IEEE Power & Energy Magazine - November/December 2017 - 81

Offer Price US$/MWh

ISOs usually do not model the distribution grid. The general
assumption has historically been that power always goes
from the transmission grid down into the distribution grid.
A growing number of distributed energy resources (DERs),
both renewable and otherwise, are changing that assumption.
DERs can include backup fossil fuel generators (e.g., natural gas or diesel reciprocating engines) that operate in parallel,
rooftop photovoltaic (PV) solar arrays, storage (e.g., batteries), fuel cells, demand response, or combinations of these
resources. Typically, there is little or no formal interaction
between ISOs and DSOs.
ISOs are finding it necessary to prepare for scenarios in
which increased DERs will impact ISO functions, including
electricity markets. ERCOT's proposed approach is not to
model the distribution system but rather to logically map DERs
to the electrically closest load in the transmission model. In
this way, the critical online tool-the ISO state estimator-is
not impacted. The state estimator can still accurately estimate
the state of the transmission grid, as the interface between the
transmission and distribution grids is unchanged. However,
the tools that manage load distribution factors and contingency
analysis will require modifications to capture the reliability
impacts of significant DER penetration.
The concept of mapping DERs to the electrically closest
load (Figure 10) in the transmission model is considered less
challenging than expanding the ISO network model into the
distribution system. This would require developing expansive and potentially expensive new processes. The ISO also
anticipates a need to plan for modifications to load forecasting, potentially including development of a DER forecasting
tool to capture rooftop PV production.
With respect to market operations, ERCOT has proposed
settling DERs at the transmission bus nodal price. Their participation in the markets could range from passive to active.
Figure 11 shows a typical metering arrangement of a DER
colocated with load but with a separate meter to measure
generation from the DER.
CAISO has made similar initiatives in the ways that DER
aggregators bid in its markets, allowing them to aggregate
across nodes as long as they are located within the same subload aggregation point. Discussions among researchers and
those involved tangentially in the New York Reforming the
Energy Vision have even included incorporating distinct marginal prices at the distribution location, similar to the wholesale market (i.e., D-LMPs or LMP+D).

Supply Curve Shifted
Below with Injection
of Emergency Supply
That Appears "Free"

november/december 2017

Price Enhancements
to Stack Emergency
Supply on Top of the
Supply Curve

Demand
Quantity MW
Q Emergency-Tier I Q Emergency-Tier II
Source: MISO

figure 9. The pricing of emergency energy and demand
response at MISO.

ISO
Modeled Transmission Grid

Transmission/
Distribution
Interface Modeled
as Load

Distribution Grid
(Not in ISO Model)
DER
Source: ERCOT

figure 10. A typical ISO network model with DER
mapped to the electrically closest load.

Electrical Bus A
ERCOT CIM Load A

ERCOT Transmission
Network Model
Electrical Bus B
ERCOT CIM Load B

Service
Delivery Point
Distribution Meter 1
Network

Market Redesign and Formation
While many market regions are making modifications to
the existing market, a number of markets are going through
more large-scale redesigns. The Independent Electricity System Operator in Ontario, Canada, is going through a market
renewal, adding a number of design features similar to their
U.S. ISO neighbors. The Alberta (Canada) Electric System
Operator has recently announced that it is changing from an
energy-only market to one with a capacity market. In 2016,

S ′′
S′

Meter 2
Native STR
Load

DER

Source: ERCOT

figure 11. A typical metering arrangement required to
provide nodal LMP to registered DER. CIM: common information model.
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Table of Contents for the Digital Edition of IEEE Power & Energy Magazine - November/December 2017