EXHIBIT 99.156
CONGESTION MANAGEMENT SUB-GROUP DRAFT #2
I. INTRODUCTION
II. TRANSMISSION CONGESTION MANAGEMENT ISSUES
A. FERC "AND" Pricing Principle
B. Time Periods for Congestion Management
C. Open Transmission Access and Preferred Schedules
D. Congestion Management through Zonal Pricing
E. Initial Zones and Zone Definitions, Criteria for Modifying Zones
F. Preferred Schedules
G. Incremental/Decremental Bids
H. Interzonal and Intrazonal Congestion Calculation and Charges
I. Optimal Power Flow
J. Access Charge, Congestion Management Revenues, Payments and Cost
K. Existing Contracts and Congestion Management
L. Transmission Market Power Concerns
M. Congestion Management and Ancillary Services
III. BRIEF OUTLINE OF CONGESTION MANAGEMENT STEPS
A. Day-Ahead Congestion Management
B. Between Day-Ahead and Hour-Ahead Congestion Management
C. Hour-Ahead Congestion Management
IV. THE CONGESTION MANAGEMENT PROCEDURE
A. ISO Day-Ahead Scheduling Protocols
B. ISO Congestion Management Between Day-Ahead and Hour-Ahead
C. ISO Hour-Ahead Scheduling Protocols
D. Real-time Congestion and Afterwards
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I. INTRODUCTION
The ISO congestion management procedure allows the ISO to efficiently eliminate
potential transmission problems before real-time energy consumption. In the new
industry structure, the Power Exchange (PX) and non-PX market participants will
operate independently of each other. Any trades between these parties are
voluntarily arranged at mutually agreed upon terms. The parties are not
compelled to trade with each other. Because these parties set their schedules
independently, the combination of their schedules may violate transmission
limits. The ISO will manage the transmission market
o to maximize efficient use of the transmission system
o to provide comparable prices for all
o to prevent discrimination for anyone
o to minimize the ISO's involvement in forward energy markets.
ISO congestion management will be done in two time periods, a day before and an
hour before real-time. In both time periods, the ISO will reschedule to
eliminate potential problems, but the ISO will minimize its rescheduling to
allow market participants to voluntarily seek their lowest cost of delivered
energy. The ISO will minimize its involvement in energy forward markets and it
will not be an energy broker that forces compulsory trades between any parties.
The ISO only arranges minimal trades as a last resort to maintain transmission
reliability.
The ISO will let everyone compete for transmission on a level playing field. The
ISO will provide transmission to the parties that can use it most cost
effectively. The ISO will provide accurate transmission marginal cost
information. Scheduling Coordinators have maximum flexibility and choice in
their scheduling decisions; ISO congestion management separates each Scheduling
Coordinator's portfolio of generation and load from other Scheduling
Coordinators while finding a lowest cost rescheduling to maintain reliability.
The ISO congestion management will keep the ISO out of energy markets and let
Scheduling Coordinators compete for transmission on a level playing field. It is
designed this way because market participants want the ISO to do three things:
1. Allow everyone to compete with minimal interference by the ISO.
2. Efficiently allocate transmission.
3. Maintain reliability at a lowest cost to everyone.
Figure 1 below gives a graphic overview of the Congestion Management process for
scheduling energy, not including Ancillary Services:
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FIGURE 1
[GRAPHIC OMITTED]
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II. TRANSMISSION CONGESTION MANAGEMENT ISSUES
A. FERC "AND" PRICING PRINCIPLE
FERC CONDITIONAL ACCEPTANCE AT P.79: "The Phase II filing must ensure that the
proposal to require customers to pay both an embedded cost average charge and a
congestion cost charge that reflects opportunity costs does not violate our
prohibition against 'and' pricing."
Congestion cost (the Usage Charge) is not the opportunity cost of transmission
owners. Congestion cost is the marginal cost of interzonal congested
transmission. Congestion cost is paid by all users of a congested transmission
path, including affiliates of transmission owners. Congestion cost is
independent of transmission ownership, non-discriminatory to any market
participant, and the cost is comparable for all market participants. The
revenues from congestion cost are used to reduce the annual cost of existing
transmission in two ways:
1. Congestion cost that is not rebated to a Transmission Congestion
Contract (TCC) owner is credited against the annual transmission access
charge.
2. The proceeds from sales of TCCs are credited against the annual
transmission access charge.
In either case, all market participants can pay the transmission access charge
without paying a congestion cost that is directly assigned to specific market
participants that want to use congested interzonal transmission.
A market participant only pays congestion cost when it uses a specific path that
is congested. All market participants (including transmission owners) would pay
this congestion cost when they want service on a specific congested path. This
short-run marginal cost price signal is needed to ensure that all users of a
congested path have the correct market price signal to pay either the short-run
marginal cost of congestion or the long-run incremental cost of a transmission
project to relieve the congestion.
Using an annual transmission revenue requirement that is a combination of annual
cost of existing transmission combined with redispatch cost that maximizes the
use of existing transmission is the method used in the Order 888 pro forma
tariffs. The ISO uses the annual transmission revenue requirement of
transmission owners as the basis for maximum use of existing transmission.
Therefore, the ISO's combined Access Charge and Usage Charge is a conforming
proposal under the FERC's Policy Statement on Transmission Pricing in Docket No.
RM93-19-000. It does so by crediting revenues from congestion or from TCC
auctions to the annual transmission revenue requirement. The ISO provides an
extension of the FERC's pricing policy by providing marginal cost price signals
to all interzonal transmission users (including transmission owners). All market
participants have the ability and the incentive to avoid paying short-run
marginal congestion costs by building incremental facilities that alleviate
interzonal congestion cost.
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Therefore, the FERC's "AND" pricing principle is not violated since all
similarly situated transmission users pay for congestion cost and all similarly
situated transmission users are given a short-run marginal cost price signal
that reflects the economic value of either paying short-run marginal cost or
paying the long-run incremental cost of a transmission improvement.
B. TIME PERIODS FOR CONGESTION MANAGEMENT
Congestion management is actually a continuous process that starts a year or
more in advance of real-time consumption. Transmission Congestion Contracts
(TCCs) are auctioned and resold by market participants that want to protect
themselves from the uncertainty of prices for delivered electrical energy. The
ISO will facilitate the auction of TCCs and a secondary market for TCCs. Market
participants are also free to make any other commercial arrangements that will
allow them financial certainty and potential operating certainty (the word
"potential" is used to recognize that real-time operations can involve many
situations which affect operating certainty that are beyond the control of the
ISO or market participants, e.g., weather, unforeseen outages, earthquakes,
etc.). However, the ISO must also have a process that allows the parties to
schedule their resources for reliable and efficient use of transmission as
real-time consumption approaches.
The IOU applicants' Phase 1 filing identified the day in advance and the hour
before real-time consumption as critical times to bring all Scheduling
Coordinators' preferred schedules together to assure that there is sufficient
transmission capacity to implement all schedules simultaneously. This draft
focuses on the ISO's congestion management in day-ahead and hour-ahead time
frames. The draft assumes that market participants have already taken whatever
actions they prefer in earlier time periods to get financial certainty and
potential operating certainty.
C. OPEN TRANSMISSION ACCESS AND PREFERRED SCHEDULES
The ISO will provide open, comparable and non-discriminatory access to the
transmission facilities placed under its control. When transmission is not
congested, the ISO will provide transmission access to implement all preferred
schedules as submitted by Scheduling Coordinators. Where transmission is
congested (there is insufficient transmission capacity to implement all
preferred schedules simultaneously), the ISO will use congestion management
procedures that alleviate the transmission congestion by allocating the
available transmission capacity to the most cost effective users. Congestion
management will facilitate transmission allocation to the most cost effective
users in two ways:
1. Scheduling Coordinators may voluntarily submit incremental/decremental
bids that the ISO will use to adjust their schedules so that congestion
is alleviated and transmission is allocated according to the voluntary
bids from each bidder.
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2. Scheduling Coordinators will be given an opportunity to change their
preferred schedules to alleviate congestion (day-ahead market) and to
change schedules between the day-ahead and the hour-ahead market.
The focus of this draft is the interaction between users and the ISO process to
alleviate transmission congestion. The process offers two opportunities for
Scheduling Coordinators to voluntarily achieve their preferred schedules. The
congestion management procedures and price signals will allow users and the ISO
to operate the transmission network within its constraints in a reliable and
efficient way.
The ISO will relieve congestion with a constrained least cost methodology. The
ISO will treat PX generators and non-PX generators on a comparable basis for
congestion management. The ISO will adjust preferred schedules from each
Scheduling Coordinator only if the Scheduling Coordinators do not fully
eliminate congestion voluntarily, and the ISO will adjust schedules on the basis
of price information these parties provide through their preferred schedules and
incremental/decremental bids.
D. CONGESTION MANAGEMENT THROUGH ZONAL PRICING
Most of the transmission network in the Western Systems Coordinating Council
(WSCC), including California, can be classified as two types:
o densely interconnected zones
o long distance paths that connect the zones to each other.
Various analogies have been used to describe the network; examples include "hub
and spoke system" or "lakes and canals". The densely interconnected zones (hubs,
lakes) tend to have small and infrequent transmission congestion. The long paths
(spokes, canals) between the zones tend to have frequent congestion and high
demand for their limited capacity. This high demand and limited capacity for the
paths has already led to a path rating system in the WSCC and numerous existing
rights to the capacity. This two part topography of the transmission network
leads to a two part congestion management and pricing method: zones where
congestion is infrequent and the differences in the delivery cost of electricity
are usually small, and paths where congestion is frequent and the differences in
the delivery cost of electricity are often large.
Congestion management through zonal pricing follows the topography, operation
and pricing of the transmission network. Zones where congestion is infrequent
tend to be easily priced on an average cost basis when the infrequent congestion
occurs. Since congestion within zones is infrequent and difficult to predict,
financial rights such as TCCs will be difficult to auction and to resell in a
secondary market. Congestion between zones is frequent and marginal cost pricing
promotes its efficient use. Short-Run Marginal Cost of transmission is the value
that market participants place on congested transmission. Short-Run Marginal
Cost is based on scheduling and bidding information for hourly real-time
consumption. This congestion management process will frequently use the term
"marginal cost" as a shortened form for Short-Run Marginal Cost of transmission.
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Marginal cost pricing provides the economic incentives that promote the
allocation of the limited transmission capacity to the most cost effective uses.
The higher frequency of interzonal congestion and high demand for limited
capacity assure a robust auction of TCCs between zones and a strong secondary
market for TCCs.
Since paths between zones are not always a single long transmission line or
group of transmission lines in a specific corridor, this congestion pricing
method uses the term "interzonal" to describe congestion and pricing between
zones (typically on a WSCC defined path), and uses the term "intrazonal" to
describe congestion and pricing within a zone. For the same reason, instead of
interzonal "path", this congestion pricing method will use the term "interzonal
interface" for all frequently congested transmission between zones. Interzonal
congestion pricing sets the price of using a congested interzonal interface to
the value of the interzonal interface to the marginal user. This marginal cost
is paid by all Scheduling Coordinators that want to use a congested interzonal
interface. Intrazonal congestion pricing sets the congestion pricing per unit of
energy to the average cost of relieving congestion within the zone. This price
is paid by all Scheduling Coordinators within a zone. The ISO's congestion
management procedure also defines when new zones will be created if intrazonal
congestion becomes frequent and inefficiently priced at average cost or when
zones will be combined if interzonal congestion becomes infrequent and
inefficiently priced at marginal cost..
The objective of interzonal congestion management is to promote reliability and
efficiency first since interzonal capacity is a scarce resource. The objective
of intrazonal congestion management is to promote reliability and accommodate
maximum customer choices since most customers are served in the zones, and the
zones are highly networked with mostly plentiful capacity. Since interzonal and
intrazonal congestion have different objectives, network topography, operational
impacts and price impacts, the ISO's congestion management and pricing procedure
will differ for the two types of congestion.
For interzonal congestion:
1. ISO will alleviate congestion by assigning transmission to its most
cost effective uses.
2. ISO will determine the most cost effective uses of congested
transmission with the incremental and decremental bids of the
Scheduling Coordinators that use the congested interzonal interface.
3. ISO will use marginal costs to charge Scheduling Coordinators for their
use of a congested interzonal interface (or to pay other Scheduling
Coordinators that create transmission capacity with a counterflow on a
congested interzonal interface).
4. ISO will "clear the market" (assure that supply and demand are in
balance) for transmission so that rational and consistent marginal
costs can be calculated.
5. ISO will avoid interfering in the energy forward markets by keeping
each Scheduling Coordinator's portfolio of generation and load separate
and balanced as it adjusts the schedules to alleviate congestion. While
parties can arrange voluntary trades among themselves, the ISO will not
force such trades as it alleviates interzonal congestion.
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6. In the day-ahead market which contains a trading period, interzonal
congestion cost will be minimized by selecting initial schedules or
changed schedules that produce the lowest total system congestion cost.
For intrazonal congestion:
1. ISO will alleviate congestion by rescheduling the resources within the
zone. Intrazonal congestion will be alleviated while achieving two
goals --
o disturb the Scheduling Coordinators' preferred schedules as
little as possible
o alleviating congestion at a lowest actual cost with the
incremental/decremental bids offered by the Scheduling
Coordinators.
2. ISO will accomplish these goals by determining a weighted minimum shift
rescheduling with the weights based on the incremental/decremental
bids.
3. ISO will use actual costs to charge or to pay Scheduling Coordinators
that have their preferred schedules changed to alleviate intrazonal
congestion. ISO will pay a Scheduling Coordinator for increased output
from its generators (or demand bids that are accepted). ISO will charge
a Scheduling Coordinator to replace energy from a generator whose
output was reduced and is replaced with energy by the ISO.
4. ISO will buy energy from Scheduling Coordinators and sell energy to
Scheduling Coordinators as it performs a minimum change in preferred
schedules to eliminate intrazonal congestion. Since the ISO prices
these trades on actual bids from Scheduling Coordinators rather than
marginal costs, the ISO does not have to clear the entire energy market
consisting of all parties in an integrated pool. Therefore, the ISO's
intrazonal congestion management has a minimal impact on the energy
markets.
E. INITIAL ZONES AND ZONE DEFINITIONS, CRITERIA FOR MODIFYING ZONES
FERC CONDITIONAL ACCEPTANCE AT P.80: "Additionally, in the Phase II filing, the
ISO should explain in detail, using examples, how new congestion zones will be
created. The filing should explain the benefits and problems with shortening the
time period over which the zones can be established." The initial ISO congestion
management zone definitions were defined in the IOU applicants' Phase 1 filing
(see Section 5.4.2.2.1 and Appendix F of the Joint Application for an ISO). The
Phase 1 section and appendix dealing with zone definitions remain virtually the
same. Depending on which parties decide to join the ISO, changes in zone
definitions may be needed. However, at this time, the 4 zones, 12 scheduling
points and 4 tie points remain as the defined pricing zones, i.e., zones between
which marginal cost of congestion will be calculated. These 20 pricing points
are based on operating experience prior to ISO access.
Once the ISO is operational, the ISO congestion management procedure will
provide sufficient marginal cost information so that any Scheduling Coordinator
can easily calculate the marginal cost of injecting a unit of energy in one zone
and withdrawing the energy from another zone. Such marginal cost information
will be readily available for transfers between contiguous zones and for
transfers between non-contiguous zones. The
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marginal cost information will be calculated from the Optimal Power Flow program
and will identify the marginal cost in the network for any interzonal path. An
uncongested interzonal path will have a marginal cost of zero. A congested
interzonal path will have a marginal cost that is calculated from the
incremental and decremental bids that Scheduling Coordinators provide to the
ISO.
ISO congestion management will directly calculate the marginal value of
transmission capacity between contiguous zones only. For example, the COB
scheduling point is contiguous to the PG&E-1 zone but not contiguous to the
Southern California zone. Therefore, marginal value of congested interzonal
capacity will be calculated between COB and PG&E-1, but not calculated between
COB and Southern California. A Scheduling Coordinator that submits a schedule
between COB and Southern California could contribute to congestion on several
interzonal interfaces. This Scheduling Coordinator would need to manage his
congestion impact on each interzonal interface individually, through TCCs or
other means. ISO congestion management will calculate the marginal value of
transmission capacity between each contiguous zone which can be used by a
Scheduling Coordinator to submit schedules that impact several interzonal
interfaces.
The rules for creating new zones were discussed. Some parties believe that a 12
month period to identify significant congestion followed by 90 days to make the
new zone effective is too long to wait. Other parties believe that 12 months is
not an adequate period to gather data to predict future congestion cost. It
cannot be determined the best time period for creating zones before the ISO is
in-service. It was decided that the timing issue is an ISO technical matter and
that the ISO management and board can select whatever time period is deemed
appropriate. At this time, TCCs are expected to be auctioned annually. Therefore
a 12 month period matching the one year TCCs seems appropriate as a starting
point. The numerical criterion to determine whether an area within a zone should
become a separate zone was presented in the Phase 1 filing. The cost of
congestion on an intrazonal congested path must, over the course of a year, be
equivalent to at least 5 percent of the product of the appropriate transmission
owner's access charge and the transmission capacity of the congested intrazonal
path (path rating). In equation form, this is
5% times T.O. Access Charge times Path Rating
for example: (5%) ($35.00/kW peak load) (1000 MW) = $1.75 million/year
Exceptions to the twelve month period:
1. ISO can change zones after the first 6 months of operation if the
threshold is exceeded by 10%.
2. If a planned addition of generation or load could change congestion.
3. A zone may be eliminated if a planned transmission project will
eliminate congestion.
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To erase an interzonal path, the criterion is applied in reverse. In other
words, the cost of congestion on an interzonal congested path must, over the
course of a year, be less than 5 percent of the product of the appropriate
transmission owner's access charge and the transmission capacity of the
congested interzonal path. If more than one transmission owner's access charge
is involved, then a weighted average of transmission owners' access charges
would be used with the weighting based on the percentage of each transmission
owner's entitlement.
F. PREFERRED SCHEDULES
By 12:00 p.m. Pacific time of the day before the next operating day, all
Scheduling Coordinators will start the congestion management process by
submitting to the ISO
o balanced preferred schedules for 24 hourly periods
o schedules for any self-provided Ancillary Services
o optionally, offers to supply Ancillary Services to the ISO
o optionally, incremental/decremental bids to be rescheduled by the ISO
in congestion management.
"Balanced preferred schedule" or "Balanced Schedule" means
1. Each Scheduling Coordinator's submitted generation equals expected load
and losses.
2. On its own, the schedule is electrically feasible; i.e., the Scheduling
Coordinator's Balanced Schedule produces power flows and voltages that
are within the operational limits of the power system.
3. If the Scheduling Coordinator is submitting Ancillary Services, either
as part of an energy schedule or as a stand alone Ancillary Service
bid, then the sources of Ancillary Service and the loads using the
Ancillary Services must be identified.
Scheduling Coordinators must designate and may choose any combination of three
ways to supply energy, Ancillary Services and to schedule energy for load and
losses:
o provide it from their own generation
o purchase it from another Scheduling Coordinator
o purchase it from the ISO as part of the ISO's real-time Ancillary
Services market.
Loss responsibility will be based on estimated scaled-marginal loss factors that
the ISO calculates and publishes in advance. Either generation or load can be
inside the ISO's control area, or either can be outside the ISO's control area.
Either generation or load can be energy trades with parties inside or outside
the ISO's control area.
G. INCREMENTAL/DECREMENTAL BIDS
Background
The April IOU filing refers to the use of price bids submitted by the Scheduling
Coordinators (including the PX) for the purposes of congestion management, as
follows:
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"Price bids are the incremental and decremental prices at which a
scheduling coordinator (PX or non-PX) will increase or decrease
generation or load. The ISO will define the form of these bid curves."
(ISO filing, page C-7)
These price bids are the same concept that the WEPEX Transmission Protocols Team
called "inc/dec" bids, and the same concept that the WEPEX BSB Team called
"merit order curves," in their earlier work and presentations to FERC.
In the Day-Ahead and Hour-Ahead forward markets, where the ISO Optimal Power
Flow (OPF) program uses a "Separation of Markets" concept,
incremental/decremental bids are used by each Scheduling Coordinator to provide
the ISO with information regarding the Scheduling Coordinator's implied value
for the potentially scarce interzonal interface transmission capacity. The OPF
will use this information to allocate the interzonal capacity to the Scheduling
Coordinators that value it the most. This will also determine the marginal cost
of interzonal interface capacity and the ISO's interzonal transmission prices.
The ISO can also use the incremental/decremental bids to make the energy trades
needed to eliminate the small amounts of intrazonal congestion.
The focus of this draft are the day-ahead and the hour-ahead markets. However,
incremental/decremental bids from the hour-ahead market can also be used in the
real-time market. In the real-time energy balancing market, the
incremental/decremental bids have a slightly different use. In this market, the
bids are not used for transmission rights allocation (where they would represent
the Scheduling Coordinator's implied value for congested transmission); the
incremental/decremental bids are used by the ISO to acquire imbalance energy if
a Scheduling Coordinator does not specifically remove his
incremental/decremental bid for the real-time market.
Definition of Incremental/Decremental Price Bids
Each Scheduling Coordinator may submit, in addition to a preferred operating
point for each of its resources, an incremental/decremental bid for that
resource. Submitting such a bid is entirely voluntary on the part of the
Scheduling Coordinator. The Scheduling Coordinator may submit a desired
operating point for the resource, this will be interpreted by the ISO as a
"price taking" bid from the Scheduling Coordinator. Price taking
incremental/decremental bids mean that a Scheduling Coordinator is willing to
pay any price to get access an interzonal path.
The incremental/decremental price bids are curves that define
o the minimum MW output that a Scheduling Coordinator will permit a
resource to be redispatched by the ISO
o the maximum MW output at which the which the Scheduling Coordinator
will permit the unit to be redispatched by the ISO,
Other restrictions on the data submitted by the Scheduling Coordinators:
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1. the Scheduling Coordinator's preferred operating point for the resource
must be within the range of the curve
2. the minimum MW output level specified for each resource may be zero MW
(in which case the ISO can effectively "decommit" the unit)
3. the minimum and maximum MW output levels for each resource must be
physically realizable by the resource
4. the minimum and maximum output levels for each resource must be such
that the resource will be capable of ramping from the preferred
operating point to these levels within the hour.
Incremental/decremental bids will be treated as optional offers by Scheduling
Coordinators to be rescheduled for congestion management. The incremental amount
of power and its cost does not have to be the same as the decremental amount of
power and its cost; but it is expected that the lowest incremental bid will be
greater than or equal to the highest decremental bid for the same unit.
Incremental/decremental bids cannot be changed in the day-ahead market; but new
incremental/decremental bids can be offered in the hour-ahead market. Since
there is no iteration or trading period in the hour-ahead market, new bids
offered for the hour-ahead market cannot change in the hour-ahead congestion
management. The hour-ahead incremental/decremental bids could be used in
real-time operations if a Scheduling Coordinator does not remove the bid at the
start of the real-time hour of operation. Because interzonal and intrazonal
congestion management have different goals with different calculations, a
Scheduling Coordinator must be aware of how the ISO will use the
incremental/decremental bids at different times for the two types of congestion.
In formulating its incremental and decremental bids, a Scheduling Coordinator
must take into account the ways that its bid(s) could be used by the ISO in
different time frames and in interzonal or in intrazonal congestion management.
Because incremental/decremental price bids have somewhat different meanings in
the forward markets, and because market conditions will change between the times
of the ISO's day-ahead scheduling process, the ISO's hour-ahead scheduling
process, and the ISO's real-time energy balancing market (immediately after the
hour-ahead market closes, but before the actual scheduling hour begins),
Scheduling Coordinators may change the incremental/decremental price bids curves
for each of these markets. However, the price bid data may not be changed within
the day-ahead scheduling process (i.e., between the first and second iterations
of the process).
1) Incremental/decremental bids can be submitted for the day-ahead market and
could be used two ways in the day-ahead market:
a) to alleviate interzonal congestion caused by Scheduling
Coordinators preferred schedules in the day-ahead market
b) to alleviate intrazonal congestion in a zone in the day-ahead
market
2) The same or new incremental/decremental bids can be submitted for the
hour-ahead market and could be used three ways in the hour-ahead market:
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a) to alleviate interzonal congestion in a Scheduling
Coordinator's preferred schedule during the hour-ahead market
b) to alleviate intrazonal congestion in a zone during the
hour-ahead market
c) to maintain reliability as an Ancillary Service in the
real-time Imbalance market.
3) Interzonal congestion management
For either the day-ahead market or the hour-ahead market, a Scheduling
Coordinator may bid the amount that it is willing to increase
generation from one of its resources. The Scheduling Coordinator could
also specify a cost that it would incur by increasing that generator's
output (looking at the generator in isolation). This is an incremental
bid for the resource. Incremental bids may be similarly defined for
load with a demand bid. Conversely, a Scheduling Coordinator could bid
the amount that it is willing to decrease generation from one of its
resources. The Scheduling Coordinator could also bid the savings that
it would achieve by decreasing the generator's output (again, looking
at the generator in isolation). This is a decremental bid for the
resource.
The incremental/decremental bids are used to determine the most cost
effective allocation of congested transmission and to set the marginal
cost of congested interzonal interfaces. Scheduling Coordinators will
be charged the marginal cost for congested transmission that they use.
They will also be paid the marginal cost for any counterflows on
congested interzonal interfaces. Interzonal congestion management keeps
each Scheduling Coordinator separate; therefore, Scheduling
Coordinators will not be paid for increased output in their revised
schedule in the ISO redispatch for interzonal congestion. Each
Scheduling Coordinator's generation is kept in balance with its load
and losses. The ISO is not buying energy from the Scheduling
Coordinator or selling energy to the Scheduling Coordinator. The ISO
will only charge and pay the Scheduling Coordinators according to their
interzonal transmission use and the market participants' determination
of the cost for interzonal transmission use.
4) Intrazonal congestion management
As before, a Scheduling Coordinator may bid incremental/decremental
bids. In performing minimal intrazonal congestion management, the ISO
may buy energy from a Scheduling Coordinator and sell energy to a
Scheduling Coordinator. The ISO will minimize the changes to the
preferred schedules needed to relieve intrazonal congestion with the
changes weighted with the market participants' incremental/decremental
bids.
If the ISO increases the output of a Scheduling Coordinator's resource,
the ISO buys the increased energy production. The Scheduling
Coordinator will be paid for the increase in output that the ISO
schedules to relieve intrazonal congestion. The increased output will
be priced at the incremental bid for the resource. A demand bid from
load is handled similarly. If the ISO decreases the output of a
Scheduling
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Coordinator's resource, the Scheduling Coordinator buys the energy to
replace the decrease in production from the ISO. The Scheduling
Coordinator will pay for the replacement energy at the decremental bid
for the resource.
A Scheduling Coordinator is not required to provide incremental/decremental bids
for congestion management. If the Scheduling Coordinator does not provide
incremental/decremental bids (or if the ranges specified in the bid are too
narrow), then the Scheduling Coordinator is a "price taker" with respect to
congestion. That is, the Scheduling Coordinator is willing to pay whatever
congestion cost that must be paid to be allocated transmission capacity to meet
its preferred schedule. The ISO will reschedule other Scheduling Coordinators
that provided incremental/decremental bids to keep the transmission network
within its limits.
It is possible that insufficient incremental/decremental bids will be submitted
to enable the ISO to perform its congestion management. A Scheduling Coordinator
that does not submit incremental/decremental bids for its resources will be
assigned incremental/decremental bids for those resources that would result in a
cost differential of 10 cents/kwh across the congestion. Movement outside the
ranges specified in a Scheduling Coordinator's bids will be priced similarly.
This price assignment will be needed by the congestion management algorithms to
solve and to encourage price bids by the Scheduling Coordinators. If a
Scheduling Coordinator provides an incremental/decremental bid with a price
equal to a bid by another Scheduling Coordinator, then a tie breaker rule will
be used. How the ISO alleviates congestion and determines congestion charges
will depend on the type of congestion, interzonal or intrazonal.
H. INTERZONAL AND INTRAZONAL CONGESTION CALCULATION AND CHARGES
1) Interzonal Congestion Payments The interzonal congestion procedure is
designed for the ISO to achieve several goals:
a) allocate congested transmission to the most cost effective
uses
b) minimize the ISO's interference with the forward energy
markets
c) clear the forward energy and transmission markets (assure that
supply and demand are in balance)
d) determine the marginal cost of congested transmission
Each Scheduling Coordinator will administer his own forward energy market
(including day-ahead and hour-ahead administration). The Scheduling Coordinator
will manage a portfolio of generation and loads that participate in his forward
market. His generators in the portfolio will compete to serve his loads in his
portfolio under the rules set for the ISO's transmission marketplace (congestion
management, losses, imbalances, etc.)
For example, the PX will manage a forward energy market structured as a pool
with marginal cost pricing. Other Scheduling Coordinators can develop commercial
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arrangements to compete with the PX using similar or disparate rules. Parties
engaging in bilateral trades can be viewed as participating in very limited
forward markets with prices set by contract. All of the different markets will
compete to have generators and loads participate in their individual Scheduling
Coordinator markets.
The ISO will administer a forward market for interzonal transmission in which
the various Scheduling Coordinators will compete for transmission. The ISO will
not participate in the forward energy markets when interzonal congestion occurs.
The ISO will not compel Scheduling Coordinators to trade among themselves, will
not attempt a total least cost redispatch of all schedules, and will not engage
in purchasing or selling energy. Rather, it will minimize its interference in
the Scheduling Coordinators' markets by keeping each Scheduling Coordinator's
portfolio (preferred schedule) separate from any other Scheduling Coordinator.
The ISO will accomplish this with the Scheduling Coordinators'
incremental/decremental bids to allocate congested transmission:
MINIMIZE Cost of changes to preferred schedules
SUBJECT TO
Each Scheduling Coordinator's portfolio is kept in balance
Interzonal transmission constraints
By solving this optimization problem, the ISO allocates congested transmission
to the most cost effective uses. It will simultaneously clear each forward
energy market individually as well as the forward transmission market. Since
each market clears, the ISO can determine the marginal costs that will be needed
to price congested interzonal interfaces. Schedule Coordinators will pay the
marginal cost for using congested transmission. This payment can be calculated
from the marginal value of a congested interzonal interface and a Scheduling
Coordinator's use of interzonal interfaces. The payment may also be calculated
from a Scheduling Coordinator's generation and load in each zone and his zonal
marginal cost. Scheduling Coordinators that provide counterflows to interzonal
congestion will be paid the marginal cost of the congested interzonal interface.
Such counterflow schedulers are obligated to provide counterflows or else pay
back to the ISO the cost of replacement energy at the real-time price.
For interzonal congestion management, the Scheduling Coordinators will pay the
ISO for using congested interzonal interfaces (or be paid for providing
counterflows on congested interzonal interfaces). Scheduling Coordinators will
not otherwise pay or be paid by the ISO for rescheduling the Scheduling
Coordinator's resources for interzonal congestion. The Scheduling Coordinator is
compensated for being rescheduled through reduced congestion charges or payment
for counterflows.
2) Intrazonal Congestion Payments
Scheduling Coordinators will not pay for intrazonal congestion based on marginal
cost. For intrazonal congestion, a Scheduling Coordinator will be paid the
actual cost of the
15
ISO's intrazonal congestion management actions as measured by the Scheduling
Coordinator's bids. If a Scheduling Coordinator has generation output increased,
then the ISO will pay that Scheduling Coordinator for its energy at its as-bid
price for incremental generation times the increase in output. If a Scheduling
Coordinator has generation output decreased, then that Scheduling Coordinator
will pay the ISO for replacement energy at its as-bid price for decremental
generation times the decrease in output. Any difference between the amount paid
by the ISO to the Scheduling Coordinators and the amount charged to the
Scheduling Coordinators will be collected from all Scheduling Coordinators in a
zone as part of the Grid Operations Charge. This part of the Grid Operations
Charge will be allocated among the Scheduling Coordinators based on their zonal
load and net zonal export.
Intrazonal congestion charges will be based on the actual cost of rescheduling
to relieve intrazonal congestion for several reasons.
o Intrazonal congestion will usually be small and infrequent; if the
congestion is not small and infrequent, then a new zone will be
created. The ability to create new zones when intrazonal congestion
reaches a limit means that any pricing inefficiency caused by as-bid
actual pricing and by not paying for counterflow schedules will be
small and self-correcting (through new zone creation and marginal cost
between the new zones).
o The intrazonal congestion management algorithm may compel Scheduling
Coordinators to engage in energy trades with other Scheduling
Coordinators in a zone. Because of the localized nature of intrazonal
congestion, the Scheduling Coordinators may not have sufficiently
diverse portfolios that would permit the ISO to keep each Scheduling
Coordinator's portfolio in balance as it reschedules to alleviate
intrazonal congestion. Although small and infrequent, these forced
trades are needed to maintain reliability. However, to minimize the
impact on the Scheduling Coordinator's individual forward energy
markets, the ISO will perform intrazonal congestion management with an
algorithm that offers a minimum change in schedules needed to alleviate
intrazonal congestion. It will not compel the Scheduling Coordinators
to make all of the trades among themselves that would be needed to
clear the combined and totally integrated forward energy market.
Consequently, accurate marginal costs will not be available from the
intrazonal congestion.
The intrazonal congestion management algorithm will determine a minimum
cost-weighted shift (change) in preferred schedules to relieve intrazonal
congestion. The ISO will weight the changes to the schedules using the available
bid and schedule information so that the most effective changes to the schedules
will be made. Scheduling Coordinators within a zone that has intrazonal
congestion will pay the net cost to relieve the intrazonal congestion based on
their loads in the zone and exports from the zone.
I. OPTIMAL POWER FLOW
Optimal Power Flow (OPF) is a computer program that can determine a minimum cost
resource schedule, marginal costs and energy movement in a transmission network.
The
16
IOU applicants tested three OPF programs with an independent consultant. The OPF
testing determined that the available OPF technology is accurate enough to price
megawatt power flows consistently. An OPF program that was available can be run
with two different objective functions:
o minimize total cost
o minimize changes in energy schedules.
An OPF program can be efficiently run using a full transmission network model.
The transmission model used in the OPF will depend on the requirements. An OPF
program can be run
o to optimize megawatt and megavar controls (Full AC OPF)
o to optimize megawatt controls while satisfying reactive power
constraints (Active Power AC OPF)
o to optimize megawatt controls and satisfy real power constraints only
(DC OPF)
The study determined that available OPF technology can calculate real power
marginal costs and enforce real and reactive power constraints. However, some
modifications will be needed to any OPF method that is chosen if the program is
to meet the necessary goals. The IOU applicants' Phase 1 filing requires an OPF
model
o to minimize the cost of alleviating congestion
o not to do a total rescheduling of all scheduled generation so that
voluntary trades can take place (allowing the marketplace to determine
least cost rescheduling)
o to reschedule only as far as needed to relieve congestion while
observing network constraints
o to provide marginal costs for interzonal congestion
o to provide actual costs for intrazonal congestion
It was determined that these goals can be met with some modifications to an
existing OPF model. The modifications include
1. adding constraints that separate each Scheduling Coordinator while
performing interzonal congestion management
2. adding constraints that prohibit Scheduling Coordinator portfolio
optimization within zones
3. running the OPF to minimize cost for interzonal congestion while not
arranging trades between Scheduling Coordinators
4. running the OPF to minimize cost-weighted shift (change) in preferred
schedules for intrazonal congestion.
In selecting the OPF models to be used for interzonal and intrazonal congestion,
it was also recognized that the type of constraints that will be treated in each
congestion management will be different:
o In interzonal congestion management, the main constraints will be
thermal or stability constraints that are modeled as limits on
interzonal interface megawatt flows.
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o In intrazonal congestion management, the OPF will mostly enforce
equipment operating constraints that are modeled as megavoltamp (MVA)
flows or ampere flow limits.
Therefore, it is recommended that the ISO pursue an OPF model to manage and
price congestion. For interzonal congestion management, a DC OPF is recommended.
For intrazonal congestion management, an Active Power AC OPF is preferred, while
a DC OPF should be an adequate fallback method if an Active Power OPF cannot be
properly modified and tested in time for ISO startup operation.
J. ACCESS CHARGE, CONGESTION MANAGEMENT REVENUES, PAYMENTS AND COST
1) ACCESS CHARGE: The Access Charge is the cost to use transmission capacity
with existing transmission facilities. In FERC Order 888, the Annual
Transmission Costs are the total cost of the transmission system. The total cost
of the transmission system included the embedded cost of transmission facilities
plus any redispatch cost that was not specifically charged to a transmission
user. The total cost of the transmission system is averaged across all users of
either Point-to-Point Service or Network Integration Service. ISO transmission
pricing represents a new paradigm that does not distinguish between
Point-to-Point Service and Network Integration Service. ISO transmission pricing
uses a "network model" which recognizes that energy transmitted with
Point-to-Point Service never did follow a designated contract path and that
Network Integration Service could have allowed energy purchases AND SALES to
produce the lowest cost to serve a group of customers across many paths. If a
transmission owner did not file for a separate Opportunity Cost charge in its
Open Access Tariff, then redispatch cost was rolled into the total annual cost
of the transmission system and paid on an average basis by all transmission
users.
The ISO Access Charge will not have a component for Opportunity Cost. Scheduling
Coordinators pay for intrazonal congestion through the Grid Operations Charge
(see below) by having the actual cost of intrazonal congestion averaged across
all load in a zone. This conforms with Order 888 and is not AND pricing. Order
888 pro forma tariffs allow transmission owners to average the Opportunity Cost
across all transmission users and pay for these costs as part of the annual
transmission cost.
Customers also pay for interzonal congestion (the Usage Charge, see below); an
iteration in the day-ahead market uses a voluntary trading period to allow
Scheduling Coordinators the opportunity to self-manage interzonal congestion.
The Scheduling Coordinator uses a portfolio of generation and purchases from
multiple areas to serve load in multiple ISO zones. As a Scheduling Coordinator,
the PX will average the cost of the Usage Charge across all PX customers. This
conforms with Order 888 and is not AND pricing
An important question that affects the analysis of the Usage Charge is "who
receives the benefits (payments) from a Usage Charge?" Neither transmission
owners nor the ISO receives benefit from any Usage Charge. All Usage Charges are
paid to TCC holders or
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to transmission owners who must use the usage charges to decrease their
transmission Access Charge. The benefits from Usage Charges flow to TCC holders
or to all transmission users on an average load basis.
FERC CONDITIONAL ACCEPTANCE AT P.81: "The Phase II filing should explain exactly
how congestion revenues will be rebated and to whom. In addition, the Phase II
filing should address the merits of alternative mechanisms for rebating
congestion revenues, especially with reference to the incentives they create for
encouraging or discouraging efficient expansions."
Two alternatives are offered for rebating Usage Charges:
a) Usage charges can be rebated to TCC holders that have paid for TCCs to
protect themselves from differences in energy prices between zones.
Scheduling Coordinators decide for themselves what is best for their
customers; to purchase TCCs, use uncongested paths, or find other
resources. This alternative provides market-based incentives for
Scheduling Coordinators to purchase TCCs, use other resources, or build
transmission. Neither the transmission owner nor the ISO benefits from
the Scheduling Coordinators' decisions. Since the Usage Charge is
customer choice based on marginal costs, it provides vital locational
market clearing price signals for energy purchases, energy sales and
ultimately long-run costs such as new generation, new transmission or
location of new load.
b) To all payers of an Access Charge, any interzonal congestion revenue
that is not paid to TCC holders will be used to decrease the Access
Charge, i.e., all Access Charge payers will receive an average benefit
from non-TCC Usage Charges. This alternative provides an average cost
incentive to create efficient expansions. Although this alternative is
not as economically efficient as #1, the lack of TCC holders for this
interzonal congestion revenue is an indication that this particular
interzonal congestion is too infrequent or too small for market
participants to build new transmission.
2) USAGE CHARGE: Interzonal congestion management will produce revenues for the
ISO when Scheduling Coordinators value the congested transmission highly enough
to load the transmission to its limit. Interzonal congestion management will be
priced at marginal cost and will be applied on the exact same basis to all
Scheduling Coordinators that are contributing to potential congestion in the
day-ahead or the hour-ahead markets. These interzonal congestion revenues will
be collected from all Scheduling Coordinators that were charged for congestion
through the day-ahead or the hour-ahead congestion management. The charges for
interzonal congestion will be billed to the Scheduling Coordinators as their
Usage Charge for transmission congestion.
3) DISBURSEMENT OF USAGE CHARGE: The sum of all Usage Charges on an interzonal
interface (the interzonal congestion revenues) will be allocated to TCC holders
as congestion management payments. TCC holders receive these payments regardless
as to whether or not the TCC holders had an actual schedule when the congestion
occurred. Sufficient TCCs may not have been sold to allocate the entire Usage
Charge on an
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interzonal interface. In this case, all transmission users within a transmission
owner's network will receive the congestion management payments. These Usage
Charges represent TCCs held by a transmission owner for the benefit of all users
within the transmission owner's network. These congestion management revenues go
to defray the cost of the transmission owner's Access Charge.
4) GRID OPERATIONS CHARGE: The ISO will incur costs to alleviate the intrazonal
congestion. The ISO will use the OPF to determine the combination of generation
and load changes that will result in a minimum change to the schedule while
using the most cost effective controls to alleviate the intrazonal congestion.
5) DISBURSEMENT OF GRID OPERATIONS CHARGE: Payments will be made to Scheduling
Coordinators with incremental bids that were accepted to alleviate the
intrazonal congestion while charges will be made to Scheduling Coordinators with
decremental bids that were accepted to alleviate intrazonal congestion. The
payments minus charges for intrazonal congestion management will be summed up
across a zone. The resulting sum for a zone and for a given period of time
(e.g., a month) will be billed as the Grid Operations Charge and collected as
revenue from all customers in the zone. All customers in a zone will pay for
their zone's intrazonal congestion through their zone's Grid Operations Charge.
The Grid Operations Charge also includes the cost of ISO operation and any other
uplift charges that customers must pay.
K. EXISTING CONTRACTS AND CONGESTION MANAGEMENT
FERC CONDITIONAL ACCEPTANCE AT P.58: "The Phase II filing must address how the
ISO will provide the existing contractual obligations under its operation ...
Finally, the Phase II filing must specifically address how existing firm
entitlements will be automatically scheduled into and through the PX and ISO in
constrained situations and what priority these transactions will have vis a vis
other PX and ISO schedules."
Existing contracts can be placed in two categories: entities that join the ISO
and entities that do not join the ISO.
1. For entities that join the ISO, they would take firm service under the
protocols described in the Phase II filing. These entities would make
their existing entitlements available to the ISO. In return, the
entities' customers would receive TCCs in proportion to the amount of
megawatts and level of firmness of their contractual entitlements.
Entities with existing entitlements that join the ISO will be scheduled
in all situations in the same way as any other ISO entity.
2. For entities that choose not to join the ISO, and that hold firm
contractual entitlements on a transmission path, the ISO will reduce
the transfer capability available to ISO participants on that path by
the contracted amount during the periods when the entities are
scheduling their capacity pursuant to their contractual provisions.
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L. TRANSMISSION MARKET POWER CONCERNS
FERC CONDITIONAL ACCEPTANCE AT P.60: "Therefore, SoCal Edison and PG&E must
demonstrate that their individual tariffs in conjunction with the ISO tariff
will not allow the exercise of transmission market power."
In response to the Market Power Filings of the three IOU's, the FERC stated that
the ISO will be responsible for proposing monitoring programs for the ISO's
portion of this filing. The ISO portion includes transmission access to all
non-radial transmission facilities owned or controlled by the IOU's. Therefore,
it is not necessary for the SoCal Edison or PG&E to address specific network
transmission market power issues in this filing; the FERC and the ISO will be
responsible for monitoring network transmission market power.
Radial transmission and distribution facilities are made available through
separate Wholesale Distribution Tariffs that will be filed concurrently with the
ISO filing. These tariffs provide unbundled, non-discriminatory and comparable
access to wholesale entities. The FERC will have the opportunity to directly
judge the mitigation of transmission and distribution market power in these
tariffs. It is expected that ISO and FERC monitoring of network transmission
access and IOU wholesale distribution tariffs that are accepted by the FERC will
demonstrate that the conjunction of the ISO tariff and the IOU's wholesale
distribution tariffs will not allow the exercise of any wholesale transmission
or distribution market power.
M. CONGESTION MANAGEMENT AND ANCILLARY SERVICES
FERC CONDITIONAL ACCEPTANCE AT P.44-45: "Specifically, ... the Phase II filing
should address the feasibility of and operating guidelines for self-providing
the requisite ancillary services. ...[T]he Phase II filing should clearly
explain how such services will be accounted for and verified, and should explain
the extent to which the ISO will have control of the generator providing the
service. ... [T]he Phase II filing should define and analyze each separate
ancillary service market with respect to the potential market power of each
Company, and all ancillary services not proposed to be subject to market-based
should be identified and a cost-based rate proposed in Phase II." Also
FERC CONDITIONAL ACCEPTANCE AT P.47: "[W]e will require the Phase II filing to
explain whether and how the proposal will achieve [efficient dispatch in light
of a separate auction for ancillary services, to be conducted by the ISO]."
The control and price of individual Ancillary Services and their cost-basis is
not part of Congestion Management. When there is no congestion in the ISO, there
are no barriers to Ancillary Services markets since the ISO operates the control
area in real-time and ensures real-time reliability. However, the Congestion
Management process must allow Ancillary Services to compete for congested
transmission when it occurs. The Congestion Management process does this by
sending the same marginal cost price signal for congested transmission to all
markets: the Energy market, the Ancillary Service market, and any other
transmission service that requires capacity on congested transmission under ISO
transmission pricing.
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The ISO Congestion Management process is expected to evaluate all bids for
access over a constrained path using an Optimal Power Flow (OPF) Computer model.
The OPF model can be modified for Ancillary Services using the same
incremental/decremental bid principles to evaluate each transaction on a
transmission path. Using this process, use of congested transmission paths would
be awarded to Scheduling Coordinators that bid the highest implied value for a
path through their incremental/decremental bids. There should be no problems
with discrimination or comparability regardless as to whether transactions are
for the delivery of energy, AGC/Regulation, Spinning Reserve, Non-Spinning
Reserve, or Replacement Reserve.
In the ISO, each Ancillary Service is a single market run by the ISO. The ISO
sets system and zonal requirements for each Ancillary Service and spreads the
requirements over buses. A Scheduling Coordinator has two options to meet its
share of Ancillary Services:
o purchase each Ancillary Service through the ISO's market
o supply each Ancillary Service "in-kind" to the ISO's market (using
either its own Ancillary Service or an Ancillary Service purchased from
another Scheduling Coordinator)
Ancillary Service requirements are allocated to each Scheduling Coordinator in
proportion to the Scheduling Coordinator's demand. A Scheduling Coordinator may
need transmission capacity so that the ISO may use the Scheduling Coordinator's
self-provided Ancillary Service in another zone across a congested interzonal
interface. Scheduling Coordinators can compete for transmission capacity needed
to use the Scheduling Coordinator's self-provided Ancillary Service in another
zone; but there is no guarantee that the Scheduling Coordinator's self-provided
Ancillary Service will be used in another zone unless it is price competitive
with Ancillary Services in the zone where the service is needed. The ISO has a
single market for Ancillary Services; there is no separation of Scheduling
Coordinators' schedules in the Ancillary Service market. The single ISO
Ancillary Service market requires the ISO to obtain the lowest cost Ancillary
Service delivered at the location that it is needed. This lowest cost includes
the cost of the Ancillary Service plus any cost to deliver the Ancillary Service
where it is needed.
The ISO may compete with Scheduling Coordinators for transmission capacity when
it is obtaining Ancillary Services at the lowest cost for any Ancillary Service
that is not self-provided and delivered at the lowest cost. The ISO will pay the
congestion charges for transmission capacity that it reserves for use in its
Ancillary Services markets. The ISO's Interzonal cost for Ancillary Services is
the same interzonal marginal cost as the Energy market and the same interzonal
marginal cost that all Scheduling Coordinators are given. This is comparable,
non-discriminatory transmission cost for all markets and for all market
participants.
To schedule an Ancillary Service in the day-ahead or hour-ahead markets, a
Scheduling Coordinator must give the following information:
1. The location(s) that will supply Ancillary Services, the amount
available, and the cost of the Ancillary Service(s) at the location(s).
22
2. The location(s) where a Scheduling Coordinator wants to use
self-provided Ancillary Service(s), the amount that will be
self-provided at the location(s), and the estimated cost that the
Scheduling Coordinator is willing to buy any shortfall from the ISO if
the Scheduling Coordinator does not get transmission to the
location(s).
ISO also competes for transmission capacity for its Ancillary Service markets
based on the bids the ISO receives from suppliers of Ancillary Services. ISO
wants to minimize the cost of Ancillary Services purchased to meet the control
area and zonal requirements after removing projected Scheduling Coordinators'
self-provisions. ISO specifies the same supply information as Scheduling
Coordinators -- the location(s) that will supply Ancillary Services, the amount
available, and the cost of the Ancillary Service(s) supplies at the location(s).
Since the ISO is responsible for any unsupplied Ancillary Services, it does not
have to specify locations to use Ancillary Service.
Ancillary Service schedules cannot be used for energy counterflows. The ISO
cannot schedule energy transactions that take advantage of Ancillary Service
"counterflows". However, schedules of Ancillary Service can offset Ancillary
Service flow in the opposite direction.
The OPF model can be modified to find least-cost generation and Ancillary
Service schedules by simultaneously considering two cases.
1. With Ancillary Services not active in the power flow, the OPF
calculates Scheduling Coordinators' schedules that satisfy energy
demands, flow limits and market separation.
2. With Ancillary Service requirements included in the power flow ("full
schedules" with Ancillary Services "turned on", i.e., treated as energy
demands), the OPF treats the Scheduling Coordinators' Ancillary
Services as energy schedules. The "full schedules" must satisfy total
new energy demands, flow limits and market separation.
By simultaneously considering these two cases in the OPF, the same marginal
costs are calculated for all power flows (energy, spinning reserve, etc.).
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III. BRIEF OUTLINE OF CONGESTION MANAGEMENT STEPS
A. DAY-AHEAD CONGESTION MANAGEMENT
Congestion management in the day-ahead market will be an iterative process that
allows users to voluntarily change their preferred schedules in the middle of
the day-ahead market time period. Voluntary changes will allow users to avoid
paying for interzonal congestion or to pay the marginal cost of interzonal
congestion if they place high enough value on the interzonal transmission
capacity. Briefly, the day-ahead iterative process will use the following steps.
1. The ISO publishes information regarding system conditions so that
Scheduling Coordinators (SCs) can factor the information into their
daily planning.
2. SCs submit their preferred schedules of balanced generation, load,
losses, Ancillary Services, and incremental/decremental bids to relieve
congestion.
3. The ISO receives the preferred schedules and checks for any interzonal
congestion between zones or tie points using a Congestion Assessment
computer program. If there is no interzonal congestion, then the ISO
proceeds to Step 7. If there is interzonal congestion, the ISO develops
advisory schedules that alleviate the congestion by using an Optimal
Power Flow (OPF) computer program. The OPF also determines the marginal
cost of using congested transmission between contiguous zones or
between zones and adjacent tie points. The OPF will be formulated to
minimize the cost of relieving congestion while maintaining separation
between the resource portfolios of different SCs. In other words, the
OPF will not arrange any trades between Scheduling Coordinators while
it is alleviating interzonal congestion and minimizing the cost of
congestion. In Step #3, the OPF action is limited to alleviating only
interzonal congestion, i.e., intrazonal congestion does not impact
interzonal congestion and the OPF reschedules only to alleviate the
interzonal congestion. The OPF is run as a linear model that treats
real power flows and controls only (losses and reactive power are
calculated separately). This assures that
o losses are treated consistently with other ISO loss
calculation procedures
o the congestion charges will be calculated using the difference
of the Scheduling Coordinators' zonal marginal prices across
interzonal interfaces
o the congestion revenues will be calculated using the marginal
value of capacity on interzonal interfaces.
4. The ISO notifies SCs of the ISO's "advisory dispatch". The advisory
dispatch is the impact of each preferred schedule that includes energy
scheduled between zones or tie points. The advisory dispatch allows
each SC to identify if he may have to pay the marginal cost of
congestion between contiguous zones or between zones and adjacent tie
points.
5. After the advisory dispatch is published, an SC has one hour to submit
changed schedules (make trades or make any other transactions that will
alleviate his potential contribution to the congestion). Within the one
hour trading period the SC can submit changes to his preferred energy
schedule or keep his original schedule. In other
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words, an SC can adjust its energy schedule, but it cannot change his
incremental/decremental bids.
6. At the end of one hour, the ISO takes the new energy schedules (changed
schedules and original schedules that were not changed) and runs the
OPF again using the same method described in Step #3. If the new
schedules do not result in interzonal congestion, then the new
schedules are accepted for scheduling in real-time operations. If the
new schedules do result in interzonal congestion, then the ISO compares
the total system congestion cost from the preferred schedules with the
total system cost congestion cost from the new schedules that include
some changes. The ISO accepts the lower cost set of schedules
(preferred schedules or changed schedules), and adjusts the schedules
as in Step #3. The congestion charge for each SC is calculated using
the marginal costs produced.
7. The ISO alleviates any intrazonal congestion. The ISO runs the OPF
using a method that minimizes the weighted change from the schedules at
the end of Step #6 within each zone. The weights are based on the
incremental/decremental bids so that the most cost effective resources
within the zone are used.
8. Intrazonal congestion management is done after interzonal congestion
management. There is a small probability that intrazonal congestion
could cause some changes in interzonal power flows. In general, this
will not alter interzonal congestion charges. In particular, a
Scheduling Coordinator supplying intrazonal replacement energy for
another Scheduling Coordinator in the same zone is not responsible for
any of the interzonal congestion charges owed by the other Scheduling
Coordinator that had his resources reduced.
9. There is a small chance that there may be insufficient resources within
a zone to relieve intrazonal congestion and resources in other zones
must be rescheduled. This is the one instance when intrazonal
congestion could alter interzonal congestion charges. In this case, the
OPF will model the interzonal impact of the intrazonal congestion as an
interzonal constraint. The ISO will add this constraint to the
interface to identify resources in another zone that can relieve the
intrazonal congestion and at the same time allows for feasible
intrazonal congestion. Rescheduling these new resources from outside
the congested zone can affect the interzonal congestion charge.
10. The ISO then notifies the SCs of their accepted day-ahead schedules
that include their preferred schedules modified to alleviate all
congestion. This ends the day-ahead congestion management.
B. BETWEEN DAY-AHEAD AND HOUR-AHEAD CONGESTION MANAGEMENT
Between the end of day-ahead congestion management and the start of hour-ahead
congestion management is a time period that allows SCs to revise their
schedules, recognizing that they will bear the economic consequences caused by
deviations from their day-ahead schedules. This time period begins with the end
of day-ahead congestion management, and it ends one hour before the start of the
hour in which real-time consumption will take place. The economic consequences
will be priced with marginal cost for any interzonal congestion created, and
priced with actual average cost per unit of energy for any intrazonal
congestion. This is similar to day-ahead congestion pricing,
25
except day-ahead schedules that became actual schedules for real-time scheduling
are not repriced (thrown in the bucket) with the new schedules. The accepted
day-ahead schedules pay the congestion price from the day-ahead congestion
management.
C. HOUR-AHEAD CONGESTION MANAGEMENT
Congestion management in the hour-ahead market is similar to the day-ahead
market except there is no opportunity for SCs to change their preferred
schedules. Hour-ahead congestion management is a two-step process: interzonal
congestion management followed by intrazonal congestion management. Briefly, the
hour-ahead process uses the following steps.
1. The ISO has already notified SCs of their accepted day-ahead schedules
and any congestion prices from the day-ahead congestion management. The
ISO will also notify SCs of any changes in transmission system
conditions.
2. SCs submit any new preferred schedules of balanced generation, load,
losses, Ancillary Services, and new incremental/decremental bids to
relieve congestion. In the hour-ahead process, the ISO will only accept
new schedules which can be accommodated through scheduling adjustments
using resources that have submitted price bids for redispatch.
3. The ISO receives the new preferred schedules, and then runs them
through the OPF. The OPF is run as a linear model treating real power
resources and flows only, i.e., losses and reactive power are
calculated separately. The OPF determines if interzonal congestion
could result from the new preferred schedules between zones or tie
points. The OPF also determines the new marginal cost of any congested
transmission between contiguous zones or between zones and adjacent tie
points. The OPF is run using a method that minimizes the cost of
relieving congestion while maintaining separation between resource
portfolios of different Schedule Coordinators. In other words, the OPF
does not force any trades between Schedule Coordinators while it is
alleviating congestion and minimizing the cost of congestion. In Step
#3, the OPF action is limited to alleviating only interzonal
congestion, i.e., intrazonal congestion does not impact interzonal
congestion alleviation and the OPF reschedules only to alleviate the
congestion.
4. The ISO alleviates any intrazonal congestion. The ISO runs the OPF
using a method that minimizes the weighted change from the schedules at
the end of Step #3 within each zone. The weights are developed from the
incremental/decremental bids so that cost effectiveness of the
resources is taken into account. The OPF is also restricted to using
the resources within the zone to alleviate intrazonal congestion.
5. Intrazonal congestion management is done after interzonal congestion
management. This means there is a small probability that intrazonal
congestion could cause some changes in interzonal power flows.
Intrazonal congestion management does not alter interzonal congestion
charges except when there are insufficient resources within a zone to
relieve intrazonal congestion. For the small chance that each zone's
resources cannot relieve the intrazonal congestion, the OPF adds a
constraint method that limits flow on interzonal interfaces to identify
resources in another zone that can relieve the
26
intrazonal congestion. Adjusting these resources from outside the
congested zone can affect the interzonal congestion charge. An SC
supplying intrazonal replacement power for another SC in the same zone
is not responsible for any additional interzonal congestion.
6. If there is any remaining congestion of any type (interzonal or
intrazonal), the ISO may rerun the OPF using a method that minimizes
the weighted change from the schedules in Step #5 within the entire
ISO. The weights are developed from the incremental/decremental bids so
that cost effectiveness of the resources is taken into account. The ISO
then notifies the SCs of their actual hour-ahead schedules that
includes their new preferred schedules modified to alleviate all
congestion. This ends the hour-ahead congestion management before the
start of the hour for real-time consumption. Any congestion that occurs
during real-time is treated as an Energy Imbalance and is priced with
the Ancillary Services used to alleviate Energy Imbalances.
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IV. THE CONGESTION MANAGEMENT PROCEDURE
The ISO will manage congestion in a way that creates the greatest opportunity
for the market to resolve any problems that may arise. It will do this by
providing the necessary operating information and system status to all
Scheduling Coordinators that enables them to optimize their own generation and
load requirements. They will have an opportunity to minimize their operating
costs through voluntary schedule revisions that avoid contributing to congestion
or help to alleviate potential congestion. Only when the market response is
inadequate will the ISO adjust schedules to relieve congestion. If the market
response is inadequate, the ISO will reschedule using efficient, comparable
prices based on bid information provided by market participants. The ISO will
relieve congestion at a least cost within network and market constraints. The
ISO will treat PX generators and non-PX generators on a comparable,
non-discriminatory basis for congestion management. As a last resort, the ISO
will maintain the reliability of the transmission network with comparable
protocols when price bids and megawatt schedules are not adequate to maintain
reliability.
The ISO will create an electronic bulletin board similar to FERC's Order 889
that will allow all scheduling transactions to be done electronically through
the bulletin board. As a backup, telephone, fax and paper transactions may be
accepted at the ISO's discretion; but the primary means of communication with
the ISO will be through the electronic bulletin board. This includes power flow
data on such as generator, transmission line and transformer status, expected
changes in status, and any other information that to the reliability of the
transmission network.
A. ISO DAY-AHEAD SCHEDULING PROTOCOLS
1) By 6:00 p.m. two days prior to the next operating day, the ISO will publish
projected system conditions for the next seven operating days. The information
will include:
a) Potentially congested transmission paths
b) Projected transmission use
c) Projected hourly unscheduled flow (loop flow) over ISO
interzonal interfaces and interconnections
d) Scheduled line outages for each hour of the next operating day
e) Potential over-generation conditions based on previous day and
current day system conditions for each hour of the next
operating day
f) ISO's advisory hourly forecast of expected total load
g) ISO's hourly reserve and regulation Ancillary Service
requirements to maintain grid reliability
h) ISO's hourly reliability must-run generation
i) ISO's generation meter multipliers
2) By 6:00 a.m. Pacific Time of the day prior to the operating day, all parties
that want to schedule through the ISO's grid will submit a forecast of hourly
loads for which they will
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schedule generation resource deliveries for the next seven operating days,
including the location. The ISO will aggregate all the non-PX loads by Utility
Distribution Company (UDC)-specific location and provide by 6:30 a.m. these
aggregate loads to each UDC. Additionally, each SC may provide the ISO with
preliminary information regarding any of its self-provided Ancillary Services.
The SC will submit to the ISO a list of any generator resources by location that
are self-providing and an advisory forecast of any expected purchases for its
pro rata share of Ancillary Services from the ISO's Ancillary Service market for
each hour of the operating day. Each UDC will submit to the ISO schedules of the
hourly deliveries of regulatory must-take and hydro spill resources.
3) Beginning at 7:00 a.m., the PX will submit to the ISO its preferred schedule
for serving the PX's bid-in demand, including its identified portfolio of
Ancillary Services generators. This preferred schedule will be balanced with
respect to generation, associated estimated transmission losses, and load. The
PX will submit incremental/decremental bids for generators and any demand bids
in its preferred schedule for congestion management. The PX will also submit to
the ISO all of its unused Ancillary Services bids. These incremental/decremental
bids and unused Ancillary Services bids to the ISO will become binding and may
not be changed during the day-ahead scheduling process. This will be complete by
12:00 p.m.
4) Beginning at 7:00 a.m., simultaneously with the PX, non-PX Scheduling
Coordinators will submit their preferred schedules to the ISO. These preferred
schedules will be balanced with respect to generation, associated estimated
transmission losses, and load. Non-PX preferred schedules may also include
self-provision of all or a portion of their pro-rata control area Ancillary
Services obligations. Non-PX Scheduling Coordinators may also submit
incremental/decremental bids for the generators and any demand bids in their
preferred schedules to the ISO for congestion management. A Non-PX Scheduling
Coordinator that does not submit incremental/decremental bids for its resources
will be assigned incremental/decremental bids for those resources that would
result in a cost differential of 10 cents/kwh across any congested interzonal
interface. Movement outside the ranges specified in a Non-PX Scheduling
Coordinator's bids will be priced similarly. If a Scheduling Coordinator
provides an incremental/decremental bid with a price equal to a bid by another
Scheduling Coordinator, then a tie breaker rule will be used. These price bids
to the ISO will become binding and may not be changed during the day-ahead
scheduling process. This will be complete by 12:00 p.m.
5) Beginning at 7:00 a.m., other Scheduling Coordinators may also bid additional
generation directly into the ISO's Ancillary Services market. These price bids
to the ISO will become binding and may not be changed during the day-ahead
scheduling process. This will be complete by 12:00 p.m.
6) By 10:00 a.m., the PX and other SCs (if applicable) will determine if
over-generation conditions may exist, and it will provide the ISO with a
compilation of what constitutes the over-generation condition in each hour,
including the projected load, and the generation differentiated into categories:
regulatory must-take, hydro spill and reliability
29
must-run. The ISO will then use the categories to implement the over-generation
protocols described in the "ISO Scheduling Applications Implementation."
7) If over-generation conditions may exist, then by 11:00 a.m. the ISO will
identify the need, the total amount of over-generation mitigation necessary, and
direct all Scheduling Coordinators to reduce their schedules pursuant to the
over-generation protocols described in the "ISO Scheduling Applications
Conceptual Design."
8) By 12:00 p.m., the ISO will combine the preferred schedules from all
Scheduling Coordinators and determine if sufficient Ancillary Services have been
self-provided to meet the control area requirements, or if an Ancillary Services
auction is required. If additional Ancillary Services are required, then the ISO
will evaluate the bids it received in Steps #4, #5, and #6 and select the least
costly mix of additional Ancillary Services to satisfy the ISO control area's
Ancillary Services requirements.
9) Beginning at 12:00 p.m., the ISO will evaluate the combined schedules, any
over-generation protocols, and Ancillary Services requirements for potential
interzonal congestion. The ISO will have received the preferred schedules and
bids by 12:00 p.m., and then the ISO will run the preferred schedules and bids
through the Optimal Power Flow (OPF) computer program. The OPF will be run as a
linear model that treats real powers and controls only (losses and reactive
power will be calculated separately). This assures that all OPF calculations and
resulting marginal costs are consistently calculated on a linear basis. The OPF
determines if interzonal transmission congestion could result between zones or
tie points. The OPF also determines the marginal cost of any congested
transmission between contiguous zones or between zones and adjacent tie points.
The OPF will be run using a method that minimizes the cost of relieving
congestion while maintaining separate preferred schedules over the entire
network. In other words, the OPF does not arrange trades between Scheduling
Coordinators while it is alleviating congestion and minimizing the cost of
congestion. In Step #10, the OPF action is limited to alleviating only
interzonal congestion, i.e., intrazonal congestion does not impact interzonal
congestion alleviation and the OPF reschedules only to alleviate the interzonal
congestion.
10) By 2:00 p.m., if there is no congestion, then the ISO will inform suppliers
selected in the ISO auction to provide Ancillary Services. The ISO will notify
all Scheduling Coordinators that their preferred day-ahead schedules for both
energy and Ancillary Services have been accepted as Committed Schedules. If
there is congestion, then the ISO will notify each Scheduling Coordinator of an
"advisory redispatch" that will be used to relieve congestion if the Scheduling
Coordinators do not alleviate congestion through schedule changes. The ISO will
also notify each Scheduling Coordinator of his interzonal prices that are
associated with the advisory redispatch. This allows generators to determine any
dispatch changes that could relieve potential congestion at a least cost. The
result is congestion prices that would be paid by all users of the congested
interzonal interface if the advisory redispatch is accepted. The advisory
redispatch will allow each Scheduling Coordinator to identify if he may have to
pay the marginal cost of congestion
30
between contiguous zones or between zones and adjacent tie points. As part of
this process, the ISO will also re-evaluate its Ancillary Services to assure
that a least cost feasible supply is arranged.
The ISO will provide the following information to each Scheduling Coordinator:
a) the committed schedules (no congestion) or the advisory
redispatch (congestion is present)
b) the associated transmission congestion cost that could be
charged to all power flow across interzonal interfaces
including the interzonal prices that are associated with his
preferred dispatch
c) the prices of each Ancillary Service
d) the relative effectiveness of generation shifts in alleviating
potential congestion.
In developing the advisory redispatch, the ISO may only adjust the scheduled
output of generation, based on the price bids, and then only as required to
relieve congestion. In so doing, the ISO will not perform "unit commitment", but
rather will use the merit order provided by Scheduling Coordinators through
their price bid information. The ISO will only make scheduling adjustments that
act to relieve congestion, and will cease making adjustments when congestion is
relieved.
11) If there is congestion after the advisory redispatch is published, a
Scheduling Coordinator has one hour to make trades that will alleviate his
potential contribution to the congestion or make any non-ISO transactions that
he believes will be profitable. These changes may include revisions to their
unit commitments, scheduled generation output, and load consumption; however,
Scheduling Coordinators may not change any components of their price bids. By
3:00 p.m., the Scheduling Coordinator can submit changes to his hourly megawatt
preferred schedule or keep his original schedule.
At 3:00 p.m., the ISO will take the new schedules (changed energy schedules and
original schedules that were not changed) and will run the OPF again using the
same method described in Steps #7, #8, #9 and #10. If the new schedules do
result in interzonal congestion, then the ISO compares the total system
congestion cost from the preferred schedules with the total system cost
congestion cost from the new schedules that include some changes. The ISO
accepts the lower cost set of schedules (preferred schedules or changed
schedules), and adjusts the schedules as in Steps #7, #8, #9 and #10. If a
Scheduling Coordinator's preferred schedule contributes to interzonal
congestion, then the Scheduling Coordinator will be notified that he will have
to pay the marginal cost of congestion between contiguous zones or between zones
and adjacent tie points. The ISO then will use the incremental/decremental bids
and other protocols to alleviate any remaining interzonal congestion.
12) The ISO will alleviate any intrazonal congestion. The ISO will run the OPF
using a method that minimizes the weighted change from the schedules in Step #12
within each zone. The weights are developed from the incremental/decremental
bids so that cost-effectiveness of the resources is taken into account.
31
13) Intrazonal congestion management is done after interzonal congestion
management. There is a small probability that intrazonal congestion could cause
some changes in interzonal power flows. In general, this will not alter
interzonal congestion charges. In particular, a Scheduling Coordinator supplying
intrazonal replacement energy for another Scheduling Coordinator in the same
zone is not responsible for any of the interzonal congestion charges owed by the
other Scheduling Coordinator that had his resources reduced.
14) There is a small chance that there may be insufficient resources within a
zone to relieve intrazonal congestion and resources in other zones must be
scheduled. This is the one instance when intrazonal congestion could alter
interzonal congestion charges. In this case, the OPF will model the interzonal
impact of the intrazonal congestion as an interzonal constraint. The ISO will
add this constraint to the zonal interface to calculate a solution that relieves
interzonal congestion and at the same time allows for feasible intrazonal
congestion management. Rescheduling these new resources from outside the
congested zone can affect the interzonal congestion charge.
15) By 5:00 p.m., the ISO notifies the Scheduling Coordinators of their accepted
day-ahead schedules that include their preferred schedules modified to alleviate
all congestion. The final accepted Ancillary Services schedules will be the
basis for the day-ahead prices for Ancillary Services in the ISO's Ancillary
Services market. A day-ahead financial commitment will be established at this
point and the ISO will notify all SCs of their commitment, including
o final Committed Schedules
o final Ancillary Service responsibilities
o the day-ahead congestion prices to be paid for all energy scheduled
across congested interzonal interfaces in the day-ahead market
o the Grid Usage charge in any zone that may have intrazonal congestion.
This ends the day-ahead congestion management.
B. ISO CONGESTION MANAGEMENT BETWEEN DAY-AHEAD AND HOUR-AHEAD
16) Between the end of day-ahead congestion management and the start of
hour-ahead congestion management (one hour before real-time consumption) is a
time period that allows Scheduling Coordinators to revise their schedules and
submit them to the ISO, recognizing that they will bear the economic
consequences caused by deviations from their day-ahead schedules. Hour-ahead
schedules are new schedules, all schedule values must be submitted. Scheduling
Coordinators submit any new preferred schedules of balanced generation, load,
losses, Ancillary Services, and new incremental/decremental bids to relieve
congestion. This time period begins with the end of day-ahead congestion
management, and it ends one hour before the start of the hour in which real-time
operation will take place. The economic consequences will be priced with
hour-ahead marginal cost for any interzonal congestion created, and priced with
hour-ahead actual average cost per
32
unit of energy for any intrazonal congestion created. This is similar to
day-ahead congestion pricing, except day-ahead schedules that became actual
schedules for real-time scheduling are not repriced (thrown in the bucket) with
the new hour-ahead schedules. The accepted day-ahead schedules pay the
congestion price from the day-ahead congestion management.
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C. ISO HOUR-AHEAD SCHEDULING PROTOCOLS
Hour-ahead scheduling protocols begin at the end of the day-ahead process and
end at the operating hour. One hour prior to the beginning of the operating
hour, the ISO will evaluate all new preferred schedules for potential
transmission congestion and adequacy of self-provided Ancillary Services.
Congestion management in the hour-ahead market is similar to the day-ahead
market except there is no opportunity for Scheduling Coordinators to change
their preferred schedules. Hour-ahead congestion management is a two-step
process: interzonal congestion management followed by intrazonal congestion
management.
17) The ISO has already notified Scheduling Coordinators of their accepted
day-ahead schedules and any congestion prices from the day-ahead congestion
management. The ISO will also notify Scheduling Coordinators of any changes in
transmission system conditions. Scheduling Coordinators submit any new preferred
schedules of balanced generation, load, losses, Ancillary Services, and new
incremental/decremental bids to relieve congestion. Hour-ahead schedules can be
submitted at any time between the end of the day-ahead process up to one hour
before the hour of actual operation.
18) Beginning one hour before the hour of actual consumption, the ISO will take
the new hour-ahead preferred schedules, and then the ISO will run the OPF to
determine interzonal congestion. The OPF will be run as a linear model that
treats real powers and controls only (losses and reactive power will be
calculated separately). This assures that all OPF calculations and resulting
marginal costs are consistently calculated on a linear basis. The OPF determines
if interzonal transmission congestion could result between zones or tie points.
The OPF also determines the marginal cost of any congested transmission between
contiguous zones or between zones and adjacent tie points. The OPF will be run
using a method that minimizes the cost of relieving congestion while maintaining
separate preferred schedules over the entire network. In other words, the OPF
will not arrange any trades between Scheduling Coordinators while it is
alleviating congestion and minimizing the cost of congestion. In Step #19, the
OPF action is limited to alleviating only interzonal congestion, i.e.,
intrazonal congestion does not impact interzonal congestion alleviation and the
OPF reschedules only to alleviate the interzonal congestion.
19) The ISO will alleviate any intrazonal congestion. The ISO will run the OPF
using a method that minimizes the weighted change from the schedules in Step #21
within each zone. The weights are developed from the incremental/decremental
bids so that cost-effectiveness of the resources is taken into account.
20) Intrazonal congestion management is done after interzonal congestion
management. There is a small probability that intrazonal congestion could cause
some changes in interzonal power flows. In general, this will not alter
interzonal congestion charges. In particular, a Scheduling Coordinator supplying
intrazonal replacement energy for another Scheduling Coordinator in the same
zone is not responsible for any of the interzonal
34
congestion charges owed by the other Scheduling Coordinator that had his
resources reduced.
21) There is a small chance that there may be insufficient resources within a
zone to relieve intrazonal congestion and resources in other zones must be
scheduled. This is the one instance when intrazonal congestion could alter
interzonal congestion charges. In this case, the OPF will model the interzonal
impact of the intrazonal congestion as an interzonal constraint. The ISO will
add this constraint to the zonal interface to calculate a solution that relieves
interzonal congestion and at the same time allows feasible intrazonal congestion
management. Rescheduling these new resources from outside the congested zone can
affect the interzonal congestion charge.
22) If there is any remaining congestion of any type (interzonal or intrazonal),
the ISO will rerun the OPF using a method that minimizes the weighted change
from the schedules for the entire ISO that will be used in Step #22. The weights
are developed from the incremental/decremental bids so that cost-effectiveness
of the resources is taken into account.
23) Before the beginning of the hour of actual operation, the ISO notifies the
Scheduling Coordinators of their accepted hour-ahead schedules that include
their preferred schedules modified to alleviate all congestion. The resulting
prices for use of congested interzonal interfaces will be used as the basis for
hour-ahead congestion settlements. The unused incremental and decremental bids
will be used as supplementary energy bids by the ISO in the real-time imbalance
energy management, unless a Scheduling coordinator specifies that his
incremental/decremental bid cannot be used for real-time operation. This ends
the hour-ahead congestion management.
D. REAL-TIME CONGESTION AND AFTERWARDS
For real-time operation, the ISO will rely on Imbalance service (a combination
of several Ancillary Services) to manage real-time congestion. This real-time
congestion management is described in the Ancillary Services section. Following
real-time operations, the ISO will perform a settlement for each Scheduling
Coordinator to reconcile Energy Imbalances, Ancillary Services, and Transmission
Congestion Costs.
35