Transcript Basic Elements of the SMD - Illinois Institute of Technology

The FERC SMD and the Midwest
Electricity Markets
IEEE PES – Chicago Chapter
Chicago, IL - January 8, 2003
Roberto F. Paliza, Ph.D.
Paliza Consulting, LLC.
[email protected]
1
Agenda

FERC SMD




Inter-ITP coordination
Midwest Markets Initiative


Focus is in the RTM, DAM, and FTRs
What is missing in the SMD?
MISO-SPP
MISO-PJM-SPP joint and common
market
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2
FERC SMD




Sets the direction for the design and
implementation of wholesale markets.
Defines the desired end state for these
markets.
Does not provide solution for transitional
issues although establishes principles to be
followed.
Provides flexibility in regards to timing of the
implementation and in accommodating
regional differences.
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3
Basic Elements of the SMD
From an operational perspective:
 Real-time market
 Day-ahead market
 Ancillary services market
 Congestion revenue rights market
 Market power monitoring & mitigation
 Capacity requirement
 Markets administered by RTOs/ITPs
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ITP Market Operations
Market Inputs
Generator Bids
Load Bids
Bilateral
Schedules
Self Schedules
ITP
Functions
Market Support
Cover
Imbalances
Ensure Reliability
Bid based
SecurityConstrained
Dispatch
Calculate
Nodal
Prices
RTO Market Settlements
At Nodal Prices
Real-Time
Balancing
Buy and Sell
In Spot Market
Congestion
Redispatch
Buy Through
Congestion
Transmission
Rights
$$$
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Hedge
Congestion
Market-Driven
Decisions
5
The Real-time Market (RTM)




RTOs will ensure that all market participants
have equal access to the spot market.
RTM main component is a bid-based security
constrained dispatch (5 min cycle).
RTM is a voluntary market.
Market participants can submit:



Bilateral schedules,
Self-schedule, or
Bid into the real-time market
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Example1: Economic Dispatch
Least expensive generators are dispatched
MW
$10
300MWs @ $10
I need MWs.
Sale goes to the
lowest bidder with capacity.
Going once....
Load
499 MWs
Capacity
300 MWs
MW
199 MWs @ $15
$15
Capacity
200 MWs
MW
$20
Capacity
200 MWs
RTO
Not Dispatched
$15
LMP for all settlement nodes
is $15
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Example2: Economic Dispatch
Highest Cost Generator Sets Price
MW
$10
300 MWs @ $10
Capacity
I need MWs.
Sale goes to the
lowest bidder with capacity.
Going once....
Load
599 MWs
300 MWs
MW
$15
200 MWs @ $15
Capacity
200 MWs
RTO
MW
$20
Capacity
200 MWs
99 MWs @ $20
$20
LMP for all settlement nodes
is $20
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8
If There is Congestion




Delivery limitations prevent use of “next
least-cost generator”
Higher cost generator closer to load must be
used to meet demand
Cost to operate more expensive generation
are translated into transmission congestion
costs in LMP calculation
Nodal pricing results in cost causation for
congestion pricing to market participants
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Real-time Market Settlements




All real-time injections, withdrawals and
transmission congestion will be settled at LMP
prices determined by the real-time dispatch.
The difference in LMP prices across the grid
will reflect congestion and incremental cost
of losses.
Loads have the choice to settle at nodal or
zonal prices.
Generators may self-schedule but only
accepted schedules will settle at LMP prices.
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LMP Definition
Cost of supplying next MW of load at a specific location,
considering generation marginal cost of energy, cost of
transmission congestion, and losses
LMP
=
Marginal
Energy
Component
(EC)
+
Marginal
Congestion
Component
(MCC)
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+
Marginal
Loss
Component
(MLC)
11
The Day-ahead Market (DAM)




DAM main component is a bid-based security
constrained unit commitment.
It is a voluntary market and is financially
binding.
DAM main function is to provide certainty for
Market Participants (MPs).
In the DAM, participants will be able to:



Buy/sell energy and self-schedule generation.
Submit bilateral transactions.
Submit virtual bids.
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12
Day-ahead Market Settlements



Process is very similar to RTM
settlement for energy, congestion, and
losses.
RTM settles deviations with respect to
DAM schedules.
FTRs are settled based on the DAM
hourly prices.
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13
Payments for Energy and Losses
Payments for Energy
by Consumers
Payments for
Energy
Settlements Energy and Losses
Generators
Day-Ahead
Residual
Account
Bid
Production
Cost
Guarantee
Pa
ym
e
nts
fo
r
Lo
ss
es
Losses Residual
Congestion Charges
Payments for Congestion
and Losses by
Transmission Customers
(Bilaterals)
Congestion Charges
Financial
Rights
Settlements
Residual
Loads
Responsible
for Reliability
Commitment
Costs
Real-Time
Residual
Account
Financial
Rights
Holders
Congestion
Management
Account
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14
Day-ahead Reliability Check


Check is performed after DAM closes and it
focuses on:

Evaluating overall resource adequacy.

Evaluating reserve adequacy.

Evaluating transmission reliability.
Reliability Commitment: Units are
committed/de-committed to satisfy reliability
criteria.
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15
Financial Transmission Rights
FTR is a financial
instrument that entitles
holder to a stream of
revenues (or charges)
based on the DA hourly
energy price differences
across the path or shadow
price of a flowgate.
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16
FTR Characteristics

MPs will be able to acquire point-to-point
(PTP) and flowgate (FGR) transmission rights
to hedge congestion charges.




PTPs and FGRs will be financial.
PTP is a full hedge between source and sink while
FGR is a full hedge for a specific constraint only.
PTPs will be available in the form of obligations
and options and FGRs will be available as options.
Awarded PTPs and FGRs will be simultaneously
feasible.
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Example: Delivery with FTR
FTR = 100 MW
Bus
A
Energy Delivery = 100
MWh
Source
(Sending End)
Bus
B
Sink
(Receiving End)
LMP $15
LMP $20
Congestion Charge = 100 MWh * ($20-$15) = $500
FTR Credit = 100 MW * ($20-$15) = $500
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18
PTP Rights Characteristics



Obligations can have a zero, positive, or
negative value.
Options can only have a zero or positive
value.
It is a perfect hedge against congestion costs
as long as:

Schedule is between specified source and sink.

Schedule is equal or less than the FTR amount.
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19
FGR Rights Characteristics




FGR owner gets paid the constraint
shadow price of that flowgate.
FGRs are proposed as options and only hedge
the specified flowgate.
Available as PTDF (monitored element) and
OTDF (monitored/contingency pair) flowgates.
Place responsibility for assessment of shift
factors and the number of FGRs required to
hedge a transaction on the market participant.
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20
Priorities and FTRs




SMD proposes when transmission is
tight, participants with FTRs have
scheduling priority.
How about curtailment priorities?
Current LMP markets do not have this
physical characteristic.
Many comments have been submitted
on this subject.
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21
Acquiring FTRs

Allocation



FTR Auction -- administered by the ITP




Is based on existing contracts.
Is a conversion process from physical to financial.
MPs can purchase “left over” capability.
It may be used as the primary way to assign FTRs.
MPs can reconfigure FTRs.
Secondary market -- bilateral trading


ITPs will facilitate the secondary market.
FTRs that exist are bought or sold.
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22
What Is Missing in the SMD?
From an operations perspective:
 SMD embraces the goal of seamless
markets but no approach is suggested.
 FERC has taken a significant step
forward in developing the SMD but the
next step – coordination of these
markets - is also a very important one.
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23
Inter-ITP Coordination

Types of ITP coordination under SMD:




LMP market and non-market coordination
LMP market and other LMP markets
Reliability backstop process
One stop shopping desired features:



Common business practices
Common user interface
Availability of CRRs that expand several ITPs
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24
Transitional Issues

SMD calls for conversion of all transmission
service to SMD. However, if grandfather
contracts do not convert to the SMD tariff,
another level of complexity will be created


Will require that ITPs support physical service in
all of their markets (RTM, DAM, FTR).
Certain special provisions of these grandfather
contracts may be difficult to honor/administer by
the ITP under LMP.
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25
Transitional Issues

Initial allocation of CRRs



May prove to be very contentious specially
in places where the system is oversold.
Availability of FTR options will add another
layer of complexity.
Modeling of FTRs in the allocation process
needs to be consistent with settlements of
these rights.
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26
Inter-ITP Coordination Elements


Honor external constraints in the same way
as internal constraints are respected.
Treatment of resources in a multi-market
environment



Parallel flow agreement that includes:



Bidding, control, scheduling, settlement…
Ancillary services
Definition and calculation of parallel flow
Agreement on usage and compensation
Convergence of LMP prices at the seams.
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27
Reliability Backstop Process

NERC TLR is the reliability backstop process
in the eastern interconnection




Relies on a central database of “tagged”
transactions
Relies on a single transmission model for impact
calculation and curtailments
Input data and results are available to all SCs
Equivalent capability needs to be provided
under SMD

May require policy changes by NERC
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28
One-stop Shopping

Market participants do business over large
geographical areas


Requires compatible market rules



Establishment of a single network access service
will enable development of large markets
Timings, scheduling practices, market protocols
and procedures, settlements……
Development of a single user interface is a
must.
Support for CRRs across several ITP regions.
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29
The Obvious Fix

Creation of a single market run by a
single market operator


Is this feasible over a very large area?



Single RTM, DAM, and FTR markets
Eastern Interconnection
MISO-PJM-SPP
What is the criteria for determining the
appropriate size of a single market?
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30
Managing Seams

Type of seams:



Manageable.
Unmanageable (e.g. unable to control
internal constraints).
A couple of factors to consider to
manage seams:


Proper grouping of constraints & resources.
Internalize as much loop flow as possible.
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31
The Midwest Markets




Dec 2003 is the target date for MISO-SPP
market operation.
It is a staged project.
Functionality to be provided in the first stage
is based on RTM, DAM with no SCUC, FTR
market, and Market Power Mitigation.
Full SCUC and Ancillary Services market will
be added in future stages.
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32
MISO Markets Initial Functionality
FUNCTIONAL AREAS
FTRs
(A financial contract that entitles holder to a stream of revenues –
or charges - based on the hourly energy price differences across
the path)
• Request processing
• Simultaneous feasibility testing
• Approval processing
Day Ahead Market
(Based on scheduled hourly quantities and day-ahead hourly
prices)
• SCUC for reliability commitment only
• Security Constrained Economic Dispatch
• LMP calculation using generation offers, demand bids, and bilateral
transaction schedules.
Real-Time Energy Market
SUPPORTING
PROCESSES
P
u
b
l
i
s
h
S
t
a
t
e
E
s
t
i
m
a
t
o
r
M
a
r
k
e
t
P
r
o
c
e
s
s
(Based on actual hourly quantity deviations from day-ahead
schedule hourly quantities and real-time prices)
• Security Constrained Economic Dispatch
• LMP calculation using real-time SE values
D
a
t
a
S
e
t
t
l
e
m
e
n
t
s
&
B
i
l
l
i
n
g
Participant Readiness
• Communications Plan
• Define Membership
Requirements
• Manage Customer Registration
• Manage Customer Relations
• Manage Training
• Perform Market Trials
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33
The Midwest Markets

Significant challenges:




No experience operating as a pool.
Many control areas of all sizes.
Allocation of transmission rights in areas where
system is overbooked.
Coordination with PJM and other neighboring
entities.



Resolution of WI and MI hold harmless provisions.
Aggressive timeline.
MISO-SPP merger needs to be completed.
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34
MISO-PJM-SPP Territory
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35
A Joint and Common Wholesale
Energy Market
The goal is to develop a common single
wholesale market with a “one-stop
shop” that meets the needs of all
customers and stakeholders using the
electric grid in the 26 states served by
them.
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36
Phase 2 - Two Blended Markets
East MISO-SPP Included
Manitoba
Montana
PJM incorporates Indiana & Illinois
North
Dakota
Michigan
Minnesota
Wyoming
South
Dakota
Wisconsin
Michigan
Nebraska
Iowa
Pennsylvania
Illinois
Kansas
New
Mexico
Oklahoma
Missouri
Indiana
Ohio
Kentucky
West
Virginia
Virginia
New Jersey
Deleware
Maryland
District of Comumbia
Arkansas
Texas
Louisana
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37
Schedule





May 2003 – AEP & DPL in PJM market
Oct 2003 – Dominion in PJM market
Dec 2003 – ComEd & IP in PJM market
Dec 2003 – MISO-SPP market operation
October 2004 – MISO-PJM-SPP market
is implemented with one-stop shopping
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38
Current Activities


MISO and PJM have chosen to resolve
seams without implementing the single
market.
MISO is also working on its LMP market
and the integration of Grid America and
TransLink while PJM is focused on the
expansion of its markets in AEP & DPL
areas.
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39
Market Model for RTO Coordination
Market Participants
Internet or VPN Access
RTO
Specific
RTO
Specific
Common Market Interface
RTO Functions
RTO Functions
(Transmission Reservation,
Energy Market, Settlements & Billing )
(Transmission Reservation,
Energy Market, Settlements & Billing )
RTO
Portals
RTO
Portals
RTO Data Repository
Planning
Scheduling
Data
Transport
Regional Entity
Control
Area
ITC
Settlements
& Billing
Operations
Data
Transport
Data
Transport
Regional Entity
Regional Entity
Control
Area
ITC
Control
Area
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ITC
40
Implementation of the SMD
Markets in the Midwest

Proper solution to the coordination
between MISO and PJM, and between
these RTOs and the Independent
Transmission Companies in their
footprints, is the key to a successful
implementation of the SMD markets in
the Midwest.
Paliza Consulting, LLC.
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41