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The business of power for utility executives
Jul|Aug|2014
volume 92|04
2 | ELECTRICLIGHT&POWER Jul|Aug|2014
Events 4
Commentary 6
COLUMNS
Customer Service: Utility Style 8
Cracker Jack Moments
by Penni McLean-Conner,
Northeast Utilities
Economic Inquiry 10 Who’s on First?
Ongoing Challenges
to FERC’s Jurisdiction
by Tanya Bodell, Energyzt
SECTIONS
Features
How Regulation Can Drive Innovation 12
by Michael Corvese,
Thermo Fisher Scientific
EPA’s Clean Power Plan 14
by Cameron Prell,
Crowell & Moring LLP
Finance
Legal Issues—The 6 Deadly Memes 16
of Tree and Power Line Conflicts
by Tracy Reichmuth, Crowell & Moring LLP,
and Stephen R. Cieslewicz,
CN Utility Consulting
Generation
Coal-fired Generation Update 20
by Teresa Hansen, editor in chief
Case Study: ScottishPower’s Strategy 24
for Asset Management and Process Safety
by Sandra DiMatteo, Bentley Systems
Renewables/Sustainability 26 Energy Storage Going Mainstream—
Valuation and Procurement
by Paul Maxwell, Colette Lamontagne
and Jay Paidipati, Navigant
28 Intelligent Energy Storage—
Key to Unlocking the Smart Grid
by John Jung, Greensmith Energy
Management Systems Inc.
IT/CIS & CRM30 How to Transform Data Into Value-added
Information Through Analytics
by Bijoy Chatt and Sam Sankaran, Navigant
39 Momentum in Utility Education
by Rod Litke, CS Week
T&D Operations32 Intelligent Undergrounding—
Burying Highly Reliable Cable
When, Where it Makes Sense
by Damien Polansky and Brent Richardson, Dow Electrical & Telecommunications
34 How to Assess the Benefits
of Transmission Investment
by Dave Bryant, CTC Global Corp.
Energy Efficiency & Demand Response36 Energy-efficient Buildings,
Analytics and Con Edison
by Rebecca Craft, Con Edison,
and Bennett Fisher, Retroficiency
Notable Quotables
40 Customer Opinion, Fossil Fuels
Top EEI Conversations
Quotes from Warren Buffett, Ted Craver,
Tom Fanning and Nick Akins
12
14
16
34
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E V E N T S
ELECTRICLIGHT& POWER is the official supporting publication of
Feb. 3-5, 2015 : San Diego Convention Center
ELECTRICLIGHT& POWER is the official print publication of
Feb. 2, 2015 : San Diego
ELECTRICLIGHT& POWER is the official print publication of
April 27 – May 1, 2015 : Char lotte (North Carolina) Convention Center
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4 | ELECTRICLIGHT&POWER Jul|Aug|2014
AUGUST
20-22
COAL-GEN
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Commentary
Teresa Hansen, editor in chief
Is Less Carbon Worth the Risk?
The electricity generation industry is in transition. As you’ll read in my article “King Coal isSoon to be Dethroned” beginning on Page 20, some 20 percent (60 GW) of U.S. coal-fired
power plants will be retired in the next few years.
Low natural gas prices are contributing to these retirements, but natural gas also will allow
much of the retired generation capacity to be replaced with combined-cycle gas turbines.
Electricity generators and consumers should be thankful that gas producers developed tech-
nology that can be used to extract shale gas because it is key to keeping electricity rates reasonable as coal-fired
plants are retired.
Because of space limitations, I wasn’t able to include everything I uncovered when researching coal genera-
tion, so I want to share some of it with you in this column.
I attended the Edison Electric Institute’s (EEI) Annual Convention in early June, where I heard several large
investor-owned utility executives discuss the changing generation mix and the need to retire many coal plants to
adhere to proposed Environmental Protection Agency regulations; most notable, the recently released (June 2)proposed clean power standards for existing power plants 111(d) rule.
American Electric Power (AEP) Chairman, President and CEO Nicholas Akins said AEP plans to retire
6,600 MW of coal plants by late 2015 to help it meet the proposed requirements of the 111(d) rule. The utility is
one of the nation’s largest CO2 emitters,
Although such retirements will drop AEP’s CO2 emissions, they could create another issue: unreliable power
supply. Fewer operating coal-fired plants could mean that AEP cannot provide needed electricity in extreme
conditions.
Supply challenges created in AEP’s service territory during winter’s polar vortex could have caused big
problems had the coal plants AEP has targeted for retirement not been available.
“During the polar vortex, 89 percent of our coal that is slated to retire in mid- to late 2015 ran at more than
50 percent capacity,” Akins said during the EEI conference. “We didn’t have a prayer of getting enough natural
gas because of pipeline infrastructure (constraints) and customer heating was the priority, and you can’t cut muchcustomer demand in the winter.”
Akins spoke about the increased winter demand caused by the polar vortex during testimony before the Sen-
ate Energy and Natural Resources Committee.
“This country did not just dodge a bullet—we dodged a cannonball,” he said during the testimony.
AEP is not the only utility concerned about unreliable power supply. Southern Co. Chairman, President and
CEO Tom Fanning said his company faced issues similar to AEP’s during the polar vortex. When temperatures
in the Deep South dipped to levels that are pretty much unheard of, Southern Co. called on 75 percent of its coal
units that are scheduled for closure, Fanning said.
The National Coal Council (NCC) performed a study at the request of Energy Secretary Ernest Moniz that
looked at the valuable role coal generation played this past winter. The NCC found that nationwide, more than 90
percent of the increase in power generation in January and February 2014 vs. January and February 2013 came
from the existing coal fleet.Retiring these coal-fired plants could create a major problem for many utilities that have relied on coal-fired
generation to meet capacity demand.
Less CO2 in the air can’t be bad, but is it worth not having enough capacity to provide reliable electricity?
It’s something to ponder.
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C O L U M N
8 | ELECTRICLIGHT& POWER Jul|Aug|2014
A u t h o r
Penni McLean-Conner
is the chief customer
officer at Northeast
Utilities, the largestenergy delivery
company in New
England. A registered
professional engineer,
McLean-Conner is
active in the utility
industry, serving on
several boards of
directors including CS
Week and the American
Council for an Energy
Efficient Economy. Herlatest book, “Energy
Efficiency: Principles
and Practices,” is
available at www.
pennwellbooks.com.
Reach her at penelope.
CS Week 2014 was held in early May
in San Antonio. The Executive Summit,which kicked off the week, attracted a
record-breaking 133 attendees.
The Executive Summit brings
together chief information technology
and customer service officers in a
highly charged, productive environment
to foster the exchange of ideas and
practical solutions.
The 2014 summit featured 11 ses-
sions that covered strategic and tacti-
cal topics, ranging from enterprise risk
management to information technologymobile strategy, smart infrastructure and
social media. But the highest-rated ses-
sion was Creating Cracker Jack Moments.
The session explored how utilities
are providing Cracker Jack moments to
their customers. Three utility customer
service executives spoke: San Diego Gas
and Electric (SDG&E) Vice President of
Customer Service and Chief Customer
Privacy Officer Caroline Winn, Con Edi-
son Senior Vice President of Customer
Operations Marilyn Caselli and DukeEnergy Senior Vice President and Chief
Customer Officer Gayle Lanier.
During the next few columns, I will
explore the Cracker Jack moments pro-
vided by these utilities. Let’s start explor-
ing the Cracker Jack moments provided
by SDG&E, one of Sempra Energy’s
regulated California utilities. Winn over-
sees all customer-related activities. She
shared several practices, including new
mover services, the Manage-Act-Save
platform and tailored treatments for tar-
geted customer segments.
New Mover Services
SDG&E, like all utilities, helps custom-
ers who are moving into the service terri-
tory get service connected. But SDG&E
is going further than just setting up the
gas and electric service for customers.
It offers “Make Moving Easier” and
connects customers with its partner, All
Connect. This provides customers one
place to transfer home phone, Internet,
TV and utility services, and it’s offeredonline and over the phone.
New mover services are not new to
the utility industry. All Connect provides
these services to many U.S. utilities.
Utilities have found that by providing this
service, they enhance customers’ overall
satisfaction.
From the customer perspective, the
benefit is one-stop shopping. Winn shared
comments from customers who noted the
benefit of one-stop shopping.
For example, customer Walter S.wrote to SD&E, “I have been in the mili-
tary for 24 years and moved eight times.
This was by far the easiest of them all.”
Sarah W. said, “The convenience of
having someone else understand all of my
requirements and price for me versus hav-
ing to call multiple different providers to
include price and coverage was fantastic.”
Manage-Act-Save
The Manage-Act-Save program began
in 2013 with SDG&E’s high energy
use customers. This program featuresproactive outreach to targeted custom-
ers and provides them the opportu-
nity for a chance to win prizes and gift
cards just for saving energy. Customers
earned rewards for saving energy and
could redeem the awards at their favorite
stores. SDG&E partnered with Starbucks
and Best Buy among others.
Customer feedback on the program
was fantastic.
Wendy M. said, “I think for me the
benefit was the first reward I received, itwas a WOW. I actually got something
in return for my effort, and that in itself
made it fun.”
Tailored Programs
In 2013, SDG&E was in the midst of rate
increases. To help mitigate the impact,
Winn said, her team reached out proac-
tively to customers who would be most
affected and offered programs and ser-
vices that could be of direct benefit, such
as discount rates, medical baseline assis-tance programs or energy efficiency pro-
grams. The proactive outreach used mul-
tiple channels including social media.
As with the others, customer feed-
back was positive. One customer, Ger-
old, was so positively affected by the
energy bill discount that he agreed to be
featured in a short YouTube video to dis-
cuss his experience.
Winn said that in Chip Bell’s book
“9 1/2 Principles of Innovative Service,”
Bell writes that “while the prize haslittle commercial value, its emotional
value was priceless. Surprise breaks the
monotony of the ho-hum, communicates
a caring attitude, and fosters an infec-
tious spirit that customers cannot wait to
narrate to others.”
SDG&E is delivering a lot of
Cracker Jack moments, evidenced by the
number of customers’ narrating their sat-
isfaction.
Cracker Jack Moments
by Penni McLean-Conner, Northeast Utilities
©canstockphoto.com/happystock
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C O L U M N
A u t h o r
10 | ELECTRICLIGHT& POWER Jul|Aug|2014
Tanya Bodell
is executive
director of Energyzt,
a collaboration ofenergy experts intent
on understanding the
impacts of energy
integration. Reach her
at 617-416-0651
or tanya.bodell@
energyzt.com.
“God forbid that Judges
upon their oath should
make resolutions to
enlarge jurisdiction.”— William Cowper
(1715), as cited in
the Dictionary of
Legal Quotations
Challenging jurisdiction has be-
come the playbook defense strategy for
market participants adversely affected
by Federal Energy Regulatory Commis-
sion (FERC) decisions.
The game of questioning
FERC’s authority is being played out
predominantly in the D.C. Circuit
Court, which recently issued rulings
about FERC’s jurisdiction over market
manipulation, demand response andcapacity markets. Although the direction
of these decisions has been mixed,
FERC intends to continue to protect its
jurisdictional plate. Will we see a grand
slam or will FERC go down swinging?
I Say Who’s on First
Historically contested on the basis of
state rights vs. federalism, a new chal-
lenger to FERC crossed federal agency
lines when the Commodity Futures
Trading Commission (CFTC) filed apetition in support of Brian Hunter’s
claim against FERC jurisdiction in
April 2012. Hunter, a former natural
gas trader, was accused of market ma-
nipulation for trading activities during
certain periods in 2006, costing Ama-
ranth Advisors $7 billion and resulting
in its demise. After CFTC’s initial ef-
forts to bring Hunter to justice, FERC
flexed its muscle under the Energy
Policy Act of 2005 and fined him $30
million for market manipulation in2011, arguing that Hunter’s trades in
natural gas futures markets affected
physical markets, thereby falling under
FERC jurisdiction. In the first fully liti-
gated proceeding under section 4A of
the Natural Gas Act, FERC struck out.
The D.C. Circuit Court ruled March 15,
2013, that FERC did not have authority
to fine Hunter, upholding the CFTC’s
exclusive authority over all transactions
involving commodity futures contracts.
What’s on Second
FERC’s jurisdiction was challenged
again after issuance of FERC Order No.
745, which set the price that indepen-
dent system operators must pay demand
response. The Electric Power Supply
Association (EPSA) along with other
industry organizations supported by 21
prominent energy economists as amici
curiae challenged FERC jurisdiction
with a lawsuit at the D.C. Circuit Court.On May 23, 2014, the majority sided
with EPSA 2-1 and ruled that FERC had
acted beyond its jurisdictional authority
by attempting to set prices for retail cus-
tomers (and further noted that the price
FERC had set was unjust and discrimi-
natory). FERC immediately petitioned
the D.C. Circuit Court for an en banc
rehearing and noted that the request
was warranted, given the ruling, which
“vacated a vital rule of national impor-
tance” and “severely departs” from priorrulings’ regarding jurisdiction granted
to FERC under the Federal Power Act.
The D.C. Circuit Court has asked for a
reply from challengers.
I Don’t Know’s on Third
FERC finally hit one home with a re-
cent D.C. Circuit Court decision. Some
market participants had filed a petition
against FERC orders related to the Inde-
pendent System Operator-New England
Forward Capacity Market and raisedconcerns’ regarding FERC jurisdiction.
On July 8, 2014, the D.C. Circuit Court
denied the petitions for review, holding
that FERC’s ratemaking authority clear-
ly extends to capacity market pricing
parameters and FERC had exercised its
oversight appropriately. This decision—
less than seven weeks after the court’s
decision to vacate FERC’s decision re-
garding demand response resources in
wholesale energy markets—indicates
the fine line over which the D.C. CircuitCourt can cry foul.
I Said I Don’t Give a Darn!
Despite continuing challenges, FERC
is not going to take its enforcement bat
and go home. Two months after the D.C.
Circuit Court issued the Hunter deci-
sion, FERC assessed a $488 million fine
against Barclays for market manipula-
tion in western electricity markets; Bar-
clays subsequently challenged FERC
jurisdiction over financial derivativesbefore a California federal judge. Five
months after Hunter, FERC issued a
show cause order against BP for manip-
ulation of physical gas markets in Texas;
BP filed a motion to dismiss, including
a challenge to FERC’s authority over in-
trastate natural gas transactions, which
FERC recently denied. At the begin-
ning of 2014, FERC and CFTC joined
teams and signed two memoranda of
understanding that address overlapping
jurisdiction, promise to share informa-tion, and look to coordinate agency en-
forcement activities across jurisdictional
lines—a critical concession given the in-
creasingly sophisticated trading hedges
that combine financial and physical
positions. It is too soon to say how the
series will end. More likely than not,
FERC will continue to win some and
lose some, clearly defining its ability to
oversee integrating energy markets in
the process.
Who’s on First? Ongoing Challengesto FERC’s Jurisdiction
by Tanya Bodell, Energyzt
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12 | ELECTRICLIGHT& POWER Jul|Aug|2014
Feature
This article was ready to submit weeks before the
Environmental Protection Agency (EPA) announced its June
2 Clean Power Plan. It will take some time to analyze the
impact of the proposed carbon rules, but until we know more,
our existing premise still holds: Extensive dialogue takes
place before, during and after regulations are implemented,
and it’s best to withhold judgment until we can see the long-
term effects of implementation.
In other words, we’ll learn more about the Clean PowerPlan in the coming months, so we’ll hold off on discussing
these newest regulations for now.
The new 111(d) rules and other EPA regulations apply
only to U.S. businesses, but remember: This is a global
issue. Most governments worldwide place at least some
restrictions on the emissions of utilities that operate within
their borders, and regulations in these countries are at varying
levels of maturity. What’s common, however, is that although
regulations play an important role in protecting public health
and the environment, they also challenge utilities that must
operate under them. But these challenges are not the only
story with environmental regulation.On its website, the EPA outlines myriad ways that
compliance with the Clean Air Act has benefitted society, from
“fewer premature deaths” to “better worker productivity.”
It concludes, “The Act has created market opportunities
that have helped to inspire innovation in cleaner
technologies—technologies in which the U.S. has become a
global market leader.”
Regulation burdens industry, especially in the short
run, but it also challenges the status quo and provides an
opportunity for long-term leaders to emerge. Yes, many
benefits of regulation accrue outside the core industry to those
who provide the new compliance services and technologies,
but benefits do accrue to industry in the form of enhanced
reputation and a prominent seat at the table to help design a
future where their leadership can endure.
A History of Regulation and Innovation
To argue that the Clean Air Act of 1970 disrupted the status
quo in the U.S. utility market would be an understatement.
The focus on the six criteria pollutants—sulfur dioxide(SO
2), nitrogen oxides (NO
X), ozone (O
3), carbon monoxide
(CO), particulate matter (PM) and lead (Pb)—gave the EPA
purview over nearly every domestic power producer. It was
sweeping and unprecedented.
Since 1970, many industries have been affected by the
by Michael Cor vese, Thermo Fisher Scientific
Michael Corvese is
director of business
development,
environmental and
process monitoring at Thermo Fisher Scientific.
A u t h o r
REGULATIONInnovation
How Can
Drive
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ELECTRICLIGHT& POWER | 13Jul|Aug|2014
FeatureClean Air Act, from new automobile standards to the removal of lead
from gasoline. Changes in these industries addressed Pb and CO
levels, but achieving reductions in SO2 and NO
X fell to the power
industry through regulations such as the Acid Rain Program in 1990,
which led to one of the first cap-and-trade programs and an entirely
new paradigm for energy economics.
Meanwhile, the power industry was busy developing newtechnologies for environmental monitoring, an effort that featured
regular dialogue among regulators and industry that led to new
compliance methods that were less onerous and costly. An early
example of this involves measurement of particulate emissions,
which originally involved taking readings of the opacity of the stack
gas. The EPA recognized the need for a less quantitative solution,
so it worked with private industry and academia to develop optical
instruments that measured the transmittance of light to determine
stack gas contents.
More recently, new EPA rules such as the Mercury and Air Toxics
Standards (MATS), due to come into effect in 2015, drove the rapid
development of particulate matter continuous emissions monitoringsystems (PM CEMS), which use more modern technologies such as
tapered element oscillating microbalance (TEOM). TEOM samplers
operate continuously, and this innovation, produced in part through
collaboration, provides significant savings over prior technologies.
What’s clear is the EPA hasn’t regulated from on high; it has
worked closely with parties involved to drive innovation that would
reduce the cost and impact of compliance.
Monitoring Expands Around the Globe
The EPA model can be seen in action outside the U.S. China, for
example, has been attacking air pollution aggressively, and the EPA’s
influence within the national Chinese Ministry of EnvironmentalProtection (MEP) and provincial Chinese Environmental Monitoring
Centers (EMC) is well-known. This has provided yet another
opportunity for regulation to lead to innovation. When China adopted
EPA-like standards for SO2 and NO
X, for example, the requirements
were far from a mystery to Chinese industry. They were prepared and
could plan proactively for implementation, and this enabled a much
more efficient and cost-effective rollout for utilities.
China also is working to address PM 2.5. This criteria pollutant,
primarily made of heavy metals and released into the atmosphere in
the form of fly ash, is associated with a wide range of adverse health
effects. Because coal-fired power plants produce a significant amount
of PM 2.5, the Chinese government announced a major measure in2013 to cut coal’s percentage of the total energy mix to below 65
percent by 2017—down from 66.8 percent in 2012. PM and other
pollutants from coal have created significant demand for pollution
measurement and control technology, driving the development of
alternative, lower-polluting energy sources.
Balancing Regulatory Challenge and Opportunity
Regardless of your position on regulation, there’s more to it than
many realize. Extensive dialogue takes place before, during and after
regulations are implemented that doesn’t become apparent until years
later, much like the benefits. From our perspective over the years,
regulators don’t trivialize the massive costs, business impacts are
weighed and great care is taken to ensure that technology exists to help
industry meet the advanced monitoring and control requirements. In
other words, there appears to be an effort to strike a balance betweenthe need to serve society and businesses’ ability to grow.
Power companies that actively participate in the industry
dialogue gain an advantage over those that do not. Although they’re
helping shape policy that is unquestionably onerous in the near
term, they also are doing long-range planning. Regulation is more
than just a burden; it’s also an impetus to test what’s coming and
what’s possible. And by working together with all key stakeholders,
public and private, today’s power industry leaders can ensure that,
among other things, compliance requirements are barriers to entry
that discriminate against less vigilant and innovative companies that
are unlikely to be in this business for the long haul.
Innovative power companies can use regulations and compliance requirements totheir advantage and become industry leaders in the process.
The implementation of new regulations, such as the EPA’s Clean Power Plan, canbe an expensive burden for power plants when it comes to purchasing necessary
equipment, but it also can spark technological advances.
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14 | ELECTRICLIGHT& POWER Jul|Aug|2014
Feature
This summer’s highly anticipated proposal from the Environ-
mental Protection Agency (EPA) to regulate carbon dioxide
(CO2) emission from existing fossil fuel power plants already
has raised near-term risks and questions for state governments,
electric utilities and business interests.
How those issues get resolved will play out through state-
level negotiation with far-reaching implications.
The EPA’s proposal, called the Clean Power Plan (CPP),
charts novel and untested legal and jurisdictional territory un-
der section 111(d) of the Clean Air Act, and some or all of the
proposed rulemaking might be rejected or remanded throughthe all-but-certain litigation challenges to come.
Yet stakeholders might not have time to find out. Absent
a federal court’s staying the effectiveness of a final rule—an-
ticipated to be issued in 2015—states will have to submit in-
trastate compliance plans by 2017 or multistate compliance
plans by 2018.
Litigation could take five years or more (approximately
2019-2020) to conclude, well after states devise the suite of
policies and regulations to meet compliance obligations by
2029 and 2030, and could involve amending existing state
energy regulations to coordinating with interstate utilities,
other states and regional transmission organizations in the
establishment of market-based carbon pricing regimes.
In the aggregate, the CPP could initiate up to 49 sets of
such complicated, state-specific negotiations (Vermont is not
included in the CPP) over how to best reduce the carbon in-
tensity of the state electric grid in a manner that achieves the
CPP’s designated performance standard, called state goal, in a
cost-efficient manner.
The biggest challenge for utilities is navigating this ac-
celerated planning process while accounting for all market,
legal and policy contingencies.In some states, the calculus may be to assume, for ex-
ample, out of necessity that the CPP could pass legal muster
and be enforced as proposed, particularly in states where the
emission-reducing activities’ being targeted require longer
lead time planning.
Conversion to natural gas-fired power, increased renew-
able energy and distributed generation integration, and end-
use energy efficiency are not new phenomena in some parts
of the country.
The challenges before many utility executives will
be which of these options are most cost-effective and what
by Cameron Prell, Crowell & Moring LLP
Cameron Prell is
a counsel in the
Energy Group in
Crowell & Moring’s
Washington, D.C., office.His practice focuses on
the business of climate
change and the
convergence of energy
and environmental
law and finance.
A u t h o r
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Legal Issues:The 6 Deadly
Memes of Tree
and Power LineConflicts
Legal Issues:The 6 Deadly
Memes of Tree
and Power LineConflicts
Legal Issues:The 6 Deadly
Memes of Tree
and Power LineConflicts
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A u t h o r
Tracy Reichmuth is a
counsel in Crowell &
Moring’s San Francisco
office, where she focuses
on complex commercialitigation, including antitrust
law, unfair competition,
commercial contract
disputes, business torts
and consumer class action
defense. She is a graduate
of Stanford University and
University of California,
Berkeley, School of Law.
Stephen R. Cieslewicz is
president of CN UtilityConsulting. He has more
than 30 years of experience
working with utilities,
regulators and service
providers around the world,
ranging from investigating
the UVM-related causes
of the 2003 Northeast
Blackout to testifying in
legal and regulatory cases.
wby Tracy Reichmuth, Crowell & Moring , and Stephen R. Cieslewicz, CN Utility Consulting
When trees conflict with energized lines, a lot can go wrong.
The consequences of this type of occurrence can include
power outages or blackouts, fires and, most tragic, accidental
injuries or deaths.
Avoiding these scenarios is among the principal reasons
the utility industry spends billions of dollars annually onutility vegetation management (UVM). These efforts over
the years have reduced significantly the number of serious
incidents’ involving these tree and power line conflicts.
Despite utilities’ best efforts, however, things can and
will go wrong. During the aftermath of these events, a utility
can expect to end up in front of a judge or jury to explain how
it could not have prevented an occurrence or at least how it
acted reasonably in trying to prevent it.
Unfortunately, bad memes, or ideas that pass through the
community, regarding UVM can color the public’s perception
of a utility’s actions’ leading up to an incident.
These preconceived notions mean that decision-makersfrom regulators and legislators to judges and juries might act
without understanding what the utility industry can do and
does do to keep lines clear, what the industry is required to do
by law, and the limitations and hurdles the industry faces. As
a result, these bad memes can make for bad decisions.
Types of Tree, Power Line Conflicts
Tree-related incidents are the most common cause of routine
outages and a significant contributor to large-scale blackouts,
such as the one that affected large parts of the Northeast in
2003.
Although tree-related fires are comparatively rare, whenthey happen they are among the most devastating types of
fires.
Tree-related fires frequently occur at times that already
are conducive to the spread of fire: during hot, dry and windy
conditions. In a recent group discussion, participants from
large investor-owned utilities ranked the possibility of a
massive fire after a tree-power line conflict No. 2 on their
list of most-feared catastrophic incidents, second only to a
nuclear power plant accident.
Another significant threat involves public and worker
safety. One fatality every week likely is influenced by the
proximity of trees to energized lines.In recent years, judgments and settlements related to
these types of events have climbed steadily into the billions
of dollars. Fire claims, for example, even have prompted
insurance carriers to stop providing umbrella insurance to
certain utilities and service providers.
Monetary judgments and insurance coverage, however,
should not be the only utility concern. The harm that these
bad memes do to the public’s perception of utilities can
be much more damaging. These misconceptions and the
accompanying legal consequences can destroy a company’s
brand image and, in turn, the company.
The Six Deadly Memes
CN Utility Consulting studies have shown that most large
utilities acknowledge a disconnect between the industry
standards for vegetation management and the public’s
perception.
Contained within this disconnect are at least six commonbut false memes that routinely show up in court and regulatory
cases in the aftermath of tree and power line incidents. These
are routinely assumed, albeit erroneous, beliefs held by most
laypeople, including those on juries:
1. Every tree within falling distance is inspected
routinely and comprehensively. Plaintiffs often have
made this claim in cases where a tree fell from outside
of normal clearing limits and caused a fire or accident.
From this starting premise, plaintiffs might argue that
a utility did not meet the appropriate standard of care
by failing to identify a problem tree. Contrary to this
erroneous meme, utilities do not routinely inspect everytree that could fall through electric lines. A quick method
to dispel this myth is to drive down a typical road and
identify every tree that could fall through the lines. It
should become apparent quickly that to accomplish
100 percent of these inspections, a utility would have to
take ownership of a large percentage of urban and rural
forests.
2. Tree failures can be predicted easily. This premise
assumes that any old arborist would have known a
particular tree would fail and was a hazard. No qualified
2006: 86%
replied “yes”
2012 Survey Sample Size: 26
2002: 80%
replied “yes”
Is There a Disconnect Between Industry
Standards and Your Customers and
Local Agencies?
Yes69%
No31%
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arborist or tree expert, however, would suggest it is possible
to predict all tree failures. It is recognized widely within the
industry that neither the expertise nor technology would enable
accurate prediction of all tree failures, as reflected in disclaimers
found in all hazard tree guides and best practices publications.
This fact is compounded by the impact of winds on trees.
Research is underway to understand tree failures better, but acompletely healthy tree with no visible signs of decay, rot or
structural defect can shed limbs or fail completely when winds
exceed 39 mph.
3. Utilities are obligated by law to prevent all tree-related
problems. This common belief demonstrates how little those
outside the industry understand regulatory requirements and
the responsibility placed on utilities. For transmission voltages,
utilities generally must maintain prescribed clearances and
address hazard trees within their defined easements, per the
North American Electric Reliability Corp.’s (NERC’s) FAC-003.
The principal regulatory requirements for distribution lines are
found in NESC Rule 218 and are adopted or not by state. NESC
Rule 218 does not require utilities to prevent all tree-related
incidents or to remove all trees that could cause such incidents.NESC Rule 218 recognizes that “it is not practical to prevent all
tree-conductor contacts on overhead lines.”
4. Utilities have the right to prevent all tree-related problems.
Plaintiffs often assert that utilities have the right to enter private
land to inspect, remove or prune any trees near overhead lines.
This is false. Even where utilities have documented easements,
they have met resistance from property owners. In two recent
cases in California and Ohio, utilities faced years of litigation
with property owners over their right to remove or prune problem
trees, despite that the utilities had documented easements across
the properties with documented rights to remove trees.
5. The trees were there first. Another common belief is that tree-
related incidents are caused by the utilities’ placement of power
lines. In our experience, most tree-related incidents are initiated
after property owners plant incompatible vegetation near existing
True or false?
Utilities in the United States are obligated by law to
prevent all tree-related problems.
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Safety and production are inseparable
at Asplundh. is how we
operate – day in and day out. The safest
crews are our most productive crews.
Equipped with proper tools, training
and supervision, our people are always
prepared to do the job in a safe, efficient
manner. at Asplundh isthe only way to get the job done.
ASPLUNDH.COM • 1-800-248-TREE
power lines. Put differently, many of these conflicts occur from
bad planting choices completely outside the utilities’ control.
6. Utilities should prune rather than remove incompatible trees
on transmission rights of way (ROWs).The public often assumes
frequent pruning can remedy the danger caused by incompatible
vegetation on transmission ROWs; however, the forced frequencywith which trees must be pruned affect the health of the trees and
lead to even more dangerous conditions.
Allowing any incompatible vegetation
on ROWs is contrary to everything the
industry knows about proper UVM. It is
costly to everyone, and it was a principal
contributing factor of the 2003 Northeast
Blackout.
The Impact of the Memes
These memes can affect the utility industry
in countless ways, including the applied legalstandard of liability. For example, it seems
unreasonable to impose strict liability on a
utility for a tree-related incident (as opposed
to a negligence or reasonable care standard)
where the company does not have the legal
right to inspect or remedy problem trees be-
fore an incident.
Similarly, a juror who does not under-
stand industry standards and the realities of
UVM might incorrectly assume what a utility
can and should do. A juror who incorrectly
assumes it is standard practice to inspect andprune every tree that might touch an overhead
line might erroneously find a utility negligent
for not doing so, even if the utility complied
with industry standards and federal and state
regulations.
What the Industry Can Do
Utilities must take every opportunity to
educate the public, legislators, regulators and,
when litigation is filed, judges and juries.
Comprehensive public education campaigns
that proactively inform the public about UVM goals, efforts and
limitations are a good place to start.
It also might be advisable to seek legislation and regulations that
address the bad memes and limit liability to what is reasonable and
within the company’s ability to control.
If a lawsuit is unavoidable, a utility should set out the realities
of the industry carefully to the judge and jury. Better yet, change thememes before a case is filed.
True or false?Utilities should prune rather than
remove incompatible trees on
transmissio rights of way.
Go to http://uaelp.hotims.com for more information.
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aKing Coal is Soon to be Dethroned
by Teresa Hansen, editor in chief As recently as 2003, coal was used to generate some 53 percent
of all electricity consumed in the United States. Its share of thegeneration mix, however, has dropped significantly since then,
accounting for only some 37 percent of the 4 trillion gigawatt-
hours (GWh) of electricity generated in 2012, according to the
Energy Information Administration (EIA), which tracks U.S.
electricity generation trends among other things.
Coal remains king of U.S. electricity generation for now.
Natural gas is second at 30 percent, but the EIA predicts that
by 2040, natural gas will supply 35 percent of the generation
mix and coal will drop to 32 percent of the mix (see Figure 1).
Figure 2 illustrates the history of generation capacity ad-
ditions and predicted additions. Overall, capacity additions are
predicted to slow considerably during the next 25 years. Natu-
ral gas is expected to be the fuel of choice for new generation.EIA predictions for new capacity additions include that:
natural gas-fired plants will account for 73 percent of addi-
tions through 2040; renewables will account for some 24 per-
cent; nuclear power will provide some 3 percent; and coal-
fired power plants will be almost nonexistent for the next 25
years—just 1 percent of new capacity additions.
The main drivers behind decreasing coal-fired generation
are low natural gas prices and U.S. Environmental Protection
Agency (EPA) regulations.
Natural Gas Prices Squeeze Coal
Low natural gas prices have allowed the most efficientnatural gas-fired plants to generate electricity at lower
operating costs than coal-fired plants in many U.S. re-
gions. Gas plants, therefore, are being dispatched be-
fore coal.
Natural gas prices have dropped significantly be-
cause of the U.S. shale gas boom. Natural gas hit its
highest price—just more than $15 per million cubic feet
(Mcf)—in 2005. Just seven years later in April 2012,
natural gas prices hit a decade low of just more than
$1.80 per Mcf on the spot market. The price has risen
since then, but not much. In 2014, natural gas prices
have ranged between just below $4 to about $4.85 perMcf; high enough to keep most producers drilling and
low enough to make natural gas attractive for power
generation.
The American Natural Gas Alliance predicts natu-
ral gas will remain between $4 and $6 per Mcf through 2035.
Horizontal drilling coupled with hydraulic fracturing,
or “fracking,” have allowed
producers to recover natural gas
from sedimentary rock formations
and shale plays. Shale gas, which
provided less than 1 percent of
natural gas produced in the U.S.in 2000, provides more than 20
percent today and is expected to
provide some 53 percent of all
natural gas produced in the U.S. by
2040, according to the EIA. (More
details on natural gas’ growing role
in power generation are available in
the article “Natural Gas Heats up
Generation Discussions Again” in
the Jan/Feb 2014 issue of Electric
Light & Power .)
Electricity Generation by Fuel,
1990-2040 (Trillion kWh)Figure 1:
Sources: Energy Information Administration. Annual Energy Outlook 2014 Early Release Overview
1990 2000 2010
2012History Projections
2020 2030 2040
1%
32%
16%
16%
35%
6
5
4
3
2
1
0
16%
Oil and other liquids
Nuclear
Renewables
Natural gas
Coal1%3%
37%
52%
19%19%
12%9%
30%
Historic and Future Capacity Additions in U.S.Figure 2:
Other Renewables
Solar
Wind
Natural Gas/Oil
Nuclear
Hydropower/Other
Coal
1985 1995 2005 2020 2030 2040
Year
G W
60
40
20
0
History 2012 Projections
Source: Energy Information Administration
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EPA Regulations
Many electricity generation and coal industry experts have accused
President Barack Obama and his administration of waging a war
on coal. While energy insiders, politicians and regulators debate
this, the EPA—headed by Obama appointee Gina McCarthy—
has proposed and enacted stringent rules that have made and will
continue to make it difficult for many coal-fired plant owners andoperators to generate electricity.
During her Climate Action Tour in May, McCarthy called
carbon dioxide (CO2) “the biggest public health threat of our time”
and said it needs to be regulated now. The EPA is obligated under
the Clean Air Act to address pollution from power plants, and it has
addressed all other pollutants, McCarthy said.
“Carbon pollution should not be treated any differently,” she
said.
The table on Page 22 lists recently proposed and enacted EPA
regulations that address CO2 and other power plant emissions. The
table is not a complete list of EPA-enacted and proposed coal-
related regulations but includes those that have or will have thegreatest impacts on coal-fired generators.
Some coal-fired power plants cannot afford to comply with
even one of the regulations. As a result, their owners and operators
will retire them rather than invest in pollution-control technologies
to keep them operating. For many other
coal-fired plants, spending money to comply
with one or two EPA regulations might be
economically feasible, but when combined,
the regulations become too costly.
The EIA predicts that between 2012 and
2020, some 60 GW of the nation’s current
310 GW of coal-fired capacity will be retired.Coal plants that will not attempt to comply
with EPA regulations are a big part of this
number.
Declining electricity demand during a
sluggish, post-Great Recession economy and
EPA regulations made 2012 a record year for
coal plant retirements (see Figure 3). It was
the year natural gas prices hit a decade low.
And retirements in 2015 are expected to
trump those in 2012. Many of the retirements
are planned just before the EPA’s Mercury
and Air Toxic Standards (MATS) becomeeffective.
Data from The Brattle Group shows
some 93 percent of coal plants lack at least
one major piece of equipment required to
control air emissions.
The clean power plant standard for new
power plants, the 111(b) rule proposed by
the EPA in fall 2013, is the main reason no
construction is planned for new coal-fired
power plants. Under the proposed rules, new
coal-fired units would need to emit less than
1,100 pounds of CO2 per MWh. The average U.S. coal plant emits
1,768 pounds of CO2 per MWh; new units would have to use carbon
capture and storage (CCS) technology to meet the new requirements.
Most utility experts agree that CCS technology is still in research
and development and is not ready for large-scale implementation. Inaddition, it’s expensive.
In comparison, combined-cycle gas turbine (CCGT) plants
emit 800-850 pounds of CO2 per MWh; they already meet the
standard.
THE POWER OF KNOWLEDGE
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CNUC’s understanding of FAC-003-3 comes from helpingdevelop the NERC standard and related BMPs, and experiencecreating strategies and plans. WE CAN HELP WITH:
MVCD compliance through the development of
defensible program processes and documentation
Defined annual inspections and selective
vegetation management plans
Tree risk assessments performed by consulting
utility foresters – even using LIDAR data
And more
AFTER JULY 1, 2014, FAC-003-3 IS ENFORCEABLE.Contact us today!
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Will Porter
Derek Vannice
Stephen Cieslewicz
Utility Arborists & Foresters | Industry Analysis | Benchmarking
Program/Compliance Reviews | Expert Witness | Software
LIDAR | QA/QC | Turn-Key UVM Operations
Figure 3:
2005 2007 2009 2011 2013 2015
Year Source: Energy Information Administration
C a p a c i t y ( G W )
12
10
8
6
4
2
0
70
60
50
40
30
20
10
0
Historic and Planned Coal Plant Retirements
N u m b e r o f U n
i t s
Historic Planned
Go to http://uaelp.hotims.com for more information.
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In early June, the EPA proposed its anticipated clean power
standard for existing power plants, the 111(d) rule. The planrecommends that coal plants reduce CO
2 emissions up to 30 percent
by 2030 compared with 2005 levels.
The EPA has given states the authority to determine how they
will meet the new targets. States have until June 2016 to submit
their detailed plans. It’s unclear what technology plants might use
to comply with the proposed reductions, but most states likely will
include some sort of carbon trading system as part of their plans.
Some states are ahead of the feds in reducing CO2 in plants.
Most experts have said the most successful plan is the
Regional Greenhouse Gas Initiative (RGGI), a cooperative carbon
reduction plan that is administered by several states: Connecticut,
Delaware, Maine, Maryland, Massachusetts, New Hampshire, NewYork, Rhode Island and Vermont. The RGGI is the first mandatory
market-based regulatory program in the U.S. to reduce greenhouse
gas emissions. Under the plan, states sell emission allowances
through auctions and invest proceeds in energy efficiency,
renewable energy and other consumer benefit programs. Each
participating state has its own CO2Budget Trading Program.
Another state-initiated initiative is the Western Climate
Initiative (WCI), a cap and trade program that includes British
Columbia, California and Quebec.
Despite Challenges, Coal is not Going Away
Although few new coal plants are expected to be built during thenext 25 years and some 20 percent of the U.S. coal fleet will be
retired soon, coal will continue to provide significantly to the
nation’s 1,063 GW of total generating capacity. Effective pollution
control, coal-gasification and CCS technologies along with CO2
cap and trade programs will be developed to ensure coal remains
viable for electricity generation. Nevertheless, these measures will
not allow coal to remain the low-cost fuel for electricity generation
that it has been in the U.S.—at least not as long as natural gas
remains at or near its current price.
In addition, despite decreased coal use in North America and
the EU during the past several years, global coal consumption is at
an all-time high and continues to grow. Its increased use is beingdriven by growing and power-hungry markets around the world,
most notable, China and India. Worldwide carbon emissions are
growing, as well: 2.2 percent annually on average from 2000 to
2010 and at an even higher annual rate since 2010, according to a
report released this year by the Intergovernmental Panel on Climate
Change.
Despite the scientific community’s urgent call to reduce carbon
emissions, coal remains king globally, and its use is expected to
rise.
Regulation Status Pollutants Targeted Compliance Options Expected Date Effect on Coal
MATS Final HAPs Baghouse, FGD/DSI, advanced coal 2015/2016 Large
(mercury, acid gases, PM). technologies
Clean Power Plan EPA issued proposed GHG (carbon). Currently there is no commercial-scale No later than Large
(GHG Standards for rule standards Limit CO2 emissions of technology to reach levels in coal-fired May 20, 2016.New Plants – 111(b)) September 2013. new power plants. plants. Gas-fired has no problem
meeting limits.
Clean Power Plan EPA issued proposed GHG (carbon). Unknown. ~2020. Large
(GHG Standards rule June 2014. Reduce CO2 emissions from Potential for trading of allowances. The EPA has given the 50
for Existing Plants – existing coal plants up to States to decide. states until June 2016 to
111(d)) 30% by 2030 compared submit plans that detail
with 2005 levels. how they intend to meet
new targets.
316(b) Final May 2014 Cooling water intake Impingement: mesh screens; Within eight years. Moderate
structures. Entrainment: case by case, No later than 2021.
may include cooling towers.
Regional Haze Final May 2012 NOx, SO2, PM SCR/SNCR, FGD/DSI, baghouse/ESP, Typically five years after Couldcombustion controls. ruling. be large
depending
on state.
Cross State Air Pollution Upheld by NOx, SO
2SCR/SNCR, FGD/DSI, fuel switching, ~2015 Moderate
Rule (CSAPR) Supreme Court 2014. allowance purchases
Combustion Byproducts Final expected Ash control equipment Bottom ash dewatering, dry fly ash Uncertain, potentially Moderate
(ash) December 2014. waste. silos, etc. ~2020.
Sources: Energy Information Administration, The Brattle Group, Environmental Protection Agency
EPA Regulations’ Affecting Coal-fired Power PlantsTable:
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PJM Frequency Regulation: 4 MW constructed
IESO Frequency Regulation: 4 MW constructed
CAES: Integrated grid scale wind to Compressed Air
Energy Storage facility
________________
Committed to everyone going home safe, every day .
4 MW (8 MW range) Ohio Energy Storage Project
Renewable Energy Systems Americas Inc.
11101 W. 120th Ave. | Suite 400
| 303.439.4200
res-americas.com [email protected]
Energy Storage DEVELOPMENT | ENGINEERING
CONSTRUCTION | OPERATIONS
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eA u t h o r
Sandra DiMatteo is
director of applications
advantage, asset
management and
operations at BentleySystems, where she
leads the marketing
strategy and positioning
for Bentley’s asset
management and
operations products.
She founded and is on
the board of the Society
of Maintenance and
Reliability Professionals
Ontario Canada Chapter
and has an HonoursBachelor of Commerce
from McMaster
University in
Hamilton, Ontario.
Case Study: ScottishPower’sStrategy for Asset Management
and Process Safetyby Sandra DiMatteo, Bentley Systems
Energy company ScottishPower, a division of Iberdrola,
was the first power generator and the second company
in the world to be certified on BSI Publicly Available
Specification 55 (PAS 55:2008), which benchmarks best
practices in asset management.
AssetWise Performance Management and the Bentley
Asset Performance Management (APM) Methodology and
the Amor Group Process Safety Methodology and KPI (key
performance indicators) Dashboard played key roles inScottishPower’s achievement.
The Need for Change, Challenges
A series of industrial incidents including one at Scottish-
Power Longannet Generating Station, coupled with the
publication of U.K. standards HSE RR509-Plant Ageing
Report, integrity guidelines HSE HSG254 and asset man-
agement standard PAS 55 2008, highlighted ScottishPow-
er’s vulnerability to a major incident and the need to make
asset management and process safety a priority. In particu-
lar, the Baker Panel report into the BP Texas City refinery
fire motivated ScottishPower to carry out a self-audit thatassessed whether a similar catastrophic incident could hap-
pen within its operations, and if so, how well risks could
be managed.
Pathway to a High-reliability Organization
ScottishPower developed sustainable processes to address the
British Government’s Health and Safety Executive HSE Plant
Ageing report of 2006 (RR509) and to attain PAS 55 accredi-
tation.
It was time to change a reactive culture in older coal-fired
plants to a proactive culture while addressing knowledge lost
because of employee attrition and the lack of technology to
support the approved business model. A road map establishedand implemented the vision for operational transformation.
An aligned information technology (IT) strategy and system
lies at the heart of ScottishPower’s success with the program.
Significant groundwork was performed during 2006-2008
to consolidate the business on a small set of best-of-breed
applications, including AssetWise Performance Management
integrated with IBM Maximo.
AssetWise provided a robust and automated source of
data required to derive leading KPIs each day. And rather than
having many KPI reporting systems, ScottishPower adopted
a unified approach that has eliminated any conflict over data
collection.Early in the program, a partnership was formed with the
Amor Group to develop an integrated data management sys-
tem to meet integrity guidelines HSE HSG254.
From Reactive to a Proactive Culture
100
90
80
70
60
50
40
30
20
10
0
P e r c e n t a g e o f P M
t o C M
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The system aggregates performance data for KPIs from core
operational business applications, including AssetWise Performance
Management to manage the business and asset integrity.
The Operational and Maintenance Excellence Strategy
The scope of the initial implementation included two coal-fired power
stations in Scotland and three combined-cycle gas turbine power sta-
tions in England.
To enable the organization to ingrain the process of asset man-
agement and process safety across multiple plants, ScottishPower lev-eraged the Bentley APM methodology to guide the implementation
through business, organizational and technology alignment to PAS 55.
The complete Bentley APM solution, supported by maintenance
task analysis failure modes and effects analyses, along with previ-
ously completed world-class reliability-centered maintenance and a
new internally developed peer-to-peer review practice enabled by the
technology AssetWise Performance Management, provided a cohe-
sive and integrated approach to develop, implement and manage a
living program.
Risk ManagementScottishPower took a simple view that incidents and near misses were
the single source of lagging indicators.
It implemented a new incident management process to capture
this data and drive consistent investigation of causes.
Incidents were classified as major, significant or minor (based on
API 754 Process safety performance indicators for the refining and pet-
rochemical industries) related to the underlying 42 risk control systems.
The Smart Use of IT and Mobile Technology
The smart use of IT and handheld data collectors that run AssetWise
Performance Management means data management systems are in-
tegrated into process plant and other day-to-day operational systems.This enables the company to drill down from each headline KPI
to reveal the underlying causes, trends and transactions in the Bent-
ley APM methodology. With these core systems, ScottishPower can
assess performance and drive progress toward targets.
The information is available to everyone in the company at any
time and enables them to identify and act upon problems within their
system before it affects business or safety.
This information is not stand-alone; it is part of a complete sys-
tem of plant, people and process residing within a strong leadership
framework where senior management understands process safety and
asset management that directly links to business performance.
Results
In only two years, ScottishPower established the asset management
and process safety framework that has led to improved plant reliability.
As a result, it has improved performance and transparency of key
processes and has experienced fewer unplanned outages and break-
downs with significant cost savings:
■ 36 percent reduction in operations and maintenance costs;
■ 22 percent increase in plant availability;
■ 52 percent reduction in plant forced outage rates; and
■ 10 percent reduction in insurance premiums.
As a high-reliability organization, ScottishPower produces itsproduct consistently over long and sustained periods.
The proactive culture is one of continual vigilance and lacks
complacency.
Employees act strongly to weak signals and set their threshold
for intervening very low, given the understanding of the condition of
their assets.
Senior management has visibility of core operational processes.
This has increased confidence and assurance from board to plant level.
The result has been improved cooperation among leadership,
work force and regulatory bodies and the drive to deliver a high-
reliability organization.
Project Summary Organization: ScottishPower
Solution: Power Generation
Location: Scotland, U.K.
Project Objective■ Address the HSE Plant Ageing report RR509
and attain PAS 55 accreditation.
■ Avoid incidents and disaster by setting a high standard
for asset management and process safety.
Products Used: AssetWise Performance Management
Fast Facts
■ AssetWise Performance Management was chosen
after a generating station experienced catastrophic
failure that resulted in plant shutdown.
■ ScottishPower is the second company in theworld to be certified on BSI Publicly Available
Specification 55 (PAS 55:2008).
■ AssetWise enables ScottishPower to drill drown from
each KPI to reveal underlying cases and trends.
ROI
■ 36 percent reduction in operations and maintenance costs;
■ 22 percent increase in plant availability;
■ 10 percent reduction in insurance premiums; and
■ 52 percent reduction in plant forced outage rates.
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dEnergy Storage GoingMainstream—Valuation
and ProcurementDuring the past five years, energy storage technologies have
experienced unprecedented funding by public and private
sources for research, development and demonstration.
For example, the Department of Energy provided some
$185 million in funding for 16 energy storage demonstrations
through the American Recovery and Reinvestment Act
(ARRA) Smart Grid Demonstration program.
These demonstrations are nearing completion, and the
results are validating the technology performance, which is
necessary for the technologies to be commercialized.This growth is supported further by the recent California
Public Utilities Commission decision that requires California
investor-owned utilities to procure more than 1.3 GW of
energy storage projects by 2020.
As a result, energy storage is enjoying a renaissance
among utility planners, regulators and system operators as
a tool for load leveling, grid operational support and grid
stabilization (see Figure 1).
Harnessing energy storage in these applications can
offer economic, reliability or environmental benefits such
as ancillary services revenue and deferred transmission and
distribution investments, as well as reduced electricity losses,power interruptions and emissions.
The value of each benefit varies significantly, depending
on the energy storage technology, location on the grid, market
structure and type of owner.
For utilities to develop successful procurement plans,
they must be able to assess the benefit and overall value of
energy storage.
Initially, utilities should conduct a high-level screening of
possible locations, technologies, capacities and the resulting
costs and benefits.
Next, utilities should conduct more detailed and
sophisticated analyses of the most attractive opportunities to
quantify the costs and benefits more accurately.
Although numerous energy storage models and toolssupport system planning control system operation and
measure cost-effectiveness, the wide range of technologies,
deployment locations, ownership structures and benefits
provided by energy storage poses challenges for traditional
utility proposal evaluations and procurement processes.
A recent Navigant study for the Energy Storage
Association identified and characterized existing energy
storage models and tools and how each addresses the needs of
energy storage industry stakeholders.
The study concluded that although numerous software
models are available to utilities for system planning, these
models historically have considered only large pumped-hydroelectric storage facilities.
As a result, current system planning models generally
do not account for the complex, variable operations of energy
storage systems and are just beginning to address the unique
modeling requirements needed to represent the true value of
energy storage systems.
Although no one model or software package can calculate
the value of energy storage at all locations on the grid (i.e.,
generation, transmission, distribution, behind the meter), it is
possible to use well-known, commercially available products
together with new models and tools to determine overall cost-
effectiveness.For example, at the generation level, commercially
available production cost models can be used in conjunction
with proprietary tools to dispatch resources on a subhourly
level and co-optimize between energy and ancillary services.
At the transmission and distribution levels, impacts identified
through load flow analysis can be used to calculate the value.
After modeling is complete and the most attractive
opportunities are identified, a procurement plan should be
tailored to request funding, proposals to secure the preferred
storage resources or both.
Several key issues must be considered when developing
by Paul Maxwell, Colette Lamontagne and Jay Paidipati, Navigant
A u t h o r s
Paul Maxwell assists
several clients with
feasibility studies,
market assessments
and regulatory support
for new storageprojects in California.
Colette Lamontagne works
with utility, independent
power producers,
project de velopers,
technology providers and
government clients to
identify and demonstrate
the value of energy
storage deployments and
the development ofstrategic plans.
Jay Paidipati has been
working in the energy
industry for 10 years and
has been working on
technology and business
strategy in energy storage
with utilities, governments
and equipment vendors
during the past four years.
Energy Storage ApplicationsFigure 1:
Load Leveling (Generating power off peak and using it on peak)
Q Renewable Energy Shifting
Q Wholesale Market Arbitrage and Cost Avoidance
Q Retail Market Arbitrage
Q Asset Management
Grid Operational Support (Matching supply to demand)
Q Load Following
Q Operating Reserves
Q Regulation
Q Renewable Energy Capacity Firming
Q Black Start
Grid Stabilization (Improving reliability)
Q Renewable Energy Ramping
Q Renewable Energy Smoothing
Q Backup Power
Q Power Quality
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Key Considerations for an Energy
Storage Procurement PlanFigure 2:
EnergyStorage
ProcurementPlan
Utility or
Third-party
Ownership?
Grid Domains—
Include Customer
sited?Storage Only
or Storage
and Energy
(Generator Behind
the Meter)?
Market
Transformation?
Aggregation
of Projects?
Provide Firm
Capacity, Flex
Capacity or
Energy Only?Thermal—
Verification of
Savings?
T&D Deferral
Benefit, Reliability
Improvement Benefit—
Identify Preferred
Sites in Advance?
a procurement plan (see Figure 2). The grid location of the new
energy storage system will affect interconnection costs, reliability
requirements and net metering growth across the system.
Co-location of energy storage with existing third-party-owned
generation raises questions about how to handle the incremental energy
under the existing power purchase agreement.
A requirement to provide firm or flex capacity can result in
relatively large storage systems to meet the discharge duration and
frequency standards as defined in the local market.
Last, procurement of thermal storage may require specialperformance standards and procedures to verify electricity savings.
Evaluation and resolution of these issues should include input
from key stakeholders, including energy storage technology providers,
national laboratories, consultants and the utility’s staff who have been
involved with demonstration projects.
The resulting procurement plan must be robust enough for utility
management and regulatory agency approval, yet flexible enough to
mitigate the technology, cost and counterparty risks with new and
evolving technologies such as energy storage.
The procurement plan and targets must be re-evaluated regularly
in response to lessons learned from each solicitation.
In some cases, certain emerging technologies or applicationsmust be procured on a demonstration project basis rather than a more
traditional energy purchase, capacity purchase or both to mitigate risk
and maximize operating experience in support of future traditional
procurement.
Vendor proposals received must be evaluated on the
aforementioned quantitative cost and benefit metrics and on key
qualitative risk factors related to emerging technologies, including:
■ Performance. Will the technology work as expected?
■ Availability. Will the technology and operator meet requirements?
■ Degradation. Will the technology’s performance degrade as
expected? What are the implications on revenue?
■ Project execution. Can the technology vendor, system
integrator and EPC meet contractual schedule and performance
requirements?
■ O&M costs. Will the project owner’s O&M budget be enough to
meet availability requirements and handle unforeseen issues?
■ Permitting. What are the necessary permits, and can the project
developer get them?■ Safety. Does the technology present any safety risks?
Looking Forward
Markets with high energy prices, high resource intermittency, high load
growth and poor transmission and distribution (T&D) reliability likely
will see the most early-stage deployment.
Subsequent penetration into less challenged markets likely will
hinge on the associated penetration of intermittent renewables across
both T&D domains. Will energy storage become the third pillar of the
electric power industry alongside generation and transmission? Or will
it remain a niche technology that proves cost-effective only for limited
applications?Proper valuation and procurement by utilities and delivery of
commercially viable and lower-cost storage systems by manufacturers
will be necessary for energy storage to become a valued contributor to
electric grid performance and reliability.
TUESDAY AUGUST 19, 2014
Join the GenerationHub editorial staff and otherindustry experts for a one-day event focusedon the business of electric power generation inNorth America.
• Compliance Strategies• Coal Plant Retirements
• Emission Control Projects
• Fuel Switching• And More!
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A u t h o r
John Jung is the CEO
of Greensmith Energy
Management Systems
Inc. More information
is available at www.greensmithenergy.com.
oIntelligent Energy Storage—Key to Unlocking the Smart Grid
by John Jung , Greensmith Energy Management Systems Inc.
Our aged, worn electric grid has seen more changes and
been confronted with more challenges during the past
10 years than at any other time since its inception.
We’ve gone from an environment of one-way
power flows from centrally located generation in
remote areas, over long transmission and distribution
lines, then finally to homes and businesses to thenew world of bidirectional power flows where
customers also can be merchants who sell their
excess power back to grid operators.
We’ve gone from a world where generators
can be tightly managed to maintain synchronous
power output to an evolving framework of must-
take renewables that add significant intermittency and stress
throughout the network.
In addition, load curves continue to change with the
proliferation of electronics in our daily lives—cell phone
penetration exceeds 100 percent, PCs are commonplace and
the average household has 2.93 TVs.It’s outpacing a grid that was designed post-WWII for
a different load profile and that is reaching its capacity and
reliability constraints.
Into this second coming of an electron gold rush of
sorts, entrepreneurs rushed in with technology solutions to
modernize the electric grid.
Some of these innovations, such as smart meters,
provide the necessary underpinnings for more innovation in
areas such as rates and usage patterns.
Some of these innovations address single points of
failure along distribution or transmission lines.
And some of these innovations have increased gridstrain and made grid operators’ jobs more challenging.
None of these innovations address the fundamental
shortcoming of the grid: that it must be operated at scale and
increasingly on a just-in-time basis.
Utilities have understood the value of being able to
store energy to time shift its use to when it is most needed or
economical to use.
Combined gas and electric utilities practice this duality
every day, storing natural gas until demanded by customers.
In addition, large-scale electric storage through legacy
pumped hydro has existed many years.
The challenge has been to provide the same
functionality cost-effectively to customers.
In the name of American recovery, utilities have
experimented with all forms of energy storage.
They knew prices would make energy storage
a competitive grid asset. San Diego Gas and
Electric, for example, has deployed multiplecontainerized systems, each demonstrating
the value of different applications,
including:
■ Site load management through
a behind-the-meter site integrating
photovoltaics, (PV), electric
vehicles (EVs) and storage; and
■ T&D deferral through a
1-MW system deployed behind
a known congestion point that
will provide the utility more
time to alleviate the need for new transmission upgradesand remote backup power for critical infrastructure.
These pilots have led to exciting conclusions for the
industry. Energy storage is a completely new type of asset.
It can function as a load and a resource. It can solve the
challenges of the duck curve. It can provide much faster
and accurate response to frequency regulation, avoiding the
overshooting so common using conventional resources. It
will allow much greater levels of renewables integration. It is
the silver bullet for the smart grid.
Which brings us to today. With California’s landmark
AB2514, it appears the market is lining up behind a big push
in the deployment of energy storage systems (ESS).But is the technology ready? Can it be delivered on a
cost-effective basis?
Many years from now, we will look back to 2014 and
conclude this was the end of the beginning.
Like a well-conducted orchestra, we see positive
movement on all major fronts to make energy storage a cost-
effective reality.
Utilities see the value in energy storage as a reliable
generation asset.
Regulators from Hawaii to New York are making policy
changes to explicitly include energy storage in the utilities’
© c an s t o ck ph o t o. c om
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integrated resource planning, as well as their
demand response portfolios.
Wholesale markets including PJM, the New
York Independent System Operator (NYISO) and
the California ISO (CAISO) are creating products
specifically tailored for energy storage to reflect
the increased value from rapidly responding assets.Further, New York is providing incentives for
customers to deploy distributed storage systems
and will allow them to participate in wholesale
markets.
The market is evolving quickly in the time
scale of utilities. One of the most encouraging
signs is the current construction of multiple
multi-MW ESS systems by several renewables
developers that intend to use the systems for large-
scale frequency regulation in the PJM market.
These units are
being built with anROI target, and it has
advanced the dialogue
to the bankability of
these systems.
Another key factor
to watch is the cost of
the storage medium.
There is no
Moore’s law for materials science, but there is the good old Hen-
derson Experience Curve: Every time production doubles, costs can
drop 20 to 30 percent. In this case, utility ratepayers are not being
expected to shoulder the burden of R&D through high initial costs.In this case, utilities are benefiting from the investment and focus
that battery original equipment manufacturers (OEMs) have placed
on developing large-format cells for the EV industry. Nearly every
major auto company has a growing line of hybrids or full EVs. Many
major battery OEMs have spent the better part of the past 10 years
developing cells to meet this rigorous environment.
This is great news for the electric sector because large-format
cells are ideal for energy applications and can be packaged easily in
racks and placed adjacent to the grid. The grid environment is less
rigorous than the EV environment, so many of these solutions are in
some ways over-engineered. With anticipated volumes set to grow for
EVs and ESS, we will soon see pricing drop below $500 per kilowatt-hour, and that will change everything.
As more systems are commissioned, we will move beyond what
energy storage can do for the grid to how to maximize the return of
energy storage—whether we consider that in terms of increasing the
asset life or prolonging the hours of operation. It is relatively simple
to follow an AGC signal and charge or discharge to meet the power
or energy requirements.
The challenge is to add intelligence to this asset through software
and analytics to maximize revenue potential from a given application
against the twin challenges of extending asset life and minimizing
the impact of round trip efficiency. Intelligent software also will be
necessary as we evolve from single-application systems
to multiple applications that are running to improve grid
function. Software will play a key role to manage storage
resources, shift capacity during peak periods, provide
ancillary services in the off-peak hours and provide standby
power for emergencies.
Meanwhile, our first glimpse into this brave new
world of energy storage is happening on an island near you. Tropical
island nations have been quick to add solar on a central station and
distributed basis.
This has been driven by fantastic solar yields and a high ceilingin terms of the price to beat. Making solar competitive against 50
cents per kilowatt-hour diesel-based generation is a lot easier than the
average 12 cents per kilowatt-hour in the continental U.S.
But all this renewable generation extracts a hidden cost on these
fragile microgrids. As solar penetration increases, it will cause many
islands to rely on a handful of generators, or, in some cases, just one.
This fragility leaves little room for error.
Couple that with intermittency, and you quickly come face-to-
face with a significant ramping challenge. Energy storage is ideal to
mitigate this problem. Placed next to a solar site and coupled with
intelligent software, energy storage can fill the gap to create a smooth
ramp rate that other resources can match though increased generation.Energy storage systems are also ideal to solve frequency
regulation challenges, as well as reactive power issues.
The smart grid is already here, able to provide: two-way
power flows, support generation both in remote areas connected by
transmission and distribution among homes and businesses, integrate
intermittent renewables, and support massive ramp rates from solar,
wind and EV charging.
Energy storage might be the silver bullet after a decade of industry
research. Never before has the industry had a tool so powerful be a
load and a resource with the ability to transform the grid to a flexible,
two-way power system to support modern lifestyles.
Software will play a key role to manage storage
resources, shift capacity during peak periods,
provide ancillary services in the off-peak hours and
provide standby power for emergencies.
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A u t h o r s
Bijoy Chattopadhyay,
Ph.D., is a director with
Navigant’s energy
practice. He has more
than 30 years ofexperience and is based
in San Francisco. Reach
him at bijoy.chattopad
Sam Sankaran is an
associate director with
Navigant’s energy
practice. He has 14
years of electric
utility experience and
is based in Burlington,Massachusetts. Reach
him at sam.sankaran@
navigant.com.
lLarge-scale deployment of advanced metering infrastruc-
ture (AMI) and intelligent energy devices (IEDs) combined
with grid edge power conditioning equipment and availabil-
ity of sensor data has created a tremendous need for data
storage and analysis. The application of analytics, however,
lags in several areas.
Big Data’s Growth
International Data Corp. (IDC), a provider of market intel-
ligence in the information technology (IT), telecommunica-tions and consumer technology markets, predicted big data
will grow 30 percent in 2014 by developing “data-optimized
cloud platforms” that will leverage high volumes of real-
time and nonreal-time data streams. On the flipside, Gartner
reported in 2013 that big data didn’t drive big growth in the
worldwide business intelligence and analytics market.
“Even though big data hype reached a fever pitch in
2013, this did little to move the dial for analytics,” accord-
ing to Gartner.
The business intelligence and analytics market grew
some 8 percent to $14.4 billion in 2013; the uptick could
have been even greater. Only 8 percent of organizationssurveyed by Gartner have deployed a big data project, with
some 57 percent still in the research and planning stages.
Regardless, the analytics of the large volumes of data ap-
pears to be one of the most critical, yet lacking elements
of big data. The analytics value proposition also remains
unclear to many in the industry.
What is Big Data?
Big data refers to data sets with size beyond the ability
of typical database software tools to capture, store, man-
age and analyze. Structured data is obtained from data that
conforms to a construct or has a preset pattern that can beanalyzed with traditional methods and business intelligence
techniques. Unstructured data consists of large sets of un-
structured information obtained from the social Web (i.e.,
social media, digital photographs, online videos), sensors
and other sources that pose a more complex challenge in
analysis but might provide greater value. The major attri-
butes of big data are:
■ Volume. The vast amounts of data generated every
second. Potentially greater than terabytes (1012) and
petabytes (1015) and could reach the zettabytes (1021)
and brontobytes (1027) range.
■ Velocity. The speed at which new data is generated
and at which data moves. Big data technology allows
for analysis of the data while it is being generated
without ever putting it into databases.
■ Variety. The different types of data. Although the
structured relational databases that neatly fit into ta-
bles are small, some 80 percent of the world’s data is
unstructured and cannot be put into tables easily.
■ Veracity. The messiness or trustworthiness of the data.
With many forms of big data, quality and accuracy areless controllable (e.g., Twitter posts with hashtags, ab-
breviations, typos and colloquial speech, as well as the
reliability and accuracy of content).
Utility Data Growth
AMI has increased the volume of utility data by the order
of thousands (see Figure 1). Before smart meters, each cus-
tomer meter was read monthly: 12 reads annually. Smart
meters produce data at 15-minute intervals: 35,040 reads an-
nually, or some 400 MB of raw data per year per meter. This
data grows in magnitude after it is analyzed. And, with some
utilities’ considering five-minute intervals, the data volumecontinues growing. When Austin Energy deployed 500,000
smart meters, its data storage requirements grew to 200 tera-
bytes based on 15-minute reads. Those needs are expected to
grow to 800 terabytes if interval reads are increased from 15
minutes to five minutes. With some 140 million smart meters
deployed across the U.S., it is expected that close to 100
petabytes of information will be generated over 10 years.
A Utility Perspective of Big Data
Utilities envisioned applications from the massive amounts
of data being collected through AMI, supervisory control
and data acquisition and other sensors, including:■ Protecting revenue from theft;
■ Targeting demand response (prioritizing customers for
energy conservation and demand response programs
using geospatial techniques, energy density mapping);
■ Distribution operations planning (targeting customers
with high peak loads to help reduce peaks by staggering
power for ventilation, heating, cooling and lighting);
■ Transformer load management (identifying transform-
ers that are overloaded or underused);
■ Quality assurance and quality control data (improv-
ing the quality of connectivity information including
How to Transform DataInto Value-added Information
Through Analytics by Bijoy Chatt and Sam Sankaran, Navigant
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phase);
■ Voltage correlation (using analytics to link meters to trans-formers including phase);
■ Energy modeling (analyzing usage patterns including unmetered
usage from streetlights and other devices);
■ Voltage deviation (identifying transformers with voltage deviat-
ing from the rated voltage by 2 to 3 percent or more);
■ Geospatial outage frequency analysis (analyzing outage patterns
geographically);
■ Predictive analytics for electric vehicle (EV) adoption (identify-
ing plug-in EV owners and predicting demand patterns to ensure
adequate transformer capacity); and
■ Asset management.
Big Data Applications in Asset Management
There is an increasing trend of developing predictive maintenance
programs for the efficient use and management of utility assets. The
management of those assets requires data from different sources and
structured and unstructured data. Thus, big data could be deployed
to address predictive maintenance in the asset management space.
One specific application for transformers is illustrated in Figure 2,
where data comes from different data-gathering systems in either astructured or unstructured fashion. These data are processed, mod-
eled and formatted for further analysis. Algorithms in the analytics
engine correlate with different information to make a decision and
provide a trending analysis of the equipment’s health.
Figure 3 provides an example of a transformer health assess-
ment based on winding temperature, differential temperature of
online tap changer and main tank temperature, dissolved gas analy-
sis and hourly loading of the transformer, among other things. Al-
though Figure 3 shows a simple qualitative assessment of the equip-
ment’s health by developing a watch list of transformers that need
early attention, a more sophisticated quantities assessment can be
made easily from the collected data.
Conclusions
Transformers are just one example of how big data and analytics can
aid utilities in asset maintenance. A similar analytical approach can
be used for circuit breakers or other utility assets to assess equipment
health conditions and for developing subsequent mitigation plans.
Growth of Utility DataFigure 1:
Sources: Electric Power Research Institute, 2008.
New Devices in Home
Enabled by Smart Meter
Time
A n n u a l R a t e
o f D a t a
I n t a k e 800 TB
600 TB
400 TB
200 TB
0 TB
OMS Upgrade
RTU Upgrade
Mobile Data Goes Live
You arehere.
Distribution Automation
Work Force Management Project
Substation Automation System
GIS System Deployment
DistributionManagement Rollout
AMI Deployment
Programmable
Communicating Thermostat Come Online
Growth of Utility DataFigure 2:
Transformer
Analytic Engine
Data Gathering and Data Modeling
SCADA
SCADA: Supervisory Control& Data Acquisition System
DFR: Digital Fault Recorder
DGA: Dissolve Gas Analysis
AMI: Advanced Metering Infrastructure
EMS: EnergyManagement System
EMS DGA Inspection AMIRelay/
DFR
SCADA DFR/Relay Inspection AMI
Main Analytics
Tank LTC LTC Tap Results/
Transformer Oil Tank Change Winding Cooling Through Asset
Identification Temp Temp Times/Day Temp Fan DGA Fault IR Loading Health
Transformer No. 1 Normal Normal Normal Normal On Normal Normal Normal Normal Normal
Transformer No. 2 Normal Normal Normal Normal On Normal Normal Normal Normal Normal
Transformer No. 3 Abnormal Normal Normal Normal On Normal Normal Normal Abnormal Watch
Transformer No. 4 Normal Normal Normal Normal On Normal Normal Normal Normal Normal
Transformer No. 5 High High High High On Abnormal Abnormal Normal Abnormal Watch
Transformer No. 6 Low Low Normal Normal On Normal Normal Normal Normal Normal
Transformer No. 7 Low Normal Normal Normal On Normal Normal Normal Normal Normal
Transformer No. 8 High Normal High Normal Off Normal Normal Abnormal Normal Watch
Example of Data Analytics for Transformer Health Assessment and Watch List CreationFigure 3:
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A u t h o r s
wDamien Polansky is global
strategic marketing
director of Dow Electrical
& Telecommunications.
Brent Richardson is
North American manager
of end use marketing
at Dow Electrical &
Telecommunications.
Whether talking about aesthetic appeal
in new residential and commercial zones,
obtaining legal rights of way or economic
loss from storm-related power outages,
putting transmission and distribution
infrastructure underground is a hot topic.
Although underground distribution
is common, one of the largest pain points
is the perceived cost of installation forunderground transmission.
High-voltage underground
transmission installations typically have
higher up-front price tags than overhead
lines; however, as new trenching methods
such as horizontal directional drilling
become more readily available and
technologies create more reliable long-
life cables, costs are moving to a more
equitable position with overhead lines.
This is true especially when seen in the
light of ongoing costs for repair andmaintenance of overhead lines over the life
of the system.
An article in the February 2013 issue of Electric Light
& Power by Frank Alonso and Carolyn Greenwell, both
transmission line engineers with SAIC, aptly states, “The
time is quickly approaching when utility customers and
government officials will demand an answer that provides
a more in-depth, independent look at how much more
expensive underground power delivery is compared with
overhead power delivery. Changes will be precipitated by
power outages associated with natural disasters, citizens
who don’t want their homes devalued by nearby overheadlines, and competitive economic forces that drive utilities to
consider placing power lines underground.”
An August 2013 report from the White House,
“Economic benefits of increasing electric grid resilience to
weather outage,” further supported a position for underground
installations.
“Between 2003 and 2012 roughly 679 power outages,
each affecting at least 50,000 customers, occurred due to
weather events,” according to the report. “Monetary costs of
these outages account for up to between $18 billion and $33
billion annually.”
The Case for Intelligent Undergrounding
Businesses within the entire power industry value chain—
from compound suppliers, accessory component producers to
cable makers, installers and utilities—all have a vested interest
in improving electrical system reliability. This is why Dow
Electrical & Telecommunications (Dow E&T) is advocating
intelligent undergrounding, which is to bury highly reliable,
Intelligent Undergrounding—Burying Highly Reliable Cable
When, Where it Makes Senseby Damien Polansky and Brent Ri chardson, Dow Electrical & Telecommunications
Observed Outages 1992-2012
Sources: Energy Information Administration
1992 1996 2000 2004 2008 2012
Nonweather-related
Weather-related
Unclassified
160
140
120
100
80
60
40
20
0
E v e n t s
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polyethylene-based cable when and where it makes sense: cross-
linked polyethylene (XLPE) for high-voltage transmission and tree-
retardant XLPE (TR-XLPE) for medium-voltage distribution.
Three recent examples include projects initiated by Wisconsin
Public Service (WPS), which services 440,000 customers in rural
Wisconsin, and Dominion Virginia Power, the largest electric utility
in Virginia with 2.3 million customers.1. As reported in the July 23, 2013, issue of the Milwaukee Journal
Sentinel, “The five-year project (for WPS) will involve burying
distribution lines underground along hundreds of miles of power
lines in rural areas.” Vern Peterson, vice president of energy
delivery for WPS, was quoted as saying, “In the affected areas,
electric reliability is significantly lower than state and national
averages. The areas we will target are those in which customers
are repeatedly faced with the loss of power due to storms—
sometimes for several days.” The article went on to state, “The
project is expected to add between $4 and $5 a month for a
typical utility customer.”
2. In another good example of intelligent undergrounding,Dominion Virginia Power won a Southeastern Electric Exchange
(SEE) Industry Excellence Award in the Transmission Line
Category for its Pleasant View-Hamilton 230-kV project in 2011.
The project addressed electricity demand and desired property
aesthetics. As stated in the presentation abstract, “To meet the
increased demand for electricity in western Loudoun County,
Dominion Virginia Power built a new 230 kV transmission line
to serve the areas west of Leesburg. The total length of new
line is 12 miles, with 2 miles installed underground with solid
dielectric XLPE cable. The underground portion of the project is
sited in an upscale neighborhood along a popular nature trail.”
3. Similarly, in the July 19, 2013, Richmond Times-Dispatch,Dominion Virginia Power released information from a study
that indicated, “Undergrounding 20 percent of the company’s
worst-performing residential lines could reduce by 63 percent
the number of repairs required to restore power to all customers
as a result of damage from major storms.” Rodney Blevins, vice
president of distribution operations, said, “Ninety-nine percent of
the utility’s storm-related outages happen on its overhead power
lines. While underground lines are significantly more expensive
to install and maintain than lines strung on poles, restoring power
after a storm also is expensive, typically costing the company $4
million to $14 million per day of outage.” Dominion Virginia
Power has a goal to put 350 miles of line underground per year—at an estimated cost of $175 million annually— until 4,000 miles
have been moved. Senate Democratic Leader Richard L. Saslaw,
who sponsored the legislation for this underground project, said,
“The rate increase could range from 70 cents a month at the start
of the project to $4 per month by its completion.”
These examples of intelligent undergrounding underscore
the where and when it’s needed: weather-related outages, relieving
congestion and reduction in the physical space needed for rights of
way and preserving aesthetics in natural areas. They also provide a
clearer understanding regarding cost. Data that objectively compares
the upfront cost of underground vs. overhead lines is limited. Every
project is unique with widely varying costs; however, when all factors
are considered in the total life cycle of the assets, undergrounding
can be cost-effective, particularly when spread over time and among
many customers and when weighed against the cost of repairs and
reputation when it comes to system reliability.
Quality Materials Matter
Cable compound suppliers are a critical part of the value chain in
the power industry and can have a huge impact on power system
reliability. Cable manufacturers and utilities have many choices
when it comes to specifying materials to manufacture cables. Yearsof experience and data from independent testing institutes indicate
that XLPE and TR-XLPE continue to provide the best performance
for robust manufacturing, ease of installation and high electrical
breakdown strength that ensures failure-free operation and lower
electrical losses over the lifetime of the cable.
Quality materials made to meet or exceed stringent industry
standards are key to long-life, reliable cables that extend that
reliability to the underground systems in which they are placed.
Thinking Ahead
Ongoing scrutiny of aging power grids and decisions for the
best systems to support new infrastructure will keep the debate ofoverhead vs. underground lines going for a long while. This is where
intelligent undergrounding best fits. The industry must come together
to weigh all factors objectively into the analysis between underground
and overhead line systems. The industry, however, shouldn’t look at
underground and overhead lines as mutually exclusive, but potentially
working in tandem to quantify the first and long-term costs to
determine when and where each makes sense. All participants in the
power value chain can share their collective experience to benefit
the entire industry to ensure reliable, long-life service of electrical
infrastructure that delivers peace of mind to utilities and their
customers for decades.
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aHow to Assess the Benefitsof Transmission Investment
As electric infrastructure becomes increasingly complex and
our economic challenges progressively demanding, accurate-
ly assessing the benefits of transmission investment is becom-
ing more important.
In the past, most transmission projects were developed
by vertically integrated utilities that built new lines to connect
new generation to serve growing demand within their service
territories. Then, benefits were relatively easy to recognize
and costs easy to allocate.
Now, the grid is a complex network of power lines, sub-
stations and control centers operated by multiple entities thatoften span state, regional and international boundaries that
serve a broad range of residential, commercial
and industrial customers.
Assessing the benefits of transmission
investment is an essential part of determining
operational characteristics, reliability objectives
and capital costs, but it also is important when
considering public policy objectives, regulatory
and market conditions and economic and envi-
ronmental impact, all of which can be critical
when establishing project priorities and cost al-
locations.Although integrated utilities continue to
build transmission to serve the needs of their
customers, decisions about which projects to
pursue, what technologies to leverage and how
to recover costs for those investments still re-
quire more thorough cost-benefit assessments.
This can be particularly challenging when the target con-
tinues to move and demand growth and generation capacity
changes cannot always be accurately modeled or predicted.
These challenges are further exacerbated by ongoing changes
in cost allocation and cost recovery schemes that continue to
evolve on a case-by-case basis. Many projects are motivatedby a few key objectives, such as the integration of renewables,
improved reliability under N-1 conditions or other primary
objectives, and secondary or tertiary benefits also are general-
ly realized but not necessarily factored in during assessments.
For instance, the use of a high-capacity, low-resistance
conductor such as ACCC to increase the capacity of a section
of the grid to accommodate an N-1 condition also will reduce
its electrical resistance substantially during normal operating
conditions. This reduction in line losses will free up genera-
tion capacity, which then can be deployed to a paying cus-
tomer or, conversely, conserved to reduce fuel consumption
and associated emissions. Transmission planners might not
always recognize or consider second- or third-tier benefits,
but these benefits have a profound impact on the overall per-
formance of the grid, are quantifiable and should and will be
considered.
As the focus of transmission planning has expanded dur-
ing the past dozen or so years to better address reliability con-
cerns, market efficiency and public policy drivers, new Feder-
al Energy Regulatory Commission (FERC) requirements for
cost allocations have driven the need to develop better ways
to assess transmission benefits. The cost-benefit analysisrequirement has attracted the attention of policymakers and
others who must pay for the transmission investments. As a
result, transmission companies and regional transmission op-
erators (RTOs) have developed improved methodologies for
evaluating the benefits of transmission projects.
Many of the current methodologies use formulaic meth-
ods to consider market and reliability attributes, but they of-ten rely on simplified production cost analyses to measure
economic benefits. Unfortunately, simplified production cost
analyses cannot measure many potential and significant ben-
efits associated with transmission projects that can prevent
many of the difficult-to-quantify yet desirable projects from
securing approval.
As a number of transmission planners and RTOs rec-
ognize the need to broaden their perspectives on the benefits
of transmission investment, efforts are being undertaken to
identify and communicate these benefits using a more com-
prehensive business case approach. Because no industry
by Dave Bryant, CTC Global Corp.
A u t h o r
Dave Bryant is director of
technology at CTC Global
Corp. and was one of
the original developers
of the high-capacity
low-loss ACCC conductorand ancillary hardware
components. Reach him at
Conventional ACSR and modern high-capacity, low-loss (ACCC) conductors
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standard for this exists, the Working Group for Investment in Reliable
and Economic Electric Systems (WIRES) commissioned The Brattle
Group to research the subject and offer guidance. The Brattle Groupsubsequently published a report, “The Benefits of Electric Transmis-
sion: Identifying and Analyzing the Value of Investments.” This and
other informative reports are available on the WIRES website, www.
wiresgroup.com.
The report identifies a broad range of potential transmission-
related benefits, performance metrics and approaches through which
any specific project or group of projects can be more effectively eval-
uated. Benefit categories included traditional production cost savings,
which are commonly used to consider the economic benefits of trans-
mission investments based on estimated reductions in fuel or other
generation production costs, the impact on wholesale market pricing
(often referred to as locational marginal prices (LMPs)) and trans-mission congestion reductions based on grid constraints, load flow
approximations and other assumptions. Using this approach, RTOs
such as PJM often cite reductions in congestion costs as the primary
economic driver for transmission investment. The economic relief
of reduced congestion costs is reflected in production cost savings,
given access to lower cost generation, and reduced market supply or
demand leverage.
Although assessing production cost savings has become a wide-
ly accepted method for evaluating proposed transmission projects
and groups of projects as they are readily estimated, the results are
based on simplified assumptions and short-term dispatch cost savings
that can underestimate the actual
project value. In addition, produc-
tion cost savings only represent a
portion of the overall value of the
transmission investment benefits.
Aside from production cost
savings, The Brattle Group reportdescribes other benefits, particu-
larly those associated with im-
proved reliability, reduced genera-
tion capital costs, reduced market
leverage and several others, which
often have been omitted in many
transmission benefit-cost analy-
ses. These omitted benefits have
been considered intangible be-
cause they generally are not con-
sidered. Although some of these
additional benefits can be difficultto estimate, omitting them implies
they have no value, which is not
the case. A more accurate ap-
proach to estimations would be to
consider a broader range of likely
benefits in any given scenario. This would yield more accurate cost-
benefit analyses, provide greater insight and a better basis for project
comparison, which would reduce the likelihood that beneficial proj-
ects would be overlooked.
Other benefits might include long-term capital and operationalcost savings, line loss reductions, generation capacity cost savings,
improved grid reliability and the potential avoidance of disruptive and
costly outages. Additional benefits also could include the improved
use of existing corridors to reduce environmental impact, reductions
of greenhouse gas emissions through improved transmission effi-
ciency and by opening access to cleaner generation. Other substan-
tial benefits could include economic development opportunities that
could provide residential, commercial and industrial customers with
access to more efficient, affordable and reliable power, which is a key
component of our ability to maintain competitive businesses, employ-
ment opportunities and quality of life.
Potential transmission-related benefits include traditional
production cost savings, the impact on wholesale market
pricing and transmission congestion reductions based on grid
constraints, load flow approximations and other assumptions.
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A u t h o r s
Rebecca Craft is a
director at Con Edison
who is responsible
for the development,
implementationand management
of the utility’s
energy efficiency
and demand-side
management programs.
Bennett Fisher is CEO
of Retroficiency, which
he co-founded in 2009.
He has spent more
than a decade building
and leading companiesaround data analytics.
bBuildings consume 40 percent of all U.S. energy, and up to half
of the energy that buildings use is routinely wasted, according
to data from the Energy Information Administration and IBM.
All that waste is bad for the environment.
“Commercial buildings account for the majority of harm-
ful (CO2) emissions in U.S. cities,” according to the Environ-
mental Protection Agency, and in New York alone, “80 percent
of carbon emissions come from commercial buildings.”
It’s no wonder building efficiency is garnering so much at-
tention. North American utilities, according to the Consortium
of Energy Efficiency, budget more than $9 billion annually fordemand-side management (DSM) programs, including energy
efficiency and demand response initiatives, to reduce consump-
tion and demand. Most of this spending targets buildings.
These ratepayer-funded programs have increasingly ag-
gressive consumption-reduction goals that utilities such as Con
Edison must meet.
But DSM mandates are not the only drivers for energy ef-
ficiency and demand management efforts. DSM also can target
specific areas of the grid to manage demand growth, supply
constraints and ongoing network maintenance more effectively.
The American Association of Civil Engineers calculates
that an additional $107 billion of investment beyond the cur-rently anticipated investment of $566 billion is needed by 2020
just to keep the power grid functioning. Nearly 90 percent of
this incremental need is for electric grid investments required to
maintain current levels of safety and reliability.
Today’s utilities face the need to build additional infra-
structure to meet increasing customer demand for electricity.
In areas such as New York City, however, the density and cost
of system upgrades can present capital expenditure and timing
challenges.
DSM is a cost-effective way to address electric demand
growth via customer-sided energy management and can allevi-
ate strains on the existing power grid while deferring or avoid-ing new infrastructure needs. According to the National Acade-
my of Sciences, the United States could cost-effectively reduce
its 2020 energy consumption by 17 to 20 percent through ex-
panded use of energy efficiency technologies. Likewise, Ret-
roficiency’s data indicates that buildings, on average, can cost-
effectively save 18 percent through efficiency upgrades such as
LED lighting, high-efficiency air conditioning and streamlined
building operations.
Despite the significant opportunities, scalability of the
nation’s energy efficiency opportunity is not being realized
largely because of the significant time and expense involved
in understanding how a building uses and loses energy. For
decades, utility programs and building owners have relied on
manual and expensive in-person audits to try to identify spe-
cific energy-saving opportunities.
Retroficiency estimates that relying on those traditional
methods, it would cost some $25 billion to $50 billion to
conduct an energy audit of every commercial building in the
United States, and when completed, not a single kilowatt-
hour would have been saved.
Often when dealing with infrastructure constraints andprogram goal mandates, time is not a luxury utilities and
building owners can afford.
During the past decade, Con Edison has taken a leader-
ship role in using DSM to target areas of its electric grid in
New York City and Westchester County. The Con Edison Tar-
geted Demand Side Management (TDSM) program focuses
on mitigating peak demand and growth to optimize the use of
existing assets in the company’s electric networks. With more
than $300 million in net benefits—total benefits minus costs—
to ratepayers, Con Edison’s TDSM is an important example
of how customer demand-side reductions can be used to meet
utility supply-side needs. To date, the program has provedDSM is a viable solution to address utility infrastructure con-
straints. Continued projected increases in customer demand for
electricity make it clear to Con Edison that geo-targeted DSM
will continue to play an important role.
To accelerate and enhance its demand management initia-
tives, Con Edison is using Retroficiency’s energy analytics to
identify and evaluate energy efficiency opportunities at scale.
Retroficiency’s solution uses meter data to understand the
energy-savings potential and opportunities for each building.
Retroficiency has analyzed nearly 900 commercial and
multifamily buildings (buildings with more than 100 kW
Energy-efficient Buildings,Analytics and Con Edison
by Rebecca Craft, Con Edison, and Bennett Fisher, Retroficiency
© c a n s t o
c k p h o t o . c
o m
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Panel Session 1: Policy and Strategy Evolution
Panel Session 3: Impact on Utility Planning and Operations
Panel Session 2: Whose Customer Is It Anyway?
Panel Session 4: e View From the Top
Electric Light & Power and POWERGRID International Awards Dinner Join us for an evening of cocktails , music and dinner whi le networking with colleagues,our Utility CEOs of the Year and executives from our Utility of the Year.
FEBRUARY 2, 2015Omni San Diego Hotel • San Diego, California
www.elpconference.com
2015 CONFERENCE PROGRAMDISRUPTING EVERY RULE: THE EVOLVING UTILITY
Owned & Produced by: Offi cial Publication:
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SPACE IS LIMITED, REGISTER EARLY!
Individual Full Conference Registration when you register on or before Nov. 14!
Visit elpconference.com to register and for complete conference details.
Katherine Hamilton Policy Director Energy Storage Association
Richard McMahonVice President Edison Electric Institute
Mike HylandSenior Vice President, Engineering Services American Public Power Association
Heather Sanders Director, Regulatory Affairs – Distributed Energy ResourcesCalifornia ISO
Jorge CardenasVice President of Asset Management andCentralized ServicesPSE&G
Robert F. CaldwellVice President, RenewableGeneration Development Duke Energy
Shay Bahramirad Manager of Smart Gridand TechnologyComEd
Pete ScarpelliVice President, Global Director of Energy &SustainabilityCBRE
Adam MillerSenior Director, InnovationDirect Energy
Caroline WinnVice President, CustomerServices and ChiefCustomer Privacy Offi cer San Diego Gas& Electric
Pete Delaney Chairman, Presidentand CEOOGE Energy Corp.
William H. SpenceChairman, Presidentand CEOPPL Corp.
Joe Rigby Chairman, President and CEOPepco Holdings Inc.
Gale KlappaChairman and CEO Wisconsin Energy Corp.
John Di StasioFormer General Manager and CEO(retired April 2014)Sacramento MunicipalUtility District
$595
Go to http://uaelp.hotims.com for more information.
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billed high demand) in nine of Con Edison’s electric networks. These
buildings accounted for a total annual consumption of 1.4 TWh. In
total, Retroficiency identified 176.4 GWh of cost-effective savings,
a 13 percent potential kWh energy savings for the analyzed portfo-
lio. The buildings with highest potential have an average kilowatt-
hour energy-saving opportunity of 25 percent. There are a host of
operational and retrofit measure possibilities in these buildings. Theanalysis identified 23 MW of permanent demand reduction potential
during network peak times, or some 6 percent of the total peak load,
with the highest potential buildings’ averaging 11 percent in demand
reduction potential during the relevant network peak. These results
demonstrate that even with Con Edison’s successes to date, energy
efficiency and demand management remain a highly viable resource
to manage network load growth.
All of these insights were uncovered with limited information.
Con Edison provided monthly or 15-minute interval meter data and
a building address to Retroficiency. Retroficiency combined its own
data sources with publicly available data— including New York City-
specific data sets such as tax records and building information—andthen churned that information through its analytical engine, which
assessed each building in minutes.
Energy data analytics make it possible for Con Edison to assess
its customer portfolio at a rate and scale that would be impossible
through traditional in-person audit approaches and that would have
been unheard of a few years ago.
Specifically, Con Edison is leveraging analytics to help improve
two key areas of the energy efficiency and demand management de-
livery process:
1) Targeting the right buildings. Retroficiency is helping Con
Edison determine the energy and demand savings potential of
buildings in load-constrained areas to help Con Edison focusresources on the buildings with the highest savings potential.
Retroficiency data shows that 30 percent of the buildings in a
segment can account for 70 percent of the savings opportunity.
Analytics can help pinpoint buildings with opportunities for
various measures, including those that support peak reduction,
which is critical when applying energy efficiency and demand
management to alleviate grid constraints.
2) Engaging customers with specific opportunities. Advanced
energy analytics also can identify areas of building energy usage
that can benefit most from efficiency measures. With interval
meter data, for example, Retroficiency’s platform makes detailed,
building-specific capital and operational recommendationsto investigate further, all before ever going on-site. These
recommendations, combined with Con Edison’s market, customer
and building technology insights, will allow Con Edison to deliver
a personalized energy management message to each customer. To
maximize effectiveness of each customer touch point, analytics-
based insights can be delivered through multiple delivery channels,
including print, email, the Web and customer account managers.
Improving the targeting and engagement process has the poten-
tial to convert more and deeper energy savings projects, which is the
primary goal.
Improved customer engagement has several other benefits.
Multiple studies have shown that customers who participate in energy
efficiency programs are more satisfied with their utilities. In addition,
delivering detailed, meaningful information to customers positions the
utility as a trusted provider of energy management solutions. As the
utility business model evolves in the face of new competitive dynam-
ics and regulatory shifts, utilities will need to reframe their customerrelationships. Analytic-enabled engagement is a step toward that end.
When and where should utilities consider deploying energy ana-
lytic solutions? Analytics also can determine when cost-effective ener-
gy savings changes are possible, such as during peak-demand periods.
This means that analytics solutions can be leveraged for either:
1. Ratepayer-funded energy efficiency or demand reduction
programs, or
2. When utilities are seeking to employ DSM as a mechanism to
manage demand on its system.
When it comes to commercial efficiency programs, energy ana-
lytics can help achieve deeper savings as utilities and regulators seekadditional energy efficiency and demand management opportunities.
Analytics help utilities go beyond traditional reliance on lighting proj-
ects (which account only for 25 to 30 percent of a building’s overall
energy-savings potential, on average) to drive projects from a variety of
measures, according to Retroficiency data.
In addition, analytics can help tap new customer segments. Many
of the largest customers participate in energy efficiency programs, but
small to midsize customers also have significant savings potential. The
small to midsize buildings and small portfolios sector “contain(s) a
whopping 95 percent of all commercial buildings by number and rep-
resents almost half of energy consumption in commercial buildings,”
according to the Preservation Green Lab in partnership with the NewBuildings Institute. As such, this group’s energy savings potential pro-
vides significant opportunities for energy savings and demand reduc-
tions. Energy analytics are enabling utilities to evaluate their entire com-
mercial building portfolios.
Energy analytics enable DSM insights and associated solutions to
become scalable. Policy increasingly favors building fewer new power
plants and closing old, polluting coal plants while providing a steady,
safe power supply to customers. Four U.S. nuclear power plants were
retired in 2013, and there is potential for more plants to shut down. One
such plant is the Indian Point Energy Center in Westchester County. In-
dian Point supplies electricity for Con Edison customers in New York
City and Westchester.From a network management perspective, the loss of supply re-
sources must be planned for appropriately. Efficiency, demand response,
storage and other load management solutions, such as those being de-
ployed by the joint Con Edison and New York State Research and De-
velopment Authority (NYSERDA) Demand Management Program, as
well as clean generation technologies such as solar, wind and geother-
mal, will combine to play a key role in the energy landscape.
As the grid gets smarter and data more accessible, utilities such as
Con Edison are looking to energy analytics to help identify and grow
their DSM opportunities. This will help utilities focus on keeping the
power flowing safely and efficiently.
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CS Week
Momentum in Utility EducationRecord attendance, enthusiastic participants and overall growth across all the components of CS Week
2014 and Conference 38 leave us with a single question: How do we capitalize on this energy and myriad
ideas to create an even better CS Week for Charlotte, North Carolina, in 2015?
There is a synergy that develops among those utility professionals who attend their first CS Week.You can hear it between workshops, watch it develop during lunch or other social gatherings. From our
point of view, meeting the educational goals of new attendees benefits not only individuals but their utili-
ties, as well.
Executive Summit doubled in participants for 2014—a clear reflection of the pressures in the industry
and the commitment of executives to seek new, innovative solutions to strengthen their utilities. Strategic
discussions and tough topics are de rigueur for Executive Summit participants. Key Account executives
face unique challenges in their close relationships with major customers. The growth in this year’s Key
Account Forum and the caliber of participants will push the Key Account Forum steering committee to
develop ever richer content and speakers.
Meeting the challenges created by this year’s successes already has begun. The annual call for presen-
tations invites utility professionals to submit abstracts for CS Week 2015 workshops that address projects,
solutions or challenges faced in customer engagement, mobile, information technology and smart infra-structure areas. Recruiting utility speakers with their firsthand knowledge of utility-specific issues sets CS
Week apart from other conferences.
This year’s Expanding Excellence Awards, presented in concert with PennWell, reinforced the excel-
lence and ingenuity utilities are bringing to serving their customers. CS Week 2014 attendees had opportu-
nities each day to take part in workshops conducted by the two winning utilities in each category.
CS Week webinars are growing a year-round following, as is our social media presence on Facebook,
Twitter and LinkedIn. New directions, strategies and implementation will build on the growth and excite-
ment of CS Week in San Antonio as our board of directors, planning committee and executive advisory
panel meet in September to create a powerhouse CS Week 2015 in Charlotte. Mark your calendars for April
27 to May 1, 2015.
Rod Litke, CEO, CS Week
For more information, please visit www.csweek.org
Complete information at your
fingertips. www.csweek.org
C h a r l o t t e ( N o r t h C a r o l i n a ) C o n v e n t i o n C e n t e r | A p r i l 2 7 – M a y 1 , 2 0 1 5
Ad Index
Ad index name. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .PG#3M. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11
Asplundh Tree Expert Co.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .19
CB&I. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5
Electric Light & Power Executive Conference 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .37Electric Light & Power Webcasts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18
Enoserv . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9
GenForum. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .27
Leidos . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .C4
Navigant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7
Quanta Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .C2
RES Americas Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .23
Sabre Communications. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .C3
Siemens AG. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3
Siemens Corp . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1
Wright Service Corp. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .21
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S P E C I A L
40 | ELECTRICLIGHT& POWER Jul|Aug|2014
Customer Opinion, Fossil FuelsTop EEI Conversations
Editor in Chief Teresa Hansen joined utility VIPs this summer in Las Vegas for the EEIAnnual Convention. These are the most memorable quotes from the week.
“Public opinion aboutcoal-fired power and greenhouse gas is formed.Utilities should embraceit. It’s happening. You
have to be there whenit (public opinion) is formed. You can’t changeit once it’s formed.”
— Warren Buffett Chairman and CEO,
Berkshire Hathaway
“As we shift to natural gas and more renewables, weare offering our customers more volatility. The riskis going up. The more generation we move to natural gas and renewables, the more we need to balancewith nuclear and coal for a sense of certainty.”
— Tom Fanning
Chairman, President and CEO, Southern Co.
“The price of natural gas has reordered the stack. Distributed generation will have the second biggest impact (on generation).”
— Ted Craver
Chairman, Edison International
“During the polar vortex, 89 percent of our coal that is slated toretire in mid- to late 2015 ran at more than 50 percent capacity.We didn’t have a prayer of getting enough natural gas because of pipeline infrastructure (constraints) and customer heating was the priority, and you can’t cut much customer demand in the winter.”
— Nick Akins
Chairman, President and CEO, American Electric Power
8/11/2019 electric light and power jul-ago.pdf
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8/11/2019 electric light and power jul-ago.pdf
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Hard hats to black hats,Leidos knows utility security.
![arXiv:1502.03840v2 [q-fin.EC] 6 Jul 2015arXiv:1502.03840v2 [q-fin.EC] 6 Jul 2015 Market Dynamics and Indirect Network Effects in Electric Vehicle Diffusion Zhe Yua, Shanjun Lib,∗,](https://img.pdfslide.net/doc/110x75/5ec961a49c4c5121401a1ebe/arxiv150203840v2-q-finec-6-jul-2015-arxiv150203840v2-q-finec-6-jul-2015.jpg)
