IEEE Power & Energy Magazine - July/August 2020 - 27

reserve requirement based on the NERC reliability standard
✔ Use a downward-sloping tail to value reserves greater
than the minimum reserve requirement at step 1, using
the LOLP, and address some pricing issues created by
a nearly vertical demand curve.
These changes, if approved by FERC, will result in more
appropriately valued reserves in the system, especially during stressed-system conditions, and provide better incentives
for resource flexibility to reliably and efficiently accommodate an ever-evolving resource mix.

Managing Natural Gas Uncertainty
For the past decade, system operators have recognized the
need to improve coordination between the electric and natural gas industries. This coordination has become even more
important during recent years as new natural gas combinedcycle units, wind turbines, and solar installations have
become the primary new and replacement generation units
throughout the system. Each energy source has introduced
unique challenges to grid operations, but the natural gas
units have presented issues on a larger scale. As the number
of natural gas units in the system increases, network resilience is increasingly at the mercy of uncertain just-in-time
fuel delivery. Gas units constitute the largest percentage of
the total installed capacity: more than 74,000 MW. They
account for 80% of the new capacity resources in the PJM
service area. Gas uncertainty, therefore, directly affects system reliability and resilience.
As referred to previously, the 2014 polar vortex was a
learning experience from a variety of angles. During that
time, a significant number of natural gas units was unavailable due to the inability to procure or deliver fuel. In
response, the day-ahead market timing was changed in 2016
to better harmonize the timing of the gas and electric operating day (Figure 6). This change provides more opportunity
for price discovery in the natural gas markets before generation offers are due in the electricity markets. In December
2018, the deadline for market participants to submit bids
and offers in the day-ahead market was extended from 10:30
a.m. to 11 a.m., better aligning day-ahead market deadlines
with the most active natural gas trading period of the day.
In late 2017, intraday offers were implemented so that units
could submit hourly bids to the day-ahead market and make
changes during the operating day to better include natural
gas costs and reflect fuel availability. At the same time,
gas pipeline contingencies were incorporated into system
operations. The gas pipeline contingencies are triggered by
certain system conditions, such as a cold/hot weather alert,
capacity emergency, pipeline operational flow orders, and
pipeline outages.

Integrating DERs, Storage, and DR
New technologies, such as DERs, microgrids, storage, and
DR, can help make the grid more resilient.
july/august 2020

DERs
DERs are connected at the distribution level and able to
directly serve the retail load during a grid outage. Due to
their resiliency attributes and economic value, more and more
DERs are coming online, which makes effectively integrating them into operations and markets very important. In the
current market, DERs can reduce load as behind-the-meter
generation (~7,000 MW, about half of which comes from solar
photovoltaics) or a resource that injects power when there is an
appropriate interconnection agreement (~1,000 MW). When
participating as DR, DERs are subject to existing DR rules;
when injecting power into the system, DERs are modeled
as generators and subject to existing generation rules. When
DERs are behind-the-meter generation, they do not participate
in the markets or provide data, but they do influence system
conditions. Additional barriers for DER integration are being
worked on with transmission owners to increase the visibility of nonwholesale DERs, improve forecasting, and enable
wholesale market participation and easy switching between
load and generation.

Storage
Storage has a very high reliability and resilience value to
the grid, due to its siting flexibility, quick build, geographic
distribution across the system, very high plant uptime, and
low risk of fuel supply disruption. Storage resources are
connected to transmission and distribution or sit behind the
meter. Storage technologies in the system currently include
pumped-storage hydroelectric plants, batteries, flywheels,
electric vehicles, and residential/commercial thermal storage, such as water heaters and other technologies. PJM is
the first of the U.S. ISOs/RTOs to demonstrate the ability of battery energy storage resources (ESRs) to provide
frequency regulation services in a competitive market.
Since 2009, the system has integrated roughly 300 MW of
advanced energy storage resources. Due to its unique ability to charge and discharge, storage can participate in the
markets as supply or load. Table 1 shows the different types
of storage resources currently participating in the wholesale
markets by type and amount. Batteries and flywheels today
participate exclusively in the regulation market, providing
fast regulation service.
Although ESRs were eligible to provide services in all its
markets, to be compliant with FERC Order 841, PJM created
an ESR participation model in December 2019 to fully recognize the physical and operational characteristics of storage
resources and further remove any barriers to their participation. This model ensures that ESRs are eligible to provide all
services for which they are technically capable, in a manner
consistent with other resources providing the same functions:
serving the load or ensuring grid reliability.
With the newly implemented model, an ESR could participate in our day-ahead and real-time energy markets
under three different modes to best manage charging and
discharging cycles:
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IEEE Power & Energy Magazine - July/August 2020

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