Using distributed energy to lower peak demand, increase resilience, save money, and lower emissions: Utility found storage cheaper than a second power line

Can grid resiliency finally pay for itself? JULIAN SPECTOR GTM Research, JUNE 07, 2019 Eversource Wants to Back Up an Entire Rural Town With Batteries Large and Small 2

This is not, strictly speaking, a resilience play — it’s using distributed energy to lower peak demand, thereby saving money and lowering carbon emissions

The traditional option would be to build a redundant power line. Eversource is trying something different.

The traditional option would be to build a redundant power line. Eversource is trying something different.

New England utility Eversource wants to deploy energy storage to back up an outage-prone New Hampshire town, while saving customers money.

The 18,070 residents of Westmoreland rely on a single radial power line to deliver electricity through the forested, rural surroundings. Ice storms and heavy snowfall regularly knock that line down, making the area an outlier in the frequency and duration of outages.

“The traditional answer would be to build a redundant line to back up the one line if it goes out,” said Charlotte Ancel, director of clean energy development at Eversource. “But we see this all the time in storms, where the redundant line goes out too.”

Instead, Ancel’s team proposed small- and large-scale energy storage to power up the entire community when the feeder goes down, and reduce bills at other times by lowering the town’s peak consumption. It’s a new spin on the concept of using clean energy technology to offset traditional grid expenses, an approach known as non-wires alternatives.

The Westmoreland Clean Innovation Project also comes as New England states use policy and regulatory tools to push their grids in a cleaner, more decentralized direction. If it gets regulatory approval and performs as expected, this could lead to similar projects in other towns with severe reliability concerns.

New approach 

Non-wires projects have featured utility-owned batteries, like Punkin Center in Arizona, or customer-owned devices, like Demand Energy’s Marcus Garvey project in Brooklyn. A few even tap a network of small devices in customers’ homes, like Liberty Utilities’ innovative residential battery pilot in New Hampshire.

The Westmoreland project would combine both. Eversource wants to own and operate the 1.7-megawatt/7.1-megawatt-hour battery as the bulwark of the local grid defenses. But it will reduce the capacity that the battery needs by complementing it with customer programs.

The utility will target energy efficiency upgrades in the area, as well as a “bring-your-own-device” plan where customers earn money for letting Eversource use their batteries, thermostats or electric car chargers for demand reduction during peak events.

“Every kilowatt of efficiency savings that we come up with enables us to size that battery smaller, which brings down cost,” Ancel said.

Reducing peak load with the network of small energy devices will shave about $750,000 off the capital expense of the battery, she added. 

This structure opens up several avenues for New England’s budding storage industry to pursue: utility-scale system design and construction (the central battery will go through competitive procurement), consumer-facing storage sales and aggregation services for customer devices.

A better deal for resilience

Grid resilience, the ability to bounce back from disruptions caused by extreme weather or climate change or some other human activity, is something a lot of people say they want until they have to actually pay for it. The Westmoreland project, notably, structures the grid investments so they provide resilience but also return net savings to ratepayers.

The number to beat was $6 million, the estimated cost of building the redundant distribution line. The project came in at around $7 million upfront, but will provide customers a net savings of $2 million over the course of its 25-year operating life, Ancel said.

An extra power line would sit around waiting for a tree to fall on its counterpart to make the investment worthwhile. When the battery isn’t preparing for a storm-induced outage, it can save money for the utility territory.

The utility gets charged for consumption during the annual peak in ISO New England, as well as monthly regional transmission peaks. Those charges get distributed among all the customers in the territory. Insofar as the battery project cuts Westmoreland’s annual and monthly peak consumption, it incrementally lowers the charges that the entire customer base has to pay. That explains the long-term savings despite the higher upfront price tag.

To secure those savings, the utility has to successfully predict the peaks and discharge the batteries accordingly. But it helps that the big battery will pack a longer duration — enough to back up the town for five hours at the beginning of its operating life.

“The longer duration of the battery makes it easier to ensure that we hit those peaks to deliver savings to our customers,” Ancel said.

This is a novel way of making clean energy feasible in today’s regulatory construct. Showing how one community’s upgrade helps all customers is a definite plus, if not a necessity. This design also makes a rate-based, utility-owned asset sound palatable, if not downright exciting.

By choosing to stay away from owning any devices behind the meter, Eversource avoided the kinds of competitive landscape challenges that arose when New Hampshire’s Liberty Utilities asked to own 1,000 Tesla Powerwalls in customer homes.

Instead of a utility trying to claim all of the grid storage pie, Eversource is taking some and offering other slices to the third-party distributed storage companies that want to operate in the region.

Regional push

The Westmoreland project needs approval as part of a broader rate case, which could take a year to evaluate.

Assuming it gets approved and built and it works as advertised, this model could pop up in other states nearby. One big driver of that proliferation is that Eversource also operates in Massachusetts and Connecticut, and Ancel’s duties cover all three states.

“We’re thinking increasingly about resiliency and making sure we design future upgrades to be resilient to climate change,” Ancel said. “We’re picking places where we can show that the battery is at a commensurate or lower net cost than the traditional solution.”

In other words, the utility is testing the new format in places with the most favorable economics and the most pronounced needs today, in the hopes of proving out the battery resilience model for wider adoption.

That drives early installations to rural or remote locations with climate-driven reliability challenges.

Eversource is developing a 25-megawatt/38-megawatt-hour battery in Provincetown, on the tip of Cape Cod, to avoid running new wires through the scenic national seashore there. A 5-megawatt/20-megawatt-hour battery is slated for the island of Martha’s Vineyard, to retire five diesel peakers. Both should enter service by the end of 2020. The utility is also working on storage projects for Connecticut.

In Massachusetts, Eversource has regulatory approval for a voluntary, three-year bring-your-own-device program, similar to what it wants to do in Westmoreland. The goal is to reduce costly grid peaks by manipulating up to 100 megawatts of demand, via paying residential and commercial customers to use their own equipment to drop load at key times.

Participants could earn up to $1,000 per year, depending on how often their devices contribute, Ancel said. Grid edge software company Enbala will aggregate and dispatch the devices.

This is not, strictly speaking, a resilience play — it’s using distributed energy to lower peak demand, thereby saving money and lowering carbon emissions. Coupling that demand-side approach with resilient infrastructure, as Westmoreland seeks to do, could lower the costs of hardening the grid against future disruption.

What the Rise of Local Energy Means for Businesses, Institutions and Communities

How the Energy World is Changing
In the words of Pittsburgh Mayor Bill Peduto, we will enter
a time soon when we no longer make our morning toast
with energy sent from a power plant hundreds of miles
away. Peduto is describing an evolution toward a more
decentralized power grid, a shifting away from electricity
delivered via large central power plants and long transmission
The new paradigm calls for use of local resources, such as
rooftop solar, small natural gas generators and microgrids
that combine several electricity solutions. Rather than being in
another city or even state, these are resources located within
neighborhoods, businesses, college campuses, hospitals and
government complexes—near the communities they serve.
The proximity of consumption prevents loss of electricity as
it travels over wires. This translates into greater efficiency,
which in turn can lower energy costs while achieving more
sustainable power.
But the significance of this reconfiguration extends beyond
geography. It can change who’s in charge of electric power.
Once almost solely the domain of utilities, electricity now
can be generated and controlled by independent companies,
as well as those who use it. Consumers and businesses can
produce their energy and, in some cases, sell their excess
back into the market, as once only energy companies could
How did this shift come about and what does it mean for
energy-intensive organizations? Who is eligible to participate
in the local energy revolution? What are the advantages
and the challenges? Is it better to go it alone or seek expert
This report makes plain the complexities involved in
capturing DER benefits. Some of the most significant
advantages occur within wholesale energy market
transactions, a complex arena best pursued with guidance
from experts in the space. Fortunately, specific contractual
arrangements and programs now exist that allow
organizations to reap the rewards of DERs without the
“The Evolution of Distributed Energy Resources: What the
Rise of Local Energy Means for Businesses, Institutions and
Communities,” is timely, given the pace of change in energy
Written for decision-makers within businesses,
communities and institutions, this special report offers
perspective on the forces transforming the grid—
regulatory, market and technological. Low energy
prices, competitive energy markets and technological
advances present a historic opportunity for energy
consumers to take “ownership” of their power. Why do
this? Under the right circumstances, if the grid goes
down, the power would likely stay on for customers
with local energy. Moreover, use of local energy opens
opportunities to improve energy efficiency, price
management and sustainability in ways not available
with conventional power.
While energy industry insiders are well aware of
these changes, many energy consumers are not.
For those managing large energy budgets, such as
commercial operations, industrial facilities, hospitals
and universities, this can mean money left on the table.
Microgrid Knowledge produced this report, sponsored
by NRG Energy, Inc., to help these sectors understand
the suite of new energy options.
This five-chapter guide explains local energy— also
called distributed energy resources (DERs)—with a
focus on microgrids and nanogrids: What they are and
offer, how they gained importance, and how they can
be managed within wholesale markets to leverage
maximum value. Chapter 1 explains terms and dives
under the hood of microgrids—the most complex of
DERs. Chapters 2-4 then look at the evolution of DERs
from a technology, regulatory and market perspective.
And finally, Chapter 5 discusses how these forces led to
today’s market opportunity.
technology and lack of knowledge among energy users
about new possibilities. Meant to help educate businesses
and organizations, this report is available as a free download,
courtesy of NRG. We welcome you to share the link widely.
Chapter 1
DERs represent a departure from the conventional electric
grid because of their proximity to the customer and the
way they function. To grasp DERs and their significance, it’s
important to first understand the grid.
In the U.S. an interconnected, centralized grid delivers
electricity from about 7,300 power plants through 160,000
miles of high-voltage power lines and millions of low-voltage
lines to about 145 million customers.
Distributed energy sits at a different position on the grid—
not at the center but along the edges close to customers.
Common DERs are fossil fuel generators, solar, rooftop wind,
combined heat and power (CHP), fuel cells, energy storage,
microgrids and nanogrids.
Most DERs in the US are connected to the grid. They typically
run when doing so is less expensive than buying power from
the grid. DERs also provide power and services to the grid—
in return for payment—when the economics warrant.
These exchanges can occur because of advancements that
allow DERs to do more than just generate power. With the
addition of new software and controls, they have become
tools that make energy management more versatile, flexible,
reliable and cost-effective.
Among DERs, microgrids are particularly important as they
offer some of the greatest benefits, thus are increasingly an
option for decision-makers.
Microgrid: A complex form of DER
A microgrid is a complex form of DER, or rather a self-reliant
organization of several DERs. Its generation, storage and
customers are all contained within a discrete geographic
footprint, and the energy is organized by a master software
controller. (Note: Nanogrids operate in a similar fashion, but
generally serve a smaller footprint, typically one building.)
Microgrid operators set controls to accomplish goals desired
by the customer, including lowest possible energy price,
greatest system efficiency or reduced emissions.
Equally important, the microgrid serves as a form of backup
electricity. When a power outage occurs, it can “island” or
disconnect from the grid and employ its on-site generators
to ensure electricity flows to the host buildings.
Not just backup power
A mistaken notion is that a microgrid serves merely
as backup generation during a power outage. Unlike
a backup generator, a microgrid can run 365 days
a year, managing multiple internal resources. This
makes it more reliable than backup generators.
During Superstorm Sandy critical facilities, including
hospitals, discovered too late that their backup
generators did not work. Since a microgrid runs often,
malfunctions are discovered more quickly and can be
repaired before a crisis.
What’s inside a microgrid?
Microgrids can vary widely in size. A microgrid may generate
enough power for a few homes or an entire community.
Some begin small and later add more generation resources.
Hence, a microgrid can easily scale to its host’s needs.
A microgrid’s internal resources can vary tremendously as
well. Some include only renewable energy; others contain
traditional fuel generators; many are a combination.
Common resources include natural gas and diesel
generators, solar panels, wind turbines, fuel cells and even
sometimes electric vehicles. Microgrids also increasingly
include energy storage.
A microgrid’s generation mix depends on a range of factors,
including the host’s energy goals, operational parameters
and accessibility of a particular fuel. Another consideration
is the host’s need for thermal energy. Early microgrids, as
well as many newer systems, use CHP if they require large
amounts of heating or cooling. CHP uses the heat byproduct
of electricity generation to produce steam, hot water or
space heating or cooling for a practical purpose—to heat or
cool a building or serve a manufacturing process. Because it
uses one fuel source to produce two forms of energy, a CHP
system is highly efficient.
In addition to generation resources, a microgrid contains
infrastructure such as wires, cables, switches, piping and
transformers to distribute energy from source to host. Digital
sensors and actuators imbue the system with data gathering
and sharing capabilities, as well as real-time response and
management abilities.
Microgrid controllers—sometimes called the “brains of
the microgrid”—manage and optimize its working software
and DERs.
Microgrid intelligence
By coupling algorithms and instructions embedded in
software and communications systems, controllers sit
at the intelligent core of a microgrid platform.
Microgrid controllers manage the system’s generation
resources, load requirements, frequency and voltage and
connection to the central grid. These software-based
devices balance generation and load and respond to any
changing conditions. In an advanced microgrid, one master
controller provides primary management, while several
secondary controls serve specific functions.
Controllers range in function and features depending on
the project’s scale and scope, as well as the client’s budget,
needs and expectations. The simplest microgrid controller
may integrate a single, on-site source of power —a natural
gas-fueled generator, for instance—and balance its output
with internal load.
Microgrid controller capabilities can get much more complex
from there. Advanced controllers continuously monitor and
balance on-site generation with internal loads and utility grid
New, more intelligent, controllers integrate predictive
analytics software. They can identify problems and issue
instructions that prevent costly and hazardous system
failures. Some include weather forecasting so operators
are aware of available solar or wind power, or the coming
of threatening storms, which gives them an opportunity to
prepare, ensuring they have fuel supply and workers, should
a power outage require that the microgrid island. The most
sophisticated can forecast electricity and fuel pricing and
optimize resource use. Based on their pricing analytics, they
may choose to use grid power, internal resources or some
combination of both at any given time.
The following examples show where microgrid controllers
realize benefits.
Conserve energy
The central grid is under strain or an outage has occurred;
sensing a problem, the microgrid islands from the main grid
and serves host buildings with internal generators. However,
the on-site production is insufficient, so the controller
begins “shedding load”—reducing electric consumption
by switching off devices, equipment or entire buildings not
crucial. Such shedding also may occur when prices are high
as a way to save on cost.
Maximize clean energy
The controller may be programmed to maximize use of
renewable energy, when it’s available. The microgrid may
rely on solar panels during the day when sunlight is plentiful.
It may even store some energy in batteries. Then, during
evenings it will discharge the batteries. When the charge is
spent, it may then turn on its natural gas generators.
Manage price
Electricity prices vary throughout the day and night. Some
advanced microgrid controllers monitor price forecasts and
choose the combination of resources—grid or internal—that
offer the best price at any given time.
Manage price
Depending on the rules of the local grid operator, the
microgrid might also sell power and services, such as system
balancing, voltage and frequency control and spinning
reserve, back to the grid. The microgrid also may participate
in demand response—curtailing its use of grid power during
periods of high demand—in return for compensation.
What is demand response? Electricity
customers participate in demand
response by reducing their usage during
peak periods. Customers may take a
range of actions, from dimming lights to
re-scheduling work shifts to relying on
on-site generators. In return they receive
financial compensation.
In addition to intelligently managing energy, the controller
helps realize another crucial microgrid benefit, the ability to
supply highly reliable power as described next.
How does a microgrid ensure reliable power?
Placing generation near the consumer enhances electric
reliability, since there is less chance for the flow of electricity
to be disrupted by a damaged wire along the path. But this
technology goes a step further.
The microgrid’s ability to island during a power outage is
one of its hallmark features. In island mode the microgrid
essentially operates autonomously and relies on internal
generators to serve its host.
As a cost-saving measure, a host may require only critical
needs be met within its buildings; perhaps the emergency
room of a hospital or freezers in a food processing plant. The
microgrid serves the most important functions first and then
works sequentially down a list of lesser priorities.
Newer, advanced systems make the switch between grid
and island mode seamless; those inside the buildings are
unaware of this electricity shift.
When microgrids come
to the rescue
Microgrids have kept the power flowing during storms
and disasters many times in recent years. Here are a
few examples:
• Puerto Rico experienced nationwide outage
after Hurricane Maria hit on September 20, 2017.
Dozens of microgrids were quickly developed to
power certain critical facilities and remote areas.
Those microgrids proved their worth when a
contractor’s truck severed a main utility line on April
18, 2018. The island again plunged into darkness,
except for facilities and neighborhoods served by
• Californians beyond the reach of wildfires
sometimes feel repercussions from power outages
when utility equipment is destroyed. Such was the
case in Sonoma Valley, where Stone Edge Farm
Estate Vineyards and Winery operates a microgrid.
When the surrounding grid went down, the
microgrid transitioned into island mode for 10 days,
allowing the farm to continue irrigating its 16 acres.
Eventually staff were forced to evacuate, but they
continued to operate the microgrid remotely.
• When Superstorm Sandy knocked out power to 8.1
million people in 2012, several microgrids continued
to function, most notably in New York and New
Jersey, where hospitals and universities were early
adopters of the technology.
Who uses microgrids?
Given their ability to keep power flowing, it’s not surprising
microgrid development is on the rise. Their importance
grows as society becomes increasingly electricity dependent
and power outages threaten safety. Economics also are
spurring microgrid development. The cost of microgrid
components has been dropping, opening the opportunity to
more organizations.
It’s clear why these organizations would install microgrids,
considering the reliable power and sophisticated energy
management they offer. But what forces brought the energy
world to this point—and what else might customers expect
as technology advances?
We answer these questions in the next chapters.
Chapter 2
DER Technology Comes of Age:
Smart and Sophisticated
Distributed generation used to be simple. Put a generator
in a building basement, or solar panels on a roof, and the job
was done.
But today’s DERs do more than produce generation. As
microgrids demonstrate, they’ve become sophisticated
management tools for complex combinations of
energy resources and can provide a range of new price,
environmental and system efficiency benefits.
How did this growth in digital intelligence and management
capability come about?
The path to smart DERs started a couple decades ago
when demand response was a relatively new tool to curtail
peak demand on an overtaxed power system. Early on,
interruptible rates served as a key enabler for demand
response, providing incentives for customers to reduce
electricity use. In that scenario, curtailment was driven by
radio controls and pagers, relatively primitive technology by
today’s standards. As electronics and controls advanced,
demand response systems became capable of more
automated and precise two-way communications between
the grid and individual devices, or loads, on the system.
Adding innovation to demand response
Technological advances in DERs and their controls, combined
with key regulatory changes (see Chapter 4), spurred further
innovation and opened new markets in demand response.
Organizations began to realize they also could participate
in demand response programs by combining a backup
generation source with battery storage and linking them
together with advanced electronic controls. Rather than
reduce business operations or dim lighting, they could
instead curtail use of grid power with an on-site generator.
From the grid operator’s perspective, the action produces
the same result— the customer consumes less power when
the grid is overtaxed.
This approach also opened a new way to minimize utility
demand charges. Such charges can be onerous for large
energy users because they are set based on their electric
usage during a high-cost peak period. By reducing usage
at the right time, the organization could lower the charges.
Operating on-site generators during this time is one way to
do so.
Evolution of microgrids
The next step was to use more than one generation resource
and manage them for greatest economic flexibility. An early
microgrid—although it wasn’t yet called that—tended to
use a CHP plant that could operate either independently
or connected to the grid. Another variation paired the CHP
plant with a second form of generation, often a fossil fuel
backup generator.
Later, solar photovoltaics and sometimes wind turbines
began to appear in the microgrid generation mix. This trend
intensified with a decline in renewable energy costs, coupled
with the drive by organizations to achieve sustainability goals.
Energy storage became the latest addition as battery
prices fell. Batteries also proved to be effective energy
management tools, charged when electricity prices are low
and discharged when prices are high. While batteries are the
most common form of storage, a microgrid may also use
thermal storage, which can employ a range of mediums such
as ice, earth and concrete, to capture and store heating and
Navigant forecasts that the annual market for microgrids will grow
from about 3 GW in 2018 to 16 GW by 2027.
Innovation leads to growth
A market research report from Deutsche Bank predicts
that in 2018, the amount of new distributed generation
may exceed the amount of new central generation globally.
The report estimates that the current 1 GW DER market
could grow to over 40 GW by 2022, and by 2023 distributed
generation could supplant the need for 320 GW of largescale
power plants. The increase in DERs will, in turn, drive
the need for intelligent distribution networks comprised of
nanogrids, microgrids and virtual power plants, according to
the report.
The path ahead
Despite their growth, DERs and microgrids face barriers to
wider adoption. For example, a microgrid with only diesel
generators may risk exceeding legal emissions limits if it runs
too long. Financial and regulatory barriers in certain cases may
also inhibit DER adoption. Expert opinion varies on the relative
importance of those barriers.
Distributed resources plans (DRPs) can
lay the groundwork for integrating DERs
into a utility’s grid, by delineating hosting
capacity on the grid, providing locational
values for DERs and streamlining
interconnection procedures.
A white paper by consulting firm West Monroe Partners
found that:
• 61 percent of utility executives identified capital
and financial constraints as the top barrier
to DER adoption
• Only 46 percent of those executives identified regulations
as a barrier
• 61 percent of regulators identified inadequate regulations
as the top barrier
• Only 33 percent of the regulators saw capital
and financial constraints as a problem
This gap in perception highlights some of the challenges the
microgrid industry faces in prioritizing reforms that will lead
to wider DER adoption.
On the financial side, the lack of long-term offtake contracts
raises concern. Much of the wholesale electric power in the
U.S. is bought and sold on the short-term or spot market, an
arena sometimes long on volatility and short on revenue that
financiers seek.
On the regulatory front, many states lack clear policies on
DER integration with the grid. That’s starting to change.
Several states, notably California and New York, have adopted
policies aimed at DER integration. Similar policies have also
been put in place at the federal level (see Chapter 5), with
more in the works.
Formal state requirements for utility adoption of distributed
resources plans (DRPs) also assists DER development. DRPs
can lay the groundwork for integrating DERs into a utility’s
grid, by delineating hosting capacity on the grid, providing
locational values for DERs and streamlining interconnection
procedures. In a white paper, the Lawrence Berkeley National
Laboratory noted that eight states have adopted some form
of DRP requirement for their investor-owned utilities.
Microgrids and DERs have come of age, offering
sophisticated technology and services that energy users
both need and want. It is now a matter of regulation, markets
and business models catching up. As we’ll see in the next
three chapters, this is already happening.
Chapter 3
The Market Evolution of DERs
Government incentives have heavily shaped DER growth
over the last two decades, particularly for renewable energy
and energy storage. They continue to do so. But DERs are
increasingly built for other reasons as well, some readily
quantified in markets and others involving human comfort
and safety.
The advent of net metering about three decades ago
marked a pivotal point for DERs. Through net metering, a
utility pays customers for the solar energy they generate but
do not use. This tends to happen mid-day when solar power
is often plentiful, but household energy use is low. The policy
spurred rooftop solar installations as 40 states instituted the
programs. For years the residential solar market experienced
an annual growth rate of 50% or more, according to the Solar
Energy Industries Association.
But for utilities net metering meant loss of revenue that they
argued would lead to an undue burden on lower-income
ratepayers. As they saw it, those who could afford solar
panels would buy less utility electricity, leaving a smaller
number of customers—those who could not afford solar
panels—covering utility fixed costs.
Concerned about looming rate inequity, state regulators
began reforming net metering rules about three years
ago. Some states, such as Hawaii, rescinded net metering,
while Arizona began to impose fixed charges on new solar
customers. This trend continues as more states reconsider
their net metering rules.
As a result, policymakers and solar power companies began
devising new ways to value solar power and
other DERs.
Shift in business models ushers in microgrids
and DERs
The loss of net metering has proven to be a boon for energy
storage. More organizations have begun pairing storage
systems with their solar installations, in what’s known as solar
plus storage. Doing so takes some of the sting out of losing
net metering by creating a new, favorable economic model.
Solar plus storage can be used to avoid or reduce demand
charges and to arbitrage the difference in electricity prices
between times of peak and low demand.
Following this model of leveraging markets and pricing, even
more revenue opportunities are emerging for the microgrid
and other DERs.
It turns out that a microgrid has several distinct potential
revenue streams. These include price arbitrage
opportunities—leveraging internal resources against realtime
electricity prices to achieve the lowest cost mix of
energy resources at any given time. A microgrid also can sell
ancillary services to the grid. For example, it might provide
frequency regulation service by injecting or absorbing energy
to maintain the grid’s critical balance between supply and
demand. Or the microgrid might offer standby power—
known as spinning and
non-spinning reserves—that grid operators require should a
generation source fail.
In addition, microgrids are increasingly valued as grid
management tools. They can be used to smooth out the
intermittency of renewable energy resources such as wind
and solar power, quickly injecting power, for example, if cloud
cover diminishes generation from a utility solar plant.
Microgrids and other DERs also are used as non-wires
alternatives (NWAs). A good example of an NWA is New
York’s Brooklyn Queens Demand Management (BQDM)
project. Instead of spending $1 billion on a substation
upgrade, Consolidated Edison (ConEd) is seeking a mix of
microgrids, energy efficiency, demand response and energy
storage to fulfill its need.
In addition, DERs and microgrids can be used as an
alternative to building new transmission and distribution
(T&D) lines, which is what Arizona Public Service did when it
installed a battery storage system instead of rebuilding about
20 miles of T&D lines to serve the small community of Punkin
Valuing DERs
Determining DER value in the above examples is fairly
straightforward; markets set the prices. Valuing another
benefit—energy reliability and resilience—is not so simple,
yet may be the primary reason an organization installs a
What is the difference between energy
reliability and energy resilience?
Energy reliability refers to the ability to
avoid power outages. Energy resiliency
describes the ability to bounce back
quickly from an outage.
Whether it is wildfires in the West or hurricanes in the East,
recent experience has demonstrated great need for a reliable
backup to grid power.
For example, it took more than 10 days to restore electricity
to 350,000 customers after fires ravaged California’s wine
country last year. Utility customers in Florida had a similar
experience when Hurricane Irma knocked out power to 4.4
million customers. Puerto Rico’s electric grid still reels from
the effects of Hurricane Maria many months later.
These events add to the urgency for greater energy
resiliency, a need that took sharp shape in late 2012 after
Superstorm Sandy knocked out power to parts of New
Jersey and New York for two weeks. Public awareness
grew about the value of microgrids and DERs when certain
universities, hospitals and communities remained online as
others around them were in the dark.
In Lower Manhattan, New York University’s CHP plant kicked
in and kept power flowing to 22 buildings until Consolidated
Edison restored power. NYU estimated that under normal
circumstances the plant would save between $5 million and
$8 million a year in energy costs. Sandy was not normal, but it
validated the value of the plant.
The same was true in the Bronx where Co-op City, the
largest single residential development in the U.S., maintained
power from its on-site microgrid even as the surrounding
neighborhoods went dark.
It is difficult to quantify the value for these New Yorkers
of having light and heat through the storm, let alone to first
responders. However, we do have a sense of the overall
price to the economy when an electric outage occurs. For
example, a U.S. government report has estimated that
weather-related outages from 2003-2012 cost $18 to $33
billion annually.
How does an organization apply that number to its operation,
especially for an unpredictable outage that will occur at some
unknown date?
This inability to value energy reliability and resiliency creates
confusion for organizations that wonder if they are paying
too much by installing a microgrid to keep power flowing.
But the lesson seems to be taking hold even without hard
numbers, and investment is being made in energy reliability
and resiliency. GTM Research forecasts that U.S. microgrid
investment will reach $12.5 billion by 2022. And states
such as California, Connecticut, New Jersey and New York
are all ramping up investments in DERs and microgrids. In
California, for instance, the state recently awarded $51.9
million to 10 microgrid projects. New York has established
the NY Prize, a competition program to distribute $40 million
for microgrid development.
Many reasons—from energy reliability to conservation —
encourage microgrids and DERs, but frequently it becomes
a dollar-and-cents decision. Fortunately, business models
are emerging that offset a microgrid’s cost based on its
market play without placing a price on reliability. Regulatory
changes also bolster the industry, as described in the next
two chapters.
Chapter 4
The Rise of Microgrids and DERs:
Out of Competition Came Innovation
The policies behind the DER flourish go back to the passage
of the Public Utility Regulatory Policies Act (PURPA) of 1978.
PURPA was the legislative response to oil price shocks.
The law aimed to foster energy independence by creating
incentives for greater efficiency in the electric power
sector. It also provided incentives for small wind generators,
hydropower plants and CHP.
Because CHP is highly efficient and saves on fuel, PURPA’s
authors wanted to encourage its development by
independent, market-driven entities. They created a rate
mechanism known as avoided costs, and amended the
Federal Power Act with what became known as “the PURPA
put.” This guaranteed a developer that if its project met
PURPA requirements, the utility had to buy the output at the
avoided cost determined by state regulators.
The new language ensured 1) a market for electric power
and steam produced by small power plants; and 2) that those
plants would be paid a fair rate.
Proof competition works
No one at the time dreamed the idea would take off as it
did, but applications to build PURPA plants flooded utilities
in several states. Initial projects included small hydro plants,
wind farms and waste coal plants; eventually natural gas-fired
plants came under the tent.
Viewed as proof that competition could work in the electric
power sector, PURPA became a wedge in the door of the
electric utility monopoly. To widen the crack, Congress
passed the Energy Policy Act of 1992 (EPAct 92), which
created open access on transmission lines and a new class
of generators to compete with utilities to build new power
plants. EPAct 92 also instituted a production tax credit for
wind power plants.
The Federal Energy Regulatory Commission (FERC) followed
EPAct 92 with two orders to open markets even more. Order
888 in 1996 required vertically-integrated utilities to provide
universal access to their transmission systems via an open
access transmission tariff. Order 2000 in 1999 mandated the
creation of competitive wholesale markets by the formation
of regional RTOs and ISOs.
These two laws, combined with the FERC orders, in effect
deregulated the electric power industry. A century-old
monopoly business became competitive. Now two-thirds of
US electricity consumers receive power that flows through
competitive wholesale markets.
Less competition exists on the retail level. Retail choice—
the ability of customers to choose energy suppliers—
became a state-by-state decision. States in the Southeast,
and to some extent the Southwest and parts of the Midwest,
did not embrace retail choice. Those that did were in New
England, the Northeast, the Mid-Atlantic and some in the
Midwest. California embraced deregulation, but after the
2000-2001 energy crisis, walked back on some elements.
The result is a patchwork of regulated and deregulated
Laying the groundwork for DERs in
wholesale markets
Deregulation also laid the groundwork for a wide range of
new services in the power sector, such as demand response.
And by instituting retail choice—the ability of customers
to switch electricity suppliers—deregulation created a new
energy business, the competitive retail supplier. This helped
electricity customers become comfortable with buying
electricity from a company other than their traditional utility.
By offering customer choice, and freeing various players to
participate in electricity markets, these events served as
precursors to today’s microgrid and DER opportunities.
The renewable portfolio standard (RPS)
became the most effective of the statelevel
incentives. An RPS mandates that
a certain percentage of utility sales in
the state be derived from renewable
energy sources.
The competitive markets continued to grow with the
production tax credit (PTC) instituted in EPAct 92, spurring
a boom in wind power development. Later, the federal
government added a tax incentive for solar, launching its
rapid growth and eventual integration into microgrids.
The Energy Policy Act of 2005 pushed restructuring even
further, rescinding the 1930s era Public Utility Holding
Company Act, and weakening PURPA to reflect the
prevalence of competitive markets. It also mandated that
utilities institute net metering.
Soon a combination of federal and state level incentives
opened the door to a DER boom. The renewable portfolio
standard (RPS) became the most effective of the state-level
incentives. An RPS mandates that a certain percentage of
utility sales in the state be derived from renewable energy
sources. A total of 29 states plus the District of Columbia
now have RPS mandates, and eight states have non-binding
renewable energy goals.
Hawaii’s RPS is the most ambitious, requiring that the state
be powered with 100 percent renewable energy by 2045.
Several other states also have robust RPS targets. For
example, California and New York both have a 50 percent by
2030 target. Most states meet RPS targets have with wind
Policies are still being worked out,
but the net result is a power market
that offers DERs more potential
revenue sources than ever before.
FERC moved to open markets more in 2008 by issuing Order
719, which allows demand response to participate in the
wholesale competitive power markets on an equal footing
with generation. FERC followed that with Order 745, on how
demand response resources are compensated in the
wholesale power markets.
To adapt the wholesale power markets to the latest
technological changes, FERC issued Order 841 in February

  1. This directed RTOs and ISOs to remove barriers to
    participation by energy storage resources in competitive
    wholesale power markets. FERC also opened an inquiry
    into the integration of aggregated DERs in wholesale power
    Some of those policies are still being worked out, but the
    net result is a power market that offers DERs more potential
    revenue sources than ever before.
    In the early days of electric competition, supporters said it
    would lead to technology innovation and better services for
    energy customers. Today microgrids and intelligent DERs
    show the predictions were correct, particularly under new
    business models that have emerged, as discussed in the
    next chapter.
    Chapter 5
    How Customers Can Get Full Value
    from Microgrids and DERs
    A push-and-pull between government energy policy and
    technological evolution helped promote today’s microgrid
    markets. Those who understand the changes—and how to
    maximize opportunities—stand to gain the most from local
    Government pushed technological innovation via incentives
    and a gradual opening of wholesale markets. This led to
    greater production, economies of scale and falling prices.
    And that, in turn led to even wider DER penetration.
    Now technology is pulling government, as software
    capabilities, electronic controls and energy storage advance
    faster than regulation. Federal and state regulatory agencies
    are scrambling to understand and react to the trends,
    exploring questions about the value of DERs, how to give
    them a fair position in markets and what role, if any, utilities
    should play.
    At the same time government is creating new mandates
    for renewable energy, requirements that add cleaner but
    also less consistent energy resources to the grid. Solar and
    wind energy ebb when the sun is not shining, or wind is not
    blowing. So other sources of energy must balance supply
    and demand. Microgrids receive monetary compensation for
    providing this service.
    Energy companies with extensive market experience
    understand not only where these changes are leading but
    how to maximize them now for customers. For microgrid
    technology, in particular, the opportunities are substantial,
    as microgrid operators increasingly use the technology for
    energy arbitrage and sale of services into a competitive
    wholesale market.
    That changes the business equation for the microgrid
    industry. When a microgrid is used as more than backup
    power—and instead becomes a means to cut costs and
    generate income—payback can be quicker.
    Still, due to wholesale market complexity, even a flexible
    microgrid may face barriers to full use of its assets. Each
    of the RTOs and ISOs in North America have rules and
    regulations that require a level of sophistication from
    participants. A business that does not specialize in energy
    is likely to become overwhelmed if it tries to navigate these
    markets on its own.
    Fortunately, the industry is now adopting financial models
    pioneered by the energy efficiency and solar industries when
    they faced similar problems.
    Expert management and no upfront costs
    Both the energy efficiency and solar industries grew by
    offering contracts that spared customers from paying upfront
    equipment costs and assuming operational risk. Instead, they
    employed a third-party ownership model.
    For microgrids, this means a third party owns and operates
    the equipment, ensuring it serves the customer properly.
    The customer pays only for the energy and related services.
    Revenue or savings from the microgrid can help offset
    customer costs.
    The emergence of asset-backed demand
    Out of these approaches, a new and sophisticated model
    has evolved, what NRG calls asset-backed demand response
    (ABDR). A third-party ownership structure, ABDR is initially
    being built around use of onsite natural gas generators, with the
    intent of adding additional resources over time, such as energy
    storage and solar.
    NRG deploys and manages all aspects of the microgrid:
    design, construction, installation, ownership and operation.
    If the customer already has generators on-site, NRG can
    take ownership. The customer pays no upfront costs for the
    microgrid system; instead the asset is backed by NRG.
    Ideally, market revenues mean the customer pays no fee and
    benefits from a lower and more stable energy spend. Any form
    of customer fee only makes sense if the customer was going to
    buy the generators anyway.
    So with the ABDR solution, the customer receives highly reliable
    energy without making a capital outlay. The customer pays
    only a fee for service, which NRG works to offset via demand
    response, market arbitrage and other revenue streams, using
    its deep expertise in wholesale power markets and electricity
    pricing. One of the largest independent power production
    companies in the U.S., NRG owns and operates 30,000 MW of
    generation assets, and trades regularly in wholesale energy,
    capacity and markets. The company also serves 3 million
    business and residential customers on the retail level.
    The ABDR model moves beyond just microgrid operations.
    NRG focuses on the customer’s entire energy spend, looking
    for opportunities to generate revenue or achieve price stability.
  2. For example, the approach achieves cost stability for a customer not only through demand response, but also by finding ways to modify the timing and amount of grid power the customer uses, what’s known as load shaping. NRG operates the microgrid generators to configure usage into a pattern attractive to wholesale power suppliers. This positions the customer to capture better supply pricing. As part of the ABDR package, NRG also procures supply for the customer, structuring contracts based on price and the customer’s risk tolerance. In doing so, NRG acts as a complete energy management provider —not just as the microgrid owner and operator.
    “ABDR draws a range of benefits from a microgrid. Clearly, this isn’t something a customer with a microgrid can do independently. Gaining these benefits requires a partner experienced in power markets and asset operation who can apply knowledge and take on risk for the customer. This is what NRG offers,” said Robert Hanvey, vice president, strategy and business development at NRG. He added, “With this approach to microgrids, your energy system becomes more than an insurance policy; it’s a financial tool.”
    As sophisticated as ABDR may sound, it’s only the beginning. According to Hanvey, the next phase of the DER evolution has begun with the cutting-edge virtual power plant (VPP), microgrid cluster and a distributed asset control system (DACS).
  3. Next: The VPP, microgrid cluster and DACS
    What if your DER could act in concert with DERs operated by others? Could economies of scale or other advantages be achieved? The short answer is yes. This is where the VPP, microgrid cluster and DACS come into play. Advanced software intelligence can coordinate the operations of multiple DERs and sometimes multiple microgrids, even those with multiple system owners. Working together, DERs and microgrids can achieve better efficiencies and leverage market opportunities not necessarily available to them if they act alone.
    A VPP aggregates multiple DERs and orchestrates their operation via a central control system. It is a collection of intelligently controlled DERs—ranging from microgrids to home energy management devices—that together serve the grid the same way a power plant would.
  4. Consider a scenario where the grid needs one megawatt because it is under strain: Several natural gas generators, linked together contractually but sited at separate businesses, might simultaneously activate by a master controller to generate one megawatt for their hosts. This would remove one megawatt of demand on the grid—which has the same effect as adding one megawatt from a power plant. Hence, the aggregation of generators “virtually” produces power and receives financial compensation for providing the grid service.
    A microgrid cluster is a similar concept. Via sophisticated controllers, multiple microgrids communicate and exchange services to improve efficiency or price or achieve other predetermined goals. Today, microgrid clusters are being tested for neighborhoods, universities and businesses. Some futurists envision microgrid clusters becoming the primary source of U.S. electricity with the main grid acting as a backup.
  5. DACS Defined
  6. A DACS is a software management system that performs critical functions, such as facility optimization and portfolio management, to drive maximum value from resources. For example, a DACS constantly monitors and collects facility and market data to forecast facility load, market conditions and DER asset availability. Based on business rules, the assets are scheduled or dispatched in real time to optimize revenue and savings opportunities.
  7. The DACS may uncover and implement ways to better manage bills, enhance reliability, provide services to the grid for compensation or undertake other activities that benefit its host. Assets can be controlled either directly by the DACS or via third-party control systems such
    as energy management systems or microgrid control
    A DACS must be scalable to unlimited end-points and be
    able to interface with diverse and widely dispersed assets
    to create a portfolio that can be integrated with the grid.
    It also must be able to manage the portfolio to meet
    changing requirements, both from the grid and from the
    individual facilities and assets comprising the portfolio.
    DACS programs are known for their ability to analyze and
    improve system functioning. Using near real-time data,
    algorithms automate decisions to optimize assets. The
    algorithms are then layered into portfolios. Frequent
    performance reports further improve business decisions.
    Where the DER Evolution
    Brings Us Today
    After years of technological, regulatory and market
    advancements, microgrids have arrived as a natural
    outgrowth of the quest for reliable and localized power.
    These mini-power plants not only supply backup power, but
    also serve as a financial asset. In addition, local energy gives
    consumers a new, empowered status. They are no longer just
    buyers; they can be producers and market players as well.
    Such sophistication not only brings greater market benefits;
    but also demands a deeper understanding of energy markets
    and technology.
    None of this is simple, of course, but that’s where an
    expert energy partner comes into play, one with a deep
    understanding of energy technology and markets. For the
    savvy organization that forms such a partnership, new
    opportunity awaits.
    About NRG Energy, Inc.
    At NRG, we’re redefining power by putting customers
    at the center of everything we do. We create value
    by generating electricity and serving nearly 3 million
    residential and commercial customers through our
    portfolio of retail electricity brands. A Fortune 500
    company, NRG delivers customer-focused solutions
    for managing electricity, while enhancing energy
    choice and working towards a sustainable energy
    future. More information is available at
    Connect with NRG on Facebook, LinkedIn and follow
    us on Twitter @nrgenergy.
    Copyright © 2018, Energy Efficiency Markets, LLC
    NRG and the plus signs are registered service marks of NRG Energy, Inc. © 2018 NRG Energy, Inc. All rights reserved. 302040207