nhathongminhvn september 11:2015
DESCRIPTION
Now more than ever, utilities are searching for the most economical path to comply with environmental regulation...TRANSCRIPT
Sep|Oct|2015
volume 93|5
www.elp.com
The Business of Power for Utility Executives
Plant Ops: Fly, Don’t Drive
Keeping Up with the Amazons
Absolute PowerWashington D.C. Leaders Making Rules for Utilities
1509ELP_C1 1 10/8/15 9:08 AM
Go to http://uaelp.hotims.com for more information.
Go to http://uaelp.hotims.com for more information.
1509ELP_C2 2 10/8/15 8:06 AM
Go to http://uaelp.hotims.com for more information.
Owned and Produced by: Offi cial Publication: Co-located with: Host Utility:
Electric Light & Power Executive ConferenceFebruary 8, 2016 • Hyatt Regency Orlando • Orlando, Florida
w w w . e l p c o n f e r e n c e . c o m
Register Todaywww.elpconference.com
Only $395 until Nov. 12!
1509ELP_1 1 10/8/15 7:54 AM
The business of power for utility executives
2 | ElEctriclight&PowEr Sep|Oct|2015
Sep|Oct|2015
volume 93|5
Events 4
Commentary 5
COLUMNS
Customer Service: Utility Style 6
AMP can be Win-Win
by Penni McLean-Conner,
Eversource Energy
Economic Inquiry 7
A Synopsis of Changes
in the Clean Power Plan
by Tanya Bodell,
Energyzt
SECTIONS
Feature New OSHA 8
Reporting Requirements
by Stephen Cockerham,
Husch Blackwell
Finance Clean Power Plan Only one 10
of Fed Issues Facing Utilities
by Rod Walton,
Senior Editor
Generation Coal Share of U.S. 14
Power Generation Falls
by Barry Cassell,
GenerationHub
Future of Plant Operations: 16
Fly, Don’t Drive
by Rosco Backus,
Versify Solutions
Renewables/Sustainability Energy Storage as Consumer Product: 18
Following Path of Rooftop Solar?
by Jessica Harrison,
DNV GL
Solar Power’s Future Looks Bright 20
by Teresa Hansen,
Chief Editor
Customers 21 Utilities Knock, Knock
Knocking on Changes’s Door
by Gadi Solotorevsky,
cVidya
24 Keeping up With the Amazons:
How Data Analytics Helps
by Micah DeHenau,
Vertex
26 Virtual Assistant Drives Self-Service
Adoption at TXU Energy
by Jeff Camp,
TXU Energy
and Dave Parkinson,
Interactions LLC
27 Fall, a Time for Change
by Rod Litke,
CS Week
T&D Operations 28 Utilities on Front Lines
of Environmental Stewardship
by Linda Blair,
ITC Holdings Corp.
30 Benchmarking in Action:
Comparing Costs of HVDC
by Steven J. Morris,
UMS Group Inc.
Energy Efficiency & Demand Response 32 Future of Demand Response:
A Practitioner’s View
by Ed Thomas,
Peak Load Management Alliance
34 Texas School District Slashes Costs
With Solar and Ice-based Storage
by Mark MacCracken,
CALMAC Manufacturing Corp.
Fight the Good FIght
36 Companies Must Battle
Against Data Theft
by Jay Mecredy,
Courion Corp.
8
10
34
28
16
21
1509ELP_2 2 10/8/15 7:54 AM
Yes, S&C’s self-healing grids are proven to pay for
themselves. They do this by avoiding unnecessary
truck roles, costly equipment damage, and reducing
customer outages.
It doesn’t matter if you have 10 or 1,000 switching
points, our fast and intelligent self-healing solutions
have proven to deliver cost savings for utilities around
the world.
Rather then let us tell you, let us show you. Contact
us today and we will help you build the economic case
for self-healing grids.
Scan the QR code
below to watch a
video and learn about
the economic impact
of turning the old grid
into the smart grid.
Or visit us at:
sandc.com/sg
Is there a business case forself-healing grids?
©2015 S&C Electric Company 1048-A1502
Go to http://uaelp.hotims.com for more information.
1509ELP_3 3 10/8/15 7:54 AM
E V E N T S
ElEctriclight&PowEr is the official supporting publication of
Feb. 9-11, 2016 : Orange County Convention Center, Orlando, Florida
ElEctriclight&PowEr is the official print publication of
Feb. 8, 2016 : Hyatt Regency Orlando, Florida
ElEctriclight&PowEr is the official print publication of
April 25 - 29, 2016 : Phoenix
ELECTRIC LIGHT & POWER, ISSN 0013-4120, USPS 858-860 is published six times a year in January/February, March/April, May/June, July/August, September/October and
November/December by PennWell Corp., 1421 S. Sheridan Road, Tulsa, OK 74112; phone 918-835-3161. © Copyright 2015 by PennWell Corp. (Registered in U.S. Patent
Trademark Office). Authorization to photocopy items for internal or personal use, or the internal or personal use of specific clients, is granted by ELECTRIC LIGHT & POWER, ISSN
0013-4120, provided that the appropriate fee is paid directly to Copyright Clearance Center, 222 Rosewood Drive, Danvers, MA 01923 USA 978-750-8400. Prior to photocopying
items for educational classroom use please contact Copyright Clearance Center, 222 Rosewood Drive, Danvers, MA 01923 USA 978-750-8400. Periodicals Class postage paid at
Tulsa, OK, and additional mailing offices. Subscription: $100 per year (U.S.), $110 (Canada/Mexico), $265 (international air mail). Single copies: $16 (U.S.), $25 (international
air mail). Back issues of ELECTRIC LIGHT & POWER may be purchased at a cost of $16 each in the U.S. and $25 elsewhere. Copies of back issues are also available on microfilm
and microfiche from University Microfilm, a Xerox Co., 300 N. Zeeb Road, Ann Arbor, MI 48103. Available on the NEXIS™ Service, Mead Data Central Inc., Box 933, Dayton, OH
45402; 937-865-6800. POSTMASTER: Send address changes to ELECTRIC LIGHT & POWER, P.O. Box 3264, Northbrook, IL 60065-3264. ™ “EL&P’’ and “Electric Light & Power’’ are
registered trademarks of PennWell Corp. We make portions of our subscriber list available to carefully screened companies that offer products and services that may be important
for your work. If you do not want to receive those offers and/or information, please let us know by contacting us at List Services, ELP, 1421 S. Sheridan Road, Tulsa, OK 74112.
Member GST No. 126813153
American Business Press Publications Mail
BPA International Agreement No. 40052420
Printed in the U.S.A.
1421 S. Sheridan Road, Tulsa, OK 74112 : P.O. Box 1260, Tulsa, OK 74101
918-835-3161 : fax 918-831-9834 : [email protected] : www.elp.com
Subscriber Service : P.O. Box 3264, Northbrook, IL 60065 : 847-763-9540 : fax 847-763-9607 : [email protected]
4 | ElEctriclight&PowEr Sep|Oct|2015
Senior Vice President, North American Power Group Richard Baker
918-831-9187 : [email protected]
Art Director
Heather Skeith 918-831-9176 : [email protected]
Exhibitor Service Manager DistribuTECH Jared Auld
918-831-9440 : [email protected]
National Sales Manager Tom Leibrandt
918-831-9184 : [email protected]
Audience Development Manager I
Jesse Fyler 918-832-9208 : [email protected]
DistribuTECH Exhibit & Sponsorship Sales Manager Sandy Norris
918-831-9115 : [email protected]
Production Manager
Daniel Greene 918-831-9401 : [email protected]
Reprints Account Executive Rhonda Brown
219-878-6094 : [email protected]
Editor in Chief
Teresa Hansen 918-831-9504 : [email protected]
Senior Editor
Rod Walton 918-831-9177 : [email protected]
Associate/Online Editor
Jeff Postelwait 918-831-9114 : [email protected]
Chairman
Robert F. BiolchiniVice Chairman
Frank T. LauingerPresident and Chief Executive Officer
Mark C. Wilmoth
Should you need assistance with creating your ad, please contact:
Marketing Solutions- Vice President: Paul Andrews Phone: 240.595.2352 Email: [email protected]
Jayne A. Gilsinger
Executive Vice President, Corporate Development and Strategy
Brian Conway Senior Vice President,
Finance and Chief Financial Officer
OCTOBER
25-29
Oracle Open World
https://www.oracle.
com/openworld/
San Francisco
NOVEMBER
3-5
The Bentley Year in
Infrastructure 2015
Conference
http://bit.ly/1RceeID
London
3-5
European Utility Week
http://www.european-
utility-week.com/
Vienna
8-11
Edison Electric Institute
Financial Conference
http://www.eei.org/
about/meetings/
Hollywood, Florida
DECEMBER
8-10
POWER-GEN International
Las Vegas
www.power-gen.com
8-10
Renewable Energy
World North America
Las Vegas
www.renewableenergyworld-
events.com
8-10
Nuclear Power International
Pennwell
Las Vegas
www.nuclearpowerinternational.com
FEBRUARY 2016
8
Electric Light & Power
Executive Conference
www.elpconference.com
Orlando
Standard Mail A Enclosed - P3
The business of power for utility executives
- See more at: http://www.eei.org/about/meetings/
meeting.aspx?EEIEventId=9C004F85-5B8D-471A-
8AC6-B3155370599C#sthash.wyoe086W.dpuf
1509ELP_4 4 10/8/15 7:54 AM
Sep|Oct|2015 ElEctriclight&PowEr | 5
Commentary
Teresa Hansen, editor in chief
Taking the Road Less Traveled
As I’ve mentioned before, I live in a small town—about 20,000 people—that owns and
operates the electric and water utilities. Until recently, all residential electric and water
meters were analog and some were more than 50 years old. City officials knew that many
of these meters were not accurate, that it was losing a lot of water through leaks and
substantial revenue through inaccurate electric and water meter readings. In addition, a
number of the residential meters were still self-read. Because most of the city’s operating
revenue comes from its utility operations, officials decided to make the move to smart
meters to reduce revenue and water losses, improve efficiency and eventually pass along time-of-use rates,
which it is already paying to its power supplier. They were and still are convinced this was the right thing to
do and I am, too.
It’s unfortunate, however, that they failed to include the city’s residents in their plans. They thought one or
two short articles in the local newspaper about their plans to move to smart meters was adequate communication.
They didn’t let people know beforehand when they were coming out to change their meters, nor did they let
them know when their new smart meters had been installed. And, even when they began to get wind of the
fact that some customers were complaining about higher bills, were worried about the health effects of smart
meters and were beginning to organize through social media, they remained mostly unconcerned. They acted
as if those people’s concerns were unjustified and didn’t need to be addressed.
Because my husband is a member of the city council, I know firsthand city leaders have since learned
differently. They are beginning to understand that they could have been better communicators, that social media
is a powerful platform for unhappy customers, that transparency is not a bad thing and that customer education
is important.
The latest information from the U.S. Energy Information Administration (EIA) says that approximately 52
million smart meters have been installed in the U.S. Some 46 million are residential, which accounts for more
than 45 percent of all U.S. residences. My little town is not the first to go down this road. Many municipalities,
cooperatives and investor-owned utilities have experienced struggles and unhappy customers during smart
meter rollouts. They’ve learned lessons and developed best practices.
So, how did this happen to my town? The vendor that provided the smart meters has been through similar
experiences with many previous customers. Why didn’t that company warn city leaders and inform them about
the importance of customer education? Why didn’t our city’s leaders already know what could happen? Plenty
has been written and published on the pitfalls of smart meter rollouts.
As the wife of a councilman who can no longer go to dinner or a movie or even a friend’s house without
having to hear about someone’s electric bill, I am a little miffed. I’d like to interject my knowledge and opinion
during these discussions, but learned early on most people don’t want to hear facts; this is an emotional issue
with many.
Our city leaders recently conducted a “town hall” type meeting for customers to voice their concerns. In
addition, the city manager has issued a letter explaining how smart meters work, why the city chose to install
them and how the utilities department is helping those with high bills determine the reason. This is the right
thing to do, but these actions and explanations will be much less impactful now than they would have been if
the city had taken these actions early on.
Successful utilities will be those utilities that value their customers and treat them like they matter. While
many customers don’t have a choice over their electricity provider now, they will someday and they will
remember how they’ve been treated by their utility. So, even if it’s more work and worry up front, in the end, it
pays to take the road less traveled by many utilities and inform and educate your customers about your plans.
1509ELP_5 5 10/8/15 7:54 AM
Customer Service: Utility StyleC O L U M N
6 | ElEctriclight&PowEr Sep|Oct|2015
A u t h o r
Penni McLean-Conner
is the chief customer
officer at Eversource
Energy, the largest
energy delivery
company in New
England. A registered
professional engineer,
McLean-Conner is
active in the utility
industry and serves
on several boards of
directors including CS
Week and the American
Council for an Energy
Efficient Economy. Her
latest book, “Energy
Effciency: Principles and
Practices,” is available
at www.pennwellbooks.
com. Reach her at
penelope.conner@
eversource.com.
While there has been a lot of
discussion and exploration of arrears
or debt management programs,
these programs are still relatively
unavailable for utility customers.
In fact, a review of the most recent
American Gas Association/Edison
Electric Institute Data Source
reveals only 10 utilities offer arrears
management programs (AMPs).
This trend may be changing. Charles
Harak, senior attorney for the National
Consumer Law Center, is a nationally
recognized low-income advocate, and
author of the report “Helping Low-
Income Utility Customers Manage
Overdue Bills Through Arrears
Management Programs” published in
September 2013. Harak later noted that
there has been a “noticeable increase in
requests by utilities and others for more
information on AMP programs since
we issued our AMP report in 2013. The
Maine Legislature in 2014 adopted a law
requiring its public service commission
to adopt an AMP. As information about
their success becomes available, more
utilities and regulators are interested in
exploring AMPs for their customers.
The reason for the interest is that arrears
management programs can provide a
win-win solution for customers, utilities
and regulatory agencies.”
Arrears management programs offer
financial assistance for low-income
customers with overdue utility bills. The
basic concept is that customers enrolled
in an AMP who make the required
affordable payments, are rewarded by
having their arrears forgiven. The best
programs are comprehensive and offer
customers training, budget counseling,
payment plans, arrears forgiveness,
energy efficiency and links to other
financial grants and assistance.
In this series of articles I will
explore arrears management programs.
This first article looks at the business
case for implementing an AMP and
explores the consumer and utility
benefits. Future articles will review the
AMP framework and best practices.
Consumer Benefits
Customers participating in arrears
management programs receive clear
benefits. Those participants gain the
protection against service disconnections
while on the program and can gain a
fresh start by successfully completing
an AMP with arrears that are totally
canceled.
The ultimate goal of these programs
is to move customers from needing
assistance to self-sufficiency. These
programs have demonstrated success
in moving customers from a cycle of
building arrears, being disconnected and
experiencing write-offs, to customers
who can successfully manage and pay
for their energy usage. Their ability to
pay is enhanced through the programs
by providing budget counseling,
implementing energy efficiency measures
and ensuring fuel assistance is secured.
Participating customers can improve
their overall credit ratings and better
manage other bills. The relationship
with the utility changes from one
that is threatening disconnection to
working with the customers as a partner.
Harak’s research additionally showed
the participating customers are more
likely to continue to pay more after
participating in the program than they
did previously.
Utility Benefits
Utilities gain several benefits, too. The
costs associated with collection activities
on these accounts are diminished as
field visits and disconnections are
avoided. In addition, AMP customers
are paying more towards their bills.
Harak’s research provides results from
two utilities. The data revealed that in all
cases AMP customers, when compared
to a group of customers not on AMP,
paid more toward their bill. Write-offs
are correspondingly reduced, because
the dollars billed are being recovered
through a combination of the customer
payments and forgiveness.
Utilities that have successfully
implemented AMPs have worked with
regulators to design regulatory recovery
and reporting for the program. The AMP
costs are allowed to be recovered as part
of rate filings.
Utilities transform the relationship
with the customer into one that is
new and positive. The best AMPs are
comprehensive and provide participating
customers with energy efficiency advice
and services that bring down their total
energy usage. In addition, the program
encourages ongoing communication
from the utility to customers about not
only their progress in reducing arrears
but also with counseling in situations
where customers are struggling to
maintain their AMP plan.
Utilities looking to make a
transformative change in working with
credit-challenged customers should take
a hard look at AMPs. These programs
combined with discounted rates and
energy efficiency programs provide a
holistic approach for credit-challenged
customers. Utilities will often find that
regulators are interested in discussing
AMPs, as these programs help them
fulfill their mandate of assisting those
customers in the greatest need.
For customers, this comprehensive
approach helps them achieve self-
sufficiency. For the utility, this approach
avoids costly field work and can result in
reduced write-offs.
For more information, please review Charlie Harak’s
entire report at: http://www.nclc.org/images/pdf/
energy_utility_telecom/consumer_protection_and_regu-
latory_issues/amp_report_final_sept13.pdf
For more information on the Maine legislation link to: http://
www.mainelegislature.org/legis/bills/getDoc.asp?id=40898
Arrears Management can be a Win-Winby Penni McLean-Conner, Eversource Energy
1509ELP_6 6 10/8/15 7:54 AM
Economic Inquiry C O L U M N
Sep|Oct|2015 ElEctriclight&PowEr | 7
Tanya Bodell is the
executive director of
Energyzt, a global
collaboration of energy
experts who create
value for investors
in energy through
actionable insights.
Visit www.energyzt.com.
Reach her at: tanya.
On Aug. 3, 2015, the U.S.
Environmental Protection
Agency (EPA) issued
the Clean Power Plan
Final Rule to regulate
carbon emissions from
the electricity industry.
Although the general
framework is consistent
with the proposed rule,
the final rule incorporates
concerns expressed in more
than 4 million comments, multiple
lawsuits, Congressional inquiry and
letters from other agencies. Changes
address key critiques concerning
reliability, implementation timelines
and jurisdiction. A brief summary of
major changes embedded in the final
rule is provided below.
Reliability Rules
The proposed rule was criticized for
ignoring potential impacts on system
reliability. Well after the proposed rule
was issued, concerns were raised by
the North American Electric Reliability
Corp. (NERC), Federal Energy
Regulatory Commission (FERC),
Congress and other government
groups. The final rule explicitly
addresses concerns about reliability
in multiple ways. State plans are to be
reviewed for reliability and must show
how potential reliability issues will be
mitigated. A reliability safety valve has
been included to allow states a 90-day
period to exceed carbon limits during
emergencies. Lastly, as described
in more detail below, the initial
deadlines and targets have been relaxed
significantly to create a “glide path”
vs. the original “cliff” with respect to
compliance in order to allow additional
time for required infrastructure
investment to come online.
Requirements
Relaxed
Another key criticism
of the original proposal
was the compliance cliff. As drafted,
states would have only one year in
which to submit a plan by mid-2016
or request a one-year extension. States
submitting regional plans could obtain
a two-year extension. Nearly 80 percent
of the targeted reductions were required
to be realized by 2020, however, with
the remainder achieved within 10
years. Given that much of the requisite
infrastructure investment would require
siting permits, environmental impact
studies and interconnection to existing
electric infrastructure, proposed
compliance requirements were
considered by some to be impossible
to meet. The final rule relaxes the
schedule in multiple ways. First, the
deadline has been shifted to September
2016 for state plan submissions from
June. Second, individual states may
request up to a two-year extension.
Third, targets have been relaxed so that
the 2020 cliff is now a more gradual
decline. Mandatory reductions begin
in 2022 with three stages to phase in of
the “best system of emission reduction”
(BSER) through 2029.
Reductions Removed
The third major change has to do with
the way the EPA calculated emission
targets for each state. The proposed
plan included four building blocks
of BSER technologies, including: 1)
efficiency improvements at coal plants;
2) conversion from high-emitting fuel
sources to lower-emitting resources
(i.e., coal to gas); 3) replacement
of high-emitting resources to zero-
emitting sources (i.e., renewables or
nuclear); and 4) demand-side reductions
such as energy efficiency. Using these
four approaches and consistent rules of
thumb applied to each block, the EPA
established average carbon emissions
levels that could be achieved for each
state. In the Final Rule, the EPA dropped
demand-side reductions from the
calculation and modified the algorithm
for the remaining three to calculate
a final average emissions target that
helped some states and harmed others.
The EPA appears to have removed the
fourth block to defend against litigation
challenging its authority to promulgate
this regulation under the Clean Air Act.
Demand response is not a BSER that
can be adopted by power generators
whereas the other three arguably are
“inside the fence” of emitters.
Ready to Roll
The EPA has issued the Clean Power
Plan Final Rule, a complex regulation
that imposes requirements on new and
existing power generators to reduce
carbon emissions. The most significant
differences between the Final Rule
and the proposed rule are changes to
address reliability, modified timing and
interim targets, and removal of demand-
side response from the equation that
calculates state targets. The net effect
is a rule that may create less havoc
on the power sector from a technical
perspective. From a legal perspective,
however, the jury is still out.
A Synopsis of Changes in the Finalized Clean Power Plan
By Tanya Bodell, Energyzt
A u t h o r
1509ELP_7 7 10/8/15 7:54 AM
8 | ElEctriclight&PowEr Sep|Oct|2015
Feature
The Occupational Safety and Health Administration
(OSHA) has required employers to report work-related
fatalities and hospitalizations of three or more employees
since 1971. Effective January 1, 2015, the reporting
requirements, currently codified at 29 C.F.R. § 1904.39, have
significantly expanded, allowing OSHA to more quickly and
effectively target occupational safety and health hazards.
The new requirements apply to all employers under OSHA’s
jurisdiction, although states with their own occupational safety
and health agencies might have different effective dates.
The New Rule
Under the new rule, employers are required to report:
• Each fatality within eight hours, if the death occurred
within 30 days of the work-related incident.
• Each inpatient hospitalization, amputation or loss of an
eye within 24 hours, for those losses occurring within 24
hours of the work-related incident.
The new rule expands the list of severe work-related
injuries that employers must report to OSHA. The agency
contends that incidents that previously were not reported,
such as amputations and hospitalizations of fewer than three
employees, are egregious events that should be reported.
OSHA anticipates 25,000 additional reports per year under
the new rule.
“OSHA will now receive crucial reports of fatalities and
severe work-related injuries and illnesses that will significantly
enhance the agency’s ability to target our resources, save lives
and prevent further injury and illness,” said David Michaels,
assistant secretary of labor for OSHA. “This new data will
enable the agency to identify the workplaces where workers
are at the greatest risk and target our compliance assistance
and enforcement resources accordingly.”
As predicted, since its implementation, the rule has
focused OSHA’s attention on industries and hazards that
had previously slipped through the regulatory cracks. For
example, the new reporting requirements identified an
unexpectedly high number of amputations at supermarkets.
In response, OSHA recently issued a safety fact sheet focused
on preventing injuries to food slicers and meat grinders.
Changes From the Old Rule
Under the old rule, employers had to report only fatalities and
inpatient hospitalizations of three or more employees from
a work-related incident. The new rule requires employers to
report the inpatient hospitalization of only one employee, but
the period of time an employer has to report a hospitalization
has increased from eight hours to 24.
The new rule also adds the requirement of reporting accidents
that result in an amputation or the loss of an eye. Additionally, the
new rule requires that a fatality, hospitalization, amputation
or loss of an eye be recorded in an employer’s OSHA injury
and illness records if work-related (and if the employer is
required to keep those records), even if it occurs outside of
the time frame required for reporting under the new rule.
Hospitalization is defined by the new rule as “a formal
admission to the inpatient service of a hospital or clinic for
care or treatment.” Under this definition, emergency room
By Stephen Cockerham, Husch Blackwell
Stephen Cockerham
is a labor and
employment attorney
on the Energy & Natural
Resources team at
Missouri-based legal
firm Husch Blackwell.
A u t h o r
OSHA Reporting Requirements
New
1509ELP_8 8 10/8/15 7:54 AM
ElEctriclight&PowEr | 9Sep|Oct|2015
Featurevisits or admissions that are purely for observation or diagnostic
testing are not covered. “Amputation” is defined in the new rule as
“a traumatic loss of a limb or other external body part. Amputations
include a part, such as a limb or appendage with or without bone loss;
medical amputations resulting from irreparable damage; amputations
of body parts that have since been reattached.”
Employers reporting a fatality, inpatient hospitalization, amputation
or loss of an eye to OSHA must report the following information:
• Establishment name
• Location of the work-related incident
• Time of the work-related incident
• Type of reportable event (i.e., fatality, inpatient hospitalization,
amputation or loss of an eye)
• Number of employees who suffered the event
• Names of the employees who suffered the event
• Contact person and his or her phone number
• Brief description of the work-related incident
This, for the most part, is consistent with the old rule, but adds
the requirement to report the “type of reportable event.”
Exemptions
The reporting requirements discussed above apply to all employers
under OSHA’s jurisdiction, even if the employer is otherwise exempt
from OSHA’s routine recordkeeping requirements (employers with
10 or fewer employees).
The new rule also updates what industries are and are not exempt
from the requirement to routinely keep OSHA injury and illness records,
based on their low occupational injury and illness rates. The new list
of exempt industries is derived from injury and illness data from the
Bureau of Labor Statistics from 2007-2009 and the North American
Industry Classification System. The net result is that more industries
are now exempt from the routine recordkeeping requirements. Yet the
new rule retains the exemption for any establishment with 10 or fewer
employees, regardless of industry classification.
How to Report
Employers can report to OSHA by either:
• Calling the nearest local OSHA office during normal business hours
• Calling OSHA’s free and confidential number at 800-321-6742
• Using the new online form that will be available soon on OSHA’s
public website at https://www.osha.gov/report_online.
Issues and Concerns
As with the implementation of any new rule, the extended reporting
requirements come with an influx of new issues and concerns. To aid
in its application, OSHA will be issuing interpretation letters further
explaining the nuances of the new rule.
One concern is whether local OSHA offices will be overwhelmed
by an increased number of injury reports. OSHA estimated that it
will receive about 30 times as many reports under the new rule as it
has received under the old reporting requirements. In response to this
concern, OSHA claims that it will be able to respond in some manner
to all reports, just not always with an inspection. Rather, it will
determine on a case-by-case basis whether to launch an inspection.
Around 40 percent of the reports in the first half of 2015 prompted
OSHA investigations, said Michaels at an April meeting of the
advisory committee on construction safety and health. OSHA also has
stated that it will post reports of injuries or fatalities on its website.
Some businesses argue that because the increased injury reports
will inundate local OSHA offices, a 24-hour time limit for reporting
is unrealistic. For one thing, it is not always clear whether an injury
constitutes an amputation, and it may take time in a hospital to get
the full details on whether the injury
is actually an amputation or whether
it resulted from a work-related event.
Additionally, the incident may happen
at a remote facility and the person
responsible for reporting may not
learn of the hospitalization for some
time. Employers have struggled with
the question of whether an injury is
“work-related” under the old rule, and the instances requiring this
determination will inevitably increase with the new rule. In making
this determination, it is important to note that the work event or
exposure does not have to be the sole or main cause of an injury or
fatality, but only a contributing cause.
Penalties
The penalty for a willful violation of OSHA requirements can
range from $5,000 to $70,000 and is meant to “inflict pocket-book
deterrence.” A failure to report under the new rule, particularly for a
repeated violation, may result in a significant fine.
State Plans
Some 27 states and territories have adopted OSHA-approved state
plans. These state plans are required to contain standards at least
equivalent to OSHA’s standards.
Though it may seem straightforward and simple, in practice,
reporting and recording injuries and fatalities to OSHA often involves
analysis of incomplete or conflicting evidence. To limit liability, it
is especially important for employers to make sure the responsible
operations and employee health and safety professionals are made
familiar with the new reporting obligations and have a protocol in
place that will result in timely reporting.
The penalty for a willful violation of OSHA requirements can range from $5,000 to $70,000 and is meant to “inflict pocket-book deterrence.”
1509ELP_9 9 10/8/15 7:54 AM
10 | ElEctriclight&PowEr Sep|Oct|2015
Finance
TBy ROD WALTON, Senior Editor
Historic might be the best way to describe the pace of legislative
and regulatory events focused on utilities in 2015. Plenty happened
that should dramatically affect the power industry for decades to
come.
First and foremost, of course, was the U.S. Environmental
Protection Agency’s (EPA’s) final release of its Clean Power Plan.
Years in the making, the set of targets compels states to decrease
power plants’ CO2 emissions an overall 32 percent below 2005 levels
by 2030.
The Clean Power Plan commanded so much attention that
relatively little notice was given to other congressional work affecting
the industry, perhaps because those are still pending. The Energy
Policy Modernization Act of 2015 and the Coal Combustion Residuals
Regulation Act of 2015 have gained some support but not yet (as of
press time) by both chambers nor President Obama’s signature.
Below is a breakdown of the possible impacts of those developments.
Clean Power Plan
The EPA’s final rule was one of those few front-page energy stories
that had nothing to do with the price of oil. The August release put all
utilities—and the states where they operate—on alert that they had
specific numbers to meet for carbon emissions. The trick now is how
or whether they can get there in the time allotted.
“Certainly the net complexity added by the rule is not a
good thing,” said Joe Nipper, who handles regulatory affairs and
communications for the American Public Power Association. “Our
industry is becoming increasingly complex…This rule adds multiple
layers of complexity, some that we can’t understand yet.”
Many states and utilities groups also are still digesting it and
determining their next steps; more than a dozen states are asking for
a delay and some of them filed federal lawsuits while it was still in
the draft stage last year. A Washington, D.C. federal court rejected
a request for an emergency stay of the new rule by 15 states and
Peabody Energy Corp.
A prominent opponent of the Clean Power Plan, surprisingly,
is environmental hero and former Vice President Al Gore’s former
counsel, Laurence Tribe. The Harvard law professor chimed in with the
“unconstitutional” tag in various comments and an op-ed piece in the
Wall Street Journal late last year. Earlier this year, Tribe stepped up his
rhetoric by saying the Clean Power Plan was “burning” the Constitution.
“The EPA is attempting an unconstitutional trifecta: Usurping
the prerogatives of the states, Congress and the federal courts all at
once,” he was quoted by multiple publications in March. “Burning the
Constitution should not become part of our national energy policy.”
Those skeptical of Tribe’s legal purity noted that he has worked
for Peabody Energy, which calls itself the world’s biggest private-
sector coal producer.
The APPA’s Nipper did not express outright opposition to the
Clean Power Plan, noting that the EPA made the rule more workable
in some ways, such as offering more time to meet mandates. The
APPA’s membership of municipally owned power generators has
about 47 million customers nationwide.
On the other hand, many states got hit harder, such as Montana,
North Dakota, South Dakota, Indiana and Kentucky, he noted.
“It’s no big surprise,” Nipper said. “They redid the formula…
and in redoing the formula, the states that have more coal generation
have a tougher target to meet.”
North Dakota, for instance, must reduce its emissions 45 percent
to 1,305 pounds per MWh by 2030, while Montana and Wyoming, all
major coal producers, must also shed CO2 by more than 40 percent
each, according to reports. South Dakota will have to reduce emissions
by more than 1,000 pounds CO2 per MWh, or close to 48 percent.
California, Rhode Island, Maine, Idaho and Connecticut are the
five states with the least amount of work to do on CO2 reductions.
Many power holding companies, such as Duke and AEP, already
have introduced plans to retire coal-fired generation, but they also are
trying to deal with the Clean Power Plan shortly after spending big
to meet the EPA’s rule on mercury and air toxics standards (MATS).
“They’re just coming off of meeting compliance with the
mercury and air toxics rule, and that was pretty expensive,” Nipper
said. “That was one of the fault lines, if you just retrofitted coal units
to meet the MATS rule.”
The MATS rule endured its own judicial slap down earlier this
summer when the U.S. Supreme Court voted 5-4 that the Obama
administration should have factored in the costs of compliance; the
EPA estimated those costs at close to $10 billion per year. While
some in the industry counted that as a “supreme” victory dismantling
MATS, the high court actually left the rule in place but sent it back to
the federal appellate level for reconsideration.
Meanwhile, the power utility industry already is moving
fast toward renewables and replacing coal with natural gas-fired
generation that can keep the grid humming if “the sun don’t shine or
the wind don’t blow.”
The Edison Electric Institute, which represents investor-owned
utilities, estimated that the industry reduced CO2 emissions by 15
percent below 2005 levels in 2014 alone. Solar Energy Industries
Clean Power Plan Rules, but Utility Industry Faces Plenty of Regulatory Edicts in 2015
California, Rhode Island, Maine, Idaho and Connecticut are the five states
with the least amount of work to do on CO2
reductions.
1509ELP_10 10 10/8/15 7:54 AM
Finance
Sep|Oct|2015 ElEctriclight&PowEr | 11
Association predicted that 20,000 MW of solar capacity would be
installed in 2015 and 2016 combined.
“Our industry also is making significant investments in
renewables and in the grid infrastructure needed to deliver renewables
to customers,” according to an EEI statement this summer. “In fact,
utility-scale solar projects now amount to almost 60 percent of
installed solar capacity, and the amount of electricity produced from
wind doubled from 2010 to 2014.”
And midway through 2015 came a historic moment: the first time
that gas-fired generation topped coal-fired power. Environmentalists
might consider that a Pyrrhic victory, because natural gas produces only
half the carbon emissions of coal but is mined from shale plays using
hydraulic fracturing and producing vast amounts of polluted water.
The future is unknown. A Republican president and Congress
could be elected next year and try to undo some of the EPA edicts.
Yet many utilities feel that the die is cast and there’s major, expensive
work to be done.
“EPA’s Clean Power Plan is the most comprehensive, far-
reaching regulation ever promulgated by the federal government to
impact the electric power sector and will significantly change electric
utility operations well in the future,” the EEI statement read.
State plans are due by September 2016 although some can get
extensions of up to two years.
Energy Policy Modernization Act of 2015
A rare bipartisan bill sponsored by U.S. Sen. Lisa Murkowski,
the Republican from Alaska, and Democrat Maria Cantwell, from
Washington state, passed its Senate committee by an 18-4 vote. The
legislation deals with a broad array of energy issues, from oil and gas
to utility infrastructure.
Portions of the bill dealing with fossil fuels and alternative
energy production garnered some mainstream attention, but what
intrigues much of the utility industry most was the call for major
investment in the traditional grid infrastructure, cybersecurity and
smart grid sectors.
Among the utility-specific highlights are: a $500 million,
10-year research and development demonstration program on
grid-scale energy storage; a 10-year, $2 billion allocation focused
on demonstration projects integrating new technologies into the
grid; doubling the U.S. Department of Energy’s expenditures on
cybersecurity research and development, among other goals.
The Energy Policy Modernization Act has plenty of debate and
rewriting left, but AEP spokesman Melissa McHenry noted that the
last major update of U.S. energy policy was in 2007.
“The current energy renaissance in this country will only
reach full potential if supported by a national energy strategy that
leverages U.S. advantages,” McHenry said in a statement. The energy
leidos.com/activate
Tap into forward thinking.
Take on the connected world.
Leidos is helping utilities to become the energy systems of the future. Our cross-cutting expertise in grid engineering, systems integration, data analytics, energy ��������������������������������� �����transforms your utility with data-driven intelligence so you can take on whatís next.
Activate Tomorrow, Today.Chris Johnson
Project Controls
Sukhwinder Kaur
Electrical Designer
Lance Anderson
Civil Engineer
Go to http://uaelp.hotims.com for more information.
1509ELP_11 11 10/8/15 7:54 AM
Finance
12 | ElEctriclight&PowEr Sep|Oct|2015
legislation developed by
Murkowski and Cantwell in
the Senate and by others in
the House of Representatives
“are significant first steps
in developing a diverse
supply of energy resources,
bolstering electric reliability
and carefully balancing
energy development with
environmental stewardship,”
she added.
The grid modernization
portion was lauded by Ed
Abbo, president and chief
technical officer at Redwood
City, California-based C3
Energy, a six-year-old startup
focused on application
software in smart grid
analytics, cloud computing
and data to improve power
delivery.
Abbo’s boss, C3 Energy
CEO Thomas Siebel, told
a House subcommittee on
energy and power that as
much as $2 trillion will be
invested globally to upgrade
the grid infrastructure
throughout this decade,
with half of that spent in the
U.S. A crucial part of that
upgrade will be the addition
of sensors needed in meters
and other smart grid devices,
Abbo echoed. Those sensors,
in turn, will cut down on the
costs of line loss, energy
inefficiencies and give
dramatic, informed power
back to both the utilities and
the customers, he said.
Utilities just need
financial encouragement
to make those investments.
Abbo predicted that the
grid modernization bill, if
approved, can do just that by
allowing companies to move
the costs of advanced analytics
and cloud-based computing
into the rate-paying structure.
Previously, many companies
have booked those new-era investments as operating expenses rather
than capital expenditure costs.
“That’s one of the obstacles or hurdles the bill will help remove,”
Abbo said. “The bill encourages regulators and utilities to treat
investments in advanced energy analytics and cloud-based (services)
as investments they can get rate recovery on.”
Real-time analytics and sensors can improve reliability, lead to
fewer outages and help consumers save money by giving them data
on rate costs and usage patterns, he added.
All in all, the modernization act can unlock $50 billion value
on both sides of the utility-customer equation, or $300 per meter per
year, in C3’s estimation.
“There’s no need for subsidies,” Abbo said. “These are
investments that pay off in net positives.”
The modernization act is no slam dunk, with some environmental
groups saying it does not include enough proactive moves on the clean
energy front. A letter by Clean Water Action, citing opposition from
groups such as itself and Sierra Club, applauded grid storage and water
conservation components of the 2015 bill, but found plenty to pick on.
“There are, however, several provisions in this bill that we
believe could cause detrimental effects to public health and our
environment,” the Clean Water Action letter read. “For example, there
is no need to exempt hydropower facilities from regulations that have
worked for a century. Some provisions could also have unintended
severe consequences for EPA public health protections. We are also
troubled by the lack of clean energy investments made by a bill that
claims to modernize our energy policy.”
Improving Coal Combustion Residuals Regulation Act
This piece of legislation, called H.R. 1734, passed the House of
Representatives around the same time as the Energy Policy Modernization
Act passed through its Senate committee. The coal combustion bill,
authored by West Virginia Republican Rep. David McKinley, has a slim-
or-none chance of either passing in the Senate or on President Obama’s
desk, according to some outside observers such as govtrack.us.
The bill deals with disposal of coal ash from power plants. It
was filed and debated in response to the EPA’s final rule on coal
combustion residuals which was published in the Federal Register
earlier this year. The stronger federal requirements on impoundment
and disposal were spurred by the December 2008 failure of a coal-ash
impoundment at the Tennessee Valley Authority’s Kingston coal-fired
plant. That mishap reportedly unleashed 5.4 million cubic yards of
fly ash to impact homes and seep into the Emory River in Tennessee,
according to reports.
Supporters of the House’s legislative response say that the
Improving Coal Combustion Residuals Regulation Act can save
approximately 316,000 jobs by letting the states design their own
coal-ash disposal programs as long as they meet EPA standards.
“While this legislative approach isn’t perfect, it’s better than
the EPA’s proposal which leaves too many opportunities for extreme
environmental groups to replace regulations based on sound science
with their agenda of shutting down the coal industry,” U.S. Rep.
Kevin Cramer, R-North Dakota, said in his official release.
State 2012
Historic*
2030 Final* Percent
change
South Dakota 2,229 1,167 47.6
Montana 2,481 1,305 47.4
North Dakota 2,368 1,305 44.9
Wyoming 2,331 1,299 44.3
Kansas 2,319 1,293 44.2
Illinois 2,208 1,245 43.6
Iowa 2,195 1,283 41.5
Wisconsin 1,996 1,176 41.1
Kentucky 2,166 1,286 40.6
Colorado 1,973 1,174 40.5
Minnesota 2,033 1,213 40.3
Nebraska 2,161 1,296 40.0
Tennessee 2,015 1,211 39.9
Michigan 1,928 1,169 39.4
Indiana 2,021 1,242 38.5
Ohio 1,900 1,190 37.4
Washington 1,566 983 37.2
Utah 1,874 1,179 37.1
Georgia 1,600 1,049 36.8
Virginia 1,477 934 36.8
West Virginia 2,064 1,305 36.8
Missouri 2,008 1,272 36.7
Maryland 2,031 1,287 36.6
Arkansas 1,779 1,130 36.5
New Mexico 1,798 1,146 36.3
North Carolina 1,780 1,136 36.2
South Carolina 1,791 1,156 35.5
Pennsylvania 1,682 1,095 34.9
Arizona 1,552 1,031 33.6
Texas 1,566 1,042 33.5
Alabama 1,518 1,018 32.9
Oklahoma 1,565 1,068 31.8
Louisiana 1,618 1,121 30.7
Delaware 1,254 916 27.0
Florida 1,247 919 26.3
New Jersey 1,091 812 25.6
New Hampshire 1,119 858 23.3
Nevada 1,102 855 22.4
Mississippi 1,185 945 20.3
Oregon 1,089 871 20.0
New York 1,140 918 19.5
Massachusetts 1,003 824 17.8
Rhode Island 918 771 16.0
California 963 828 14.0
Maine 873 779 10.8
Idaho 858 771 10.1
Connecticut 846 786 07.1
* CO2 rate (pounds per MWh)
Source: EPA Clean Power Plan state-specific fact sheets
Impact of EPA’s Clean Power Plan Rule: State by State
1509ELP_12 12 10/8/15 7:54 AM
®
FEBRUARY 9–11, 2016 + DISTRIBUTECH.COMORANGE COUNTY CONVENTION CENTER - WEST HALLS A & B + ORLANDO, FL
FOCUSED ON
THE FUTURE
SEE FOR YOURSELF WHAT ALL THE TWEETING IS ABOUT.REGISTER ON OR BEFORE NOV. 12, 2015 AND SAVE $200.distributech.com
Owned & Produced By:
Official Publication of DistribuTECH:
Supporting Publication:
Host Utility:
Kelly Saye @WHOLEISTICSafar
@DistribuTECH San Diego was a huge success! Looking forward to engaging new talent in #cleantech #energyefficiency with @EnertechSearch
Access WDS @AccessWDS
Great #DTECH2015 thank you @DistribuTECH! This year was even better than last. We are looking forward to 2016.
SmartUtilitySystems @SmartUtilitySys
We had a very successful time @DistribuTECH. Thanks to all who stopped by our booth. See you next year in Orlando.
McDonnell Group @mcdonnellgroup
We’re sad #DTECH2015 is over – it was such a great conference. Our clients had rave reviews! Thanks @DistribuTECH
Go to http://uaelp.hotims.com for more information.
1509ELP_13 13 10/8/15 7:54 AM
Generation
14 | ElEctriclight&PowEr Sep|Oct|2015
SA u t h o r
Barry Cassell is chief
analyst for Genera-
tionHub covering coal
and emission controls
issues, projects and
policy. He has covered
the coal and power
generation industry for
more than 26 years,
beginning in November
2011 at GenerationHub
and prior to that as
editor of SNL Energy’s
Coal Report. He was
formerly with Coal
Outlook for 15 years
as the publication’s
editor and contributing
writer, and prior to that
he was editor of Coal
& Synfuels Technology
and associate editor of
The Energy Report. He
has a bachelor’s degree
from Central Michigan
University. Reach him at
2015 Coal Share of U.S. Power Generation to Fall 8.2 Percent From 2014
By Barry Cassell, GenerationHubSlower growth in world coal demand, lower
international coal prices and higher coal output in other coal-
exporting countries have all led to a decline in U.S. coal
exports, said the U.S. Energy Information Administration
in its most recent monthly Short-Term Energy Outlook
published Sept. 9.
Lower mining costs, cheaper transportation costs
and favorable exchange rates will continue to provide an
advantage to mines in other major coal-exporting countries
compared with U.S. producers, EIA added. Coal exports for
the first half of 2015 are down 20 percent compared with the
same period in 2014, and U.S. steam coal exports fell by 21
percent, or 4.1 million short tons (MMst).
U.S. coal imports, which increased by more than 2
MMst in 2014 to 11 MMst, are expected to average near that
level in 2015 and 2016.
EIA said it expects a 7 percent decrease in total coal
consumption in 2015, with electric power sector consumption
falling 7 percent. Lower natural gas prices are the key factor
driving the decrease in coal consumption. Projected low
natural gas prices (power sector natural gas prices are 27
percent lower in 2015 compared with 2014) make it more
economical to run natural gas-fired generating units at higher
utilization rates.
The retirements of coal-fired power plants, many of
them done earlier this year, in response to the implementation
of the federal Mercury and Air Toxics Standards (MATS)
also reduces coal-fired capacity in the power sector in 2015.
Because retirements are occurring throughout 2015, however,
the full effect will not be evident until 2016.
Projected rising electricity demand and higher natural
gas prices next year are expected to contribute to higher
utilization rates among remaining coal-fired power plants.
Even with continued implementation of MATS, which the
U.S. Supreme Court in June sent back to the U.S. Court
of Appeals for the D.C. Circuit for further review, coal
consumption in the electric power sector is forecast to
increase by 1.5 percent in 2016.
A barrier to larger rebound in coal-fired generation in
2016 is expected growth in renewable-based generation,
EIA reported. Non-hydropower renewable-based electricity
generation is expected to grow by 12 percent in 2016, with
the largest growth (21 percent) occurring in the South.
Lower domestic coal consumption and exports
combined with a slight increase in coal imports are projected
to contribute to a decrease in production in all coal-producing
regions in 2015, with the largest percentage decline occurring
in the Appalachian region.
The annual average coal price to the electric power sector
increased from $2.34 per million British thermal units (MMBtu)
in 2013 to $2.36/MMBtu in 2014. EIA expects the delivered
coal price to average $2.27/MMBtu in both 2015 and 2016.
Nearly 9,800 MW of Coal Capacity Retired in First Half
Of 2015
The electricity industry retired nearly 9,800 MW of
conventional steam coal-fired capacity during the first six
months of this year. These retirements represent 3.3 percent
of the amount of operating steam coal capacity existing at the
end of 2014. The states with the largest amount of retired coal
capacity include Ohio (2,659 MW), Georgia (1,861 MW)
and Kentucky (1,409 MW). The industry plans to retire an
additional 3,133 MW of coal capacity this year and nearly
6,000 MW during 2016.
While the retirement of some coal-fired capacity has
contributed to the decline in coal-fired generation over the
past year, the relatively low cost of natural gas has been a
more significant driver in coal’s declining share and the
increase in the share generated by natural gas. During the first
half of 2015, coal accounted for 34 percent of total generation
compared with 40 percent during the same period last year,
while natural gas accounted for 30 percent, up from 25percent
during the first half of 2014. For all of 2015, EIA expects the
annual amount of coal generation will be 8.2 percent lower
than in 2014, and the annual level of natural gas generation
will rise by 14.5 percent.
A longer version of this article was originally published
in GenerationHub on Sept. 9.
U.S. Coal ConsumptionFigure 1
1509ELP_14 14 10/8/15 7:55 AM
Go to http://uaelp.hotims.com for more information.
To the Annual Awards Gala Monday, Dec. 7, 2015
Owned & Produced by:
Presented by:
Providing role models to inspire young women to pursue careers in energy.
Nominated by industry peers and selected by a committee of women in the
power generation industry, the PennWell Power-Gen Woman of the Year award is
given each year to a woman who has, through hard work, vision, and
determination, moved the industry forward.
Register online at www.power-gen.com
PRESENTING THE
Honoring excellence in design, construction and engineering
of power generation facilities worldwide.
Awards will be given in the following categories:
Best Coal-f red Project Best Gas-f red Project Best Nuclear Project
Best Renewable Energy Project Best Project of the Year
You're Invited
Sponsored by:
1509ELP_15 15 10/8/15 7:55 AM
Generation
16 | ElEctriclight&PowEr Sep|Oct|2015
NA u t h o r
For over 26 years,
Rosco Backus worked
at or for major U.S.
utilities, including
Duke Energy, where
he managed a diverse
portfolio of generation
assets. Today, Rosco
works at Versify Solu-
tions, a platform
provider of integrated
analytics software
to power generators.
Reach him at Rosco at
Navigating the Future of Plant Operations: Fly, Don’t Drive
By Rosco Backus, Versify SolutionsNot only is this not your father’s Oldsmobile…we’re not
driving anymore.
For nearly 30 years I worked at power plants for one of
the world’s largest electric utilities and merchant generators,
running assets across multiple ISOs for everything from coal-
fired power plants, to gas plants, to solar and wind farms.
Let me say, times are different. I believe our industry is
at a tipping point in why and how we use emerging analytics
tools to run power plants as part of a larger business.
Where Are we Going?
Power generators have a growing
mandate to increase the reliability
and performance of their fleet,
reduce spending and increase
revenues and margins. In the
old energy era, things were
predictable, centralized and all
about compartmentalized control
of assets and information to ensure
the reliable flow of electrons,
without too much regard for other external factors.
The new energy era will be dynamic, distributed and all
about variable assets and integrated information flows to manage
and deliver not only electrons from all sorts of energy sources,
but also a host of energy-related products and services, and with
a much keener eye towards accountability, both operational and
financial.
As a result, plant operations will be fundamentally
different as well – it’s no longer just about generation, trading
or compliance—it’s about all of these things, working together.
There are positive and compelling business reasons to look for
ways to improve plant operations in the new energy era: deliver
new forms of energy to market, outpace the competition and
drive higher margins. And there are “negative” reasons as
well: minimize outages, ensure compliance, reduce risk and
avoid market and regulatory penalties.
In both cases, there is the same imperative: plant
operators who have been doing the same things for the last
40-plus years—driving the same car if you will—are on the
cusp of finding new ways to ‘get there.’
… And how did we get here?
Power plant operations are not just a discipline or a
function, they’re a phenomenon with thousands of moving
parts and equipment, as well as an entire network of people
and processes, working together. In the regulated world, it’s
about “operational efficiency” and being a good steward of
ratepayer-funded assets. In the non-regulated world of merchant
generators, effective plant operations is all about matching
output with demand, at the highest price, in real time.
And like your father’s Oldsmobile, there has always been
the constant need to check things—temperature, fluids, pressure,
water levels and emissions. There probably are hundreds of
gauges on that dashboard. To do their job well going forward,
the “drivers’—control room operators, dispatchers and systems
operators—will need new tools to be more actively engaged than
their predecessors, even as a large
percentage of such workers retire
within the next five years (more on
that in a moment).
With the increasing growth
of renewables, this phenomenon
of disparate moving parts will
only get more complex. When
driving your car before, if you tap
the brake and it pulls to the right so
you know you’ve got a problem.
Maybe it’s a tire, the alignment or
a tie rod—very solvable. Today, we’ve got something more
akin to the Jetsons, where part of your vehicle looks like the
car you know, but then another part is something very new
and different—like wings on an aircraft! This may sound
cool, but it’s also much harder to troubleshoot and maintain.
Why the Differences Today Will Require Changes Tomorrow
Even as the definition of a “power plant” is changing, plant
operators will have to change how they manage their assets,
not only to generate reliable power but also to meet emerging
requirements driven by policy and the market. They cannot do
this without access to more and better information, faster. And
yet most plants today carry the burden of legacy everything:
• Legacy systems with too many screens and too many
information silos
• Legacy processes, as in “we’ve been doing it this way
for 40 years”
• Legacy people, a good thing in most ways except that an
aging workforce will soon limit access to expertise
When it comes to gathering information, however,
manual processing simply will not work, especially as data
collection, analysis and reporting times shrink from hours
to minutes. Tomorrow’s operators must identify problems
before they happen to avoid severe consequences such as
penalties, blackouts and customer wrath.
1509ELP_16 16 10/8/15 7:55 AM
Sep|Oct|2015 ElEctriclight&PowEr | 17
Generation
Consider one power plant where I worked, with over 1,300
MW spread out over 500 acres. Even then, we had thousands of key
performance indicators. Today that plant is part of a portfolio with coal,
solar, wind, combined-cycle and simple-cycle gas plants, all working
together and balancing each other out. This updated plant, as well as
the entire portfolio, calls for an updated approach to plant operations.
This means checking more stuff, more often and more accurately.
Yet now as before, engineers go back and forth on the job, they enter
their reports and the status of those assets, often on a paper report with no
real digital log or trending system to prevent errors. To keep pushing our
vehicle analogy and comparing yesterday to today, it’s the difference
between jury-rigging the timing on your car and knowing that if you
are a little sloppy, it’ll still run, versus ignoring the engine warning light
on your main rocket booster as you get ready to launch … um, bad idea.
As one vice president of commercial ops tells me, “For 95 percent
of utilities, people in the plants are so disconnected from the business”
that they cannot track key metrics to business impacts: things like
turbine outages, capacity factors, curtailments and operating reserves.
The stakes for plant operators are much higher in today’s environment
than they were 30, 20 or even 10 years ago. The mantra, “Be safe, do
what we tell you and everything will be fine,” is giving way to “You
must run it like a business…avoid catastrophes and make money too.”
Coincidental with this new imperative are all the old problems
and some new ones: an aging workforce, distributed energy, dynamic
markets, ever increasing regulations and the shift to being more
customer-focused and accountable. Furthermore, as power providers
age out in their workforce, they also are trying to do more with less. I
estimate that for many critical plant operations functions, there is up
to 60 percent less staff than there was in the 1970s, doing more work
for longer hours. Something has to give.
Calling all Drivers
Plant operators are migrating from being drivers to being flyers, and
pilots, too. Utilities will need new and more technology to deal with
the changes quickly moving towards them—that means standing
still is not an option. It’s also important to note that your technology
choices and the choice to “go digital” in your plant operations will
not only determine how efficient and effective you can become, it will
also contribute to attracting and retaining the right talent.
Consider these examples: I walk in a restaurant today and the
waiter uploads my order from a handheld. In the 1990s, overnight
delivery drivers were using palm-sized computers to synch orders
and deliveries. My 14-year old manages her entire schedule, does
homework and communicates halfway across the world, all from her
smart phone. Mobility, cloud and wireless, all at scale—that’s the
world we live in, right? But in the last six months, I’ve been to more
than a half-dozen large, well-known utilities, where paper-based
“processing” still prevails. Utilities can catch up, as technology
advancements and the next-generation work force go hand in hand.
Stop Driving, Start Flying
Most power plants are still reactive. For example, one plant I saw
in my travels needed a boiler feed pump, which cost the operation
about $10,000 per hour when down. By luck, one guy heard about the
problem, told another guy, who just happened to know that the missing
part was sitting in a nearby warehouse (they were getting ready to
place a very expensive overnight order). The digital-age answer to
this challenge is pretty simple: put barcodes on all equipment, log
the data and automate the inventory management for all the plant’s
moving parts. I call it “digital common sense.” In other words, why
drive when you can fly?
Another recent case comes to mind: In another plant I toured, the
operations manager was scheduling outages with the asset manager on
the commercial side, where different individuals were trying to figure out
and interact with markets. The operator was planning on taking a piece
of equipment offline for one full day, which would make generation 100
MW short in the day-ahead market. The message was clear: “don’t bid
us into the market for this power.” So now the traders knew. Then, 3
hours after market closed the maintenance manager called and said that
expected part—a feed pump—was not going to make it any time soon.
Now the 24-hour contract that required the trader to buy 100
MW in the market to bring the position up needed to be extended
so that the utility could avoid a potentially very costly exposure to
the real-time market and/or penalties. In this case, the utility has
integrated analytics tools and a platform that can deliver a real-time,
auto-updated, single source of truth to enable the operations manager,
asset manager, traders and the maintenance manager to work together
to solve the problem. And management can track it too. That is flying
vs. driving in the digital age for utilities.
Getting Ready to Fly
As we reflect on the power industry of the future, it’s time to lift
our eyes and answer the question, “When it comes to data collection,
information analysis and situational awareness, is there a better way?”
Related to that question, here’s digital-age, plant operator “pilot
checklist” of things plant operators should know and/or do:
1. Understand going digital is mandatory
2. Recognize things are different—your markets, your talent (less people)
and your risk profile—making situational awareness harder than ever.
3. Develop more and better cross-function communication—materials
handling, maintenance and the control room cannot operate alone.
4. Build or buy information and communications management
systems to deliver automation at scale for transparency,
transparency…and more transparency.
A “features and functionality” menu (below) lists what new
digital-age tools should do to help address these new realities. The
right functionality in high-performance plant ops systems would mean you could do things like:
• Consolidate information across system types to avoid costly
integration
• Standardize and automate data collection, work flows and reporting
• Rank and prioritize dispatch based on real-time market dynamics
• Codify time-consuming manual work into automated processes
• Communicate outward to optimize assets in conjunction with other parties
• Manage assets and events in real time while remaining compliant
As for me, I like to fly!
1509ELP_17 17 10/8/15 7:55 AM
Renewables/Sustainability
18 | ElEctriclight&PowEr Sep|Oct|2015
IEnergy Storage as Consumer Product: Will Storage Follow the Path of Rooftop Solar?
Innovative financing, declining costs of equipment and
installation and supportive policies have all contributed to a
rapid uptake in photovoltaic (PV) solar across the U.S. and
the emergence of PV as a consumer product. In addition, new
private sector investment and innovative financing, dropping
costs and emerging policies are supporting a growing market
for energy storage. Energy storage, therefore, should follow
suit to also become a consumer product.
The first consumer storage products are already entering
the marketplace. Tesla’s Powerwall home battery, offered in a
10 kWh ($3,500 plus installation) size for back-up applications
and 7 kWh size ($3,000 plus installation) for daily use, will ship
soon. SimpliPhi is also offering commercial and residential
units in 2.6 kWh ($5,395 plus installation) and 3.4 kWh ($6,945
plus installation) sizes. In addition, Orison has announced a
concept for 2 kWh batteries that plug into standard wall outlets
with expected availability in 2016. The units will be offered
in a panel ($1,600) or a tower ($1,995) format with expansion
batteries ($1,100 each). They come with LED lamps, wireless
controls, smart-phone connection and an added Bluetooth
speaker and induction phone charger for the tower.
Consumers appear to be interested in home storage
devices. In the days following its launch, over 38,000 orders
were in for Tesla’s Powerwall. Desire for clean energy,
increased resiliency and energy bill management are driving
market demand for home energy products like energy storage.
Furthermore, current and planned policy initiatives will likely
push the market demand. California’s investor-owned utilities
will be moving residential customers to default time-of-use
pricing by 2019, increasing the economic benefit of load-
shifting capability to a larger pool of people. The California
Public Utility Commission energy storage target outlines 200
MW of customer storage (though not all will be independent
battery units). In New York, Consolidated Edison and the
New York State Energy Research and Development Authority
launched incentives for demand management resources,
including energy storage.
At today’s costs, however, mass adoption of home energy
storage product remains a tough proposition. Prices need
to drop to justify storage as a means for PV shifting, back-
up power or energy bill management. (A reservation for
the Powerwall doesn’t require putting money down). Total
installed costs for storage are dropping and expected to drop
precipitously, similarly to expectations for PV.
It is likely, too, that more innovative financing for storage
and storage plus PV units will emerge. Larger commercial,
industrial and municipal customers are beginning to delve
into this area. For example, TIP Capital, which provides
leasing and financing options for commercial, industrial,
and municipal energy-related projects, has partnered with
Green Charge Networks to offer zero down energy storage
financing for Green Charge Network customers. LFC Capital
has partnered with ViZn Energy Systems to offer financing
for solar and storage investments. The program would use an
operating lease with ownership options after six and seven
years. In addition, SolarCity is offering financing options
to its customers for solar and storage products, including
options with no upfront costs. In the not so distant future
offerings that bundle solar and storage financing with home
mortgages are likely.
By Jessica Harrison, DNV GL
A u t h o r
Jessica Harrison is
the head of section
for energy strategy,
markets and policy
development at DNV GL.
Number of Households With Rooftop SolarFigure 1
Source: Adapted from USC 2014
Mill
ions
Will storage emerge as a consumer product? Yes. Will this market
emergence differ for storage than what it did for PV? Probably.
actual
high case projection
low case projected
1509ELP_18 18 10/8/15 7:55 AM
Sep|Oct|2015 ElEctriclight&PowEr | 19
Renewables/Sustainability
Will storage emerge as a consumer product? Yes. Will this
market emergence differ for storage than what it did for PV? Probably.
To start, the dispatchability of storage makes it readily available for
pairing with multiple resources, such as demand response and PV, or
it can be used on its own. In addition, energy storage has the potential
to serve multiple functions for a single installation, depending on how
the controls and priorities are established. These factors create a wide
playing field for energy storage.
The emerging concept of plug and play devices could
significantly reduce installation costs and make storage ubiquitous
throughout the household. A wide range of products might eventually
arise in the storage space—stand-alone, pluggable devices to larger
units paired with PV that serve as back-up power or demand response
management.
With the advent of improved aggregation and controls systems,
a growing potential for customer-cited, grid-supporting applications
exists. Through a process of prioritization and seamless switching,
customer storage devices could both meet customer needs and provide
grid resources, narrowing the economic hurdles for investment. For
this to occur, more policies and programs must be created to fairly
compensate customers and further investment for the aggregation and
control systems.
Finally, to support large-scale deployment of storage as a
consumer product, a sizable amount of storage standards work
still needs to be completed. The main gaps include safety,
reliability and commissioning and installation. A number of
efforts are underway today:
– Pacific Northwest National Laboratories has a program
focused on key installations.
– The Electric Power Research Institute’s Energy Storage
Integration Council has established a working group on standards.
– The National Electric Manufacturers Association has a
technical advisory committee on storage (TAG 120).
– UL Safety Testing has established a safety standard for storage
(UL 9540).
– Sandia National Labs initiated a standards inventory and roadmap.
– DNV GL is running an initiative named GRIDSTOR, which
will deliver an open-source, recommended practice for grid-
connected energy storage. It focuses on guidelines and methods
to evaluate, assess and test safety, operation and performance
of grid-connected energy storage while taking into account
worldwide-accepted regulations and best practices like ISO, IEC
and IEEE standards (e.g. IEC TC-120).
Ultimately, the various technologies, applications and types of
storage devices make energy storage products unique. Further work in
aggregation and controls and the rules for shared services will expand
the applications and economic viability of energy storage devices for
consumers. As it did for PV, the marketplace’s gradual increasing faith
in the engineering and controls along with increased understanding
of lifetime operations and maintenance costs for the technology will
help create new financing options. The synchronization of standards
also will support more common deployments of the technology.
Though on separate tracks, together solar-plus-storage offers a
powerful prospect for customers, policymakers and grid operators.
Energy storage is a key enabler for solar because it allows solar to
be dispatchable, enhancing the value to customers and mitigating
some of its biggest grid-integration challenges. In turn, solar is a
key enabler for energy storage, serving as a valuable application and
helping break some of the barriers in the market for consumer energy
devices. Both likely will see market expansion with continued policy
support and cost reductions.
Together, solar and storage can further drive volume up and
prices down.
Source: Adapted from Rocky Mountain Institute
The emerging concept of plug and play devices could sig-
nificantly reduce installation costs and make storage ubiq-
uitous throughout the household.
S Ad t d f R k M t i I tit t
Installed PV Cost ($/WDC) Battery Cost ($/kWh) Figure 2
$7.00
$6.00
$5.00
$4.00
$3.00
$2.00
$1.00
0
$700
$600
$500
$400
$300
$200
$100
0
$900
$800
2010 2015 2020 2025 2013 2018 2023 2028
BNEF
EPA
Combined Averages
NREL
Black & Veatch
BNEF
Navigant
Averaged
EIA
1509ELP_19 19 10/8/15 7:55 AM
Renewables/Sustainability
20 | ElEctriclight&PowEr Sep|Oct|2015
Solar Power’s Future Looks BrightSolar power is rising quickly and isn’t likely to fade for a while.
Decreasing prices of photovoltaic (PV) technology and energy
storage, some states’ aggressive renewable portfolio standards, tax
incentives, the Clean Power Plan and customers’ desire for clean
energy sources are fueling solar power’s growth. Several utilities in
the southwestern U.S., California, Hawaii and a few states along the
East Coast have experienced substantial solar PV growth. In most
states, however, its growth is still slow to nonexistent.
“For some utilities, this (integrating large
amounts of solar PV) is an urgent matter, but for
most it’s just now time to start thinking about it,”
said Julia Hamm, president and CEO of Solar
Electric Power Association (SEPA) during the
Solar Growth Engine session at the 2015 Edison Electric Institute’s
(EEI’s) Annual Convention in June.
Ten utilities in the U.S. interconnected 72 percent of all solar PV
last year, Hamm said. California utilities San Diego Gas & Electric
and Southern California Edison experienced the most solar PV growth
at 48 percent each. Hawaii is another state that has seen big growth in
rooftop solar installations. Rooftop solar now makes up more than 13
percent of Oahu, Hawaii’s total generation mix, she said.
“Technology curves are coming down so rapidly that the future
is here today,” Constance Lau, Hawaiian Electric Industries’ president
and CEO, said during the same EEI session. “On some islands,
payback for rooftop solar is three to four years.”
Some 50 U.S. utilities each connected more than 25 solar
installations per month in 2014, according to SEPA. These numbers
have increased in 2015.
Table 1 lists the four types of solar PV deployment
arrangements common in North America. While residential solar
installations are the most widely touted, these systems make up
only a small portion (20 percent) of the 20 GW in U.S. generation
capacity, according to the Solar Energy Industries Association
(SEIA). Utility-scale solar installations make up the largest portion
at about 60 percent.
“There is a lot of noise and talk around distributed solar
(rooftop), but the bulk of the PV is still utility scale,” James Hughes,
CEO of First Solar, a global solar energy solutions company with
more than 10 GW of installed capacity worldwide, said during the
EEI session. “It’s cost, cost, cost that triggers demand and puts us
above our competitors. It’s always cost.”
Expiration of the investment tax credit at utility-scale is
irrelevant because utility scale solar installation costs will continue
to drop, Hughes said.
“We are down to around six cents per kilowatt hour and expect to
get down to the three-cent range from utility scale PV,” he said. “And,
there is no risk of fuel price volatility like with natural gas.”
Environmental concerns are driving some of the increase in PV
uptake, however, economics is the driver at utility scale, Hughes said.
The Brattle Group released results of a study in July that was
sponsored by First Solar with support from EEI. The study reveals that
utility-scale PV is much more cost-effective than residential-
scale PV. The report, “Comparative Generation Costs of
Utility-scale and Residential-scale PV in Xcel Energy
Colorado’s Service Area,” compares equal amounts of
residential- and utility-scale PV solar deployed on utility
systems. The study found that the kWh costs of residential-
scale solar is approximately twice as high as utility-scale.
For customers in Xcel Energy Colorado’s service territory,
residential-scale costs averaged 16.7 cents/kWh and utility-
scale costs averaged 8.3 cents/kWh.
The Brattle Group study cited three reasons for the cost
discrepancy: a) lower total plant costs per installed kilowatt for
larger facilities; b) greater solar electric output from the same PV
capacity due to optimized panel orientation and tracking; and c)
other economies of scale and efficiencies associated with utility-scale
installations.
Another advantage of utility-scale, as well as community-scale
solar, is that it gives customers a choice for clean energy, Hughes said.
“About 75 percent of residential customers aren’t eligible for
rooftop solar, but many still want clean energy and you (the energy
provider) better give it to them.” he said. “Community solar is a way
to do that.”
Solar energy’s growth is expected to continue for several years
and its cost should continue to decline. Most experts, including those
who participated in EEI’s Solar Growth Engine session, believe
a number of electricity consumers also will become electricity
providers, whether through community or rooftop PV systems.
This shift is a dramatic change for not only traditional utilities,
but also for regulators who are challenged to keep up with customers’
wants and expectations.
“Innovators are changing customer offerings faster than the
regulators can and do change,” Hawaiian Electric Industries’ Lau
said.
The innovators Lau spoke about will continue to push regulators,
customers, utilities and technology providers to adjust as solar
becomes a bigger part of the generation mix.
Solar will be a dominant theme at EEI’s annual conventions for
at least the next five years, Hughes predicted.
By Teresa Hansen, Editor in Chief
Type of system Examples
Residential Rooftop solar PV on homes usually connected to the distribution grid
Utility scale Larger systems usually interconnected to the transmission grid
Community solar Centralized PV system owned by a group of residential customers
Commercial & Industrial Solar installed at C&I facility, such as big box stores, to meet facility’s needs and/
or sell back to grid.
Source: Data extracted from The Brattle Group’s study “Comparative Generation Costs of Utility-scale and Residential-scale PV in Xcel Energy
Colorado’s Service Area”
Table 1: Common Solar PV Deployment Arrangements
Environm
ake, howev
The Br
sp sored
ut
s
U
1509ELP_20 20 10/8/15 8:01 AM
Customers
Sep|Oct|2015 ElEctriclight&PowEr | 21
Gadi Solotorevsky, Ph.D,
is the CTO of cVidya,
a supplier of revenue
analytics solutions for
utilities, communica-
tions and digital service
providers. He has
more than 15 years of
experience developing
and deploying revenue
analytics solutions
and methodologies. Dr.
Solotorevsky is one of
the founders and the
chair of the revenue
assurance modeling
team of the TM Forum.
He is also one of the
authors of the TM Forum
documents TR131 and
GB941 that are today
the de facto standard
in revenue assurance
best practices.
WWhen Bob Dylan wrote “The Times They Are a-Changin”
in 1963, it’s certain he did not have in mind what would
eventually take place in the electricity utilities market in 2015.
Given that he wrote the song in the hopes that it would be
an anthem for all types of change afoot, maybe he wouldn’t
mind it having a place in what is currently taking place in the
utilities market. All this provided, of course, that he’d be paid
royalties for its use.
So what is the change taking place, and, just as
importantly, what does it mean? Could this new dawn result
in substantial risks for both providers and consumers, along
with the potential for greater rewards?
The electricity market is becoming more complex and
segmented in the areas of production, transportation and
distribution of electricity. This, in turn, is opening up the
market to greater competition, resulting in a multitude of
companies competing against each other for customers who
have options when selecting a utility provider.
Concurrently, some utilities are witnessing a shortage
of supply, and struggle to provide electricity at all times
to all customers, especially during periods of peak energy
consumption. This means the cost of providing electricity
over certain thresholds can be high, as extra capacity must
often be purchased from third parties in order to keep up with
customers’ usage.
One answer to short supply and high cost is demand
response (DR), a concept by which electricity companies can
adjust prices according to demand. This can include raising
prices when customers are approaching their limits or charging
more in the evening during peak usage, while lowering charges
during the off-peak and morning hours or both. The ultimate
goal is for utilities to be able to provide clean energy at prices
that make sense for everyone. Several challenges to this
seemingly straightforward approach exist, however.
Admit the Waters Around You Have Grown
Utilities must be able to offer their customers attractive price
plans that also are good for business and allow providers to
intelligently control electricity usage. To accomplish this,
however, customers must opt-into DR and be willing to sign
a contract for dynamic pricing. Analytics are required for
utilities to be able to assess their customers’ requirements
and habits in relation to their own distribution capabilities, so
they can offer them the best possible plan.
Many utilities are currently losing large amounts of
revenue through “non-technical” losses, such as fraud
and revenue leakage. Causes of non-technical loss vary
from operational losses, such as meter manipulation and
energy tapping reading errors to financial losses caused by
missing or late payments, rating errors and undercharging
or overcharging. Any or all of these can lead to losses of up
to 20 percent, depending on a country’s maturity. In 2009,
Utilities Knock, Knock, Knocking on Change’s Door
By Gadi Solotorevsky, cVidya
A u t h o r
1509ELP_21 21 10/8/15 8:01 AM
22 | ElEctriclight&PowEr Sep|Oct|2015
Customers
this translated into varied monetary losses, in some cases in excess
of $5 billion per year, according to Bloomberg. The ultimate goal,
therefore, is to reduce electricity usage during peak hours, when a loss
of just 10 percent can be significant.
The ability to detect fraud and leakage enables companies
to immediately reduce energy losses, requiring a lot of complex
analytics around the customer, to track their behavior and identify
fraud and leakage. For example, if a customer’s electricity usage
inexplicably drops, analytics can determine if this is a legitimate
fall because the customer is away on vacation, or due to more
nefarious circumstances, such as bypassing the system and syphoning
electricity from a neighbor. Utilities can therefore classify customers
by harnessing analytics to track their behavior over time, thereby
learning to identify fraud and leakage.
Many companies today only detect leakage physically, through
sending personnel into the field. This operation is expensive, however.
Some European companies perform more than 150,000 physical
inspections per year—resulting in enormous costs, and also limiting
the amount and type of leakage that can be detected.
You Better Start Swimmin’ or You’ll Sink Like a Stone
The utility market is moving inexorably toward widespread smart
meter adoption. Prior to smart meters, analog meters were seldom
read more frequently than once per quarter and only small amounts of
data were collected, meaning there was less data for utility companies
to analyze. Smart meters allow readings to be taken hourly, or even
every few minutes. Utilities now have vast amounts of information
with which to work, so deeper and more varied analytics are possible.
Smart meters are essential equipment for utilities of the future,
but they have not been universally welcomed with open arms. Counter-
movements aiming to forestall the adoption of smart meters exist. On
the customers’ side, arguments against smart meter adoption include
accusations of unreasonable bill increases, privacy infringements and
possible health ramifications.
As meter readings become more frequently and larger amounts
Where Revenue Assurance Enters the GameFigure 1
GenerationHub’s experienced analysts provide original content that dives into the issues facing decision-makers in today’s rapidly changing regulatory and economic landscape.
Original analysis
Online
Timely
Accurate
Data
Mobile-Friendly
Paired with our searchable database of over 20,000 generating units and more than 10,000 source documents, GenerationHub presents a more transparent view of the power generation industry than you will find anywhere else.
BARRY CASSELLCoal
WAYNE BARBERNatural Gas & Nuclear
KENT KNUTSONData Management & Renewables
CONTACT:
Shaun Jameson, Sales Executive918.832.9291 | [email protected]
www.generationhub.comGo to http://uaelp.hotims.com for more information.
1509ELP_22 22 10/8/15 8:01 AM
Sep|Oct|2015 ElEctriclight&PowEr | 23
Customers
of data are collected, consumers can take greater ownership over
their energy consumption and electricity charges no longer must
remain fixed. Pricing, therefore, will become more complex causing
confusion for both customers and electricity providers.
Utilities will be challenged to transition customers to smart
meters and the new price plans. Utilities are concerned about the risk
of bad press, as even a small error can result in many users reluctant
to sign on to smart meters. This is particularly significant with regards
to “bill shock”—customers being hit with surprise bill increases,
sometimes exceeding tens of thousands of dollars.
Bill shock can be caused by various issues and a number of bill
shock cases have been reported in the media over the last few years.
For example, in 2014 an article titled “Why Hydro One’s billing is
Under Attack” in Toronto’s The Star newspaper wrote about meter-
related issues at the utility. The article highlighted late billing and back-
billing, whereby customers did not receive bills for a number of months
(sometimes years), only to be hit with backdated and grossly inflated
bills based on estimates from outdated meter readings. Problematic
transformation projects also contribute to bill shock and have resulted
in more than three million UK energy consumers being overcharged
in 2014, including 16 percent of Scottish Power’s customers, due
to problems caused by the implementation of a new billing system,
according to a story in The Guardian. Other contributors to bill shock
include incorrect pricing, meter failure, clock accuracy and fraud.
The Line it is Drawn
Bill shock leads to a bad reputation for the utility. This, in turn, makes
customers more reluctant to adopt smart meters and can even drive
customers away and into the arms of the competition. In addition,
regulators can impose penalties on utilities, resulting in additional losses.
The causes and potential ramifications of bill shock are real
threats to the adoption of smart meters. The good news for utilities
is that the problems that cause bill shock can be detected and, if not
prevented, at least corrected effectively, preserving goodwill between
customers and their provider.
The correct solution, as illustrated in Figure 1, combines the
implementation of smart meters with customer education and suitable
demand response plans, tailored to individual customers’ requirements
through effective analytics. The result is “smart utilization.” Utilities
can then enjoy greater savings, thanks to appropriate demand response
plans, fraud mitigation, accurate meter readings and peak usage
regulation, resulting in reduced costs for the customer with accurate
and timely billing. More and more customers can then opt into smart
metering plans, resulting in an increased return-on-investment in
smart meter adoption.
There are significant positive ramifications for utility service
providers that implement analytics-based smart meters. For those
who do not employ analytics, as Dylan’s lyrics warn “…the first one
now will later be last, for the times they are a-changin.’”
Go to http://uaelp.hotims.com for more information.Go to http://uaelp.hotims.com for more information.
P O W E R - G E N . C O M
L A S V E G A S , N V
L A S V E G A S C O N V E N T I O N C E N T E R
D E C . 8 — 1 0 , 2 0 1 5
R E G I S T E R T O D AY
THE WORLD’S
LARGEST POWER GENERATION EVENT
OWNED & PRODUCED BY: PRESENTED BY:
SUPPORTED BY:
1509ELP_23 23 10/8/15 8:01 AM
Customers
24 | ElEctriclight&PowEr Sep|Oct|2015
A u t h o r
For the last eight years,
Micah DeHenau has
managed advanced
analytics teams and
consulting engagements
in numerous industries
and has been focused
in utilities for the last
five. At Vertex, DeHenau
currently oversees a
team of senior analytics
practitioners, business
intelligence specialists,
Ph.D. statisticians and
analytics value engi-
neers. Prior to Vertex, he
developed and delivered
analytically driven
projects and programs
for many Fortune 500
companies including
AT&T and Comcast.
AA service outage hits. A high bill is delivered.
Customers flood the call center with a deluge of questions
and complaints. Costs rise, customers are unhappy.
What would happen if each of those calls could actually
yield valuable data? Through speech analytics technology
utilities can turn customer calls into a treasure trove of usable
data by tracking sentiment, word choice and overall satisfac-
tion. While customers might call in for a specific reason, they
usually bring up a number of topics on a single call. Truly
understanding and responding to the voice of the customer
will improve the customer experience when he or she does
call, but also will help reduce the number of calls when the
next outage or high bill hits.
Cutting-edge speech and predictive analytics, part of the
secret recipe that makes companies like Amazon and Netflix
so successful, can make utilities more customer friendly and, in
turn, improve the bottom line. Utilities have unique challenges
and opportunities when it comes to the customer experience.
Utilities want to reduce call volumes, increase self-ser-
vice, reduce bad debt, ensure regulatory compliance and, of
course, make their customers happier. The question is “how?”
Unlock Customer Insights Hidden in your Data
With Speech and Predictive Analytics
Utilities have recognized that analytics are an integral part
of their business, particularly for issues like load forecasting
and grid management. According to the Utility Analytics
Institute, in North America utility spending on data analytics
is expected to grow 29 percent year over year, totaling more
than $2 billion in 2016. Worldwide, the expected investment
is staggering, with Pike Research indicating that cumulative
spending on smart grid data analytics alone will reach
approximately $34 billion by 2020.
But now, more customer-oriented analytics are available
to utilities of all sizes, supporting the increased focus on cus-
tomer experience. Speech analytics allows utilities to unlock
data from conversations. Utilities can now analyze everything
the customer talked about, everything the agent talked about,
and how the agent represented the utility in that interaction
and adhered to corporate policies on how to speak with cus-
tomers. Correlations can be drawn from a conversation. If
certain things are said by an agent, how will the customer
respond and how can that information be used to improve
overall call center performance and customer satisfaction?
Speech analytics is used extensively in retail, telecom
and other industries to extract deeper meaning from every cus-
tomer interaction and develop strategies based on the insights
gained. Utilities are now beginning to adopt the technology
and uncover value that was previously hidden in their calls.
Predictive analytics can determine customer behavior
and help utilities answer questions, such as which custom-
ers are likely to enroll in self-service, sign-up for paperless
billing, be most interested in energy efficiency and conserva-
tion initiatives and pay their bills once in arrears. By harness-
ing data to predict customer behavior, utilities capitalize on
events before they happen.
How Well can you Understand your Customer?
The power of predictive analytics has been harnessed by
leading consumer-facing companies to help them know what
their customers want. For example, according to Netflix, 75
percent of the content consumed by customers is actually
suggested or recommended, suggesting that Netflix knows
its customers better than they know themselves.
Amazon, likewise, uses predictive analytics to antici-
pate its customers’ purchases, developing an algorithm that
analyzes shopping patterns and behaviors to ship products to
regional facilities before customers even buy them. Packages
are then on their way as soon as a customer hits the “place
your order” button.
The result is that companies like Netflix and Amazon con-
sistently rank high in customer satisfaction and loyalty, even
in a highly competitive marketplace. In fact, according to the
annual American Customer Satisfaction Index’s retail sector
report, Netflix has a customer satisfaction score of 79 percent.
Utilities, by contrast, historically had little incentive to
innovate in the same way. Utility customers are, however,
also Netflix and Amazon customers. They expect a similar
level of customer experience from their utility. It can be dif-
ficult to make a quick and easy business case for an invest-
ment in analytics but the savings can add up by reducing the
Keeping up With the Amazons: How Data Analytics can Improve Utility Customer Experience
By Micah DeHenau, Vertex
1509ELP_24 24 10/8/15 8:01 AM
Sep|Oct|2015 ElEctriclight&PowEr | 25
Customers
number of calls into the call center, providing electronic bills instead
of mailing paper ones, and reducing average handle time as well as
increasing first-call resolution.
Happier customers translate to a better bottom line. In a Bloom-
berg Businessweek research report, it was revealed that process com-
panies in the utilities and energy and resources sectors lead the pack
of global industries in expected big data investment returns, with utili-
ties being able to expect a 73 percent return in 2013.
Even in the case of an outage, when customers are the unhappi-
est, analytics provides opportunity. Many of those customers could
have been channeled to a website or automated phone system to
receive the answers they want, heading off calls before they’re ever
made and providing more information faster to more customers than
an agent could on the phone. Yet a recent 2014 study by Booz Allen
found that just 26 percent of utilities have a mobile app, reflecting the
ongoing hesitancy of many utilities to embrace technology that can
dramatically impact their bottom lines.
Analytics as a Service Reduces Resource Expenditure
Utilities have rightly been concerned with the cost and time involved
to implement new technology like advanced analytics, as well as the
skills needed to operate them. In the past, advanced analytics was a
costly process that could take years rather than months to implement,
diverting attention away from the core business or serving customers.
Today’s technology, however, can be up, running and deliver-
ing insight in as little as a couple of months. Standing up an orga-
nization’s analytics capabilities can be accomplished on a time- and
cost-efficient basis, particularly with analytics as a service. Instead of
having to build and support a team that understands and implements
analytics, organizations can rent them, thereby lowering the cost of
entry. This type of analytics on demand leaves utilities the ability to
focus on their customers.
The return on investment (ROI) is there. Analytics can create a
highly effective phone call that can prevent sending a technician to a
customer’s location to root out a problem. Its results are seen when a
customer’s needs are anticipated by automated voice prompts on the
telephone or through web interaction, preventing the need for a live
agent conversation. Moving the needle even slightly can result in a
significant ROI and improved customer experience.
For utilities dealing with an ever-increasing influx of data, the
sheer amount and variety of information can either be overwhelming
or overlooked. Analytics tools and services provide a way to spin that
raw data into a golden opportunity.
P O W E R - G E N . C O M
L A S V E G A S , N V
L A S V E G A S C O N V E N T I O N C E N T E R
D E C . 8 — 1 0 , 2 0 1 5
THE WORLD’S
LARGEST POWER GENERATION EVENT
OWNED & PRODUCED BY: PRESENTED BY: SUPPORTED BY:
R E G I S T E R T O D AY
Go to http://uaelp.hotims.com for more information.
1509ELP_25 25 10/8/15 8:01 AM
Customers
26 | ElEctriclight&PowEr Sep|Oct|2015
A u t h o r
Jeff Camp is vice
president of contact
center operations at
TXU Energy and Dave
Parkinson is chief
operations officer at
Interactions LLC
IIn Texas, where there is a competitive retail electricity market,
85 percent of consumers can choose their service provider
from a group of more than 50 companies. The competition is
steep, but TXU Energy is the largest retail electricity provider
in Texas, powering more Texans than any other retailer in the
state. This has been achieved by offering a variety of innovative
energy efficiency products and programs, competitively priced
service plans, and great customer service. Customer service, in
particular, is central to the success of TXU Energy.
Telephone support is a primary service channel for TXU
Energy customers. More than 8.5 million customer service
calls are received each year. They range from simple requests,
such as reporting an outage or making a payment, to more
complex tasks, like selecting service plans, transferring
service or resolving a billing issue.
While TXU Energy had a good touch-tone, menu-
based system in place, company leaders recognized that
new technologies made an even better customer experience
possible. With that in mind, the company partnered with
Franklin, Massachusetts-based Interactions to create IVY,
the first and only full natural language virtual assistant
IVR system in the Texas utility market. Just one year after
deployment, IVY reached an important milestone: It began
resolving more calls than all of TXU Energy’s phone-based agents.
IVY: The new Voice of TXU Energy
IVY is not just a creatively branded interface. It’s a highly
conversational customer care virtual assistant capable of
handling complex but repetitive activities, just like a live agent.
IVY does not force customers to use rigid voice prompts
or to put themselves in predetermined boxes requiring them to
select 1, 2 or 3. It simply asks, “How may I help you?” and allows
customers to make requests in their natural speech patterns.
Because it is a virtual assistant rather than a menu-based IVR
system, it can handle a broader scope of responsibilities.
Among its expanded key features, IVY is able to
authenticate accounts, retrieve balances, accept payments,
make payment arrangements and enroll customers in
programs like TXU Energy Average Monthly Billing. It can
also help customers sign up for AutoPay, toggle between
languages in real time; update contact information, reconnect
service related to a disconnection for non-payment, accept
and provide information on service outages, and relay
updates on service orders.
TXU’s Customers Embrace IVY
The response to IVY by TXU Energy’s customers has
been tremendous. In 2013, the legacy solution serviced
approximately 3.4 million calls. In 2014, following the
introduction of IVY, that number jumped to more than 4.5
million calls. By the end of second quarter 2015, IVY was
resolving more calls than TXU Energy’s live agents.
Not only does the system allow for a wider array of self-
service tasks to be completed, but it also has reduced the time it
takes to complete self-service tasks by 35 percent compared to
the legacy system. This is possible because of IVY’s responsive
and conversational nature, which is capable of understanding
open-ended sentences, grammatically incorrect statements and
requests made even when there is background noise.
IVY eliminates another common frustration that
plagues customers. For calls that require an agent, it provides
a seamless handoff. This allows the agent to know who
the customer is immediately and where they were in the
dialogue, saving the customer from the hassle of sharing their
information again and reducing agent-handle time.
Most encouraging: TXU Energy has boosted its CSAT
(customer satisfaction) score by 11 percentage points since
the deployment of IVY from a respectable 82 percent through
the prior IVR system to an impressive 93 percent with virtual
assistant IVY.
Building the Business Case for new Technology
TXU Energy reached the projected three- to five-month
business-case run rate at an accelerated pace of only 40
days and agents are also no longer burdened with low-level,
repetitive activities.
Even though the system is now resolving more calls
than TXU Energy’s live agents, the adoption rate is still
increasing. IVY will never replace TXU Energy’s agents;
that isn’t the goal. IVY still triages the most important calls
to the agents, who are able to provide a more personalized,
attentive, concierge level of service.
Many customers prefer to leverage self-service channels
to quickly and easily get work done on their own terms. The
problem is many menu-based IVR systems simply don’t
facilitate the freedom needed to achieve this goal.
Times have changed and more businesses, whether it
be in the Texas utility market or elsewhere, are leveraging
customer service as an important differentiator. The
implementation of virtual assistant technology not only
offers TXU Energy customers quicker and easier self-service
options, but it has real, tangible business benefits that are
being felt across the call center operation, as well.
Virtual Assistant Drives Self-Service Adoption at TXU Energy
By Jeff Camp, TXU Energy, and Dave Parkinson, Interactions LLC
1509ELP_26 26 10/8/15 8:01 AM
Sep|Oct|2015 ElEctriclight&PowEr | 27
Customers
Complete information at your fingertips. www.csweek.org
Rod Litke, CEO, CS Week
For more information, please visit www.csweek.org
P h o e n i x | A p r i l 2 5 – 2 9 , 2 0 1 6
Fall, a Time for Change…Fall is a time of change for many of us. Farmers and ranchers prepare their land for winter.
Wildlife prepare in various ways for winter and even the Farmer’s Almanac forecasts winter
weather based on wildlife behavior. I’m curious and anxious to see the El Nino effect. Much of
the West, particularly California, could do with the wet winter that is forecasted. Here in Texas,
we also expect an El Nino winter, which means it will be wetter than normal.
Besides the change of season, fall also marks the beginning of football season, a time
many of us enjoy.
Here at CS Week, fall marks something big—the time when our planning committee,
executive advisory panel and CS Week board begin work on the educational content and
direction for our CS Week conference. The 2016 event will be held in Phoenix April 25-29.
I’m certain many of you are aware that we are combining the AGA EEI Customer Service
conference in with CS Week 2016, which promises to make the event even better.
CS Week groups and venues are front and center at the annual planning meetings. This
year we had much more information from our surveys than ever. Our survey results showed
that customer service is the primary interest of 89 percent of our respondents, followed by
75 percent of respondents who list CIS and billing as their primary interest. I’m especially
interested in and proud of the workshop-related survey results that reveal our attendees CS
Week workshop content and ensure our presenters remain at a high quality level.
It is not too early for you to start thinking about two dates that pop up sooner than
expected. Registration for CS Week opens in mid-November online at www.CSWEEK.org.
Also in response to your requests, the Call for 2016 Expanding Excellence Awards submissions
has already opened. Submissions are due no later than Jan. 4, 2016.
Watch for information available soon on greater outreach and year-round involvement in
CS Week’s Women in Utilities.
Stay tuned to our website and social media as
we update events, dates and opportunities
leading up to future CS Weeks. We are
excited to return to Phoenix and are
building toward an even greater
attendee experience—beyond
the classroom—including
the historical setting, the
food and the endless
networking opportunities.
1509ELP_27 27 10/8/15 8:01 AM
T&D Operations
28 | ElEctriclight&PowEr Sep|Oct|2015
MUtilities on the Front Lines of Environmental Stewardship
by Linda Blair, ITC Holdings Corp.
A u t h o r
Linda Blair is executive
vice president and chief
business unit officer at
ITC Holdings Corp.
More than many other industries, utility companies
exemplify environmental stewardship. Power lines,
particularly the high-voltage lines transmitting massive
amounts of electricity across huge swaths of land, must
coexist with the great outdoors.
Managing our country’s high-voltage power grid
carries far-ranging environmental responsibility spanning
the lifecycle of a transmission line. From planning and siting
processes through construction and maintenance activities,
utilities must ensure the safe and reliable delivery of power in
a responsible way that helps protect land, water and species.
ITC’s environmental stewardship activities are driven
by an ISO-14,001-based environmental management system
across our operations. These regulated standards provide a
framework for setting goals for environmental improvement;
developing policies, procedures and work practices to meet
those goals; evaluating performance, developing corrective
and preventive actions and performing management reviews.
Planning and Siting
When planning transmission projects, ITC includes
environmental assessments for wetlands, threatened and
endangered species and other sensitive habitats. By including
these factors at the front end in a transmission line route
analysis, ITC can adjust the placement of the line and
structures to avoid or limit the environmental impact.
For example, we discovered that the proposed route
for our 122-mile greenfield KETA line linking eastern and
western Kansas passed through a breeding ground for the
lesser prairie chicken. This medium-sized, gray-brown
species of grouse occurs in scattered populations in short-
grass prairie in the southwestern quarter of Kansas. In an
effort to preserve the bird’s
breeding grounds, ITC
developed an appropriate
environmental mitigation
and accommodation plan
i n cooperation with the
Kansas Department of
Wildlife and
Parks that included converting approximately 1,200 acres
of privately-owned land in south-central Kansas into lesser
prairie chicken habitat. The 345-kV KETA project entered
service in 2012, facilitating the integration of wind energy
throughout the region.
Line rebuild projects in rural wetlands can pose
particular environmental challenges. In west Michigan, we
needed to replace five 138 kV lines running through 4.5 miles
of wetlands on deteriorated wood H-frames. Before line work
could begin, crews had to reconstruct an old access road and
install three temporary bridges over waterways. The five
lines were consolidated onto three sets of double-circuit steel
monopoles, leaving room for a future sixth circuit. Because
wetlands regulations restrict the digging and installation of
foundations, caissons for the towers had to be sunk directly
into the ground using a hydraulic vibration process. The five
lines were returned to service in 2011.
Construction and Recycling
Rebuilding hundreds of miles of old transmission
infrastructure poses the challenge of how to properly handle
the retired components. ITC decommissioned and recycled
an estimated 6 million pounds of equipment from the electric
transmission network last year alone, including circuit
breakers, transformers and other metals. That’s equal to a
fleet of 280 school buses-worth of metal. We also recycled
more than 225,000 gallons of oil last year.
Wooden transmission poles are recyclable, too. ITC this
past summer donated 10 cedar poles from decommissioned
power structures to the Iowa Department of Transportation
(IDOT) to use as bat poles serving the habitat of the Indiana
long-eared bat, a federally endangered species. The poles
are being installed in two locations where the IDOT has
woodland and wetland mitigation projects.
Also this past summer, ITC partnered with the Huron
River Watershed Council, Southeast Michigan Osprey Watch,
Audubon Society and Ann Arbor Parks to increase the number
of osprey in the region. We repurposed decommissioned cedar
transmission poles into two osprey nest platforms, which were
installed in the watershed in July. ITC has active partnerships
with five watershed conservation groups in Michigan.
Proper handling of emissions from substation equipment
ITC collaborates with organizations in Iowa and Michigan to create natural transmission corridors featuring native plants.
1509ELP_28 28 10/8/15 8:01 AM
Sep|Oct|2015 ElEctriclight&PowEr | 29
T&D Operations
is another ITC focus. We voluntarily joined forces with the U.S.
Environmental Protection Agency (EPA) SF6 (sulfur hexafluoride)
Emission Reduction Partnership for Electric Power Systems in
2005. ITC joined the partnership to institute an industry standard for
reporting its emissions; to establish inventory tracking of its SF6 use;
and to work in collaboration with other industry partners and the EPA
to develop and improve gas handling and maintenance programs.
In recognition of these efforts, the EPA presented its SF6 Team
Leadership Award to ITC in 2012.
Operations and Maintenance
An ever-present reality to us as the country’s largest independent
transmission company is that trees and high-voltage power lines can
be a hazardous combination. To prevent events like the Northeast
Blackout of 2003, vegetation management needs to be a key
component of any utility’s operations and maintenance program.
Selective removal of incompatible species in urban, suburban and
rural transmission corridors is the cornerstone of our integrated
vegetation management program. These efforts make space for
grasses, wildflowers and low-growing shrubs to thrive.
Foresters and other trained field staff routinely inspect our
corridors, identify both appropriate and incompatible species on a
site-by-site basis and recommend suitable management methods
in the greenways. We favor the removal of incompatible trees over
trimming because trees that are trimmed can produce aggressive new
growth. This is especially hazardous during hot summer months when
transmission lines sag due to the energy load they carry.
In addition to the objective of maintaining safe and reliable
service, responsible vegetation management can result in diverse,
stable, natural greenways under and adjacent to transmission
corridors, with less environmental disturbance. For example, in
2010, ITC began partnering with Stony Creek Metropark, a 4,500-
acre, multi-use recreational park north of Detroit, to manage wildlife
habitat in ITC’s transmission corridor passing through the park. Our
vegetation management plan in the park focuses on the removal of
invasive woody and herbaceous species, and the re-establishment and
seeding of native prairie grasses and wildflowers. The Stony Creek
project is among 10 ITC environmental conservation efforts certified
by the Wildlife Habitat Council, which promotes and certifies habitat
conservation and management on corporate lands nationally through
partnerships and education.
ITC is lending similar support toward helping states address
declines in natural lands and habitats. To help Iowa address its
increasing loss of native prairie lands, ITC over-seeded three
electric transmission line corridors in the Cedar Rapids area in late
2014, covering about 42 acres. The plantings feature native grasses,
wildflowers and broadleaf native plants. Well-established prairie
grasses will help prevent various types of invasive trees from taking
root and potentially growing into the power lines.
Elsewhere in Iowa, we are working with the U.S. Fish and
Wildlife Service and other agencies on ways to deter eagles from
coming into accidental contact with transmission lines, by installing
bird diverters on lines.
Michigan also is dealing with a declining natural feature—
lakeplain prairie lands. We began partnering with The Nature
Conservancy in 2013 in a multi-year effort to restore these lands in
southeast Michigan, including some found along ITC transmission
line corridors. Restoration involves eliminating invasive plant species
that crowd out the original prairie and are detrimental to wildlife.
This effort helps restore ecosystem functions, improve and increase
habitat for rare insects, plants and animals and increase flora and fauna
diversity.
In our Facilities
Our commitment to the environment extends to our workplaces,
with waste reduction efforts underway at several ITC facilities. By
removing wood, cardboard, paper and plastic from the general waste
streams and recycling these materials, we have reduced the average
volume of material sent from our warehouses to landfills by 50
percent over the past two years. At two warehouses, we now compact
and send waste that cannot be recycled to energy recovery facilities,
converting what trash remains into electricity.
Additionally, employees at our corporate headquarters in Novi,
Michigan, have embraced their own waste reduction effort. An audit
conducted by our employee volunteer Green Team showed that about
55 percent of the waste generated onsite—much of which could be
recycled—was going to a landfill. The audit led to a program to
achieve zero landfill waste from the building by a goal year of 2016.
Among other efforts, our Green Team rolled out a program to make
recycling easier in the building and is studying food waste composting
and a waste-to-energy stream to achieve this goal.
Collaboration and Best Practices
As evidenced, the work of our industry carries great environmental
responsibility from multiple perspectives. Few companies and
industries operate as close to the landscape as we utilities do, so let’s
continue to exchange ideas as we all strive for the best approaches to
environmental stewardship.
An integrated vegetation management program begins with keeping trees away from power lines.
1509ELP_29 29 10/8/15 8:01 AM
TThe recent proliferation of utility-scale renewable energy
projects, driven by legislative mandates, has created a need to
transfer large amounts of electricity from distant rural areas,
often in the middle of the continent, to urban load centers
generally on the coasts. The long distances involved have
led to a resurgence in interest in high-voltage direct current
(HVDC) overhead transmission, a technology little used in
North America in the last 30-40 years.
A handful of 400 kV or bigger HVDC overhead
transmission lines were built in North America in the 1970s
and ‘80s, These included Nelson River, Quebec-New England,
Pacific DC Intertie, Path 27, and the CU Line. While HVDC
has been used in a number of undersea cable projects on the
continent, since 1986 no new HVDC overhead line has been
energized in North America.
That will soon change.
Over a dozen new projects are under development
or construction across North America. Most are intended
to transport hydro power or wind power from the North to
the South or the middle of the continent to the coasts. The
large amount of capacity needed and the long distance to be
travelled make HVDC a viable option for these projects.
In addition to the myriad challenges involved in building
any large-scale, high-voltage transmission project, HVDC
brings additional challenges as there is little recent experience
in building or operating these systems and few companies
have HVDC lines. Therefore, there is a desire by companies
building these systems to understand costs (and validate EPC
estimates) of both constructing and operating these systems
in order to ensure they are prudent and reasonable.
For one company developing a 500kV HVDC project
in North America, the answer to better comprehension of
what it would take to build and run the project was to use
benchmarking to understand comparative costs. This is an
approach which others would be advised to consider as it
can serve to validate to the board that costs are reasonable,
prove to regulators that costs are prudent, and assist asset
management in understanding the likely O&M costs.
A limited number of 400 kV+ HVDC overhead line
projects have been implemented in North America, although
a number of projects are planned. Given the lack of recent
North American systems and relatively small number
of HVDC projects implemented, comparative data for a
benchmarking exercise will have to be sourced globally,
as most of the existing 400-600 kV+ HVDC overhead line
projects have been built outside of North America.
Using data from other countries to benchmark brings
a host of challenges which includes normalizing the data
for currency fluctuations and wage rate differences, not to
mention inflation for different time periods. In addition, there
are significant differences in regulatory and environmental
regimes around the globe which can impact costs.
Benchmarking Construction Costs
For lines specifically, there are also a number of factors which
must be accounted for to ensure costs are comparable. The
projects being compared will vary in terms of capacity and
higher capacity lines translate into higher costs. Using linear
regression, a formula can be developed by which capacity of
all projects can be adjusted to an equivalent basis versus the
average. By applying the formula to the difference in capacity
from the average, an adjustment factor can be calculated. This
factor can then applied to the project’s cost per line mile to
determine an equivalent cost per mile (see Figure 1).
Different tower types can also be used for projects. As
guyed towers are less expensive than freestanding towers,
the projects being compared must be adjusted to factor in the
average cost difference between them to put the towers on an
equivalent cost-per-mile basis. There are other adjustments
which can be made to the comparative cost of overhead lines
such as return type, foundation type, conductor type, etc.
However, comparative data on these can be hard to gather
and the value may not be worth the additional cost and effort.
Benchmarking lines is always an easier task than stations
(regardless of AC or DC) because of the relative simplicity of
transmission lines vs substations. As discussed previously,
transmission lines mainly differ in just a few dimensions
(tower type, foundation type, conductor type/size/capacity,
etc). Substations are all unique with different numbers,
types and voltage levels of equipment. Therefore, accurate
T&D Operations
30 | ElEctriclight&PowEr Sep|Oct|2015
Benchmarking in Action:Comparing the Costs of HVDC
by Steven J. Morris, UMS Group Inc.
A u t h o r
Steven Morris is a Principal
of UMS Group Inc. and
its client sponsored
benchmarking and best
practice study leader. He
has 20 years of utility
industry experience and
has assisted numerous
utilities in benchmarking
generation, transmission,
distribution, and corporate
services functions.
Reach him at smorris@
umsgroup.com.
Example of Adjustments to Overhead Line CostsFigure 1
1509ELP_30 30 10/8/15 8:01 AM
Sep|Oct|2015 ElEctriclight&PowEr | 31
T&D Operations
benchmarking requires decomposing the substations to be compared
into equivalent values (i.e., transformer capacity) and counts for
major equipment.
For HVDC projects, this decomposition is impossible to
achieve. There are only three vendors supplying converter stations.
Price is heavily driven by the competitive pressure on the companies
to procure projects at that specific time. Therefore, the same project
procured in a different period might be more or less competitively
bid. In addition, virtually all HVDC converter stations are procured
through turn-key contracts with strict confidentiality clauses. This
inhibits the ability to break station costs down into their constituent
components hindering analysis of cost drivers. However, there are
some normalization factors that can be used to assess stations. This
includes assessing on a cost per MW basis, as well as adjusting to
equivalent capacity (as with lines) (see figure 2).
From an overall project perspective, the benchmarking effort
should look at location-specific drivers of cost differences. The
most common of these is wage rates which can be used to normalize
labor costs. However, a look at a functional cost breakdown (i.e.,
permitting, ROW acquisition) can also be used to identify not only
where local differences are driving costs, but also where internal
efficiency (e.g., project management, engineering) exists.
Benchmarking Operations and Maintenance Costs
The above discussion has dealt with benchmarking construction
costs, but a company building a new HVDC project also needs to
understand what it’s going to cost to operate and maintain the system.
Typically, the converter station vendor will provide a recommended
maintenance schedule for the DC yard, but there are a number of
operating factors which impact maintenance that will not be known
until operating experience occurs. These include power transfer
levels, operating scheme, utilization rate, etc.
In addition, companies maintain their converter stations
differently. Some maintain them remotely, while others maintain
them locally. Some have dedicated DC staff, while others have
shared staff with their AC stations. Some have 24/7 on-site personnel,
while others only run one shift. The physical size of the facility and
amount/type of the equipment in the station also impact the amount
of maintenance required.
Another factor driving O&M costs is that not all projects face
the same reliability requirements. Commercial projects typically
don’t face strict system operator requirements for reliability,
different regulators have different requirements for inspection and
maintenance, and non-North American projects don’t have to meet
NERC CIPS requirements. These factors all impact the amount of
maintenance required and must all be taken into consideration when
benchmarking staffing levels and O&M costs (see Figure 3).
Outside of North America, it is common for utilities to contract
out maintenance of their HVDC converter stations. As many have
only one or two converter stations, they do not see the point in staffing
and training a small group just for HVDC. However, in North
America, most major maintenance is performed in house. Regardless,
availability of contract resources can impact staffing levels. Stations
that are located in areas where the skills needed for HVDC are simply
not available or in areas with heavy demand from other industries may
not be able to take advantage of contractors, even if they wished to.
The number of maintenance outages taken also differs by
company and can drive total O&M costs. Depending on the degree
of redundancy in critical systems and the loading scheduling, some
utilities may take outages biennially. However, most utilities with
HVDC typically take scheduled maintenance outages once or twice
a year. These outages can last from several days to several weeks,
depending on the complexity of the tasks to be completed and are a
key cost driver.
Newer stations have a high degree of remote, self-diagnostic
capabilities, requiring less on-site monitoring. Remote operations by
the control center allow for use of shared resources versus on-site
operations which require dedicated staff. However, on-site operators
are generally also able to perform minor maintenance, so there may
be a cost trade-off which must be factored into to comparisons.
Finally, companies building HVDC projects, particularly
those without existing HVDC assets, will face a learning curve on
maintenance. During the first couple of years of operation there will
likely be increased demand for O&M field personnel (e.g., support initial
equipment troubles, capital loading for project deficiency corrections
and warranty, etc.) that will decrease over time, supporting the release of
dedicated technical resources and increased sharing of resources.
Benchmarking can serve a useful purpose for companies
developing overhead HVDC projects. However, careful consideration
must be given to those exogenous factors which drive cost differences
to ensure that an apples-to-apples comparison is made.
Scatter Chart of Converter Station Cost vs. CapacityFigure 2
Equivalent Staffing Levels for Converter StationsFigure 3
1509ELP_31 31 10/8/15 8:01 AM
Energy Efficiency & Demand Response
32 | ElEctriclight&PowEr Sep|Oct|2015
A u t h o r
Ed Thomas has been
executive director of
Peak Load Management
Alliance since 2013.
UUntil recently, demand response was mostly considered a
stopgap measure to be used during a peak load event. Recently,
however, utilities are beginning to see demand response as a
tool to be used in system planning and operations, especially
when it comes to integrating renewable energy.
Peak Load Management Alliance (PLMA) Board
Chairman Paul Tyno with Buffalo Energy Advisors, PLMA
Board Vice Chairman Rich Philip with Duke Energy,
and Extensible Energy President and CEO John Powers
participated in a PLMA Demand Response Dialogue in
early August. They discussed demand response’s move into
the mainstream and how utilities are incorporating demand
response into their operating and business processes.
“Many in the demand response community feel this is a
transformative time for demand response as we’ve known it,”
Tyno said. “I look at the future of demand response in terms
of dynamic load management and what a collective group of
customer-based assets could do, including a robust demand
response capability. What could those assets provide back to
the grid in a market that compensates them for the capability?
We’re at a very interesting point. I
think of demand response as a 24/7,
365-day resource proactively used
to manage versus an emergency-
only resource of last resort.”
Duke Energy looks at
demand response as a transmission
distribution planning tool, Philip
said. In some situations, localized demand response activities
are being used to address implications from the changing
generation mix coupled with transmission construction
constraints that can result in overloaded circuits.
“We are considering how demand management might
be able to make a difference for a lot more days of the year
than just the three or four “emergency” days that used to be
applied in the traditional generation planning context,” Philip
said. “In one circumstance, we might be able to impact how
many days certain lines may be exposed and, hopefully,
reduce that risk from 50 days at 85 degrees, or warmer, to
a lower contingency, something like 30 days at 88 degrees.”
Demand Response is Growing Up
“Demand response is becoming less of a safety net and
moving in the direction of becoming a mainstream resource,”
Tyno said
Philip added that he believes it may be a key building
block for where energy utility system planning is going in
the future.
“Just over the last several years, it’s pretty astounding
to see how the cost and capabilities of new control systems
have evolved. Ten years ago, the idea of behavioral demand
response was a nice concept, but today it’s been made real by
our automated metering infrastructure,” he said.
The emergence of AMI
technology deployments across the
country will enable utilities like Duke
Energy to explore a shorter-term type
of demand response in a more succinct
way. With that will come more
robust evaluation into the customer
experience to verify that their comfort is not impacted, Philip said.
As demand response becomes more automatic and can
be activated based on certain thresholds like temperature,
load and frequency levels, and does not require real-time
human decision-making, the more utilities will consider it
a deployable resource that operators will trust and use for
planning purposes, he said.
Powers looks at things a little differently.
“As an economist, I take the
valuation question a little more
literally. There is a lot of work still to
be done in some markets on how to
value demand response,” Powers said.
In areas where demand
response, especially fast-acting
demand response, is beginning to
play in ancillary services markets, its value is starting to be
recognized, he said.
Some examples of utilities operating in jurisdictions
where demand response programs are being monetized
include Pacific Gas & Electric service areas and others in
California, as well as Great River Energy in the Midwest.
Great River Energy has initiated a program with grid-
interactive water heaters. The program has shown a higher
valuation than many other programs because the utility has
been allowed to tap into the market for ancillary services,
The Future of Demand Response: The Practitioner’s View
By Ed Thomas, PLMA
Rich Philip, PLMA Board Vice Chairman, Duke Energy
Paul Tyno, Peak Load Management Alliance Board Chairman, Buffalo Energy Advisors
John Powers, President and CEO, Extensible Energy
1509ELP_32 32 10/8/15 8:02 AM
Sep|Oct|2015 ElEctriclight&PowEr | 33
Energy Efficiency & Demand Response
Powers said.
While customer satisfaction is essential to a successful demand
response program, utilities also must find a way to pay for the
program, he said.
DR and Renewable Energy
Renewable energy integration is also a driver in the future of
demand response.
Although controls and monitoring technologies are improving
and their costs are going down, more will be required to make demand
response a viable tool for renewable energy integration, Powers said.
“It will take a combination of technology, program design and
redesign of business models, in particular pricing and risk sharing,”
he said. “The problems presented by renewables integration are really
very different than those presented by peak shaving. We shouldn’t be
surprised that the solutions need to be different as well.”
Tyno believes demand response is becoming less of a safety net
and moving in the direction of becoming a mainstream resource. It
has the potential to work much better than it’s working now, but that
potential is not tapped by most programs today. For demand response
to be an effective tool for renewable integration, it must reach its
potential, he said.
“I go back to what the objectives of the programs were and what
the objectives under renewable integration will become,” Powers said.
“We all talk about demand response in terms of a few dimensions,
right? It’s how responsive the load is in terms of latency from when
the signal goes out to when it goes down and to the duration of the
impact or the frequency of the impact. Is it one way or two-way? Can
you actually increase load as well as decrease load? What about the
size of the impact depending on time of day or whether there are other
constraints? All those dimensions shift from an emergency program
or peak shaving program into a renewables integration program. A
utility can’t simply assume its demand-response tactics for peak
shaving will fit the bill for a renewables integration problem.
“If we’re willing to embrace some changes in technology
program redesign and pricing, then I think we can provide a
mainstream operational response to renewables integration. If
we’re just looking to say, ‘Let’s take our existing program and call
it renewables integration,’ I think we’ll miss huge opportunities,”
Powers said.
A Focus on the Customer
No matter how well planned or implemented, no demand
response program will be successful unless customers buy into it.
And, as customers become more educated, look for more sustainable
energy options and even opt to become energy providers, utility
demand response programs must evolve to be accepted.
If utilities take a customer-oriented perspective, things will start
to move faster, Tyno said.
“Customers, especially on the C&I (commercial and industrial)
side, are thinking in terms of optimization and taking more of a holistic
view on how they want to interact or function with the grid,” Tyno
said. “They’re looking for market signals to make investments. Those
investments might be in co-generation, renewables, storage, energy
efficiency, certainly demand response and demand-management
capabilities. That’s how you animate the market, by sending the right
price/investment signal down to the customer.”
Powers agreed.
“The increased penetration of renewables is having a bigger
impact on the grid than most of us have acknowledged so far,” he said.
“When you look at the prices of renewables and how rapidly they’re
dropping, it takes some people by surprise.”
In the most recent solar procurements in Texas and Nevada,
some power purchase agreements are coming in at four or five cents
per kWh, Powers said.
“That changes things a lot; the signals we’re sending to
customers are still that energy is expensive—but it’s not. Energy is
cheap, reliability is expensive and once we get that into price signals
that are going out to customers we will get a lot more responsive load
from customers,” he said.
Powers cited community solar as an example. Distributed
photovoltaic solar adds variability to the net system load and a well-
matched set of demand response options has the potential to offset or
remove some of that same variability.
“Community solar presents a special opportunity for utilities. I tell
people that rooftop solar is something that happens to utilities; community
solar is something that utilities can help make happen,” he said.
A utility can implement strategic siting and put a solar plant
somewhere on the grid where it will do the most good rather than
the most harm. It also can coordinate the output from that solar
plant around demand response customers with whom it has existing
relationships.
Appealing to customers is an important part of the equation.
Market research continues to suggest that most customers want more
renewables and they know little about demand response despite
utilities’ best efforts to educate them. Designing a demand-response
program that can tap into the popularity of renewables can pay off,
Powers said.
“We think that community solar presents a special opportunity
for utilities that are trying to accelerate that shift towards demand
response as a renewables integration strategy,” he said.
The way forward will be to align the benefits to both customers
and utilities with automatically enabled energy management where
demand response is a “behind the scenes activity” that happens in
ways that are often invisible to customers, Philip said.
“I really do think that’s the way forward,” he said. “Paying
incentives to people to do something that they would never dream of
doing otherwise is how demand response ‘grew up.’ We are getting
away from that.”
The markets should take that approach going forward, he said.
s
p
c
c
t
f
“...the signals we’re sending to customers are still that energy is expensive—but it’s not. Energy is cheap, reliability is expensive...” John Powers, Extensible Energy
1509ELP_33 33 10/8/15 8:02 AM
Energy Efficiency & Demand Response
34 | ElEctriclight&PowEr Sep|Oct|2015
A u t h o r
Mark M. MacCracken
is CEO of CALMAC
Manufacturing Corp.,
which claims to be the
largest manufacturer of
thermal energy storage
equipment in the
world, with over 4,000
installations in 37
countries. He also the
former board of direc-
tors’ chair for the U.S.
Green Building Council.
TThe Alamo Heights Independent School District
(AHISD) serves the Texas communities of Alamo Heights,
Terrell Hills, Olmos Park, and a portion of north San Antonio.
Originally established in 1909, AHISD has a rich history
that is deeply ingrained within the local community and has
evolved from a rural district to a suburban district. In 2010,
the 9.4 square mile district started an initiative to increase
sustainability and reduce utility costs.
Challenge
Facing reductions in budgets and the need for upgrades to
address a growing student population, the AHISD turned to
the community. In 2010, community voters approved a $44
million bond for the school district. These funds were then
earmarked to help improve technology in classrooms, expand
the High School’s Music Building, increase the number of
overall classrooms, implement technologies that would help
reduce operating costs and address the numerous needs listed
in the district’s bond proposal.
Solution
AHISD explored many options on how to implement the
newly obtained funds. The use of geothermal energy and tri-
generation were discussed, but ultimately the deployment of
solar generation and ice-based thermal energy storage was
decided upon.
AHISD installed a 500 kW solar system split between
two campuses—Alamo Heights High School and Woodridge
Elementary—through CPS Energy’s Solartricity program.
The system generates $235,000 annually, with all energy
being sold back to CPS Energy at 27 cents per kWh.
Separate from this program, the AHISD decided to
install another five solar arrays at four campuses and the
maintenance building. The energy produced by these arrays,
totaling 400 kW and generating 40,000 kWh of energy per
month, is used by the district to power daily operations.
Payback on all the arrays is between 12 and 14 years.
Although the renewable technology will prove beneficial for
both utility and school district, there was still a need to reduce
energy costs by lowering demand.
AHISD relies partially on the grid for electricity use and
the grid is mostly powered by fossil fuels. Fossil fuels are not
just a form of energy; they are a form of stored energy held in
reserves. Renewables on the other hand are energy that only
happens when they happen. So when renewables were added
to the schools, peak demand didn’t necessarily go down.
The sun didn’t always shine. The school ended up using the
grid as a backup source of generation when renewables were
unavailable. When a school is unable to generate enough
energy from solar, it draws from the grid, which usually
occurs during peak demand hours when the least efficient
power plants are running and electricity is most expensive.
As a strategy to reduce peak demand and complement
the solar installation, Brian Uhlrich of DBR Engineering
Consultants, recommended CALMAC’s IceBank® energy
storage tanks. They came online in 2012. The energy storage
system creates cooling in the form of ice at night and then
stores it within the energy storage tanks when demand is
low and energy prices are discounted. The next day during
peak demand hours, the ice is melted to cool students and
teachers inside of a building. Through third-party automated
control software, demand targets can be set and the ice will be
used once within 10 percent of the programmed target. This
provides a flat, more attractive load profile to the utility and
controls district energy costs.
Fine Arts Building
AHISD also identified that ice-based energy storage would help
with the expansion of the high school’s fine arts building, one
of the major projects that was included in the bond proposal.
Enrollment in AHISD’s music programs had tripled since the
opening of the music program. It was to the point that the
orchestra program students were using the foyer as a classroom,
making expansion a top priority.
Lowell Tacker, AIA, LEED AP, Principal with LPA,
Inc. was chosen to help bring the expansion of the fine arts
building to fruition. This addition and renovation project
added a building that could serve as a direct link between
the existing practice facility and auditorium. The extra square
footage that was added as a result of the project could be
Texas School District Slashes Operating Costs with Solar and Ice-based Energy Storage
By Mark MacCracken, CALMAC Manufacturing Corp.
1509ELP_34 34 10/8/15 8:02 AM
Sep|Oct|2015 ElEctriclight&PowEr | 35
Energy Efficiency & Demand Response
cooled using cooling that was created at night and stored in the ice-
based energy storage tanks. This would allow the district to meet
the extra cooling demand of the new structure without upgrading to
bigger chillers to meet the new load.
“This was the first project that I’ve worked on involving a
thermal storage system,” said Lowell. “Given the size and usage of
the campus we felt a thermal storage system appropriate. The best
thing is we have actual usage data to back up the numbers. We added
over 40,000 square feet and the energy costs per square foot have
gone down considerably. For any project of this scale and usage,
there’s no reason not to use consider energy storage technology.”
Results
The decision to use the bond funds to target energy efficiency upgrades
and lower operating costs has proven itself extremely wise, as the
Alamo Heights district has roughly $422 less per student today from
traditional state funding than it did at the start of the projects in 2010.
The district is able to generate revenue through its solar program and
has reduced peak demand in buildings with energy storage.
Currently 240 kW of energy storage is being used. Energy
storage is responsible for providing air-conditioning to 325,442
square feet split between the five buildings on the high school
campus. AHISD has reduced peak demand energy consumption by
roughly 21 percent at Alamo Heights High School in its first year of
operation. This decrease in peak energy usage from the grid comes
despite the high school increasing the size of its fine arts building by
over 12,000 square feet.
“Despite fiscal pressure, we identified a need to become smarter
with our energy purchases in order to reduce operating costs and
reallocate them to other important areas. We had heard about energy
storage in the past, but the technology has exceeded expectations,” said
Mike Hagar, assistant superintendent for business and finance at AHISD.
Summary
Through community support, AHISD was able to make a big impact
to its energy future by implementing energy storage and renewable
energy technology. These chosen strategies have allowed the district
to generate revenue and reduce peak demand. The proactive actions
of the AHISD has set the foundation for a much more cost-effective
and sustainable future.
Ad Index
Ad index name . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .PG#DISTRIBUTECH 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13
DOBLE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .23
EL&P EXECUTIVE CONFERENCE 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1
GENERATION HUB . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .22
LEIDOS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11
MITSUBISHI HITACHI POWER SYSTEMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .C2
POWER AWARDS GALA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .15
POWER-GEN INTERNATIONAL 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23, 25
RES AMERICAS INC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .C4
S&C ELECTRIC COMPANY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3
SABRE INDUSTRIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .C3
Ad Index
1509ELP_35 35 10/8/15 8:02 AM
S P E C I A L
36 | ElEctriclight&PowEr Sep|Oct|2015
Fight the Good Fight
A u t h o r
EJay Mecredy is product
manager at Courion
Corp. Courion is focused
on identity and access
management solutions.
Energy companies are a nearly irresistible target for
hackers and data thieves. They have their customers’ financial
data and employees’ healthcare information. They perform a
vital economic function. They operate large, complex and often
computer-controlled machinery. After an era of deregulation,
mergers, acquisitions and consolidation, they often have a
patchwork of IT systems and security applications with seams
and forgotten back doors to be exploited.
So is it surprising that the Department of Homeland
Security’s Computer Emergency Readiness Team investigated
79 hacking incidents at energy companies in 2014? Or that
hackers broke into 37 percent of energy companies in 2013-
14, according to ThreatTrack Security?
It shouldn’t be. What’s more surprising is that it doesn’t
happen more often. The energy industry is in the mainstream
of U.S. industries that are using outmoded, largely manual
methods of protecting their networks. Most energy companies
concentrate their security efforts on keeping intruders out of
the network while they are vulnerable to the most devastating
and hard-to-detect attack—an internal attack using legitimate
user privileges to steal or corrupt data.
Hackers are targeting energy companies with
increasingly clever tactics to trick network users into giving
up their credentials. With email addresses widely available on
the Internet, hackers can contact employees directly under the
guise of official business and present seemingly legitimate
reasons for replying with user names and passwords; or they
can get them to click on a malware attachment disguised to
look like a harmless document or image. Sometimes it can
be as easy for a hacker as exploiting a security hole in a Web
browser while the user is surfing the Web to seize credentials
and access privileged services.
Once a hacker is inside a power company network using
legitimate credentials he or she can sign into applications
and databases or request access to more resources.
In a large organization, IT can’t vet these requests
because they don’t know the sources. Once the
hacker has network access, it’s almost impossible to catch
them with the tools available to most IT professionals today.
The primary access protection device at most energy
companies is certification processes mandated by federal
regulations. IT extracts lists of users from database and
application access management systems, cleanses them,
and distributes them to business managers for certification,
usually as spreadsheets. If an employee has left or has a
privilege that isn’t necessary for their job, the manager
notifies IT to terminate the privileges.
By then, it’s usually too late. Hackers probe networks
and phish for credentials almost every hour of the day, but
most organizations only review their access privileges
quarterly or, at the most, monthly. Reviews based on manual
data extraction and cleansing are too slow and expensive
to conduct frequently, so most organizations do enough to
satisfy regulatory requirements and little more.
It is this lack of intelligent, automated access management
solution tools in most corporate infrastructures that puts IT at
a disadvantage against hackers. With the constant push toward
more open networks that encompass customers, vendors and
partners, data is constantly more exposed to hackers. In the
energy industry, the growing popularity of wireless meters
linked in mesh networks opens another door to the network,
as do employees at remote drill sites who send data back over
wireless links.
Focusing data security resources on keeping the wrong
people out of the networks is playing a losing game in this era
of increasing openness. Energy companies need data security
systems that help them identify hackers who are using
legitimate credentials. They are composed of three essential
elements: 1) automated data extraction to eliminate slow,
costly manual data extraction; 2) role-based management
that prescribes which access privileges employees need to do
their jobs and makes identifying suspicious privilege requests
easier; and 3) user data analytics for detecting suspicious
patterns of use.
Unified in a security framework that encompasses all vital
IT resources, these elements enable IT staff to answer questions
that identify high-risk individuals and groups, such as:
• Are there domain administrator accounts whose
passwords have been changed?
• Which non-sales system have sales people accessed?
• Is anyone accessing customer information without a
genuine need to know?
• Does this business unit have an abnormal number of
accounts with unnecessary entitlements?
Hackers and energy companies have one thing in
common: they both work constantly. Energy company IT
staffs need the tools to identify hackers who have stolen
legitimate access credentials to probe networks from the
inside. The tools are available now—Amazon.com has
been using comparable technology for years to track
customer preferences. Energy companies owe it to their
own customers—and employees, partners, vendors, etc.—to
adopt it now.
Energy Companies Must Fight the Internal Battle Against Data Theft
By Jay Mecredy, Courion Corp.
1509ELP_36 36 10/8/15 8:02 AM
Go to http://uaelp.hotims.com for more information.
1509ELP_C3 3 10/8/15 8:06 AM
Go to http://uaelp.hotims.com for more information.
19.8 MW (7.9 MWh)
Jake Energy Storage Center
Renewable Energy Systems
11101 W. 120th Ave. | Suite 400
� ���������������| 303.439.4200
res-americas.com [email protected]
Powering Change DEVELOPMENT | ENGINEERING
CONSTRUCTION | OPERATIONS
���������� ���������������������������������������
���������������������������������������������������������
��������������������������������
Technologies
Energy Storage: 75 MW ��������������������������������
���������������������� �����������������������
Wind and Solar: ���� 8,000 MW ����������������������
������������������������������������
Transmission: 650 miles ���������������������������������
� ����������� ����
Capabilities
��5,000 MW�&���&��%������������&�������&%�
����&��%�������&%������������� ��%�����������%��
����&&��%������&%�&%��&��!��%�����"�����"&��%�#��%���
����&'�%���������%���&&��%��������������%�$�%'�%��
��������%���&&��%�����
����%�energy storage solutions���� ��������%����%���&
������%������%�������%��'��&��&����������&%��&���
����������%���
��Customized������&�'��������������%���
����&��%���&�����&��%��&��solutions���������������
������������������� �����������
Go to http://uaelp.hotims.com for more information.
1509ELP_C4 4 10/8/15 8:06 AM