2.33
2.29
2.68
See Items 1A and 7 for further discussion of fuel supply and costs.
17
Fuel Sources
Coal — PSCo normally maintains approximately 41 days of coal inventory. Coal supply inventories at Dec. 31, 2016 and 2015 were
approximately 36 and 49 days of usage, respectively. At Dec. 31, 2016, stockpile reductions in preparation for unit retirements at the
Cherokee and Valmont stations in 2017 resulted in coal inventories being slightly below optimal levels. PSCo’s generation stations
use low-sulfur western coal purchased primarily under contracts with suppliers operating in Colorado and Wyoming. During 2016 and
2015, PSCo’s coal requirements for existing plants were approximately 9.9 million tons and 10.5 million tons, respectively. The
estimated coal requirements for 2017 are approximately 10.0 million tons. The increase is primarily due to higher expected natural gas
prices in 2017.
PSCo has contracted for coal supply to provide 84 percent of its estimated coal requirements in 2017, and a declining percentage of
requirements in subsequent years. PSCo’s general coal purchasing objective is to contract for approximately 80 percent of
requirements for the first year, 50 percent of requirements in year two, and 25 percent of requirements in year three. Remaining
requirements will be filled through the procurement process or over-the-counter transactions.
PSCo has coal transportation contracts that provide for delivery of 100 percent its coal requirements in 2017 and 2018. Coal delivery
may be subject to interruptions or reductions due to operation of the mines, transportation problems, weather and availability of
equipment.
Natural gas — PSCo uses both firm and interruptible natural gas supply and standby oil in combustion turbines and certain boilers.
Natural gas supplies for PSCo’s power plants are procured under contracts to provide an adequate supply of fuel. However, as natural
gas primarily serves intermediate and peak demand, any remaining forecasted requirements are able to be procured through a liquid
spot market. The majority of natural gas supply under contract is covered by a long-term agreement with Anadarko Energy Services
Company, the balance of natural gas supply contracts have variable pricing features tied to changes in various natural gas indices.
PSCo hedges a portion of that risk through financial instruments. See Note 11 to the consolidated financial statements for further
discussion.
Most transportation contract pricing is based on FERC approved transportation tariff rates. Certain natural gas supply and
transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make
payments in lieu of delivery.
• At Dec. 31, 2016, PSCo’s commitments related to gas supply contracts, which expire in various years from 2017 through
2023, were approximately $654 million and commitments related to gas transportation and storage contracts, which expire in
various years from 2017 through 2060, were approximately $573 million.
• At Dec. 31, 2015, PSCo’s commitments related to gas supply contracts were approximately $750 million and commitments
related to gas transportation and storage contracts were approximately $684 million.
PSCo has limited on-site fuel oil storage facilities and primarily relies on the spot market for incremental supplies.
Renewable Energy Sources
PSCo’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and
PPAs. As of Dec. 31, 2016, PSCo was in compliance with mandated RPS, which requires generation from renewable resources of
20.0 percent of electric retail sales.
• Renewable energy comprised 28.3 percent and 22.0 percent of PSCo’s total energy for 2016 and 2015, respectively;
• Wind energy comprised 23.7 percent and 19.4 percent of the total energy for 2016 and 2015, respectively; and
• Hydroelectric, biomass and solar power comprised approximately 4.6 percent and 2.6 percent of the total energy for 2016 and
2015.
PSCo also offers customer-focused renewable energy initiatives. Windsource allows customers to purchase a portion or all of their
electricity from renewable sources. In 2016, the number of customers utilizing Windsource increased to approximately 46,000 from
45,000 in 2015.
18
Additionally, to encourage the growth of solar energy on the system, customers are offered incentives to install solar panels on their
homes and businesses under the Solar*Rewards program. Over 32,500 PV systems with approximately 276 MW of aggregate
capacity and over 29,500 PV systems with approximately 258 MW of aggregate capacity have been installed in Colorado under this
program as of Dec. 31, 2016 and 2015, respectively. Additionally, 25 community solar gardens with 18.1 MW of capacity and 24
gardens with 16.6 MW of capacity have been completed in Colorado as of Dec. 31, 2016 and 2015, respectively.
Wind — PSCo acquires the majority of its wind energy from PPAs with wind farm owners, primarily located in Colorado. Currently,
PSCo has 19 of these agreements in place, with facilities ranging in size from two MW to over 300 MW.
•
PSCo had approximately 2,560 MW of wind energy on its system at the end of 2016 and 2015. In addition to receiving
purchased wind energy under these agreements, PSCo also typically receives wind RECs which are used to meet state
renewable resource requirements.
• The average cost per MWh of wind energy under these contracts was approximately $42 in 2016 and 2015. The cost per
MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state-specific
renewable resource requirements, and the year of contract execution. Generally, contracts executed in 2016 continued to
benefit from improvements in wind technology, excess capacity among manufacturers, and motivation to commence new
construction prior to the anticipated expiration of the federal PTCs. In December 2015, the federal PTCs were extended
through 2019 with a phase down beginning in 2017.
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 and sharing of any margins is determined through
state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. See Item 7 for further
discussion.
Public Utility Regulation
SPS
Summary of Regulatory Agencies and Areas of Jurisdiction — The PUCT and NMPRC regulate SPS’ retail electric operations and
have jurisdiction over its retail rates and services and the construction of transmission or generation in their respective states. The
municipalities in which SPS operates in Texas have original jurisdiction over SPS’ rates in those communities. Each municipality can
deny SPS’ rate increases. SPS can then appeal municipal rate decisions to the PUCT, which hears all municipal rate denials in one
hearing. The NMPRC also has jurisdiction over the issuance of securities. SPS is regulated by the FERC with respect to its 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. As
approved by the FERC, SPS operates within the SPP RTO and SPP IM wholesale market. SPS is authorized to make wholesale
electric sales at market-based prices.
Fuel, Purchased Energy and Conservation Cost-Recovery Mechanisms — SPS has several retail adjustment clauses that recover
fuel, purchased energy and other resource costs:
• DCRF — Recovers certain distribution costs in Texas that are not included in base rates.
• EECRF — Recovers costs associated with providing energy efficiency programs in Texas.
• EE rider — Recovers costs associated with providing energy efficiency programs in New Mexico.
• FPPCAC — Adjusts monthly to recover the actual fuel and purchased power costs.
• PCRF — Allows recovery of certain purchased power costs in Texas that are not included in base rates.
• RPS — Recovers deferred costs associated with renewable energy programs in New Mexico.
•
TCRF — Recovers certain transmission infrastructure improvement costs and changes in wholesale transmission charges in
Texas that are not included in base rates.
Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor, which is part of
SPS’ retail electric tariff. SO2 and NOx allowance revenues and costs are also recovered through the fixed fuel and purchased energy
recovery factor. The regulations allow retail fuel factors to change up to three times per year.
The fixed fuel and purchased energy recovery factor provides for the over- or under-recovery of fuel and purchased energy expenses.
Regulations also require refunding or surcharging over- or under- recovery amounts, including interest, when they exceed four percent
of the utility’s annual fuel and purchased energy costs on a rolling 12-month basis, if this condition is expected to continue.
19
PUCT regulations require periodic examination of SPS’ fuel and purchased energy costs, the efficient use of fuel and purchased
energy, fuel acquisition and management policies and purchased energy commitments. SPS is required to file an application for the
PUCT to retrospectively review fuel and purchased energy costs at least every three years. In June 2016, SPS filed its fuel
reconciliation application which reconciles fuel and purchased power costs for 2013 through 2015. In February 2017, an unopposed
stipulation was reached which resolves all issues in this case. The stipulation is pending PUCT approval, which is expected in the first
half of 2017.
Each New Mexico utility operating with a FPPCAC must periodically file an application for continued use. In October 2015, the
NMPRC granted SPS authority to continue using its FPPCAC to collect its fuel and purchase power costs. SPS will be required to file
a request for continuation of its FPPCAC by October 2019.
SPS recovers fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased
economic energy cost adjustment clause accepted for filing by the FERC.
Capacity and Demand
Uninterrupted system peak demand for SPS for each of the last three years and the forecast for 2017, assuming normal weather
conditions, is as follows:
SPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4,871
4,678
4,836
4,484
System Peak Demand (in MW)
2014
2015
2016
2017 Forecast
The peak demand for the SPS system typically occurs in the summer. The 2016 system peak demand for SPS occurred on July 13,
2016. The 2016 peak demand increased due to warmer than normal July summer weather. The 2017 forecast assumes normal peak
day weather. In addition, the partial requirement contract with Golden Spread ends May 2017, causing a lower 2017 forecast peak
demand for SPS.
Energy Sources and Related Transmission Initiatives
SPS expects to use existing electric generating stations, power purchases, DSM and new generation options to meet its system
capacity requirements.
Purchased Power — SPS has contracts to purchase power from other utilities and independent power producers. Long-term
purchased power contracts typically require a periodic capacity charge and an energy charge for energy actually purchased. SPS also
makes short-term purchases to meet system load and energy requirements, to replace generation from company-owned units under
maintenance or during outages, to meet operating reserve obligations or to 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.
High Priority Incremental Load Study Report — In 2014, the SPP Board of Directors approved the High Priority Incremental Load
Study Report, a reliability assessment that evaluated the anticipated transmission needs of certain parts of the SPP region resulting
from expected load growth. As a result of this study, SPS has received NTCs and conditional NTCs for 44 new transmission projects
at an estimated cost of approximately $557 million to be placed into service by 2020. As of Dec. 31, 2016, 16 of these projects have
been completed at an original estimated cost of $88 million. SPS is developing plans for the remaining 28 projects and submitting
CCNs to the PUCT and the NMPRC. The original estimated cost for these remaining projects is $469 million. These projects are
intended to provide regional reliability benefits as well as the ability to serve the increase in load in southeastern New Mexico.
TUCO Substation to Yoakum County Substation to Hobbs Plant Substation 345 KV Transmission Line — In March 2016, the
PUCT approved SPS’ CCN for the 33-mile Yoakum County to Texas/New Mexico State line portion of this 345 KV line project. A
CCN for the 111-mile TUCO to Yoakum County substation segment was filed in June 2016. Assuming approval of this CCN, this
segment is scheduled to be in service in 2019. A 36-mile CCN for the Texas/New Mexico state line to Hobbs Plant segment is planned
to be filed later in the first quarter of 2017. The estimated project cost for all three segments is approximately $242 million.
20
Hobbs Plant Substation to China Draw Substation 345 KV Transmission Line — In November 2016, the NMPRC approved SPS’
CCN for the Hobbs Plant to China Draw transmission line. The estimated project cost is approximately $163 million. The line is
anticipated to be in service in 2018.
SPS Resource Plans — SPS was required to develop and implement a renewable portfolio plan by 2015, in which 15 percent of its
energy to serve its New Mexico retail customers is produced by renewable resources. The requirement was met through PPAs,
including wind, solar and distributed generation. In 2020, the renewable resource production requirement increases to 20 percent. In
addition, SPS indicated that it was evaluating water supply issues at its Tolk facility and if additional investment is required to operate
the plant through its existing life. The Ogallala aquifer in this region of the country has depleted more rapidly than expected and SPS
is currently seeking a permit for a horizontal well configuration pilot program that could help to delay the need for a more substantial
investment solution. As a result of this issue and environmental issues currently facing the plant, SPS is seeking a decrease to the
remaining useful life of the facility in its current New Mexico rate case proceeding (see Note 12).
Wholesale Customer Participation in ERCOT — In March 2016, the PUCT Staff requested comments on Lubbock Power & Light’s
(LP&L’s) proposal to transition a portion of its load (approximately 430 MW on a peak basis) to the ERCOT in June 2019. LP&L’s
proposal would result in an approximate seven percent reduction of load in SPS, or a loss of approximately $18 million in wholesale
transmission revenue. The remaining portion of LP&L’s load (approximately 170 MW) would continue to be served by SPS. Should
LP&L join ERCOT, costs to SPS’ remaining customers would increase as SPS’ transmission costs would be spread across a smaller
base of customers.
The PUCT has indicated there will be a two-step process regarding LP&L’s possible transfer to ERCOT. The first step will be a
proceeding to determine whether the proposed transfer is in the public interest and to consider certain protections for non-LP&L
customers who would be affected by LP&L’s transfer. If the PUCT determines the transfer is in the public interest, the second step
will be for LP&L to file a CCN application for transmission facilities to connect with ERCOT. The PUCT asked SPP and ERCOT to
perform reliability and economic studies to better understand the implications of LP&L’s proposal. SPS intends to participate in the
PUCT’s processes to protect its customers’ interests.
In May 2016, SPS submitted a filing to the FERC seeking approval to impose an Interconnection Switching Fee (exit fee) associated
with LP&L’s proposal. In September 2016, FERC dismissed SPS’ petition without prejudice to refile, finding the petition premature
since LP&L has not made a final decision to move to ERCOT and the terms of the transition have not been determined.
Energy Source Statistics
SPS
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . .
Wind (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other (b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Owned generation . . . . . . . . . . . . . . . . . . . . .
Purchased generation . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016
Year Ended Dec. 31
2015
2014
Millions of
KWh
Percent of
Generation
Millions of
KWh
Percent of
Generation
Millions of
KWh
Percent of
Generation
10,990
10,909
6,120
347
28,366
15,015
13,351
28,366
39%
38
22
1
100%
53%
47
100%
12,441
10,514
5,252
150
28,357
16,480
11,877
28,357
44%
36
19
1
100%
58%
42
100%
12,770
10,068
3,762
180
26,780
16,956
9,824
26,780
48%
37
14
1
100%
63%
37
100%
(a)
(b)
This category includes wind energy de-bundled from RECs and also includes Windsource RECs. SPS uses RECs to meet or exceed state resource requirements
and may sell surplus RECs.
Distributed generation from the Solar*Rewards program is not included, was approximately 14, 13 and 10 million net KWh for 2016, 2015, and 2014,
respectively.
21
Fuel Supply and Costs
The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for owned electric generation,
the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.
SPS Generating Plants
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal
Natural Gas
Cost
Percent
Cost
Percent
Weighted
Average Owned
Fuel Cost
2.12
2.12
2.07
70% $
73
71
2.81
3.11
4.76
30% $
27
29
2.32
2.39
2.85
See Items 1A and 7 for further discussion of fuel supply and costs.
Fuel Sources
Coal — SPS purchases all of the coal requirements for its two coal facilities, Harrington and Tolk electric generating stations, from
TUCO. 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. The coal supply contract with TUCO expires in December 2017 for both Harrington and Tolk. SPS normally maintains
approximately 43 days of coal inventory. As of Dec. 31, 2016 and 2015, coal inventories at SPS were approximately 64 and 76 days
supply, respectively. At Dec. 31, 2016, milder weather, purchase commitments and relatively low natural gas prices resulted in coal
inventories being above optimal levels. SPS’ generation stations primarily use low-sulfur western coal from mines operating in
Wyoming. TUCO has coal agreements to supply 65 percent of SPS’ estimated coal requirements in 2017. SPS’ general coal
purchasing objective is to contract for approximately 80 percent of requirements for the first year.
Natural gas — SPS uses both firm and interruptible natural gas supply and standby oil in combustion turbines and certain boilers.
Natural gas for SPS’ power plants is procured under contracts to provide an adequate supply of fuel; which typically is purchased with
terms of one year or less. The transportation and storage contracts expire in various years from 2017 to 2033. All of the natural gas
supply contracts have variable pricing that is tied to various natural gas indices.
Most transportation contract pricing is based on FERC and Railroad Commission of Texas approved transportation tariff rates.
Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of
natural gas or to make payments in lieu of delivery. SPS’ commitments related to gas supply contracts were approximately $17
million and $10 million and commitments related to gas transportation and storage contracts were approximately $161 million and
$192 million at Dec. 31, 2016 and 2015, respectively.
SPS has limited on-site fuel oil storage facilities and primarily relies on the spot market for incremental supplies.
Renewable Energy Sources
SPS’ renewable energy portfolio includes wind and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2016,
SPS is in compliance with mandated RPS, which require generation from renewable resources of 3.7 percent of Texas electric retail
sales and 15.0 percent of New Mexico electric retail sales.
• Renewable energy comprised 22.8 percent and 19.0 percent of SPS’ total energy for 2016 and 2015, respectively;
• Wind energy comprised 21.6 percent and 18.5 percent of the total energy for 2016 and 2015, respectively; and
•
Solar power comprised approximately 1.2 percent and 0.5 percent of the total energy for 2016 and 2015, respectively.
SPS also offers customer-focused renewable energy initiatives. Windsource allows customers in New Mexico to purchase a portion or
all of their electricity from renewable sources. The number of customers utilizing Windsource increased to approximately 900 in 2016
from 880 in 2015.
22
Additionally, to encourage the growth of solar energy on the system in New Mexico, customers are offered incentives to install solar
panels on their homes and businesses under the Solar*Rewards program. Over 147 PV systems with approximately 8.1 MW of
aggregate capacity and over 144 PV systems with approximately 8.0 MW of aggregate capacity have been installed in New Mexico
under this program as of Dec. 31, 2016 and 2015, respectively.
Wind — SPS acquires its wind energy from IPP contracts and QF tariffs with wind farm owners, primarily located in the Texas
Panhandle area of Texas and New Mexico. SPS currently has 24 of these agreements in place, with facilities ranging in size from
under two MW to 250 MW for a total capacity greater than 1,500 MW.
•
SPS had approximately 1,500 MW and 1,755 MW of wind energy on its system at the end of 2016 and 2015, respectively.
This decrease is primarily due to the timing of supplier contracts expiring. In addition to receiving purchased wind energy
under these agreements, SPS also typically receives wind RECs, which are used to meet state renewable resource
requirements.
• The average cost per MWh of wind energy under the IPP contracts and QF tariffs was approximately $25 and $24 for 2016
and 2015, respectively. The cost per MWh of wind energy varies by contract and may be influenced by a number of factors
including regulation, state-specific renewable resource requirements and the year of contract execution. Generally, contracts
executed in 2016 continued to benefit from improvements in technology, excess capacity among manufacturers, and
motivation to commence new construction prior to the anticipated expiration of the federal PTCs. In December 2016, the
federal PTCs were extended through 2019 with a phase down beginning in 2017.
Wholesale and Commodity Marketing Operations
SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services
and energy related products. SPS uses physical and financial instruments to minimize commodity price and credit risk and hedge sales
and purchases. See Item 7 for further discussion.
Summary of Recent Federal Regulatory Developments
The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro
facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of Xcel
Energy Inc.’s utility subsidiaries and transmission-only subsidiaries, including enforcement of NERC mandatory electric reliability
standards. State and local agencies have jurisdiction over many of Xcel Energy Inc.’s utility subsidiaries’ activities, including
regulation of retail rates and environmental matters. In addition to the matters discussed below, see Note 12 to the accompanying
consolidated financial statements for a discussion of other regulatory matters.
Status of FERC Commissioners — The FERC is comprised of five commissioners appointed by the President and subject to
confirmation by the Senate. There are today only two sitting commissioners. It is uncertain when the President will appoint new
commissioners to the open seats or when those appointments may be confirmed. Without three sitting commissioners, the FERC will
not have a quorum to act on contested matters. The lack of a quorum could affect the timing of FERC decisions on proposed rules or
pending, newly submitted and future filings involving, among other things, contested electric rate matters and CPCNs for construction
of interstate natural gas pipeline facilities to serve the utility subsidiaries.
FERC Order, ROE Policy — The FERC has adopted a two-step ROE methodology for electric utilities. The issue of how to apply
the FERC ROE methodology is being contested in various complaint proceedings. There are two ROE complaints against the MISO
TOs, which include NSP-Minnesota and NSP-Wisconsin. In September 2016, the FERC issued an order in the first MISO ROE
complaint, which upheld the initial decision made by the ALJ in December 2015, establishing an ROE of 10.32 percent for the period
Nov. 12, 2013 to Feb. 11, 2015, and prospectively. The second complaint is pending FERC action after issuance of an initial decision
by the ALJ in June 2016, recommending an ROE of 9.7 percent for the period Feb. 12, 2015 to May 11, 2016. The FERC is expected
to issue an order in the second litigated MISO ROE complaint proceeding during 2017. See Note 12 to the consolidated financial
statements for discussion of the MISO ROE Complaints.
23
NERC Critical Infrastructure Protection Requirements — The FERC has approved Version 5 of NERC’s critical infrastructure
protection standards, which added additional requirements to strengthen grid security controls. Xcel Energy applied the requirements
to high and medium impact assets by the July 1, 2016 deadline. Requirements must be applied to low impact assets through a
staggered implementation beginning April 1, 2017 through September 2018. Xcel Energy is currently in the process of implementing
initiatives to meet the compliance deadline. The additional cost for compliance is anticipated to be recoverable through rates.
NERC Physical Security Requirements — In 2014, the FERC approved NERC’s proposed critical infrastructure protection standard
related to physical security for bulk electric system facilities. The new standard became enforceable in October 2015 with staggered
milestone deliverable dates through 2016. Xcel Energy has developed physical security plans in accordance with the requirements of
the standard. The additional cost for compliance is anticipated to be recoverable through rates.
Formula Rate Treatment of Accumulated Deferred Income Taxes (ADIT) — In 2015, NSP-Minnesota, NSP-Wisconsin, SPS and
PSCo filed changes to their transmission formula rates and PSCo filed changes to its production formula rate to comply with IRS
guidance regarding how ADIT must be reflected in formula rates using future test years and a true-up. The filings were intended to
ensure that NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are in compliance with IRS rules and may continue to use accelerated tax
depreciation. Each filing requested a Jan. 1, 2016 effective date.
In 2015, the FERC partially accepted and partially rejected the proposed NSP-Minnesota and NSP-Wisconsin transmission formula
rate changes. In September 2016, the FERC clarified their order, but required NSP-Minnesota and NSP-Wisconsin to submit a new
tariff change filing to implement the treatment of ADIT in the formula rate true-up. In November 2016, NSP-Minnesota and NSP-
Wisconsin filed the changes proposing a Jan. 1, 2017 effective date, but requesting authority to calculate the 2016 true-up pursuant to
the new ADIT tariff provisions. In December 2016, the FERC issued an order which approved the tariff revisions, effective Jan. 1,
2017, but rejected the portion of their application related to the 2016 true-up.
In April 2016, the FERC accepted the SPS and PSCo ADIT formula rate changes, effective Jan. 1, 2016, subject to a compliance
filing. In August 2016, the FERC approved PSCo and SPS’ compliance filings.
Xcel Energy believes its wholesale formula rates are in compliance with the IRS ADIT rules.
Public Utility Regulatory Policies Act (PURPA) Enforcement Complaint against CPUC — In December 2016, Sustainable Power
Group, LLC (sPower) petitioned the FERC to initiate an enforcement action in federal court against the CPUC under PURPA. The
petition asserts that a December 2016 CPUC ruling, which indicated that a QF must be a successful bidder in a PSCo resource
acquisition bidding process, violated PURPA and FERC rules. In January 2017, PSCo filed a motion to intervene and protest, arguing
that the FERC should decline the petition. The CPUC filed a similar pleading. sPower has proposed to construct 800 MW of solar
generation and 700 MW of wind generation in Colorado and seeks to require PSCo to contract for these resources under PURPA. If
sPower were to prevail, PSCo’s ability to select generation resources through competitive bidding would be negatively affected.
FERC action is pending.
24
Electric Sales Statistics
Electric Operating Statistics
Year Ended Dec. 31
2016
2015
2014
Electric sales (Millions of KWh)
Residential. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Large C&I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Small C&I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Public authorities and other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total retail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales for resale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total energy sold. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Number of customers at end of period
Residential. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Large C&I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Small C&I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Public authorities and other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total retail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wholesale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total customers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
24,726
27,664
35,830
1,103
89,323
18,694
108,017
3,053,732
1,228
432,012
68,935
3,555,907
52
3,555,959
Electric revenues (Thousands of Dollars)
Residential. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,965,681
1,706,546
Large C&I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,327,562
Small C&I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
140,464
Public authorities and other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total retail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
8,140,253
693,101
Wholesale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
666,427
Other electric revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total electric revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 9,499,781
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wholesale revenue per KWh . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
25,120
2,289
11.99¢
6.17
9.29
9.11
3.71
24,498
27,719
35,806
1,071
89,094
15,283
104,377
3,023,494
1,229
429,617
68,595
3,522,935
47
3,522,982
24,857
27,657
36,022
1,104
89,640
14,931
104,571
2,994,075
1,128
426,289
68,306
3,489,798
44
3,489,842
$ 2,891,371
1,689,695
3,303,838
136,730
8,021,634
660,590
593,762
$ 9,275,986
$
25,290
2,277
11.80¢
6.10
9.23
9.00
4.32
$ 2,956,576
1,789,742
3,382,750
143,442
8,272,510
795,425
397,955
$ 9,465,890
$
25,686
2,370
11.89¢
6.47
9.39
9.23
5.33
25
Energy Source Statistics
Xcel Energy
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . .
Wind (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hydroelectric. . . . . . . . . . . . . . . . . . . . . . . . .
Other (b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Owned generation . . . . . . . . . . . . . . . . . . . . .
Purchased generation . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016
Year Ended Dec. 31
2015
2014
Millions of
KWh
Percent of
Generation
Millions of
KWh
Percent of
Generation
Millions of
KWh
Percent of
Generation
40,566
27,351
22,123
14,191
4,435
2,167
110,833
74,149
36,684
110,833
36%
25
20
13
4
2
100%
67%
33
100%
47,003
25,151
18,186
12,895
4,001
1,456
108,692
73,279
35,413
108,692
43%
23
17
12
4
1
100%
67%
33
100%
49,123
22,071
16,478
13,503
4,203
1,795
107,173
73,620
33,553
107,173
46%
21
15
12
4
2
100%
69%
31
100%
(a)
(b)
This category includes wind energy de-bundled from RECs and also includes Windsource RECs. Xcel Energy uses RECs to meet or exceed state resource
requirements and may sell surplus RECs.
Includes energy from other sources, including solar, biomass, oil and refuse. Distributed generation from the Solar*Rewards program is not included, and was
approximately 430, 266 and 222 million net KWh for 2016, 2015 and 2014, respectively.
Overview
NATURAL GAS UTILITY OPERATIONS
The most significant developments in the natural gas operations of the utility subsidiaries are uncertainty regarding political and
regulatory developments that impact hydraulic fracturing, safety requirements for natural gas pipelines and the continued trend of
declining use per residential and small C&I customer, as a result of improved building construction technologies, higher appliance
efficiencies and conservation. From 2000 to 2016, average annual sales to the typical residential customer declined 18 percent, while
sales to the typical small C&I customer declined 12 percent, each on a weather-normalized basis. Although wholesale price increases
do not directly affect earnings because of natural gas cost-recovery mechanisms, high prices can encourage further efficiency efforts
by customers.
The Pipeline and Hazardous Materials Safety Administration
Protecting our Infrastructure of Pipelines and Enhancing Safety Act (PIPES) Act — The PIPES Act, signed into law in June 2016,
requires the DOT PHMSA to issue regulations on the construction and operation of the nation’s underground gas storage fields. The
act also grants PHMSA emergency order authority for pipeline operators, which would require operators to make immediate changes
to assets or operations. The act also directs PHMSA to continue work on a variety of mandates from the 2012 Pipeline Safety,
Regulatory Certainty, and Job Creation Act (Pipeline Safety Act), many of which have not been completed.
PHMSA issued interim final rules for underground storage operators in December 2016. PSCo operates three underground storage
fields in Colorado and PSCo is developing a plan to meet the storage rules. PSCo does not expect these changes to have a material
impact on costs or operating reliability.
Pipeline Safety Act — The Pipeline Safety Act requires additional verification of pipeline infrastructure records by pipeline owners
and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely
populated areas. The DOT PHMSA will require operators to re-confirm the maximum allowable operating pressure if records are
inadequate. This process could cause temporary or permanent limitations on throughput for affected pipelines.
In addition, the Pipeline Safety Act requires PHMSA to issue reports and develop new regulations including: requiring use of
automatic or remote-controlled shut-off valves; requiring testing of certain previously untested transmission lines; and expanding
integrity management requirements. The Pipeline Safety Act also raises the maximum penalty for violating pipeline safety rules to $2
million per day for related violations. Xcel Energy is taking actions that are intended to comply with the Pipeline Safety Act and any
related PHMSA regulations as they become effective. Xcel Energy cannot predict the ultimate impact the Pipeline Safety Act will
have on its costs, operations or financial results. PSCo and NSP-Minnesota can generally recover costs to comply with the
transmission and distribution integrity management programs through the PSIA and GUIC riders, respectively.
26
Public Utility Regulation
NSP-Minnesota
Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s retail
natural gas operations are regulated by the MPUC and the NDPSC within their respective states. The MPUC has regulatory authority
over security issuances, certain property transfers, mergers with other utilities and transactions between NSP-Minnesota and its
affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s natural gas supply plans for meeting customers’ future
energy needs. NSP-Minnesota is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate
commerce. NSP-Minnesota is subject to the DOT, the Minnesota Office of Pipeline Safety, the NDPSC and the SDPUC for pipeline
safety compliance, including pipeline facilities used in electric utility operations for fuel deliveries.
Purchased Gas and Conservation Cost-Recovery Mechanisms — NSP-Minnesota’s retail natural gas rates for Minnesota and North
Dakota include a PGA clause that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased natural
gas, transportation service and storage service. The annual difference between the natural gas cost revenues collected through PGA
rates and the actual natural gas costs is collected or refunded over the subsequent 12-month period.
NSP-Minnesota also recovers costs associated with transmission and distribution pipeline integrity management programs through its
GUIC rider. Costs recoverable under the GUIC rider include funding for pipeline assessments as well as deferred costs from NSP-
Minnesota’s existing sewer separation and pipeline integrity management programs. The MPUC and NDPSC have the authority to
disallow recovery of certain costs if they find the utility was not prudent in its procurement activities.
Minnesota state law requires utilities to invest 0.5 percent of their state natural gas revenues in CIP. These costs are recovered through
customer base rates and an annual cost-recovery mechanism for the CIP expenditures.
Capability and Demand
Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum
daily send-out (firm and interruptible) for NSP-Minnesota was 800,232 MMBtu, which occurred on Jan. 18, 2016 and 774,044
MMBtu, which occurred on Jan. 12, 2015.
NSP-Minnesota purchases natural gas from independent suppliers, generally based on market indices that reflect current prices. The
natural gas is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable
pipeline capacity of 624,123 MMBtu per day. In addition, NSP-Minnesota contracts with providers of underground natural gas
storage services. These agreements provide storage for approximately 26 percent of winter natural gas requirements and 29 percent of
peak day firm requirements of NSP-Minnesota.
NSP-Minnesota also owns and operates one LNG plant with a storage capacity of 2.0 Bcf equivalent and three propane-air plants with
a storage capacity of 1.3 Bcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity
equivalent to 246,000 MMBtu of natural gas per day, or approximately 30 percent of peak day firm requirements. LNG and propane-
air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space
heating demand on extremely cold winter days.
NSP-Minnesota is required to file for a change in natural gas supply contract levels to meet peak demand, to redistribute demand costs
among classes, or to exchange one form of demand for another. In February 2016, the MPUC approved NSP-Minnesota’s contract
demand levels for the 2015 through 2016 heating season. Demand levels for the 2016 through 2017 heating season were approved by
the MPUC in February 2017.
Natural Gas Supply and Costs
NSP-Minnesota actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides
increased flexibility, decreased interruption and financial risk and economical rates. In addition, NSP-Minnesota conducts natural gas
price hedging activity that has been approved by the MPUC.
The following table summarizes the average delivered cost per MMBtu of natural gas purchased for resale by NSP-Minnesota’s
regulated retail natural gas distribution business:
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.47
4.07
6.17
27
The cost of natural gas in 2016 decreased due to lower wholesale commodity prices.
NSP-Minnesota has firm natural gas transportation contracts with several pipelines, which expire in various years from 2017 through
2033.
NSP-Minnesota has certain natural gas supply, transportation and storage agreements that include obligations for the purchase and/or
delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2016, NSP-Minnesota was
committed to approximately $528 million in such obligations under these contracts.
NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 29 domestic and
Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Minnesota to maintain competition from suppliers
and minimize supply costs.
See Items 1A and 7 for further discussion of natural gas supply and costs.
Public Utility Regulation
NSP-Wisconsin
Summary of Regulatory Agencies and Areas of Jurisdiction — NSP-Wisconsin is regulated by the PSCW and the MPSC. 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 period beginning the following January. NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to certain
natural gas transactions in interstate commerce. NSP-Wisconsin is subject to the DOT, the PSCW and the MPSC for pipeline safety
compliance.
Natural Gas Cost-Recovery Mechanisms — NSP-Wisconsin has a retail PGA cost-recovery mechanism for Wisconsin operations to
recover the actual cost of natural gas and transportation and storage services. The PSCW has the authority to disallow certain costs if
it finds NSP-Wisconsin was not prudent in its procurement activities.
NSP-Wisconsin’s natural gas rate schedules for Michigan customers include a natural gas cost-recovery factor, which is based on 12-
month projections.
Capability and Demand
Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum
daily send-out (firm and interruptible) for NSP-Wisconsin was 155,583 MMBtu, which occurred on Jan. 18, 2016, and 158,719
MMBtu, which occurred on Jan. 7, 2015.
NSP-Wisconsin purchases natural gas from independent suppliers, generally based on market indices that reflect current prices. The
natural gas is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable
pipeline capacity of approximately 140,143 MMBtu per day. In addition, NSP-Wisconsin contracts with providers of underground
natural gas storage services. These agreements provide storage for approximately 32 percent of winter natural gas requirements and
34 percent of peak day firm requirements of NSP-Wisconsin.
NSP-Wisconsin also owns and operates one LNG plant with a storage capacity of 270,000 Mcf equivalent and one propane-air plant
with a storage capacity of 2,700 Mcf equivalent to help meet its peak requirements. These peak-shaving facilities have production
capacity equivalent to 18,408 MMBtu of natural gas per day, or approximately 12 percent of peak day firm requirements. LNG and
propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm
space heating demand on extremely cold winter days.
NSP-Wisconsin is required to file a natural gas supply plan with the PSCW annually to change natural gas supply contract levels to
meet peak demand. NSP-Wisconsin’s winter 2016-2017 supply plan was approved by the PSCW in October 2016.
28
Natural Gas Supply and Costs
NSP-Wisconsin actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides
increased flexibility, decreased interruption and financial risk and economical rates. In addition, NSP-Wisconsin conducts natural gas
price hedging activity that has been approved by the PSCW.
The following table summarizes the average delivered cost per MMBtu of natural gas purchased for resale by NSP-Wisconsin’s
regulated retail natural gas distribution business:
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.62
4.11
6.52
The cost of natural gas in 2016 decreased due to lower wholesale commodity prices.
The cost of natural gas supply, transportation service and storage service is recovered through various cost-recovery adjustment
mechanisms. NSP-Wisconsin has firm natural gas transportation contracts with several pipelines, which expire in various years from
2017 through 2029.
NSP-Wisconsin has certain natural gas supply, transportation and storage agreements that include obligations for the purchase and/or
delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2016, NSP-Wisconsin was
committed to approximately $103 million in such obligations under these contracts.
NSP-Wisconsin purchased firm natural gas supply utilizing long-term and short-term agreements from approximately nine domestic
and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Wisconsin to maintain competition from
suppliers and minimize supply costs.
See Items 1A and 7 for further discussion of natural gas supply and costs.
Public Utility Regulation
PSCo
Summary of Regulatory Agencies and Areas of Jurisdiction — PSCo is regulated by the CPUC with respect to its facilities, rates,
accounts, services and issuance of securities. PSCo holds a FERC certificate that allows it to transport natural gas in interstate
commerce without PSCo becoming subject to full FERC jurisdiction under the Federal Natural Gas Act. PSCo is subject to the DOT
and the CPUC with regards to pipeline safety compliance.
Purchased Natural Gas and Conservation Cost-Recovery Mechanisms — PSCo has retail adjustment clauses that recover purchased
natural gas and other resource costs:
• GCA — Recovers the actual costs of purchased natural gas and transportation to meet the requirements of its customers and is
revised quarterly to allow for changes in natural gas rates.
• DSMCA — Recovers costs of DSM and performance initiatives to achieve various energy savings goals.
• PSIA — Recovers costs associated with transmission and distribution pipeline integrity management programs and two projects
to replace large transmission pipelines. The rider has been extended through 2018.
QSP Requirements — The CPUC established a natural gas QSP that provides for bill credits to customers if PSCo does not achieve
certain performance targets relating to natural gas leak repair time and customer service. The CPUC has extended the terms of the
QSP through 2018.
Capability and Demand
Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum
daily send-out (firm and interruptible) for PSCo was 1,932,070 MMBtu, which occurred on Dec. 17, 2016 and 1,633,493 MMBtu,
which occurred on March 4, 2015.
29
PSCo purchases natural gas from independent suppliers, generally based on market indices that reflect current prices. The natural gas
is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity
of approximately 1,818,151 MMBtu per day, which includes 854,852 MMBtu of natural gas held under third-party underground
storage agreements. In addition, PSCo operates three company-owned underground storage facilities, which provide approximately
43,500 MMBtu of natural gas supplies on a peak day. The balance of the quantities required to meet firm peak day sales obligations
are primarily purchased at PSCo’s city gate meter stations.
PSCo is required by CPUC regulations to file a natural gas purchase plan each year projecting and describing the quantities of natural
gas supplies, upstream services and the costs of those supplies and services for the 12-month period of the following year. PSCo is
also required to file a natural gas purchase report by October of each year reporting actual quantities and costs incurred for natural gas
supplies and upstream services for the previous 12-month period.
Natural Gas Supply and Costs
PSCo actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased
flexibility, decreased interruption and financial risk and economical rates. In addition, PSCo conducts natural gas price hedging
activities that have been approved by the CPUC.
The following table summarizes the average delivered cost per MMBtu of natural gas purchased for resale by PSCo’s regulated retail
natural gas distribution business:
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.27
3.92
4.91
The cost of natural gas in 2016 decreased due to lower wholesale commodity prices.
PSCo has natural gas supply, transportation and storage agreements that include obligations for the purchase and/or delivery of
specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2016, PSCo was committed to approximately
$884 million in such obligations under these contracts, which expire in various years from 2017 through 2029.
PSCo purchases natural gas by optimizing a balance of long-term and short-term natural gas purchases, firm transportation and natural
gas storage contracts. During 2016, PSCo purchased natural gas from approximately 32 suppliers.
See Items 1A and 7 for further discussion of natural gas supply and costs.
Natural Gas Facilities Used for Electric Generation
SPS
SPS does not provide retail natural gas service, but purchases and transports natural gas for certain of 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 certain natural gas transactions in interstate commerce; and to the jurisdiction of the PHMSA
and the PUCT for pipeline safety compliance.
See Items 1A and 7 for further discussion of natural gas supply and costs.
30
Natural Gas Operating Statistics
Natural gas deliveries (Thousands of MMBtu)
Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
C&I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total retail. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation and other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total deliveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Number of customers at end of period
Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
C&I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total retail. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation and other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total customers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended Dec. 31
2016
2015
2014
132,853
84,082
216,935
133,498
350,433
135,394
86,093
221,487
125,263
346,750
152,269
95,879
248,148
124,000
372,148
1,835,507
157,286
1,992,793
7,316
2,000,109
1,814,321
156,306
1,970,627
6,981
1,977,608
1,795,190
155,515
1,950,705
6,594
1,957,299
Natural gas revenues (Thousands of Dollars)
Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
C&I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total retail. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation and other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
929,889
468,977
1,398,866
132,546
Total natural gas revenues. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,531,412
$ 1,042,884
547,165
1,590,049
82,032
$ 1,672,081
$ 1,320,207
727,071
2,047,278
95,460
$ 2,142,738
MMBtu sales per retail customer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revenue per retail customer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Residential revenue per MMBtu. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
C&I revenue per MMBtu . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation and other revenue per MMBtu . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
108.86
702
7.00
5.58
0.99
$
112.39
807
7.70
6.36
0.65
127.21
1,050
8.67
7.58
0.77
GENERAL
Seasonality
The 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. See Item 7 for further discussion.
Competition
Xcel Energy is a vertically integrated utility in all of its jurisdictions, subject to traditional cost-of-service regulation by state public
utilities commissions. However, Xcel Energy is subject to different public policies that promote competition and the development of
energy markets. Xcel Energy’s industrial and large commercial customers have the ability to own or operate facilities to generate their
own electricity. In addition, customers may have the option of substituting other fuels, such as natural gas, steam or chilled water for
heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region. Customers also have the
opportunity to supply their own power with solar generation (depending on jurisdiction, rooftop solar or solar gardens) 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 policies designed to promote the development of solar and other distributed energy resources through significant
incentive policies; with these incentives and federal tax subsidies, distributed generating resources are potential competitors to Xcel
Energy’s electric service business.
31
The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result,
Xcel Energy Inc.’s utility subsidiaries and their wholesale customers can purchase the output from generation resources of competing
wholesale suppliers and use the transmission systems of the utility subsidiaries on a comparable basis to serve their native load. State
public utilities commissions have created resource planning programs that promote competition in the acquisition of electricity
generation resources used to provide service to retail customers. In addition, FERC Order 1000 seeks to establish competition for
construction and operation of certain new electric transmission facilities. Xcel Energy Inc.’s utility subsidiaries also have franchise
agreements with certain cities subject to periodic renewal. If a city elected not to renew the franchise agreement, it could seek
alternative means for its citizens to access electric power or gas, such as municipalization. While each of Xcel Energy Inc.’s utility
subsidiaries faces these challenges, Xcel Energy believes their rates and services are competitive with currently available alternatives.
ENVIRONMENTAL MATTERS
Xcel Energy’s facilities are regulated by federal and state environmental agencies. These agencies 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 all necessary authorizations
for the construction and continued operation of its generation, transmission and distribution systems. Xcel Energy’s facilities have
been designed and constructed to operate in compliance with applicable environmental standards. 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 environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may have upon
Xcel Energy’s operations. See Item 7 and Notes 12 and 13 to the consolidated financial statements for further discussion.
There are significant present and future environmental regulations to encourage the use of clean energy technologies and regulate
emissions of GHGs to address climate change. Xcel Energy has undertaken a number of initiatives to meet current requirements and
prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. If these
future environmental regulations do not provide credit for the investments we have already made to reduce GHG emissions, or if they
require additional initiatives or emission reductions, then their requirements would potentially impose additional substantial costs.
Xcel Energy believes, based on prior state commission practice, it would recover the cost of these initiatives through rates.
Xcel Energy is committed to addressing climate change and potential climate change regulation through efforts to reduce its GHG
emissions in a balanced, cost-effective manner. Xcel Energy adopted a methodology for calculating CO2 emissions based on the
reporting protocols of The Climate Registry, a nonprofit organization that provides and compiles GHG emissions data from reporting
entities. Starting in 2011, Xcel Energy began reporting GHG emissions to the EPA under the EPA’s mandatory GHG Reporting
Program.
Based on The Climate Registry’s current reporting protocol, Xcel Energy estimated that its current electric generating portfolio
emitted approximately 53.0 million and 56.6 million tons of CO2 in 2016 and 2015, respectively. Xcel Energy also estimated
emissions associated with electricity purchased for resale to Xcel Energy customers from generation facilities owned by third parties.
Xcel Energy estimates these non-owned facilities emitted approximately 9.0 million and 10.2 million tons of CO2 in 2016 and 2015,
respectively. Estimated total CO2 emissions associated with service to Xcel Energy electric customers decreased by 4.9 million tons in
2016 compared to 2015, and this decrease in emissions was associated with an increase of 2.1 million net MWh of generation in 2016
compared to 2015. Since 2012, the average annual decrease in CO2 emissions is approximately 2.8 million tons of CO2 per year.
CAPITAL SPENDING AND FINANCING
See Item 7 for a discussion of expected capital expenditures and funding sources.
EMPLOYEES
As of Dec. 31, 2016, Xcel Energy had 11,440 full-time employees and 72 part-time employees, of which 5,428 were covered under
collective-bargaining agreements. See Note 9 to the consolidated financial statements for further discussion.
32
EXECUTIVE OFFICERS
Ben Fowke, 58, Chairman of the Board, President and Chief Executive Officer and Director, Xcel Energy Inc., August 2011 to
present. Chief Executive Officer, NSP-Minnesota, NSP-Wisconsin, PSCo, and SPS, January 2015 to present. Previously, President
and Chief Operating Officer, Xcel Energy Inc., August 2009 to August 2011.
Christopher B. Clark, 50, President and Director, NSP-Minnesota, January 2015 to present. Previously, Regional Vice President,
Rates and Regulatory Affairs, NSP-Minnesota, October 2012 to December 2014; Managing Director, Government and Regulatory
Affairs, NSP-Minnesota, January 2012 to October 2012; Managing Attorney, Xcel Energy Inc., November 2007 to January 2012.
David L. Eves, 58, President and Director, PSCo, January 2015 to present. Previously, President, Director and Chief Executive
Officer, PSCo, December 2009 to December 2014.
Robert C. Frenzel, 46, Executive Vice President, Chief Financial Officer, Xcel Energy Inc., May 2016 to present. Previously, Senior
Vice President and Chief Financial Officer, Luminant, a subsidiary of Energy Future Holdings Corp., an electric utility and power
generation company, February 2012 to April 2016; Senior Vice President for Corporate Development, Strategy and Mergers and
Acquisitions, Energy Future Holdings Corp., February 2009 to February 2012. In April 2014, Energy Future Holdings Corp., the
majority of its subsidiaries, including Texas Competitive Energy Holdings (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.
David T. Hudson, 56, President and Director, SPS, January 2015 to present. Previously, President, Director and Chief Executive
Officer, SPS, January 2014 to December 2014; Director, Community Service & Economic Development, SPS, April 2011 to January
2014; Director, Strategic Planning, SPS, May 2008 to April 2011.
Kent T. Larson, 57, Executive Vice President and Group President Operations, Xcel Energy Inc., January 2015 to present. Previously,
Senior Vice President, Group President Operations, Xcel Energy Services Inc., August 2014 to December 2014; Senior Vice President
Operations, Xcel Energy Services Inc., September 2011 to August 2014; Chief Energy Supply Officer, Xcel Energy Services Inc.,
March 2010 to September 2011.
Marvin E. McDaniel, Jr., 57, Executive Vice President, Group President, Utilities, and Chief Administrative Officer, Xcel Energy Inc.,
January 2015 to present. Previously, Senior Vice President, Chief Administrative Officer, Xcel Energy Inc., August 2012 to December
2014; Senior Vice President and Chief Administrative Officer, Xcel Energy Services Inc., September 2011 to August 2012; Vice
President and Chief Administrative Officer, Xcel Energy Services Inc., August 2009 to September 2011 and Vice President, Talent and
Technology Business Areas, Xcel Energy Services Inc., August 2009 to September 2011.
Timothy O’Connor, 57, Senior Vice President, Chief Nuclear Officer, Xcel Energy Services Inc., February 2013 to present. Previously,
Acting Chief Nuclear Officer, NSP-Minnesota, September 2012 to February 2013; Vice President, Engineering and Nuclear
Regulatory Compliance and Licensing July 2012 to September 2012; Monticello Site Vice President, May 2007 to July 2012.
Judy M. Poferl, 57, Senior Vice President, Corporate Secretary and Executive Services, Xcel Energy Inc., January 2015 to present.
Previously, Vice President, Corporate Secretary, Xcel Energy Inc., May 2013 to December 2014; President, Director and Chief
Executive Officer, NSP-Minnesota, August 2009 to May 2013.
Jeffrey S. Savage, 45, Senior Vice President, Controller, Xcel Energy Inc., January 2015 to present. Previously, Vice President,
Controller, Xcel Energy Inc., September 2011 to December 2014; Senior Director, Financial Reporting, Corporate and Technical
Accounting, Xcel Energy Services Inc., December 2009 to September 2011.
Mark E. Stoering, 56, President and Director, NSP-Wisconsin, January 2015 to present. Previously, President, Director and Chief
Executive Officer, NSP-Wisconsin, January 2012 to December 2014; Vice President, Portfolio Strategy and Business Development,
Xcel Energy Services Inc., August 2000 to December 2011.
Scott M. Wilensky, 60, Executive Vice President, General Counsel, Xcel Energy Inc., January 2015 to present. Previously, Senior
Vice President, General Counsel, Xcel Energy Inc., September 2011 to December 2014; Vice President, Regulatory and Resource
Planning, Xcel Energy Services Inc., September 2009 to September 2011.
No family relationships exist between any of the executive officers or directors.
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Item 1A — Risk Factors
Xcel Energy is subject to a variety of risks, many of which are beyond our control. Important risks that may adversely affect the
business, financial condition and results of operations are further described below. These risks should be carefully considered together
with the other information set forth in this report and in future reports that Xcel Energy files with the SEC.
Oversight of Risk and Related Processes
A key accountability of the Board of Directors is the oversight of material risk, and our Board of Directors employs an effective
process for doing so. Management and each Board of Directors’ committee has responsibility for overseeing the identification and
mitigation of key risks and reporting its assessments and activities to the full Board of Directors.
Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability.
Management broadly considers our business, the utility industry, the domestic and global economies and the environment when
identifying, assessing, managing and mitigating risk. Identification and analysis occurs formally through a key risk assessment
process conducted by senior management, the financial disclosure process, the hazard risk management process and internal auditing
and compliance with financial and operational controls. Management also identifies and analyzes risk through its business planning
process and development of goals and key performance indicators, which include risk identification to determine barriers to
implementing Xcel Energy’s strategy. The business planning process also identifies areas in which there is a potential for a business
area to take inappropriate risk to meet goals, and determines how to prevent inappropriate risk-taking.
At a threshold level, Xcel Energy has developed a robust compliance program and promotes a culture of compliance, including tone at
the top, which mitigates risk. The process for risk mitigation includes adherence to our code of conduct and other compliance
policies, operation of formal risk management structures and groups and overall business management to mitigate the risks inherent in
the implementation strategy. Building on this culture of compliance, Xcel Energy manages and further mitigates risks through
operation of formal risk management structures and groups, including management councils, risk committees and the services of
internal corporate areas such as internal audit, the corporate controller and legal services.
Management communicates regularly with the Board of Directors and key stakeholders regarding risk. Senior management presents a
periodic assessment of key risks to the Board of Directors. The presentation and the discussion of the key risks provides the Board of
Directors with information on the risks management believes are material, including the earnings impact, timing, likelihood and
controllability. Management also provides information to the Board of Directors in presentations and communications over the course
of the year.
The Board of Directors approaches oversight, management and mitigation of risk as an integral and continuous part of its governance
of Xcel Energy. First, the Board of Directors regularly reviews management’s key risk assessment and analyzes areas of existing and
future risks and opportunities. In addition, the Board of Directors assigns oversight of certain critical risks to each of its four standing
committees to ensure these risks are well understood and given focused oversight by the appropriate committee. The Audit
Committee is responsible for reviewing the adequacy of risk oversight and affirming that appropriate oversight occurs. New risks are
considered and assigned as appropriate during the annual Board of Directors’ and committee evaluation process, and committee
charters and annual work plans are updated accordingly. Committees regularly report on their oversight activities and certain risk
issues may be brought to the full Board of Directors for consideration where deemed appropriate to ensure broad Board of Directors’
understanding of the nature of the risk. Finally, the Board of Directors conducts an annual strategy session where Xcel Energy’s future
plans and initiatives are reviewed and confirmed.
34
Risks Associated with Our Business
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 past, present and future operations, including air
emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances.
These laws and regulations require us to obtain and comply with a wide variety of environmental requirements including those for
protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archaeological and
historical resources), licenses, permits, inspections and other approvals. Environmental laws and regulations can also require us to
restrict or limit the output of certain facilities or the use of certain fuels, shift generation to lower-emitting, but potentially more costly
facilities, install pollution control equipment at our facilities, clean up spills and other contamination and correct environmental
hazards. Environmental regulations may also lead to shutdown of existing facilities, either due to the difficulty in assuring compliance
or that the costs of compliance makes operation of the units no longer economical. Both public officials and private individuals may
seek to enforce the applicable environmental laws and regulations against us. 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 certain other parties, caused environmental contamination.
At Dec. 31, 2016, these sites included:
Sites of former MGPs operated by our subsidiaries, predecessors or other entities; and
•
• Third party sites, such as landfills, for which we are alleged to be a PRP that sent hazardous materials and wastes.
We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. Failure
to meet the requirements of these mandates may result in fines or penalties, which could have a material effect on our results of
operations. 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 position or cash flows.
In addition, existing environmental laws or regulations may be revised, and new laws or regulations may be adopted or become
applicable to us, including but not limited to, regulation of mercury, NOx, SO2, CO2 and other GHGs, particulates, cooling water
intakes, water discharges and ash management. 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.
Climate change can create physical and financial risk. Physical risks from climate change can include changes in weather conditions,
changes in precipitation and extreme weather events.
Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating
and cooling represent their largest energy use. 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 additional generating assets,
transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may result in decreased
revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system
stress, including service interruptions. Weather conditions outside of our service territory could also have an impact on our revenues.
We buy and sell electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy
demand may raise electricity prices, which would increase the cost of energy we provide to our customers.
Severe weather impacts our service territories, primarily when thunderstorms, tornadoes and snow or ice storms occur. To the extent
the frequency of extreme weather events increases, this could increase our cost of providing service. Changes in precipitation
resulting in droughts or water shortages, whether caused by climate change or otherwise, could adversely affect our operations,
principally our fossil generating units. A negative impact to water supplies due to long-term drought conditions could adversely
impact our ability to provide electricity to customers, as well as increase the price they pay for energy. We may not recover all costs
related to mitigating these physical and financial risks.
Climate change may impact a region’s economic health, which could impact our revenues. Our financial performance is tied to the
health of the regional economies we serve. The price of energy has an impact on the economic health of our communities. The cost
of additional regulatory requirements, such as regulation of CO2 emissions under the CAA, or additional environmental regulation
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.
35
Financial Risks
Our profitability depends in part on the ability of our utility subsidiaries to recover their costs from their customers and there may
be changes in circumstances or in the regulatory environment that 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. The utility commissions in the states
where we operate regulate many aspects of our utility operations, including siting and construction of facilities, customer service and
the rates that we can charge customers. The FERC has jurisdiction, among other things, over wholesale rates for electric transmission
service, the sale of electric energy in interstate commerce and certain natural gas transactions in interstate commerce.
The profitability of our utility operations is dependent on our ability to recover the costs of providing energy and utility services to our
customers and earn a return on our capital investment. Our utility subsidiaries provide service at rates approved by one or more
regulatory commissions. These rates are generally regulated and based on an analysis of the utility’s costs incurred in a test year. Our
utility subsidiaries are subject to both future and historical test years depending upon the regulatory mechanisms approved in each
jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its costs at any given time. While rate regulation is
premised on providing an opportunity to earn a reasonable rate of return on invested capital, in a continued low interest rate
environment there has been pressure pushing down ROE. There can also be no assurance that the applicable regulatory commission
will judge all the costs of our utility subsidiaries to have been prudent, which could result in cost disallowances, or that the regulatory
process in which rates are determined will always result in rates that will produce full recovery of such costs. Changes in the long-
term cost-effectiveness or changes to the operating conditions of our assets may result in early retirements and while regulation
typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining
costs leaving all or a portion of these asset costs stranded. Rising fuel costs could increase the risk that our utility subsidiaries will not
be able to fully recover their fuel costs from their customers. Furthermore, there could be changes in the regulatory environment that
would impair the ability of our utility subsidiaries to recover costs historically collected from their customers.
Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place.
However, adverse regulatory rulings or the imposition of additional regulations could have an adverse impact on our results of
operations and hence could materially and adversely affect our ability to meet our financial obligations, including debt payments and
the payment of dividends on our 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 any of our current ratings or our subsidiaries’ ratings will remain in effect for any given period of time, or
that a rating will not be lowered or withdrawn entirely by a rating agency. 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. Also, our utility subsidiaries may enter into certain procurement and derivative contracts that require the 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. Any disruption in
capital markets could have a material impact on our ability to fund our operations. Capital markets are global in nature and are
impacted by numerous issues and events throughout the world economy. Capital market disruption events and resulting broad
financial market distress could prevent us from issuing new securities or cause us to issue securities with less than ideal 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.
Changes in interest rates may also impact the fair value of the debt securities in the nuclear decommissioning fund and master pension
trust, as well as our ability to earn a return on short-term investments of excess cash.
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.
36
Credit risk also includes the risk that various counterparties that owe us money or product will breach their obligations. Should the
counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our
financial results could be adversely affected and we could incur losses.
One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges. The credit risk is then
socialized through the exchange central clearinghouse function. While exchanges do remove counterparty credit risk, all participants
are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value
daily. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires broad clearing of financial swap
transactions through a central counterparty, which could lead to additional margin requirements that would impact our liquidity.
However, we have taken advantage of an exception to mandatory clearing afforded to commercial end-users who are not classified as
a major swap participant. The Board of Directors has authorized Xcel Energy and its subsidiaries to take advantage of this end-user
exception.
We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to various 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 SPP, PJM, MISO and ERCOT, in which any credit losses
are socialized to all market participants.
We do have additional indirect credit exposures to various domestic and foreign financial institutions in the form of letters of credit
provided as security by power suppliers under various long-term physical purchased power contracts. If any of the credit ratings of
the letter of credit issuers were to drop below the designated investment grade rating stipulated in the underlying long-term purchased
power contracts, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the
party could be in technical default under the contract, which would enable us to exercise our contractual rights.
Increasing costs associated with our defined benefit retirement plans and other employee benefits may adversely affect our results
of operations, financial position or liquidity.
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, including mortality tables, have a significant impact on our
funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock
and bond market performance, changes in interest rates and changes in governmental regulations. In addition, the Pension Protection
Act changed the minimum funding requirements for defined benefit pension plans with modifications that allowed additional
flexibility in the timing of contributions. 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 retirements or employees leaving
Xcel Energy could trigger settlement accounting and could require Xcel Energy to recognize material incremental pension expense
related to unrecognized plan losses in the year these liabilities are paid.
Increasing costs associated with health care plans may adversely affect our results of operations.
Our self-insured costs of health care benefits for eligible employees have increased in recent years. Increasing levels of large
individual health care claims and overall health care claims could have an adverse impact on our operating results, financial position
and liquidity. We believe that our employee benefit costs, including costs related to health care plans for our employees and former
employees, will continue to rise. Changes in industry standards utilized by management in key assumptions (e.g., mortality tables)
could have a significant impact on future liabilities and benefit costs. Legislation related to health care could also significantly change
our benefit programs and costs.
We must rely on cash from our subsidiaries to make dividend payments.
We are a holding company and our investments in our subsidiaries are our primary assets. Substantially all of our operations are
conducted by our subsidiaries. Consequently, our operating cash flow and our ability to service our indebtedness and pay dividends
depends upon the operating cash flows of our subsidiaries and the payment dividends to us. 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 to us depends on any statutory and/or contractual restrictions
which may include requirements to maintain minimum levels of equity ratios, working capital or assets. Also, our utility subsidiaries
are regulated by various state utility commissions, which possess broad powers to ensure that the needs of the utility customers are
being met.
If our 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.
37
Changes in federal tax law may significantly impact our business.
There are a number of provisions in federal tax law designed to incentivize capital investments which have benefited our customers by
keeping rates lower than without such provisions. Examples of these include the use of accelerated and bonus depreciation for most of
our capital investments, PTCs for wind energy, investment tax credits for solar energy and research and development tax credits and
deductions. Changes to current federal tax law have the ability to benefit or adversely affect our earnings and our customer costs.
Significant changes in corporate tax rates could result in the impairment of deferred tax assets that are established based on existing
law. Changes to the value of various tax credits could change the economics of resources and our resource selections. While
regulation allows us to incorporate changes in tax law into the rate-setting process, there could be timing delays before realization of
the changes.
Operational Risks
We are subject to commodity risks and other risks associated with energy markets and energy production.
We engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. 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 (mark-to-market accounting). Actual
settlements can vary significantly from estimated fair values recorded, and significant changes from the assumptions underlying our
fair value estimates could cause significant earnings variability.
If we encounter market supply shortages or our suppliers are otherwise unable to meet their contractual obligations, we may be unable
to fulfill our contractual obligations to our customers at previously anticipated costs. Therefore, a significant disruption could cause us
to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Any
significantly higher energy or fuel costs relative to corresponding sales commitments could have a negative impact on our cash flows
and potentially result in economic losses. Potential market supply shortages may not be fully resolved through alternative supply
sources and may cause short-term disruptions in our ability to provide electric and/or natural gas services to our customers. The
impact of these cost and reliability issues vary in magnitude for each operating subsidiary depending upon unique operating conditions
such as generation fuels mix, availability of water for cooling, availability of fuel transportation including rail shipments of coal,
electric generation capacity, transmission, natural gas pipeline capacity, etc.
Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.
NSP-Minnesota’s two nuclear stations, PI and Monticello, subject it to the risks of nuclear generation, which include:
• The risks associated with use of radioactive material in the production of energy, the management, handling, storage and
disposal and the current lack of a long-term disposal solution for radioactive materials;
• Limitations on the amounts and types of insurance available to cover losses that might arise in connection with nuclear
operations; and
• Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their
licensed lives. For example, similar to pensions, interest rate and other assumptions regarding decommissioning costs may
change based on economic conditions and changes in the expected life of the asset 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. In the
event of non-compliance, the NRC has the authority to impose fines and/or shut down a unit until compliance is achieved. Revised
NRC safety requirements could necessitate substantial capital expenditures or a substantial 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 effect on our results of operations or financial condition. Furthermore, the non-
compliance of other nuclear facilities operators or the occurrence of a serious nuclear incident at other facilities could result in
increased regulation of the industry, which could then increase NSP-Minnesota’s compliance costs and impact the results of operations
of its facilities.
NSP-Wisconsin’s production and transmission system is operated on an integrated basis with NSP-Minnesota’s production and
transmission system, and NSP-Wisconsin may be subject to risks associated with NSP-Minnesota’s nuclear generation.
38
Our utility operations are subject to long-term planning risks.
Most electric utility investments are long-lived and are planned to be used for decades. Transmission and generation investments
typically have long lead times, and therefore are planned well in advance of when they are brought in-service subject to long-term
resource plans. These plans are based on numerous assumptions over the planning horizon such as: sales growth, customer usage,
economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. The electric utility sector
is undergoing a period of significant change. For example, public policy has driven increases in appliance and lighting efficiency and
energy efficient buildings, wider adoption and lower cost of renewable generation and distributed generation, including community
solar gardens and customer-sited solar, shifts away from coal generation to decrease CO2 emissions and increasing use of natural gas
in electric generation driven by lower natural gas prices. Over time, customer adoption of these technologies and increased energy
efficiency could result in excess transmission and generation resources as well as stranded costs if Xcel Energy is not able to fully
recover the costs and investments. These changes also introduce additional uncertainty into long-term planning which gives rise to a
risk that the magnitude and timing of resource additions and growth in customer demand may not coincide, and that the preference for
the types of additions may change from planning to execution. In addition, we are also subject to longer-term availability of the
natural resource inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources
during the planning period could jeopardize long-term operations of our facilities or make them uneconomic to operate.
The resource plans reviewed and approved by our state regulators assume continuation of the traditional utility cost of service model
under which utility costs are recovered from customers as they receive the benefit of service. Xcel Energy is engaged in significant
and ongoing infrastructure investment programs to accommodate distributed generation and maintain high system reliability. Xcel
Energy is also investing in renewable and natural gas-fired generation to reduce our CO2 emissions profile. The inability of coal
mining companies to attract capital could disrupt longer-term supplies. Early plant retirements that may result from these changes
could expose us to premature financial obligations, which could result in less than full recovery of all remaining costs. Both
decreasing use per customer driven by appliance and lighting efficiency and the availability of cost-effective distributed generation
puts downward pressure on load growth. This could lead to under recovery of costs, excess resources to meet customer demand and
increases in electric rates.
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 a variety of inherent hazards and operating risks, such as leaks,
explosions and mechanical problems, which could cause substantial financial losses. Our electric transmission and distribution
activities also include inherent hazards and operating risks such as contact, fire and widespread outages which could cause substantial
financial losses. In addition, these natural gas and electric risks could result in loss of human life, significant damage to property,
environmental pollution, impairment of our operations and substantial losses to us. We maintain insurance against some, but not all,
of these risks and losses.
The occurrence of any of these events not fully covered by insurance could have a material effect on our financial position and results
of operations. For our natural gas transmission or distribution lines located near populated areas, the level of potential damages
resulting from these risks is greater.
Additionally, for natural gas the operating or other costs that may be required in order to comply with potential new regulations,
including the Pipeline Safety Act, could be significant. The Pipeline Safety Act requires verification of pipeline infrastructure records
by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or
more-densely populated areas. We have programs in place to comply with the Pipeline Safety Act and for systematic infrastructure
monitoring and renewal over time. A significant incident could increase regulatory scrutiny and result in penalties and higher costs of
operations.
Public Policy Risks
We may be subject to legislative and regulatory responses to climate change and emissions, with which compliance could be
difficult and costly.
Increased public awareness and concern regarding climate change may result in more state, regional and/or federal requirements to
reduce or mitigate the effects of GHGs. Legislative and regulatory responses related to climate change and new interpretations of
existing laws through climate change litigation create financial risk as our electric generating facilities may be subject to additional
regulation at either the state or federal level in the future. Such regulations could impose substantial costs on our system. International
agreements could have an impact to the extent they lead to future federal or state regulations.
39
In 2015, the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change reached consensus among
190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries (“nationally
determined contributions”), with a goal of holding the increase in global average temperature to below 2o Celsius above pre-industrial
levels and an aspiration to limit the increase to 1.5o Celsius. If implemented, the Paris Agreement could result in future additional GHG
reductions in the United States.
We have been, and in the future may be, subject to climate change lawsuits. An adverse outcome in any of these cases could require
substantial capital expenditures and could possibly require payment of substantial penalties or damages. Defense costs associated with
such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows and financial
condition if such costs are not recovered through regulated rates.
The EPA has proposed the CPP, which would regulate GHGs from power plants by mandating state plans to achieve state-specific
emission reduction goals. The legality of the CPP has been challenged in the courts, and the Supreme Court stayed the rule while
those challenges proceed. If the rule is ultimately implemented, uncertainties remain regarding implementation plans, including
available opportunities to reduce costs, availability of emission trading, how states will allocate the reduction burden among utilities,
what actions are creditable and the indirect impact of carbon regulation on natural gas and coal prices.
Some states have indicated a desire to continue to pursue climate policies even in the absence of federal mandates. All of the steps
that 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 standards under the CPP or
the Paris Agreement, repeal of these policies would not impact those state-endorsed actions and plans.
Whether under state or federal programs, an important factor is our ability to recover the costs incurred to comply with any regulatory
requirements in a timely manner. 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.
We are also subject to a significant number of proposed and potential rules that will impact our coal-fired and other generation
facilities. These include rules associated with emissions of SO2 and NOx, mercury, regional haze, ozone and PM, water intakes, water
discharges and ash management. The costs of investment to comply with these rules could be substantial and in some cases would
lead to early retirement of coal units. We may not be able to timely recover all costs related to complying with regulatory
requirements imposed on us.
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 now impose
penalties of up to $1.2 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural
gas. Under statute, the FERC can adjust penalties for inflation. In addition, NERC electric reliability standards and critical
infrastructure protection requirements are mandatory and subject to potential financial penalties by regional entities, the NERC or the
FERC for violations. Additionally, the PHMSA, the Occupational Safety and Health Administration and other federal agencies also
have penalty authority. In the event of serious incidents, these agencies have become more active in pursuing penalties. Some states
have the authority to impose substantial penalties in the event of non-compliance. If a serious reliability or safety incident did occur, it
could have a material effect on our operations or financial results.
We attempt to mitigate the risk of regulatory penalties through formal training on such prohibited practices and a compliance function
that reviews our interaction with the markets under FERC and CFTC jurisdictions. We are also managing natural gas risk on our
system by removing types of pipe (e.g. cast iron) with known problem tendencies and by testing transmission pipelines in high
consequence areas. However, there is no guarantee our compliance programs will be sufficient to ensure against violations.
Macroeconomic Risks
Economic conditions impact our business.
Our operations are affected by local, national and worldwide economic conditions. Growth in our customer base is correlated with
economic conditions. While the number of customers is growing, sales growth is relatively modest due to an increased focus on
energy efficiency including federal standards for appliance and lighting efficiency and distributed generation, primarily solar PV.
Instability in the financial markets also may affect the cost of capital and our ability to raise capital, which is discussed in the capital
market risk section above.
40
Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which
may impact customers’ ability to pay timely, increase customer bankruptcies, and may lead to increased bad debt.
Further, worldwide economic activity has an impact on the demand for basic commodities needed for utility infrastructure, such as
steel, copper, aluminum, etc., which may impact our ability to acquire sufficient supplies. Additionally, the cost of those commodities
may be higher than expected.
Our operations could be impacted by war, acts of terrorism, threats of terrorism or disruptions in normal operating conditions due
to localized or regional events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist
activities. Any such disruption could 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 and results of operations. 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. In addition, we may experience additional capital and operating costs to
implement security for our plants, including our nuclear power plants under the NRC’s design basis threat requirements. We have also
already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection. In
addition, we may experience additional capital and operating costs to comply with the NERC critical infrastructure protection
standards as they are implemented and clarified.
The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, the
insurance we are able to obtain 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. Because our generation, the transmission systems and local natural gas distribution companies 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 or an event (severe storm, severe temperature extremes, wildfires, solar storms, generator or transmission facility
outage, breakdown or failure of equipment, pipeline rupture, railroad disruption, sudden and significant increase or decrease in wind
generation or any disruption of work force such as may be caused by flu or other epidemic) within our operating systems or on a
neighboring system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair
assets, which could have a material impact on our financial condition and results.
The degree to which we are able to maintain day-to-day operations in response to unforeseen events will in part determine the
financial impact of certain events on our financial condition and results. It is difficult to predict the magnitude of such events and
associated impacts.
A cyber incident or cyber security breach could have a material effect on our business.
We operate in an industry that requires the continued operation of sophisticated information technology 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.
Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or
physical assets, as well as the information processed in our systems (e.g., information about our customers, employees, operations,
infrastructure and assets) could be affected by cyber security incidents, including those caused by human error. Our industry has
begun to see 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 exposing us to liability. Our 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. In addition, such an event would likely receive regulatory scrutiny at both the federal and state level.
We are unable to quantify the potential impact of cyber security threats or subsequent related actions. These potential cyber security
incidents and corresponding 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.
41
We maintain security measures designed to protect our information technology systems, network infrastructure and other assets.
However, these assets and the information they process may be vulnerable to cyber security incidents, including the resulting
disability, or failures of assets or unauthorized access to assets or information. If our technology systems were to fail or be breached,
or those of our third-party service providers, we may be unable to fulfill critical business functions, including effectively maintaining
certain internal controls over financial reporting. We are unable to quantify the potential impact of cyber security incidents on our
business.
Rising energy prices could negatively impact our business.
Although commodity prices are currently relatively low, if fuel costs increase, customer demand could decline and bad debt expense
may rise, which could have a material impact on our results of operations. While we have fuel clause 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 as compared with expenditures for fuel purchases could have an impact on our cash flows. Low fuel
costs could have a positive impact on sales, although particularly on the southern part of our service territory, low oil prices could
negatively impact oil and gas production activities. We are unable to predict future prices or the ultimate impact of such prices on our
results of operations or cash flows.
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 throughout our
service territory, and 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.
Our operations use third party contractors in addition to employees to perform periodic and on-going work.
We rely on third party contractors with specific qualifications to perform work both for ongoing operations and maintenance and for
capital construction. We have contractual arrangements with these contractors which typically include performance standards,
progress payments, insurance requirements and security for performance. Poor vendor performance could impact on going operations,
restoration operations, our reputation and could introduce financial risk or risks of fines for Xcel Energy.
Item 1B — Unresolved Staff Comments
None.
42
Item 2 — Properties
Virtually all of the utility plant property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the lien of their first
mortgage bond indentures.
Electric Utility Generating Stations:
NSP-Minnesota
Station, Location and Unit
Steam:
A.S. King-Bayport, Minn., 1 Unit . . . . . . . . . . . . . . . . . . . . .
Sherco-Becker, Minn.
Unit 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unit 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unit 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Monticello-Monticello, Minn., 1 Unit . . . . . . . . . . . . . . . . . .
PI-Welch, Minn.
Unit 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unit 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fuel
Coal
Coal
Coal
Coal
Nuclear
Nuclear
Nuclear
Various locations, 4 Units. . . . . . . . . . . . . . . . . . . . . . . . . . . . Wood/Refuse-derived fuel
Combustion Turbine:
Angus Anson-Sioux Falls, S.D., 3 Units . . . . . . . . . . . . . . . .
Black Dog-Burnsville, Minn., 2 Units . . . . . . . . . . . . . . . . . .
Blue Lake-Shakopee, Minn., 6 Units . . . . . . . . . . . . . . . . . . .
High Bridge-St. Paul, Minn., 3 Units . . . . . . . . . . . . . . . . . . .
Inver Hills-Inver Grove Heights, Minn., 6 Units . . . . . . . . . .
Riverside-Minneapolis, Minn., 3 Units . . . . . . . . . . . . . . . . .
Various locations, 14 Units. . . . . . . . . . . . . . . . . . . . . . . . . . .
Wind:
Grand Meadow-Mower County, Minn., 67 Units. . . . . . . . . .
Nobles-Nobles County, Minn., 134 Units . . . . . . . . . . . . . . .
Pleasant Valley-Mower County, Minn., 100 Units. . . . . . . . .
Border-Rolette County, N.D., 75 Units . . . . . . . . . . . . . . . . .
Courtenay Wind, N.D., 100 Units. . . . . . . . . . . . . . . . . . . . . .
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Wind
Wind
Wind
Wind
Wind
Installed
1968
1976
1977
1987
1971
1973
1974
Various
1994-2005
1987-2002
1974-2005
2008
1972
2009
Various
2008
2010
2015
2015
2016
Total
Summer 2016
Net Dependable
Capability (MW)
511
680
682
517 (a)
617
521
519
36 (b)
327
282
453
530
282
454
67
101 (c)
201 (c)
200 (c)
150 (c)
200 (c)
7,330
(a)
(b)
(c)
Based on NSP-Minnesota’s ownership of 59 percent.
Refuse-derived fuel is made from municipal solid waste.
This capacity is only available when wind conditions are sufficiently high enough to support the noted generation values above. Therefore, the on-demand net
dependable capacity is zero.
NSP-Wisconsin
Fuel
Station, Location and Unit
Steam:
Coal/Wood/Natural Gas
Bay Front-Ashland, Wis., 3 Units. . . . . . . . . . . . . . . . . . . . . .
French Island-La Crosse, Wis., 2 Units . . . . . . . . . . . . . . . . . Wood/Refuse-derived fuel
Combustion Turbine:
Flambeau Station-Park Falls, Wis., 1 Unit . . . . . . . . . . . . . . .
French Island-La Crosse, Wis., 2 Units . . . . . . . . . . . . . . . . .
Wheaton-Eau Claire, Wis., 5 Units. . . . . . . . . . . . . . . . . . . . .
Hydro:
Various locations, 63 Units. . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural Gas
Oil
Natural Gas/Oil
Hydro
Installed
1948-1956
1940-1948
1969
1974
1973
Various
Total
Summer 2016
Net Dependable
Capability (MW)
56
16
(a)
12
122
238
135
579
(a)
Refuse-derived fuel is made from municipal solid waste.
43
PSCo
Station, Location and Unit
Steam:
Cherokee-Denver, Colo., 1 Unit . . . . . . . . . . . . . . . . . . . . . . .
Comanche-Pueblo, Colo.
Unit 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unit 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unit 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Craig-Craig, Colo., 2 Units. . . . . . . . . . . . . . . . . . . . . . . . . . .
Hayden-Hayden, Colo., 2 Units . . . . . . . . . . . . . . . . . . . . . . .
Pawnee-Brush, Colo., 1 Unit . . . . . . . . . . . . . . . . . . . . . . . . .
Valmont-Boulder, Colo., 1 Unit . . . . . . . . . . . . . . . . . . . . . . .
Combustion Turbine:
Blue Spruce-Aurora, Colo., 2 Units . . . . . . . . . . . . . . . . . . . .
Cherokee-Denver, Colo., 3 Units . . . . . . . . . . . . . . . . . . . . . .
Fort St. Vrain-Platteville, Colo., 6 Units. . . . . . . . . . . . . . . . .
Rocky Mountain-Keenesburg, Colo., 3 Units . . . . . . . . . . . .
Various locations, 6 Units. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hydro:
Cabin Creek-Georgetown, Colo.
Pumped Storage, 2 Units . . . . . . . . . . . . . . . . . . . . . . . . . . .
Various locations, 9 Units. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fuel
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Coal
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Hydro
Hydro
Installed
1968
1973
1975
2010
1979-1980
1965-1976
1981
1964
2003
2015
1972-2009
2004
Various
1967
Various
Total
Summer 2016
Net Dependable
Capability (MW)
352 (a)
325
335
500 (b)
83 (c)
233 (d)
505
184 (e)
264
576
968
580
171
210
26
5,312
(a)
(b)
Cherokee Unit 4 will be fuel switched from coal to natural gas by Dec. 31, 2017.
Based on PSCo’s ownership interest of 67 percent of Unit 3.
(c)
Based on PSCo’s ownership interest of 10 percent. Craig Unit 1 is expected to be early retired in approximately 2025.
(d)
(e)
Based on PSCo’s ownership interest of 76 percent of Unit 1 and 37 percent of Unit 2.
Valmont Unit 5 will be retired by Dec. 31, 2017.
SPS
Station, Location and Unit
Steam:
Cunningham-Hobbs, N.M., 2 Units . . . . . . . . . . . . . . . . . . . . . . . . .
Harrington-Amarillo, Texas, 3 Units . . . . . . . . . . . . . . . . . . . . . . . .
Jones-Lubbock, Texas, 2 Units. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Maddox-Hobbs, N.M., 1 Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nichols-Amarillo, Texas, 3 Units. . . . . . . . . . . . . . . . . . . . . . . . . . .
Plant X-Earth, Texas, 4 Units. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tolk-Muleshoe, Texas, 2 Units. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Combustion Turbine:
Carlsbad-Carlsbad, N.M., 1 Unit . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cunningham-Hobbs, N.M., 2 Units . . . . . . . . . . . . . . . . . . . . . . . . .
Jones-Lubbock, Texas, 2 Units. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Maddox-Hobbs, N.M., 1 Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(a)
Carlsbad Unit 5 was decommissioned on Dec. 31, 2016.
Fuel
Installed
Summer 2016
Net Dependable
Capability (MW)
Natural Gas
Coal
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Coal
Natural Gas
Natural Gas
Natural Gas
Natural Gas
1957-1965
1976-1980
1971-1974
1967
1960-1968
1952-1964
1982-1985
1968
1998
2011-2013
1963-1976
Total
254
1,018
486
112
457
411
1,067
— (a)
212
338
61
4,416
44
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2016:
Conductor Miles
500 KV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
345 KV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
230 KV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
161 KV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
138 KV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
115 KV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less than 115 KV . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NSP-Minnesota
NSP-Wisconsin
PSCo
SPS
2,917
9,012
2,157
417
—
7,517
85,068
—
1,153
—
1,577
—
1,817
32,537
—
2,630
12,890
—
92
4,929
76,355
—
8,509
9,424
—
—
12,685
24,499
Electric utility transmission and distribution substations at Dec. 31, 2016:
Quantity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
345
204
230
452
NSP-Minnesota
NSP-Wisconsin
PSCo
SPS
Natural gas utility mains at Dec. 31, 2016:
Miles
Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NSP-Minnesota
NSP-Wisconsin
PSCo
WGI
134
10,218
—
2,395
2,281
22,262
11
—
Item 3 — Legal Proceedings
Xcel Energy is involved in various litigation matters that are being defended and handled 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 such losses that are 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.
Additional Information
See Note 13 to the consolidated financial statements for further discussion of legal claims and environmental proceedings. See Item 1,
Item 7 and Note 12 to the consolidated financial statements for a discussion of proceedings involving utility rates and other regulatory
matters.
Item 4 — Mine Safety Disclosures
None.
PART II
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Quarterly Stock Data
Xcel Energy Inc.’s common stock is listed on the New York Stock Exchange (NYSE). The trading symbol is XEL. The number of
common shareholders of record as of Dec. 31, 2016 was approximately 61,779. The following are the intra-day high and low stock
prices based on the NYSE Composite Transactions for the quarters of 2016 and 2015 and the dividends declared per share during
those quarters. See Item 7 and Note 4 to the consolidated financial statements for further discussion of Xcel Energy Inc.’s dividend
policy and restrictions.
2016
First quarter. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
High
Low
Dividends
$
41.85
44.78
45.42
41.80
$
35.19
38.43
40.34
38.00
0.3400
0.3400
0.3400
0.3400
45
2015
First quarter. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
High
Low
Dividends
$
38.35
35.35
36.48
37.25
$
33.41
31.76
32.12
34.33
0.3200
0.3200
0.3200
0.3200
The following compares our cumulative TSR on common stock with the cumulative TSR of the EEI Investor-Owned Electrics Index
and the S&P 500 Composite Stock Price Index over the last five years (assuming a $100 investment on Dec. 31, 2011, and the
reinvestment of all dividends).
The EEI Investor-Owned Electrics Index (market capitalization-weighted) included 44 companies at year-end and is a broad measure
of industry performance.
COMPARISON OF FIVE YEAR CUMULATIVE TOTAL RETURN*
Among Xcel Energy Inc., the EEI Investor-Owned Electrics
and the S&P 500
* $100 invested on Dec. 31, 2011 in stock or index — including reinvestment of dividends. Fiscal years ending Dec. 31.
Xcel Energy Inc.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
EEI Investor-Owned Electrics . . . . . . . . . . . . . . . . . . . .
S&P 500 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
100
100
100
$
100
102
116
$
109
115
154
$
146
149
175
$
151
143
177
177
168
198
2011
2012
2013
2014
2015
2016
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 Inc.’s Proxy Statement for its 2017 Annual Meeting of Shareholders, which is incorporated by reference.
46
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table provides information about our purchases of equity securities that are registered by Xcel Energy Inc. for the fourth
quarter of fiscal year 2016, pursuant to Section 12 of the Exchange Act:
Issuer Purchases of Equity Securities
Period
Oct. 1, 2016 — Nov. 30, 2016. . . . . . . .
Dec. 1, 2016 — Dec. 31, 2016 (a) . . . . .
Total. . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Number
of Shares
Purchased
Average Price
Paid per Share
—
730,000
730,000
$
—
39.99
Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or
Programs
Maximum Number of Shares
That May Yet Be Purchased
Under the Plans or Programs
730,000
730,000
2,270,000
2,270,000
(a)
In October 2015, the Xcel Energy Inc. Board of Directors authorized open market purchases of up to 3.0 million shares for share-based compensation plan
settlements with no expiration date for repurchases made under this authority.
Item 6 — Selected Financial Data
Set forth below is selected financial data for Xcel Energy related to the most five recent years ended Dec. 31. This information has
been derived from and should be read in conjunction with the consolidated financial statements and notes appearing elsewhere in this
annual report on Form 10-K.
(Millions of Dollars, Thousands of Shares, Except Per Share Data)
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Earnings available to common shareholders . . . . . . . . . . . . .
Weighted average common shares outstanding:
2016
11,107
8,893
1,123
1,123
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
508,794
509,465
EPS:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividends declared per common share . . . . . . . . . . . . . . . . .
Total assets (a) (b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt (b) (c). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Book value per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Return on average common equity . . . . . . . . . . . . . . . . . . . .
Ratio of earnings to fixed charges (d) . . . . . . . . . . . . . . . . . . .
2.21
2.21
1.36
41,155
14,195
21.73
$
$
2015
11,025
9,024
984
984
507,768
508,168
1.94
1.94
1.28
38,821
12,399
20.89
$
$
2014
11,686
9,738
1,021
1,021
503,847
504,117
2.03
2.03
1.20
36,958
11,500
20.20
$
$
2013
10,915
9,067
948
948
496,073
496,532
1.91
1.91
1.11
33,907
10,911
19.21
$
$
2012
10,128
8,306
905
905
487,899
488,434
1.86
1.85
1.07
31,141
10,144
18.19
10.4%
3.3
9.5%
3.2
10.3%
3.3
10.3%
3.1
10.4%
2.8
Non-GAAP:
Ongoing earnings (e) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Ongoing diluted EPS (e) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1,123
2.21
1,064
2.09
$
1,021
2.03
$
$
968
1.95
888
1.82
(a) As a result of adopting ASU No. 2015-17 (Balance Sheet Classification of Deferred Taxes, Topic 740), $140.2 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. See Note 2 for additional
information.
(b) As a result of adopting ASU No. 2015-03 (Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30), $91.8 million of deferred debt issuance costs
was retrospectively reclassified from other non-current assets to long-term debt on the consolidated balance sheet as of Dec. 31, 2015. See Note 2 for additional
information.
(c)
(d)
(e)
Includes capital lease obligations.
See Exhibit 12.01.
See Item 7 for reconciliations of ongoing earnings and diluted EPS to GAAP earnings and diluted EPS.
47
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations
Business Segments and Organizational Overview
Xcel Energy Inc. is a public utility holding company. Xcel Energy’s operations included the activity of four utility subsidiaries that
serve electric and natural gas customers in eight states. These utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS.
These utilities serve customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and
Wisconsin. Along with the TransCo 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, these companies comprise the regulated
utility operations.
Xcel Energy Inc.’s nonregulated subsidiaries are Eloigne and Capital Services. Eloigne invests in rental housing projects that qualify
for low-income housing tax credits, and Capital Services procures equipment for construction of renewable generation facilities at
other subsidiaries.
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 2017 EPS guidance and
assumptions, are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,”
“may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” 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, 2016 (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 and Exhibit 99.01 hereto), could cause actual results to differ materially from management expectations as
suggested by such forward-looking information: 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;
business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth, recovery, trade,
fiscal, taxation and environmental policies in areas where Xcel Energy has a financial interest; customer business conditions; actions
of credit rating agencies; competitive factors including the extent and timing of the entry of additional competition in the markets
served by Xcel Energy and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber
security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and
investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance
conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other
effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies
imposed by regulatory bodies; outcomes of regulatory proceedings; availability of cost of capital; and employee work force factors.
Management’s Strategic Priorities
Xcel Energy strives to provide our investors an attractive value proposition and our customers with safe, clean and reliable energy
services at a competitive price. This mission is enabled via five key strategic priorities:
Invest in infrastructure;
Improve the customer experience;
•
•
• Advance the regulatory framework and performance;
• Transition the power generation fleet; and
•
Provide a competitive total return to investors and maintain strong investment grade credit ratings.
Below is a discussion of these objectives.
48
Invest in infrastructure
Sound investments today are necessary for tomorrow’s success. Our capital expenditures are projected to be approximately $18.4
billion from 2017 through 2021. This capital investment profile will grow our consolidated rate base at a compounded average annual
rate of approximately 5.5 percent. Our capital plan includes investments in renewables, transmission, distribution, electric generation,
natural gas and other parts of our utility business. Our plan includes approximately $1.3 billion of investment for grid modernization
to improve the customer experience, enhance grid reliability and enable new and innovative programs and rate structures. In addition,
we plan to invest $2.2 billion in gas infrastructure to enhance safety, reliability and operational performance for the benefit of our
customers and communities.
Improve the customer experience
The utility landscape is changing, and we must continue to thoughtfully anticipate and address the future needs of our stakeholders,
including our customers, policymakers, employees and shareholders. Adapting to this changing environment is critical to our long-
term success. Our customers expect to have choices, and we are committed to providing options and solutions that they want and
value at a competitive price. Our continued investment in clean energy is an example of this commitment to our customers.
Environmental stewardship remains foundational to Xcel Energy and is designed to meet customer and policy maker expectations
while creating shareholder value. We will continue to offer and expand our production of renewable energy, including wind and solar
alternatives, and further develop and promote DSM, conservation and renewable programs.
Advance the regulatory framework and performance
Xcel Energy is a holding company comprised primarily of several utility operating companies. As part of the regulatory process, each
state will generally establish an authorized ROE. In many states, our utility operating companies earn less than the authorized ROE
due to numerous factors including the timing of implementation of new rates, timing of capital investments, a regulatory commission
not allowing the recovery of certain costs, the time period used as a test year for rate cases, fluctuations in sales, the impact of weather,
unanticipated cost increases, etc. The difference between the authorized ROE and the earned ROE is referred to as an ROE gap. Xcel
Energy is focused on reducing this gap.
We continue to pursue regulatory and legislative changes to streamline rate case proceedings and optimize recovery, while improving
our alignment with state policies and keeping pace with evolving customer preferences.
In addition, keeping our costs competitive is also essential in terms of customer affordability and improving ROE over time. Xcel
Energy is working to keep O&M expense relatively flat without compromising reliability or safety. We intend to accomplish this
objective by continually improving our processes, leveraging technology, proactively managing risk and maintaining a workforce that
is prepared to meet the needs of our business today and tomorrow.
Transition the power generation fleet
For more than a decade, we have managed the risk of climate change through a clean energy strategy that consistently reduces carbon
emissions and transitions our operations for the future. We continue to provide shareholder value while transforming how we produce,
deliver and encourage the efficient use of energy through four primary mechanisms:
Increasing the use of renewable energy;
•
• Offering energy efficiency programs for customers;
• Retiring or repowering coals units and modernizing our generating plants; and
• Advancing power grid capabilities.
Our service territories benefit from the geographic concentration of favorable renewable resources. Strong wind and high solar
irradiance yield high generation capacity factors and consequently lowers the cost of these resources.
49
The combination of high capacity factors, a strong transmission network, improved supply chain, technological improvements and the
extension of the renewable tax credits translates into low renewable energy costs for our customers. As a result, we have a beneficial
opportunity to invest in renewable generation, in which the capital costs are largely or completely offset by fuel savings. This
provides us the opportunity to lower the emission profile of our generation fleet, grow our renewable portfolio and provide significant
fuel savings to our customers.
Our capital forecast for 2017-2021 includes $3.5 billion of investment in renewable generation. This includes the following projects:
• The 600 MW Rush Creek wind project in Colorado, which was approved by the CPUC in 2016;
• A proposal to build and own 750 MW of new wind generation at NSP-Minnesota. This project is pending MPUC approval;
•
and
Plans to spend an additional $1.5 billion on other renewable projects in our various states. This could include our preliminary
plans to add 500-1,000 MW of wind generation at SPS.
Emission reductions are an important driver of our strategy. Since 2005, we have reduced carbon emissions 30 percent and are
projected to achieve an approximate 43 percent reduction by 2021.
Provide a competitive total return to investors and maintain strong investment grade credit
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 plan to:
• Deliver long-term annual EPS growth of four percent to six percent;
• Deliver annual dividend increases of five percent to seven percent;
• Target a dividend payout ratio of 60 to 70 percent of annual ongoing EPS; and
• Maintain senior unsecured debt credit ratings in the BBB+ to A range.
We have successfully achieved our prior financial objectives, meeting or exceeding our earnings guidance range for twelve
consecutive years and believe we are positioned to continue to deliver on our value proposition. Our ongoing earnings have grown
approximately 6.1 percent and our dividend has grown approximately 4.3 percent annually from 2005 through 2016. In addition, our
current senior unsecured debt credit ratings for Xcel Energy and its utility subsidiaries are in the BBB+ to A range.
Financial Review
The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy’s financial
condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It
should be read in conjunction with the accompanying consolidated financial statements and the related notes to consolidated financial
statements.
The only common equity securities that are publicly traded are common shares of Xcel Energy Inc. The diluted earnings and EPS of
each subsidiary as well as the ROE of each subsidiary discussed below do not represent a direct legal interest in the assets and
liabilities allocated to such subsidiary but rather represent a direct interest in our assets and liabilities as a whole. Ongoing diluted
EPS and ongoing ROE for Xcel Energy and by subsidiary are financial measures not recognized under GAAP. Ongoing diluted EPS
is calculated by dividing the net income or loss attributable to the controlling interest of each subsidiary, adjusted for certain
nonrecurring items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing ROE
is calculated by dividing the net income or loss attributable to the controlling interest of Xcel Energy or each subsidiary, adjusted for
certain nonrecurring items, by each entity’s average common stockholders’ or stockholder’s equity. We use these non-GAAP financial
measures to evaluate and provide details of earnings results. We believe these measurements are useful to investors to evaluate the
actual and projected financial performance and contribution of our subsidiaries. These non-GAAP financial measures should not be
considered as alternatives to measures calculated and reported in accordance with GAAP.
50
Results of Operations
The following table summarizes the diluted EPS for Xcel Energy:
Diluted Earnings (Loss) Per Share
NSP-Minnesota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
PSCo. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NSP-Wisconsin. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity earnings of unconsolidated subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulated utility (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Xcel Energy Inc. and other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ongoing diluted EPS (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on Monticello LCM/EPU project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
GAAP diluted EPS (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2016
2015
2014
0.96
0.91
0.30
0.14
0.05
2.35
(0.15)
2.21
—
2.21
$
$
0.85
0.92
0.25
0.15
0.04
2.21
(0.11)
2.09
(0.16)
1.94
$
$
0.80
0.90
0.26
0.14
0.04
2.14
(0.11)
2.03
—
2.03
(a)
Amounts may not add due to rounding.
Ongoing earnings for 2015 excludes an adjustment related to the Monticello nuclear facility LCM/EPU project. See below as well as
Note 12 to the consolidated financial statements for further discussion.
Xcel Energy’s management believes that ongoing earnings provide a meaningful comparison of earnings results and is representative
of Xcel Energy’s fundamental core earnings power. Xcel Energy’s management uses ongoing earnings internally for financial
planning and analysis, for reporting of results to the Board of Directors, in determining whether performance targets are met for
performance-based compensation and when communicating its earnings outlook to analysts and investors.
2015 Adjustment to GAAP Earnings
Loss on Monticello LCM/EPU Project — In March 2015, the MPUC approved full recovery, including a return, on $415 million of
the project costs, inclusive of AFUDC, but only allowed recovery of the remaining $333 million of costs with no return on this portion
of the investment for 2015 and beyond. As a result of this decision, Xcel Energy recorded a pre-tax charge of approximately $129
million, or $79 million net of tax, in the first quarter of 2015. See Note 12 to the consolidated financial statements for further
discussion.
Earnings Adjusted for Certain Items
2016 Comparison with 2015
Xcel Energy — 2016 GAAP earnings increased due to the 2015 loss on Monticello LCM/EPU project, see Note 12 for further
information. In addition, GAAP and ongoing earnings increased $0.12 per share. Increases in electric and natural gas margins were
primarily driven by higher rates and riders across various jurisdictions to recover our capital investments and the favorable impact of
weather as compared with the previous year. These positive factors and a lower ETR were partially offset by higher depreciation,
interest charges and property taxes.
NSP-Minnesota — 2016 GAAP earnings increased due to the 2015 loss on Monticello LCM/EPU project, see Note 12 for further
information. In addition, GAAP and ongoing earnings increased $0.11 per share due to the following: higher electric margins
primarily driven by an interim electric rate increase in Minnesota (net of estimated provision for refund); non-fuel riders; the favorable
impact of weather; and a lower ETR. These positive factors were partially offset by higher depreciation, O&M expenses, interest
charges and property taxes
51
PSCo — Earnings decreased $0.01 per share for 2016. The positive impact of higher natural gas margins (primarily due to a rate
increase), sales growth and a lower estimated electric earnings test refund, were more than offset by increased depreciation and
interest charges.
SPS — Earnings increased $0.05 per share for 2016. Higher electric margins and lower O&M expenses were partially offset by an
increase in depreciation and interest charges.
NSP-Wisconsin — Earnings decreased $0.01 per share for 2016. The positive impact of higher electric margins (primarily driven by
an electric rate increase) was more than offset by higher O&M expenses and depreciation.
Equity earnings of unconsolidated subsidiaries — Earnings of unconsolidated subsidiaries increased $0.01 per share in 2016 due to
facility expansion and increased sales at WYCO.
Xcel Energy Inc. and other — Xcel Energy Inc. and other includes financing costs at the holding company and other items.
The decrease in earnings was primarily related to higher long-term debt levels.
2015 Comparison with 2014
Xcel Energy — Twelve month year-over-year GAAP earnings decreased due to the 2015 loss on Monticello LCM/EPU project, refer
to Note 12 for further information. Ongoing earnings increased $0.06 per share for 2015 primarily due to rate increases in various
jurisdictions, non-fuel riders, a lower earnings test refund in Colorado and a decline in O&M expenses. These positive factors were
partially offset by the impact of negative weather as well as higher depreciation, property taxes, interest charges and lower AFUDC.
NSP-Minnesota — Twelve month year-over-year GAAP earnings decreased due to the 2015 loss on Monticello LCM/EPU project,
refer to Note 12 for further information. Ongoing earnings increased $0.05 per share for 2015 and were positively impacted by
electric rate increases in Minnesota, North Dakota and South Dakota, and lower O&M expenses. These positive factors were partially
offset by unfavorable weather, sales decline, higher depreciation, increased interest charges, property taxes and lower AFUDC.
PSCo — Earnings increased $0.02 per share for 2015. Higher revenue primarily due to the CACJA rider (partially offset by an
electric base rate decrease), as well as a natural gas rate increase, effective in October 2015, lower estimated electric earnings test
refunds and the positive impact of weather. These positive factors were partially offset by higher property taxes, depreciation, O&M
expenses, interest charges and lower AFUDC.
SPS — Earnings decreased $0.01 per share for 2015. Although Texas electric rates rose as a result of the prior year rate case, this was
reduced by the negative impact of the 2015 case. The net increase in electric rates was more than offset by additional depreciation,
higher O&M expenses and lower AFUDC.
NSP-Wisconsin — Earnings increased $0.01 per share for 2015. Higher electric revenues primarily driven by an electric rate increase
and lower O&M expenses were partially offset by higher depreciation and lower natural gas margins.
52
Changes in Diluted EPS
The following table summarizes significant components contributing to the changes in 2016 EPS compared with the same period in
2015:
Diluted Earnings (Loss) Per Share
2015 GAAP diluted EPS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on Monticello LCM/EPU project. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015 ongoing diluted EPS (a). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Dec. 31
1.94
0.16
2.09
Components of change — 2016 vs. 2015
Higher electric margins . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lower ETR . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Higher natural gas margins. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Higher depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Higher interest charges. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Higher taxes (other than income taxes) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016 GAAP and ongoing diluted EPS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
0.32
0.06
0.04
(0.21)
(0.06)
(0.02)
(0.01)
2.21
Diluted Earnings (Loss) Per Share
2014 GAAP and ongoing diluted EPS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dec. 31
2.03
Components of change — 2015 vs. 2014
Higher electric margins . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lower conservation and DSM program expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lower O&M expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Higher depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lower AFUDC — equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Higher ETR . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Higher taxes (other than income taxes) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Higher interest charges. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015 ongoing diluted EPS (a). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on Monticello LCM/EPU project. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015 GAAP diluted EPS (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
0.31
0.09
0.01
(0.13)
(0.07)
(0.06)
(0.06)
(0.03)
0.01
2.09
(0.16)
1.94
(a)
Amounts may not add due to rounding.
The following table summarizes the ROE for Xcel Energy and its utility subsidiaries:
ROE — 2016
2016 GAAP and ongoing ROE . . .
NSP-Minnesota
9.29%
PSCo
SPS
8.92%
8.14%
NSP-Wisconsin
8.63%
Operating
Companies
Xcel Energy
8.94%
10.39%
ROE — 2015
2015 ongoing ROE . . . . . . . . . . . .
Loss on Monticello LCM/EPU
project . . . . . . . . . . . . . . . . . . . . .
2015 GAAP ROE . . . . . . . . . . . . .
NSP-Minnesota
PSCo
SPS
NSP-Wisconsin
Operating
Companies
Xcel Energy
8.72%
(1.49)
7.23%
9.33%
—
9.33%
7.56%
10.45%
8.91%
10.22%
—
7.56%
(0.42)
10.03%
(0.62)
8.29%
(0.76)
9.46%
53
The following tables provide reconciliations of ongoing to GAAP earnings (net income) and ongoing to GAAP diluted EPS for the
years ended Dec. 31:
(Millions of Dollars)
Ongoing earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on Monticello LCM/EPU project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
GAAP earnings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
$
Diluted Earnings (Loss) Per Share
Ongoing diluted EPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on Monticello LCM/EPU project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
GAAP diluted EPS (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2016
1,123.4
—
1,123.4
2016
2.21
—
2.21
$
$
$
$
2015
1,063.7
(79.2)
984.5
2015
2.09
(0.16)
1.94
$
$
$
$
2014
1,021.3
—
1,021.3
2014
2.03
—
2.03
(a)
Amounts may not add due to rounding.
Statement of Income Analysis
The following discussion summarizes the items that affected the individual revenue and expense items reported in the consolidated
statements of income.
Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and
natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on
the number of customers, temperature variances and the amount of natural gas or electricity the average customer historically uses per
degree of temperature. Accordingly, deviations in weather from normal levels can affect Xcel Energy’s financial performance.
Degree-day or Temperature-Humidity Index (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. Heating degree-days (HDD) is the measure of the variation
in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. Cooling degree-days (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 as defined above to derive the amount of demand
associated with the weather impact.
The percentage increase (decrease) in normal and actual HDD, CDD and THI are provided in the following table:
HDD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CDD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
THI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(13.4)%
11.1
7.7
(7.9)%
6.2
(2.3)
(5.5)%
5.1
10.9
7.8%
(2.6)
(11.9)
2016 vs.
Normal
2015 vs.
Normal
2016 vs.
2015
2014 vs.
Normal
2015 vs.
2014
(14.8)%
10.3
14.1
Weather — The following table summarizes the estimated impact of temperature variations on EPS compared with sales under normal
weather conditions:
Retail electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Firm natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
$
0.002
(0.025)
(0.023) $
(0.020) $
(0.018)
(0.038) $
0.022
(0.007)
0.015
$
$
0.010
0.019
0.029
$
$
(0.030)
(0.037)
(0.067)
2016 vs.
Normal
2015 vs.
Normal
2016 vs.
2015
2014 vs.
Normal
2015 vs.
2014
54
Sales Growth (Decline) — The following tables summarize Xcel Energy and its utility subsidiaries’ sales growth (decline) for actual
and weather-normalized sales for the years ended Dec. 31, compared with the previous year:
NSP-Minnesota
PSCo
SPS
NSP-Wisconsin
Xcel Energy
2016 vs. 2015
Actual
Electric residential (a) . . . . . . . . . . . . . . . . . . .
Electric C&I. . . . . . . . . . . . . . . . . . . . . . . . . .
Total retail electric sales . . . . . . . . . . . . . . .
Firm natural gas sales . . . . . . . . . . . . . . . . . .
1.2%
(0.5)
—
(4.1)
1.8%
(0.4)
0.4
(1.1)
(1.6)%
1.1
0.7
N/A
2016 vs. 2015
0.3%
(0.1)
(0.1)
(7.4)
0.9%
—
0.3
(2.4)
Weather-normalized
Electric residential (a) . . . . . . . . . . . . . . . . . . .
Electric C&I. . . . . . . . . . . . . . . . . . . . . . . . . .
Total retail electric sales . . . . . . . . . . . . . . .
Firm natural gas sales . . . . . . . . . . . . . . . . . .
Weather-normalized - adjusted for leap
day
Electric residential (a) . . . . . . . . . . . . . . . . . . .
Electric C&I. . . . . . . . . . . . . . . . . . . . . . . . . .
Total retail electric sales . . . . . . . . . . . . . . . .
Firm natural gas sales . . . . . . . . . . . . . . . . . .
NSP-Minnesota
PSCo
SPS
NSP-Wisconsin
Xcel Energy
0.1%
(0.8)
(0.5)
(0.3)
1.9%
(0.4)
0.4
(0.2)
(1.3)%
0.8
0.5
N/A
(0.2)%
(0.2)
(0.3)
(4.3)
0.5%
(0.3)
—
(0.5)
NSP-Minnesota
PSCo
SPS
NSP-Wisconsin
Xcel Energy
2016 vs. 2015 (Excluding Leap Day) (b)
(0.2)%
(1.0)
(0.8)
(0.8)
1.6%
(0.7)
0.1
(0.7)
(1.6)%
0.5
0.2
N/A
(0.6)%
(0.5)
(0.6)
(4.8)
0.3%
(0.5)
(0.3)
(1.0)
(a) Extreme weather variations and additional factors such as windchill and cloud cover may not be reflected in weather-normalized and actual growth estimates.
(b)
The estimated impact of the 2016 leap day is excluded to present a more comparable year-over-year presentation. The estimated impact of the additional day of
sales in 2016 was approximately 20-40 basis points for retail electric and 50 basis points for firm natural gas for the twelve months ended Dec. 31, 2016.
Weather-normalized Electric 2016 Sales Growth (Decline) — Excluding Leap Day
• NSP-Minnesota’s residential sales decreased as a result of lower use per customer, partially offset by customer additions.
•
•
C&I sales declined primarily as a result of lower use by customers in the manufacturing and service industries.
PSCo’s residential growth reflects an increased number of customers. The C&I decline was mainly due to lower sales to
certain large customers in the manufacturing, mining, oil and gas industries. The decline was partially offset by an increase
in the number of small C&I customers.
SPS’ residential sales decline was primarily the result of lower use per customer, partially offset by an increased number of
customers. The increase in C&I sales was driven by energy sector expansion in the Southeastern New Mexico, Permian
Basin area as well as greater use by agricultural customers.
• NSP-Wisconsin’s residential sales decrease was primarily attributable to lower use per customer, partially offset by customer
additions. The C&I decline was largely due to reduced sales to small customers. The overall decrease was partially offset by
an increase in the number of C&I customers as well as greater use in the large C&I class for the oil and gas industries.
Weather-normalized Natural Gas 2016 Sales Decline — Excluding Leap Day
• Across natural gas service territories, lower natural gas sales reflect a decline in customer use, partially offset by a slight
increase in the number of customers.
Weather-normalized sales for 2017 are projected to increase approximately 0 percent to 0.5 percent for retail electric and firm natural
gas customers, respectively.
Actual
Electric residential (a) . . . . . . . . . . . . . . . . . . .
Electric C&I. . . . . . . . . . . . . . . . . . . . . . . . . .
Total retail electric sales . . . . . . . . . . . . . . .
Firm natural gas sales . . . . . . . . . . . . . . . . . .
NSP-Minnesota
PSCo
SPS
NSP-Wisconsin
Xcel Energy
2015 vs. 2014
(3.2)%
(0.6)
(1.4)
(16.6)
55
1.1%
(0.4)
0.1
(6.6)
(0.4)%
0.3
0.1
N/A
(6.1)%
0.4
(1.5)
(16.4)
(1.4)%
(0.2)
(0.6)
(10.5)
NSP-Minnesota
PSCo
SPS
NSP-Wisconsin
Xcel Energy
2015 vs. 2014
Weather-normalized
Electric residential (a) . . . . . . . . . . . . . . . . . . .
Electric C&I. . . . . . . . . . . . . . . . . . . . . . . . . .
Total retail electric sales . . . . . . . . . . . . . . .
Firm natural gas sales . . . . . . . . . . . . . . . . . .
(0.7)%
(0.2)
(0.4)
(1.1)
0.4%
(0.9)
(0.5)
(2.0)
0.6%
0.7
0.5
N/A
(2.8)%
0.8
(0.3)
(1.7)
(0.3)%
(0.1)
(0.2)
(1.7)
(a) Extreme weather variations and additional factors such as windchill and cloud cover may not be reflected in weather-normalized and actual growth estimates.
Weather-normalized Electric 2015 Sales Growth (Decline)
•
PSCo’s residential growth was primarily the result of customer additions, partially offset by lower use per customer. C&I
decline was primarily due to reduced sales to certain large manufacturing customers and/or those that support the fracking
industry.
• NSP-Minnesota’s residential decrease was due to lower use per customer, partially offset by an increase in customer
additions. C&I electric sales decreased as a result of lower use by large and small customers (e.g., services, retail trade,
finance insurance and real estate industries), partially offset by higher use by certain large customers in the petroleum and
food processing industries. The decline was partially reduced by an increase in the number of customers in both the small
and large classes.
SPS’ residential growth reflects an increased number of customers. C&I also had an increase in customers, primarily in the
oil and gas exploration and production industries. However, this was partially offset by reduced activity per customer within
these industries, as well as less irrigation by agricultural customers due to wet weather.
•
• NSP-Wisconsin’s residential decline was primarily attributable to lower use per customer, partially offset by customer
additions. C&I electric sales growth was largely due to strong sales to large customers primarily in the oil and gas industries.
Weather-normalized Natural Gas 2015 Sales Decline
• Across natural gas service territories, lower natural gas sales reflect a decline in customer use.
Electric Revenues and Margin
Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuation in the price of natural gas, coal and
uranium used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses,
these price fluctuations have minimal impact on electric margin. The following table details the electric revenues and margin:
(Millions of Dollars)
Electric revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Electric fuel and purchased power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Electric margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2016
2015
2014
9,500
(3,718)
5,782
$
$
9,276
(3,763)
5,513
$
$
9,466
(4,210)
5,256
The following tables summarize the components of the changes in electric revenues and electric margin for the years ended Dec. 31:
Electric Revenues
(Millions of Dollars)
Retail rate increases (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transmission revenue, net of costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Trading. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-fuel riders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Estimated impact of weather, excluding decoupling in Minnesota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fuel and purchased power cost recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total increase in electric revenues. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2016 vs. 2015
190
71
40
28
19
(127)
3
224
2016 Comparison with 2015 — Electric revenues increased primarily due to various rate increases at NSP-Minnesota (net of
estimated provision for refund), NSP-Wisconsin and SPS.
56
Electric Margin
(Millions of Dollars)
Retail rate increases (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-fuel riders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Estimated impact of weather, excluding decoupling in Minnesota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transmission revenue, net of costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retail sales growth, excluding weather impact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PSCo earnings test refunds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Conservation incentive. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Firm wholesale. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total increase in electric margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2016 vs. 2015
190
28
19
14
9
6
3
(12)
12
269
(a) Increase is primarily due to interim rates in Minnesota (net of estimated provision for refund) and final rates in Wisconsin and New Mexico.
2016 Comparison to 2015 — The increase in electric margin was primarily due to the various rate increases at NSP-Minnesota (net of
estimated provision for refund), NSP-Wisconsin and SPS as well as the non-fuel riders.
Electric Revenues
(Millions of Dollars)
Fuel and purchased power cost recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Conservation and DSM program revenues (offset by expenses). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Estimated impact of weather . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Trading. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retail rate increases (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Colorado CACJA non-fuel rider . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transmission revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PSCo earnings test refund . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-fuel riders (b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total decrease in electric revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2015 vs. 2014
(469)
(62)
(23)
(14)
101
94
91
74
20
(2)
(190)
2015 Comparison with 2014 — Electric revenues decreased primarily due to lower fuel and purchased power cost recovery, which is
offset in operating expense. This decrease was partially offset by various rate increases at NSP-Minnesota, NSP-Wisconsin and SPS
as well as the non-fuel rider in Colorado.
Electric Margin
(Millions of Dollars)
Retail rate increases (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Colorado CACJA non-fuel rider . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PSCo earnings test refunds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transmission revenue, net of costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-fuel riders (b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Conservation and DSM program revenues (offset by expenses). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Estimated impact of weather . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total increase in electric margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2015 vs. 2014
101
94
74
47
20
(62)
(23)
6
257
(a) Increase due to rate proceedings in Minnesota, South Dakota, Texas, North Dakota, New Mexico and Wisconsin. These increases were partially offset by a
decline in Colorado retail base rates, which was more than offset by increased CACJA rider revenue as approved by the CPUC in the first quarter of 2015.
(b) Primarily related to the Transmission Cost Recovery rider in Minnesota.
2015 Comparison to 2014 — The increase in electric margin was primarily due to the various rate increases at NSP-Minnesota, NSP-
Wisconsin and SPS as well as the non-fuel rider in Colorado.
57
Natural Gas Revenues and Margin
Total natural gas expense tends to vary with changing sales requirements and the cost of natural gas purchases. Due to the design of
purchased natural gas cost recovery mechanisms for sales to retail customers, fluctuations in the cost of natural gas has minimal
impact on natural gas margin. The following table details natural gas revenues and margin:
(Millions of Dollars)
Natural gas revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Cost of natural gas sold and transported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2016
2015
2014
1,531
(733)
798
$
$
1,672
(905)
767
$
$
2,143
(1,372)
771
The following tables summarize the components of the changes in natural gas revenues and natural gas margin for the years ended
Dec. 31:
Natural Gas Revenues
(Millions of Dollars)
Purchased natural gas adjustment clause recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Estimated impact of weather . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Infrastructure and integrity riders, partially offset in O&M expenses. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retail rate increases (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Conservation and DSM program revenues (offset by expenses). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total decrease in natural gas revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2016 vs. 2015
(177)
(5)
(5)
36
8
2
(141)
2016 Comparison to 2015 — Natural gas revenues decreased primarily due to the purchased natural gas adjustment clause recovery,
which is offset in operating expense.
Natural Gas Margin
(Millions of Dollars)
Retail rate increases (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Conservation and DSM program revenues (offset by expenses). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Estimated impact of weather . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Infrastructure and integrity riders, partially offset in O&M expenses. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total increase in natural gas margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(a)
Increase is primarily related to final natural gas rates in Colorado.
2016 Comparison to 2015 — The increase in natural gas margins was primarily due to the rate increase in Colorado.
Natural Gas Revenues
(Millions of Dollars)
Purchased natural gas adjustment clause recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Estimated impact of weather . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Conservation and DSM program revenues (offset by expenses). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Infrastructure and integrity riders, partially offset in O&M expenses. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased gas adjustment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retail rate increases (Colorado). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total decrease in natural gas revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016 vs. 2015
36
8
(5)
(5)
(3)
31
2015 vs. 2014
(462)
(30)
(13)
30
5
4
(5)
(471)
$
$
$
$
2015 Comparison to 2014 — Natural gas revenues decreased primarily due to the purchased natural gas adjustment clause recovery,
which is offset in operating expense.
58
Natural Gas Margin
(Millions of Dollars)
Estimated impact of weather . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Conservation and DSM program revenues (offset by expenses). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Infrastructure and integrity riders, partially offset in O&M expenses. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased gas adjustment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retail rate increases (Colorado). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total decrease in natural gas margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2015 vs. 2014
(30)
(13)
30
5
4
(4)
2015 Comparison to 2014 — Natural gas margins decreased primarily due to warmer winter weather and lower gas recovery rates
primarily in NSP-Minnesota and PSCo.
Non-Fuel Operating Expenses and Other Items
O&M Expenses — O&M expenses decreased $3.1 million, or 0.1 percent, for 2016 compared with 2015.
O&M expenses decreased $4.7 million, or 0.2 percent for 2015 compared with 2014. The decline was primarily related to a reduction
in nuclear expense driven by operational efficiencies and lower amortization of prior outages, which were partially offset by an
increase in labor and contract labor as a result of various projects and initiatives to improve business processes.
Conservation and DSM Program Expenses — Conservation and DSM program expenses increased $20.1 million, or 8.9 percent, for
2016 compared with 2015. The increase is primarily attributable to more customer participation in DSM programs. Higher
conservation and DSM program expenses are generally offset by higher revenues due to recovery mechanisms.
Conservation and DSM program expenses decreased $77.1 million, or 25.5 percent, for 2015 compared with 2014. The decrease was
primarily attributable to lower electric and gas recovery rates at NSP-Minnesota and PSCo.
Depreciation and Amortization — Depreciation and amortization increased $178.7 million, or 15.9 percent, for 2016 compared with
2015. The increase was primarily attributable to capital investments, including Pleasant Valley and Border Wind Farms, reduction of
the excess depreciation reserve in Minnesota and recognition of the DOE settlement credits in 2015.
Depreciation and amortization increased $105.5 million, or 10.4 percent, for 2015 compared with 2014. The increase was primarily
attributed to capital investments and lower amortization of the excess depreciation reserve in Minnesota, partially offset by
Minnesota’s amortization of the DOE settlement.
Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $20.4 million, or 4.0 percent, for 2016 compared
with 2015. The increase was primarily due to higher property taxes in Minnesota, excluding the impact of the proposed tax deferral in
the settlement agreement in the Minnesota 2016 multi-year electric rate case.
Taxes (other than income taxes) increased $45.8 million, or 9.8 percent, for 2015 compared with 2014. The increase was primarily
due to higher property taxes in Colorado, Minnesota and Texas.
AFUDC, Equity and Debt — AFUDC increased $5.4 million for 2016 compared with 2015. The increase was primarily due to the
expansion of transmission facilities and other capital expenditures.
AFUDC decreased $46.0 million for 2015 compared with 2014. The decrease was primarily due to the implementation of the CACJA
rider, facilitating earlier and alternative recovery of construction costs.
Interest Charges — Interest charges increased $51.6 million, or 8.7 percent, for 2016 compared with 2015. The increase was related
to higher long-term debt levels to fund capital investments, partially offset by refinancings at lower interest rates.
Interest charges increased $28.7 million, or 5.1 percent, for 2015 compared with 2014. The increase was primarily due to higher long-
term debt levels, partially offset by refinancings at lower interest rates.
Income Taxes — Income tax expense increased $38.5 million for 2016 compared with 2015. The increase in income tax expense was
primarily due to higher pretax earnings in 2016, partially offset by increased wind PTCs in 2016. The ETR was 34.1 percent for 2016
compared with 35.5 percent for 2015. The lower ETR in 2016 is primarily due to the wind PTCs in 2016. See Note 6 to the
consolidated financial statements for further discussion.
59
Income tax expense increased $18.9 million for 2015 compared with 2014. The increase was primarily due to a higher tax benefit for
a carryback claim in 2014 and decrease in permanent plant-related deductions (e.g., AFUDC-equity) in 2015. The ETR was 35.5
percent for 2015 compared with 33.9 percent for 2014. See Note 6 to the consolidated financial statements for further discussion.
Xcel Energy Inc. and Other Results
The following tables summarize the net income and EPS contributions of Xcel Energy Inc. and its nonregulated businesses:
(Millions of Dollars)
Xcel Energy Inc. financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Eloigne (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Xcel Energy Inc. taxes and other results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Xcel Energy Inc. and other costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(Earnings per Share)
Xcel Energy Inc. financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Eloigne (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Xcel Energy Inc. taxes and other results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Xcel Energy Inc. and other costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(a)
Amounts include gains or losses associated with sales of properties held by Eloigne.
Contribution to Xcel Energy’s Earnings
2016
2015
2014
(70.6) $
0.6
(6.0)
(76.0) $
(56.1) $
0.1
(2.7)
(58.7) $
(51.8)
(0.5)
(5.0)
(57.3)
Contribution to Xcel Energy’s EPS
2016
2015
2014
(0.14) $
—
(0.01)
(0.15) $
(0.11) $
—
—
(0.11) $
(0.10)
—
(0.01)
(0.11)
Xcel Energy Inc.’s results include interest charges, which are incurred at Xcel Energy Inc. and are not directly assigned to individual
subsidiaries.
Factors Affecting Results of Operations
Xcel Energy’s utility revenues depend on customer usage, which varies with weather conditions, general business conditions and the
cost of energy services. Various regulatory agencies approve the prices for electric and natural gas service within their respective
jurisdictions and affect Xcel Energy’s ability to recover its costs from customers. The historical and future trends of Xcel Energy’s
operating results have been, and are expected to be, affected by a number of factors, including those listed below.
General Economic Conditions
Economic conditions may have a material impact on Xcel Energy’s operating results. While economic growth has been improving
over the past year, management cannot predict whether this trend will be sustained going forward. Other events impact overall
economic conditions and management cannot predict the impact of fluctuating energy prices, terrorist activity, war or the threat of war.
However, Xcel Energy 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.
Fuel Supply and Costs
Xcel Energy Inc.’s operating utilities have varying dependence on coal, natural gas and uranium. Changes in commodity prices are
generally recovered through fuel recovery mechanisms and have very little impact on earnings. However, availability of supply, the
potential implementation of a carbon tax or emissions-related generation restrictions and unanticipated changes in regulatory recovery
mechanisms could impact our operations. See Item 1 for further discussion of fuel supply and costs.
Pension Plan Costs and Assumptions
Xcel Energy has significant net pension and postretirement benefit costs that are measured using actuarial valuations. Inherent in
these valuations are key assumptions including discount rates and expected return on plan assets. Xcel Energy evaluates these key
assumptions at least annually by analyzing current market conditions, which include changes in interest rates and market returns.
Changes in the related net pension and postretirement benefits costs and funding requirements may occur in the future due to changes
in assumptions. The payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees
leaving Xcel Energy would trigger settlement accounting and could require Xcel Energy to recognize material incremental pension
expense related to unrecognized plan losses in the year these liabilities are paid. For further discussion and a sensitivity analysis on
these assumptions, see “Employee Benefits” under Critical Accounting Policies and Estimates.
60
Tax Reform
Tax reform is a key component of the pro-growth agenda of the new Congress and the Trump Administration. Xcel Energy believes it
is early in the process and will continue to evolve. Xcel Energy has initially analyzed two potential tax-reform scenarios and their
potential impact. Both scenarios assume a reduction in the corporate tax rate to 20 percent in 2018, with the first scenario maintaining
interest deductibility and not including 100 percent capital expensing, and the second scenario providing for 100 percent capital
expensing and no deductibility of interest expense.
The impact under the first scenario could be mildly accretive to Xcel Energy’s earnings in 2021, due to a reduction in the deferred tax
liability over time. The impact under the second scenario would be modestly dilutive to Xcel Energy’s earnings in 2021, due to the
loss of interest deductibility and lower rate base.
Xcel Energy believes that the industry and its customers are negatively impacted by the loss of interest deductibility. Accordingly,
Xcel Energy will continue to work vigorously to advance the interests of customers and the industry.
Regulation
FERC and State Regulation — The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.’s utility
subsidiaries, TransCo subsidiaries and WGI. Decisions by these regulators can significantly impact Xcel Energy’s results of
operations. Xcel Energy expects to periodically file for rate changes based on changing operating costs, new or planned investments,
fluctuations in energy markets and general economic conditions.
The electric and natural gas rates charged to customers of Xcel Energy Inc.’s utility subsidiaries are approved by the FERC or the
regulatory commissions in the states in which they operate. The rates are designed to recover plant investment, operating costs and an
allowed return on investment. Rates charged by Xcel Energy Inc.’s TransCo subsidiaries and WGI are approved by the FERC. Xcel
Energy requests changes in rates for utility services through filings with the governing commissions. Changes in operating costs can
affect Xcel Energy’s financial results, depending on the timing of filing general rate cases and the implementation of final rates. In
addition to changes in operating costs, 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.
Wholesale Energy Market Regulation — Wholesale energy markets in the Midwest and South Central U.S. are operated by MISO
and SPP, respectively, to centrally dispatch all regional electric generation and apply a regional transmission congestion management
system. NSP-Minnesota and NSP-Wisconsin are members of MISO and SPS is a member of SPP. NSP-Minnesota, NSP-Wisconsin
and SPS expect to recover energy charges through either base rates or various recovery mechanisms. See Note 12 to the consolidated
financial statements for further discussion.
Capital Expenditure Regulation — Xcel Energy Inc.’s utility subsidiaries make substantial investments in plant additions to build and
upgrade power plants, and expand and maintain the reliability of the energy transmission and distribution systems. In addition to
filings for increases in base rates charged to customers to recover the costs associated with such investments, the CPUC, MPUC,
SDPUC, NDPSC and PUCT in certain instances have approved proposals to recover, through a rate rider, costs to upgrade generation
plants and lower emissions, increased transmission investment costs, increased distribution investment costs, and increased purchased
power capacity costs. These non-fuel rate riders are expected to provide cash flows to enable recovery of costs incurred on a more
timely basis. For wholesale electric transmission and production services, Xcel Energy has, consistent with FERC policy,
implemented formula rates for each of the utility subsidiaries that will provide annual rate changes as transmission or production
investments increase in a manner similar to the retail rate riders. In November 2014, the FERC approved transmission formula rates
for XETD and XEST, which would apply to electric transmission assets the TransCos may own. NSP-Minnesota and NSP-Wisconsin
have no cost-based wholesale production customers and therefore have not implemented a production formula rate.
Environmental Matters
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. A trend of greater environmental awareness and increasingly stringent regulation may
continue to cause higher operating expenses and capital expenditures for environmental compliance.
61
Costs charged to operating expenses for nuclear decommissioning and spent nuclear fuel disposal expenses, environmental monitoring
and disposal of hazardous materials and waste were approximately:
•
•
•
$304 million in 2016;
$292 million in 2015; and
$292 million in 2014.
Xcel Energy estimates an average annual expense of approximately $354 million from 2017 through 2021 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.
Capital expenditures for environmental improvements at regulated facilities were approximately:
•
•
•
$93 million in 2016;
$184 million in 2015; and
$373 million in 2014.
See Item 7 — Capital Requirements for further discussion.
Xcel Energy’s operations are subject to federal and state laws and regulations related to air emissions, water discharges and waste
management from various sources. Such laws and regulations impose monitoring and reporting requirements and may require Xcel
Energy to obtain pre-approval for the construction or modification of projects that increase air emissions, water discharges or land
disposal of wastes, obtain and comply with permits that contain emission, discharge and operational limitations, or install or operate
pollution control equipment at facilities. Xcel Energy will likely be required to incur capital expenditures in the future to comply with
these requirements for remediation of MGP and other legacy sites and various regulations for air emissions, water intake and discharge
and waste disposal. Actual expenditures could vary from the estimates presented. The scope and timing of these expenditures cannot
be determined until any new or revised regulations become final or until more information is learned about the need for remediation at
the legacy sites.
Pollution control equipment can be required by federal and state regulations, such as those requiring mercury emission reductions, and
by state or federal implementation plans, such as those to address visibility impairment, interstate air pollution impacts or attainment
of NAAQS. Xcel Energy has installed and is operating control equipment needed to comply with the requirements of the federal
Mercury and Air Toxic Standards Rule. In 2016, the EPA adopted a federal visibility plan for Texas which imposes SO2 emission
limitations that reflect installation of dry scrubbers on Tolk Units 1 and 2, with compliance required by early 2021. This rule has been
stayed by the United States Court of Appeals for the Fifth Circuit (Fifth Circuit) until it reaches a decision on the merits of the rule.
See Note 13 to the consolidated financial statements for further discussion of Xcel Energy’s environmental contingencies.
Inflation
Inflation at its current level is not expected to materially affect Xcel Energy’s prices or returns to shareholders. However, potential
future inflation could result from economic conditions or the economic and monetary policies of the U.S. Government and the Federal
Reserve. This could lead to future price increases for materials and services required to deliver electric and natural gas services to
customers. These potential cost increases could in turn lead to increased prices to customers. Likewise, lower oil prices lead to
sustained deflation, that could also reduce general economic activity although it may lead to lower electric and natural gas prices to
customers. Additionally, under statute, federal agencies such as FERC now can adjust statutory penalties for inflation.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Preparation of the consolidated financial statements and related disclosures in compliance with GAAP requires the application of
accounting rules and guidance, as well as the use of estimates. The 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 and disclosures, based on varying assumptions. In
addition, the financial and operating environment also may have a significant effect on the operation of the business and on the results
reported. The following is a list of accounting policies and estimates that are most significant to the portrayal of Xcel Energy’s
financial condition and results, and require management’s most difficult, subjective or complex judgments. 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.
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Regulatory Accounting
Xcel Energy Inc. is a holding company with rate-regulated subsidiaries that are 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
the competitive environment makes it probable that such rates will be charged and collected. Xcel Energy’s 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 OCI.
Each reporting period Xcel Energy assesses 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 Xcel Energy’s results of operations, financial condition or cash flows.
As of Dec. 31, 2016 and 2015, Xcel Energy has recorded regulatory assets of $3.4 billion and $3.2 billion, respectively and regulatory
liabilities of $1.6 billion, for both periods. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If
future recovery of costs, in any such jurisdiction, ceases to be probable, Xcel Energy would be required to charge these assets to
current net income or OCI. 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 15 to the consolidated financial statements for further discussion of regulatory assets and liabilities and Note 12 to
the consolidated financial statements for further discussion of rate matters.
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 the 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 ETR in the future. At this time, due to the inherent uncertainty
of future legislation, any potential resulting impact cannot be reasonably estimated.
ETRs are highly impacted by assumptions. ETR calculations are revised every quarter based on best available year-end tax
assumptions (income levels, deductions, credits, etc.); adjusted in the following year after returns are filed, with the tax accrual
estimates being trued-up to the actual amounts claimed on the tax returns; and further adjusted after examinations by taxing authorities
have been completed.
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.
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. The change in the unrecognized tax benefits needs to be reasonably estimated based on
evaluation of the nature of uncertainty, the nature of event that could cause the change and an estimated range of reasonably possible
changes. Management will use prudent business judgment to derecognize appropriate amounts of tax benefits at any period end, and
as new developments occur. Unrecognized tax benefits can be recognized as issues are favorably resolved and loss exposures decline.
We may adjust our unrecognized tax benefits and interest accruals to the updated estimates as disputes with the IRS and state tax
authorities are resolved. These adjustments may increase or decrease earnings. See Note 6 to the consolidated financial statements for
further discussion.
Employee Benefits
Xcel Energy’s pension costs are based on an actuarial calculation that includes a number of key assumptions, most notably the annual
return level that pension and postretirement health care investment assets are expected to earn in the future and the interest rate used to
discount future pension benefit payments to a present value obligation. In addition, the pension cost calculation uses an asset-
smoothing methodology to reduce the volatility of varying investment performance over time. See Note 9 to the consolidated
financial statements for further discussion on the rate of return and discount rate used in the calculation of pension costs and
obligations.
63
Pension costs are expected to increase in 2017 and then decline in the following few years. Funding requirements are expected to
increase in 2017 and then be flat in the following years. While investment returns exceeded the assumed levels in 2014, investment
returns were below the assumed levels in 2015 and 2016. 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 percent per year. As these differences between the actual investment returns and the expected
investment returns are incorporated into the market-related value, the differences are recognized in pension cost over the expected
average remaining years of service for active employees, which was approximately 12 years in 2016.
Based on current assumptions and the recognition of past investment gains and losses, Xcel Energy currently projects the pension
costs recognized for financial reporting purposes will be $121.9 million in 2017 and $115.2 million in 2018, while the actual pension
costs were $121.7 million in 2016 and $127.7 million in 2015. The expected increase in 2017 costs is due primarily to the decrease in
the discount rate, offset by improvements in the mortality assumption and a decrease to the long-term increase in compensation
assumption. Further, future year costs are expected to decrease primarily as a result of reductions in loss amortizations and an increase
in expected return on assets due to planned future contributions and expected return of current assets.
In 2014, the Society of Actuaries published a new mortality table (RP-2014) and projection scale (MP-2014) that increased the overall
life expectancy of males and females. On Dec. 31, 2014 Xcel Energy adopted the RP-2014 table, with modifications, based on its
population and specific experience and a modified MP-2014 projection scale. During 2016, a new projection table was released
(MP-2016). In 2016, Xcel Energy adopted a modified version of the MP-2016 table and will continue to utilize the RP-2014 base
table, modified for company experience.
At Dec. 31, 2016, Xcel Energy set the rate of return on assets used to measure pension costs at 6.87 percent, which is consistent with
the rate set at Dec. 31, 2015. The rate of return used to measure postretirement health care costs is 5.80 percent at Dec. 31, 2016 and
this is consistent with Dec. 31, 2015. 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 interest rate sensitive 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.
Xcel Energy set the discount rates used to value the Dec. 31, 2016 pension and postretirement health care obligations each at 4.13
percent, which represents a 53 basis point and a 52 basis point decrease from Dec. 31, 2015, respectively. 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 Citigroup Pension Liability
Discount Curve and the Citigroup Above Median Curve. At Dec. 31, 2016, these reference points supported the selected rate. In
addition to these reference points, Xcel Energy also reviews general actuarial survey data to assess the reasonableness of the discount
rate selected.
The following are the pension funding contributions across all four of Xcel Energy’s pension plans, both voluntary and required, for
2014 through 2017:
•
•
•
•
$150.0 million in January 2017;
$125.2 million in 2016;
$90.1 million in 2015; and
$130.6 million in 2014.
For future years, we anticipate contributions will be made as necessary. These contributions are summarized in Note 9 to the
consolidated financial statements. Future year amounts are estimates and 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.
64
If Xcel Energy were to use alternative assumptions at Dec. 31, 2016, a one-percent change would result in the following impact on
2016 pension costs:
(Millions of Dollars)
Rate of return. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Discount rate (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pension Costs
+1%
-1%
(13.0) $
(6.8)
18.3
8.8
(a) These costs include the effects of regulation.
Effective Jan. 1, 2017, the initial medical trend assumption decreased from 6.00 percent to 5.50 percent. The ultimate trend
assumption remained at 4.5 percent. The period until the ultimate rate is reached is two years. 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.
• Xcel Energy contributed $17.9 million, $18.3 million and $17.1 million during 2016, 2015 and 2014, respectively, to the
postretirement health care plans.
• Xcel Energy expects to contribute approximately $11.8 million during 2017.
Xcel Energy recovers employee benefits costs in its regulated utility operations consistent with accounting guidance with the
exception of the areas noted below.
• NSP-Minnesota recognizes pension expense in all regulatory jurisdictions as calculated 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.
• 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.
See Note 9 to the consolidated financial statements for further discussion.
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 various
assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted
risk free rates and cost escalation rates. When Xcel Energy revises any assumptions used to estimate AROs, it adjusts the carrying
amount of both the ARO liability and the related long-lived asset. Xcel Energy accretes ARO liabilities 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 total
obligation for nuclear decommissioning is expected to be funded by the external decommissioning trust fund. The difference between
regulatory funding (including depreciation expense less returns from the external trust fund) and expense recognized under current
accounting guidance is deferred as a regulatory asset. The amounts recorded for AROs related to future nuclear decommissioning
were $2.249 billion and $2.141 billion as of Dec. 31, 2016 and 2015, respectively. Based on their significance, the following
discussion relates specifically to the AROs associated with nuclear decommissioning.
NSP-Minnesota obtains periodic cost studies in order to estimate the cost and timing of planned nuclear decommissioning activities.
These independent cost studies are based on relevant information available at the time performed. Estimates of future cash flows for
extended periods of time are by nature 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 over the decommissioning period of the
nuclear plants, including decontamination and removal of radioactive material. The MPUC approved NSP-Minnesota’s most recent
decommissioning filing in October 2015. The next filing is expected to be submitted in the fourth quarter of 2017.
65
The following key assumptions have a significant effect on the estimated nuclear obligation:
• Timing — Decommissioning cost estimates are impacted by each facility’s retirement date and the expected timing of the
actual decommissioning activities. Currently, the 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. By utilizing this method, 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 and experience as well as changes in regulations regarding nuclear decommissioning could cause cost estimates to
change significantly. NSP-Minnesota’s most recent nuclear decommissioning filing assumed current technology and
regulations.
• Escalation Rates — Escalation rates represent projected cost increases over time due to both general inflation and increases in
the cost of specific decommissioning activities. NSP-Minnesota used an escalation rate of 4.36 percent in calculating the
AROs related to nuclear decommissioning for the remaining operational period through the radiological decommissioning
period. An escalation rate of 3.36 percent was utilized for the period of operating costs related to interim dry cask storage of
spent nuclear fuel and site restoration.
• Discount Rates — Changes in timing or estimated expected 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 four to seven percent have been used to
calculate the net present value of the expected future cash flows over time.
Significant uncertainties exist in estimating the future cost of nuclear decommissioning including the method to be utilized, the
ultimate costs to decommission, and the planned method of disposing spent fuel. If different cost estimates, life assumptions or cost
escalation rates were utilized, the AROs could change materially. However, changes in estimates have minimal impact on results of
operations as NSP-Minnesota expects to continue to recover all costs in future rates.
Xcel Energy continually makes judgments and estimates related to these critical accounting policy areas, based on an evaluation of the
varying assumptions and uncertainties for each area. The information and assumptions underlying many 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 the events and 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, 2016.
Derivatives, Risk Management and Market Risk
Xcel Energy Inc. and its subsidiaries 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. See Note 11 to the consolidated
financial statements for further discussion of market risks associated with derivatives.
Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated
by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall
credit risk, when necessary, 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 Xcel Energy expects that the
counterparties will perform under the contracts underlying its derivatives, the contracts expose Xcel Energy to some credit and non-
performance risk.
Though no material non-performance risk currently exists with the counterparties to Xcel Energy’s commodity derivative contracts,
distress in the financial markets may in the future impact that risk to the extent it impacts those counterparties. Distress in the
financial markets may also impact the fair value of the securities in the nuclear decommissioning fund and master pension trust, as
well as Xcel Energy’s ability to earn a return on short-term investments of excess cash.
66
Commodity Price Risk — Xcel Energy Inc.’s utility subsidiaries 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 for various fuels used in generation and distribution activities. Commodity price risk
is also managed through the use of financial derivative instruments. Xcel Energy’s risk management policy allows it to manage
commodity price risk within each rate-regulated operation to the extent such exposure exists.
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’s risk management policy allows management to conduct these activities within guidelines and
limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the
activities governed by this policy.
At Dec. 31, 2016, the fair values by source for net commodity trading contract assets were as follows:
(Thousands of Dollars)
NSP-Minnesota . . . . . . . . . . . . . . . .
PSCo. . . . . . . . . . . . . . . . . . . . . . . . .
Futures / Forwards
Source of
Fair Value
Maturity
Less Than
1 Year
Maturity
1 to 3 Years
Maturity
4 to 5 Years
Maturity
Greater Than
5 Years
Total Futures /
Forwards
Fair Value
1
1
$
$
2,344
(188)
2,156
$
$
6,437
—
6,437
$
$
1,178
—
1,178
$
$
— $
—
— $
9,959
(188)
9,771
1 — Prices actively quoted or based on actively quoted prices.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing mechanisms for the years ended Dec.
31, were as follows:
(Thousands of Dollars)
Fair value of commodity trading net contract assets outstanding at Jan. 1 . . . . . . . . . . . . . . . . . . . . . . . . . $
Contracts realized or settled during the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commodity trading contract additions and changes during the period . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value of commodity trading net contract assets outstanding at Dec. 31 . . . . . . . . . . . . . . . . . . . . . . . $
2016
11,040
(4,873)
3,604
9,771
$
$
2015
21,811
(3,578)
(7,193)
11,040
At Dec. 31, 2016, a 10 percent increase in market prices for commodity trading contracts would decrease pretax income by
approximately $1.1 million, whereas a 10 percent decrease would increase pretax income by approximately $1.1 million. At Dec. 31,
2015, a 10 percent increase in market prices for commodity trading contracts would increase pretax income by approximately $0.3
million, whereas a 10 percent decrease would decrease pretax income by approximately $0.3 million.
Xcel Energy Inc.’s utility subsidiaries’ wholesale and commodity trading operations measure the outstanding risk exposure to price
changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology
known as Value at Risk (VaR). VaR expresses the potential change in fair value on the outstanding transactions, contracts and
obligations over a particular period of time under normal market conditions.
The VaRs for the NSP-Minnesota and PSCo commodity trading operations, calculated on a consolidated basis using a Monte Carlo
simulation with a 95 percent confidence level and a one-day holding period, were as follows:
(Millions of Dollars)
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended
Dec. 31
VaR Limit
Average
High
Low
$
0.09
0.10
$
3.00
3.00
$
0.16
0.28
$
0.38
1.34
0.05
0.06
Nuclear Fuel Supply — NSP-Minnesota is scheduled to take delivery of approximately 13 percent of its 2017 and approximately 56
percent of its 2018 enriched nuclear material requirements from sources that could be impacted by events in Ukraine and sanctions
against Russia. Alternate potential sources are expected to provide the flexibility to manage NSP-Minnesota’s nuclear fuel supply to
ensure that plant availability and reliability will not be negatively impacted in the near-term. Long-term, through 2024, NSP-
Minnesota is scheduled to take delivery of approximately 31 percent of its average enriched nuclear material requirements from
sources that could be impacted by events in Ukraine and extended sanctions against Russia. NSP-Minnesota is closely following the
progression of these events and will periodically assess if further actions are required to assure a secure supply of enriched nuclear
material.
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Interest Rate Risk — Xcel Energy is subject to the risk of fluctuating interest rates in the normal course of business. Xcel Energy’s
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.
At Dec. 31, 2016 and 2015, a 100 basis point change in the benchmark rate on Xcel Energy’s variable rate debt would impact annual
pretax interest expense by approximately $3.9 million and $8.5 million, respectively. See Note 11 to the consolidated financial
statements for a discussion of Xcel Energy Inc. and its subsidiaries’ interest rate derivatives.
NSP-Minnesota also maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is
subject to interest rate risk and equity price risk. At Dec. 31, 2016, the fund was invested in a diversified portfolio of cash equivalents,
debt securities, equity securities and other investments. These investments may be used only for activities related to nuclear
decommissioning. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, 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, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear
decommissioning. Since the accounting for nuclear decommissioning recognizes that costs are recovered through rates, fluctuations in
equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings.
Credit Risk — Xcel Energy Inc. and its subsidiaries are also exposed to credit risk. Credit risk relates to the risk of loss resulting from
counterparties’ nonperformance on their contractual obligations. Xcel Energy Inc. and its subsidiaries maintain credit policies
intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.
At Dec. 31, 2016, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $5.7 million,
while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of $16.6 million. At Dec. 31, 2015, a 10
percent increase in commodity prices would have resulted in a decrease in credit exposure of $1.9 million, while a decrease in prices
of 10 percent would have resulted in an increase in credit exposure of $6.1 million.
Xcel Energy Inc. and its subsidiaries conduct standard credit reviews for all counterparties. Xcel Energy employs additional credit
risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and
termination provisions that allow for offsetting of positive and negative exposures. 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 Xcel Energy’s credit risk.
Fair Value Measurements
Xcel Energy follows accounting and disclosure guidance on fair value measurements that contains a hierarchy for inputs used in
measuring fair value and requires disclosure of the observability of the inputs used in these measurements. See Note 11 to the
consolidated financial statements for further discussion of the fair value hierarchy and the amounts of assets and liabilities measured at
fair value that have been assigned to Level 3.
Commodity Derivatives — Xcel Energy continuously monitors the creditworthiness of the counterparties to its commodity derivative
contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment and
the typically short duration of these contracts, 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, 2016. 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 deferred
as OCI or regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved
regulatory recovery mechanisms. Xcel Energy also assesses the impact of its own credit risk when determining the fair value of
commodity derivative liabilities. The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair
value of commodity derivative liabilities at Dec. 31, 2016.
Commodity derivative assets and liabilities assigned to Level 3 typically consist of FTRs, as well as forwards and options that are
long-term in nature. Level 3 commodity derivative assets and liabilities represent 1.0 percent and 3.9 percent of gross assets and
liabilities, respectively, measured at fair value at Dec. 31, 2016.
Determining the fair value of FTRs requires numerous management forecasts that vary in observability, including various forward
commodity prices, retail and wholesale demand, generation and resulting transmission system congestion. Given the limited
observability of management’s forecasts for several of these inputs, these instruments have been assigned a Level 3. Level 3
commodity derivatives assets and liabilities included $19.3 million and $2.0 million of estimated fair values, respectively, for FTRs
held at Dec. 31, 2016.
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Determining the fair value of certain commodity forwards and options can require management to make use of subjective price and
volatility forecasts which extend to periods beyond those readily observable on active exchanges or quoted by brokers. When less
observable forward price and volatility forecasts are significant to determining the value of commodity forwards and options, these
instruments are assigned to Level 3. Level 3 commodity derivative liabilities included an immaterial estimated fair value for forwards
held at Dec. 31, 2016. There were no Level 3 options held at Dec. 31, 2016.
Liquidity and Capital Resources
Cash Flows
(Millions of Dollars)
Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2016
2015
2014
3,052
$
3,038
$
2,659
Net cash provided by operating activities increased by $14 million for 2016 as compared to 2015. The increase was primarily due to
timing of vendor payments and higher net income, excluding amounts related to non-cash operating activities (e.g., depreciation,
deferred tax expenses and a charge related to the Monticello LCM/EPU project in 2015), partially offset by timing of customer
receipts, refunds and recovery of certain electric and natural gas riders and incentive programs.
Net cash provided by operating activities increased by $379 million for 2015 as compared to 2014. The increase was primarily due to
rate increases in various jurisdictions, higher customer refunds in 2014 and income tax refunds received in 2015 compared to taxes
paid in 2014, partially offset by refunds issued as part of a settlement agreement with Golden Spread and PNM in 2015.
(Millions of Dollars)
Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2016
2015
2014
(3,261) $
(3,623) $
(3,117)
Net cash used in investing activities decreased by $362 million for 2016 as compared to 2015. The decrease was primarily attributable
to the acquisition of two wind projects in 2015, partially offset by the establishment of rabbi trusts in 2016 and higher insurance
proceeds received in 2015.
Net cash used in investing activities increased by $506 million for 2015 as compared to 2014. The increase was primarily attributable
to the acquisition of two wind projects in 2015, partially offset by higher insurance proceeds related to Sherco Unit 3 received in 2015.
(Millions of Dollars)
Net cash provided by financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2016
2015
2014
209
$
590
$
430
Net cash provided by financing activities decreased by $381 million for 2016 as compared to 2015. The decrease was primarily due to
higher repayments of long-term and short-term debt, higher dividend payments and repurchases of common stock, partially offset by
higher debt issuances in 2016.
Net cash provided by financing activities increased by $160 million for 2015 as compared to 2014. The increase was primarily due to
higher debt issuances, partially offset by repayments of short-term debt in 2015 compared to proceeds in 2014 and the impact of less
common stock issuances in 2015.
See discussion of trends, commitments and uncertainties, and the potential future impact on cash flow and liquidity under Capital
Sources.
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.
69
Capital Expenditures — The current estimated base capital expenditure programs of Xcel Energy’s operating companies for the years
2017 through 2021 are shown in the table below:
(Millions of Dollars)
2017
2018
2019
2020
2021
2017 - 2021
Total
Capital Forecast
By Subsidiary
NSP-Minnesota . . . . . . . . . . . . . . . . . . . . . . . . .
PSCo. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NSP-Wisconsin. . . . . . . . . . . . . . . . . . . . . . . . . .
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total capital expenditures . . . . . . . . . . . . . . . .
(Millions of Dollars)
By Function
Electric transmission . . . . . . . . . . . . . . . . . . . . .
Electric distribution . . . . . . . . . . . . . . . . . . . . . .
Electric generation . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Renewables. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total capital expenditures . . . . . . . . . . . . . . . .
$
$
$
$
1,195
1,590
610
250
10
3,655
2017
795
760
670
400
610
420
3,655
$
$
$
$
1,170
1,670
570
280
510
4,200
2018
840
865
685
415
1,055
340
4,200
$
$
$
$
1,515
1,190
490
250
660
4,105
$
$
1,405
1,030
400
280
360
3,475
Capital Forecast
2019
2020
750
950
655
420
1,065
265
4,105
$
$
690
905
405
420
775
280
3,475
$
$
$
$
1,220
980
450
300
—
2,950
$
$
6,505
6,460
2,520
1,360
1,540
18,385
2021
2017 - 2021
Total
805
955
485
415
—
290
2,950
$
$
3,880
4,435
2,900
2,070
3,505
1,595
18,385
In 2016, Xcel Energy subsidiary Capital Services entered into an agreement with Vestas-American Wind Technology, Inc.,
establishing terms under which Xcel Energy subsidiaries may contract to purchase wind turbines in total quantities sufficient for the
construction of up to 2,500 MW of new wind generation facilities. In order to secure the full benefit of the PTC for potential wind
projects at Xcel Energy subsidiaries, Capital Services made deposits of $200 million toward the purchase of wind turbine components
under the contract in 2016.
The capital expenditure programs of Xcel Energy are subject to continuing review and modification. Actual capital expenditures may
vary from the estimates due to changes in electric and natural gas projected load growth, regulatory decisions, legislative initiatives,
reserve margin requirements, the availability of purchased power, alternative plans for meeting long-term energy needs, compliance
with environmental requirements, renewable portfolio standards and merger, acquisition and divestiture opportunities. The table above
does not include potential expenditures of Xcel Energy’s transmission-only subsidiaries.
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. Xcel Energy does not anticipate issuing any
equity to fund its capital investment program for 2017-2021. The current estimated financing plans of Xcel Energy Inc. and its
subsidiaries for the years 2017 through 2021 are shown in the table below.
(Millions of Dollars)
Funding Capital Expenditures
Cash from Operations* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
New Debt** . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2017-2021 Capital Expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
Maturing Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
13,465
4,920
—
18,385
3,550
* Net of dividends.
** Reflects a combination of short and long-term debt.
70
Contractual Obligations and Other Commitments — In addition to its capital expenditure programs, Xcel Energy has contractual
obligations and other commitments that will need to be funded in the future. The following is a summarized table of contractual
obligations and other commercial commitments at Dec. 31, 2016. See the statements of capitalization and additional discussion in
Notes 4 and 13 to the consolidated financial statements.
Total
(Thousands of Dollars)
Long-term debt, principal and interest
payments (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 23,902,112
Capital lease obligations . . . . . . . . . . . . . . . . . .
317,326
Operating leases (b)(c) . . . . . . . . . . . . . . . . . . . . .
3,364,045
Unconditional purchase obligations (d) . . . . . . .
7,622,742
Other long-term obligations, including current
portion (e) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Payments to vendors in process . . . . . . . . . . . .
Short-term debt . . . . . . . . . . . . . . . . . . . . . . . . .
228,240
38,579
392,000
Total contractual cash obligations (f)(g)(h) . . . . $ 35,865,044
Payments Due by Period
Less than 1 Year
1 to 3 Years
3 to 5 Years
After 5 Years
$
$
873,147
15,055
237,488
1,725,982
85,674
38,579
392,000
3,367,925
$
$
2,725,135
29,170
498,304
1,772,997
131,315
—
—
5,156,921
$
$
2,651,633
28,010
538,734
1,275,267
$ 17,652,197
245,091
2,089,519
2,848,496
11,251
—
—
4,504,895
—
—
—
$ 22,835,303
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate at Dec. 31, 2016, and outstanding principal for each
investment with the terms ending at each instrument’s maturity.
Under some leases, Xcel Energy would have to sell or purchase the property that it leases if it chose to terminate before the scheduled lease expiration date. Most
of Xcel Energy’s railcar, vehicle and equipment and aircraft leases have these terms. At Dec. 31, 2016, the amount that Xcel Energy would have to pay if it chose
to terminate these leases was approximately $32.3 million. In addition, at the end of the equipment lease terms, each lease must be extended, equipment
purchased for the greater of the fair value or unamortized value of equipment sold to a third party with Xcel Energy making up any deficiency between the sales
price and the unamortized value.
Included in operating lease payments are $212.3 million, $443.4 million, $490.8 million and $1.9 billion, 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 current coal, nuclear fuel and natural gas
requirements. Additionally, the utility subsidiaries of Xcel Energy Inc. have entered into agreements with utilities and other energy suppliers for purchased power
to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve
obligations. Certain contractual purchase obligations are adjusted on indices. The effects of price changes are mitigated through cost of energy adjustment
mechanisms.
Other long-term obligations relate primarily to amounts associated with technology agreements as well as uncertain tax positions.
Xcel Energy also has outstanding authority under O&M contracts to purchase up to approximately $3.7 billion of goods and services through the year 2053, in
addition to the amounts disclosed in this table.
In January 2017, contributions of $150.0 million were made across four of Xcel Energy’s pension plans. Obligations of this type are dependent on several factors,
including management discretion, and therefore, they are not included in the table.
Xcel Energy expects to contribute approximately $11.8 million to the postretirement health care plans during 2017. Obligations of this type are dependent on
several factors, including management discretion, and therefore, they are not included in the table.
Common Stock Dividends — Future dividend levels will be dependent on Xcel Energy’s results of operations, financial position, cash
flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. In February
2017, Xcel Energy announced a quarterly dividend of $0.36 per share, which represents an increase of 5.9 percent. Xcel Energy’s
dividend policy balances:
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 certain limits on the ability of
public utilities within a holding company system to declare dividends.
71
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 4 to the consolidated financial statements for further discussion of restrictions on dividend payments.
Regulation of Derivatives — In July 2010, financial reform legislation was passed that provides for the regulation of derivative
transactions amongst other provisions. Provisions within the bill provide the CFTC and the SEC with expanded regulatory authority
over derivative and swap transactions. The CFTC ruled that swap dealing activity conducted by entities for the preceding 12 months
under a notional limit, initially set at $8 billion, will fall under the general de minimis threshold and will not subject an entity to
registering as a swap dealer. The de minimis threshold is scheduled to be reduced to $3 billion in 2018. Xcel Energy’s current and
projected swap activity is well below these de minimis thresholds. The bill also contains provisions that exempt certain derivatives
end users from much of the clearing and margin requirements and Xcel Energy’s Board of Directors has renewed the end-user
exemption on an annual basis. Xcel Energy is currently meeting all reporting requirements and transaction restrictions.
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 and interest rate swap securities, and alternative investments, including private equity, real
estate, hedge funds and commodity investments.
The funded status and pension assumptions are summarized in the following tables:
(Millions of Dollars)
Fair value of pension assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Projected pension obligation (a). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Funded status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
Dec. 31, 2016
Dec. 31, 2015
$
2,856
3,682
(826) $
2,884
3,568
(684)
(a)
Excludes nonqualified plan of $44 million and $42 million at Dec. 31, 2016 and 2015, respectively.
Pension Assumptions
Discount rate. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected long-term rate of return. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016
2015
4.13%
6.87
4.66%
6.87
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 in large
part 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. At Dec. 31, 2016 and 2015, there was $3.6 million and $3.3 million of cash held in these accounts,
respectively.
Commercial Paper — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper
programs. The authorized levels for these commercial paper programs are:
•
•
•
•
•
$1 billion for Xcel Energy Inc.;
$700 million for PSCo;
$500 million for NSP-Minnesota;
$400 million for SPS; and
$150 million for NSP-Wisconsin.
72
Commercial paper outstanding for Xcel Energy was as follows:
(Amounts in Millions, Except Interest Rates)
Borrowing limit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Amount outstanding at period end. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average amount outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Maximum amount outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average interest rate, computed on a daily basis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average interest rate at end of period. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Three Months Ended
Dec. 31, 2016
2,750
392
290
582
0.75%
0.95
(Amounts in Millions, Except Interest Rates)
Borrowing limit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Amount outstanding at period end . . . . . . . . . . . . . . . . . . . . . . . . . .
Average amount outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Maximum amount outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average interest rate, computed on a daily basis . . . . . . .
Weighted average interest rate at end of period . . . . . . . . . . . . . . . .
Year Ended Dec. 31,
2016
Year Ended Dec. 31,
2015
Year Ended Dec. 31,
2014
$
2,750
392
485
1,183
0.74%
0.95
$
2,750
846
601
1,360
0.48%
0.82
2,750
1,020
841
1,200
0.33%
0.56
Amended Credit Agreements — In June 2016, 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
remained at $2.75 billion. The amended credit agreements have substantially the same terms and conditions as the prior credit
agreements with the following exceptions:
• The maturity extended from October 2019 to June 2021.
• The Eurodollar borrowing margins on these lines of credit were reduced to a range of 75 to 150 basis points per year, from a
range of 87.5 to 175 basis points per year, based upon applicable long-term credit ratings.
• The commitment fees, calculated on the unused portion of the lines of credit, were reduced to a range of 6 to 22.5 basis points
per year, from a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.
Xcel Energy Inc., NSP-Minnesota, PSCo, and SPS each have the right to request an extension of the revolving credit facility
termination date for two additional one-year periods. 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.
As of Feb. 17, 2017, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet
liquidity needs:
(Millions of Dollars)
Xcel Energy Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PSCo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NSP-Minnesota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NSP-Wisconsin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
(a)
(b)
These credit facilities mature in June 2021.
Includes outstanding commercial paper and letters of credit.
Facility (a)
Drawn (b)
Available
Cash
Liquidity
1,000
700
500
400
150
2,750
$
$
202
81
30
117
48
478
$
$
798
619
470
283
102
2,272
$
$
— $
1
1
1
—
3
$
798
620
471
284
102
2,275
Money Pool — Xcel Energy received FERC approval 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. The money
pool balances are eliminated in consolidation.
NSP-Minnesota, PSCo and SPS participate in the money pool pursuant to approval from their respective state regulatory commissions.
NSP-Wisconsin does not participate in the money pool.
73
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, 2016 and 2015, Xcel Energy Inc. had approximately 507 million shares and 508 million shares of
common stock outstanding, respectively. In addition, Xcel Energy Inc.’s Articles of Incorporation authorize the issuance of seven
million shares of $100 par value preferred stock. Xcel Energy Inc. had no shares of preferred stock outstanding on Dec. 31, 2016 and
2015.
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.
Financing Plans — During 2017, Xcel Energy Inc. and its utility subsidiaries anticipate issuing the following:
• Xcel Energy Inc. plans to issue approximately $300 million of senior unsecured bonds;
• NSP-Minnesota plans to issue approximately $600 million of first mortgage bonds;
• NSP-Wisconsin plans to issue approximately $100 million of first mortgage bonds;
•
•
PSCo plans to issue approximately $400 million of first mortgage bonds
SPS plans to issue approximately $250 million of first mortgage bonds.
Financing plans are subject to change, depending on capital expenditures, internal cash generation, market conditions and other
factors.
Long-Term Borrowings and Other Financing Instruments — See the consolidated statements of capitalization and a discussion of
the long-term borrowings in Note 4 to the consolidated financial statements.
Xcel Energy Inc. issued approximately 5.7 million shares of common stock through an ATM program for approximately $175 million
during the first six months of 2014. Xcel Energy completed its ATM program as of June 30, 2014. Xcel Energy does not anticipate
issuing any additional equity over the next five years based on its current capital expenditure plan.
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.
Earnings Guidance
Xcel Energy’s 2017 GAAP and ongoing earnings guidance is $2.25 to $2.35 per share.(a) Key assumptions related to 2017 earnings
are detailed below:
• Constructive outcomes in all rate case and regulatory proceedings.
• Normal weather patterns are experienced for the year.
• Weather-normalized retail electric utility sales are projected to increase 0 percent to 0.5 percent.
• Weather-normalized retail firm natural gas sales are projected to increase 0 percent to 0.5 percent.
• Capital rider revenue is projected to increase by $60 million to $70 million over 2016 levels.
• O&M expenses are projected to be flat.
• Depreciation expense is projected to increase approximately $165 million to $175 million over 2016 levels.
•
•
• AFUDC — equity is projected to increase approximately $0 million to $10 million from 2016 levels.
• The ETR is projected to be approximately 32 percent to 34 percent.
• Average common stock and equivalents are projected to be approximately 509 million shares.
Property taxes are projected to increase approximately $0 million to $10 million over 2016 levels.
Interest expense (net of AFUDC — debt) is projected to increase $20 million to $30 million over 2016 levels.
(a)
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 diluted EPS to corresponding GAAP diluted EPS.
74
Long-Term EPS and Dividend Growth Rate Objectives
Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend
yield, based on the following long-term objectives:
• Deliver long-term annual EPS growth of 4 percent to 6 percent;
• Deliver annual dividend increases of 5 percent to 7 percent;
• Target a dividend payout ratio of 60 percent to 70 percent; and
• Maintain senior unsecured debt credit ratings in the BBB+ to A range.
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.
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 18 to the consolidated financial statements for summarized quarterly financial data.
75
Management Report on Internal Controls 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.
In 2016, Xcel Energy Inc. implemented the general ledger modules, as well as initiated deployment of work management systems
modules, of a new enterprise resource planning system. Xcel Energy Inc. will continue to implement additional modules including the
conversion of existing work management systems during 2017. Xcel Energy Inc. does not believe this implementation has or will
have an adverse effect on its internal control over financial reporting.
Xcel Energy Inc. management assessed the effectiveness of Xcel Energy Inc.’s internal control over financial reporting as of Dec. 31,
2016. 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,
2016, 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 the Xcel Energy Inc.’s internal control
over financial reporting. Its report appears herein.
/s/ BEN FOWKE
Ben Fowke
Chairman, President and Chief Executive Officer
Feb. 24, 2017
/s/ ROBERT C. FRENZEL
Robert C. Frenzel
Executive Vice President, Chief Financial Officer
Feb. 24, 2017
76
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Xcel Energy Inc.
Minneapolis, Minnesota
We have audited the accompanying consolidated balance sheets and statements of capitalization of Xcel Energy Inc. and subsidiaries
(the “Company”) as of December 31, 2016 and 2015, and the related consolidated statements of income, comprehensive income, cash
flows, and common stockholders' equity for each of the three years in the period ended December 31, 2016. Our audits also included
the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the
responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial
statement schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Xcel Energy Inc.
and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.
Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements
taken as a whole, present fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
Company's internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control-
Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report
dated February 24, 2017 expressed an unqualified opinion on the Company's internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 24, 2017
77
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Xcel Energy Inc.
Minneapolis, Minnesota
We have audited the internal control over financial reporting of Xcel Energy Inc. and subsidiaries (the "Company") as of December
31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission. The Company's management is responsible 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 the
Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over
financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of
internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We
believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal
executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors,
management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control
over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management
and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper
management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.
Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to
the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies
or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31,
2016, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2016 of the Company
and our report dated February 24, 2017 expressed an unqualified opinion on those financial statements and financial statement
schedules.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 24, 2017
78
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(amounts in thousands, except per share data)
Year Ended Dec. 31
2016
2015
2014
Operating revenues
Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 9,499,781
1,531,412
75,727
11,106,920
$ 9,275,986
1,672,081
76,419
11,024,486
$ 9,465,890
2,142,738
77,507
11,686,135
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). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on Monticello life cycle management/extended power uprate project . . . . . . . . . . .
Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,717,685
732,689
36,075
2,326,558
244,784
1,303,203
532,071
—
8,893,065
3,762,953
904,794
36,216
2,329,670
224,679
1,124,524
511,675
129,463
9,023,974
4,210,142
1,372,479
34,352
2,334,379
301,772
1,019,045
465,836
—
9,738,005
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,213,855
2,000,512
1,948,130
Other income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity earnings of unconsolidated subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Allowance for funds used during construction — equity. . . . . . . . . . . . . . . . . . . . . . . . . . .
7,950
42,123
60,547
5,400
34,390
55,936
5,296
30,151
89,750
Interest charges and financing costs
Interest charges — includes other financing costs of $25,170, $24,175 and
$22,986, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Allowance for funds used during construction — debt . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total interest charges and financing costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
646,907
(27,028)
619,879
595,282
(26,248)
569,034
566,608
(38,402)
528,206
Income before income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,704,596
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
581,217
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,123,379
1,527,204
542,719
984,485
$
1,545,121
523,815
$ 1,021,306
Weighted average common shares outstanding:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
508,794
509,465
507,768
508,168
503,847
504,117
Earnings per average common share:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2.21
2.21
$
1.94
1.94
2.03
2.03
Cash dividends declared per common share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1.36
$
1.28
$
1.20
See Notes to Consolidated Financial Statements
79
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(amounts in thousands)
Year Ended Dec. 31
2016
2015
2014
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,123,379
$
984,485
$ 1,021,306
Other comprehensive (loss) income
Pension and retiree medical benefits:
Net pension and retiree medical losses arising during the period, net of tax of $(4,944),
$(5,026), and $(4,687), respectively. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of losses included in net periodic benefit cost, net of tax of $2,185,
$2,249, and $2,159, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative instruments:
Net fair value increase (decrease), net of tax of $2, $(46), and $(103), respectively. . . . .
Reclassification of losses to net income, net of tax of $2,342, $1,810, and $1,493,
respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(7,783)
(7,906)
(7,517)
3,471
(4,312)
3,526
(4,380)
3,495
(4,022)
3
(70)
(163)
3,708
3,711
2,836
2,766
2,288
2,125
Marketable securities:
Net fair value increase, net of tax of $0, $0, and $21, respectively . . . . . . . . . . . . . . . . . .
—
—
33
Other comprehensive loss. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(601)
$ 1,122,778
$
(1,614)
982,871
(1,864)
$ 1,019,442
See Notes to Consolidated Financial Statements
80
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in thousands)
Year Ended Dec. 31
2015
2014
2016
Operating activities
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjustments to reconcile net income to cash provided by operating activities:
$ 1,123,379
$
984,485
$ 1,021,306
Depreciation and amortization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Conservation and demand side management program amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear fuel amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of investment tax credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Allowance for equity funds used during construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity earnings of unconsolidated subsidiaries. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividends from unconsolidated subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provision for bad debts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Share-based compensation expense. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on Monticello life cycle management/extended power uprate project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net realized and unrealized hedging and derivative transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in other noncurrent assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in other noncurrent liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash provided by operating activities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investing activities
Utility capital/construction expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Allowance for equity funds used during construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from insurance recoveries. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases of investment securities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from the sale of investment securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investments in WYCO Development LLC and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from issuance of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repurchases of common stock. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividends paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash provided by financing activities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,318,752
3,854
116,982
586,650
(5,203)
(60,547)
(42,123)
46,170
38,960
41,170
—
7,939
(889)
(83,170)
(74,965)
1,349
61,515
117,744
(19,378)
20,249
(90,707)
(16,191)
(39,241)
3,052,299
(3,255,550)
60,547
4,509
(546,612)
478,866
(3,962)
789
(3,261,413)
(454,000)
2,423,768
(1,035,901)
—
(32,209)
(680,521)
(12,487)
208,650
1,142,966
5,225
106,424
535,868
(5,277)
(55,936)
(34,390)
40,128
36,074
44,928
129,463
21,919
(1,326)
65,826
73,625
(11,240)
9,273
(120,002)
102,465
78,158
(69,256)
10,553
(52,090)
3,037,863
(3,683,359)
55,936
27,237
(1,257,924)
1,236,873
(1,392)
(145)
(3,622,774)
(173,500)
1,626,212
(250,882)
7,011
—
(606,574)
(12,024)
590,243
1,036,515
6,033
114,542
569,378
(5,543)
(89,750)
(30,151)
36,707
42,765
32,189
—
5,506
—
(125,146)
(41,262)
(20,558)
(111,300)
(53,242)
195,823
148,441
(101,457)
44,364
(15,674)
2,659,486
(3,199,791)
89,750
6,000
(595,569)
588,430
(2,376)
(3,695)
(3,117,251)
260,500
837,584
(275,948)
180,798
—
(561,411)
(11,294)
430,229
Net change in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents at beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash received (paid) for income taxes, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Supplemental disclosure of non-cash investing and financing transactions:
Property, plant and equipment additions in accounts payable. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Issuance of common stock for reinvested dividends and equity awards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(464)
84,940
84,476
$
5,332
79,608
84,940
$
(27,536)
107,144
79,608
(591,996) $
61,933
(542,860) $
58,287
(512,602)
(4,542)
253,955
29,427
$
321,969
52,911
$
417,473
62,078
$
$
$
See Notes to Consolidated Financial Statements
81
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in thousands, except share and per share data)
Dec. 31
2016
2015
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
84,476
776,289
729,832
604,226
363,655
38,224
106,697
138,682
2,842,081
84,940
724,606
654,867
608,584
344,630
33,842
163,023
155,734
2,770,226
Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
32,841,750
31,205,851
$
$
Other assets
Nuclear decommissioning fund and other investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulatory assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deposits and 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total deferred credits and other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2,091,858
3,080,867
50,189
248,532
5,471,446
41,155,277
255,529
392,000
1,044,959
220,894
457,392
172,901
172,456
26,959
503,953
3,247,043
6,784,319
63,216
1,383,212
2,782,229
148,146
195,214
1,112,366
223,965
12,692,667
1,902,995
2,858,741
51,083
32,581
4,845,400
38,821,477
657,021
846,000
960,982
306,830
438,189
166,829
162,410
29,839
490,197
4,058,297
6,153,442
68,419
1,332,889
2,608,562
168,311
228,999
941,002
261,756
11,763,380
Commitments and contingencies
Capitalization
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 507,222,795 and 507,535,523 shares
outstanding at Dec. 31, 2016 and 2015, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additional paid in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated other comprehensive loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total common stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total liabilities and equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
14,194,718
12,398,880
1,268,057
5,881,494
3,981,652
(110,354)
11,020,849
41,155,277
$
1,268,839
5,889,106
3,552,728
(109,753)
10,600,920
38,821,477
See Notes to Consolidated Financial Statements
82
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
(amounts in thousands)
Common Stock Issued
Shares
Par Value
Additional
Paid In
Capital
Retained
Earnings
Accumulated
Other
Comprehensive
Loss
Total Common
Stockholders’
Equity
Balance at Dec. 31, 2013 . . . . . . . . . . . . . . . . 497,972
$ 1,244,929
$ 5,619,313
$ 2,807,983
$
(106,275) $ 9,565,950
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other comprehensive loss. . . . . . . . . . . . . . . .
Dividends declared on common stock . . . . . .
Issuances of common stock . . . . . . . . . . . . . .
Share-based compensation . . . . . . . . . . . . . . .
Balance at Dec. 31, 2014 . . . . . . . . . . . . . . . . 505,733
7,761
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other comprehensive loss. . . . . . . . . . . . . . . .
Dividends declared on common stock . . . . . .
Issuances of common stock . . . . . . . . . . . . . .
Share-based compensation . . . . . . . . . . . . . . .
Balance at Dec. 31, 2015 . . . . . . . . . . . . . . . . 507,536
1,803
19,404
$ 1,264,333
185,145
32,872
$ 5,837,330
4,506
$ 1,268,839
28,017
23,759
$ 5,889,106
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other comprehensive loss. . . . . . . . . . . . . . . .
Dividends declared on common stock . . . . . .
Issuances of common stock . . . . . . . . . . . . . .
Repurchases of common stock . . . . . . . . . . . .
Share-based compensation . . . . . . . . . . . . . . .
Balance at Dec. 31, 2016
486
(799)
1,216
(1,998)
507,223
$ 1,268,057
15,110
(30,211)
7,489
$ 5,881,494
See Notes to Consolidated Financial Statements
1,021,306
(608,331)
$ 3,220,958
$
984,485
(652,715)
$ 3,552,728
$
1,123,379
(694,886)
431
$ 3,981,652
$
(1,864)
1,021,306
(1,864)
(608,331)
204,549
32,872
(108,139) $ 10,214,482
(1,614)
984,485
(1,614)
(652,715)
32,523
23,759
(109,753) $ 10,600,920
(601)
1,123,379
(601)
(694,886)
16,326
(32,209)
7,920
(110,354) $ 11,020,849
83
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(amounts in thousands, except share and per share data)
Dec. 31
2016
2015
Long-Term Debt
NSP-Minnesota
First Mortgage Bonds, Series due:
March 1, 2018, 5.25% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aug. 15, 2020, 2.2% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aug. 15, 2022, 2.15% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
May 15, 2023, 2.6% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
July 1, 2025, 7.125% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 1, 2028, 6.5% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
July 15, 2035, 5.25% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 1, 2036, 6.25% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
July 1, 2037, 6.2% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nov. 1, 2039, 5.35% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aug. 15, 2040, 4.85% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aug. 15, 2042, 3.4% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
May 15, 2044, 4.125% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aug. 15, 2045, 4.0% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
May 15, 2046, 3.6% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized debt expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less current maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total NSP-Minnesota long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
500,000
300,000
300,000
400,000
250,000
150,000
250,000
400,000
350,000
300,000
250,000
500,000
300,000
300,000
350,000
23
(16,951)
(39,907)
4,843,165
10
$ 4,843,155
$
500,000
300,000
300,000
400,000
250,000
150,000
250,000
400,000
350,000
300,000
250,000
500,000
300,000
300,000
—
33
(15,911)
(37,701)
4,496,421
11
$ 4,496,410
PSCo
First Mortgage Bonds, Series due:
Sept. 1, 2017, 4.375% (a). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aug. 1, 2018, 5.8% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 1, 2019, 5.125% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nov. 15, 2020, 3.2% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sept. 15, 2022, 2.25%. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 15, 2023, 2.5% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
May 15, 2025, 2.9% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sept. 1, 2037, 6.25%. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aug. 1, 2038, 6.5% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aug. 15, 2041, 4.75% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sept. 15, 2042, 3.6%. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 15, 2043, 3.95% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 15, 2044, 4.30% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 15, 2046, 3.55% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital lease obligations, through 2060, 11.2% — 14.3% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized debt expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less current maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total PSCo long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SPS
First Mortgage Bonds, Series due:
$
— $
300,000
400,000
400,000
300,000
250,000
250,000
350,000
300,000
250,000
500,000
250,000
300,000
250,000
155,927
(12,922)
(26,799)
4,216,206
5,270
$ 4,210,936
129,500
300,000
400,000
400,000
300,000
250,000
250,000
350,000
300,000
250,000
500,000
250,000
300,000
—
164,031
(11,340)
(26,595)
4,105,596
8,103
$ 4,097,493
June 15, 2024, 3.3% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aug. 15, 2041, 4.5% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aug. 15, 2046, 3.4% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unsecured Senior E Notes, due Oct. 1, 2016, 5.6% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unsecured Senior G Notes, due Dec. 1, 2018, 8.75%. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unsecured Senior C and D Notes, due Oct. 1, 2033, 6% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unsecured Senior F Notes, due Oct. 1, 2036, 6%. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized premium. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized debt expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less current maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total SPS long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
350,000
400,000
300,000
—
250,000
100,000
250,000
365
(14,507)
1,635,858
—
$ 1,635,858
$
350,000
400,000
—
200,000
250,000
100,000
250,000
605
(12,083)
1,538,522
200,000
$ 1,338,522
84
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION — (Continued)
(amounts in thousands, except share and per share data)
NSP-Wisconsin
First Mortgage Bonds, Series due:
Oct. 1, 2018, 5.25% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 15, 2024, 3.3% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sept. 1, 2038, 6.375%. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oct. 1, 2042, 3.7% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
City of La Crosse Resource Recovery Bond, Series due Nov. 1, 2021, 6% (b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fort McCoy System Acquisition, due Oct. 15, 2030, 7%. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized debt expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less current maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total NSP-Wisconsin long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Subsidiaries
Various Eloigne Co. Affordable Housing Project Notes, due 2017-2052, 0% — 7.05%. . . . . . . . . . . . . . . . . . . . . . . .
Unamortized debt expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less current maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total other subsidiaries long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Xcel Energy Inc.
Unsecured Senior Notes, Series due:
May 9, 2016, 0.75% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
April 1, 2017, 5.613% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 1, 2017, 1.2% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
May 15, 2020, 4.7% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 15, 2021, 2.4% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
March 15, 2022, 2.6% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 1, 2025, 3.3% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dec. 1, 2026, 3.35% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
July 1, 2036, 6.5% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sept. 15, 2041, 4.8%. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Elimination of PSCo capital lease obligation with affiliates. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized debt expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less current maturities (including elimination of PSCo capital lease obligation) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Xcel Energy Inc. long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dec. 31
2016
2015
$
$
$
$
150,000
200,000
200,000
100,000
18,600
456
1,575
(2,865)
(4,697)
663,069
1,123
661,946
30,986
(365)
30,621
763
29,858
$
$
$
$
150,000
200,000
200,000
100,000
18,600
490
1,634
(3,131)
(5,144)
662,449
1,131
661,318
31,255
(417)
30,838
709
30,129
$
— $
—
250,000
550,000
400,000
300,000
600,000
500,000
300,000
250,000
(63,521)
(2,380)
(22,771)
3,061,328
248,363
$ 2,812,965
$ 14,194,718
450,000
253,979
250,000
550,000
—
—
250,000
—
300,000
250,000
(66,454)
(5,551)
(9,899)
2,222,075
447,067
$ 1,775,008
$ 12,398,880
Common Stockholders’ Equity
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 507,222,795 and
507,535,523 shares outstanding at Dec. 31, 2016 and Dec. 31, 2015, respectively . . . . . . . . . . . . . . . . . . . . . . . . . .
Additional paid in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated other comprehensive loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total common stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,268,057
5,881,494
3,981,652
(110,354)
$ 11,020,849
$ 1,268,839
5,889,106
3,552,728
(109,753)
$ 10,600,920
(a)
(b)
Pollution control financing.
Resource recovery financing.
See Notes to Consolidated Financial Statements
85
XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
Business and System of Accounts — 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 consolidated financial statements and disclosures are presented in accordance with GAAP. All of the utility subsidiaries’
underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state
regulatory commissions, which are the same in all material respects.
Principles of Consolidation — In 2016, Xcel Energy’s operations included the activity 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 Xcel Energy’s operations are WGI, an interstate natural gas
pipeline company, and WYCO, a joint venture with CIG to develop and lease natural gas pipelines, storage and compression facilities.
Xcel Energy Inc.’s nonregulated subsidiaries are Eloigne and Capital Services. 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 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 variable interest entities for which it is the
primary beneficiary. In the consolidation process, all intercompany transactions and balances are eliminated. 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 several 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. See Note 5 for further discussion of jointly
owned generation, transmission, and gas facilities and related ownership percentages.
Xcel Energy evaluates its arrangements and contracts with other entities, including but not limited to, investments, PPAs and fuel
contracts to determine if the other party is a variable interest entity, if Xcel Energy has a variable interest and if Xcel Energy is the
primary beneficiary. Xcel Energy follows accounting guidance for variable interest entities which requires consideration of the
activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining
whether Xcel Energy is a variable interest entity’s primary beneficiary. See Note 13 for further discussion of variable interest entities.
Use of Estimates — In recording transactions and balances resulting from business operations, Xcel Energy uses estimates based on
the best information available. Estimates are used for such items 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. The recorded estimates are revised when better information becomes
available or when actual amounts can be determined. Those revisions can affect operating results.
Regulatory Accounting — Our regulated utility subsidiaries account for certain 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 OCI, 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 OCI, 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.
86
If restructuring or other changes in the regulatory environment occur, regulated 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 financial condition, results of operations and cash flows. See Note 15 for further
discussion of regulatory assets and liabilities.
Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered
to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, 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 presents its revenues net of
any excise or other fiduciary-type taxes or fees.
NSP-Minnesota participates in MISO, and SPS participates in SPP. Xcel Energy’s utility subsidiaries recognize sales to both native
load and other end use customers on a gross basis. Revenues and charges for short term wholesale sales of excess energy transacted
through RTOs are recorded on a gross basis in electric revenues and cost of sales. Other revenues and charges related to participating
and transacting in RTOs are recorded on a net basis in cost of sales.
Xcel Energy Inc.’s utility subsidiaries have various rate-adjustment mechanisms in place that provide for the recovery of natural gas,
electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from
customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred.
When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to
customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over
fuel revenues billed to customers) are deferred as regulatory assets.
Certain rate rider mechanisms qualify as alternative revenue programs under generally accepted accounting principles. 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, revenue is recognized equal to the revenue requirement, including return on
rate base items, for the qualified mechanisms. The mechanisms are revised periodically for differences between the total amount
collected under the riders and the revenue recognized, which may increase or decrease the level of revenue collected from customers.
Conservation Programs — Xcel Energy Inc.’s utility subsidiaries have implemented programs in many of their retail jurisdictions to
assist customers in reducing peak demand and conserving energy on the electric and natural gas systems. These programs include
efficiency and redesign programs, as well as rebates for the purchase of items such as high efficiency lighting.
The costs incurred for DSM and CIP programs are deferred if it is probable future revenue will be provided to permit recovery of the
incurred cost. Recorded revenues for incentive programs designed for recovery of lost margins and/or conservation performance
incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned.
For PSCo, SPS and NSP-Minnesota, DSM and CIP program costs are recovered through a combination of base rate revenue and rider
mechanisms. The revenue billed to customers recovers incurred costs for conservation programs and also incentive amounts that are
designed to encourage Xcel Energy’s achievement of energy conservation goals and compensate for related lost sales margin. For
these utility subsidiaries, regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been
collected from customers. NSP-Wisconsin recovers approved conservation program costs in base rate revenue.
Property, Plant and Equipment and Depreciation — 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 major 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 also includes costs
associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually and revised, if
appropriate.
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.
See Note 12 for a discussion of the loss recognized in 2015 related to the Monticello LCM/EPU project. 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.
87
Xcel Energy records depreciation expense related to its plant 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 2.9, 2.8, and 2.7 percent for the years ended Dec. 31, 2016, 2015 and 2014, respectively.
Leases — Xcel Energy evaluates a variety of contracts for lease classification at inception, including PPAs and rental arrangements for
office space, vehicles and equipment. Contracts determined to contain a lease because of per unit pricing that is other than fixed or
market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a
capital lease. See Note 13 for further discussion of leases.
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 service rates. In addition to construction-related amounts, cost of capital also is recorded to
reflect returns on capital used to finance conservation programs in Minnesota.
Generally, AFUDC costs are recovered from customers as the related property is depreciated. However, in some cases commissions
have approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of
AFUDC. In other cases, some commissions have allowed an AFUDC calculation greater than the FERC-defined AFUDC rate,
resulting in higher recognition of AFUDC.
AROs — Xcel Energy Inc.’s utility subsidiaries account 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.
Xcel Energy Inc.’s 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 balance sheets as a regulatory liability. See Note 13 for further
discussion of AROs.
Nuclear Decommissioning — Nuclear decommissioning studies estimate NSP-Minnesota’s ultimate costs of decommissioning its
nuclear power plants and are performed at least every three years and submitted to the MPUC and other state commissions for
approval. NSP-Minnesota’s most recent triennial nuclear decommissioning studies were approved by the MPUC in October 2015.
These studies reflect NSP-Minnesota’s plans for prompt dismantlement of the Monticello and PI facilities. These studies assume that
NSP-Minnesota will store spent fuel on site pending removal to a U.S. government facility.
For rate making purposes, NSP-Minnesota recovers the total decommissioning costs related to its nuclear power plants over each
facility’s expected service life based on the triennial decommissioning studies filed with the MPUC and other state commissions. 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. See Note 14 for further discussion of the approved
nuclear decommissioning studies and funded amounts. For financial reporting purposes, NSP-Minnesota accounts for nuclear
decommissioning as an ARO as described above.
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 11 for further discussion of the nuclear
decommissioning fund.
Nuclear Fuel Expense — Nuclear fuel expense, which is recorded as NSP-Minnesota’s nuclear generating plants use fuel, includes
the cost of fuel used in the current period (including AFUDC) and costs associated with the end-of-life fuel segments.
Nuclear Refueling Outage Costs — Xcel Energy uses a deferral and amortization method for nuclear refueling O&M costs. This
method amortizes refueling outage costs over the period between refueling outages consistent with how the costs are recovered ratably
in electric rates.
Income Taxes — Xcel Energy accounts for income taxes using the asset and liability method, which requires the 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 the tax 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 income in
the period that includes the enactment date.
88
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. In making such a determination, all available evidence is considered, including scheduled reversals of deferred
tax liabilities, projected future taxable income, tax planning strategies and recent financial operations.
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, the reversal of some temporary differences are accounted for as current income tax expense. 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 certain regulatory assets and liabilities related to income taxes, which are
summarized in Note 15.
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.
Xcel Energy reports interest and penalties related to income taxes within the other income and interest charges sections in the
consolidated statements of income.
Xcel Energy Inc. and its subsidiaries file consolidated federal income tax returns as well as combined or separate state income tax
returns. Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company
computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state
filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries based on the relative positive tax
liabilities of the subsidiaries.
See Note 6 for further discussion of income taxes.
Types of and Accounting for 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.
All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the
accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative
instruments. This includes certain instruments used to mitigate market risk for the utility operations including transmission in
organized markets and all instruments related to the commodity trading operations. The 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.
The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.
Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues; 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. Certain utility subsidiaries are allowed to recover in electric or natural gas rates the costs
of certain financial instruments purchased to reduce commodity cost volatility. For further information on derivatives entered to
mitigate commodity price risk on behalf of electric and natural gas customers, see Note 11.
Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction, or future cash
flow (cash flow hedge). Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective, are included
in OCI or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged
transaction.
Normal Purchases and Normal Sales — Xcel Energy enters into contracts for the purchase and sale of commodities for use in its
business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine
whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from derivative
accounting if designated as normal purchases or normal sales.
Xcel Energy evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and
normal sales designation requirements. None of the contracts entered into within the commodity trading operations qualify for a
normal purchases and normal sales designation.
See Note 11 for further discussion of Xcel Energy’s risk management and derivative activities.
89
Commodity Trading Operations — All applicable gains and losses related to commodity trading activities, whether or not settled
physically, are shown on a net basis in electric operating revenues in the consolidated statements of income.
Xcel Energy’s commodity trading operations are conducted by NSP-Minnesota and PSCo. 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 11 for further discussion.
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 as a primary input 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 for
an identical contract in an active market, Xcel Energy may use quoted prices for similar contracts or internally prepared valuation
models to determine fair value. For the 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. See Note 11 for further discussion.
Cash and Cash Equivalents — Xcel Energy considers investments in certain instruments, including commercial paper and money
market funds, 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.
Inventory — All inventory is recorded at average cost.
RECs — RECs are marketable environmental instruments that represent proof that energy was generated from eligible renewable
energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a
form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from
renewable energy sources, but can also be sold separately from the energy produced. Utility subsidiaries acquire RECs from the
generation or purchase of renewable power.
When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost. The cost of RECs that are
utilized for compliance purposes is recorded as electric fuel and purchased power expense. As a result of state regulatory orders, Xcel
Energy reduces recoverable fuel costs for the cost of certain RECs and records that cost as a regulatory asset when the amount is
recoverable in future rates.
Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross
basis. The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are
recorded in electric fuel and purchased power expense.
Emission Allowances — Emission allowances, including the annual SO2 and NOx emission allowance entitlement received from the
EPA, are recorded at cost plus associated broker commission fees. Xcel Energy follows the inventory accounting model for all
emission allowances. Sales of emission allowances are included in electric utility operating revenue and the operating activities
section of the consolidated statements of cash flows.
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, excluding inflationary increases, are recorded based on experience, an assessment of the current situation
and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised
and remediation proceeds. If other participating PRPs exist and acknowledge their potential involvement with a site, costs are
estimated and recorded only for Xcel Energy’s expected share of the cost. Any future costs of restoring sites where operation may
extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a
provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates before the related costs
are incurred are classified as a regulatory liability.
See Note 13 for further discussion of environmental costs.
90
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 under applicable
accounting guidance requires management to make various assumptions and estimates.
Based on the regulatory recovery mechanisms of Xcel Energy Inc.’s utility subsidiaries, certain unrecognized actuarial gains and
losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI.
See Note 9 for further discussion of benefit plans and other postretirement benefits.
Guarantees — Xcel Energy recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the
obligation that has been assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other
conditions which may modify the ongoing obligation to perform under the guarantee.
The obligation recognized is reduced over the term of the guarantee as Xcel Energy is released from risk under the guarantee. See
Note 13 for specific details of issued guarantees.
Reclassifications — Due to adoption of new accounting pronouncements, certain previously reported amounts have been reclassified
to conform to the current year presentation. See Note 2 for further discussion of recently adopted accounting pronouncements.
Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2016 up to the date of issuance of
these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that
evaluation.
2. Accounting Pronouncements
Recently Issued
Revenue Recognition — In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09),
which provides a new framework for the recognition of revenue. Xcel Energy expects its adoption will result in increased disclosures
regarding revenue, cash flows and obligations related to arrangements with customers, as well as separate presentation of alternative
revenue programs in the consolidated statements of income. Xcel Energy has not yet fully determined the impacts of adoption for
several aspects of the standard, including a determination of whether receipts of non-refundable contributions in aid of construction
should be recognized as revenues or may continue to be recorded as reductions to property, plant and equipment. Also, it is yet to be
determined whether and how much an evaluation of the collectability of regulated electric and gas revenues will impact the amounts
of revenue recognized upon delivery. Xcel Energy currently expects to implement the standard on a modified retrospective basis,
which requires application to contracts with customers effective Jan. 1, 2018, with the cumulative impact on contracts not yet
completed as of Dec. 31, 2017 recognized as an adjustment to the opening balance of retained earnings.
Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of
Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which among other changes in accounting and
disclosure requirements, replaces the cost method of accounting for non-marketable equity securities with a model for recognizing
impairments and observable price changes, and also eliminates the available-for-sale classification for marketable equity securities.
Under the new guidance, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of
equity securities are to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning
after Dec. 15, 2017. Xcel Energy is currently evaluating the impact of adopting ASU No. 2016-01 on its consolidated financial
statements.
Leases — In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which, for lessees, requires balance sheet
recognition of right-of-use assets and lease liabilities for all leases. Additionally, for leases that qualify as finance leases, the guidance
requires expense recognition consisting of amortization of the right-of-use asset as well as interest on the related lease liability using
the effective interest method. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018,
and early adoption is permitted. Xcel Energy is currently evaluating the impact of adopting ASU No. 2016-02 on its consolidated
financial statements.
91
Recently Adopted
Consolidation — In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02),
which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities.
Xcel Energy implemented the guidance on Jan. 1, 2016, and other than the classification of certain real estate investments held within
the Nuclear Decommissioning Trust as non-consolidated variable interest entities, the implementation did not have a significant
impact on its consolidated financial statements.
Presentation of Debt Issuance Costs — In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic
835-30 (ASU No. 2015-03), which requires the presentation of debt issuance costs on the balance sheet as a deduction from the
carrying amount of the related debt, instead of presentation as an asset. Xcel Energy implemented the new guidance as required on
Jan. 1, 2016, and as a result, $91.8 million of such deferred costs were retrospectively reclassified from other non-current assets to
long-term debt on the consolidated balance sheet as of Dec. 31, 2015.
Fair Value Measurement — In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset
Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which eliminates the requirement to categorize fair value
measurements using NAV methodology in the fair value hierarchy. Xcel Energy implemented the guidance on Jan. 1, 2016, and the
implementation did not have a material impact on its consolidated financial statements. For related disclosures, see Note 9 and Note
11 to the consolidated financial statements.
Presentation of Deferred Taxes — In November 2015, the FASB issued Balance Sheet Classification of Deferred Taxes, Topic 740
(ASU No. 2015-17), which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent on the
consolidated balance sheet based on the classification of the related asset or liability, and instead requires classification of all deferred
tax assets and liabilities as noncurrent. Xcel Energy early adopted the new guidance in the fourth quarter of 2016 and as a result
$140.2 million of current deferred income taxes were retrospectively reclassified to long-term deferred income tax liabilities on the
consolidated balance sheet as of Dec. 31, 2015.
Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718
(ASU No. 2016-09), which simplifies accounting and financial statement presentation for share-based payment transactions. The
guidance requires that the difference between the tax deduction available upon settlement of share-based equity awards and the tax
benefit accumulated over the vesting period be recognized as an adjustment to income tax expense. Xcel Energy adopted the guidance
in 2016, resulting in immaterial 2016 adjustments to income tax expense and changes in classification of cash flows related to tax
withholding in the consolidated statements of cash flows for the years ended Dec. 31, 2016, 2015 and 2014.
3. Selected Balance Sheet Data
(Thousands of Dollars)
Accounts receivable, net
Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Less allowance for bad debts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(Thousands of Dollars)
Inventories
Materials and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
Dec. 31, 2016
Dec. 31, 2015
827,112
(50,823)
776,289
Dec. 31, 2016
312,430
181,752
110,044
604,226
$
$
$
$
776,494
(51,888)
724,606
Dec. 31, 2015
290,690
202,271
115,623
608,584
92
(Thousands of Dollars)
Property, plant and equipment, net
Electric plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Common and other property. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plant to be retired (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CWIP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less accumulated amortization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dec. 31, 2016
Dec. 31, 2015
$
$
38,220,765
5,317,717
1,888,518
31,839
1,373,380
46,832,219
(14,381,603)
2,571,770
(2,180,636)
32,841,750
$
$
36,464,050
4,944,757
1,709,508
38,249
1,256,949
44,413,513
(13,591,259)
2,447,251
(2,063,654)
31,205,851
(a)
In 2017, PSCo expects to early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas. PSCo also expects Craig
Unit 1 to be early retired in approximately 2025. Amounts are presented net of accumulated depreciation.
4. Borrowings and Other Financing Instruments
Short-Term Borrowings
Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term
investments in and borrowings between the utility subsidiaries. NSP-Wisconsin does not participate in the money pool. 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. The money pool balances are eliminated in consolidation.
Commercial Paper — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the
issuance of commercial paper and borrowings under their credit facilities. Commercial paper outstanding for Xcel Energy was as
follows:
(Amounts in Millions, Except Interest Rates)
Borrowing limit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Amount outstanding at period end. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average amount outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Maximum amount outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average interest rate, computed on a daily basis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average interest rate at period end. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Three Months Ended
Dec. 31, 2016
(Amounts in Millions, Except Interest Rates)
Borrowing limit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Amount outstanding at period end . . . . . . . . . . . . . . . . . . . . . . . . . .
Average amount outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Maximum amount outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average interest rate, computed on a daily basis . . . . . . .
Weighted average interest rate at end of period . . . . . . . . . . . . . . . .
Year Ended Dec. 31
2016
2015
2014
$
2,750
392
485
1,183
0.74%
0.95
$
2,750
846
601
1,360
0.48%
0.82
2,750
392
290
582
0.75%
0.95
2,750
1,020
841
1,200
0.33%
0.56
Letters of Credit — Xcel Energy Inc. and its subsidiaries use letters of credit, generally with terms of one year, to provide financial
guarantees for certain operating obligations. At Dec. 31, 2016 and 2015, there were $19 million and $29 million of letters of credit
outstanding, respectively, under the credit facilities. The contract amounts of these letters of credit approximate their fair value and
are subject to fees.
93
Credit Facilities — In order to use their 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 2016, 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
remained at $2.75 billion. The amended credit agreements have substantially the same terms and conditions as the prior credit
agreements with the following exceptions:
• The maturity extended from October 2019 to June 2021.
• The Eurodollar borrowing margins on these lines of credit were reduced to a range of 75 to 150 basis points per year, from a
range of 87.5 to 175 basis points per year, based upon applicable long-term credit ratings.
• The commitment fees, calculated on the unused portion of the lines of credit, were reduced to a range of 6 to 22.5 basis points
per year, from a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.
NSP-Minnesota, PSCo, SPS, and Xcel Energy Inc. each have the right to request an extension of the termination date for two
additional one-year periods. NSP-Wisconsin has the right to request an extension of the termination date for an additional one-year
period. All extension requests are subject to majority bank group approval.
Other features of the credit facilities include:
• Xcel Energy Inc. may increase its credit facility by up to $200 million, NSP-Minnesota and PSCo may each increase their
credit facilities by $100 million and SPS may increase its credit facility by $50 million. The NSP-Wisconsin credit facility
cannot be increased.
• Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio of each entity be less than or
equal to 65 percent. Each entity was in compliance at Dec. 31, 2016 and 2015, respectively, as evidenced by the table below:
Xcel Energy Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NSP-Wisconsin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NSP-Minnesota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SPS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PSCo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt-to-Total Capitalization Ratio
2016
2015
57%
47
48
47
45
57%
46
48
46
45
•
If Xcel Energy Inc. or any of 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.
• The Xcel Energy Inc. credit facility has a cross-default provision that provides 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 percent of Xcel Energy’s consolidated total assets, default on certain indebtedness in an aggregate principal
amount exceeding $75 million.
• Xcel Energy Inc. and its subsidiaries were in compliance with all financial covenants in their debt agreements as of Dec. 31,
2016 and 2015.
At Dec. 31, 2016, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available:
(Millions of Dollars)
Xcel Energy Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PSCo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NSP-Minnesota. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NSP-Wisconsin. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
Credit Facility (a)
Drawn (b)
Available
1,000
700
500
400
150
2,750
$
$
68
132
96
55
60
411
$
$
932
568
404
345
90
2,339
(a)
(b)
These credit facilities mature in June 2021.
Includes outstanding commercial paper and letters of credit.
94
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under
the respective credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on the credit facilities outstanding at Dec.
31, 2016 and 2015.
Long-Term Borrowings and Other Financing Instruments
Generally, all real and personal 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 associated with refinanced debt are deferred and amortized over the life of the related new issuance, in
accordance with regulatory guidelines.
Maturities of long-term debt are as follows:
(Millions of Dollars)
2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
256
1,206
406
1,257
425
During 2016, Xcel Energy Inc. and its utility subsidiaries completed the following financings:
• Xcel Energy Inc. issued $400 million of 2.4 percent senior notes due March 15, 2021 and $350 million of 3.3 percent senior
notes due June 1, 2025;
• NSP-Minnesota issued $350 million of 3.6 percent first mortgage bonds due May 15, 2046;
•
•
• Xcel Energy Inc. issued $300 million of 2.6 percent senior notes due March 15, 2022 and $500 million of 3.35 percent senior
PSCo issued $250 million of 3.55 percent first mortgage bonds due June 15, 2046;
SPS issued $300 million of 3.4 percent first mortgage bonds due Aug. 15, 2046; and
notes due Dec. 1, 2026.
During 2015, Xcel Energy Inc. and its utility subsidiaries completed the following financings:
PSCo issued $250 million of 2.9 percent first mortgage bonds due May 15, 2025;
•
• Xcel Energy Inc. issued $250 million of 1.2 percent senior notes due June 1, 2017 and $250 million of 3.3 percent senior
notes due June 1, 2025;
• NSP-Wisconsin issued $100 million of 3.3 percent first mortgage bonds due June 15, 2024;
• NSP-Minnesota issued $300 million of 2.2 percent first mortgage bonds due Aug. 15, 2020 and $300 million of 4.0 percent
first mortgage bonds due Aug. 15, 2045; and
SPS issued $200 million of 3.3 percent first mortgage bonds due June 15, 2024.
•
Issuances of Common Stock — During the year ended Dec. 31, 2014, Xcel Energy Inc. issued approximately 5.7 million shares of
common stock through an at-the-market (ATM) program and received cash proceeds of $172.7 million net of $1.9 million in fees and
commissions. Xcel Energy completed its ATM program as of June 30, 2014. The proceeds from the issuances of common stock were
used to repay short-term debt, infuse equity into the utility subsidiaries and for other general corporate purposes.
Deferred Financing Costs — Deferred financing costs of approximately $109 million and $92 million, net of amortization, are
presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2016 and 2015, respectively. Xcel Energy is
amortizing these financing costs over the remaining maturity periods of the related debt.
Capital Stock — Xcel Energy Inc. has 7,000,000 shares of preferred stock authorized to be issued with a $100 par value. At Dec. 31,
2016 and 2015, there were no shares of preferred stock outstanding.
The charters of PSCo and SPS authorize each subsidiary to issue 10,000,000 shares of preferred stock with par values of $0.01 and
$1.00 per share, respectively. At Dec. 31, 2016 and 2015, there were no preferred shares of subsidiaries outstanding.
Xcel Energy Inc. has 1,000,000,000 shares of common stock authorized to be issued with a $2.50 par value. Outstanding shares at
Dec. 31, 2016 and 2015 were 507,222,795 and 507,535,523, respectively.
95
Dividend and Other Capital-Related Restrictions — Xcel Energy depends on its subsidiaries to pay dividends. All of Xcel Energy
Inc.’s utility subsidiaries’ dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital
accounts; payment of dividends is allowed out of retained earnings only. Due to certain restrictive covenants, Xcel Energy Inc. is
required to be current on particular interest payments before dividends can be paid.
The most restrictive dividend limitations for NSP-Minnesota, NSP-Wisconsin and SPS are imposed by their respective state regulatory
commission. PSCo’s dividends are subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of
dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.
Only NSP-Minnesota has a first mortgage indenture which places certain restrictions on the amount of cash dividends it can pay to
Xcel Energy Inc., the holder of its common stock. Even with this restriction, NSP-Minnesota could have paid more than $1.7 billion
in additional cash dividends to Xcel Energy Inc. at both Dec. 31, 2016 and 2015.
NSP-Minnesota’s state regulatory commissions indirectly limit the amount of dividends NSP-Minnesota can pay by requiring an
equity-to-total capitalization ratio between 46.9 percent and 57.3 percent. NSP-Minnesota’s equity-to-total capitalization ratio was
52.1 percent at Dec. 31, 2016 and $1.0 billion in retained earnings was not restricted. Total capitalization for NSP-Minnesota was
$10.3 billion at Dec. 31, 2016, which did not exceed the limit of $10.75 billion.
NSP-Wisconsin cannot pay annual dividends in excess of approximately $53.1 million if its calendar year average equity-to-total
capitalization ratio is or falls below the state commission authorized level of 52.5 percent, as calculated consistent with PSCW
requirements. NSP-Wisconsin’s calendar year average equity-to-total capitalization ratio calculated on this basis was 53.6 percent at
Dec. 31, 2016 and $33.6 million in retained earnings was not restricted.
SPS’ state regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc. by requiring an equity-
to-total capitalization ratio (excluding short-term debt) between 45.0 percent and 55.0 percent. In addition, SPS may not pay a
dividend that would cause it to lose its investment grade bond rating. SPS’ equity-to-total capitalization ratio (excluding short-term
debt) was 54.1 percent at Dec. 31, 2016 and $487 million in retained earnings was not restricted.
The issuance of securities by Xcel Energy Inc. generally is not subject to regulatory approval. However, utility financings and certain
intra-system financings are subject to the jurisdiction of the applicable state regulatory commissions and/or the FERC. As of Dec. 31,
2016:
•
•
PSCo has authorization to issue up to an additional $2.2 billion of long-term debt and up to $800 million of short-term debt.
SPS has authorization to issue up to $500 million of short-term debt and SPS will file for additional long-term debt
authorization.
• NSP-Wisconsin has authorization to issue up to $150 million of short-term debt and NSPW will file for additional long-term
debt authorization.
• NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization ratio remains between
46.9 percent and 57.3 percent and to issue short-term debt provided it does not exceed 15 percent of total capitalization. Total
capitalization for NSP-Minnesota cannot exceed $10.75 billion.
Xcel Energy believes these authorizations are adequate and seeks additional authorization as necessary.
5. Joint Ownership of Generation, Transmission and Gas Facilities
Following are the investments by Xcel Energy Inc.’s utility subsidiaries in jointly owned generation, transmission and gas facilities
and the related ownership percentages as of Dec. 31, 2016:
(Thousands of Dollars)
NSP-Minnesota
Electric Generation:
Plant in
Service
Accumulated
Depreciation
CWIP
Ownership %
Sherco Unit 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Sherco Common Facilities Units 1, 2 and 3 . . . . . . . . . . . . . . . . .
Sherco Substation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
589,903
145,447
4,790
Electric Transmission:
Grand Meadow Line and Substation . . . . . . . . . . . . . . . . . . . . . . .
CapX2020 Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total NSP-Minnesota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
10,647
965,289
1,716,076
$
$
398,367
95,909
3,146
1,871
116,942
616,235
$
$
9,714
540
—
—
56,024
66,278
59%
80
59
50
51
96
(Thousands of Dollars)
NSP-Wisconsin
Electric Transmission:
Plant in
Service
Accumulated
Depreciation
CWIP
Ownership %
CapX2020 Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
La Crosse, Wis. to Madison, Wis. . . . . . . . . . . . . . . . . . . . . . . . . .
Total NSP-Wisconsin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
164,040
—
164,040
(Thousands of Dollars)
PSCo
Electric Generation:
Plant in
Service
Hayden Unit 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Hayden Unit 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hayden Common Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Craig Units 1 and 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Craig Common Facilities 1, 2 and 3 . . . . . . . . . . . . . . . . . . . . . . .
Comanche Unit 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Comanche Common Facilities. . . . . . . . . . . . . . . . . . . . . . . . . . . .
149,221
148,795
38,230
60,318
37,925
892,978
24,694
Electric Transmission:
$
$
$
$
$
$
10,874
—
10,874
Accumulated
Depreciation
67,415
64,024
18,951
37,570
19,312
112,254
1,821
42,546
41,131
83,677
81%
37
CWIP
Ownership %
97
64
282
15,730
183
6
636
76%
37
53
10
7
67
82
Transmission and other facilities, including substations . . . . . . . .
166,840
65,619
4,313
Various
Gas Transportation:
Rifle, Colo. to Avon, Colo. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas Transportation Compressor. . . . . . . . . . . . . . . . . . . . . . . . . . .
Total PSCo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
23,406
8,397
1,550,804
$
7,679
368
395,013
$
—
—
21,311
60
50
NSP-Minnesota and PSCo have approximately 517 MW and 816 MW of jointly owned generating capacity, respectively. Each
Company’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the
respective owners is responsible for providing its own financing.
6.
Income Taxes
Consolidated Appropriations Act, 2016 — In December 2015, the Consolidated Appropriations Act, 2016 (Act) was signed into law.
The Act provides for the following:
•
•
•
Immediate expensing, or “bonus depreciation,” of 50 percent for property placed in service in 2015, 2016, and 2017; 40
percent for property placed in service in 2018; and 30 percent for property placed in service in 2019. Additionally, some
longer production period property placed in service in 2020 will be eligible for bonus depreciation;
PTCs at 100 percent of the credit rate ($0.023 per KWh) for wind energy projects that begin construction by the end of 2016;
80 percent of the credit rate for projects that begin construction in 2017; 60 percent of the credit rate for projects that begin
construction in 2018; and 40 percent of the credit rate for projects that begin construction in 2019. The wind energy PTC was
not extended for projects that begin construction after 2019;
ITCs at 30 percent for commercial solar projects that begin construction by the end of 2019; 26 percent for projects that begin
construction in 2020; 22 percent for projects that begin construction in 2021; and 10 percent for projects thereafter;
• R&E credit was permanently extended; and
• Delay of two years (until 2020) of the excise tax on certain employer-provided health insurance plans.
The accounting related to the Act was recorded beginning in the fourth quarter of 2015 because a change in tax law is accounted for
beginning in the period of enactment. The fourth quarter 2015 accounting impacts included:
• Recognition of additional tax deductions for bonus depreciation of $1.2 billion, and as a result, recognition of $4.9 million
benefit related to a carryback claim (see additional discussion below) and $3.5 million expense related to valuation
allowances and expirations of charitable contribution carryforwards; and
• Recognition of $6.8 million benefit for federal R&E credits.
97
Tax Increase Prevention Act of 2014 — In 2014, the Tax Increase Prevention Act (TIPA) was signed into law. The TIPA provides for
the following:
• The R&E credit was extended for 2014;
•
PTCs were extended for projects that began construction before the end of 2014 with certain projects qualifying into future
years; and
50 percent bonus depreciation was extended one year through 2014. Additionally, some longer production period property
placed in service in 2015 is also eligible for 50 percent bonus depreciation.
•
The accounting related to the TIPA was recorded beginning in the fourth quarter of 2014 because a change in tax law is accounted for
in the period of enactment.
Federal Tax Loss Carryback Claims — In 2012-2015, Xcel Energy identified certain expenses related to 2009, 2010, 2011, 2013,
2014 and 2015 that qualify for an extended carryback beyond the typical two-year carryback period. As a result of a higher tax rate in
prior years, Xcel Energy recognized a tax benefit of approximately $5 million in 2015, $17 million in 2014, $12 million in 2013 and
$15 million in 2012.
Federal Audit — Xcel Energy files a consolidated federal income tax return. In 2012, the IRS commenced an examination of tax
years 2010 and 2011, including the 2009 carryback claim. As of Dec. 31, 2016, the IRS had proposed an adjustment to the federal tax
loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 claims and the 2013 through
2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In 2016, the IRS audit
team and Xcel Energy presented their cases to Appeals; however, the outcome and timing of a resolution is uncertain. The statute of
limitations applicable to Xcel Energy’s 2009 through 2011 federal income tax returns, following extensions, expires in December
2017. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of the IRS’s
proposed adjustment of the carryback claims.
In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of Dec. 31, 2016, the IRS had not
proposed any material adjustments to tax years 2012 and 2013. Subsequent to year-end, the IRS proposed an adjustment to tax years
2012 through 2013 that may impact Xcel Energy’s NOL and tax credit carryforwards and ETR. However, Xcel Energy is continuing
to evaluate the IRS’ proposal and the outcome and timing of a resolution is uncertain.
State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions of Colorado,
Minnesota, Texas, and Wisconsin, and various other state income-based tax returns. As of Dec. 31, 2016, Xcel Energy’s earliest open
tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows:
State
Colorado. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Minnesota. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wisconsin. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year
2009
2009
2009
2012
In February 2016, Texas began an audit of years 2009 and 2010. As of Dec. 31, 2016, Texas had not proposed any adjustments.
In June 2016, Minnesota began an audit of years 2010 through 2014. As of Dec. 31, 2016, Minnesota had not proposed any
adjustments.
In August 2016, Wisconsin began an audit of years 2012 and 2013. As of Dec. 31, 2016, Wisconsin had not proposed any
adjustments. As of Dec. 31, 2016, there were no other state income tax audits in progress.
98
Unrecognized Tax Benefits — The 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 of cash to the taxing authority to an earlier period.
A reconciliation of the amount of unrecognized tax benefit is as follows:
(Millions of Dollars)
Unrecognized tax benefit — Permanent tax positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Unrecognized tax benefit — Temporary tax positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total unrecognized tax benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:
(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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lapse of applicable statutes of limitations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at Dec. 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2016
2015
$
120.7
8.2
(0.3)
9.8
(4.7)
—
—
66.5
27.1
(4.5)
34.8
(2.9)
(0.3)
—
$
133.7
$
120.7
$
Dec. 31, 2016
Dec. 31, 2015
29.6
104.1
133.7
$
$
$
25.8
94.9
120.7
2014
41.2
28.7
(2.0)
16.0
(6.0)
(9.6)
(1.8)
66.5
The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The
amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:
(Millions of Dollars)
NOL and tax credit carryforwards. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dec. 31, 2016
Dec. 31, 2015
$
(43.8) $
(36.7)
It is reasonably possible that Xcel Energy’s amount of unrecognized tax benefits could significantly change in the next 12 months as
the IRS Appeals and audit progress, the Minnesota, Texas and Wisconsin audits progress, and other state audits resume. As the IRS
Appeals and IRS, Minnesota, Texas and Wisconsin audits progress, it is reasonably possible that the amount of unrecognized tax
benefit could decrease up to approximately $61 million.
The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax
credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax
benefits reported are as follows:
(Millions of Dollars)
Payable for interest related to unrecognized tax benefits at Jan. 1 . . . . . . . . . . . . . . . . . . $
Interest (expense) income related to unrecognized tax benefits . . . . . . . . . . . . . . . . . . . .
Payable for interest related to unrecognized tax benefits at Dec. 31 . . . . . . . . . . . . . . . .
$
2016
2015
2014
(0.1) $
(3.3)
(3.4) $
(0.3) $
0.2
(0.1) $
(0.6)
0.3
(0.3)
No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2016, 2015 or 2014.
99
Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the
deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:
(Millions of Dollars)
Federal NOL carryforward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Federal tax credit carryforwards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State NOL carryforwards. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Valuation allowances for state NOL carryforwards. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State tax credit carryforwards, net of federal detriment (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Valuation allowances for state credit carryforwards, net of federal benefit (b) . . . . . . . . . . . . . . . . . . . . . .
$
2016
2015
$
1,916
424
1,949
(59)
74
(54)
2,153
360
2,124
(65)
45
(24)
(a)
(b)
State tax credit carryforwards are net of federal detriment of $40 million and $24 million as of Dec. 31, 2016 and 2015, respectively.
Valuation allowances for state tax credit carryforwards were net of federal benefit of $29 million and $13 million as of Dec. 31, 2016 and 2015, respectively.
The federal carryforward periods expire between 2021 and 2036. The state carryforward periods expire between 2017 and 2035.
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. The following reconciles such differences for the years ending Dec. 31:
Federal statutory rate. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increases (decreases) in tax from:
Tax credits recognized, net of federal income tax expense . . . . . . . . . . . . . . . . . . . . . . . .
Regulatory differences — utility plant items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State income taxes, net of federal income tax benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in unrecognized tax benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NOL carryback . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Effective income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
The components of Xcel Energy’s income tax expense for the years ending Dec. 31 were:
2016
2015
2014
35.0%
35.0%
35.0%
(4.2)
(0.5)
4.2
0.2
—
(0.6)
34.1%
(2.7)
(1.0)
4.1
0.6
(0.3)
(0.2)
35.5%
(2.6)
(1.3)
4.0
0.2
(0.9)
(0.5)
33.9%
(Thousands of Dollars)
Current federal tax benefit. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Current state tax (benefit) expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current change in unrecognized tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred federal tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred state tax expense. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred change in unrecognized tax benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred investment tax credits. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2016
(2,809) $
(3,345)
5,924
476,439
112,308
(2,097)
(5,203)
581,217
$
2015
(36,129) $
2,324
45,933
480,078
92,132
(36,342)
(5,277)
542,719
$
2014
(73,160)
9,225
23,915
505,236
84,787
(20,645)
(5,543)
523,815
The components of deferred income tax expense for the years ending Dec. 31 were:
(Thousands of Dollars)
Deferred tax expense excluding items below . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Amortization and adjustments to deferred income taxes on income tax regulatory assets
and liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax benefit allocated to OCI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax expense. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2016
630,877
(44,638)
415
(4)
586,650
$
$
2015
546,664
(11,810)
1,013
1
535,868
$
$
2014
616,934
(48,674)
1,117
1
569,378
100
The components of Xcel Energy’s net deferred tax liability at Dec. 31 were as follows:
(Thousands of Dollars)
Deferred tax liabilities:
2016
2015
Differences between book and tax bases of property . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 7,696,833
313,034
Regulatory assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
186,007
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 8,195,874
$ 7,119,023
308,130
229,005
$ 7,656,158
Deferred tax assets:
NOL carryforward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax credit carryforward. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rate refund . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Environmental remediation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulatory liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred investment tax credits. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred fuel costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NOL and tax credit valuation allowances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
753,851
497,518
32,810
30,288
28,249
27,436
11,387
(57,515)
87,531
Total deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,411,555
Net deferred tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,784,319
$
$
851,242
404,738
50,441
38,663
36,257
29,650
57,220
(27,679)
62,184
$ 1,502,716
$ 6,153,442
7. Earnings Per Share
Basic EPS was computed by dividing the earnings available to Xcel Energy Inc.’s common shareholders by the weighted average
number of common shares outstanding during the period. Diluted EPS was computed by dividing the earnings available to Xcel
Energy Inc.’s 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 Xcel Energy
Inc.’s diluted EPS is calculated using the treasury stock method.
Common Stock Equivalents — Xcel Energy Inc. currently has common stock equivalents related to certain equity awards in share-
based compensation arrangements.
Common stock equivalents causing a dilutive impact to EPS include commitments to issue common stock related to time based equity
compensation awards and time based employer matching contributions to certain 401(k) plan participants. Effective August 2015,
401(k) matching contributions are settled in cash for all Xcel Energy employee groups.
Stock equivalent units granted to Xcel Energy Inc.’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 awards. Restricted stock, granted to settle amounts
due to certain employees under the Xcel Energy Inc. Executive Annual Incentive Award Plan, is included in common shares
outstanding when granted.
Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following:
• Equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions for
settlement have been satisfied by the end of the reporting period.
• Liability awards subject to a performance condition; any portions settled in shares are included in common shares
outstanding upon settlement.
101
The dilutive impact of common stock equivalents affecting EPS was as follows:
(Amounts in thousands, except
per share data)
Net income . . . . . . . . . . . . . . . .
Basic EPS:
Earnings available to common
shareholders . . . . . . . . . . . . . . .
Effect of dilutive securities:
Equity awards . . . . . . . . . . . .
Diluted EPS:
Earnings available to common
shareholders . . . . . . . . . . . . . . .
2016
2015
2014
Income
$ 1,123,379
Shares
Per
Share
Amount
Income
$ 984,485
Shares
Per
Share
Amount
Income
$ 1,021,306
Shares
Per
Share
Amount
1,123,379
508,794
$ 2.21
984,485
507,768
$ 1.94
1,021,306
503,847
$ 2.03
—
671
—
400
—
270
$ 1,123,379
509,465
$ 2.21
$ 984,485
508,168
$ 1.94
$ 1,021,306
504,117
$ 2.03
Dividend Reinvestment and Stock Purchase Plan and Stock Compensation Settlements — In 2015, the Xcel Energy Inc. Board of
Directors authorized open market purchases by the plan administrator as the source of shares for the dividend reinvestment program as
well as market purchases of up to 3.0 million shares for stock compensation plan settlements. In 2016, Xcel Energy Inc. repurchased
approximately 0.8 million shares of common stock in the open market at a total cost of approximately $32.2 million.
8. Share-Based Compensation
Restricted Stock — Certain employees may elect to receive shares of common or restricted stock under the Xcel Energy Inc.
Executive Annual Incentive Award Plan. Restricted stock is treated as an equity award and vests and settles in equal annual
installments over a three-year period. Xcel Energy Inc. reinvests dividends on the restricted stock while restrictions are in place.
Restrictions also apply to the additional shares of restricted stock acquired through dividend reinvestment. If the restricted shares are
forfeited, the employee is not entitled to the dividends on those shares. Restricted stock has a fair value equal to the market trading
price of Xcel Energy Inc.’s stock at the grant date.
Xcel Energy Inc. granted shares of restricted stock for the years ended Dec. 31 as follows:
(Shares in Thousands)
Granted shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Grant date fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2016
2015
2014
20
38.82
$
42
35.00
$
46
29.69
A summary of the changes of nonvested restricted stock for the year ended 2016 were as follows:
(Shares in Thousands)
Nonvested restricted stock at Jan. 1, 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividend equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nonvested restricted stock at Dec. 31, 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Shares
83
20
—
(38)
2
67
Weighted Average
Grant Date Fair Value
32.62
$
38.82
—
31.41
40.04
35.43
Other Equity Awards — Xcel Energy Inc.’s Board of Directors has granted equity awards under the Xcel Energy Inc. 2005 Long-
Term Incentive Plan (as amended and restated in 2010) and the 2015 Omnibus Incentive Plan (effective May 20, 2015). These plans
allow the attachment of various vesting conditions and performance goals to the awards granted. The vesting conditions and
performance goals may vary by plan year. At the end of the restricted period, such grants will be awarded if the vesting conditions
and/or performance goals are met.
Commencing in 2014, certain employees were granted equity awards with one portion of shares subject only to service conditions, and
the other portion subject to performance conditions. Inclusive of other grants of time-based awards, a total of 0.3 million, 0.3 million,
and 0.4 million time-based equity shares subject only to service conditions were granted in 2016, 2015, and 2014, respectively. Other
than shares associated with these time-based awards, restricted stock and certain 401(k) employer match settlements, payout of all
other employee equity awards and the lapsing of restrictions on the transfer of units are based on the achievement of performance
criteria.
102
The performance conditions for a portion of the awards granted from 2014 to 2016 are based on relative TSR, measured identically to
TSR liability awards granted in those years, and measurement of performance for a portion of units awarded from 2011 to 2013 is
based on EPS growth with an additional condition that Xcel Energy Inc.’s annual dividend paid on its common stock remains at a
specified amount per share or greater. The performance conditions for the remaining employee equity awards are based on
environmental goals. Equity awards with performance conditions awarded from 2011 to 2016, plus associated dividend equivalents,
will be settled or forfeited and the restricted period will lapse after three years, with potential payouts ranging from zero to 150 percent
for 2011 to 2013 grants, and zero to 200 percent for 2014 to 2016 grants, depending on the level of achievement.
• The 2011 awards measured on EPS growth and the 2011 environmental awards met their targets as of Dec. 31, 2013 and were
settled in shares in February 2014.
• The 2012 awards measured on EPS growth and the 2012 environmental awards met their targets as of Dec. 31, 2014, and
were settled in shares in February 2015.
• The 2013 awards measured on EPS growth, the 2013 environmental awards and the 2013 time-based awards met their targets
as of Dec. 31, 2015, and were settled in shares in February 2016.
• The 2014 environmental awards and the 2014 time-based awards met their targets as of Dec. 31, 2016, and will be settled in
shares in February 2017.
Equity award units granted to employees, excluding restricted stock and applicable 401(k) employer match settlements, for the years
ended Dec. 31 were as follows:
(Units in Thousands)
Granted units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average grant date fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2016
2015
2014
522
36.00
$
496
36.09
$
588
29.90
Approximately 0.5 million of these units vested during 2016 at a total fair value of $21.6 million. Approximately 0.8 million of these
units vested during 2015 at a total fair value of $27.1 million. Approximately 0.5 million of these units vested during 2014 at a total
fair value of $19.6 million.
A summary of the changes in the nonvested portion of these equity award units for the year ended 2016, were as follows:
(Units in Thousands)
Nonvested Units at Jan. 1, 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividend equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nonvested Units at Dec. 31, 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Units
1,025
522
(80)
(530)
47
984
Weighted Average
Grant Date Fair Value
32.81
$
36.00
33.48
29.92
33.64
36.05
The total fair value of these nonvested equity awards as of Dec. 31, 2016 was $40.0 million and the weighted average remaining
contractual life was 1.7 years.
Stock Equivalent Units — Non-employee members of the Xcel Energy Inc. Board of Directors receive annual awards of stock
equivalent units, with each unit having a value equal to one share of Xcel Energy Inc. common stock. The annual grants are vested as
of the date of each member’s election to the Board of Directors; there is no further service or other condition attached to the annual
grants. Additionally, directors may elect to receive their fees in stock equivalent units in lieu of cash. Dividends on Xcel Energy
Inc.’s common stock are converted to stock equivalent units and granted based on the number of stock equivalent units held by each
participant as of the dividend date. The stock equivalent units are payable as a distribution of Xcel Energy Inc.’s common stock upon
a director’s termination of service.
The stock equivalent units granted for the years ended Dec. 31 were as follows:
(Units in Thousands)
Granted units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Grant date fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2016
2015
2014
49
40.68
$
60
34.58
$
62
30.57
103
A summary of the stock equivalent unit changes for the year ended 2016 are as follows:
(Units in Thousands)
Stock equivalent units at Jan. 1, 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Units distributed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividend equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stock equivalent units at Dec. 31, 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Units
Weighted Average
Grant Date Fair Value
25.38
$
40.68
19.98
40.57
27.39
746
49
(69)
24
750
TSR Liability Awards — Xcel Energy Inc.’s Board of Directors has granted TSR liability awards under the Xcel Energy Inc. 2005
Long-Term Incentive Plan (as amended and restated effective in 2010). The plan allows Xcel Energy to attach various performance
goals to the awards granted. The liability awards granted have been historically dependent on a single measure of performance, Xcel
Energy Inc.’s relative TSR measured over a three-year period. For 2016, 2015 and 2014 awards, Xcel Energy Inc.’s TSR is compared
to the TSR of other companies in a 22-member utilities peer group. At the end of the three-year period, potential payouts of the awards
range from zero to 200 percent, depending on Xcel Energy Inc.’s TSR compared to the applicable peer group or index.
The TSR liability awards granted for the years ended Dec. 31 were as follows:
(In Thousands)
Awards granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016
2015
2014
264
224
270
The total amounts of TSR liability awards settled during the years ended Dec. 31 were as follows:
(In Thousands)
Awards settled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlement amount (cash, common stock and deferred amounts) . . . . . . . . . . . . . . . . . . . . $
2016
2015
2014
354
13,724
$
—
— $
—
—
The amount of cash used to settle Xcel Energy’s TSR liability awards was $5.6 million in 2016.
Share-Based Compensation Expense — Other than for restricted stock and certain 401(k) employer match settlements, the vesting of
employee equity awards is generally predicated on the achievement of a performance condition, which is the achievement of a TSR,
EPS or environmental measures target. Additionally, approximately 0.3 million, 0.3 million, and 0.4 million of equity awards were
granted in 2016, 2015, and 2014, respectively, with vesting subject only to service conditions for periods of three years. Generally, all
of these instruments are considered to be equity awards since the plan settlement determination (shares or cash) resides with Xcel
Energy and not the participants. In addition, these awards have not been previously settled in cash and Xcel Energy plans to continue
electing share settlement. The grant date fair value of equity awards is expensed over the service period as employees vest in their
rights to those awards.
The TSR liability awards have been historically settled partially in cash, and therefore 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.
The compensation costs related to share-based awards for the years ended Dec. 31 were as follows:
(Thousands of Dollars)
Compensation cost for share-based awards (a) (b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Tax benefit recognized in income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capitalized compensation cost for share-based awards (c) . . . . . . . . . . . . . . . . . . . . . . . . .
2016
2015
2014
$
41,170
16,005
—
$
44,928
17,570
—
32,189
12,557
1,887
(a)
(b)
(c)
Compensation costs for share-based payment arrangements are included in O&M expense in the consolidated statements of income.
Included in compensation cost for share-based awards are matching contributions related to the Xcel Energy 401(k) plan, which totaled $7.4 million for 2014. In
October 2013, Xcel Energy determined that it would settle the 401(k) employer match in cash instead of common stock going forward for all employee groups
except PSCo bargaining employees. Share-based compensation accounting for the impacted employee groups ceased in October 2013, and corresponding expense
amounts recorded to equity were reclassified to a liability for expected cash settlements. In August 2015, consistent with a new PSCo bargaining agreement,
share-based compensation accounting ceased for the employer 401(k) match for PSCo bargaining employees, which will be paid in cash. As a result, 2015 and
2016 compensation cost for share-based awards includes no 401(k) matching contributions.
An allocated amount of the 401(k) match is capitalized.
104
The maximum aggregate number of shares of common stock available for issuance under the Xcel Energy Inc. 2015 Omnibus
Incentive Plan (effective May 20, 2015) is 7.0 million shares. The maximum aggregate number of shares of common stock available
for issuance under the Xcel Energy Inc. 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) is 8.3
million shares. Under the Xcel Energy Inc. Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010),
the total number of shares approved for issuance is 1.2 million shares.
As of Dec. 31, 2016 and 2015, there was approximately $29.0 million and $36.4 million, respectively, of total unrecognized
compensation cost related to nonvested share-based compensation awards. Xcel Energy expects to recognize the amount
unrecognized at Dec. 31, 2016 over a weighted average period of 1.6 years.
9. Benefit Plans and Other Postretirement Benefits
Xcel Energy offers various benefit plans to its employees. Approximately 47 percent of employees that receive benefits are
represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2016:
• NSP-Minnesota had 1,959 and NSP-Wisconsin had 399 bargaining employees covered under a collective-bargaining
agreement, which expires at the end of 2019. NSP-Minnesota also had an additional 253 nuclear operation bargaining
employees covered under several collective-bargaining agreements. These agreements expire in 2017, 2018 and 2019.
PSCo had 1,984 bargaining employees covered under a collective-bargaining agreement, which expires in May 2017.
SPS had 833 bargaining employees covered under a collective-bargaining agreement, which expired in October 2014. While
collective bargaining is ongoing, the terms and conditions of the expired agreement are automatically extended.
•
•
The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which
establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring fair value. The three levels in
the hierarchy and examples of each level are as follows:
Level 1 — Quoted prices are available in active markets for identical assets as of the reporting date. The types of assets
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 included in Level 2 are typically either comparable to actively traded securities or
contracts, or priced with models using highly observable inputs.
Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets included in
Level 3 are those with inputs requiring significant management judgment or estimation.
Specific valuation methods include the following:
Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are
measured using quoted NAVs.
Insurance contracts — Insurance contract fair values take into consideration the value of the investments in separate accounts of the
insurer, which are priced based on observable inputs.
Investments in commingled funds, 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, which take into consideration the value of underlying fund
investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value. The
investments in commingled funds may be redeemed for net asset value with proper notice. Proper notice varies by fund and can range
from daily with a few days’ notice to annually with 90 days’ notice. Private equity 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. Depending on the fund,
unscheduled distributions from real estate investments may require approval of the fund or may be redeemed with proper notice,
which is typically quarterly with 45-90 days’ notice; however, withdrawals from real estate investments 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.
Derivative Instruments — Fair values for foreign currency derivatives are determined using pricing models based on the prevailing
forward exchange rate of the underlying currencies. The fair values of interest rate derivatives are based on broker quotes that utilize
current market interest rate forecasts.
105
Pension 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, the employee’s average pay and, in some cases, social security benefits. Xcel Energy’s policy is
to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting
purposes, subject to the limitations of applicable employee benefit and tax laws.
In addition to the qualified pension plans, Xcel Energy maintains a supplemental executive retirement plan (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. The nonqualified pension plan provides unfunded, nonqualified 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. The
total obligations of the SERP and nonqualified plan as of Dec. 31, 2016 and 2015 were $43.5 million and $41.8 million, respectively.
In 2016 and 2015, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $7.9 million
and $9.5 million, respectively.
In 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of the SERP and its deferred
compensation plan, supplemented by Xcel Energy’s consolidated operating cash flows as determined necessary. For more information
regarding the funding of rabbi trusts, see Note 11 to the consolidated financial statements. Also in 2016, Xcel Energy amended the
deferred compensation plan to provide eligible participants the ability to diversify deferred settlements of equity awards, other than
time-based equity awards, into various fund options.
Xcel Energy bases the investment-return assumption on expected long-term performance for each of the investment types included in
its pension asset portfolio. Xcel Energy considers the historical returns achieved by its asset portfolio over the past 20-year or longer
period, as well as the long-term return levels projected and recommended by investment experts. Xcel Energy continually reviews its
pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long-term.
•
•
•
•
Investment returns in 2016 were below the assumed level of 6.87 percent;
Investment returns in 2015 were below the assumed level of 7.09 percent;
Investment returns in 2014 were above the assumed level of 7.05 percent; and
In 2017, Xcel Energy’s expected investment-return assumption is 6.87 percent.
The 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 the necessity of contributions to the plan, within appropriate levels of risk. The principal
mechanism for achieving these objectives is the projected allocation of assets to selected asset classes, given the long-term risk, return,
and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry,
index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by
pension assets in any year.
The following table presents the target pension asset allocations for Xcel Energy at Dec. 31 for the upcoming year:
Domestic and international equity securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-duration fixed income and interest rate swap securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Short-to-intermediate fixed income securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Alternative investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016
2015
38%
27
16
17
2
100%
39%
27
13
19
2
100%
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. The aggregate projected asset
allocation presented in the table above for the master pension trust results from the plan-specific strategies.
106
Pension Plan Assets
The following tables present, for each of the fair value hierarchy levels, Xcel Energy’s pension plan assets that are measured at fair
value as of Dec. 31, 2016 and 2015:
Dec. 31, 2016
Level 1
Level 2
Level 3
Investments
Measured at
NAV (a)
Total
$
112,515
$
— $
— $
— $
112,515
(Thousands of Dollars)
Cash equivalents. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commingled funds:
U.S. equity funds. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non U.S. equity funds. . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. corporate bond funds. . . . . . . . . . . . . . . . . . . . . . .
Emerging market equity funds . . . . . . . . . . . . . . . . . . .
Emerging market debt funds . . . . . . . . . . . . . . . . . . . . .
Commodity funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Private equity investments . . . . . . . . . . . . . . . . . . . . . .
Real estate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other commingled funds. . . . . . . . . . . . . . . . . . . . . . . .
Debt securities:
Government securities. . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. corporate bonds. . . . . . . . . . . . . . . . . . . . . . . . . . .
Non U.S. corporate bonds . . . . . . . . . . . . . . . . . . . . . . .
Mortgage-backed securities . . . . . . . . . . . . . . . . . . . . .
Asset-backed securities . . . . . . . . . . . . . . . . . . . . . . . . .
Equity securities:
—
—
—
—
—
—
—
—
—
363,386
238,077
38,218
6,119
2,898
—
3,238
651,936
—
—
—
—
—
—
—
—
—
—
—
—
—
—
490,919
368,866
268,017
194,495
163,586
21,275
100,877
183,608
210,252
—
—
—
—
—
490,919
368,866
268,017
194,495
163,586
21,275
100,877
183,608
210,252
363,386
238,077
38,218
6,119
2,898
—
—
— $
—
—
2,001,895
$
89,467
3,238
2,855,813
$
U.S. equities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
89,467
—
201,982
$
(a)
Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy.
See Note 2 for further information on the adoption of ASU No. 2015-07.
(Thousands of Dollars)
Cash equivalents. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commingled funds:
U.S. equity funds. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non U.S. equity funds. . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. corporate bond funds. . . . . . . . . . . . . . . . . . . . . . .
Emerging market equity funds . . . . . . . . . . . . . . . . . . .
Emerging market debt funds . . . . . . . . . . . . . . . . . . . . .
Commodity funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Private equity investments . . . . . . . . . . . . . . . . . . . . . .
Real estate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other commingled funds. . . . . . . . . . . . . . . . . . . . . . . .
Debt securities:
Government securities. . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. corporate bonds. . . . . . . . . . . . . . . . . . . . . . . . . . .
Non U.S. corporate bonds . . . . . . . . . . . . . . . . . . . . . . .
Asset-backed securities . . . . . . . . . . . . . . . . . . . . . . . . .
Equity securities:
Dec. 31, 2015
Level 1
Level 2
Level 3
Investments
Measured at
NAV (a)
Total
$
178,884
—
$
— $
2,850
— $
—
— $
—
178,884
2,850
—
—
—
—
—
—
—
—
—
412,932
213,972
34,467
2,446
—
3,001
669,668
$
—
—
—
—
—
—
—
—
—
—
—
—
—
392,738
377,334
237,370
172,116
166,222
52,132
126,396
200,835
216,254
—
—
—
—
392,738
377,334
237,370
172,116
166,222
52,132
126,396
200,835
216,254
412,932
213,972
34,467
2,446
—
—
— $
—
—
1,941,397
$
93,831
3,001
2,883,780
U.S. equities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
93,831
—
272,715
$
(a)
Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy.
See Note 2 for further information on the adoption of ASU No. 2015-07.
107
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2016, 2015 or 2014.
Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for Xcel Energy is
presented in the following table:
(Thousands of Dollars)
Accumulated Benefit Obligation at Dec. 31. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2016
3,488,758
Change in Projected Benefit Obligation:
Obligation at Jan. 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plan amendments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actuarial loss (gain). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefit payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Obligation at Dec. 31. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(Thousands of Dollars)
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Actual return (loss) on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employer contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefit payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value of plan assets at Dec. 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
3,567,927
91,739
160,102
1,922
185,469
(325,541)
3,681,618
2016
2,883,780
172,359
125,215
(325,541)
2,855,813
2015
3,368,239
3,746,752
99,311
148,524
—
(169,678)
(256,982)
3,567,927
2015
3,083,771
(33,102)
90,093
(256,982)
2,883,780
$
$
$
$
$
(Thousands of Dollars)
Funded Status of Plans at Dec. 31:
Funded status (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2016
2015
(825,805) $
(684,147)
(a)
Amounts are recognized in noncurrent liabilities on Xcel Energy’s consolidated balance sheets.
(Thousands of Dollars)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Prior service credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(Thousands of Dollars)
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net-of-tax accumulated OCI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2016
2015
1,835,966
(5,232)
1,830,734
2016
101,426
1,649,482
31,032
48,794
1,830,734
$
$
$
$
1,710,097
(9,073)
1,701,024
2015
105,426
1,520,975
29,002
45,621
1,701,024
Measurement date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dec. 31, 2016 Dec. 31, 2015
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected average long-term increase in compensation level . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mortality table . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016
2015
4.13%
3.75
RP-2014
4.66%
4.00
RP-2014
108
Mortality — In 2014, the Society of Actuaries published a new mortality table (RP-2014) and projection scale (MP-2014) that
increased the overall life expectancy of males and females. On Dec. 31, 2014 Xcel Energy adopted the RP-2014 table, with
modifications, based on its population and specific experience and a modified MP-2014 projection scale. During 2016, a new
projection table was released (MP-2016). In 2016, Xcel Energy adopted a modified version of the MP-2016 table and will continue to
utilize the RP-2014 base table, modified for company experience.
Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other
calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were
made in 2014 through 2017 to meet minimum funding requirements.
Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:
•
•
•
•
$150.0 million in January 2017;
$125.2 million in 2016;
$90.1 million in 2015; and
$130.6 million in 2014.
For future years, Xcel Energy anticipates contributions will be made as necessary.
Plan Amendments — The 2016 increase in the projected benefit obligation resulted from a change in the discount rate basis for lump
sum conversion to annuity participants and annuity conversion to lump sum participants in the Xcel Energy Pension Plan.
Additionally, the annual credits contributed to the PSCo Bargaining Plan retirement spending account increased. In 2015, there were
no plan amendments made which affected the projected benefit obligation.
Benefit Costs — The components of Xcel Energy’s net periodic pension cost were:
(Thousands of Dollars)
Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of prior service credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net periodic pension cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Costs not recognized due to effects of regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net benefit cost recognized for financial reporting. . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016
91,739
160,102
(210,299)
(1,919)
97,539
137,162
(15,459)
121,703
2015
99,311
148,524
(213,890)
(1,805)
125,152
157,292
(29,633)
127,659
$
$
$
$
2014
88,342
156,619
(207,205)
(1,746)
116,762
152,772
(26,315)
126,457
$
$
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. . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016
2015
2014
4.66%
4.00
6.87
4.11%
3.75
7.09
4.75%
3.75
7.05
Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan.
The return assumption used for 2017 pension cost calculations is 6.87 percent.
Defined Contribution Plans
Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees. Total expense to these
plans was approximately $35.8 million in 2016, $34.1 million in 2015 and $32.4 million in 2014.
Postretirement Health Care Benefits
Xcel Energy has a contributory health and welfare benefit plan that provides health care and death benefits to certain Xcel Energy
retirees.
• NSP-Minnesota and NSP-Wisconsin discontinued contributing toward health care benefits for nonbargaining employees
retiring after 1998 and for bargaining employees who retired after 1999.
• Xcel Energy discontinued contributing toward health care benefits for PSCo and SPS, nonbargaining employees retiring after
June 30, 2003.
• Employees of NCE who retired in 2002 continue to receive employer-subsidized health care benefits.
109
• Nonbargaining employees of the former NCE who retired after 1998, bargaining employees of the former NCE who retired
after 1999 and nonbargaining employees of NCE who retired after June 30, 2003, are eligible to participate in the Xcel
Energy health care program with no employer subsidy.
Plan Assets — Certain state agencies that regulate Xcel Energy Inc.’s utility subsidiaries also have issued guidelines related to the
funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico jurisdictional
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.
The following table presents the target postretirement asset allocations for Xcel Energy at Dec. 31 for the upcoming year:
Domestic and international equity securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Short-to-intermediate fixed income securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Alternative investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016
2015
25%
57
13
5
100%
25%
57
13
5
100%
Xcel Energy bases its investment-return assumption for the postretirement health care fund assets on expected long-term performance
for each of the investment types included in its asset portfolio. The 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 the necessity of
contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected
allocation of assets to selected asset classes, given the long-term risk, return, correlation and liquidity characteristics of each particular
asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact
even well-diversified portfolios and significantly affect the return levels achieved by postretirement health care assets in any year.
The following tables present, for each of the fair value hierarchy levels, Xcel Energy’s postretirement benefit plan assets that are
measured at fair value as of Dec. 31, 2016 and 2015:
(Thousands of Dollars)
Cash equivalents. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Insurance contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commingled funds:
U.S. equity funds . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.S fixed income funds . . . . . . . . . . . . . . . . . . . . . . .
Emerging market debt funds . . . . . . . . . . . . . . . . . . .
Other commingled funds . . . . . . . . . . . . . . . . . . . . . .
Debt securities:
Government securities . . . . . . . . . . . . . . . . . . . . . . . .
U.S. corporate bonds . . . . . . . . . . . . . . . . . . . . . . . . .
Non U.S. corporate bonds . . . . . . . . . . . . . . . . . . . . .
Asset-backed securities . . . . . . . . . . . . . . . . . . . . . . .
Mortgage-backed securities. . . . . . . . . . . . . . . . . . . .
Equity securities:
Dec. 31, 2016
Level 1
Level 2
Level 3
Investments
Measured at
NAV (a)
$
20,545
—
— $
47,233
— $
—
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
37,745
62,317
17,281
18,922
28,717
—
—
—
—
—
—
—
—
—
54,440
27,109
30,431
54,957
—
—
—
—
—
Total
20,545
47,233
54,440
27,109
30,431
54,957
37,745
62,317
17,281
18,922
28,717
Non U.S. equities. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
40,960
—
61,505
$
—
1,448
213,663
$
—
—
— $
—
—
166,937
$
40,960
1,448
442,105
(a)
Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy.
See Note 2 for further information on the adoption of ASU No. 2015-07.
110
Dec. 31, 2015
Level 1
Level 2
Level 3
Investments
Measured at
NAV (a)
Total
19,638
—
$
— $
47,205
— $
—
— $
—
19,638
47,205
(Thousands of Dollars)
Cash equivalents. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Insurance contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commingled funds:
U.S. equity funds . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non U.S. equity funds . . . . . . . . . . . . . . . . . . . . . . . .
U.S fixed income funds . . . . . . . . . . . . . . . . . . . . . . .
Emerging market equity funds . . . . . . . . . . . . . . . . .
Emerging market debt funds . . . . . . . . . . . . . . . . . . .
Other commingled funds . . . . . . . . . . . . . . . . . . . . . .
Debt securities:
—
—
—
—
—
—
—
—
—
—
—
—
Government securities . . . . . . . . . . . . . . . . . . . . . . . .
U.S. corporate bonds . . . . . . . . . . . . . . . . . . . . . . . . .
Non U.S. corporate bonds . . . . . . . . . . . . . . . . . . . . .
Asset-backed securities . . . . . . . . . . . . . . . . . . . . . . .
Mortgage-backed securities. . . . . . . . . . . . . . . . . . . .
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
—
—
—
—
—
—
19,638
$
39,241
59,879
12,997
28,691
35,612
(412)
223,213
$
—
—
—
—
—
—
—
—
—
—
—
—
— $
38,202
33,596
24,248
11,096
35,667
61,973
—
—
—
—
—
—
204,782
$
38,202
33,596
24,248
11,096
35,667
61,973
39,241
59,879
12,997
28,691
35,612
(412)
447,633
(a)
Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy.
See Note 2 for further information on the adoption of ASU No. 2015-07.
There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2016, 2015 or 2014.
Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for Xcel Energy is presented in
the following table:
(Thousands of Dollars)
Change in Projected Benefit Obligation:
Obligation at Jan. 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Medicare subsidy reimbursements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plan participants’ contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actuarial loss (gain). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefit payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Obligation at Dec. 31. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(Thousands of Dollars)
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Actual return (loss) on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plan participants’ contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employer contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefit payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value of plan assets at Dec. 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2016
2015
584,267
1,727
26,107
2,058
6,896
32,954
(50,925)
603,084
2016
447,633
20,555
6,896
17,946
(50,925)
442,105
$
$
$
$
642,869
2,116
25,297
1,958
6,718
(45,793)
(48,898)
584,267
2015
475,058
(3,570)
6,718
18,325
(48,898)
447,633
(Thousands of Dollars)
Funded Status of Plans at Dec. 31:
Funded status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncurrent assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncurrent liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Net postretirement amounts recognized on consolidated balance sheets . . . . . . . . . . . . . . . . . . . $
2016
2015
(160,979) $
437
(6,395)
(155,021)
(160,979) $
(136,634)
1,820
(7,495)
(130,959)
(136,634)
111
(Thousands of Dollars)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Prior service credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(Thousands of Dollars)
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 OCI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2016
2015
136,391
(54,239)
82,152
2016
247
90,990
(1,004)
(14,221)
2,387
3,753
82,152
$
$
$
$
103,039
(64,925)
38,114
2015
352
50,135
(985)
(16,916)
2,148
3,380
38,114
Measurement date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dec. 31, 2016 Dec. 31, 2015
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mortality table . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Health care costs trend rate — initial . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016
2015
4.13%
RP 2014
5.50%
4.65%
RP 2014
6.00%
Effective Jan. 1, 2017, the initial medical trend rate was decreased from 6.0 percent to 5.5 percent. The ultimate trend assumption
remained at 4.5 percent. The period until the ultimate rate is reached is two years. 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 increases experienced by Xcel Energy’s retiree medical plan.
A one-percent change in the assumed health care cost trend rate would have the following effects on Xcel Energy:
(Thousands of Dollars)
APBO. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Service and interest components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
One-Percentage Point
Increase
Decrease
$
57,329
2,926
(48,831)
(2,477)
Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related
regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional
cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Xcel Energy contributed $17.9
million during 2016, $18.3 million during 2015, $17.1 million during 2014 and expects to contribute approximately $11.8 million
during 2017.
Plan Amendments — In 2016 and 2015, there were no plan amendments made which affected the benefit obligation.
Benefit Costs — The components of Xcel Energy’s net periodic postretirement benefit costs were:
(Thousands of Dollars)
Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of prior service credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net periodic postretirement benefit (credit) cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2016
2015
2014
$
1,727
26,107
(24,995)
(10,686)
4,042
(3,805) $
$
2,116
25,297
(26,600)
(10,686)
5,404
(4,469) $
3,457
34,028
(33,954)
(10,688)
11,740
4,583
112
Significant Assumptions Used to Measure Costs:
Discount rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected average long-term rate of return on assets. . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016
2015
2014
4.65%
5.80
4.08%
5.80
4.82%
7.17
Projected Benefit Payments
The following table lists Xcel Energy’s projected benefit payments for the pension and postretirement benefit plans:
(Thousands of Dollars)
2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2022-2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Projected
Pension Benefit
Payments
276,123
260,252
266,823
270,677
270,119
1,321,308
Gross Projected
Postretirement
Health Care
Benefit Payments
49,245
$
48,322
47,497
47,640
46,865
215,956
Expected
Medicare Part D
Subsidies
$
2,245
2,371
2,485
2,575
2,672
14,750
Net Projected
Postretirement
Health Care
Benefit Payments
47,000
$
45,951
45,012
45,065
44,193
201,206
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, including electrical workers, boilermakers, and other construction and facilities workers who may perform services for
more than one employer during a given period 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.
Contributions to multiemployer plans were as follows for the years ended Dec. 31, 2016, 2015 and 2014. The average number of
NSP-Minnesota union employees covered by the multiemployer pension plans decreased to approximately 700 in 2016 from 900 in
2015. There were no other significant changes to the nature or magnitude of the participation of NSP-Minnesota and NSP-Wisconsin
in multiemployer plans for the years presented:
(Thousands of Dollars)
Multiemployer pension contributions:
2016
2015
2014
NSP-Minnesota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
NSP-Wisconsin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
13,843
707
14,550
Multiemployer other postretirement benefit contributions:
NSP-Minnesota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
86
86
$
$
$
$
17,223
944
18,167
135
135
$
$
$
$
20,254
156
20,410
273
273
113
10. Other Income, Net
Other income, net for the years ended Dec. 31 consisted of the following:
(Thousands of Dollars)
Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other nonoperating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Insurance policy expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2016
2015
2014
8,342
2,981
(3,373)
7,950
$
$
5,737
3,514
(3,851)
5,400
$
$
7,353
4,866
(6,923)
5,296
11. Fair Value of Financial Assets and Liabilities
Fair Value Measurements
The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain
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. The three levels in the hierarchy are as follows:
Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types
of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.
Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of
the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded
securities or contracts, or priced with models using highly observable inputs.
Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and
liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.
Specific valuation methods include the following:
Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are
measured using quoted NAVs.
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, which take into consideration the value of underlying fund investments, as well as
the other accrued assets and liabilities of a fund, in order to determine a per-share market value. The investments in commingled
funds may be redeemed for NAV with proper notice. Proper notice varies by fund and can range from daily with one or two days
notice to annually with 90 days notice. Private equity 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 investments
may be redeemed with proper notice, which is typically quarterly with 45-90 days notice; however, withdrawals from real estate
investments 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 — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest
rate forecasts.
114
Commodity derivatives — The 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. When
contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance
of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level
3 classification.
Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments, generally referred to as FTRs,
purchased from MISO. Electric commodity derivatives held by SPS include FTRs purchased from SPP. 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 energy congestion, which is caused
by overall transmission load and other transmission constraints. 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. The
valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of
transmission system congestion on the historical pricing of FTR purchases.
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 management’s forecasts for several of the inputs to
this complex valuation model – 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 to the
complex model used for valuation of FTRs are insignificant to the consolidated financial statements of Xcel Energy.
Non-Derivative Instruments Fair Value Measurements
The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating
plants. Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the
purpose of decommissioning the Monticello and PI nuclear generating plants. The fund contains cash equivalents, debt securities,
equity securities and other investments – all classified as available-for-sale. NSP-Minnesota plans to reinvest matured securities until
decommissioning begins. 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 of its nuclear generating plants over the lives of the plants,
assuming rate recovery of all costs. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets,
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, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for
nuclear decommissioning.
Unrealized gains for the nuclear decommissioning fund were $378.6 million and $328.8 million at Dec. 31, 2016 and 2015,
respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $46.9 million and $100.2 million
at Dec. 31, 2016 and 2015, respectively.
115
The following tables present the cost and fair value of Xcel Energy’s non-derivative instruments with recurring fair value
measurements in the nuclear decommissioning fund at Dec. 31, 2016 and 2015:
(Thousands of Dollars)
Nuclear decommissioning fund (a)
Cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commingled funds:
Non U.S. equities . . . . . . . . . . . . . . . . . . . . . . . . . .
Emerging market debt funds . . . . . . . . . . . . . . . . . .
Commodity funds . . . . . . . . . . . . . . . . . . . . . . . . . .
Private equity investments . . . . . . . . . . . . . . . . . . .
Real estate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other commingled funds. . . . . . . . . . . . . . . . . . . . .
Debt securities:
Government securities. . . . . . . . . . . . . . . . . . . . . . .
U.S. corporate bonds . . . . . . . . . . . . . . . . . . . . . . . .
Non U.S. corporate bonds . . . . . . . . . . . . . . . . . . . .
Municipal bonds . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mortgage-backed securities. . . . . . . . . . . . . . . . . . .
Equity securities:
Dec. 31, 2016
Fair Value
Cost
Level 1
Level 2
Level 3
Investments
Measured at
NAV (b)
Total
$
20,379
$
20,379
$
— $
— $
— $
20,379
260,877
93,597
106,571
132,190
128,630
151,048
32,764
104,913
21,751
13,609
2,785
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
31,965
105,772
21,672
13,786
2,816
—
—
176,011
—
—
—
—
—
—
—
—
—
—
—
245,359
97,543
92,091
190,462
187,647
159,489
—
—
—
—
—
245,359
97,543
92,091
190,462
187,647
159,489
31,965
105,772
21,672
13,786
2,816
—
—
— $
—
—
972,591
473,400
218,381
$ 1,860,762
$
U.S. equities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non U.S. equities . . . . . . . . . . . . . . . . . . . . . . . . . .
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
270,779
189,100
$ 1,528,993
$
473,400
218,381
712,160
$
(a)
(b)
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $132.8 million of equity investments in
unconsolidated subsidiaries and $98.3 million of miscellaneous investments.
Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note
2 for further information on the adoption of ASU No. 2015-07.
(Thousands of Dollars)
Nuclear decommissioning fund (a)
Cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commingled funds:
Non U.S. equities . . . . . . . . . . . . . . . . . . . . . . . . . .
Emerging market debt funds . . . . . . . . . . . . . . . . . .
Commodity funds . . . . . . . . . . . . . . . . . . . . . . . . . .
Private equity investments . . . . . . . . . . . . . . . . . . .
Real estate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other commingled funds. . . . . . . . . . . . . . . . . . . . .
Debt securities:
Government securities. . . . . . . . . . . . . . . . . . . . . . .
U.S. corporate bonds . . . . . . . . . . . . . . . . . . . . . . . .
Non U.S. corporate bonds . . . . . . . . . . . . . . . . . . . .
Municipal bonds . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset-backed securities . . . . . . . . . . . . . . . . . . . . . .
Mortgage-backed securities. . . . . . . . . . . . . . . . . . .
Equity securities:
Dec. 31, 2015
Fair Value
Cost
Level 1
Level 2
Level 3
Investments
Measured at
NAV (b)
Total
$
27,484
$
27,484
$
— $
— $
— $
27,484
259,114
88,987
99,771
105,965
115,019
150,877
24,444
73,061
13,726
49,255
2,837
11,444
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
21,356
65,276
12,801
51,589
2,830
11,621
—
—
—
—
—
—
—
—
—
—
—
—
231,122
88,467
77,338
157,528
165,190
164,389
—
—
—
—
—
—
231,122
88,467
77,338
157,528
165,190
164,389
21,356
65,276
12,801
51,589
2,830
11,621
U.S. equities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non U.S. equities . . . . . . . . . . . . . . . . . . . . . . . . . .
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
273,106
200,509
$ 1,495,599
$
432,495
214,664
674,643
$
—
—
165,473
$
—
—
— $
—
—
884,034
432,495
214,664
$ 1,724,150
(a)
(b)
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $130.0 million of equity investments in
unconsolidated subsidiaries and $48.9 million of miscellaneous investments.
Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note
2 for further information on the adoption of ASU No. 2015-07.
For the year ended Dec. 31, 2016 and 2015 there were no Level 3 nuclear decommissioning fund investments and no transfers of
amounts between levels.
116
The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by
asset class, at Dec. 31, 2016:
(Thousands of Dollars)
Government securities . . . . . . . . . . . . . . .
U.S. corporate bonds . . . . . . . . . . . . . . . .
Non U.S. corporate bonds . . . . . . . . . . . .
Municipal bonds . . . . . . . . . . . . . . . . . . .
Mortgage-backed securities. . . . . . . . . . .
Debt securities. . . . . . . . . . . . . . . . . . . .
$
$
Rabbi Trusts
Due in 1 Year
or Less
Due in 1 to 5
Years
Due in 5 to 10
Years
Due after 10
Years
Total
Final Contractual Maturity
— $
608
—
—
—
608
$
9,158
28,375
6,477
205
—
44,215
$
$
149
67,475
10,525
5,763
—
83,912
$
$
22,658
9,314
4,670
7,818
2,816
47,276
$
$
31,965
105,772
21,672
13,786
2,816
176,011
In June 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of its supplemental executive
retirement plan and deferred compensation plan. The following table presents the cost and fair value of the assets held in rabbi trusts at
Dec. 31, 2016:
(Thousands of Dollars)
Rabbi Trusts (a)
Dec. 31, 2016
Fair Value
Cost
Level 1
Level 2
Level 3
Total
Cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Mutual funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
47,831
1,663
49,494
$
$
47,831
1,901
49,732
$
$
— $
—
— $
— $
—
— $
47,831
1,901
49,732
(a)
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
Rabbi trust assets at Dec. 31, 2015 were comprised only of an immaterial amount of mutual funds.
Derivative Instruments Fair Value Measurements
Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to
manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.
Interest Rate Derivatives — Xcel Energy enters into various instruments that effectively fix the 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.
At Dec. 31, 2016, accumulated other comprehensive losses related to interest rate derivatives included $3.4 million of net losses
expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings,
including forecasted amounts for unsettled hedges, as applicable.
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’s risk management policy allows management to conduct these activities within guidelines and
limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the
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.
117
Xcel Energy enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but
are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are
recorded in OCI or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on
commission approved regulatory recovery mechanisms. Xcel Energy recorded immaterial amounts to income related to the
ineffectiveness of cash flow hedges for the years ended Dec. 31, 2016 and 2015.
Additionally, 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.
The following table details the gross notional amounts of commodity forwards, options and FTRs at Dec. 31:
(Amounts in Thousands) (a)(b)
MWh of electricity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MMBtu of natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gallons of vehicle fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016
2015
46,773
121,978
—
50,487
20,874
141
(a)
(b)
Amounts are not reflective of net positions in the underlying commodities.
Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.
Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of the 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. Given this assessment, as well as an assessment of the impact of Xcel Energy’s own
credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair
value of unsettled commodity derivatives presented in the consolidated balance sheets.
Xcel Energy Inc. and its subsidiaries employ additional credit risk control mechanisms when appropriate, such as letters of credit,
parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and
negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit
enhancement is provided.
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. At Dec. 31, 2016, one of Xcel Energy’s 10 most
significant counterparties for these activities, comprising $13.4 million or 6 percent of this credit exposure, had investment grade
credit ratings from S&P’s, Moody’s or Fitch Ratings. Nine of the 10 most significant counterparties, comprising $77.5 million or 36
percent of this credit exposure, were not rated by these external agencies, but based on Xcel Energy’s internal analysis, had credit
quality consistent with investment grade. All ten of these significant counterparties are municipal or cooperative electric entities or
other utilities.
Financial Impact of Qualifying Cash Flow Hedges — The 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, is detailed in the following table:
2014
2016
2015
$ (54,862) $ (57,628) $ (59,753)
(163)
2,288
$ (51,151) $ (54,862) $ (57,628)
(70)
2,836
3
3,708
(Thousands of Dollars)
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 . . . . . . . . . . . .
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges . . . . . .
After-tax net realized losses on derivative transactions reclassified into earnings . . . . . . . . .
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 . . . . . . . . . . .
118
The following tables detail the impact of derivative activity during the years ended Dec. 31, 2016, 2015 and 2014, on accumulated
other comprehensive loss, regulatory assets and liabilities, and income:
Pre-Tax Fair Value
Gains Recognized
During the Period in:
Year Ended Dec. 31, 2016
Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from:
Accumulated
Other
Comprehensive
Loss
Regulatory
(Assets) and
Liabilities
Accumulated
Other
Comprehensive
Loss
Regulatory
Assets and
(Liabilities)
Pre-Tax Gains
(Losses)
Recognized
During the Period
in Income
(Thousands of Dollars)
Derivatives designated as cash
flow hedges
Interest rate . . . . . . . . . . . . . . . . . $
Vehicle fuel and other
commodity. . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . .
$
Other derivative instruments
Commodity trading . . . . . . . . . . . $
Electric commodity . . . . . . . . . . .
Natural gas commodity . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . .
$
— $
5
5
$
— $
—
—
— $
— $
—
— $
— $
17,437
621
18,058
$
(a)
5,859
191 (b)
6,050
—
—
—
—
$
$
$
$
—
—
—
—
(8,147)
14,879
6,732
(d)
(e)
$
$
$
$
—
—
—
(c)
(e)
2,568
—
(8,252)
(5,684)
Pre-Tax Fair Value
Losses Recognized
During the Period in:
Year Ended Dec. 31, 2015
Pre-Tax Losses
Reclassified into Income
During the Period from:
Accumulated
Other
Comprehensive
Loss
Regulatory
(Assets) and
Liabilities
Accumulated
Other
Comprehensive
Loss
Regulatory
Assets and
(Liabilities)
Pre-Tax Losses
Recognized
During the Period
in Income
(Thousands of Dollars)
Derivatives designated as cash
flow hedges
Interest rate . . . . . . . . . . . . . . . . . $
Vehicle fuel and other
commodity. . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . .
$
Other derivative instruments
Commodity trading . . . . . . . . . . . $
Electric commodity . . . . . . . . . . .
Natural gas commodity . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . .
$
— $
(116)
(116)
$
— $
—
—
— $
— $
—
— $
— $
(18,543)
(16,163)
(34,706)
$
(a)
4,515
131 (b)
4,646
—
—
—
—
$
$
$
$
—
—
—
—
16,338
15,694
32,032
(d)
(e)
$
$
$
$
—
—
—
(c)
(e)
(7,286)
—
(11,840)
(19,126)
119
Year Ended Dec. 31, 2014
Pre-Tax Fair Value
Gains (Losses) Recognized
During the Period in:
Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from:
Accumulated
Other
Comprehensive
Loss
Regulatory
(Assets) and
Liabilities
Accumulated
Other
Comprehensive
Loss
Regulatory
Assets and
(Liabilities)
Pre-Tax Gains
(Losses)
Recognized
During the Period
in Income
(Thousands of Dollars)
Derivatives designated as cash
flow hedges
Interest rate . . . . . . . . . . . . . . . . . $
Vehicle fuel and other
commodity. . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . .
$
Other derivative instruments
Commodity trading . . . . . . . . . . . $
Electric commodity . . . . . . . . . . .
Natural gas commodity . . . . . . . .
Other commodity . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . .
$
— $
(266)
(266)
$
— $
—
—
—
— $
— $
—
— $
— $
(8,306)
5,166
—
(3,140)
$
(a)
3,836
(55) (b)
3,781
—
—
—
—
—
$
$
$
$
—
—
—
(d)
(e)
—
(9,036)
(13,997)
—
(23,033)
$
$
$
$
—
—
—
(c)
(e)
(c)
881
—
(13,220)
643
(11,696)
(a)
(b)
(c)
(d)
(e)
Amounts are recorded to interest charges.
Amounts are recorded to O&M expenses.
Amounts are 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 are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and
purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.
Amounts for the years ended Dec. 31, 2016 and Dec. 31, 2015 included $0.2 million and $1.1 million of settlement losses on derivatives entered to mitigate
natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory
asset, as appropriate. Such losses for the years ended Dec. 31, 2014 were immaterial. The remaining settlement losses for the years ended Dec. 31, 2016, 2015
and 2014 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and
reclassified out of income to a regulatory asset, as appropriate.
Xcel Energy had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2016, 2015 and 2014.
Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.
Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including
those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale contracts
and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons,
including if the applicable utility subsidiary is unable to maintain its credit ratings. At Dec. 31, 2016 and 2015, there were no
derivative instruments in a liability position with underlying contract provisions that required the posting of collateral or settlement of
applicable outstanding contracts if the credit ratings of Xcel Energy Inc.’s utility subsidiaries were downgraded below investment
grade.
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, 2016 and 2015.
120
Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, Xcel Energy’s
derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2016:
(Thousands of Dollars)
Current derivative assets
Other derivative instruments:
Commodity trading. . . . . . . . . . . . . . . . . . . . . . . . . .
Electric commodity. . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas commodity. . . . . . . . . . . . . . . . . . . . . . .
Total current derivative assets. . . . . . . . . . . . . . .
PPAs (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current derivative instruments . . . . . . . . . . . . . .
Noncurrent derivative assets
Other derivative instruments:
Commodity trading. . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas commodity. . . . . . . . . . . . . . . . . . . . . . .
Total noncurrent derivative assets. . . . . . . . . . . .
PPAs (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncurrent derivative instruments . . . . . . . . . . .
(Thousands of Dollars)
Current derivative liabilities
Other derivative instruments:
Commodity trading. . . . . . . . . . . . . . . . . . . . . . . . . .
Electric commodity. . . . . . . . . . . . . . . . . . . . . . . . . .
Total current derivative liabilities . . . . . . . . . . . .
PPAs (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current derivative instruments . . . . . . . . . . . . . .
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading. . . . . . . . . . . . . . . . . . . . . . . . . .
Total noncurrent derivative liabilities . . . . . . . . .
PPAs (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncurrent derivative instruments . . . . . . . . . . .
$
$
$
$
$
$
$
$
Fair Value
Level 1
Level 2
Level 3
Fair Value
Total
Counterparty
Netting (b)
Total
Dec. 31, 2016
13,179
—
—
13,179
100
—
100
$
$
$
$
14,105
—
8,839
22,944
31,029
1,652
32,681
$
$
$
$
— $
19,251
—
19,251
$
27,284
19,251
8,839
55,374
— $
—
— $
31,129
1,652
32,781
Dec. 31, 2016
$
$
$
$
(20,637) $
(1,976)
—
(22,613)
$
(7,323) $
—
(7,323)
$
6,647
17,275
8,839
32,761
5,463
38,224
23,806
1,652
25,458
24,731
50,189
Fair Value
Level 1
Level 2
Level 3
Fair Value
Total
Counterparty
Netting (b)
Total
13,787
—
13,787
$
$
11,320
—
11,320
$
$
22
1,976
1,998
$
$
25,129
1,976
27,105
$
$
(20,974) $
(1,976)
(22,950)
$
89
89
$
$
23,424
23,424
$
$
— $
— $
23,513
23,513
$
$
(10,727) $
(10,727)
$
4,155
—
4,155
22,804
26,959
12,786
12,786
135,360
148,146
(a)
(b)
In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term
PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery
mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. 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.
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 at Dec. 31, 2016. At Dec. 31, 2016, derivative assets and
liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $3.7 million. The counterparty netting amounts presented exclude
settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
121
6,230
17,333
193
23,756
10,086
33,842
20,861
20,861
30,222
51,083
The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair
value on a recurring basis at Dec. 31, 2015:
Level 1
Fair Value
Level 2
Level 3
Fair Value
Total
Counterparty
Netting (b)
Total
Dec. 31, 2015
(Thousands of Dollars)
Current derivative assets
Other derivative instruments:
Commodity trading. . . . . . . . . . . . . . . . . . . . . . . . . .
Electric commodity. . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas commodity. . . . . . . . . . . . . . . . . . . . . . .
$
Total current derivative assets. . . . . . . . . . . . . . . . $
PPAs (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current derivative instruments . . . . . . . . . . . . . .
Noncurrent derivative assets
Other derivative instruments:
225
—
—
225
$
$
10,620
—
496
11,116
$
$
1,250
21,421
—
22,671
$
$
12,095
21,421
496
34,012
$
$
(5,865) $
(4,088)
(303)
(10,256)
$
Commodity trading. . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total noncurrent derivative assets. . . . . . . . . . . . . $
— $
— $
27,416
27,416
$
$
— $
— $
27,416
27,416
$
$
(6,555) $
(6,555)
PPAs (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncurrent derivative instruments . . . . . . . . . . .
$
(Thousands of Dollars)
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity . . . . . . . . . . . . . .
Other derivative instruments: . . . . . . . . . . . . . . . . . . .
Commodity trading. . . . . . . . . . . . . . . . . . . . . . . . . .
Electric commodity. . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas commodity. . . . . . . . . . . . . . . . . . . . . . .
Total current derivative liabilities . . . . . . . . . . . .
PPAs (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current derivative instruments . . . . . . . . . . . . . .
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading. . . . . . . . . . . . . . . . . . . . . . . . . .
Total noncurrent derivative liabilities . . . . . . . . .
PPAs (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncurrent derivative instruments . . . . . . . . . . .
$
$
$
$
Level 1
Fair Value
Level 2
Level 3
Fair Value
Total
Counterparty
Netting (b)
Total
Dec. 31, 2015
— $
205
$
— $
205
$
— $
205
152
—
—
152
$
7,866
—
5,407
13,478
$
555
4,088
—
4,643
$
8,573
4,088
5,407
18,273
$
(6,904)
(4,088)
(303)
(11,295)
$
— $
— $
19,898
19,898
$
$
— $
— $
19,898
19,898
$
$
(9,780) $
(9,780)
$
1,669
—
5,104
6,978
22,861
29,839
10,118
10,118
158,193
168,311
(a)
(b)
In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term
PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery
mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. 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.
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 at Dec. 31, 2015. At Dec. 31, 2015, derivative assets and
liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $4.3 million. The counterparty netting amounts presented exclude
settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
122
The following table presents the changes in Level 3 commodity derivatives for the years ended Dec. 31, 2016, 2015 and 2014:
(Thousands of Dollars)
Balance at Jan. 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers out of Level 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net transactions recorded during the period:
(Losses) gains recognized in earnings (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gains (losses) recognized as regulatory assets and liabilities . . . . . . . . . . . . . . .
Balance at Dec. 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
(a)
These amounts relate to commodity derivatives held at the end of the period.
Year Ended Dec. 31
2016
2015
$
18,028
35,593
(89,085)
—
(54)
52,771
17,253
$
$
56,155
63,712
(69,754)
—
1,533
(33,618)
18,028
$
2014
41,660
135,008
(145,974)
(1,093)
10,692
15,862
56,155
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 the years ended Dec. 31, 2016 and 2015. The transfer of amounts from Level 3 to Level 2 in the
year ended Dec. 31, 2014 was due to the valuation of certain long-term derivative contracts for which observable commodity pricing
forecasts became a more significant input during the period.
Fair Value of Long-Term Debt
As of Dec. 31, 2016 and 2015, other financial instruments for which the carrying amount did not equal fair value were as follows:
(Thousands of Dollars)
Long-term debt, including current portion (a) . . . . . . . . . . . . . . . . $ 14,450,247
Carrying
Amount
Fair Value
$ 15,513,209
Carrying
Amount
$ 13,055,901
Fair Value
$ 14,094,744
2016
2015
(a)
Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for
more information on the adoption of ASU No. 2015-03.
The 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. The fair value estimates are based on information available to management as of Dec. 31, 2016 and 2015,
and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.
12. Rate Matters
NSP-Minnesota
Pending and Recently Concluded Regulatory Proceedings — MPUC
Minnesota 2016 Multi-Year Electric Rate Case — In November 2015, NSP-Minnesota filed a three-year electric rate case with the
MPUC. The rate case is based on a requested ROE of 10.0 percent and a 52.50 percent equity ratio. In December 2015, the MPUC
approved interim rates for 2016. The request is detailed in the table below:
Request (Millions of Dollars)
Rate request . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Increase percentage. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interim request . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Rate base. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2016
2017
2018
194.6
6.4%
163.7
7,800
$
$
$
52.1
1.7%
44.9
7,700
$
$
50.4
1.7%
N/A
7,700
123
Settlement Agreement
In August 2016, NSP-Minnesota and various parties reached a settlement which resolves all revenue requirement issues in dispute.
The settlement agreement requires the approval of the MPUC.
Key terms of the settlement are listed below:
•
Four-year period covering 2016-2019;
• Annual sales true-up as detailed below:
•
•
•
2016 weather-normalized actuals used to set final 2016 rates, no cap;
2016-2019 full decoupling for residential and non-demand metered commercial classes with a 3 percent cap; and
2017-2019 annual true-up for non-decoupled classes with a 3 percent cap.
• ROE of 9.2 percent and an equity ratio of 52.5 percent;
• Nuclear related costs will not be considered provisional;
• Continued use of all existing riders, however no new riders may be utilized during the four-year term;
• Deferral of incremental 2016 property tax expense above a fixed threshold to 2018 and 2019;
Four-year stay out provision for rate cases;
•
•
Property tax true-up mechanism for 2017-2019; and
• Capital expenditure true-up mechanism for 2016-2019.
(Millions of Dollars, incremental)
Settlement revenues (a). . . . . . . . . . . . . . . . . . . . . .
NSP-Minnesota’s sales true-up . . . . . . . . . . . . . . . .
Total rate impact (b) . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2016
2017
2018
2019
Total
74.99
59.95
134.94
$
$
59.86
—
59.86
$
$
— $
—
— $
50.12
(0.20)
49.92
$
$
184.97
59.75
244.72
(a)
(b)
The settlement revenues are based on the DOC’s sales forecast.
The total rate impact reflects an increase of 4.62 percent in 2016; 2.05 percent in 2017; 0 percent in 2018 and 1.71 percent in 2019.
The schedule for the Minnesota rate case is listed below:
• ALJ report — March 3, 2017; and
• MPUC decision — June 2017.
A current liability that is consistent with the settlement and represents NSP-Minnesota’s best estimate of a refund obligation for 2016
associated with interim rates was recorded as of Dec. 31, 2016.
Monticello Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello LCM/EPU project. The multi-year project
extended the life of the facility and increased the capacity from 600 to 671 MW in 2015. The Monticello LCM/EPU project
expenditures were approximately $665 million. Total capitalized costs were approximately $748 million, which includes AFUDC. In
2008, project expenditures were initially estimated at approximately $320 million, excluding AFUDC.
In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent.
In March 2015, the MPUC voted to allow for full recovery, including a return, on $415 million of the total plant costs (inclusive of
AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the
remaining life of the plant. As a result of these determinations, Xcel Energy recorded an estimated pre-tax loss of $129 million in the
first quarter of 2015, after which the remaining book value of the Monticello project represented the present value of the estimated
future cash flows.
2016 TCR Filing — In January 2017, the MPUC issued an order approving NSP-Minnesota’s requested 2016 revenue requirements of
$78.4 million to recover costs for three CapX2020 projects and two additional projects.
124
Electric, Purchased Gas and Resource Adjustment Clauses
CIP and CIP Rider — CIP expenses are recovered through base rates and a rider that is adjusted annually. The estimated average
annual electric and natural gas incentives for 2016 are $30.6 million and $3.6 million, respectively, based on the approved savings
goals. The MPUC approved the following for NSP-Minnesota:
• A new CIP financial incentive mechanism for the 2017-2019 triennial period with an average forecasted incentive of $12.5
million for electric conservation and $1.8 million for gas conservation;
• The 2015 CIP electric and natural gas financial incentives totaling $43.3 million and $5.8 million, respectively; and
• This proposed 2016 electric and natural gas CIP riders with estimated 2016 recovers of $45.1 million of electric CIP expenses
and $15.4 million of natural gas CIP expenses. This proposed recovery through the riders is in addition to an estimated $90.2
million and $3.8 million through electric and gas base rates, respectively.
GUIC Rider — In 2016, NSP-Minnesota filed the GUIC rider with the MPUC for approval to recover the cost of natural gas
infrastructure investments in Minnesota to improve safety and reliability. Costs include funding for pipeline assessments as well as
deferred costs from NSP-Minnesota’s existing sewer separation and pipeline integrity management programs. NSP-Minnesota
requested recovery of approximately $22.1 million from Minnesota gas utility customers beginning April 1, 2017. An MPUC decision
is expected in the first half of 2017.
Annual Automatic Adjustment (AAA) of Charges — In 2016, the DOC recommended the MPUC should hold utilities responsible for
incremental costs of replacement power incurred due to unplanned outages at nuclear facilities under certain circumstances. The
DOC’s recommendation could impact replacement power cost recovery for the PI nuclear facility outages allocated to the Minnesota
jurisdiction during the AAA fiscal year ended June 30, 2015. NSP-Minnesota expects a MPUC decision in mid-2017.
NSP-Wisconsin
Recently Concluded Regulatory Proceedings — PSCW
Wisconsin 2017 Electric and Gas Rate Case — In April 2016, NSP-Wisconsin filed a request with the PSCW for an increase in
annual electric rates of $17.4 million, or 2.4 percent, and an increase in natural gas rates by $4.8 million, or 3.9 percent, effective
January 2017.
The electric rate request was for the limited purpose of recovering increases in (1) generation and transmission fixed charges and fuel
and purchased power expenses related to the interchange agreement with NSP-Minnesota, and (2) costs associated with forecasted
average rate base of $1.188 billion in 2017.
The natural gas rate request was for the limited purpose of recovering expenses related to the ongoing environmental remediation of a
former MGP site and adjacent area in Ashland, Wis.
No changes were requested to the capital structure or the 10.0 percent ROE authorized by the PSCW in the 2016 rate case. As part of
an agreement with stakeholders to limit the size and scope of the case, NSP-Wisconsin also agreed to an earnings cap, solely for 2017,
in which 100 percent of the earnings in excess of the authorized ROE would be refunded to customers.
125
In December 2016, the PSCW issued an order approving an electric rate increase of approximately $22.5 million, or 3.2 percent, and a
natural gas rate increase of $4.8 million, or 3.9 percent. The differences between NSP-Wisconsin’s original electric rate request and
the PSCW’s approved electric increase are summarized below:
Electric Rate Request (Millions of Dollars)
Rate base investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Generation and transmission expenses (excluding fuel and purchased power) (a) . . . . .
Fuel and purchased power expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015 fuel refund (b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Department of Energy settlement refund . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total electric rate increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
NSP-Wisconsin Request
11.0
6.8
11.0
28.8
(9.5)
(1.9)
17.4
$
Final Decision
7.6
6.1
10.7
24.4
—
(1.9)
22.5
(a)
(b)
Includes Interchange Agreement billings. For financial reporting purposes, these expenses are included in O&M.
In July 2016, the PSCW required NSP-Wisconsin to return the 2015 fuel refund directly to customers, rather than using it to offset the proposed 2017 rate
increase, as originally proposed by NSP-Wisconsin. This decision, when combined with the increase in forecasted fuel and purchased power expense, effectively
increased NSP-Wisconsin’s requested electric rate increase to $29.9 million, or 4.2 percent.
PSCo
Pending Regulatory Proceedings — CPUC
Annual Electric Earnings Test — As part of an annual earnings test, PSCo must share with customers earnings that exceed the
authorized ROE threshold of 9.83 percent for 2015 through 2017. The 2016 earnings test did not result in a material customer refund
obligation as of Dec. 31, 2016. PSCo will file its 2016 earnings test with the CPUC in April 2017. The final sharing obligation will
be based on the CPUC approved tariff and could vary from the current estimate.
Electric, Purchased Gas and Resource Adjustment Clauses
DSM and the DSMCA — Energy efficiency and DSM costs are recovered through a combination of the DSMCA riders and base
rates. DSMCA riders are adjusted biannually to capture program costs, performance incentives, and any over- or under-recoveries are
trued-up in the following year. Savings goals were 400 GWh in 2015 and 2016 with incentives awarded in the year following plan
achievements. PSCo is able to earn $5 million upon reaching its annual savings goal along with an incentive on five percent of net
economic benefits up to a maximum annual incentive of $30 million. For the years 2017 through 2020, the annual electric energy
savings goal is 400 GWh per year with an annual spending limit of $84.3 million.
In February 2017, the CPUC approved PSCo’s 2017-2018 DSM plan:
• A 2017 DSM electric budget of $80.4 million and a natural gas budget of $13.1 million; and
• A 2018 DSM electric budget of $77.7 million and a natural gas budget of $12.8 million.
REC Sharing — In 2011, the CPUC approved margin sharing on stand-alone REC transactions at 10 percent to PSCo and 90 percent
to customers for 2014. In 2012, the CPUC approved an annual margin sharing on the first $20 million of margins on hybrid REC
trades of 80 percent to the customers and 20 percent to PSCo. Margins in excess of the $20 million are to be shared 90 percent to the
customers and 10 percent to PSCo. The CPUC authorized PSCo to return to customers unspent carbon offset funds by crediting the
RESA regulatory asset balance. PSCo credited to the RESA regulatory liability balance approximately $5.8 million and $5.5 million
in 2016 and 2015, respectively. The cumulative credit to the RESA regulatory liability balance was $116.3 million and $110.6 million
at Dec. 31, 2016 and Dec. 31, 2015, respectively. The credits include the customers’ share of REC trading margins and the unspent
share of carbon offset funds. The current sharing mechanism, without modification, extends through Dec. 31, 2017.
126
SPS
Pending and Recently Concluded Regulatory Proceedings — PUCT
Appeal of the Texas 2015 Electric Rate Case Decision — In 2014, SPS had requested an overall retail electric revenue rate increase
of $64.8 million, which it subsequently revised to $42.1 million. In 2015, the PUCT approved an overall rate decrease of
approximately $4.0 million, net of rate case expenses. In April 2016, SPS filed an appeal, with the Texas State District Court, of the
PUCT’s order that had denied SPS’ request for rehearing on certain items in SPS’ Texas 2015 electric rate case related to capital
structure, incentive compensation and wholesale load reductions. A decision by the Texas State District Court is pending.
Texas 2016 Electric Rate Case — In February 2016, SPS filed a retail electric, base rate case in Texas with each of its Texas
municipalities and the PUCT requesting an overall increase in annual base rate revenue of approximately $71.9 million, or 14.4
percent. The filing is based on a historic test year ended Sept. 30, 2015, a requested ROE of 10.25 percent, an electric rate base of
approximately $1.7 billion, and an equity ratio of 53.97 percent. In September 2016, SPS revised its requested rate increase to $61.5
million and along with recovery of rate case expenses made for an overall revised request of $65.5 million.
In December 2016, SPS reached an unopposed settlement that resolves all issues in the rate case. The following table reflects the total
estimated impact:
(Millions of Dollars)
Base rate increase, retroactive to July 20, 2016. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Power factor revenues (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rate case expenses to be addressed in a separate proceeding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total estimated impact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Settlement
35.2
12.6
4.0
51.8
(a)
SPS’ request assumed customers would adjust their power factors, which would reduce revenue. To the extent power factor revenues are less than $12.6 million, a
mechanism will be established to ensure SPS recovers this amount and effectively offset lower anticipated power factor charges.
Additional key terms are as follows:
•
SPS’ next TCRF application will have a cap of $19 million in additional annual revenue and parties will make reasonable
efforts to obtain PUCT approval within 100 days of SPS’ initial filing;
• No disallowance of SPS’ requested capital additions; and
• No restrictions on filing future rate cases or rate riders.
Pursuant to legislation passed in Texas in 2015, the final rates established in the case will be effective retroactive to July 20, 2016. In
December 2016, an ALJ approved interim rates, effective as of Dec. 10, 2016. In the fourth quarter of 2016, SPS deferred certain
costs associated with this rate case. In January 2017, the PUCT approved the settlement and no refund of interim rates was necessary.
SPS expects to file a surcharge to recover the additional revenue associated with final rates, for the period of July 20, 2016 through
Dec. 9, 2016, by the third quarter of 2017.
Texas 2016 TCRF Application — In February 2017, SPS filed an application with the PUCT to recover additional annual revenue of
approximately $16.1 million through its TCRF, or 1.79 percent. The filing is based upon expenses and investments through Dec. 31,
2016. Based on the settlement agreement approved in the Texas 2016 electric rate case, SPS expects a PUCT decision and
implementation of TCRF rates by mid-2017.
Pending Regulatory Proceedings — NMPRC
New Mexico 2016 Electric Rate Case — In November 2016, SPS filed an electric rate case with the NMPRC for an increase in base
rates of approximately $41.4 million, representing a total revenue increase of approximately 10.9 percent. The rate filing is based on a
future test year ending June 30, 2018, a requested return on equity of 10.1 percent, an equity ratio of 53.97 percent and an electric rate
base of approximately $832 million.
SPS has excluded fuel and purchased power costs from base rates. This base rate case also takes into account the decline in sales of
380 MW in 2017 from certain wholesale customers and seeks to adjust the service life of SPS’ Tolk power plant to a remaining life of
2030 based on the investments to provide cooling water and the risks of investments in additional environmental controls.
127
The major components of the requested rate increase are summarized below:
(Millions of Dollars)
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Allocator changes, including wholesale load reductions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transmission expense, net of revenue, including charges paid to SPP for construction of regionally shared
transmission projects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation, including adjustment of service life for the Tolk generating station . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rate case expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Requested rate increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Request
20.1
11.5
4.7
3.6
1.1
0.4
41.4
Key dates in the procedural schedule are as follows:
Staff and intervenor testimony — April 14, 2017;
• Deadline for settlement — Feb. 28, 2017;
•
• Rebuttal testimony — May 3, 2017;
• Hearings — May 15, 2017; and
• An NMPRC decision and implementation of final rates is anticipated in the second half of 2017.
Pending Regulatory Proceedings — FERC
MISO ROE Complaints/ROE Adder — In November 2013, a group of customers filed a complaint at the FERC against MISO TOs,
including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in transmission formula rates in the
MISO region from 12.38 percent to 9.15 percent, a prohibition on capital structures in excess of 50 percent equity, and the removal of
ROE adders (including those for RTO membership and for being an independent transmission company), effective Nov. 12, 2013.
In December 2015, an ALJ initial decision recommended the FERC approve a ROE of 10.32 percent, which the FERC upheld in an
order issued on Sept. 28, 2016. This ROE is applicable for the 15 month refund period from Nov. 12, 2013 to Feb. 11, 2015, and
prospectively from the date of the FERC order. The total prospective ROE is 10.82 percent, which includes a previously approved 50
basis point adder for RTO membership.
In February 2015, a second complaint seeking to reduce the MISO region ROE from 12.38 percent to 8.67 percent prior to any adder
was filed, which the FERC set for hearings, resulting in a second period of potential refund from Feb. 12, 2015 to May 11, 2016. The
MPUC, NDPSC, SDPUC and the DOC joined a joint complainant/intervenor initial brief recommending an ROE of approximately
8.81 percent. FERC staff recommended a ROE of 8.78 percent. The MISO TOs recommended a ROE of 10.92 percent. On June 30,
2016, the ALJ recommended a ROE of 9.7 percent, the midpoint of the upper half of the discounted cash flow range. A FERC
decision is expected later in 2017.
As of Dec. 31, 2016, NSP-Minnesota has recognized a current liability for the Nov. 12, 2013 to Feb. 11, 2015 complaint period based
on the 10.32 percent ROE provided in the FERC order, as well as a current liability representing the best estimate of the final ROE for
the second complaint period.
SPP Open Access Transmission Tariff (OATT) Upgrade Costs — Under the SPP OATT, costs of participant-funded, or “sponsored,”
transmission upgrades may be recovered, in part, from other SPP customers whose transmission service depends on capacity enabled
by the upgrade. The SPP OATT has allowed SPP to collect charges since 2008, but SPP had not been charging its customers any
amounts attributable to these upgrades.
In April 2016, SPP filed a request with the FERC for a waiver that would allow SPP to recover the charges not billed since 2008. The
FERC approved the waiver request in July 2016. SPS and certain other parties requested rehearing of the FERC order. Amounts due
to SPP are expected to be paid over a five-year period commencing November 2016 under an optional payment plan that was
approved by the FERC in September 2016 and elected by SPS in October 2016. In October 2016, SPS filed applications for deferred
accounting and future recovery of related costs in Texas and New Mexico. In November 2016, SPP billed SPS a net amount, for the
period from 2008 through August 2016, of $12.8 million for these charges. In December 2016, SPS’ New Mexico application was
consolidated with its base rate case and SPS’ Texas application was referred to the ALJ for hearing. A decision is expected in the first
half of 2017. SPS anticipates these costs will be recoverable through regulatory mechanisms.
128
13. Commitments and Contingencies
Commitments
Capital Commitments — Xcel Energy has made commitments in connection with a portion of its projected capital expenditures. Xcel
Energy’s capital commitments primarily relate to the following major projects:
NSP-Minnesota Upper Midwest Wind Projects — NSP-Minnesota has issued a RFP, seeking up to 1,500 MW of wind energy projects.
The RFP requests both PPAs and build-own-transfer proposals. NSP-Minnesota has submitted a request to self-build 750 MW of this
total.
PSCo Advanced Grid Intelligence and Security Initiative — PSCo is pursuing projects to update and advance its electric distribution
grid to increase reliability and security standards, meet customer expectations, offer additional customer choice and control over
energy usage and implement new rate structures.
PSCo Rush Creek Wind Farm — PSCo has gained approval to build, own and operate a 600 MW wind generation facility and
proposed transmission line in Colorado.
PSCo Gas Transmission Integrity Management Programs — PSCo is proactively identifying and addressing the safety and reliability
of natural gas transmission pipelines. The pipeline integrity efforts include primarily pipeline assessment and maintenance projects.
PSCo Electric Distribution Integrity Management Programs — PSCo is assessing aging infrastructure for distribution assets and
replacing worn components to increase system performance.
SPS Transmission NTC — SPS has accepted NTCs for several hundred miles of transmission line and related substation projects based
on needs identified through SPP’s various planning processes, including those associated with economics, reliability, generator
interconnection or the load addition processes. Most significant are the 345 KV transmission line from TUCO to Yoakum County to
Hobbs Plant and the Hobbs Plant to China Draw 345 KV transmission line.
Fuel Contracts — Xcel Energy has entered into various long-term commitments for the purchase and delivery of a significant portion
of its current coal, nuclear fuel and natural gas requirements. These contracts expire in various years between 2017 and 2060. Xcel
Energy is required to pay additional amounts depending on actual quantities shipped under these agreements.
The estimated minimum purchases for Xcel Energy under these contracts as of Dec. 31, 2016 are as follows:
(Millions of Dollars)
2017. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2018. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2019. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Coal
Nuclear fuel
Natural gas
supply
Natural gas
storage and
transportation
707.6
372.0
102.7
49.3
50.4
295.1
1,577.1
$
$
113.2
60.8
111.1
37.7
90.2
449.5
862.5
$
$
395.6
187.4
181.4
186.1
193.3
172.0
1,315.8
$
$
252.0
195.4
155.1
141.4
132.9
1,108.8
1,985.6
Additional expenditures for fuel and natural gas storage and transportation will be required to meet expected future electric generation
and natural gas needs. Xcel Energy’s risk of loss, in the form of increased costs from market price changes in fuel, is mitigated
through the use of natural gas and energy cost-rate adjustment mechanisms, which provide for pass-through of most fuel, storage and
transportation costs to customers.
PPAs — NSP Minnesota, PSCo and SPS have entered into PPAs with other utilities and energy suppliers with expiration dates through
2039 for purchased power to meet system load and energy requirements and meet operating reserve obligations. In general, these
agreements provide for energy payments, based on actual energy delivered and capacity payments. Certain PPAs accounted for as
executory contracts also contain minimum energy purchase commitments. Capacity and energy payments are typically contingent on
the independent power producing entity meeting certain contract obligations, including plant availability requirements. Certain
contractual payments are adjusted based on market indices. The effects of price adjustments on our financial results are mitigated
through purchased energy cost recovery mechanisms.
129
Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of
$190.6 million, $230.6 million and $229.8 million in 2016, 2015 and 2014, respectively. At Dec. 31, 2016, 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, are as follows:
(Millions of Dollars)
2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Capacity
Energy (a)
165.8
130.2
85.0
69.4
79.4
300.3
830.1
$
$
91.8
93.2
98.7
105.4
139.8
522.7
1,051.6
(a)
Excludes contingent energy payments for renewable energy PPAs.
Additional energy payments under these PPAs and PPAs accounted for as operating leases will be required to meet expected future
electric demand.
Leases — Xcel Energy leases a variety of equipment and facilities used in the normal course of business. Three of these leases
qualify as capital leases and are accounted for accordingly. The assets and liabilities at the inception of a capital lease are recorded at
the lower of fair market value or the present value of future lease payments and are amortized over the term of the contract.
WYCO was formed as a joint venture with CIG to develop and lease natural gas pipeline, storage, and compression facilities. Xcel
Energy Inc. has a 50 percent ownership interest in WYCO. WYCO generally leases its facilities to CIG, and CIG operates the
facilities, providing natural gas storage services to PSCo under separate service agreements.
PSCo accounts for its Totem natural gas storage service arrangement with CIG as a capital lease. As a result, PSCo had $127.0
million and $132.9 million of capital lease obligations recorded for the arrangement as of Dec. 31, 2016 and 2015, respectively. Xcel
Energy Inc. eliminates 50 percent of the capital lease obligation related to WYCO in the consolidated balance sheet along with an
equal amount of Xcel Energy Inc.’s equity investment in WYCO.
PSCo records amortization for its capital leases as cost of natural gas sold and transported on the consolidated statements of income.
Total amortization expenses under capital lease assets were approximately $8.1 million, $8.2 million and $7.2 million for 2016, 2015
and 2014, respectively. Following is a summary of property held under capital leases:
(Millions of Dollars)
Gas storage facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Gas pipeline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property held under capital leases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total property held under capital leases, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Dec. 31, 2016
Dec. 31, 2015
200.5
20.7
221.2
(65.3)
155.9
$
$
200.5
20.7
221.2
(57.2)
164.0
The remainder of the leases, primarily for office space, railcars, generating facilities, natural gas pipeline transportation, vehicles,
aircraft and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations for
Xcel Energy were approximately $255.3 million, $265.3 million and $271.9 million for 2016, 2015 and 2014, respectively. These
expenses include capacity payments for PPAs accounted for as operating leases of $216.4 million, $223.6 million and $228.2 million
in 2016, 2015 and 2014, respectively, recorded to electric fuel and purchased power expenses.
Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been
accounted for as operating leases in accordance with the applicable accounting guidance.
130
Future commitments under operating and capital leases are:
(Millions of Dollars)
2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total minimum obligation. . . . . . . . . . . . . . . . . . . . . . .
Interest component of obligation. . . . . . . . . . . . . . . . . . .
Present value of minimum obligation . . . . . . . . . . .
Operating
Leases
PPA (a) (b)
Operating
Leases
Total
Operating
Leases
Capital Leases
$
25.2
25.2
29.7
24.4
23.5
170.1
$
212.3
212.8
230.6
244.2
246.6
1,919.4
237.5
238.0
260.3
268.6
270.1
2,089.5
$
$
15.1
14.7
14.5
14.3
13.7
245.0
317.3
(224.9)
92.4
(c)
(a)
(b)
(c)
Amounts do not include PPAs accounted for as executory contracts.
PPA operating leases contractually expire through 2039.
Future commitments exclude certain amounts related to Xcel Energy’s 50 percent ownership interest in WYCO.
Variable Interest Entities — The accounting guidance for consolidation of variable interest entities requires enterprises to consider the
activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining
whether an enterprise is a variable interest entity’s primary beneficiary.
PPAs — Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from independent power producing entities for which
the utility subsidiaries are required to reimburse natural gas or biomass 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. In addition, certain solar PPAs
provide the utility subsidiaries with 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 independent power producing entity.
Xcel Energy has determined that certain independent power producing entities are variable interest entities. Xcel Energy is not subject
to risk of loss from the operations of these entities, and no significant financial support has been, or is required to be provided other
than contractual payments for energy and capacity set forth in the PPAs.
Xcel Energy has evaluated each of these variable interest entities 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 has 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. Xcel Energy’s utility subsidiaries had approximately 3,537 and 3,698 MW of capacity under long-term PPAs
as of Dec. 31, 2016, and 2015, respectively, with entities that have been determined to be variable interest entities. These agreements
have expiration dates through the year 2041.
Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk electric generating stations from TUCO under
contracts for those facilities that expire in December 2017. 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.
No significant financial support has been, or is required to be provided to TUCO by SPS, other than contractual payments for
delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of certain fuel procurement
costs. SPS has determined that TUCO is a variable interest entity. SPS has concluded that it is not the primary beneficiary of TUCO
because SPS 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 limited partnerships to be variable interest entities primarily due to
contractual arrangements within each limited partnership that establish sharing of ongoing voting control and profits and losses that
does not consistently align with the partners’ proportional equity ownership. These limited partnerships are designed to qualify for
low-income housing tax credits. Eloigne and NSP-Wisconsin generally receive a larger allocation of the tax credits than the general
partners at inception of the arrangements. Xcel Energy Inc. has determined that Eloigne and NSP-Wisconsin have the power to direct
the activities that most significantly impact these entities’ economic performance, and therefore Xcel Energy Inc. consolidates these
limited partnerships in its consolidated financial statements.
131
Equity financing for these entities has been provided by Eloigne, NSP-Wisconsin and the general partner of each limited partnership.
Xcel Energy’s risk of loss 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. Mortgage-backed debt typically comprises the majority of the financing at inception of each limited partnership and
is paid over the life of the limited partnership arrangement. Obligations of the limited partnerships are generally secured by the
housing properties of each limited partnership, and the creditors of each limited partnership have no significant recourse to Xcel
Energy Inc. or its subsidiaries. Likewise, the assets of the limited partnerships may only be used to settle obligations of the limited
partnerships, and not those of Xcel Energy Inc. or its subsidiaries.
Amounts reflected in Xcel Energy’s consolidated balance sheets for the Eloigne and NSP-Wisconsin low-income housing limited
partnerships include the following:
(Thousands of Dollars)
Current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment, net. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other noncurrent assets (a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Mortgages and other long-term debt payable (a). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other noncurrent liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Dec. 31, 2016
Dec. 31, 2015
7,102
49,638
918
57,658
7,769
30,343
658
38,770
$
$
$
$
6,274
51,480
977
58,731
7,540
30,665
644
38,849
(a)
Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for
more information on the adoption of ASU 2015-03.
Technology Agreements — Xcel Energy has a contract that extends through December 2019 with International Business Machines
Corp. (IBM) for information technology services. The contract is cancelable at Xcel Energy’s option, although Xcel Energy would be
obligated to pay 50 percent of the contract value for early termination. Xcel Energy capitalized or expensed $118.7 million, $109.5
million and $111.3 million associated with the IBM contract in 2016, 2015 and 2014, 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
$34.6 million, $17.3 million and $27.3 million associated with the Accenture contract in 2016, 2015 and 2014, respectively.
Committed minimum payments under these obligations are as follows:
(Millions of Dollars)
2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IBM
Agreement
Accenture
Agreement
$
31.6
30.6
30.5
—
—
—
10.0
10.5
10.7
11.0
—
—
Guarantees and Indemnifications
Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities under specified agreements or transactions. The
guarantees and bond indemnities issued by Xcel Energy Inc. guarantee payment or performance by its subsidiaries. As a result, Xcel
Energy Inc.’s exposure under the guarantees and bond indemnities 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. and its subsidiaries
limit the exposure to a maximum amount stated in the guarantees and bond indemnities. As of Dec. 31, 2016 and 2015, Xcel Energy
Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements.
132
Guarantees and Surety Bonds
The following table presents guarantees and bond indemnities issued and outstanding as of Dec. 31, 2016:
(Millions of Dollars)
Guarantee of customer loans for the Farm Rewiring Program (a) . NSP-Wisconsin
Guarantee of the indemnification obligations of Xcel Energy
Services Inc. under the aircraft leases (b) . . . . . . . . . . . . . . . . . . Xcel Energy Inc.
Guarantor
Guarantee of residual value of assets under the Bank of Tokyo-
Mitsubishi Capital Corporation Equipment Leasing
Agreement (c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . NSP-Minnesota
Total guarantees issued . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
Guarantee performance and payment of surety bonds for Xcel
Energy Inc.’s utility subsidiaries (d) . . . . . . . . . . . . . . . . . . . . . . Xcel Energy Inc. $
Guarantee
Amount
Current
Exposure
1.0
$
13.0
4.8
18.8
43.0
$
(i)
0.1
—
—
0.1
Triggering
Event
(e)
(f)
(g)
(h)
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)
The term of this guarantee expires in 2020, which is the final scheduled repayment date for the loans. As of Dec. 31, 2016, no claims had been made by the
lender.
The terms of this guarantee expires in 2021 and 2023 when the associated leases expire.
The term of this guarantee expires in 2019 when the associated lease expires.
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.
The debtor becomes the subject of bankruptcy or other insolvency proceedings.
Nonperformance and/or nonpayment.
Actual fair value of leased assets is less than the guaranteed residual value amount at the end of the lease term.
Failure of any one of Xcel Energy Inc.’s utility subsidiaries to perform under the agreement that is the subject of the relevant bond. In addition, per the indemnity
agreement between Xcel Energy Inc. and the various surety companies, the 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. and its subsidiaries provide indemnifications through contracts entered into in the normal course of business. These
are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of
representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets
sold. Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. The
maximum potential amount of future payments under these indemnifications cannot be reasonably estimated as the obligated amounts
of these indemnifications often are not explicitly stated.
Environmental Contingencies
Xcel Energy has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In
many situations, the subsidiary involved believes it will recover some portion of these costs through insurance claims. Additionally,
where applicable, the subsidiary involved is pursuing, or intends to pursue, recovery from other PRPs and through the regulated rate
process. New and changing federal and state environmental mandates can also create added financial liabilities for Xcel Energy,
which are normally recovered through the regulated rate process. To the extent any costs are not recovered through the options listed
above, Xcel Energy would be required to recognize an expense.
Site Remediation — Various federal and state environmental laws impose liability, without regard to the legality of the original
conduct, 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 operated by Xcel Energy Inc.’s subsidiaries or their predecessors, or other entities; and third-party sites, such as landfills, for
which one or more of Xcel Energy Inc.’s subsidiaries are alleged to be a PRP that sent wastes to that site.
MGP Sites
Ashland MGP Site — NSP-Wisconsin has been named a PRP for contamination at a site in Ashland, Wis. The Ashland/Northern
States Power Lakefront Superfund Site (the Site) includes NSP-Wisconsin property, previously operated as a MGP facility (the Upper
Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park); and an area of Lake Superior’s Chequamegon Bay
adjoining the park.
133
In 2012, under a settlement agreement with the EPA, NSP-Wisconsin agreed to remediate the Phase I Project Area (which includes the
Upper Bluff and Kreher Park areas of the Site). The current cost estimate for the cleanup of the Phase I Project Area is approximately
$72.4 million, of which approximately $56.7 million has been spent.
NSP-Wisconsin performed a wet dredge pilot study in the summer of 2016 and demonstrated that a wet dredge remedy can meet the
performance standards for remediation of the Sediments. As a result, the EPA authorized NSP-Wisconsin to extend the wet dredge
pilot to additional areas of the Site. In January 2017, under a settlement agreement with the EPA, NSP-Wisconsin agreed to remediate
the Phase II Project Area (the Sediments). The settlement agreement was lodged with the U.S. District Court for the Western District
of Wisconsin (District Court) in January 2017, and a 30-day public comment period lapsed in February 2017. If the settlement is
timely approved by the District Court, NSP-Wisconsin anticipates a full scale wet dredge remedy of the Sediments will be performed
in 2017, with restoration activities concluding in 2018.
At Dec. 31, 2016 and 2015, NSP-Wisconsin had recorded a total liability of $64.3 million and $94.4 million, respectively, for the
entire site.
NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation costs as a regulatory asset. The PSCW has
consistently authorized NSP-Wisconsin rate recovery for all remediation costs incurred at the Site. In 2012, the PSCW agreed to
allow NSP-Wisconsin to pre-collect certain costs, to amortize costs over a ten-year period and to apply a three percent carrying cost to
the unamortized regulatory asset. In April 2016, NSP-Wisconsin filed a limited natural gas rate case for recovery of additional
expenses associated with remediating the Site. In December 2016, the PSCW issued a written order approving the requested increase
in annual recovery of MGP clean-up costs from $7.6 million in 2016 to $12.4 million in 2017.
Fargo, N.D. MGP Site — In May 2015, underground pipes, tars and impacted soils were discovered in a right-of-way in Fargo, N.D.
that appeared to be associated with a former MGP operated by NSP-Minnesota or prior companies. NSP-Minnesota removed
impacted soils and other materials from the right-of-way at that time and commenced an investigation of the historic MGP and
adjacent properties (the Fargo MGP Site). Based on the investigation, NSP-Minnesota has recommended that targeted source removal
of impacted soils and historic MGP infrastructure should be performed. The North Dakota Department of Health approved NSP-
Minnesota’s proposed cleanup plan in January 2017. The timing and final scope of remediation is dependent on whether current
property owners will agree to provide reasonable access to NSP-Minnesota to perform and implement the approved cleanup plan.
NSP-Minnesota has initiated insurance recovery litigation in North Dakota. The U.S. District Court for the District of North Dakota
agreed to the parties’ request for a stay of the litigation until May 2017.
As of Dec. 31, 2016 and Dec. 31, 2015, NSP-Minnesota had recorded a liability of $11.3 million and $2.7 million, respectively, for the
Fargo MGP Site, with the increase due to the remediation activities proposed by NSP-Minnesota. In December 2015, the NDPSC
approved NSP-Minnesota’s request to defer costs associated with the Fargo MGP Site, resulting in deferral of all investigation and
response costs with the exception of approximately 12 percent allocable to the Minnesota jurisdiction. Uncertainties related to the
liability recognized include obtaining access to perform the approved remediation, final designs that will be developed to implement
the approved cleanup plan and the potential for contributions from entities that may be identified as PRPs.
Other MGP Sites — Xcel Energy is currently involved in investigating and/or remediating several other MGP sites where regulated
materials may have been deposited. Xcel Energy has identified seven sites across all of its service territories where former MGP
activities have or may have resulted in site contamination and are under current investigation and/or remediation. At some or all of
these MGP sites, there are other parties that may have responsibility for some portion of any remediation. Xcel Energy anticipates that
the majority of the remediation at these sites will continue through at least 2017. Xcel Energy had accrued $2.0 million and $2.1
million for all of these sites at Dec. 31, 2016 and 2015, respectively. There may be insurance recovery and/or recovery from other
PRPs that will offset any costs incurred. Xcel Energy anticipates that any amounts spent will be fully recovered from customers.
134
Environmental Requirements
Water and Waste
Asbestos Removal — Some of Xcel Energy’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that
contain it are demolished or removed. Xcel Energy has recorded an estimate for final removal of the asbestos as an ARO. It may be
necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing
asbestos as part of other work is not expected to be material and is recorded as incurred as operating expenses for maintenance
projects, capital expenditures for construction projects or removal costs for demolition projects.
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. In 2015, the EPA published a final rule regulating the management and disposal of coal
combustion residuals (“CCR” or coal ash) as a nonhazardous waste. In December 2016, the Water Infrastructure Improvements for
the Nation Act (WIIN Act) was signed into law, which includes provisions that allow the CCR rule to be implemented through a state
or federal based permit program and that give the EPA direct enforcement authority. Xcel Energy is in the process of evaluating
whether the costs of implementing the CCR rule under the potential federal and/or state permit programs could have a material impact
on the results of operations, financial position or cash flows.
In 2015, industry and environmental non-governmental organizations sought judicial review of the final CCR rule. In June 2016, the
D.C. Circuit issued an order remanding and vacating certain elements of the rule as a result of partial settlements with these parties. A
final court decision is anticipated in the first half of 2017. Until a final decision is reached in the case, it is uncertain whether the
litigation or partial settlements will have any significant impact on results of operations, financial position or cash flows on Xcel
Energy. Xcel Energy believes that these associated costs would be recoverable through regulatory mechanisms.
Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In 2015, the EPA issued a final ELG rule for power
plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned
landfills that receive coal combustion residuals. Xcel Energy estimates that the capital cost to comply with the ELG rule for Colorado
will range from $9 million to $21 million, and could change as Xcel Energy continues to assess alternate compliance technologies.
Xcel Energy is in the process of evaluating whether the costs of compliance at NSP-Minnesota and NSP-Wisconsin could have a
material impact on the results of operations, financial position or cash flows. The anticipated costs of compliance with the final rule at
SPS are not expected to have a material impact on the results of operations, financial position or cash flows. Xcel Energy believes
that compliance costs would be recoverable through regulatory mechanisms.
Federal CWA Section 316(b) — Section 316(b) of the federal CWA requires the EPA to regulate cooling water intake structures to
assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. The
EPA published the final 316(b) rule in 2014. The rule prescribes technology for protecting fish that get stuck on plant intake screens
(known as impingement) and describes a process for site-specific determinations by each state for sites that must protect the small
aquatic organisms that pass through the intake screens into the plant cooling systems (known as entrainment). For Xcel Energy, these
requirements will primarily impact plants within the NSP-Minnesota service territory. The timing of compliance with the
requirements will vary from plant-to-plant since the new rule does not have a final compliance deadline. Xcel Energy estimates the
likely cost for complying with impingement requirements may be incurred between 2017 and 2027 and is approximately $53 million
with the majority needed for NSP-Minnesota. Xcel Energy believes at least six NSP-Minnesota plants and two NSP-Wisconsin plants
could be required by state regulators to make improvements to reduce entrainment. The exact cost of the entrainment improvements is
uncertain, but could be up to $192 million depending on the outcome of certain entrainment studies and cost-benefit analyses. Xcel
Energy anticipates these costs will be fully recoverable in rates.
Federal CWA Waters of the United States Rule — In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule
that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal
jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby
potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing
project costs and expanding permitting and reporting requirements. In October 2015, the U.S. Court of Appeals for the Sixth Circuit
issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over
challenges to the rule. In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges
to the rule. A ruling is expected by June 2017.
135
Air
GHG Emission Standard for Existing Sources (Clean Power Plan or CPP) — In 2015, a final rule was published by the EPA for
GHG emission standards for existing power plants. Under the rule, states were required to develop implementation plans by
September 2016, with the possibility of an extension to September 2018, or submit to a federal plan for the state prepared by the EPA.
Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants
achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. The CPP was
challenged by multiple parties in the D.C. Circuit Court. In January 2016, the D.C. Circuit Court denied requests to stay the
effectiveness of the rule. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. In September 2016,
the D.C. Circuit Court heard oral arguments in the consolidated challenges to the CPP. The stay will remain in effect until the D.C.
Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a
decision of its own. During the pendency of the stay, states are not required to submit implementation plans and the EPA will not
enforce deadlines or issue a federal plan for any state. Several of the states served by Xcel Energy have suspended formal planning
efforts, while others are continuing.
Xcel Energy has undertaken a number of initiatives that reduce GHG emissions and respond to state renewable and energy efficiency
goals. The CPP could require additional emission reductions in states in which Xcel Energy operates. If state plans do not provide
credit for the investments Xcel Energy has already made to reduce GHG emissions, or if they require additional initiatives or emission
reductions, then their requirements would potentially impose additional substantial costs. Until Xcel Energy has more information
about SIPs or the EPA finalizes its proposed federal plan for the states that do not develop related plans, Xcel Energy cannot predict
the costs of compliance with the final rule once it takes effect. Xcel Energy believes compliance costs will be recoverable through
regulatory mechanisms. If Xcel Energy’s regulators do not allow recovery of all or a part of the cost of capital investment or the
O&M costs incurred to comply with the CPP or cost recovery is not provided in a timely manner, it could have a material impact on
results of operations, financial position or cash flows.
CSAPR — CSAPR addresses long range transport of PM and ozone by requiring reductions in SO2 and NOx from utilities in the
eastern half of the United States using an emissions trading program. For Xcel Energy, the rule applies in Minnesota, Wisconsin and
Texas.
CSAPR was adopted to address interstate emissions impacting downwind states’ attainment of the 1997 ozone NAAQS and the 1997
and 2006 particulate NAAQS. As the EPA revises NAAQS, it will consider whether to make any further reductions to CSAPR
emission budgets and whether to change which states are included in the emissions trading program. In December 2015, the EPA
proposed adjustments to CSAPR emission budgets which address attainment of the more stringent 2008 ozone NAAQS. In
September 2016, the EPA adopted a final rule that reduced the ozone season emission budget for NOx in Texas by approximately 22
percent, which is expected to lead to increased costs to purchase emission allowances. In November 2016, the EPA proposed to
remove Texas from the particle NAAQS program. If adopted as proposed, Texas would no longer be subject to the annual SO2 and
NOx emission budgets under CSAPR. Xcel Energy does not anticipate these increased costs to purchase emission allowances will
have a material impact on the results of operations, financial position or cash flows.
Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a
multitude of sources. The BART requirements of the EPA’s regional haze rules require the installation and operation of emission
controls for industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. Under BART,
regional haze plans identify facilities that will have to reduce SO2, NOx and PM emissions and set emission limits for those facilities.
BART requirements can also be met through participation in interstate emission trading programs such as the CAIR and its successor,
CSAPR. The regional haze plans developed by Minnesota and Colorado have been fully approved and are being implemented in
those states. States are required to revise their plans every ten years. The next plans for Minnesota and Colorado will be due in 2021.
Texas’ first regional haze plan is still undergoing federal review as described below.
Actions affecting Harrington Units: Texas developed a SIP that finds the CAIR equal to BART for EGUs. As a result, no additional
controls beyond CAIR compliance would be required. In 2014, the EPA proposed to approve the BART portion of the SIP, with
substitution of CSAPR compliance for Texas’ reliance on CAIR. In January 2016, the EPA adopted a final rule that defers its approval
of CSAPR compliance as BART until the EPA considers further adjustments to CSAPR emission budgets under the D.C. Circuit
Court’s remand of the Texas SO2 emission budgets. In June 2016, the EPA issued a memorandum which allows Texas to voluntarily
adopt the CSAPR emission budgets limiting annual SO2 and NOx emissions and rely on those emission budgets to satisfy Texas’
BART obligations under the regional haze rules. The Texas Commission on Environmental Quality (TCEQ) has not utilized this
option. The EPA then published a proposed rule in January 2017 that could have the effect of requiring installation of dry scrubbers
to reduce SO2 emissions from Harrington Units 1 and 2. Investment costs associated with dry scrubbers for Harrington Units 1 and 2
could be approximately $400 million. The EPA’s deadline to issue a final BART rule for Texas is September 2017.
136
Actions affecting Tolk units: In January 2016, the EPA adopted a final rule establishing a federal implementation plan for the state of
Texas, which imposed SO2 emission limitations that reflect 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 approximately $600 million. SPS appealed the
EPA’s decision and requested a stay of the final rule. The Fifth Circuit granted the stay and decided that the Fifth Circuit is the
appropriate venue for this case. The EPA sought a remand of its order and SPS and others have opposed the terms of that remand. A
decision is expected in late 2017 or early 2018. It is likely that Texas and other affected entities including SPS would continue to
challenge the determinations to date. The new Administration has not yet taken any public position regarding its views of the
proposed and final regional haze regulations affecting SPS facilities in Texas. The risk of these controls being imposed along with the
risk of investments to provide cooling water to Tolk have caused SPS to seek to decrease the remaining depreciable life of the Tolk
units.
Implementation of the NAAQS for SO2 — The EPA adopted a more stringent NAAQS for SO2 in 2010. The EPA is requiring states
to evaluate areas in three phases. The first phase includes areas near PSCo’s Pawnee plant and SPS’ Tolk and Harrington plants. The
Pawnee plant recently installed an SO2 scrubber and the Tolk and Harrington Plants utilize low sulfur coal to reduce SO2 emissions.
In June 2016, the EPA issued final designations which found the area near the Tolk plant to be meeting the NAAQS and the areas near
the Harrington and Pawnee plants 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. It is anticipated that the area near the Pawnee plant will be able to show
compliance with the NAAQS through air dispersion modeling performed by the Colorado Department of Public Health and
Environment.
The areas near the remaining Xcel Energy power plants will be evaluated in the next designation phase, ending December 2017. The
remaining plants, PSCo’s Comanche and Hayden plants along with NSP-Minnesota’s King and Sherco plants, utilize scrubbers to
control SO2 emissions. NSP-Minnesota’s King plant demonstrated compliance with the SO2 NAAQS as part of their recent permit
renewal. In late 2016, Xcel Energy submitted air dispersion modeling to the Colorado Department of Public Health and Environment,
MPCA and the EPA which demonstrated that PSCo’s Comanche and Hayden plants as well as NSP-Minnesota’s Sherco plant comply
with the NAAQS. If an area is designated nonattainment in 2020, the states will need to evaluate all SO2 sources in the area. The
state would then submit an implementation plan, which would be due by 2022, 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
designation of nonattainment areas is made and any required state plans are developed. Xcel Energy believes that should SO2 control
systems be required or require upgrades 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 position
or cash flows.
Revisions to the NAAQS for Ozone — In 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75
parts per billion (ppb) to 70 ppb. In areas where Xcel Energy operates, current monitored air quality concentrations comply with the new
standard in the Twin Cities Metropolitan Area in Minnesota and meet the 70 ppb level in the Texas panhandle. In documents issued with
the new standard, the EPA projects that both areas will meet the new standard. The Denver Metropolitan Area is currently not meeting
the prior ozone standard and will therefore not meet the new, more stringent standard, however PSCo’s scheduled retirement of coal fired
plants in Denver should help in any plan to mitigate non-attainment.
Asset Retirement Obligations
Recorded AROs — AROs have been recorded for property related to the following: electric production (nuclear, steam, wind, other
and hydro), electric distribution and transmission, natural gas production, natural gas transmission and distribution, natural gas
storage, thermal and general property. The electric production obligations include asbestos, ash-containment facilities, radiation
sources, storage tanks, control panels and decommissioning. The asbestos recognition associated with electric production includes
certain plants at NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. NSP-Minnesota also recognized asbestos obligations for its general
office building. AROs also have been recorded for NSP-Minnesota, NSP-Wisconsin, PSCo and SPS steam production related to ash-
containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills. NSP-Minnesota and PSCo have also
recorded AROs for the retirement and removal of assets at certain wind production facilities for which the land is leased and removal
is required by contract.
Xcel Energy has recognized an ARO for the retirement costs of natural gas mains and lines at NSP-Minnesota, NSP-Wisconsin and
PSCo and an ARO for the retirement of above ground gas gathering, extraction and wells related to gas storage facilities at PSCo. In
addition, an ARO was recognized for the removal of electric transmission and distribution equipment at NSP-Minnesota, NSP-
Wisconsin, PSCo and SPS, which consists of many small potential obligations associated with PCBs, mineral oil, storage tanks,
lithium batteries, mercury and street lighting lamps. The electric and common general AROs include small obligations related to
storage tanks, radiation sources and office buildings.
137
In April 2015, the EPA published the final rule regulating the management and disposal of coal combustion byproducts (e.g., coal ash)
as a nonhazardous waste to the Federal Register. The rule became effective in October 2015. The estimated costs to comply with the
final rule were incorporated into the cash flow revisions in 2015.
For the nuclear assets, the ARO is associated with the decommissioning of the NSP-Minnesota nuclear generating plants, Monticello
and PI. See Note 14 for further discussion of nuclear obligations.
A reconciliation of Xcel Energy’s AROs for the years ended Dec. 31, 2016 and 2015 is as follows:
(Thousands of Dollars)
Electric plant
Nuclear production decommissioning. . . . . .
Steam and other production ash containment
Steam and other production asbestos . . . . . .
Wind production . . . . . . . . . . . . . . . . . . . . . .
Electric distribution . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas plant
Gas transmission and distribution . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Common and other property
Common general plant asbestos . . . . . . . . . .
Common miscellaneous. . . . . . . . . . . . . . . . .
Total liability. . . . . . . . . . . . . . . . . . . . . . . .
Beginning
Balance
Jan. 1, 2016
$2,141,024
131,587
84,491
71,646
13,187
4,543
Liabilities
Recognized
Liabilities
Settled
Accretion
Cash Flow
Revisions (b)
Ending
Balance
Dec. 31, 2016
$
— $
—
—
17,305 (a)
—
645
— $ 108,298
4,913
4,054
3,166
485
176
(6,271)
—
—
—
(29)
$
— $ 2,249,322
116,386
88,442
92,178
20,123
4,884
(13,843)
(103)
61
6,451
(451)
155,933
3,966
—
185
—
—
6,368
158
42,483
—
204,784
4,309
551
1,634
$2,608,562
$
—
—
18,135
—
—
28
57
(6,300) $ 127,703
$
—
(469)
34,129
579
1,222
$ 2,782,229
$
(a)
(b)
The liability recognized relates to the NSP-Minnesota Courtenay Wind Farm which was placed in service during 2016.
In 2016, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the gas transmission and distribution AROs were
mainly related to increased miles of gas mains.
The aggregate fair value of NSP-Minnesota’s legally restricted assets, for purposes of funding future nuclear decommissioning, was
$1.9 billion as of Dec. 31, 2016, consisting of external investment funds.
(Thousands of Dollars)
Electric plant
Nuclear production decommissioning . . . . . . .
Steam and other production ash containment .
Steam and other production asbestos. . . . . . . .
Wind production . . . . . . . . . . . . . . . . . . . . . . .
Electric distribution . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas plant
Gas transmission and distribution . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Common and other property
Common general plant asbestos. . . . . . . . . . . .
Common miscellaneous . . . . . . . . . . . . . . . . . .
Total liability . . . . . . . . . . . . . . . . . . . . . . . . .
Beginning
Balance
Jan. 1, 2015
$2,037,947
127,600
69,698
38,260
12,593
4,605
Liabilities
Recognized
Liabilities
Settled
Accretion
Cash Flow
Revisions (a)
Ending
Balance
Dec. 31, 2015 (b)
$
— $
—
3,875
31,085 (a)
—
127
— $ 103,077
4,746
—
3,670
—
1,778
—
463
—
(273)
178
149,964
3,925
—
—
—
—
5,969
155
$
— $
(759)
7,248
523
131
(94)
—
(114)
2,141,024
131,587
84,491
71,646
13,187
4,543
155,933
3,966
505
1,534
$2,446,631
—
—
35,087
$
—
—
27
56
(273) $ 120,119
$
19
44
6,998
$
551
1,634
2,608,562
$
(a) The liability recognized relates to the NSP-Minnesota Pleasant Valley and Border Wind Farms which were placed in service during 2015.
(a)
In 2015, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the asbestos AROs were mainly related to
updated cost estimates.
The aggregate fair value of NSP-Minnesota’s legally restricted assets, for purposes of funding future nuclear decommissioning, was
$1.7 billion as of Dec. 31, 2015, consisting of external investment funds.
138
Indeterminate AROs — Outside of the known and recorded asbestos AROs, other plants or buildings may contain asbestos due to the
age of many of Xcel Energy’s facilities, but no confirmation or measurement of the amount of asbestos or cost of removal could be
determined as of Dec. 31, 2016. Therefore, an ARO has not been recorded for these facilities.
Removal Costs — Xcel Energy records a regulatory liability for the plant removal costs of generation, transmission and distribution
facilities of its utility subsidiaries that are recovered currently in rates. Generally, the accrual of future non-ARO removal obligations
is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have
allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based
on varying rates as authorized by the appropriate regulatory entities. Given the long time periods over which the amounts were
accrued and the changing of rates over time, 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.
The accumulated balances by entity were as follows at Dec. 31:
(Millions of Dollars)
NSP-Minnesota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PSCo. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NSP-Wisconsin. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Xcel Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2016
2015
419
367
209
140
1,135
$
$
430
364
204
132
1,130
Nuclear Insurance
On Dec. 31, 2016, NSP-Minnesota’s public liability for claims resulting from any nuclear incident was limited to $13.4 billion under
the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota had secured $375 million of coverage for its public
liability exposure with a pool of insurance companies. The remaining $13.0 billion of exposure was funded by the Secondary
Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. On Jan. 1, 2017,
the available insurance limit was increased from $375 million to $450 million. This increase in limit occurs periodically and the Price-
Anderson amendment to the Atomic Energy Act requires purchasing the full available limit. On Jan. 1, 2017 this $450 million limit
was secured from the insurance pool. NSP-Minnesota is subject to assessments of up to $127.3 million per reactor per accident for
each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the
United States. The maximum funding requirement is $19.0 million per reactor per incident during any one year. These maximum
assessment amounts are both subject to inflation adjustment by the NRC and state premium taxes. The NRC’s last adjustment was
effective September 2013.
NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd.
(NEIL). The coverage limits are $2.3 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business
interruption insurance coverage, including the cost of replacement power obtained during certain 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 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. However, in each calendar year, NSP-Minnesota could be subject
to maximum assessments of approximately $19.8 million for business interruption insurance and $43.0 million for property damage
insurance if losses exceed accumulated reserve funds.
Legal Contingencies
Xcel Energy is involved in various litigation matters that are being defended and handled 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 such losses that are probable of
being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably
possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are
in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty
regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not
specifically reported herein, management does not anticipate that the ultimate liabilities, if any, 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.
139
Employment, Tort and Commercial Litigation
Pacific Northwest FERC Refund Proceeding — A complaint with the FERC posed that sales made in the Pacific Northwest in 2000
and 2001 through bilateral contracts were unjust and unreasonable under the Federal Power Act. The City of Seattle (the City) alleged
between $34 million to $50 million in sales with PSCo were subject to refund. In 2003, the FERC terminated the proceeding,
although it was later remanded back to the FERC in 2007 by the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).
In May 2015, the FERC rejected the City’s claim that any of the sales made resulted in an excessive burden and concluded that the
City failed to establish a causal link between any contracts and any claimed unlawful market activity. In February 2016, the City
appealed this decision to the Ninth Circuit.
In October 2016, a settlement was reached that resolved all outstanding claims between and among the City and the respondents,
including PSCo. Settlement terms required PSCo to pay the City $15,000 and the City to withdraw its pending appeal with the Ninth
Circuit. These terms have been met, bringing this matter to a close.
Gas Trading Litigation — e prime, inc. (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. Thirteen lawsuits were
commenced against e prime and Xcel Energy (and NSP-Wisconsin, in two instances) between 2003 and 2009 alleging fraud and
anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices.
The cases were consolidated in U.S. District Court in Nevada. Five of the cases have since been settled and seven have been
dismissed. One multi-district litigation (MDL) matter remains and it consists of a Colorado class (Breckenridge), a Wisconsin class
(NSP-Wisconsin), a Kansas class, and two other cases identified as “Sinclair Oil” and “Farmland.” In November 2016, the MDL
judge dismissed e prime and Xcel Energy from the Farmland lawsuit. Motions for summary judgment have been filed by defendants,
including e prime, in all of the remaining lawsuits. Defendants have also filed briefs opposing plaintiffs’ motion for class certification.
The majority of the motions filed were argued to the court in January 2017. It is uncertain when the court will render a decision
concerning these motions. Xcel Energy, NSP-Wisconsin and e prime have concluded that a loss is remote.
Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in Denver State Court,
stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric
service agreements entered into by PSCo and various developers. The dispute involves assigned interests in those claims by over fifty
developers. In May 2016, the district court granted PSCo’s motion to dismiss the lawsuit, concluding that jurisdiction over this
dispute resides with the CPUC. In June 2016, DRC filed a notice of appeal. The matter has been fully briefed and plaintiff has
requested oral arguments. DRC also brought a proceeding before the CPUC as assignee on behalf of two developers, Ryland Homes
and Richmond Homes of Colorado. In March 2016, the ALJ issued an order rejecting DRC’s claims for additional allowances and
refunds. In June 2016, the ALJ’s determination was approved by the CPUC. DRC did not file a request for reconsideration before the
CPUC contesting the decision, but filed an appeal in Denver District Court in August 2016. DRC filed its brief in February 2017 and
PSCo’s answer brief will be due March 2017.
PSCo has concluded that a loss is remote with respect to this matter as the service agreements were developed to implement CPUC
approved tariffs and PSCo has complied with the tariff provisions. Also, if a loss were sustained, PSCo believes it would be allowed
to recover these costs through traditional regulatory mechanisms. The amount or range in dispute is presently unknown and no accrual
has been recorded for this matter.
Other Contingencies
See Note 12 for further discussion.
14. Nuclear Obligations
Fuel Disposal — NSP-Minnesota is responsible for temporarily storing used or spent nuclear fuel from its nuclear plants. The DOE is
responsible for permanently storing spent fuel from NSP-Minnesota’s nuclear plants as well as from other U.S. nuclear plants, but no
such facility is yet available. NSP-Minnesota has funded its portion of the DOE’s permanent disposal program since 1981. Through
May 2014, the fuel disposal fees were based on a charge of 0.1 cent per KWh sold to customers from nuclear generation. Since that
time, the DOE has set the fee to zero.
Fuel expense includes the DOE fuel disposal assessments of approximately $5 million in 2014. There were no DOE fuel disposal
assessments in 2016 or 2015. In total, NSP-Minnesota paid approximately $452.1 million to the DOE through Dec. 31, 2014.
140
NSP-Minnesota has its own temporary on-site storage facilities for spent fuel at its Monticello and PI nuclear plants, which consist of
storage pools and dry cask facilities at both sites. The amount of spent fuel storage capacity is determined by the NRC and the
MPUC. The Monticello dry-cask storage facility currently stores 16 of the 30 authorized canisters, and the PI dry-cask storage facility
currently stores 40 of the 64 authorized casks.
Regulatory Plant Decommissioning Recovery — Decommissioning activities related to 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. The MPUC most recently approved NSP-Minnesota’s 2014 nuclear
decommissioning study in October 2015. This cost study quantified decommissioning costs in 2014 dollars and utilized escalation
rates of 4.36 percent per year for plant removal activities, and 3.36 percent for spent fuel management and site restoration activities
over a 60-year decommissioning scenario.
The total obligation for decommissioning is expected to be funded 100 percent by the external decommissioning trust fund when
decommissioning commences. NSP-Minnesota’s most recently approved decommissioning study resulted in an annual funding
requirement of $14 million to be recovered in utility customer rates which started in 2016. This cost study assumes the external
decommissioning fund will earn an after-tax return between 5.23 percent and 6.30 percent. Realized and unrealized gains on fund
investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs.
As of Dec. 31, 2016, NSP-Minnesota has accumulated $1.9 billion of assets held in external decommissioning trusts. The following
table summarizes the funded status of NSP-Minnesota’s decommissioning obligation based on parameters established in the most
recently approved decommissioning study. Xcel Energy believes future decommissioning costs, if necessary, will continue to be
recovered in customer rates. The amounts presented below were prepared on a regulatory basis, and are not recorded in the financial
statements for the ARO.
Regulatory Basis
(Thousands of Dollars)
Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars). . . . $ 3,012,342
258,278
Effect of escalating costs (to 2016 and 2015 dollars, respectively, at 4.36/3.36 percent). . . . . . . . . . . .
3,270,620
Estimated decommissioning cost obligation (in current dollars) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7,934,874
Effect of escalating costs to payment date (4.36/3.36 percent). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Estimated future decommissioning costs (undiscounted) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11,205,494
Effect of discounting obligation (using average risk-free interest rate of 3.25 percent and 3.01
2016
(7,068,362)
percent for 2016 and 2015, respectively). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Discounted decommissioning cost obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,137,132
Assets held in external decommissioning trust . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,860,762
Underfunding of external decommissioning fund compared to the discounted decommissioning
obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,276,370
2015
$ 3,012,342
126,464
3,138,806
8,066,688
11,205,494
(6,891,392)
$ 4,314,102
$ 1,724,150
2,589,952
Calculations and data used by the regulator in approving NSP-Minnesota’s rates are useful in assessing future cash flows. The
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. The following table provides a reconciliation of the discounted decommissioning cost obligation
- regulated basis to the ARO recorded in accordance with GAAP:
(Thousands of Dollars)
Discounted decommissioning cost obligation - regulated basis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Differences in discount rate and market risk premium . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
O&M costs not included for GAAP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear production decommissioning ARO - GAAP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016
$ 4,137,132
(1,043,655)
(844,155)
$ 2,249,322
2015
$ 4,314,102
(1,275,438)
(897,640)
$ 2,141,024
141
Decommissioning expenses recognized as a result of regulation for the years ending Dec. 31 were:
(Thousands of Dollars)
Annual decommissioning recorded as depreciation expense: (a) (b). . . . . . . . . . . . . . . . . $
2016
2015
2014
20,372
$
6,862
$
7,138
(a)
(b)
Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.
Decommissioning expense in 2016 includes Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million. The 2014 and 2015 expense
was offset by the DOE settlement refund.
The 2014 nuclear decommissioning filing approved in 2015 has been used for the regulatory presentation for both 2015 and 2016.
15. Regulatory Assets and Liabilities
Xcel Energy prepares its consolidated financial statements in accordance with the applicable accounting guidance, as discussed in
Note 1. Under this guidance, 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. Any portion of Xcel Energy’s business that is not
regulated cannot establish regulatory assets and liabilities. If changes in the utility industry or the business of Xcel Energy no longer
allow for the application of regulatory accounting guidance under GAAP, Xcel Energy would be required to recognize the write-off of
regulatory assets and liabilities in net income or OCI.
The components of regulatory assets shown on the consolidated balance sheets at Dec. 31, 2016 and 2015 are:
See Note(s)
Remaining
Amortization Period
Dec. 31, 2016
Dec. 31, 2015
Current
Noncurrent
Current
Noncurrent
9 Various
$
89,413
$ 1,548,966
$
90,249
$ 1,368,115
(Thousands of Dollars)
Regulatory Assets
Pension and retiree medical obligations (a) . . . . . . . . . . . .
Recoverable deferred taxes on AFUDC recorded in plant
Net AROs (b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Environmental remediation costs . . . . . . . . . . . . . . . . . . .
Contract valuation adjustments (c). . . . . . . . . . . . . . . . . . .
Depreciation differences . . . . . . . . . . . . . . . . . . . . . . . . . .
1
1, 13, 14
Plant lives
Plant lives
1, 13 Various
1, 11 Term of related contract
Pending rate case
1
Purchased power contract costs . . . . . . . . . . . . . . . . . . . .
13 Term of related contract
PI EPU . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Conservation programs (d) . . . . . . . . . . . . . . . . . . . . . . . . .
State commission adjustments . . . . . . . . . . . . . . . . . . . . .
12 Eighteen years
1 One to three years
1
Plant lives
Renewable resources and environmental initiatives . . . . .
13 One to four years
Losses on reacquired debt. . . . . . . . . . . . . . . . . . . . . . . . .
4 Term of related debt
Deferred purchased natural gas and electric energy costs
1 One to four years
Nuclear refueling outage costs . . . . . . . . . . . . . . . . . . . . .
Gas pipeline inspection and remediation costs . . . . . . . . .
1 One to two years
12 One to three years
Property tax. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Various
CACJA recovery rider. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less than one year
—
—
10,863
17,710
15,363
1,762
3,288
47,609
970
34,381
4,058
18,313
48,750
7,042
9,393
24,260
424,354
379,375
165,190
111,102
90,426
70,107
61,772
48,451
27,310
23,392
22,576
16,317
16,196
13,513
1,653
—
—
—
6,702
26,379
14,221
1,587
2,967
31,793
988
33,014
5,008
11,783
67,545
6,858
21,757
—
408,994
306,671
166,883
128,780
99,835
70,411
65,060
50,047
26,708
23,565
26,268
12,762
28,913
13,662
14,428
20,020
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total regulatory assets . . . . . . . . . . . . . . . . . . . . . . . . . .
Various
30,480
363,655
60,167
$ 3,080,867
$
23,779
344,630
27,619
$ 2,858,741
$
(a)
(b)
(c)
(d)
Includes $241.0 million and $257.5 million for the regulatory recognition of the NSP-Minnesota pension expense of which $15.3 million and $21.3 million is
included in the current asset at Dec. 31, 2016 and 2015, respectively. Also included are $11.1 million and $12.5 million of regulatory assets related to the
nonqualified pension plan of which $2.6 million and $4.0 million is included in the current asset at Dec. 31, 2016 and 2015, respectively.
Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning
investments.
Includes the fair value of 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.
142
The components of regulatory liabilities shown on the consolidated balance sheets at Dec. 31, 2016 and 2015 are:
(Thousands of Dollars)
Regulatory Liabilities
See Note(s)
Remaining
Amortization Period
Dec. 31, 2016
Dec. 31, 2015
Current
Noncurrent
Current
Noncurrent
Plant removal costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1, 13
Plant lives
$
— $
1,134,583
$
— $
1,131,023
Renewable resources and environmental initiatives . . . . .
12, 13 Various
Deferred income tax adjustment . . . . . . . . . . . . . . . . . . . .
Investment tax credit deferrals . . . . . . . . . . . . . . . . . . . . .
Gain from asset sales . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Contract valuation adjustments (a). . . . . . . . . . . . . . . . . . .
PSCo earnings test . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred electric, natural gas and steam production costs
Conservation programs (b) . . . . . . . . . . . . . . . . . . . . . . . . .
DOE settlement. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas pipeline inspection costs . . . . . . . . . . . . . . . . . . . . . .
Low income discount program . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total regulatory liabilities (c) . . . . . . . . . . . . . . . . . . . . .
1, 6 Various
1, 6 Various
12 Various
1, 11 Term of related contract
12 One to two years
1
Less than one year
1, 12
Less than one year
12
Less than one year
Less than one year
Less than one year
Various
4,674
—
—
—
22,077
8,300
97,823
25,200
19,668
5,108
2,025
36,019
71,098
48,054
45,334
4,000
1,652
914
—
—
—
—
—
77,577
6,271
—
—
2,640
21,661
42,868
146,235
34,444
16,139
1,140
2,475
32,957
41,869
46,737
48,985
2,584
—
9,472
—
—
—
4,273
—
47,946
$
220,894
$
1,383,212
$
306,830
$
1,332,889
(a)
(b)
(c)
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 $46.0 million and $75.0 million for 2016 and 2015, respectively, is included in other current liabilities.
At Dec. 31, 2016 and 2015, approximately $166 million and $169 million of Xcel Energy’s regulatory assets represented past
expenditures not currently earning a return, respectively. This amount primarily includes recoverable purchased natural gas and
electric energy costs and certain expenditures associated with renewable resources and environmental initiatives.
16. Other Comprehensive Income
Changes in accumulated other comprehensive (loss) income, net of tax, for the years ended Dec. 31, 2016 and 2015 were as follows:
(Thousands of Dollars)
Accumulated other comprehensive (loss) income at Jan. 1 . . . . . . . . . $
Other comprehensive income (loss) before reclassifications. . . . . . .
Losses reclassified from net accumulated other comprehensive loss
Net current period other comprehensive income (loss) . . . . . . . . . . . .
Accumulated other comprehensive (loss) income at Dec. 31 . . . . . . . $
Gains and
Losses on Cash
Flow Hedges
Year Ended Dec. 31, 2016
Unrealized
Gains and Losses
on Marketable
Securities
Defined Benefit
Pension and
Postretirement
Items
Total
(54,862) $
3
3,708
3,711
(51,151) $
110
—
—
—
110
$
$
(55,001) $ (109,753)
(7,783)
(7,780)
7,179
3,471
(4,312)
(601)
(59,313) $ (110,354)
(Thousands of Dollars)
Accumulated other comprehensive (loss) income at Jan. 1 . . . . . . . . . $
Other comprehensive loss before reclassifications . . . . . . . . . . . . . .
Losses reclassified from net accumulated other comprehensive loss
Net current period other comprehensive income (loss) . . . . . . . . . . . .
Accumulated other comprehensive (loss) income at Dec. 31 . . . . . . . $
Gains and
Losses on Cash
Flow Hedges
Year Ended Dec. 31, 2015
Unrealized
Gains and Losses
on Marketable
Securities
Defined Benefit
Pension and
Postretirement
Items
Total
(57,628) $
(70)
2,836
2,766
(54,862) $
110
—
—
—
110
$
$
(50,621) $ (108,139)
(7,906)
(7,976)
6,362
3,526
(4,380)
(1,614)
(55,001) $ (109,753)
143
Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2016 and 2015 were as follows:
(Thousands of Dollars)
Losses (gains) on cash flow hedges:
Interest rate derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Vehicle fuel derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total, pre-tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total, net of tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Defined benefit pension and postretirement losses (gains):
Amortization of net losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prior service credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total, pre-tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total, net of tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total amounts reclassified, net of tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Amounts Reclassified from Accumulated
Other Comprehensive Loss
Year Ended
Dec. 31, 2016
Year Ended
Dec. 31, 2015
5,859
191
6,050
(2,342)
3,708
5,912
(256)
5,656
(2,185)
3,471
7,179
(a)
(b)
$
(c)
(c)
$
(a)
(b)
(c)
(c)
4,515
131
4,646
(1,810)
2,836
6,132
(357)
5,775
(2,249)
3,526
6,362
(a)
(b)
(c)
Included in interest charges.
Included in O&M expenses.
Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for details regarding these benefit plans.
17. Segments and Related Information
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 are each separately and regularly reviewed by Xcel Energy’s
chief operating decision maker. Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from
the product or service provided. 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 utility, regulated natural gas utility and all other.
• Xcel Energy’s 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. Regulated electric utility also includes
wholesale commodity and trading operations.
• Xcel Energy’s regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of
Minnesota, Wisconsin, North Dakota, Michigan and Colorado.
• Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore
included in the all other category. Those primarily include steam revenue, appliance repair services, nonutility 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 $132.8 million and $130.0 million as of Dec. 31, 2016 and
2015, 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 because as an integrated electric and
natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment, and 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.
To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly
assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are
allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including
office supplies, rent, property insurance and general advertising.
The accounting policies of the segments are the same as those described in Note 1.
144
Regulated
Electric
Regulated
Natural Gas
All Other
Reconciling
Eliminations
Consolidated
Total
(Thousands of Dollars)
2016
Operating revenues from external customers . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . . . . . . . . . . . .
Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 9,499,781
1,327
$ 9,501,108
$ 1,531,412
1,110
$ 1,532,522
Depreciation and amortization . . . . . . . . . . . . . . . . . .
Interest charges and financing costs . . . . . . . . . . . . . .
Income tax expense (benefit). . . . . . . . . . . . . . . . . . . .
Net income (loss). . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,135,584
449,916
566,957
1,066,758
$
160,293
53,913
76,378
124,250
(Thousands of Dollars)
2015
Operating revenues from external customers . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . . . . . . . . . . . .
Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulated
Electric
Regulated
Natural Gas
$ 9,275,986
1,511
$ 9,277,497
$ 1,672,081
1,251
$ 1,673,332
Depreciation and amortization . . . . . . . . . . . . . . . . . .
Interest charges and financing costs . . . . . . . . . . . . . .
Income tax expense (benefit). . . . . . . . . . . . . . . . . . . .
Net income (loss). . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
962,565
425,999
508,568
921,403
154,892
49,763
60,545
106,023
(Thousands of Dollars)
2014
Operating revenues from external customers . . . . . . .
Intersegment revenues . . . . . . . . . . . . . . . . . . . . . . . . .
Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulated
Electric
Regulated
Natural Gas
$ 9,465,890
1,774
$ 9,467,664
$ 2,142,738
5,893
$ 2,148,631
Depreciation and amortization . . . . . . . . . . . . . . . . . .
Interest charges and financing costs . . . . . . . . . . . . . .
Income tax expense (benefit). . . . . . . . . . . . . . . . . . . .
Net income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
866,746
397,824
512,551
890,535
144,661
43,940
76,418
128,559
18. Summarized Quarterly Financial Data (Unaudited)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
75,727
—
75,727
7,326
116,050
(62,118)
(67,629)
All Other
76,419
—
76,419
7,067
93,272
(26,394)
(42,941)
All Other
77,507
—
77,507
7,638
86,442
(65,154)
2,212
— $ 11,106,920
(2,437)
—
(2,437) $ 11,106,920
— $ 1,303,203
619,879
—
581,217
—
1,123,379
—
Reconciling
Eliminations
Consolidated
Total
— $ 11,024,486
(2,762)
—
(2,762) $ 11,024,486
— $ 1,124,524
569,034
—
542,719
—
984,485
—
Reconciling
Eliminations
Consolidated
Total
— $ 11,686,135
(7,667)
—
(7,667) $ 11,686,135
— $ 1,019,045
528,206
—
523,815
—
1,021,306
—
(Amounts in thousands, except per share data)
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EPS total — basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
EPS total — diluted. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash dividends declared per common share . . . . . . . . . . . . . . . . .
March 31, 2016
2,772,273
489,870
241,312
0.47
0.47
0.34
(Amounts in thousands, except per share data)
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
EPS total — basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
EPS total — diluted. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash dividends declared per common share . . . . . . . . . . . . . . . . .
March 31, 2015
2,962,219
350,845
152,066
0.30
0.30
0.32
$
$
$
$
Quarter Ended
June 30, 2016
Sept. 30, 2016
Dec. 31, 2016
$
$
2,499,849
431,581
196,795
0.39
0.39
0.34
$
$
3,040,147
827,054
457,795
0.90
0.90
0.34
2,794,651
465,350
227,477
0.45
0.45
0.34
Quarter Ended
June 30, 2015
Sept. 30, 2015
Dec. 31, 2015
$
$
2,515,134
422,845
196,931
0.39
0.39
0.32
$
$
2,901,312
785,812
426,463
0.84
0.84
0.32
2,645,821
441,010
209,025
0.41
0.41
0.32
145
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A — Controls and Procedures
Disclosure Controls and Procedures
Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in
reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the
time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to
be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer
(CFO), allowing timely decisions regarding required disclosure. As of Dec. 31, 2016, 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 the procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures were
effective.
Internal Control Over Financial Reporting
No change in Xcel Energy’s internal control over financial reporting has occurred during the most recent fiscal quarter that has
materially affected, or is 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, 2016 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 and as approved by the SEC and as
indicated in Management Report on Internal Controls herein.
In 2016, Xcel Energy implemented the general ledger modules, as well as initiated deployment of work management systems
modules, of a new enterprise resource planning system to improve certain financial and related transaction processes. Xcel Energy is
continuing to implement additional modules including the conversion of existing work management systems to this same system
during 2017. In connection with this ongoing implementation, Xcel Energy is updating its internal control over financial reporting, as
necessary, to accommodate modifications to its business processes and accounting systems. Xcel Energy does not believe that this
implementation will have an adverse effect on its internal control over financial reporting.
Item 9B — Other Information
None.
Item 10 — Directors, Executive Officers and Corporate Governance
PART III
Information required under this Item with respect to Directors and Corporate Governance is set forth in Xcel Energy Inc.’s Proxy
Statement for its 2017 Annual Meeting of Shareholders, which is incorporated by reference. Information with respect to Executive
Officers is included in Item 1 to this report.
Item 11 — Executive Compensation
Information required under this Item is set forth in Xcel Energy Inc.’s Proxy Statement for its 2017 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 2017 Annual Meeting of Shareholders,
which is incorporated by reference.
146
Item 13 — Certain Relationships and Related Transactions, and Director Independence
Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2017 Annual Meeting of Shareholders,
which is incorporated by reference.
Item 14 — Principal Accountant Fees and Services
Information required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2017 Annual Meeting of Shareholders,
which is incorporated by reference.
Item 15 — Exhibits, Financial Statement Schedules
PART IV
1.
2.
3.
*
+
t
PSCo
2.01* t
Consolidated Financial Statements:
Management Report on Internal Controls Over Financial Reporting — For the year ended Dec. 31, 2016.
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, 2016, 2015, and 2014.
Consolidated Statements of Comprehensive Income — For the three years ended Dec. 31, 2016, 2015, and 2014.
Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2016, 2015, and 2014.
Consolidated Balance Sheets — As of Dec. 31, 2016 and 2015.
Consolidated Statements of Common Stockholders’ Equity — For the three years ended Dec. 31, 2016, 2015, and 2014.
Consolidated Statements of Capitalization — As of Dec. 31, 2016 and 2015.
Schedule I — Condensed Financial Information of Registrant.
Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2016, 2015 and 2014.
Exhibits
Indicates incorporation by reference
Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
Certain portions of this agreement have been omitted pursuant to a request for confidential treatment and have been filed
separately with the SEC.
Purchase and Sale Agreement by and between Riverside Energy Center, LLC and Calpine Development Holdings, Inc., as
Sellers, and PSCo, as Purchaser, dated as of April 2, 2010 (excluding certain schedules and exhibits referred to in the
agreement, as amended, which the Registrant agrees to furnish supplemental to the SEC upon request) (Exhibit 2.01 to
Form 10-Q for the quarter ended June 30, 2010 (file no. 001-03034)).
Xcel Energy Inc.
3.01*
Amended and Restated Articles of Incorporation of Xcel Energy Inc., as filed on May 17, 2012 (Exhibit 3.01 to Form 8-K
dated May 16, 2012 (file no. 001-03034)).
3.02*
Xcel Energy Inc. Bylaws, as amended on Feb. 17, 2016 (Exhibit 3.01 to Form 8-K dated Feb. 17, 2016 (file no.
001-03034)).
Xcel Energy Inc.
4.01*
4.02*
4.03*
4.04*
4.05*
Indenture dated Dec. 1, 2000, between Xcel Energy Inc. and Wells Fargo Bank Minnesota, National Association, as
Trustee. (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Dec. 14, 2000).
Supplemental Indenture No. 3 dated June 1, 2006 between Xcel Energy Inc. and Wells Fargo Bank, National Association,
as Trustee, creating $300 million principal amount of 6.5 percent Senior Notes, Series due 2036 (Exhibit 4.01 to Current
Report on Form 8-K (file no. 001-03034) dated June 6, 2006).
Supplemental Indenture No. 4 dated March 30, 2007 between Xcel Energy Inc. and Wells Fargo Bank, National
Association, as Trustee, creating $253.979 million aggregate principal amount of 5.613 percent Senior Notes, Series due
2017 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 30, 2007).
Junior Subordinated Indenture, dated as of Jan. 1, 2008, by and between Xcel Energy Inc. and Wells Fargo Bank, National
Association, as Trustee (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Jan. 16, 2008).
Supplemental Indenture No. 1, dated Jan. 16, 2008, by and between Xcel Energy Inc. and Wells Fargo Bank, National
Association, as Trustee, creating $400 million principal amount of 7.6 percent Junior Subordinated Notes, Series due
2068 (Exhibit 4.02 to Form 8-K (file no. 001-03034) dated Jan. 16, 2008).
147
4.06*
4.07*
4.08*
4.09*
4.10*
4.11*
4.12*
Replacement Capital Covenant, dated Jan. 16, 2008 (Exhibit 4.03 to Form 8-K (file no. 001-03034) dated Jan. 16, 2008).
Supplemental Indenture No. 5 dated as of May 1, 2010 between Xcel Energy Inc. and Wells Fargo Bank, National
Association, as Trustee, creating $550 million principal amount of 4.70 percent Senior Notes, Series due May 15, 2020
(Exhibit 4.01 to Form 8-K (file no. 001-03034) 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, creating $250 million principal amount of 4.80 percent Senior Notes, Series due Sept. 15,
2041 (Exhibit 4.01 to Form 8-K dated Sept. 12, 2011 (file no. 001-03034)).
Supplemental Indenture No. 7 dated as of May 1, 2013 between Xcel Energy and Wells Fargo Bank, NA, as Trustee,
creating $450 million principal amount of 0.75 percent Senior Notes, Series due May 9, 2016 (Exhibit 4.01 to Form 8-K
dated May 9, 2013 (file no. 001-03034)).
Supplemental Indenture No. 8 dated as of June 1, 2015 between Xcel Energy Inc. and Wells Fargo Bank, National
Association, as Trustee, creating $250 million aggregate principal amount of 1.20 percent Senior Notes, Series due June 1,
2017 and $250 million aggregate principal amount of 3.30 percent Senior Notes, Series due June 1, 2025. (Exhibit 4.01 to
Form 8-K dated June 1, 2015 (file no. 001-03034)).
Supplemental Indenture No. 9, dated as of March 1, 2016, by and between Xcel Energy Inc. and Wells Fargo Bank,
National Association, as Trustee, with respect to $400 million aggregate principal amount of 2.40 percent Senior Notes,
Series due March 15, 2021 (Exhibit 4.02 to Form 8-K dated March 8, 2016 (file no. 001-03034)).
Supplemental Indenture No. 10, dated as of Dec. 1, 2016, by and between Xcel Energy Inc. and Wells Fargo Bank,
National Association, as Trustee, creating $300.0 million in aggregate principal amount of 2.60 percent Senior Notes,
Series due March 15, 2022 and $500.0 million aggregate principal amount of 3.35 percent Senior Notes, Series due Dec.
1, 2026 (Exhibit 4.01 to Form 8-K dated Dec. 1, 2016 (file no. 001-03034)).
NSP-Minnesota
4.13*
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 (Exhibit 4.02 to Form 10-K of NSP-Minnesota for the year
ended Dec. 31, 1988 (file no. 001-03034)). Supplemental Indentures between NSP-Minnesota and said Trustee, dated as
follows:
Supplemental Trust Indenture dated June 1, 1995, creating $250 million principal amount of 7.125 percent First Mortgage
Bonds, Series due July 1, 2025 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated June 28, 1995).
Supplemental Trust Indenture dated April 1, 1997, creating $100 million principal amount of 8.5 percent First Mortgage
Bonds, Series due Sept. 1, 2019 and $27.9 million principal amount of 8.5 percent First Mortgage Bonds, Series due
March 1, 2019 (Exhibit 4.47 to Form 10-K (file no. 001-03034) dated Dec. 31, 1997).
Supplemental Trust Indenture dated March 1, 1998, creating $150 million principal amount of 6.5 percent First Mortgage
Bonds, Series due March 1, 2028 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 11, 1998).
Supplemental Trust Indenture dated Aug. 1, 2000 (Assignment and Assumption of Trust Indenture) (Exhibit 4.51 to NSP-
Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
Indenture, dated July 1, 1999, between NSP-Minnesota and Norwest Bank Minnesota, NA, as Trustee, providing for the
issuance of Sr. Debt Securities. (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999).
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 (Assignment and Assumption of Indenture)
(Exhibit 4.63 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
Supplemental Trust Indenture dated July 1, 2002 between NSP-Minnesota and BNY Midwest Trust Company, as
successor Trustee, creating $69 million principal amount of 8.5 percent First Mortgage Bonds, Series due April 1, 2030
(Exhibit 4.06 to NSP-Minnesota Quarterly Report on Form 10-Q (file no. 001-31387) dated Sept. 30, 2002).
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 percent First Mortgage Bonds, Series due July 15, 2035
(Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K (file no. 001-31387) dated July 14, 2005).
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 percent First Mortgage Bonds, Series due June 1, 2036
(Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K (file no. 001-31387) dated May 18, 2006).
Supplemental Trust Indenture, dated June 1, 2007, between NSP-Minnesota and BNY Midwest Trust Company, as
successor Trustee (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated June 19, 2007).
Supplemental Trust Indenture dated March 1, 2008 between NSP-Minnesota and The Bank of New York Trust Company,
NA, as successor Trustee (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated March 11, 2008).
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 percent First Mortgage Bonds, Series due
Nov. 1, 2039 (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated Nov. 16, 2009).
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 1.950 percent First Mortgage Bonds,
Series due Aug. 15, 2015 and $250 million principal amount of 4.850 percent First Mortgage Bonds, Series due Aug. 15,
2040 (Exhibit 4.01 to NSP-Minnesota Form 8-K dated Aug. 4, 2010 (file no. 001-31387)).
4.14*
4.15*
4.16*
4.17*
4.18*
4.19*
4.20*
4.21*
4.22*
4.23*
148
4.24*
4.25*
4.26*
4.27*
4.28*
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 percent First Mortgage Bonds, Series
due Aug. 15, 2022 and $500 million principal amount of 3.40 percent First Mortgage Bonds, Series due Aug. 15, 2042
(Exhibit 4.01 to NSP-Minnesota Form 8-K dated Aug. 13, 2012 (file no. 001-31387)).
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 percent First Mortgage Bonds,
Series due May 15, 2023 (Exhibit 4.01 to NSP-Minnesota Form 8-K dated May 20, 2013 (file no. 001-31387)).
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 percent First Mortgage Bonds,
Series due May 15, 2044. (Exhibit 4.01 to NSP-Minnesota Form 8-K dated May 13, 2014 (file no. 001-31387)).
Supplemental Indenture dated as of Aug. 1, 2015 between NSP-Minnesota and The Bank of New York Mellon Trust
Company, N.A., as successor Trustee, creating $300 million principal amount of 2.20 percent First Mortgage Bonds,
Series due Aug. 15, 2020 and $300 million principal amount of 4.00 percent First Mortgage Bonds, Series due Aug. 15,
2045 (Exhibit 4.01 to Form 8-K of NSP-Minnesota dated Aug. 11, 2015 (file no. 001-31387)).
Supplemental Trust Indenture dated as of May 1, 2016 between NSP-Minnesota and The Bank of New York Mellon Trust
Company, N.A., as successor Trustee, creating $350 million principal amount of 3.600 percent First Mortgage Bonds,
Series due May 15, 2046. (Exhibit 4.01 to Form 8-K of NSP-Minnesota dated May 31, 2016 (file no. 001-31387)).
NSP-Wisconsin
4.29*
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 (Exhibit 4.01 to Registration Statement 33-39831).
4.30*
4.31*
4.32*
4.33*
4.34*
4.35*
4.36*
PSCo
4.37*
4.38*
Supplemental Trust Indenture, dated April 1, 1991 (Exhibit 4.01 to Form 10-Q (file no. 001-03140) for the quarter ended
March 31, 1991).
Supplemental Trust Indenture, dated Dec. 1, 1996, between NSP-Wisconsin and Firstar Trust Company, as
Trustee (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Dec. 12, 1996).
Trust Indenture dated Sept. 1, 2000, between NSP-Wisconsin and Firstar Bank, NA as Trustee (Exhibit 4.01 to Form 8-K
(file no. 001-03140) dated Sept. 25, 2000).
Supplemental Trust Indenture dated Sept. 1, 2003 between NSP-Wisconsin and U.S. Bank National Association,
supplementing indentures dated April 1, 1947 and March 1, 1991 (Exhibit 4.05 to Xcel Energy Form 10-Q (file
no. 001-03034) for the quarter ended Sept. 30, 2003).
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 percent First Mortgage Bonds, Series due Sept. 1,
2038 (Exhibit 4.01 of Form 8-K of NSP-Wisconsin dated Sept. 3, 2008 (file no. 001-03140)).
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 3.700 percent First Mortgage Bonds, Series due Oct. 1, 2042
(Exhibit 4.01 of Form 8-K of NSP-Wisconsin dated Oct. 10, 2012 (file no. 001-03140)).
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 percent First Mortgage Bonds, Series due June 15,
2024. (Exhibit 4.01 of Form 8-K of NSP-Wisconsin dated June 23, 2014 (file no. 001-03140)).
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 (Form 10-Q, Sept. 30, 1993 — Exhibit 4(a)).
Indentures supplemental to Indenture dated as of Oct. 1, 1993, between PSCo and Morgan Guaranty Trust Company of
New York, as trustee:
Dated as of
Nov. 1, 1993
Jan. 1, 1994
Sept. 2, 1994
Nov. 1, 1996
Feb. 1, 1997
April 1, 1998
Aug. 15, 2002
Aug. 1, 2005
Previous Filing: Form; Date or file no.
S-3, (33-51167)
10-K, 1993
8-K, September 1994
10-K, 1996 (001-03280)
10-Q, March 31, 1997 (001-03280)
10-Q, March 31,1998 (001-03280)
10-Q, Sept. 30, 2002 (001-03280)
8-K, Aug. 18, 2005 (001-03280)
149
Exhibit
No.
4(b)(2)
4(b)(3)
4(b)
4(b)(3)
4(a)
4(b)
4.03
4.02
4.39*
4.40*
4.41*
4.42*
4.43*
4.44*
4.45*
4.46*
4.47*
4.48*
4.49*
4.50*
SPS
4.51*
4.52*
4.53*
4.54*
4.55*
4.56*
4.57*
4.58*
4.59*
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 15, 1999, between PSCo and The Bank of New York (Exhibits 4.1
and 4.2 to Form 8-K (file no. 001-03280) dated July 13, 1999).
Financing Agreement between Adams County, Colorado and PSCo, dated as of Aug. 1, 2005 relating to $129.5 million
Adams County, Colorado Pollution Control Refunding Revenue Bonds, 2005 Series A (Exhibit 4.01 to PSCo Current
Report on Form 8-K, dated Aug. 18, 2005, file no. 001-03280).
Supplemental Indenture, dated Aug. 1, 2007, between PSCo and U.S. Bank Trust National Association, as successor
Trustee (Exhibit 4.01 to PSCo Form 8-K (file no. 001-03280) dated Aug. 8, 2007).
Supplemental Indenture dated as of Aug. 1, 2008, between PSCo and U.S. Bank Trust National Association, as successor
Trustee, creating $300 million principal amount of 5.80 percent First Mortgage Bonds, Series No. 18 due 2018 and $300
million principal amount of 6.50 percent First Mortgage Bonds, Series No. 19 due 2038 (Exhibit 4.01 of Form 8-K of
PSCo dated Aug. 6, 2008 (file no. 001-03280)).
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 percent First Mortgage Bonds, Series No. 20 due 2019
(Exhibit 4.01 of Form 8-K of PSCo dated May 28, 2009 (file no. 001-03280)).
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 3.200 percent First Mortgage Bonds, Series No. 21 due 2020
(Exhibit 4.01 of Form 8-K of PSCo dated Nov. 8, 2010 (file no. 001-03280)).
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 percent First Mortgage Bonds, Series No. 22 due 2041 (Exhibit
4.01 to Form 8-K of PSCo dated Aug. 9, 2011 (file no. 001-03280)).
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 percent First Mortgage Bonds, Series No. 23 due 2022 and $500
million principal amount of 3.60 percent First Mortgage Bonds, Series No. 24 due 2042 (Exhibit 4.01 to PSCo’s Form 8-K
dated Sept. 11, 2012 (file no. 001-03280)).
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 percent First Mortgage Bonds, Series No. 25 due 2023 and $250
million principal amount of 3.95 percent First Mortgage Bonds, Series No. 26 due 2043 (Exhibit 4.01 to Form 8-K of
PSCo dated March 26, 2013 (file no. 001-03280)).
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 percent First Mortgage Bonds, Series No. 27 due 2044. (Exhibit
4.01 to Form 8-K of PSCo dated March 10, 2014 (file no. 001-03280)).
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 percent First Mortgage Bonds, Series No. 28 due 2025. (Exhibit
4.01 to Form 8-K of PSCo dated May 12, 2015 (file no. 001-03280)).
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 percent First Mortgage Bonds, Series No. 29 due 2046. (Exhibit
4.01 to Form 8-K of PSCo dated June 13, 2016 (file no. 001-03280)).
Indenture dated Feb. 1, 1999 between SPS and The Chase Manhattan Bank (Exhibit 99.2 to Form 8-K (file
no. 001-03789) dated Feb. 25, 1999).
Third Supplemental Indenture dated Oct. 1, 2003 to the indenture dated Feb. 1, 1999 between SPS and JPMorgan Chase
Bank, as successor Trustee, creating $100 million principal amount of Series C and Series D Notes, 6 percent due 2033
(Exhibit 4.04 to Xcel Energy Form 10-Q (file no. 001-03034) for the quarter ended Sept. 30, 2003).
Fourth Supplemental Indenture dated Oct. 1, 2006 between SPS and The Bank of New York, as successor Trustee
(Exhibit 4.01 to Form 8-K (file no. 001-03789) dated Oct. 3, 2006).
Red River Authority for Texas Indenture of Trust dated July 1, 1991 (Form 10-K, Aug. 31, 1991 — Exhibit 4(b)).
Fifth Supplemental Indenture dated as of Nov. 1, 2008 between SPS and The Bank of New York Mellon Trust Company,
NA, as successor Trustee, creating $250 million principal amount of Series G Senior Notes, 8.75 percent due 2018
(Exhibit 4.01 of Form 8-K of SPS, dated Nov. 14, 2008 (file no. 001- 03789))
Indenture dated as of Aug. 1, 2011 between SPS and U.S. Bank National Association, as Trustee (Exhibit 4.01 to Form 8-
K dated Aug. 10, 2011 (file no. 001-03789)).
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 percent First Mortgage Bonds, Series No. 1 due 2041 (Exhibit 4.02 to Form 8-K
dated Aug. 10, 2011 (file no. 001-03789)).
Sixth Supplemental Indenture dated as of June 1, 2014 between SPS and The Bank of New York Mellon Trust Company,
N.A., as successor Trustee. (Exhibit 4.03 to SPS’ Form 8-K dated June 2, 2014 (file no. 001-03789)).
Supplemental Indenture No. 2 dated as of June 1, 2014 between SPS and U.S. Bank National Association, as Trustee.
(Exhibit 4.06 to SPS’ Form 8-K dated June 2, 2014 (file no. 001-03789)).
150
4.60*
4.61*
Supplemental Indenture No. 3 dated as of June 1, 2014 between SPS and U.S. Bank National Association, as Trustee,
creating $150 million principal amount of 3.30 percent First Mortgage Bonds, Series No. 3 due 2024. (Exhibit 4.02 to
SPS’ Form 8-K dated June 9, 2014 (file no. 001-03789)).
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 percent First Mortgage Bonds, Series No. 4 due 2046. (Exhibit 4.02 to Form 8-K of
SPS dated Aug. 12, 2016 (file no. 001-03789)).
Xcel Energy Inc.
10.01*+ Xcel Energy Inc. Nonqualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K of Xcel Energy (file
no. 001-03034) for the year ended Dec. 31, 2008).
10.02*+ Xcel Energy Senior Executive Severance and Change-in-Control Policy (2009 Amendment and Restatement)
(Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) 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
(Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Form U5B (file
no. 001-03034) dated Nov. 16, 2000).
10.04*
10.05*+ Xcel Energy Inc. Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 (Exhibit 10.17 to
Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.06*+ Amendment dated Aug. 26, 2009 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy
(Exhibit 10.06 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.07*+ Xcel Energy Inc. Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.08 to Form 10-
Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.08*+ Xcel Energy Inc. Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (incorporated
by reference to Appendix A to Schedule 14A, Definitive Proxy Statement to Xcel Energy Inc. (file no. 001-03034) dated
April 6, 2010).
10.09*+ Xcel Energy Inc. 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (incorporated by
reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy Inc. (file no. 001-03034) dated
April 6, 2010).
10.10*+ Stock Equivalent Plan for Non-Employee Directors of Xcel Energy Inc. as amended and restated effective Feb. 23, 2011
(Appendix A to the Xcel Energy Definitive Proxy Statement (file no. 001-03034) filed April 5, 2011).
10.11*+ Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.07 to Form 10-K of Xcel
Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.12*+ First Amendment effective Nov. 29, 2011 to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009
Restatement) (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).
10.13*+ Second Amendment dated Oct. 26, 2011 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy
(Exhibit 10.18 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).
10.14*+ First Amendment dated Feb. 20, 2013 to the Xcel Energy Inc. Executive Annual Incentive Award Plan (as amended and
restated effective Feb. 17, 2010) (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended
March 31, 2013).
10.15*+ Fourth Amendment dated Feb. 20, 2013 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy
(Exhibit 10.02 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013).
10.16*+ First Amendment dated May 21, 2013 to the Xcel Energy Inc. 2005 Long-Term Incentive Plan (as amended and restated
effective Feb. 17, 2010) (Exhibit 10.21 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31,
2013).
10.17*+ Second Amendment dated May 21, 2013 to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009
Restatement) (Exhibit 10.22 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013).
10.18*+ Xcel Energy Inc. 2005 Long-Term Incentive Plan Form of Long-Term Incentive Award Agreement (Exhibit 10.23 to Form
10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2013).
10.19*+ Xcel Energy Inc. 2015 Omnibus Incentive Plan (incorporated by reference to Appendix B to Schedule 14A, Definitive
Proxy Statement to Xcel Energy Inc. (file no. 001-03034) dated April 6, 2015).
10.20*+ Stock Equivalent Program for Non-Employee Directors of Xcel Energy Inc. (As First Effective May 20, 2015) under the
Xcel Energy Inc. 2015 Omnibus Incentive Plan. (Exhibit 10.02 to Form 8-K of Xcel Energy, dated May 26, 2015 (file no.
001-03034).
10.21*+ Form of Xcel Energy Inc. 2015 Omnibus Incentive Plan Award Agreement and Award Terms and Conditions (Restricted
Stock Units and Performance Share Units) under the Xcel Energy Inc. 2015 Omnibus Incentive Plan. (Exhibit 10.03 to
Form 8-K of Xcel Energy, dated May 26, 2015 (file no. 001-03034).
10.22*+ Xcel Energy Inc. 2015 Omnibus Incentive Plan Form of Award Agreement (Exhibit 10.28 to Form 10-K of Xcel Energy
(file no. 001-03034) for the year ended Dec. 31, 2015).
10.23*+ Xcel Energy Inc. Executive Annual Incentive Award Sub-plan pursuant to the Xcel Energy Inc. 2015 Omnibus Incentive
Plan (Exhibit 10.29 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2015).
151
10.24*+ Fifth Amendment dated May 3, 2016 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy
(Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June 30, 2016).
10.25*
Second Amended and Restated Credit Agreement, dated as of June 20, 2016 among Xcel Energy Inc., as Borrower, the
several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America,
N.A. and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association and The Bank of Tokyo-
Mitsubishi UFJ, Ltd., as Documentation Agents. (Exhibit 99.01 to Form 8-K of Xcel Energy dated June 20, 2016 (file no.
001-03034)).
10.26*+ Third Amendment dated Sept. 30, 2016 to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009
10.27+
Restatement) (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2016).
Form of Xcel Energy, Inc. 2015 Omnibus Incentive Plan Award Agreement and Award Terms and Conditions (Restricted
Stock Units and Performance Share Units) under the Xcel Energy Inc. 2015 Omnibus Incentive Plan.
NSP-Minnesota
10.28*
10.29*
10.30*
Ownership and Operating Agreement, dated March 11, 1982, between NSP-Minnesota, Southern Minnesota Municipal
Power Agency and United Minnesota Municipal Power Agency concerning Sherburne County Generating Unit No. 3
(Exhibit 10.01 to Form 10-Q for the quarter ended Sept. 30, 1994 (file no. 001-03034)).
Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota (Exhibit 10.01 to NSP-
Wisconsin Form S-4 (file no. 333-112033) dated Jan. 21, 2004).
Second Amended and Restated Credit Agreement, dated as of June 20, 2016 among NSP-Minnesota, as Borrower, the
several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America,
N.A. and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association and The Bank of Tokyo-
Mitsubishi UFJ, Ltd., as Documentation Agents. (Exhibit 99.02 to Form 8-K of Xcel Energy dated June 20, 2016 (file no.
001-03034)).
NSP-Wisconsin
10.31*
Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota (Exhibit 10.01 to
Form S-4 (file no. 333-112033) dated Jan. 21, 2004).
10.32*
Second Amended and Restated Credit Agreement, dated as of June 20, 2016 among NSP-Wisconsin, as Borrower, the
several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America,
N.A. and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association and The Bank of Tokyo-
Mitsubishi UFJ, Ltd., as Documentation Agents. (Exhibit 99.05 to Form 8-K of Xcel Energy dated June 20, 2016 (file no.
001-03034)).
PSCo
10.33*
10.34*
10.35*
10.36*
10.37*
SPS
10.38*
Amended and Restated Coal Supply Agreement entered into Oct. 1, 1984 but made effective as of Jan. 1, 1976 between
PSCo and Amax Inc. on behalf of its division, Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1984 —
Exhibit 10(c)(1)).
First Amendment to Amended and Restated Coal Supply Agreement entered into May 27, 1988 but made effective Jan. 1,
1988 between PSCo and Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1988 — Exhibit 10(c)(2)).
Proposed Settlement Agreement excerpts, as filed with the CPUC (Exhibit 99.02 to Form 8-K of Xcel Energy (file
no. 001-03034) dated Dec. 3, 2004).
Settlement Agreement among PSCo and Concerned Environmental and Community Parties, dated Dec. 3, 2004
(Exhibit 99.03 to Form 8-K of Xcel Energy (file no. 001-03034) dated Dec. 3, 2004).
Second Amended and Restated Credit Agreement, dated as of June 20, 2016 among PSCo, as Borrower, the several
lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A.
and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association and The Bank of Tokyo-
Mitsubishi UFJ, Ltd., as Documentation Agents. (Exhibit 99.03 to Form 8-K of Xcel Energy dated June 20, 2016 (file no.
001-03034)).
Coal Supply Agreement (Harrington Station) between SPS and TUCO, dated May 1, 1979 (Form 8-K (file
no. 001-03789), May 14, 1979 — Exhibit 3).
10.39* Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO, dated July 1, 1978 (Form 8-K
10.40*
10.41*
(file no. 001-03789), May 14, 1979 — Exhibit 5(A)).
Guaranty of Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO (Form 8-K (file
no. 001-03789) May 14, 1979 — Exhibit 5(B)).
Coal Supply Agreement (Tolk Station) between SPS and TUCO dated April 30, 1979, as amended Nov. 1, 1979 and
Dec. 30, 1981 (Form 10-Q for the quarter ended Feb. 28, 1982 (file no. 001-03789) — Exhibit 10(b)).
152
10.43*
10.44*
10.42* Master Coal Service Agreement between Wheelabrator Coal Services Co. and TUCO dated Dec. 30, 1981, as amended
Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q for the quarter ended Feb. 28, 1982 (file no. 001-03789) — Exhibit 10(c)).
Power Purchase Agreement dated May 23, 1997 between Borger Energy Associates, L.P, and SPS.
Second Amended and Restated Credit Agreement, dated as of June 20, 2016 among SPS, as Borrower, the several lenders
from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and
Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association and The Bank of Tokyo-
Mitsubishi UFJ, Ltd., as Documentation Agents. (Exhibit 99.04 to Form 8-K of Xcel Energy dated June 20, 2016 (file no.
001-03034)).
Xcel Energy Inc.
12.01
21.01
23.01
24.01
31.01
31.02
32.01
99.01
101
Statement of Computation of Ratio of Earnings to Fixed Charges.
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.
Statement pursuant to Private Securities Litigation Reform Act of 1995.
The following materials from Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2016 are
formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the
Consolidated Statements of Comprehensive Income, (iii) the Consolidated Statements of Cash Flows, (iv) the
Consolidated Balance Sheets, (v) the Consolidated Statements of Common Stockholders’ Equity, (vi) Consolidated
Statements of Capitalization, (vii) Notes to Consolidated Financial Statements, (viii) document and entity information,
(ix) Schedule I, and (x) Schedule II.
153
SCHEDULE I
Income
XCEL ENERGY INC.
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(amounts in thousands, except per share data)
Year Ended Dec. 31
2016
2015
2014
Equity earnings of subsidiaries. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,198,556
1,198,556
Total income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,045,788
1,045,788
$ 1,077,714
1,077,714
Expenses and other deductions
22,128
Operating expenses. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(3,047)
Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
115,473
Interest charges and financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
134,554
Total expenses and other deductions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,064,002
Income before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(59,377)
Income tax benefit. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,123,379
$
19,865
(1,242)
91,801
110,424
935,364
(49,121)
984,485
19,756
(537)
84,830
104,049
973,665
(47,641)
$ 1,021,306
Other Comprehensive Income
Pension and retiree medical benefits, net of tax of $(2,759), $(2,777), and $(2,528)
respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(4,312) $
3,711
Derivative instruments, net of tax of $2,344, $1,764, and $1,390, respectively. . . . . . . . . .
—
Other, net of tax of $0, $0 and $21, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(601)
Other comprehensive (loss) income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Comprehensive income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,122,778
$
(4,380) $
2,766
—
(1,614)
982,871
(4,022)
2,125
33
(1,864)
$ 1,019,442
Weighted average common shares outstanding:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
508,794
509,465
507,768
508,168
503,847
504,117
Earnings per average common share:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash dividends declared per common share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2.21
2.21
1.36
$
1.94
1.94
1.28
2.03
2.03
1.20
See Notes to Condensed Financial Statements
154
XCEL ENERGY INC.
CONDENSED STATEMENTS OF CASH FLOWS
(amounts in thousands)
Year Ended Dec. 31
2016
2015
2014
Operating activities
Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
816,717
$
704,823
$
842,832
Investing activities
Capital contributions to subsidiaries. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investments in the utility money pool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Return of investments in the utility money pool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(414,246)
(1,879,500)
1,879,500
—
(414,246)
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 provided by (used in) financing activities. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net change in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents at beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(516,000)
1,538,762
(703,979)
—
(32,209)
(680,521)
(8,690)
(402,637)
(166)
517
351
$
(820,382)
(971,200)
987,200
(16)
(804,398)
203,500
495,449
—
7,011
—
(606,574)
—
99,386
(189)
706
517
(422,459)
(1,148,000)
1,204,000
—
(366,459)
(95,500)
—
—
180,798
—
(561,411)
—
(476,113)
260
446
706
$
See Notes to Condensed Financial Statements
155
XCEL ENERGY INC.
CONDENSED BALANCE SHEETS
(amounts in thousands)
Assets
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Accounts receivable from subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investment in subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Liabilities and Equity
Current portion of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Dividends payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Short-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commitments and contingencies
Capitalization
Long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Common stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total liabilities and equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
See Notes to Condensed Financial Statements
Dec. 31
2016
2015
$
$
$
351
363,617
10,007
373,975
13,903,657
163,795
14,067,452
14,441,427
250,000
172,456
68,000
17,537
507,993
37,734
37,734
517
315,866
35,701
352,084
13,236,758
163,237
13,399,995
13,752,079
450,000
162,410
584,000
80,526
1,276,936
35,694
35,694
2,874,851
11,020,849
13,895,700
14,441,427
$
1,838,529
10,600,920
12,439,449
13,752,079
156
NOTES TO CONDENSED FINANCIAL STATEMENTS
Incorporated by reference are Xcel Energy’s consolidated statements of common stockholders’ equity and OCI 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.
Related Party Transactions — Xcel Energy Inc. presents its related party receivables net of payables. Accounts receivable and
payable with affiliates at Dec. 31 were:
(Thousands of Dollars)
NSP-Minnesota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NSP-Wisconsin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PSCo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SPS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Xcel Energy Services Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Xcel Energy Ventures Inc.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other subsidiaries of Xcel Energy Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2016
2015
Accounts
Receivable
Accounts
Payable
Accounts
Receivable
Accounts
Payable
58,642
13,969
131,680
30,897
92,809
17,060
18,560
363,617
$
$
— $
—
—
—
—
—
—
— $
58,952
17,391
114,524
21,357
73,054
20,003
10,585
315,866
$
$
—
—
—
—
—
—
—
—
Dividends — Cash dividends paid to Xcel Energy Inc. by its subsidiaries were $923 million, $784 million and $857 million for the
years ended Dec. 31, 2016, 2015 and 2014, respectively. These cash receipts are included in operating cash flows of the condensed
statements of cash flows.
Money Pool — Xcel Energy received FERC approval 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. The following
tables present money pool lending for Xcel Energy Inc.:
(Amounts in Millions, Except Interest Rates)
Lending limit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Loan outstanding at period end . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average loan outstanding. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Maximum loan outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average interest rate, computed on a daily basis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average interest rate at end of period. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Money pool interest income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Three Months Ended
Dec. 31, 2016
250
—
77
211
0.80%
N/A
0.2
157
(Amounts in Millions, Except Interest Rates)
Lending limit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
Year Ended
Dec. 31, 2016
Year Ended
Dec. 31, 2015
Year Ended
Dec. 31, 2014
250
—
66
211
0.69%
N/A
0.5
$
$
250
—
27
141
0.42%
N/A
0.1
$
$
250
16
25
250
0.22%
0.45
0.1
See Xcel Energy’s notes to the consolidated financial statements in Part II, Item 8 for other disclosures.
158
SCHEDULE II
XCEL ENERGY INC. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DEC. 31, 2016, 2015 AND 2014
(amounts in thousands)
Additions
Balance at
Jan. 1
Charged to
Costs and
Expenses
Charged to
Other
Accounts
(a)
Deductions
from
Reserves
(b)
Balance at
Dec. 31
Allowance for bad debts:
2016. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2015. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NOL and tax credit valuation allowances:
2016. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2015. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
51,888
57,719
53,107
27,679
3,402
3,263
$
$
38,960
36,074
42,765
3,175
2,064
139
$
$
10,570
11,784
14,067
34,637
24,784
—
$
$
50,595
53,689
52,220
7,976
2,571
—
50,823
51,888
57,719
57,515
27,679
3,402
(a)
(b)
Accrual of valuation allowance for North Dakota ITC, offset to regulatory liability.
Reductions to valuation allowances for North Dakota ITC carryforwards primarily due to a consolidated adjustment to the regulatory liability accrual referenced
above. Reductions to valuation allowances for NOL carryforwards primarily due to changes in forecasted taxable income.
159
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.
SIGNATURES
Feb. 24, 2017
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
*
*
*
*
*
*
*
*
*
*
Gail Koziara Boudreaux
Richard K. Davis
Richard T. O’Brien
Christopher J. Policinski
James T. Prokopanko
A. Patricia Sampson
James J. Sheppard
David A. Westerlund
Kim Williams
Timothy V. Wolf
Chairman, President, Chief Executive Officer and Director
(Principal Executive Officer)
Executive Vice President, Chief Financial Officer
(Principal Financial Officer)
Senior Vice President, Controller
(Principal Accounting Officer)
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
*By:
/s/ ROBERT C. FRENZEL
Robert C. Frenzel
Attorney-in-Fact
160
On the Cover
Wind towers twirl over the corn fields surrounding the Courtenay Wind Farm in North
Dakota. This is the first company-owned wind farm that Xcel Energy has built from the
ground up. The project generates electricity to power more than 100,000 homes and brought
significant economic development to Courtenay, North Dakota and the surrounding area.
Company Description
Xcel Energy is a major U.S. electric and natural gas company with annual revenues of
$11 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.
Financial Highlights
Xcel Energy Earnings Per Share
Dollars per share (diluted)
2015
2016
Total GAAP earnings per share
1.94
2.21
Ongoing earnings per share
2.09
2.21
Dividends annualized
1.28
1.36
Stock price (close)
35.91
40.70
Assets (millions)
38,821
41,155
Book value per common share
20.89
21.73
3
0
.
2
3
0
.
2
4
9
.
1
9
0
.
2
1
2
.
2
1
2
.
2
2014
2015
2016
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 Form 10-K.
Some sections in this annual report, including the letter to shareholders, contain forward-looking statements. For a discussion of factors
that could affect operating results, please see management’s discussion and analysis listed in the table of contents of the Form 10-K.
2 Xcel Energy | 2016
Shareholder Information
Headquarters
414 Nicollet Mall, Minneapolis, MN 55401
Website
xcelenergy.com
Stock Transfer Agent
Wells Fargo 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 New York Stock Exchange (NYSE) 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 Tara Stoffel, assistant corporate secretary,
at 612.215.5391 or email tara.m.heine@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 2016. It has also filed with the
New York Stock Exchange the CEO certification for 2016 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.
Xcel Energy Board of Directors
Gail Koziara Boudreaux 2, 4
CEO and Founder, GKB Global Health, LLC
Richard K. Davis 2,3
Chairman and CEO, U.S. Bancorp
Ben Fowke
Chairman, President and CEO
Xcel Energy Inc.
Richard T. O’Brien 1, 4
Independent Consultant
Christopher J. Policinski 3
Lead Independent Director
President and CEO
Land O’ Lakes, Inc.
James Prokopanko 1, 4
Retired President and CEO
The Mosaic Company
A. Patricia Sampson 1, 3
CEO, President and Owner
The Sampson Group, Inc.
James J. Sheppard 2, 4
Independent Consultant
David A. Westerlund 2, 3
Retired Executive Vice President,
Administration and Corporate Secretary
Ball Corporation
Kim Williams 1, 3
Retired Partner
Wellington Management Company LLP
Timothy V. Wolf 1, 4
President
Wolf Interests, Inc.
Daniel Yohannes*
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
* Joined board on March 1, 2017
Fiscal Agents
XCEL ENERGY INC.
Transfer Agent, Registrar, Dividend
Distribution, Common Stock
Wells Fargo Shareowner Services,
1110 Centre Pointe Curve, Suite 101
Mendota Heights, MN 55120
Trustee – Bonds
Wells Fargo Bank, N.A., Corporate Trust Services
150 East 42nd Street, 40th Floor,
New York, NY 10017
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2016 Annual Report
ALWAYS DELIVERING.
xcelenergy.com | © 2017 Xcel Energy Inc. | Xcel Energy is a
registered trademark of Xcel Energy Inc. | 17-02-102
1 Xcel Energy | 2016