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Market Rule Amendment Proposal
PART 1 – MARKET RULE INFORMATION
Identification No.:
MR-00375-R00
Subject:
Enhanced Day-Ahead Commitment Process (EDAC)
Title:
Market Rule True-up
Nature of Proposal:
Alteration
Deletion
Chapter:
7
Sections:
2.2, 2.2C, 3.3, 3.3A, 5.1, 5.5, 5.8, 6.3B, 12.1
Addition
Appendix:
Sub-sections proposed for amending:
Various
PART 2 – PROPOSAL HISTORY
Version
Reason for Issuing
Version Date
1.0
Working Draft for Discussion Purposes
November 3, 2010
2.0
Second Working draft (expanded version)
December 8, 2010
3.0
Third Draft (expanded version)
February 15, 2011
Approved Amendment Publication Date:
Approved Amendment Effective Date:
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PART 3 – EXPLANATION FOR PROPOSED AMENDMENT
Provide a brief description of the following:



The reason for the proposed amendment and the impact on the IESO-administered markets if the
amendment is not made.
Alternative solutions considered.
The proposed amendment, how the amendment addresses the above reason and impact of the
proposed amendment on the IESO-administered markets.
Summary
This amendment proposal is the third set of market rule amendments required to implement the
enhanced day-ahead commitment (EDAC) process design approved by the IESO Board in February
2009. The EDAC Project Advisory Group has identified changes that are required to:




address design detail changes subsequent to approved amendments MR-00348 and MR-00349,
including obligations regarding pseudo-units (R00, R01);
enable the IESO to recover CMSC for the hours associated with a given start that occur after
the DACP dispatch day (R01);
change participant workstation requirements (R03); and
provide greater clarity and consistency throughout.
Background
EDAC is a modification to the existing Day-Ahead Commitment Process (DACP) that introduces the
following elements:
 Optimization of commitment over the entire 24 hours of the next day;
 Use of multiple passes of the constrained algorithm to determine commitment and resource
scheduling; and
 Three-part offers, i.e., the use of offers for energy supported by submitted fixed costs and
technical data.
For further background information, refer to MR-00375-Q00.
Discussion
Section 2.2 Registered Facilities
Section 2.2.6B describes the required submission for certain dispatchable generation facilities. Minor
wording changes are proposed to provide greater clarity. One reference to minimum run-time is
unnecessary in this instance and has been deleted. The following editorial changes are required so that
section numbering follows the market rules conventional style:
 Delete sections 2.2.6B.1 through 2.2.6.B3, and move to sections 2.2.6J, 2.2.6K, and 2.2.6G,
respectively. These sections describe data submission requirements.
 Information will be submitted in accordance with the applicable market manuals and will not
be itemized in the rules.
In sections 2.2.6E and 2.2.6F, changes include:
 Removing the reference to 2.2.6C which was deleted as part of MR-00348.
 Revise section 2.2.6F to add references to 2.2.6J (which describes the daily submission of
information) and 2.2.6G (which describes the information submitted for combined cycle
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PART 3 – EXPLANATION FOR PROPOSED AMENDMENT
facilities and pseudo-units), all of which the IESO will respect in scheduling. Also change the
reference to section 4 since the determination of the real-time schedule is section 6.
New section 2.2.6I has been added to specify the IESO’s obligation to use the submitted daily
information referred to in section 2.2.6J to calculate the pseudo-unit technical parameters, provided
that the participant has declared to operate as a pseudo-unit in accordance with section 2.2.6G.
Section 2.2C Generation Facility Eligibility for the Production Cost Guarantee
 Modify the section title to reflect the change from Production Cost Guarantee to Day-Ahead
Production Cost Guarantee.
Section 3.3 Dispatch Data Submissions
 Modify section 3.3.1 to reflect the change in the deadline for submitting initial dispatch data
from 11:00 to 10:00 EST.
 Modify section 3.3.2. The IESO will determine the initial pre-dispatch schedule after the
release of the schedule of record (subject to the operation of the DACP on that pre-dispatch
day), rather than during the DACP. Market participants may have revised their initial dispatch
data under section 3.3A.6; the initial pre-dispatch schedule will consider the initial dispatch
data as revised under 3.3A.6.
Section 3.3A Dispatch Data Submission for the Day-Ahead Commitment Process
 Modify section 3.3A.6 after the word “offers” to insert the words “or bids”, referring to
submitted information from dispatchable loads and from boundary entities for export
transactions. Delete words describing the types of market participants that submit dispatch
data; this detail is provided under section 3.3A.2 which is referenced in this section. Also
change wording of this section to clarify the timing and requirements for revision of dispatch
data after 10:00 EST by market participants.
 Delete section 3.3A.7. The section is redundant and therefore unnecessary. Section 3.3.2
already requires the IESO to determine the initial pre-dispatch schedule using the initial
dispatch data submitted, including the dispatch data submitted under section 3.3A.2 and
3.3A.5.
 Modify section 3.3A.8 to reflect the correct time after which dispatch data may be revised
without restriction (until 2 hours prior to the dispatch hour, subject to 3.3A.9 and 3.3A.10);
participants do not need to wait until after the release of the schedule of record, but rather may
revise dispatch data after 14:00 EST.
 Modify section 3.3A.9 to delete unnecessary wording and clarify the meaning of the section.
 Modify section 3.3A.10 to reflect the change from Production Cost Guarantee to Day-Ahead
Production Cost Guarantee.
Section 5.1 Purpose and Timing of Pre-dispatch Schedules
 Modify section 5.1.2 to specify the time for the determination of the initial pre-dispatch
schedule for the next dispatch day, “no later than 16:00 EST” (changed from 12:00 EST).
Section 5.5 Release of Pre-dispatch Schedule Information
 Modify section 5.5.1 to specify the time by which the IESO must release and publish the initial
pre-dispatch schedule, market schedule projections and market prices, “by 16:00 EST”
(changed from 12:00 EST).
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PART 3 – EXPLANATION FOR PROPOSED AMENDMENT
Section 5.8 The Day-Ahead Commitment Scheduling Process
 Modify section 5.8.1 to delete the reference to pre-dispatch schedules. Appendix 7.5A is used
only for the determination of the schedule of record.
 Modify section 5.8.2 to delete the reference to section 5.5 which refers to the release of predispatch information only, not DACP information. The schedule of record is released in
accordance with the applicable market manual. Also modify this section to make the release of
the schedule of record subject to the schedule of record first being determined under section
5.8.1.
 Modify section 5.8.4 to reflect the change from Production Cost Guarantee to Day-Ahead
Production Cost Guarantee.
 Modify section 5.8.5 to state that a facility will be constrained at minimum loading point or
greater for all hours the facility is scheduled in the schedule of record (not just the minimum
generation block run-time hours). Also modify this section to make it subject to section 5.8.4
(the facility must be eligible under section 2.2C for the day-ahead production cost guarantee).
 Modify section 5.8.7 to delete the reference to pre-dispatch schedules since they are no longer
produced before the schedule of record. The IESO only ignores the net intertie scheduling
limit (NISL) for the first hour of the next dispatch day during the DACP timeframe.
Section 6.3B Real-Time Scheduling of Generation Facilities Eligible for the Production Cost
Guarantee
 Modify the section title and sections 6.3B.1, 6.3B.2 and 6.3B.3 to reflect the change from
Production Cost Guarantee to Day-Ahead Production Cost Guarantee.
Section 12.1 IESO System Status Reports
 Modify section 12.1.1.3 and 12.1.1.4 to reflect the new time for publishing the system status
report, at 09:00 EST not 10:30 EST.
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PART 4 – PROPOSED AMENDMENT
1.7
IESO Authorities and Obligations Regarding the
Operation of the Day-Ahead Commitment Process
Functions
1.7.1
The Chief Executive Officer of the IESO shall determine when the day-ahead
commitment process shall first be used.
1.7.2
[Intentionally left blank – section deleted]
1.7.3
The IESO shall notify market participants at least five business days in advance of
the day the day-ahead commitment process will first be used.
1.7.4
The IESO shall cancel the day-ahead commitment process for a given dispatch day
when process or software failures prevent one or more hourly day-ahead
commitment process runs from meeting the minimum criteria for a minimum
acceptable DACP run, as defined in the applicable market manual.
1.7.5
In accordance with the applicable market manual, if the IESO cancels the dayahead commitment process for a given dispatch day, the IESO shall:


inform market participants of the cancellation;
inform market participants as to whether the day-ahead commitment process will
resume for the subsequent dispatch day.
………………………………………….
2.2
Registered Facilities
…………………………………………….
2.2.6A
A registered market participant for a generation facility may submit the following
facility specific information: forbidden regions; and period of steady operation. If
the information regarding forbidden regions is submitted, the market participant shall
respect such information when submitting dispatch data for the real-time market. If
the dispatch data submitted does not respect such information the IESO shall reject
the dispatch data submission for the affected resource and for the corresponding
dispatch hour or dispatch hours and shall advise the submitting registered market
participant accordingly.
2.2.6B
A registered market participant for a dispatchable generation facility shall submit to
the IESO the minimum loading point, the minimum generation block run-time, and
the minimum run-time for the generation facility if the minimum loading point for the
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facility is greater than zero MW and if the minimum generation block run-time for the
facility is greater than one hour.
2.2.6C
[Intentionally left blank – section deleted]
2.2.6D
The IESO may request, and the registered market participant for a dispatchable
generation facility shall submit to the IESO, the following information for the
generation facility:


start-up time; and
minimum shut-down time.
2.2.6E
If no facility specific data is submitted to the IESO for the generation facility’s
minimum loading point, forbidden regions, or period of steady operation in
accordance with sections 2.2.6A and 2.2.6B, the IESO shall assign default values of
zero for that data.
2.2.6F
If facility specific data is submitted to the IESO in accordance with sections 2.2.6A,
2.2.6B, 2.2.6G or 2.2.6J, the IESO shall respect the data as submitted in its
determination of the real-time schedule in accordance with section 6 and day-ahead
schedule in accordance with section 5.
2.2.6G
In accordance with the applicable market manuals, a registered market participant
that operates a combined cycle facility that is not aggregated under section 2.3 shall
submit to the IESO the required data for that combined cycle facility, and for those
registered market participants that wish to designate their non-aggregated combined
cycle facility as a pseudo-unit in the day-ahead commitment process set out in section
5.8, the required data for that pseudo-unit.
2.2.6H
A registered market participant for a dispatchable hydroelectric generation facility
shall submit to the IESO where applicable the daily cascading hydroelectric
dependency for that generation facility.
2.2.6I
Subject to section 2.2.6G, the IESO shall determine, in accordance with the
applicable market manual, the pseudo-unit technical parameters based on the facility
specific data submitted under section 2.2.6J.
2.2.6J
A registered market participant for a dispatchable generation facility that is not a
quick-start facility may submit on a daily basis the minimum loading point, the
minimum generation block run-time, the maximum number of starts per day and the
minimum generation block down time, and, for facilities designated as a pseudo-unit
under section 2.2.6G, the combustion turbine single cycle mode, and the IESO shall
use this data in the day-ahead commitment process set out in section 5.8.
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2.2.6K
A registered market participant for a dispatchable generation facility shall submit to
the IESO the elapsed time to dispatch for the generation facility.
…………………………………
2.2C
Generation Facility Eligibility for the Day-Ahead
Production Cost Guarantee
2.2C.1
A registered market participant for a generation facility shall be eligible for the
guarantee of certain elements of the facility’s costs, calculated in accordance with
section 4.7D of Chapter 9, provided the following criteria are met:
2.2C.2
2.2C.1.1
the facility is not a quick-start facility;
2.2C.1.2
the facility is a dispatchable generation facility with a elapsed time to
dispatch greater than one hour;
2.2C.1.3
[Intentionally left blank – section deleted]
2.2C.1.4
the registered market participant has, according to the timelines and in the
form specified in the applicable market manual, submitted to the IESO the
following information for the generation facility: the start-up costs; and
the speed no-load costs; and
2.2C.1.5
the registered market participant has, according to the timelines and in the
form specified in the applicable market manual, submitted to the IESO the
following information for the generation facility: the minimum loading
point; and the minimum generation block run-time and the IESO accepts
all such information as reasonable.
[Intentionally left blank – section deleted]
…………………………………….3.3
Dispatch Data Submissions
3.3.1
Subject to sections 3.3.9 and 3.3A, a registered market participant that submits or is
required to submit dispatch data for the initial pre-dispatch schedule, shall submit
initial dispatch data for each dispatch hour of the dispatch day after 06:00 EST but
before 10:00 EST of each pre-dispatch day. Such initial dispatch data may thereafter
be revised as permitted by this section 3.3.
3.3.2
Subject to section 3.3A.6, the IESO shall use the initial dispatch data submitted by
registered market participants to determine and publish the initial pre-dispatch
schedule in accordance with section 5.
3.3.3
Subject to section 3.3A.8, a registered market participant may submit revised
dispatch data with respect to any dispatch hour without restriction until 2 hours prior
to the beginning of that dispatch hour.
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3.3.4
[Intentionally left blank – section deleted]
3.3.4A
[Intentionally left blank – section deleted]
………………………………..3.3A
Dispatch Data Submissions for the
Day-Ahead Commitment Process
3.3A.1
Subject to section 1.7, defining when the day-ahead commitment process shall
function, this section 3.3A shall be in effect.
3.3A.2
Subject to the standing dispatch data provisions of section 3.3.9, each registered
market participant that intends its dispatchable generation facility, including a
generation facility that intends to operate in segregated mode of operation in realtime, or dispatchable load facility to be eligible for dispatch by the IESO for a given
dispatch hour of a dispatch day shall, after 06:00 EST but before 10:00 EST of the
pre-dispatch day, submit dispatch data for those dispatch hours of the dispatch day
including, where applicable, the daily energy limit for the facility for the dispatch day.
The registered market participant may then only revise such initial dispatch data as
permitted by this section 3.3A.
3.3A.3
If a registered market participant for a dispatchable generation facility does not
provide dispatch data in accordance with section 3.3A.2 the facility shall not operate
in real-time without the approval of the IESO under section 3.3A.12.
3.3A.4
A registered market participant for a dispatchable load facility may, in the dispatch
data submitted under section 3.3A.2, identify all or a portion of the consumption at
such registered facility as non-dispatchable load in accordance with the applicable
market manual.
3.3A.5
A registered market participant for a boundary entity may submit, between 6:00 EST
and 10:00 EST of the pre-dispatch day, an import offer or export bid for the next
dispatch day with a valid NERC tag identifier. If the import offer is included in the
schedule of record determined under section 5.8, the registered market participant
will receive the day-ahead intertie offer guarantee determined under section 3.8A of
Chapter 9.
3.3A.6
Registered market participants that submitted offers or bids in accordance with either
section 3.3A.2 or section 3.3A.5 shall require IESO approval to modify those offers or
bids between 10:00 and 14:00 EST except for registered market participants for:


3.3A.7
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dispatchable hydroelectric generation facilities which submitted a daily cascading
hydroelectric dependency in accordance with section 2.2.6K and which are
designated by the IESO as eligible energy-limited resources, and
physical generation units associated with a pseudo-unit designated in accordance
with section 2.2.6G.
[Intentionally left blank – section deleted]
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Market Participant Revisions to Dispatch Data
3.3A.8
Subject to sections 3.3A.9 and 3.3A.10, after 14:00 EST a registered market
participant may submit revised dispatch data with respect to any dispatch hour
without restriction until 2 hours prior to the beginning of that dispatch hour.
3.3A.9
Subject to section 3.3A.10, a registered market participant for a dispatchable
generation facility that did submit dispatch data under section 3.3A.2 may revise its
offer in real-time provided the revised dispatch data does not increase the number of
hours offered or the offered quantity in any hour relative to the dispatch data
submitted under section 3.3A.2. Revised offers which represent increases to the
number of hours offered or increases to the offered quantity relative to the dispatch
data submitted under section 3.3A.2 will require IESO approval. Changes to daily
energy limits will not require IESO approval.
3.3A.10
A registered market participant for a dispatchable generation facility that was
deemed to have accepted the day-ahead production cost guarantee in accordance with
section 5.8.4 shall not increase the offer price associated with the minimum loading
point of the facility.
3.3A.11
A registered market participant for a dispatchable load facility that declared its intent
for all or a portion of its consumption to be non-dispatchable under sections 3.3A.2
and 3.3A.4 will require IESO approval to increase its declared bid quantity and bid
that consumption in real-time as dispatchable load.
3.3A.12
The IESO shall approve increases to declared availability of a dispatchable facility if
that generation facility or dispatchable load facility returns from outage earlier than
planned, or if the IESO has solicited additional offers and bids, or if such increases
will avoid an emergency operating state or high-risk operating state, or as permitted
under section 3.3.6.3.
3.3A.13
A registered market participant for a boundary entity who is eligible to receive a dayahead intertie offer guarantee for an import transaction in accordance with section
3.3A.5 shall not revise the submitted dispatch data to link that import transaction to
an export transaction as described in section 3.5.8.2 of Chapter 7. If the IESO
determines that the dispatch data was revised by the registered market participant in
the manner described above, the IESO shall recover from the registered market
participant any day-ahead intertie offer guarantee payment for that import transaction
and shall redistribute the payment in accordance with chapter 9, section 4.8.2.11.
……………………………..
3.7
Self-Scheduling Generators
3.7.3
Subject to section 1.7 defining when the day-ahead commitment process shall
function, a registered market participant for a registered facility that is a selfscheduling generation facility shall submit dispatch data after 6:00 EST but before
10:00 EST of the pre-dispatch day in accordance with section 3.7.1.
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……………………………..
3.7
Self-Scheduling Generators
3.7.1
A registered market participant for a self-scheduling generation facility shall submit
dispatch data indicating the amount of energy that the registered market participant
reasonably expects to be provided by that self-scheduling generation facility in each
dispatch hour. Such dispatch data shall:
3.7.1.1
be submitted to the IESO in such form as may be specified by the IESO,
including provision of the applicable information specified in Appendix
7.1; and
3.7.1.2
comply with section 3.4.4A.
3.7.2
A registered market participant for a self-scheduling cogeneration facility or selfscheduling enhanced combined cycle facility shall ensure its facility operates in
accordance with its dispatch data within the tolerances for updating dispatch data
outlined in section 3.3.8.
3.7.3
Subject to section 1.7 defining when the day-ahead commitment process shall
function, a registered market participant for a registered facility that is a selfscheduling generation facility shall submit dispatch data after 6:00 EST but before
10:00 EST of the pre-dispatch day in accordance with section 3.7.1.
3.8
Intermittent Generators
3.8.1
A registered market participant for an intermittent generator shall submit dispatch
data indicating its best forecast of the amount of energy that the intermittent
generator will inject in each dispatch hour. Such dispatch data shall:
3.8.1.1
be submitted to the IESO in such form as may be specified by the IESO,
including provision of the applicable information specified in Appendix
7.1; and
3.8.1.2
comply with section 3.4.4A.
3.8.2
Subject to section 1.7 defining when the day-ahead commitment process shall
function, a registered market participant for a registered facility that is an intermittent
generator shall submit dispatch data after 6:00 EST but before 10:00 EST of the predispatch day indicating its best forecast of the amount of energy that the intermittent
generator will inject in each dispatch hour of the next dispatch day in accordance
with section 3.8.1.
3.8A
Transitional Scheduling Generators
3.8A.1
A registered market participant for a registered facility that is a transitional scheduling
generator shall submit dispatch data indicating its forecast of the amount of energy
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that the transitional scheduling generator will inject in each dispatch hour of the
dispatch day. Such dispatch data shall be submitted to the IESO for the initial predispatch schedule in accordance with section 3.3.1 and in such form as may be
specified by the IESO.
3.8A.2
Subject to section 1.7 defining when the day-ahead commitment process shall
function, a registered market participant for a registered facility that is a transitional
scheduling generator shall submit dispatch data after 6:00 EST but before 10:00 EST
of the pre-dispatch day indicating its forecast of the amount of energy that the
transitional scheduling generator will inject in each dispatch hour of the next
dispatch day in accordance with section 3.8A.1.
……………………………..
5.1
Purpose and Timing of Pre-dispatch Schedules
5.1.1
The IESO shall determine pre-dispatch schedules in order to provide itself and market
participants with advance information and projections necessary to plan the physical
operation of the electricity system.
5.1.2
The IESO shall determine an initial pre-dispatch schedule for the 24 dispatch hours
of each dispatch day no later than 16:00 EST on the pre-dispatch day.
5.1.3
The IESO shall prepare a revised pre-dispatch schedule for each dispatch day
whenever the IESO determines that changed circumstances have made the previous
pre-dispatch schedule materially incorrect. A revised pre-dispatch schedule shall be
determined only for dispatch hours following the changes that make it necessary.
5.1.4
Each time the IESO determines a pre-dispatch schedule, it shall also determine the
associated projected market prices for energy and operating reserve and the
associated projected market schedule.
5.1.5
The IESO shall publish and release to market participants each pre-dispatch schedule
as provided in section 5.5. The most recently published pre-dispatch schedule shall
supersede all previous pre-dispatch schedules for the same dispatch hours.
……………………………..
5.5
Release of Pre-dispatch Schedule Information
5.5.1
The IESO shall release the initial pre-dispatch schedule and associated projections of
market schedules and shall publish market prices by 16:00 EST of each pre-dispatch
day, and shall release any revised pre-dispatch schedules and projections of market
schedules and shall publish market prices as soon as practical after they are
determined. The information to be released to market participants is described in this
section 5.5.
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…………………………….
5.8
The Day-Ahead Commitment Pre-Dispatch Scheduling
Process
5.8.1
Starting from 10:00 EST, the IESO may in accordance with Appendix 7.5A determine
the schedule of record.
5.8.2
Where the IESO determines the schedule of record in accordance with Section 5.8.1,
it will be released by the IESO no later than 15:00 EST in accordance with the
applicable market manual.
5.8.3
[Intentionally left blank – section deleted.]
5.8.4
A registered market participant whose facility is eligible under section 2.2C for the
day-ahead production cost guarantee and whose facility is included in the schedule of
record is deemed to have accepted the guarantee for its facility.
5.8.5
Subject to sections 5.8.4 and 5.8.6, the IESO shall ensure that the scheduled output for
a facility will meet or exceed its minimum loading point for all hours that it was
included in the schedule of record in future iterations of the pre-dispatch schedule and
in the real-time schedule.
5.8.6
The IESO may, to maintain the reliable operation of the IESO-controlled grid, require
a generation facility that was included in the schedule of record to either
desynchronize from the IESO-controlled grid or to not synchronize to the IESOcontrolled grid.
5.8.7
When determining the schedule of record applicable to the first hour of the next
dispatch day , the IESO may disregard the net intertie scheduling limit.
5.8.8
[Intentionally left blank – section deleted]
…………………………….
6.3B
Real-Time Scheduling of Generation Facilities Eligible for
the Day-Ahead Production Cost Guarantee
6.3B.1
If the IESO, for reasons of reliability, requires a generation facility that was eligible
for the day-ahead production cost guarantee under section 2.2C to either
desynchronize from the IESO-controlled grid or to not synchronize to the IESOcontrolled grid such that the generation facility does not comply with its schedule of
record, the generation facility shall remain eligible for the day-ahead production cost
guarantee. The registered market participant for the generation facility may also
apply to the IESO for additional compensation under section 4.7E.1 of Chapter 9.
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6.3B.2
If a generation facility that was eligible for the day-ahead production cost guarantee
under section 2.2C does not close its breaker by the start of the first interval of the
first hour of its schedule of record due to reasons not specified in sections 6.3B.1or
6.3B.3 then the generation facility shall not remain eligible for the day-ahead
production cost guarantee associated with that start determined in accordance with
section 5.8 nor shall the registered market participant for the generation facility be
eligible to apply to the IESO for additional compensation under section 4.7E.1 of
Chapter 9.
6.3B.3
If a generation facility that was eligible for the day-ahead production cost guarantee
under section 2.2C does not comply with its schedule of record due to reasons
specified in section 1.2.3 of Chapter 5 then the facility shall remain eligible for a prorated day-ahead production cost guarantee determined in accordance with section
4.7D of Chapter 9.
………………………………
12.1
IESO System Status Reports
12.1.1
The IESO shall publish system status reports with respect to each dispatch day at the
following times:
12.1.1.1
15:30 EST of the day two days prior to the dispatch day;
12.1.1.2
05:30 EST of the pre-dispatch day;
12.1.1.3
09:00 EST of the pre-dispatch day;
12.1.1.4 any time of the pre-dispatch day subsequent to 09:00 EST if there is a
material change to the information in the previous system status report for the
dispatch day; and
12.1.1.5 any time during the dispatch day, for the current and remaining dispatch
hours of the dispatch day, if there is a material change to the information in the
previous system status report for such dispatch hours.
PART 5 – IESO BOARD DECISION RATIONALE
Insert Text Here
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Market Rule Amendment Proposal
PART 1 – MARKET RULE INFORMATION
Identification No.:
MR-00375-R01
Subject:
Enhanced Day-Ahead Commitment Process (EDAC)
Title:
Market Rule True-up
Nature of Proposal:
Alteration
Deletion
Chapter:
9
Sections:
3.1, 3.5, 3.8A, 3.8E, 4.7B, 4.7D
Addition
Appendix:
Sub-sections proposed for amending:
Various
PART 2 – PROPOSAL HISTORY – PLEASE REFER TO MR-00375-R00
Version
Reason for Issuing
Version Date
Approved Amendment Publication Date:
Approved Amendment Effective Date:
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PART 3 – EXPLANATION FOR PROPOSED AMENDMENT
Provide a brief description of the following:



The reason for the proposed amendment and the impact on the IESO-administered markets if the
amendment is not made.
Alternative solutions considered.
The proposed amendment, how the amendment addresses the above reason and impact of the
proposed amendment on the IESO-administered markets.
Summary
Please refer to MR-00375-R00.
Background
Please refer to MR-00375-R00.
Discussion
It is proposed to modify the market rules in Chapter 9 in the following manner:
Section 3.1 Hourly Settlement Variables and Data (for DACP)

Insert a new subsection 3.1.11 to reflect the IESO obligation to calculate the required
information for settlement of a pseudo-unit.
Section 3.5 Hourly Congestion Management Settlement Credits (CMSC)

Insert a new subsection 3.5.7A to give the IESO the authority to recover CMSC revenue, up to
MLP, earned as a result of a constraint in the hours after midnight (after the DACP dispatch
day).
Section 3.8A Hourly Settlement Amounts for Intertie Offer Guarantees



Modify section 3.8A.4 to reflect the change from EDAC to DACP. The name of this project is
EDAC; however, the name of the IESO program in the market rules remains DACP.
Also modify section 3.8A.4 to change “market schedule” (i.e. unconstrained schedule) to
“constrained schedule” wherever it appears in order to reflect the approved equations in this
section.
Reinstate sections 3.8A.5 and 3.8A.6, which were removed in error under MR-00349 (deleted),
noting that they are intentionally left blank.
Section 3.8E Day-Ahead Linked Wheel Failure Charge (DA-LWFC)

Modify section 3.8E.3 to reflect the correct calculation of the charge when a linked wheel is
subject to both the DA-LWFC and the real time failure charge(s), by adjusting the real time
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PART 3 – EXPLANATION FOR PROPOSED AMENDMENT
failure charges within the calculation. This necessary adjustment is included in the
stakeholdered EDAC design and in the settlements market manual.
Section 4.7B Real-Time Generation Cost Guarantee Payments

Modify section 4.7B.3 to correct the reference to section 4.7B.1.1 (which is currently shown as
4.7.1.1 in error).

Modify section 4.7B.4 to reflect the change from day-ahead generation cost guarantee to dayahead production cost guarantee and the change from generation facility to generation unit.
Section 4.7D Day-Ahead Production Cost Guarantee Payments

Strike out “4.7D.1.1” and “4.7D.2.1”, which are unnecessary.

Modify section 4.7D.2, 4.7D.4, 4.7D.5 and 4.7D.6 to reflect the change from EDAC to DACP
and the change from generation facility to generation unit.

Modify section 4.7D.4, Component 3 to use “schedule of record” not “day-ahead schedule”,
and minor errata.

Modify section 4.7D.5 and 4.7D.6 to change the correct the reference to “4.7D.3” by changing
it to “4.7D.4”.
PART 4 – IESO BOARD DECISION RATIONALE
Day-Ahead Commitment Process Variables, Data and Information
3.1.2A
The IESO shall determine the following day-ahead quantities from the schedule of
record, and provide them directly to the settlement process:
schedule of record quantity scheduled for injection by market
DA_DQSIk,hi,t
= participant ‘k’ for an import transaction at intertie metering point ‘i’
DA_DQSIk,hm,t
= participant ‘k’ at delivery point ‘m’ during metering interval ‘t’ of
DA_DQSWk,hi,t
schedule of record quantity scheduled for withdrawal by
market participant ‘k’ for an export transaction at intertie
=
metering point ‘i’ during metering interval ‘t’ of settlement
hour ‘h’
DA_ELMPhm,t
= day-ahead constrained schedule intertie price at the delivery
point ‘m’ of the sink for the export transaction during metering
during metering interval ‘t’ of settlement hour ‘h’
schedule of record quantity scheduled for injection by market
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settlement hour ‘h’
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interval ‘t’ of settlement hour ‘h’
DA_ILMPh
3.1.2B
m,t
day-ahead constrained schedule intertie price at the delivery
= point ‘m’ of the source for the import transaction during
metering interval ‘t’ of settlement hour ‘h’
The IESO shall provide directly to the settlement process:
3.1.2B.1
information to identify market participants which are deemed to have
accepted in accordance with section 5.8.4 of Chapter 7 a day-ahead
production cost guarantee for their generation facility;
3.1.2B.2
information to identify any event in which the IESO de-commits a
generation facility between the release and publication of the schedule
of record and the end of its committed schedule in the schedule of
record where the market participant has been deemed to have
accepted in accordance with section 5.8.4 of Chapter 7 a day-ahead
production cost guarantee for that facility;
3.1.2B.3
exemptions from the day-ahead import failure charge described in
section 3.8B, for any applicable import transactions scheduled in the
schedule of record where such exemptions have been determined in
accordance with chapter 7, section 7.5.8B;
3.1.2B.4
exemptions from the day-ahead export failure charge described in
section 3.8D, for any applicable export transactions scheduled in the
schedule of record where such exemptions have been determined in
accordance with chapter 7, section 7.5.8B;
3.1.2B.5
exemptions from the day-ahead linked wheel failure charge described
in section 3.8E, for any applicable linked wheel transactions scheduled
in the schedule of record where such exemptions have been
determined in accordance with chapter 7, section 7.5.8B; and
3.1.2B.6
exemptions from the day-ahead generator withdrawal charge
described in section 3.8F, for any applicable registered facility
scheduled in the schedule of record where such exemptions have been
determined in accordance with chapter 7, section 7.5.3.
3.1.2B.7
the following information:
DA_BEk,hm,t
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energy offers submitted in day-ahead, represented as an N by 2
matrix of price-quantity pairs for each market participant ‘k’
at delivery point ‘m’ during metering interval ‘t’ of settlement
=
hour ‘h’ arranged in ascending order by the offered price in
each price quantity pair where offered prices ‘P’ are in column
1 and offered quantities ‘Q’ are in column 2
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DA_BEk,hi,t
energy offers submitted in day-ahead, represented as an N by 2
matrix of price-quantity pairs for each market participant ‘k’
at intertie metering point ‘i’ during metering interval ‘t’ of
=
settlement hour ‘h’ arranged in ascending order by the offered
price in each price quantity pair where offered prices ‘P’ are in
column 1 and offered quantities ‘Q’ are in column 2
DA_BLk,hi,t
energy bids submitted in day-ahead, represented as an N by 2
matrix of price-quantity pairs for each market participant ‘k’
at intertie metering point ‘i’ during metering interval ‘t’ of
=
settlement hour ‘h’ arranged in ascending order by the offered
price in each price quantity pair where offered prices ‘P’ are in
column 1 and offered quantities ‘Q’ are in column 2
DA_SNLCk,h m
as-offered speed-no-load cost associated with three-part offers
= for a given settlement hour ‘h’ for market participant ‘k’ at
delivery point ‘m’
DA_SUCk,h m
as-offered start-up cost associated with three-part offers for a
= given settlement hour ‘h’ for market participant ‘k’ at delivery
point ‘m’
minimum output of energy the market participant ‘k’ at
= delivery point ‘m’ can maintain without ignition support in
metering interval ‘t’ of settlement hour ‘h’
The IESO shall determine from the pre-dispatch schedule and the pre-dispatch
projected market schedule, and provide directly to the settlement process the
following pre-dispatch prices and quantities:
MLPk,h m,t
3.1.2C
PD_DQSIk,hi,t
pre- dispatch constrained quantity scheduled for injection by
= market participant ‘k’ at intertie metering point ‘i’ during
metering interval ‘t’ of settlement hour ‘h’
PD_DQSWk,hi,t
pre- dispatch constrained quantity scheduled for withdrawal
= by market participant ‘k’ at intertie metering point ‘i’ during
metering interval ‘t’ of settlement hour ‘h’
PD_EMPhm,t
PD_ELMPh
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m,t
= pre-dispatch projected energy market price applicable to all
delivery points ‘m’ in the Ontario zone in metering interval ‘t’
of settlement hour ‘h’
In instances where this variable is provided to the settlement
process on an hourly basis as determined in section 3.9, it shall
be deemed to apply uniformly to all metering intervals ‘t’ in
settlement hour ‘h’
pre-dispatch constrained schedule intertie price at the delivery
= point ‘m’ of the sink for the export transaction during metering
interval ‘t’ of settlement hour ‘h’
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pre-dispatch constrained schedule intertie price at the delivery
= point ‘m’ of the source for the import transaction during
metering interval ‘t’ of settlement hour ‘h’
PD_ILMPhm,t
3.1.2D The IESO shall provide directly to the settlement process:
3.1.2D.1
the following information:
energy offers submitted in pre-dispatch, represented as an N by
2 matrix of price-quantity pairs for each market participant ‘k’
at intertie metering point ‘i’ during metering interval ‘t’ of
=
settlement hour ‘h’ arranged in ascending order by the offered
price in each price quantity pair where offered prices ‘P’ are in
column 1 and offered quantities ‘Q’ are in column 2
PD_BEk,hi,t
3.1.3
energy bids submitted in pre-dispatch, represented as an N by
2 matrix of price-quantity pairs for each market participant ‘k’
at intertie metering point ‘i’ during metering interval ‘t’ of
PD_BLk,hi,t
=
settlement hour ‘h’ arranged in ascending order by the offered
price in each price quantity pair where offered prices ‘P’ are in
column 1 and offered quantities ‘Q’ are in column 2.
The IESO shall determine energy market prices and quantities as provided in
Chapter 7 and shall provide the following variables and data from the energy
market, determined in accordance with section 3.1.4A, directly to the settlement
process:
MQSIk,hm,t
=
market quantity scheduled for injection in the market schedule by
market participant ‘k’ at location m or intertie metering point ‘m’ in
metering interval ‘t’ of settlement hour ‘h’
MQSWk,hm,t
=
market quantity scheduled for withdrawal in the market schedule by
market participant ‘k’ at location m or intertie metering point ‘m’ in
metering interval ‘t’ of settlement hour ‘h’
DQSIk,hm,t
=
dispatch quantity scheduled for injection in the real-time schedule by
market participant ‘k’ at location m or intertie metering point ‘m’ in
metering interval ‘t’ of settlement hour ‘h’ determined on the basis of
the dispatch instructions issued to market participant ‘k’ for that
metering interval
DQSWk,hm,t
=
dispatch quantity scheduled for withdrawal in the real-time schedule
by market participant ‘k’ at location m or intertie metering point ‘m’
in metering interval ‘t’ of settlement hour ‘h’ determined on the basis
of the dispatch instructions issued to market participant ‘k’ for that
metering interval
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TMQSIh
m,t
=
=
total market quantity scheduled for injection in the market schedule by
all market participants at location m or intertie metering point ‘m’ in
metering interval ‘t’ of settlement hour ‘h’
k MQSIk,hm,t, with k = all market participants
energy market price at delivery point ‘m’ in metering interval ‘t’ of
settlement hour ‘h’
intertie congestion price for energy at intertie metering point ‘i’ in
metering interval ‘t’ of settlement hour ‘h’
where i  M such that M is the set of all delivery points ‘m’ and
intertie metering points ‘m’.
EMPhm,t
=
ICPhi,t
=
EMPhi,t
=
energy market price at intertie metering point ‘i’ in metering interval
‘t’ of settlement hour ‘h’
=
ICPhi,t + EMPhm,t subject to the constraints outlined in sections 8.2.2.4
and 8.2.2.5 of Chapter 7.
where m is any delivery point while uniform pricing exists.
where i  M such that M is the set of all delivery points ‘m’ and
intertie metering points ‘m’.
HOEPh
=
hourly Ontario energy price in settlement hour ‘h’
=
m,t EMPhm,t/12,
with t = all metering intervals in settlement hour ‘h’
m = all primary RWMs
3.1.4
The IESO shall determine operating reserve market prices and quantities in a
process integrated with the energy market, as provided in Chapter 7. For each of
the two types “r” of class r reserves, the IESO shall provide directly to the
settlement process the following variables and data, determined in accordance
with section 3.1.4A:
PRORr,hm,t
= market price (in $/MW) of class r reserve in metering interval ‘t’ of
settlement hour ‘h’ at delivery point ‘m’ or intertie metering point ‘m’
PRORr,hi,t
= market price (in $/MW) of class r reserve in metering interval ‘t’ of
settlement hour ‘h’ at intertie metering point ‘i’
where i  M such that M is the set of all delivery points ‘m’ and
intertie metering points ‘m’.
= ICPr,hi,t + PRORr,hm,t subject to the constraints outlined in
sections 8.2.2.6 and 8.2.2.7 of Chapter 7.
where m is any delivery point while uniform pricing exists.
ICPr,hi,t
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= intertie congestion price for class r reserve at intertie metering point
‘i’ in metering interval ‘t’ of settlement hour ‘h’
where i  M such that M is the set of all delivery points ‘m’ and
intertie metering points ‘m’.
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SQRORr,k,h
m,t
DQSRr,k,hm,t
3.1.4A
3.1.5
3.1.6
= scheduled quantity (in MW) of class r reserve for market participant
‘k’ in metering interval ‘t’ of settlement hour ‘h’ at location m or
intertie metering point ‘m’ as described in the market schedule
= dispatch quantity (in MW) of class r reserve for market participant ‘k’
at location m in metering interval ‘t’ or intertie metering point ‘m’ of
settlement hour ‘h’ as determined on the basis of the dispatch
instructions issued to market participant ‘k’ for that metering interval
For the purposes of sections 3.1.3, 3.1.4 and 3.5.2, “location m” in respect of
market participant ‘k’ shall mean the location of:
3.1.4A.1
the relevant meter used by market participant ‘k’ to meet the
monitoring requirements of section 7.3, 7.4, 7.5 or 7.6, as the case may
be, of Chapter 4 in respect of registered facility k/m, where such
requirements apply in respect of registered facility k/m; or
3.1.4A.2
the RWM for registered facility k/m, where the monitoring
requirements of section 7.3, 7.4, 7.5 or 7.6, as the case may be, of
Chapter 4 do not apply in respect of registered facility k/m.
If the daily capacity reserve market is active, the IESO shall determine capacity
reserve prices and capacity reserve quantities in the capacity reserve market and
shall provide the following variables and data directly to the settlement process:
QCAPRk,hm
=
capacity reserve quantity (in MW) sold by market participant ‘k’ at
RWM m for settlement hour ‘h’
PCAPRhm
=
capacity reserve price (in $/MW/hr) at RWM m in settlement hour ‘h’
Physical bilateral contract quantities shall be determined for each settlement hour
by the IESO using physical bilateral contract data submitted by selling market
participants and, where so required by the nature of the physical bilateral contract
data, operating results. The IESO shall divide each hourly physical bilateral
contract quantity into equal physical bilateral contract quantities if determination
of settlement amounts requires quantities for each metering interval of each
settlement hour. The IESO shall provide the following variables and data directly
to the settlement process:
BCQs,b,hm
=
physical bilateral contract quantity of energy (in MWh) sold by
selling market participant s to buying market participant b at primary
or intertie metering point ‘m’ in settlement hour ‘h’
BCQs,b,hm,t
=
physical bilateral contract quantity of energy (in MWh) sold by
selling market participant s to buying market participant b at primary
or intertie metering point ‘m’ for each metering interval ‘t’ in
settlement hour ‘h’
=
(1/12)  BCQs,b,hm, for all 12 metering intervals ‘t’ in settlement hour
‘h’
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3.1.7
The IESO shall offer a service whereby the selling market participant in a
physical bilateral contract or the selling market participant under a financial
bilateral contract may assume responsibility for components of the buying or
buying market participant’s settlement obligations other than those for energy.
3.1.8
The IESO shall provide the following TR data directly to the settlement process:
QTRk,hm,n
3.1.9
3.1.10
3.1.11
=
quantity of TRs (in MW) assigned to market participant ‘k’ for
transmission from primary or intertie metering point ‘m’ to primary or
intertie metering point ‘n’ for settlement hour ‘h’
The IESO shall determine the following allocated physical quantities for each
market participant for each primary RWM and each intertie metering point using
metering data, operating results, physical allocation data submitted by metered
market participants and interchange schedule data. If physical quantities are
provided only for each settlement hour (as they may be for interchange schedules,
non-dispatchable loads, self-scheduled generation facilities, transitional
scheduling generators and intermittent generators), the IESO shall, if necessary for
settlement purposes, determine the interval amounts defined below by dividing
the hourly amounts into twelve equal interval amounts:
AQEIk,hm,t
=
allocated quantity (in MWh) of energy injected by market participant
‘k’ at primary or intertie metering point ‘m’ in metering interval ‘t’ of
settlement hour ‘h’
AQEWk,hm,t
=
allocated quantity (in MWh) of energy withdrawn by market
participant ‘k’ at primary or intertie metering point ‘m’ in metering
interval ‘t’ of settlement hour ‘h’
AQORr,k,hm,t
=
allocated quantity (in MW) of class r reserve for market participant
‘k’ at primary or intertie metering point ‘m’ in metering interval ‘t’ of
settlement hour ‘h’
AQCRk,hm,t
=
allocated capacity reserve quantity (in MW) for market participant ‘k’
at primary or intertie metering point ‘m’ in metering interval ‘t’ of
settlement hour ‘h’
[Intentionally left blank – section deleted]
The IESO shall, in accordance with the applicable market manual, determine the
required settlement data for registered market participants that submitted dispatch
data for facilitiesoperating as pseudo-units, using the information submitted under
Chapter 7, sections 2.2.6G and 2.2.6J, and shall provide this settlement data
directly to the settlement process.
……………………………..
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3.5.7A
A registered market participant for a constrained on generation facility is not
entitled to a congestion management settlement credits determined in accordance
with section 3.5.2 for that facility up to minimum loading point if the congestion
management settlement credit is earned as a result of constraints applied under
Chapter 7, section 5.8.5 for hours in the day after the dispatch day. In this case,
the IESO may withhold or recover such congestion management settlement credits
and shall redistribute any recovered payments in accordance with section 4.8.2 of
Chapter 9.
...........................................
3.8A
Hourly Settlement Amounts for Intertie Offer
Guarantees
3.8A.1
The market prices determined by the real-time market schedule provided by the
IESO used for the settlement of a boundary entity associated with an intertie
metering point will sometimes deviate from:

in the case of an import transaction not scheduled in the schedule of
record, its accepted offer prices in the pre-dispatch market schedule (the
“projected market schedule”) in ways that, based on the real-time dispatch
process, imply a change to market participant ‘k’s net operating profits
relative to the operating profits implied by the pre-dispatch market
schedule for that boundary entity; or

in the case of an import transaction scheduled in the schedule of record, its
accepted offer prices in the schedule of record in ways that, based on the
real-time dispatch process, imply a change to market participant ‘k’s net
operating profits relative to the operating profits implied by the schedule
of record for that boundary entity.
When this occurs but subject to section 3.8A.3, market participant ‘k’ associated
with that boundary entity for settlement hour ‘h’ shall receive as compensation:
3.8A.1.1
in the case of an import transaction not scheduled in the schedule of
record, a real-time intertie offer guarantee (RT_IOGk,h) settlement
credit for the import of energy into the IESO-administered markets
equal to the cumulative losses resulting from a negative change in
implied operating profits over the course of each settlement hour,
resulting from such settlement, calculated in accordance with
section 3.8A.2; or
3.8A.1.2
in the case of an import transaction scheduled in the schedule of
record, the real-time intertie offer guarantee settlement credit
(RT_IOGk,h) or the day-ahead intertie offer guarantee settlement credit
(DA_IOGk,h) for the import of energy into the IESO-administered
markets equal to the cumulative losses resulting from a negative
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change in implied operating profits over the course of each settlement
hour, resulting from such settlement, calculated in accordance with
section 3.8A.2 or 3.8A.2B as the case may be.
Real-Time Intertie Offer Guarantee
3.8A.2
The real-time intertie offer guarantee settlement credit for market participant ‘k’
for settlement hour ‘h’ (“RT_IOGk,h”) shall be determined by the following
equation:
Let OP(P,Q,B) be a profit function of Price (P), Quantity (Q) and an N by 2 matrix (B) of price-quantity pairs:
s*
OP(P, Q, B)  P  Q   Pn  (Q n  Q n 1 )  (Q  Qs* )  Ps* 1
n 1
Using matrix notation for parameter ' B' this may be expressed as follows :
s*
OP(P, Q, B)  P  Q   Bn,1 Bn,2   Bn - 1,2  Q  Bs*,2  Bs * 1,1
n1
Where:
s* is the highest indexed row of B such that Qs*  Q  Qn and where, Q0=0
‘P’ is EMPhi,t: the real-time 5-minute energy market price at the applicable intertie
metering point ‘i’ during metering interval ‘t’ of settlement hour ‘h’
‘Q’ is MQSIk,hi,t: the market quantity scheduled for injection in the market
schedule by market participant ‘k’ at intertie metering point ‘i’ in metering
interval ‘t’ of settlement hour ‘h’
‘B’ is matrix BEk,hi,t of N price-quantity pairs offered by market participant ‘k’ to
supply energy from a particular boundary entity associated with an intertie
metering point ‘i’ in the IESO-administered markets, during metering interval ‘t’
of settlement hour ‘h’ arranged in ascending order by offered price where offered
prices are in column 1 and offered quantities are in column 2.
Using the terms below, let RT_IOGk,h be expressed as follows:
RT_IOGk,h
= EIMk,h
Where:
EIMk,h represents that component of the real-time intertie offer guarantee
settlement credit for market participant ‘k’ during settlement hour ‘h’ attributable
to import of energy into the IESO-administered markets at all relevant intertie
metering points ‘i’ in accordance with the rationale referred to in section 3.8A.1
and is calculated as follows:
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
EIM k,h  I (-1)  MIN 0, T OP(EMPh , MQSI k,h , BE)
i,t
i,t

Such that:
I is the set of all relevant intertie metering points ‘i’
T is the set of all metering intervals ‘t’ in settlement hour ‘h’
EMPhi,t is the real-time 5-minute energy market price at the applicable intertie
metering point ‘i’ during metering interval ‘t’ of settlement hour ‘h’
Day-Ahead Intertie Offer Guarantee
3.8A.2A The day-ahead intertie offer guarantee settlement credit for market participant ‘k’
for settlement hour ‘h’ (“DA_IOGk,h”) shall be determined for import transactions
that are not part of a day-ahead linked wheel.
3.8A.2B
The day-ahead intertie offer guarantee settlement credit for market participant ‘k’
for settlement hour ‘h’ (“DA_IOGk,h”) shall be determined by the following
equation:
DA_BEk,hi,t is the offer matrix of N price-quantity pairs for the eligible import
transaction scheduled in the schedule of record for market participant ‘k’ during
metering interval ‘t’ for settlement hour ‘h’ at intertie metering point ‘i’ arranged
in ascending order by offered price where offered prices are in column 1 and
offered quantities are in column 2.
Let OP(P,Q,B) be a profit function of Price (P), Quantity (Q) and an N by 2
matrix (B) of price-quantity pairs:
s*
OP(P, Q, B)  P  Q   Pn  (Q n  Q n 1 )  (Q  Qs* )  Ps* 1
n 1
Using matrix notation for parameter ' B' this may be expressed as follows :
s*
OP(P, Q, B)  P  Q   Bn,1 Bn,2   Bn - 1,2  Q  Bs*,2  Bs * 1,1
n1
Where:
s* is the highest indexed row of B such that Qs* ≤ Q ≤ Qn and where, Q0=0
‘P’ is EMPhi,t: the real-time 5-minute energy market price at the applicable intertie
metering point ‘i’ during metering interval ‘t’ of settlement hour ‘h’
‘Q’ is the minimum of:
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
DA_DQSIk,h : the schedule of record constrained quantity scheduled for
injection by market participant ‘k’ for an import transaction at intertie
metering point ‘i’ during metering interval ‘t’ of settlement hour ‘h’; or

DQSIk,hi,t: the real-time constrained quantity scheduled for injection by
market participant ‘k’ at intertie metering point ‘i’ during metering
interval ‘t’ of settlement hour ‘h’;
i,t
‘B’ is matrix DA_BEk,hi,t : energy offers submitted into the schedule of record,
represented as an N by 2 matrix of price-quantity pairs for each market
participant ‘k’ at intertie metering point ‘i’ during metering interval ‘t’ of
settlement hour ‘h’ arranged in ascending order by the offered price in each pricequantity pair where offered prices are in column 1 and offered quantities are in
column 2;
such that the day-ahead intertie offer guarantee is formulated as follows:
The principles for the settlement of the day-ahead intertie offer guarantee are as follows:
1. Component 1: Any shortfall in payment on the real-time import flow of the schedule of
record will be based upon the real-time revenue received for that amount of energy in
comparison with the costs submitted in the importer’s day-ahead offer;
2. Component 2: For the portion of schedule of record that is not implemented in the realtime dispatch schedule, the day-ahead intertie offer guarantee will guarantee the cost
incurred of arranging the import (where the real-time offer price is less than day ahead
offer price) or subtract any revenue gained (where the real-time offer price is greater than
the day-ahead offer price) 1; and
3. Component 3: Any income from real-time congestion management settlement credit
(CMSC) included in an importer’s schedule of record delivered in real-time will be used
to reduce the day-ahead intertie offer guarantee payment.
The Day-Ahead Intertie Offer Guarantee is calculated as follows:
DA_IOGk,h
=
Where:
T
1
=
set of all metering intervals ‘t’ in the set of all settlement hour ‘h’
Where the real-time offer is equal to the day-ahead offer, the cost/gain is equal to zero (0).
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Component 1
Component 1 includes any shortfall in payment on the delivered real-time dispatch of the
schedule of record based upon the real-time revenue received for that amount of energy in
comparison with the costs as represented in the importer’s day-ahead offer. Component 1 is
calculated as follows:
DA_IOG_COMP1k,hi,t
As-offered day-ahead costs for the minimum of the importer’s
schedule of record and the real-time constrained schedule for the
=
interval minus all real-time revenue received over the interval for
that amount of energy
DA_IOG_COMP1k,hi,t =
Component 2
If, as a result of economic selection, a portion of the schedule of record is not implemented in
the real-time dispatch schedule, the day-ahead intertie offer guarantee:

Guarantees the cost of arranging the delivery if the real-time offer is less
than the day-ahead offer; or

Subtracts any gain where the real-time offer is greater than the day-ahead
offer.

If there are no real-time energy offers submitted by the market participant
for any portion of the day-ahead constrained schedule, the real-time
energy offers for that portion of energy will be set to MMCP (Maximum
Market Clearing Price) for the purposes of calculating Component 2.

If the real-time energy offers for any portion of the day-ahead constrained
schedule is below $0.00 $/MWh (i.e. negative), the real-time energy offers
for that portion of energy will be set to $0.00 $/MWh for the purposes of
calculating Component 2.

Component 2 is calculated as follows:
As-offered day-ahead costs for the difference between:
DA_IOG_COMP2k,hi,t =

the minimum of the importer’s schedule of record quantity,
or the real-time constrained schedule; and

the minimum of the importer’s schedule of record quantity.
over the interval minus all real-time energy offers (with a minimum
limit of zero) over the interval for that amount of energy
DA_IOG
_COMP2k,hi,t
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
Where:
Let XBE k,hi,t be the function which calculates the area under the curve created by an n x 2
matrix (B) of offered price-quantity pairs:
where matrix (B) is energy offers submitted in real-time, represented as an N by 2 matrix of
price-quantity pairs for each market participant ‘k’ at intertie metering point ‘i’ during
metering interval ‘t’ of settlement hour ‘h’ arranged in ascending order by the offered price
in each price quantity pair where offered prices ‘P’ are in column 1 and offered quantities
‘Q’ are in column 2
Let XDA_BEk,hi,t be the function which calculates the area under the curve created
by an n x 2 matrix (B) of offered price-quantity pairs:
where matrix (B) is energy offers submitted in pre-dispatch, represented as an N by 2 matrix of pricequantity pairs for each market participant ‘k’ at intertie metering point ‘i’ during metering interval ‘t’
of settlement hour ‘h’ arranged in ascending order by the offered price in each price quantity pair
where offered prices ‘P’ are in column 1 and offered quantities ‘Q’ are in column 2
c*
the highest indexed row of matrix XDA_BEk,hi,t such that Qc* ≤
= min[DA_DQSIk,hi,t, DQSIk,hi,t,] ≤ Qn and where Qc*-1 =
min[DA_DQSIk,hi,t, DQSIk,hi,t] and where if Qc* < Qc*-1, let Qc* = Qc*-1
the highest indexed row of matrix XDA_BEk,hi,t such that Qd* ≤
DA_DQSIk,hi,t ≤ Qn
d*
=
p*
the highest indexed row of matrix XBEk,hi,t such that Qp* ≤
= min[DA_DQSIk,hi,t, DQSIk,hi,t] ≤ Qn and where Qp*-1 =
min[DA_DQSIk,hi,t, DQSIk,hi,t] and where if Qp* < Qp*-1, let Qp* = Qp*-1
s*
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=
the highest indexed row of matrix XBEk,hi,t such that Qs* ≤
DA_DQSIk,hi,t ≤ Qn
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Component 3

The DA-IOG payment for an import will be reduced by the income
received from real time congestion management settlement credit (CMSC)
for the importer’s schedule of record delivered in real-time.

The importer’s schedule of record will be measured against both the realtime constrained schedule and the real-time unconstrained schedule to
determine the amount of revenue from CMSC that should be included in
the day-ahead intertie offer guarantee calculation.

For any interval, there are six possible orderings of the amount of an
importer’s capacity that may be included in the schedule of record, the
real-time unconstrained schedule and the real-time constrained schedule.
Table 0-1: Ordering of Importer’s Capacity and Day-Ahead Intertie Offer
Guarantee Component 3 summarizes the six possible orderings and the
inclusion of Component 3 in the day-ahead intertie offer guarantee
calculation.

For the purposes of determining the applicable CMSC in Component 3,
the offer price is subject to Section 3.5.6.
Table 0-1: Ordering of Importer’s Capacity and Day-Ahead Intertie Offer Guarantee
Component 3
Scenario
1
2
3
4
5
6
Ordering
DQSI >= MQSI >= DA_DQSI
MQSI >= DQSI >= DA_DQSI
DQSI > DA_DQSI > MQSI
MQSI > DA_DQSI > DQSI
DA_DQSI >= DQSI > MQSI
DA_DQSI >= MQSI > DQSI
Component 3 - CMSC
Included?
N
N
Y (Partial CMSC)
Y (Partial CMSC)
Y (All CMSC)
Y (All CMSC)
Component 3 is calculated as follows :
DA_IOG
_COMP3k,hi,t
Income received from real time congestion management settlement
= credits (CMSC) for the importer’s schedule of record delivered in
real-time over the interval
Component 3 is only calculated when the real-time CMSC for the same interval is a value other than
zero.
Scenario 1
DA_IOG
_COMP3k,hi,t
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Scenario 2
DA_IOG
_COMP3k,hi,t
= 0
Scenario 3
DA_IOG
_COMP3k,hi,t
=
Scenario 4
DA_IOG
_COMP3k,hi,t
=
Scenario 5
DA_IOG
_COMP3k,hi,t
=
Congestion management settlement credit calculated as per Section
3.5.
=
Congestion management settlement credit calculated as per Section
3.5.
Scenario 6
DA_IOG
_COMP3k,hi,t
Intertie Offer Guarantee Settlement
3.8A.3
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The cumulative intertie offer guarantee settlement credits payable to a market
participant for any and all applicable settlement hours in the real-time market for
an energy billing period shall be adjusted by the IESO in accordance with section
3.8A.4 to nullify such credits where:
3.8A.3.1
that market participant has submitted one or more energy offers and
one or more energy bids as contemplated by section 3.5.8.1 of
Chapter 7 for the same dispatch interval; or
3.8A.3.2
the market assessment unit has determined that the market participant
has an agreement or arrangement to share the intertie offer guarantee
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settlement credit with one or more other market participants and they
have submitted one or more energy offers and one or more energy bids
as contemplated by section 3.5.8.1 of Chapter 7 for the same dispatch
interval; or
3.8A.3.3
the market participant has one or more import transactions in the
schedule of record at an intertie metering point and where:


the same import transaction is subsequently scheduled in the
corresponding metering interval of the corresponding settlement
hour in the real-time market; and

the market participant submits one or more schedule of record
and/or real-time energy bids as contemplated by section 3.5.8.1 of
Chapter 7 for the same dispatch interval;
and, at least one of such energy offers and one of such energy bids is scheduled.
For certainty, any market participant shall have recourse to the dispute resolution
provisions of section 2 of Chapter 3 if it believes that the market assessment unit
did not have reasonable grounds for making the determination that the market
participant had any such agreement or arrangement with another market
participant as described in section 3.8A.3.2.
3.8A.4
The combined day-ahead and real-time intertie offer guarantees and intertie offer
guarantee settlement credit offset (“IOG Offset”) process is as follows. Any
adjustment made by the IESO under section 3.8A.3 shall be applied with respect
to any export transaction in the constrained schedule for market participant ‘k’ in
each settlement hour ‘h’ for which market participant ‘k’ is entitled to receive a
real-time or day-ahead intertie offer guarantee settlement credit meeting the
conditions set out in section 3.8A.3. The total amount offset shall be limited by
the cumulative quantity of the export transactions expressed in the constrained
schedule for that settlement hour and shall not exceed the total combined real-time
and day-ahead intertie offer guarantee settlement credits received for the
settlement hour. Where the cumulative quantity of the export transactions
expressed in the constrained schedule for the settlement hour is less than the
cumulative quantity of imports triggering real-time and day-ahead intertie offer
guarantee settlement credits for that same settlement hour, the real-time and dayahead intertie offer guarantee settlement credits will be offset in ascending order
from the import transaction with the smallest real-time and/or smallest day-ahead
intertie offer guarantee settlement rate to the import transaction attracting the
largest real-time and/or largest day-ahead intertie offer guarantee settlement rate
and only up until the point at which the total quantity of import transactions
equals the total quantity of export transactions, and may be expressed as described
in the general rule that follows.
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The offset process described in this section shall apply to:

real-time intertie offer guarantee settlement credits meeting the criteria of
section 3.8A.3.1; or

real-time intertie offer guarantee settlement credits or day-ahead intertie
offer guarantee settlement credits meeting the criteria of section 3.8A.3.3.
For the purposes of this calculation all applicable real-time or day-ahead intertie
offer guarantee settlement credits meeting the criteria described above, attributable
to market participant ‘k’ for settlement hour ‘h’ shall be arranged in ascending
order by rate (dollars per megawatt per transaction), and subject to the following
decision rules:
a. [Intentionally left blank - section deleted]
b. Where a day-ahead intertie offer guarantee settlement credit is associated with
the import transaction, but no real-time intertie offer guarantee settlement
credit was applicable, the day-ahead intertie offer guarantee settlement credit
will be included;
c. Where a real-time intertie offer guarantee settlement credit is associated with
the import transaction, but no day-ahead intertie offer guarantee settlement
credit is applicable, the real-time intertie offer guarantee settlement credit will
be included;
The ordering of these settlement amounts is described in terms of a general rule as
follows:
Let MIk,ht [N,13] be an N by 13 matrix of N pairs of import quantities scheduled
for injection by market participant ‘k’ in the real-time dispatch schedule and/or
the constrained schedule from the DACP schedule of record in the settlement
hour ‘h’ (DA_DQSIk,hi and/or DQSIk,h i as the case may be) paired with the
corresponding day-ahead intertie offer guarantee, the component of the real-time
intertie offer guarantee settlement credit, DA-IOG rate, RT-IOG rate, DA Offset
DQSW, DA-Offset Flag, Settlement rate, (gross) IOG$, RT Offset DQSW, IOG
Offset $, (net) IOG $ for all intertie metering points ‘i’ arranged in ascending
order by settlement rate in each row. Columns 1 through 4 are original inputs to
the matrix, while columns 5 through 13 are derived.
The general rules to settle IOG are as follows:
Note: MIk,h [N,13] matrix has been transposed such that the columns are on the rows.
Event Type
General Rule
Matrix MIk,h [Row ‘n’, Column 1]
DA_DQSIk,hi
Associated with the settlement amount in column 3
Matrix MIk,h [Row ‘n’, Column 2]
DQSIk,hi
Associated with the settlement amount in column 3
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and 4
Matrix MIk,h [Row ‘n’, Column 3]
DA_IOGk,hi
Matrix MIk,h [Row ‘n’, Column 4]
RT_IOGk,hi
Matrix MIk,h [Row ‘n’, Column 5]
MIk,h [n,5] {DA_IOG_RATEk,hi}=
DA_IOGk,hi / MIN(DA_DQSIk,hi, DQSIk,hi )
Matrix MIk,h [Row ‘n’, Column 6]
MIk,h [n,6] {RT_IOG_RATE k,hi}=
RT_IOGk,hi / DQSIk,hi
Matrix MIk,h [Row ‘n’, Column 7]
MIk,h [n,7] {DA_OFFSET_DQSWk,hi}
Matrix MIk,h [Row ‘n’, Column 8]
MIk,h [n,8] { DA_OFFSET_FLAGk,hi } = “Y” or “N”
Such that:
DA_OFFSET_FLAGk,hi = “Y”
when
{DA_OFFSET_DQSWk,hi}>= 50% of
MIN{DA_DQSIk,hi,DQSIk,hi }
Matrix MIk,h [Row ‘n’, Column 9]
MIk,h [n,9] {IOG_SETTLEMENT_RATEk,hi} =
RT_IOG_RATEk,hi if DA_OFFSET_FLAGk,hi = “Y”;
OR
MIk,hi [n,9] {IOG_SETTLEMENT_RATEk,hi} =
MAX[DA_IOG_RATE k,hi , RT_IOG_RATE k,hi ] if
DA_OFFSET_FLAGk,hi = “N”;
Subject to:
MIk,h [n,9] >= MIk,h [n-1,9];
MIk,h [1,9] = MIN[MIk,h [1 to N,9]];
[MIk,h [1 to N,9]] <> 0
Matrix MIk,h [Row ‘n’, Column 10]
MIk,hi [n,10] {IOG$k,hi} =
the DA_IOG$k,hi or RT_IOG$k,hi associated with the
Settlement Rate k,hi (i.e. RT_IOG_RATEk,hi or
MAX(DA_IOG_RATEk,hi ,RT_IOG_RATEk,hi))
Matrix MIk,h [Row ‘n’, Column 11]
MIk,h [n,11] {RT_OFFSET_DQSW k,hi }
Matrix MIk,h [Row ‘n’, Column 12]
MIk,h [n,12] {IOG_OFFSETk,hi }
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Matrix MIk,h [Row ‘n’, Column 13]
MIk,h [n,13] {Net_IOGk,hi } =
MIk,h [n,10] {IOG$k,hi} - MIk,hi [n,12]
{IOG_OFFSETk,hi }
The outcomes from the general rules are as follows
A
B
C
D
Event Type
An import
transaction
scheduled day
ahead receiving a
DA-IOG but no
RT-IOG and is not
offset Day Ahead
An import
transaction
scheduled day
ahead receiving a
DA-IOG but no
RT-IOG and is
offset Day Ahead
An import
transaction
scheduled only in
the real-time and
receiving a RTIOG but no DAIOG
An import
transaction
scheduled both in
the day ahead and
in the real-time
receiving DA-IOG
and RT-IOG.
Matrix MIk,h
[Row ‘n’,
Column 1]
DA_DQSIk,hi
DA_DQSIk,hi
NULL
DA_DQSIk,hi
Matrix MIk,h
[Row ‘n’,
Column 2]
DQSIk,hi
DQSIk,hi
DQSIk,hi
DQSIk,hi
Matrix MIk,h
[Row ‘n’,
Column 3]
DA_IOGk,hi
DA_IOGk,hi
DA_IOGk,hi
DA_IOGk,hi
Matrix MIk,h
[Row ‘n’,
Column 4]
RT_IOGk,hi
RT_IOGk,hi
= NULL
= NULL
Matrix MIk,h
[Row ‘n’,
Column 5]
{DA_IOG_RATEk,
i
h}
Matrix MIk,h
[Row ‘n’,
Column 6]
= NULL
RT_IOGk,hi
RT_IOGk,hi
{DA_IOG_RATE
i
k,h }
NULL
{DA_IOG_RATE
i
k,h }
{RT_IOG_RATEk,h
i
}=
{RT_IOG_RATEk
i
,h }=
{RT_IOG_RATEk,h
i
}
{RT_IOG_RATEk
i
,h }
NULL
NULL
Matrix MIk,h
[Row ‘n’,
Column 7]
{DA_OFFSET_DQS
Wk,hi} = 0
{DA_OFFSET_DQ
SWk,hi} > 0
NULL
{DA_OFFSET_DQ
SWk,hi} >= 0
Matrix MIk,h
[Row ‘n’,
{DA_OFFSET_FLA
Gk,hi } = “N”
{DA_OFFSET_FLA
Gk,hi } = “Y”
NULL
{DA_OFFSET_FLA
Gk,hi } = “Y” or “N”
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A
B
C
D
An import
transaction
scheduled day
ahead receiving a
DA-IOG but no
RT-IOG and is not
offset Day Ahead
An import
transaction
scheduled day
ahead receiving a
DA-IOG but no
RT-IOG and is
offset Day Ahead
An import
transaction
scheduled only in
the real-time and
receiving a RTIOG but no DAIOG
An import
transaction
scheduled both in
the day ahead and
in the real-time
receiving DA-IOG
and RT-IOG.
Matrix MIk,h
[Row ‘n’,
Column 9]
MIk,h [n,9]
{IOG_SETTLEME
NT_RATEk,hi} =
{DA_IOG_RATEk,
i
h}
NULL
MIk,h [n,9]
{IOG_SETTLEME
NT_RATEk,hi} =
{RT_IOG_RATEk,h
i
}
MIk,h [n,9]
{IOG_SETTLEM
ENT_RATEk,hi} =
{RT_IOG_RATEk
i
,h } or
MAX(DA_IOG_R
ATEk,hi ,
RT_IOG_RATEk,h
i
)
Matrix MIk,h
[Row ‘n’,
Column 10]
MIk,h [n,10]
{IOG$k,hi} =
NULL
MIk,h [n,10]
{IOG$k,hi} =
MIk,h [n,10]
{IOG$k,hi} =
RT_IOG$k,hi
{RT_IOG$k,hi} or
MAX(DA_IOG$k,
hi, RT_IOG$k,hi)
Matrix MIk,h
[Row ‘n’,
Column 11]
MIk,h [n,11]
{RT_OFFSET_DQS
W k,hi } >= 0
NULL
MIk,h [n,11]
{RT_OFFSET_DQS
W k,hi } >= 0
MIk,h [n,11]
{RT_OFFSET_DQ
SW k,hi } >= 0
Matrix MIk,h
[Row ‘n’,
Column 12]
MIk,h [n,12]
{IOG_OFFSETk,hi }
>= 0
NULL
MIk,h [n,12]
{IOG_OFFSETk,hi }
>= 0
MIk,h [n,12]
{IOG_OFFSETk,hi }
>= 0
Matrix MIk,h
[Row ‘n’,
Column 13]
MIk,h [n,13]
{Net_IOGk,hi } =
NULL
MIk,h [n,13]
{Net_IOGk,hi } =
MIk,h [n,13]
{Net_IOGk,hi } =
MIk,h [n,10]
{IOG$k,hi} - MIk,h
[n,12]
{IOG_OFFSETk,hi }
MIk,h [n,10]
{IOG$k,hi} - MIk,h
[n,12]
{IOG_OFFSETk,hi }
Event Type
Column 8]
DA_IOG$k,hi
MIk,h [n,10]
{IOG$k,hi} - MIk,h
[n,12]
{IOG_OFFSETk,hi }
The Day-Ahead IOG rate (DA_IOG RATEk,hi) column 5, at an intertie metering point ‘i’ in settlement
hour ‘h’ is calculated using the day ahead constrained import schedule value in columns 1
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(DA_DQSIk,h ) and real time import schedule value in column 2 (DQSIk,h ) and the DA_IOGk,hi value
in Column 3 of each unique row ‘n’ in matrix MIk,h as follows:
i
DA_IOG RATEk,hi
i
=
The Real-Time IOG rate (RT_IOG_RATEk,hi) column 6 at an intertie metering point ‘i’ in settlement
hour ‘h’ is calculated using the real-time constrained import schedule of column 2 and the RT_IOGk,hi
value of Column 4 of each unique row ‘n’ in matrix MIk,h as follows:
RT_IOG RATEk,hi
=
The matrix is arranged in ascending order on DA_IOG_RATEk,hi (Column 5) from the lowest rate to
the highest rate.
The day-ahead export schedule quantity offset by market participant ‘k’ at an intertie metering point
‘i’ in settlement hour ‘h’ (DA_OFFSET_DQSWk,hi) column 7 is calculated using the day ahead
constrained import schedule value in columns 1 (DA_DQSIk,hi ), real time import schedule value in
column 2 (DQSIk,hi) and the day ahead constrained export schedule value for the market participant
for an hour as follows:
DA_DQSW_REMk,h
=
DA_OFFSET_DQSWk,hi
=
Where:
I
=
set of all intertie metering points ‘i’
n
=
The number of day ahead import transactions with DA_OFFSET_DQSW
at each pass.
The day-ahead IOG offset flag (DA_OFFSET FLAGk,hi) column 8 at an intertie metering point ‘i’ in
settlement hour ‘h’ is calculated using the values in column 7 DA_OFFSET_DQSWk,hi , columns 1
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(DA_DQSIk,h ) and real time import schedule value in column 2 (DQSIk,h ) of each unique row ‘n’ in
matrix MIk,h as follows:
i
k,hi
i
=
The IOG offset rate (IOG_SETTLEMENT_RATEk,hi) column 9 at an intertie metering point ‘i’ in
settlement hour ‘h’ is calculated using the values in Column 5 (DA_IOG_RATEk,hi) and Column 6
(RT_IOG_RATEk,hi) of each unique row ‘n’ in matrix MIk,h as follows:
IOG_SETTLEMENT_RATEk,hi =
Subject to:
MIk,h [n,9] >= MIk,h [n-1,9];
MIk,h [1,9] = MIN[MIk,h [1 to N,9]];
[MIk,h [1 to N,9]] <> 0
The IOG dollar amount (IOG$k,hi) column 10 at an intertie metering point ‘i’ in settlement hour ‘h’ is
the IOG dollar amount associated with the rate used in Column 9 (IOG_SETTLEMENT_RATEk,hi).
The matrix is arranged in ascending order of (IOG_SETTLEMENT_RATEk,hi) (Column 9) from the
lowest rate to the highest rate.
The real-time export schedule quantity offset by market participant ‘k’ at an intertie metering point
‘i’ in settlement hour ‘h’ (RT_OFFSET_DQSWk,hi) column 11 is calculated using the real-time
constrained import schedule values in column 2 (DQSIk,hi ) and the real time constrained export
schedule value for the market participant for an hour as follows:
RT_DQSW_REMk,h
=
RT_OFFSET_DQSWk,hi
=
Where:
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I
=
set of all intertie metering points ‘i’
n
=
The number of real time import transactions with RT_OFFSET_DQSW at
each pass.
The IOG offset settlement amount for market participant ‘k’ at an intertie metering point ‘i’ in
settlement hour ‘h’ (IOG_OFFSETk,hi) column 12 is calculated using column 9
(IOG_SETTLEMENT_RATEk,hi ) and column 11(RT_OFFSET_DQSWk,hi ) as follows:
IOG_OFFSETk,hi
=
The IOG settlement amount for market participant ‘k’ at an intertie metering point ‘i’ in metering
settlement hour ‘h’ (NET_IOGk,hi,) column 13 is calculated using column10 (IOG$k,hi) and column 12
(IOG_OFFSETk,hi) as follows:
NET_IOGk,hi
=
3.8A.5
[Intentionally left blank - section deleted]
3.8A.6
[Intentionally left blank - section deleted]
Day-Ahead Intertie Offer Guarantee Adjustments
3.8A.7
[Intentionally left blank - section deleted]
3.8A.8
[Intentionally left blank – section deleted]
3.8A.9
[Intentionally left blank – section deleted]
3.8B
Day Ahead Import Failure Charge
3.8B.1
The IESO shall apply the day-ahead import failure charge specified in section
3.8B.2 to a market participant for any quantity of energy scheduled for injection
at an intertie metering point scheduled in the schedule of record where:
3.8B.1.1
Page 38 of 164
the market participant fails either in whole or in part to schedule a
dispatch quantity scheduled for injection in the pre-dispatch schedule
in the corresponding metering interval of the corresponding settlement
hour at the same intertie metering point;
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3.8B.2
3.8B.1.2
the IESO has not determined, nor has the market participant
demonstrated to the satisfaction of the IESO, that the failure is due to
bona fide and legitimate reasons as described in chapter 7,
section 7.5.8B of these market rules; and
3.8B.1.3
the import transaction is not part of a day-ahead linked wheel.
For all import transactions scheduled in the schedule of record and meeting the
criteria of section 3.8B.1, the day-ahead import failure charge shall be formulated
as follows:
Let OP(P,Q,B) be a profit function of Price (P), Quantity (Q) and an N by 2
matrix (B) of offered price-quantity pairs:
s*
OP(P, Q, B)  P  Q   Pn  (Q n  Q n 1 )  (Q  Qs* )  Ps* 1
n 1
Using matrix notation for parameter ' B' this may be expressed as follows :
s*
OP(P, Q, B)  P  Q   Bn,1 Bn,2   Bn - 1,2  Q  Bs*,2  Bs * 1,1
n1
Where:
s* is the highest indexed row of B such that Qs*  Q  Qn and where, Q0=0
‘P’ is PD_EMPhm,t: pre-dispatch projected energy market price applicable to all
delivery points 'm' in the Ontario zone in metering interval 't' of settlement hour
'h';
‘Q’ is DA_ISDk,hi,t as defined below; and
‘B’ is DA_BEk,hi,t: energy offers submitted into the schedule of record,
represented as an N by 2 matrix of price-quantity pairs for each market participant
‘k’ at intertie metering point ‘i’ during metering interval ‘t’ of settlement hour ‘h’
arranged in ascending order by the offered price in each price-quantity pair where
offered prices are in column 1 and offered quantities are in column 2; or
‘B’ is PD_BEk,hi,t: energy offers submitted in pre-dispatch, represented as an N by
2 matrix of price-quantity pairs for each market participant ‘k’ at intertie
metering point ‘i’ during metering interval ‘t’ of settlement hour ‘h’ arranged in
ascending order by the offered price in each price-quantity pair where offered
prices are in column 1 and offered quantities are in column 2.
the offer matrix of price-quantity pairs for the applicable import transaction that
was submitted by market participant ‘k’ and scheduled in the schedule of record
during metering interval ‘t’ for settlement hour ‘h’ of the real-time trading day
and,
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i,t
Let DA_ISDk,h be the day-ahead import scheduling deviation quantity calculated
for market participant ‘k’ at intertie metering point ‘i’ during metering interval ‘t’
of settlement hour ‘h’ as determined by the formula:
DA import scheduling deviation
quantity (DA_ISDk,hi,t)
=
MAX (day-ahead import transaction quantity –
pre-dispatch import transaction quantity, 0)
DA_ISDk,hi,t
=
MAX (DA_DQSIk,hi,t – PD_DQSIk,hi,t, 0)
Where:
DA_DQSIk,hi,t is the schedule of record quantity
scheduled for injection by market participant ‘k’
for an import transaction at intertie metering point
‘i’ during metering interval ‘t’ of settlement hour
‘h’; and
PD_DQSIk,hi,t is the pre-dispatch quantity
scheduled for injection by market participant ‘k’
at intertie metering point ‘i’ during metering
interval ‘t’ of settlement hour ‘h’
Let XPD_BE k,hi,t be the function which calculates the area under the curve created
by an n x 2 matrix (B) of offered price-quantity pairs:
where matrix (B) is energy offers submitted in pre-dispatch, represented as an N
by 2 matrix of price-quantity pairs for each market participant ‘k’ at intertie
metering point ‘i’ during metering interval ‘t’ of settlement hour ‘h’ arranged in
ascending order by the offered price in each price quantity pair where offered
prices ‘P’ are in column 1 and offered quantities ‘Q’ are in column 2
Let XDA_BEk,hi,t be the function which calculates the area under the curve created
by an n x 2 matrix (B) of offered price-quantity pairs:
where matrix (B) is energy offers submitted in the schedule of record, represented as an N by
2 matrix of price-quantity pairs for each market participant ‘k’ at intertie
metering point ‘i’ during metering interval ‘t’ of settlement hour ‘h’ arranged in
ascending order by the offered price in each price quantity pair where offered
prices ‘P’ are in column 1 and offered quantities ‘Q’ are in column 2
Page 40 of 164
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Such that the day-ahead import failure charge for market participant ‘k’ during
settlement hour ‘h’ for all intertie metering points ‘i’ may be formulated with the
above components as follows:
DA_IFCk,h
=
For all intertie metering points and all metering intervals during the
settlement hour:
-1 x MINIMUM of:
[MAXIMUM of:
[[The sum of all revenues implied by each import transaction
valued at the pre-dispatch energy market price in the Ontario
zone for the difference in quantity scheduled in pre-dispatch
and the quantity scheduled in the schedule of record.
Minus:
Those costs represented through the offers for the import
transaction scheduled in the schedule of record]
or zero],
[MAXIMUM of:
[the pre-dispatch offer to increase quantity scheduled in predispatch to quantity scheduled day-ahead minus the dayahead offer to increase quantity scheduled in pre-dispatch to
quantity scheduled in the schedule of record]
or zero],
[day-ahead import scheduling deviation quantity times the
MAXIMUM of (zero or the pre-dispatch energy market price in the
Ontario zone)]]
DA_IFCk,h =
Where:
DA_BEk,hi,t are energy offers submitted into the schedule of record, represented as
an N by 2 matrix of price-quantity pairs for each market participant ‘k’ at intertie
metering point ‘i’ during metering interval ‘t’ of settlement hour ‘h’ arranged in
ascending order by the offered price in each price-quantity pair where offered
prices are in column 1 and offered quantities are in column 2;
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i,t
PD_BEk,h are energy offers submitted in pre-dispatch, represented as an N by 2
matrix of price-quantity pairs for each market participant ‘k’ at intertie metering
point ‘i’ during metering interval ‘t’ of settlement hour ‘h’ arranged in ascending
order by the offered price in each price-quantity pair where offered prices are in
column 1 and offered quantities are in column 2;
PD_EMPhm,t is the pre-dispatch projected energy market price applicable to all
delivery points 'm' in the Ontario zone in metering interval 't' of settlement hour
'h';
‘T’ is the set of all metering intervals ‘t’ in settlement hour ‘h’;
‘I’ is the set of all intertie metering points ‘i’.
3.8C
Real-Time Import and Real-Time Export Failure
Charges
3.8C.1
The real-time import failure charge and the real-time export failure charges
referred to in section 7.5.8B of Chapter 7 are settlement amounts that shall be
determined in sections 3.8C.2 and 3.8C.3 and in sections 3.8C.4 and 3.8C.5
respectively.
Real-time Import Failure Charge
3.8C.2
3.8C.3
The IESO shall assess a market participant with a real-time import failure charge
for any quantity of energy scheduled for injection at an intertie metering point in
the constrained pre-dispatch schedule where:
3.8C.2.1
the market participant fails either in whole or in part to schedule a
dispatch quantity for injection in the constrained real-time schedule in
the corresponding metering interval of the corresponding settlement
hour at the same intertie metering point; and,
3.8C.2.2
the IESO has not determined, nor has the market participant
demonstrated to the satisfaction of the IESO, that the failure was due
to bona fide and legitimate reasons as described in chapter 7,
section 7.5.8B.
For all import transactions scheduled in the constrained pre-dispatch schedule and
meeting the criteria set out in section 3.8C.2, the real-time import failure charge
shall be formulated as follows:
Let RT_ISDk,hi,t be the real-time import scheduling deviation quantity calculated
for market participant ‘k’ at intertie metering point ‘i’ during metering interval ‘t’
of settlement hour ‘h’ as determined by the formula:
Real-time Import
Scheduling
Page 42 of 164
=
MAX (pre-dispatch import transaction
quantity – real-time import transaction
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Deviation Quantity
RT_ISDk,hi,t
quantity, 0)
=
MAX (PD_DQSIk,hi,t - DQSIk,hi,t, 0)
such that the real-time import failure charge for market participant ‘k’ during
settlement hour ‘h’ for all intertie metering points‘i’ may be formulated with the
above components as follows:
RT_IFCk,h =
For all intertie metering points:
-1 x [MAXIMUM of:
[[The difference between: the real-time energy
market price in the Ontario zone adjusted by the
prevailing price bias adjustment factor for imports
in effect for the settlement hour minus the predispatch projected energy market price in the
Ontario zone
times :
real-time import scheduling deviation quantity.]
or zero, ]
subject to: a maximum value of the real-time import
scheduling deviation quantity times the maximum of the
real-time energy market price in the Ontario zone or zero]


RT_IFC k,h   (-1)  MIN MAX 0, (EMPh
I,T
m, t
 PB_IM h - PD_EMP h
t
m, t
)  RT_ISD k,h
i,t
, MAX(0, EMP
m, t
h
)  RT_ISD k,h
i,t

where:
PD_EMPhm,t is the pre-dispatch projected energy market price
applicable to all delivery points ‘m’ in the Ontario zone during
metering interval ‘t’ of settlement hour ‘h’;
EMPhm,t is the real-time 5-minute energy market price applicable to all
delivery points ‘m’ in the Ontario zone during metering interval ‘t’ of
settlement hour ‘h’;
PB_IMht is the price bias adjustment factor for import transactions in
effect during metering interval ‘t’ of settlement hour ‘h’;
‘I’ is the set of all intertie metering points ‘i’;
‘T’ is the set of all metering intervals in settlement hour ‘h’.
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Real-time Export Failure Charge
3.8C.4
3.8C.5
The IESO shall assess a market participant with a real-time export failure charge
for any quantity of energy scheduled for withdrawal at an intertie metering point
in the constrained pre-dispatch schedule where:
3.8C.4.1
the market participant fails either in whole or in part to schedule a
dispatch quantity for withdrawal in the constrained real-time schedule
in the corresponding metering interval of the corresponding settlement
hour at the same intertie metering point; and,
3.8C.4.2
the IESO has not determined, nor has the market participant
demonstrated to the satisfaction of the IESO, that the failure was due
to bona fide and legitimate reasons described in chapter 7,
section 7.5.8B.
For all export transactions scheduled in the constrained pre-dispatch schedule and
meeting the criteria set out in section 3.8C.4, the real-time export failure charge
shall be formulated as follows:
Let RT_ESDk,hi,t be the real-time export scheduling deviation quantity calculated
for market participant ‘k’ at intertie metering point ‘i’ during metering interval ‘t’
of settlement hour ‘h’ as determined by the formula:
Real-time Export Scheduling
Deviation Quantity
=
MAX (pre-dispatch export transaction
quantity – real-time export transaction
quantity, 0)
RT_ESDk,hi,t
=
MAX (PD_DQSWk,hi,t - DQSWk,hi,t, 0)
such that the real-time export failure charge for market participant ‘k’ during
settlement hour ‘h’ for all intertie metering points ‘i’ may be formulated with the
above components as follows:
RT_EFCk,h =
Page 44 of 164
For all intertie metering points:
-1 x [MAXIMUM of:
[[The difference between the pre-dispatch
projected energy market price in the Ontario zone
minus the real-time energy market price in the
Ontario zone adjusted by the prevailing price bias
adjustment factor for exports in effect for the
settlement hour]
times :
real-time export scheduling deviation quantity.]
or zero,]
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subject to: a maximum value of the:
real-time export scheduling deviation quantity times the
maximum of the pre-dispatch energy market price in the
Ontario zone or zero]


RT_EFC k,h   (-1)  MIN MAX 0, (PD_EMP h
I,T
m, t
- EMPh
m, t
 PB_EX h )  RT_ESD k,h
t
i,t
, MAX(0, PD_EMP
m, t
h
)  RT_ESD k,h
i,t

where:
PD_EMPhm,t is the pre-dispatch projected energy market price
applicable to all delivery points ‘m’ in the Ontario zone during
metering interval ‘t’ of settlement hour ‘h’
EMPhm,t is the real-time 5-minute energy market price applicable to all
delivery points ‘m’ in the Ontario zone during metering interval ‘t’ of
settlement hour ‘h’
PB_EXht is the price bias adjustment factor for export transactions in
effect during metering interval ‘t’ of settlement hour ‘h’
‘I’ is the set of all intertie metering points ‘i’
‘T’ is the set of all metering intervals in settlement hour ‘h’
3.8C.6
Where any import transaction scheduled in the pre-dispatch schedule of record
and subsequently scheduled at the same intertie metering point in the real-time
market is subject to both the day ahead import failure charge of section 3.8B and
the real-time import failure charge of section 3.8C, the market participant shall be
assessed with the greater of these charges but not both.
3.8C.7
The IESO shall determine, in accordance with the applicable market manual, any
applicable price bias adjustment factors to be used in the calculation of the realtime import failure charge and the real-time export failure charge. The price bias
adjustment factor shall compensate for systematic differences between the predispatch and real-time price.
3.8C.8
The IESO shall publish all applicable price bias adjustment factors in advance of
the settlement hours to which such factors apply.
3.8C.9
Until the IESO has the software capability to include the following settlement
amounts:

the real-time import failure charge (RT_IFCk,h); or

the real-time export failure charge (RT_EFCk,h),
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as hourly settlement amounts on preliminary settlement statements under section
6.5.2A.1, the IESO may include such settlement amounts in the preliminary
settlement statement issued in respect of the last trading day of a billing period.
The IESO shall give market participants 5 days notice of when such software
capability will be put into service. This section shall then cease to have effect and
shall be noted as “[Intentionally left blank – section deleted]”.
3.8D
Day Ahead Export Failure Charge
3.8D.1
The IESO shall apply the day-ahead export failure charge specified in section
3.8D.2 to a market participant for any quantity of energy scheduled for
withdrawal at an intertie metering point scheduled in the schedule of record
where:
3.8D.2
3.8D.1.1
the market participant fails either in whole or in part to schedule a
dispatch quantity scheduled for withdrawal in the pre-dispatch
schedule in the corresponding metering interval of the corresponding
settlement hour at the same intertie metering point;
3.8D.1.2
the IESO has not determined, nor has the market participant
demonstrated to the satisfaction of the IESO, that the failure is due to
bona fide and legitimate reasons as described in chapter 7,
section 7.5.8B; and
3.8D.1.3
the export transaction is not part of a day-ahead linked wheel.
For all export transactions scheduled in the schedule of record and meeting the
criteria of section 3.8D.1, the day-ahead export failure charge shall be formulated
as follows:
Let OP(P,Q,B) be a profit function of Price (P), Quantity (Q) and an N by 2
matrix (B) of offered price-quantity pairs:
s*
OP(P, Q, B)  P  Q   Pn  (Q n  Q n 1 )  (Q  Qs* )  Ps* 1
n 1
Using matrix notation for parameter ' B' this may be expressed as follows :
s*
OP(P, Q, B)  P  Q   Bn,1 Bn,2   Bn - 1,2  Q  Bs*,2  Bs * 1,1
n1
Where:
s* is the highest indexed row of B such that Qs*  Q  Qn and where, Q0=0
‘P’ is PD_EMPhm,t: pre-dispatch projected energy market price applicable to all
delivery points 'm' in the Ontario zone in metering interval 't' of settlement hour
'h';
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‘Q’ is DA_ESDk,h as defined below; and
i,t
‘B’ is DA_BLk,hi,t: energy bids submitted into the schedule of record, represented
as an N by 2 matrix of price-quantity pairs for each market participant ‘k’ at
intertie metering point ‘i’ during metering interval ‘t’ of settlement hour ‘h’
arranged in ascending order by the offered price in each price quantity pair where
offered prices ‘P’ are in column 1 and offered quantities ‘Q’ are in column 2; or
‘B’ is PD_BLk,hi,t: energy bids submitted in pre-dispatch, represented as an N by 2
matrix of price-quantity pairs for each market participant ‘k’ at delivery point ‘m’
during metering interval ‘t’ of settlement hour ‘h’ arranged in ascending order by
the offered price in each price quantity pair where offered prices ‘P’ are in
column 1 and offered quantities ‘Q’ are in column 2
the offer matrix of price-quantity pairs for the applicable export transaction that
was submitted by market participant ‘k’ and scheduled in the schedule of record
during metering interval ‘t’ for settlement hour ‘h’ of the real-time trading day
and,
Let XDA_BL k,hi,t be the function which calculates the area under the curve
created by an n x 2 matrix (B) of offered price-quantity pairs:
where matrix (B) is energy bids submitted into the schedule of record, represented
as an N by 2 matrix of price-quantity pairs for each market participant ‘k’ at
intertie metering point ‘i’ during metering interval ‘t’ of settlement hour ‘h’
arranged in ascending order by the offered price in each price quantity pair where
offered prices ‘P’ are in column 1 and offered quantities ‘Q’ are in column 2
Let XPD_BL k,hi,t be the function which calculates the area under the curve
created by an n x 2 matrix (B) of offered price-quantity pairs:
where matrix (B) energy bids submitted in pre-dispatch, represented as an N by 2
matrix of price-quantity pairs for each market participant ‘k’ at intertie metering
point ‘i’ during metering interval ‘t’ of settlement hour ‘h’ arranged in ascending
order by the offered price in each price quantity pair where offered prices ‘P’ are
in column 1 and offered quantities ‘Q’ are in column 2
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Such that the day-ahead export failure charge for market participant ‘k’ during
settlement hour ‘h’ for all intertie metering points ‘i’ may be formulated with the
above components as follows:
DA_EFCk,h
=
For all intertie metering points and all metering intervals during the
settlement hour:
-1 x MINIMUM of:
[MAXIMUM of:
[-1 x [The sum of all revenues implied by each export
transaction valued at the pre-dispatch energy market price in
the Ontario zone for the difference in quantity scheduled in
pre-dispatch and the quantity scheduled in the schedule of
record.
Minus:
Those costs represented through the offers for the export
transaction scheduled in the schedule of record]
or zero],
[MAXIMUM of:
[the day-ahead bid to increase quantity scheduled in predispatch to quantity scheduled day-ahead minus the predispatch bid to increase quantity scheduled in pre-dispatch to
quantity scheduled in the schedule of record]
or zero]
MAXIMUM of (zero or the day-ahead bid to increase quantity
scheduled in pre-dispatch to quantity scheduled in the schedule of
record)]
DA_EFCk,h =
Where:
DA_BLk,hi,t are energy bids submitted into the schedule of record, represented as
an N by 2 matrix of price-quantity pairs for each market participant ‘k’ at intertie
metering point ‘i’ during metering interval ‘t’ of settlement hour ‘h’ arranged in
ascending order by the offered price in each price quantity pair where offered
prices ‘P’ are in column 1 and offered quantities ‘Q’ are in column 2;
Page 48 of 164
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i,t
PD_BLk,h are energy bids submitted in pre-dispatch, represented as an N by 2
matrix of price-quantity pairs for each market participant ‘k’ at intertie metering
point ‘i’ during metering interval ‘t’ of settlement hour ‘h’ arranged in ascending
order by the offered price in each price quantity pair where offered prices ‘P’ are
in column 1 and offered quantities ‘Q’ are in column 2;
PD_EMPhm,t is the pre-dispatch projected energy market price applicable to all
delivery points 'm' in the Ontario zone in metering interval 't' of settlement hour
'h';
‘T’ is the set of all metering intervals ‘t’ in settlement hour ‘h’;
‘I’ is the set of all intertie metering points ‘i’.
3.8E
Day Ahead Linked Wheel Failure Charge
3.8E.1
The IESO shall apply the day-ahead linked wheel failure charge specified in
section 3.8E.2 to a market participant for any quantity of energy scheduled for a
linked wheel at an intertie metering point scheduled in the schedule of record
where:
3.8E.2
3.8E.1.1
the market participant fails either in whole or in part to schedule a
dispatch quantity scheduled for a linked wheel in the pre-dispatch
schedule in the corresponding metering interval of the corresponding
settlement hour at the same intertie metering point; and,
3.8E.1.2
the IESO has not determined, nor has the market participant
demonstrated to the satisfaction of the IESO, that the failure is due to
bona fide and legitimate reasons as described in chapter 7,
section 7.5.8B.
For all linked wheel transactions scheduled in the schedule of record and meeting
the criteria of section 3.8E.1, the day-ahead linked wheel failure charge shall be
formulated as follows:
Day-ahead linked wheel
scheduling deviation
(DA_LWSDk,hi,t)
=
MAX[(day-ahead import – hour-ahead predispatch import), (day-ahead export – hourahead pre-dispatch export)]
DA_LWSDk,hi,t
=
MAX[(DA_DQSIk,hi,t - PD_DQSIk,hi,t ),
(DA_DQSWk,hi,t - PD_DQSWk,hi,t )]
Where:
DA_DQSIk,h i,t is schedule of record quantity
scheduled for injection by market participant
‘k’ at delivery point ‘m’ during metering
interval ‘t’ of settlement hour ‘h’;
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i,t
PD_DQSIk,h is the pre-dispatch constrained
quantity scheduled for injection by market
participant ‘k’ at intertie metering point ‘i’
during metering interval ‘t’ of settlement hour
‘h’;
DA_DQSWk,h i,t is the schedule of record
quantity scheduled for withdrawal by market
participant ‘k’ at delivery point ‘m’ during
metering interval ‘t’ of settlement hour ‘h’;
and
PD_DQSWk,h i,t is the pre-dispatch
constrained quantity scheduled for withdrawal
by market participant ‘k’ at intertie metering
point ‘i’ during metering interval ‘t’ of
settlement hour ‘h’
Page 50 of 164
Day-ahead price spread
(DA_PSk,hi,t)
=
day-ahead constrained schedule intertie price
of the sink for the export transaction minus
day-ahead constrained intertie price of the
source for the import transaction
DA_PSk,hi,t
=
DA_ELMPk,hm,t – DA_ILMPk,hm,t
Where:
DA_ELMPhi,t is the day-ahead constrained
schedule intertie price at the intertie metering
point ‘i’ of the sink for the export transaction
during metering interval ‘t’ of settlement hour
‘h’; and
DA_ILMPhi,t is the day-ahead constrained
intertie price at the intertie metering point ‘i’
of the source for the import transaction during
metering interval ‘t’ of settlement hour ‘h’
Pre-dispatch price spread
(PD_PSk,hi,t)
=
pre-dispatch constrained schedule intertie
price of the sink for the export transaction –
pre-dispatch constrained intertie price of the
source for the import transaction
PD_PSk,hi,t
=
PD_ELMPhm,t – PD_ILMPhm,t
Where:
PD_ELMPhi,t is the pre-dispatch constrained
schedule intertie price at the intertie metering
point ‘i’ of the sink for the export transaction
during metering interval ‘t’ of settlement hour
‘h’; and
PD_ILMPhi,t is the pre-dispatch constrained
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intertie price at the intertie metering point ‘i’
of the source for the import transaction during
metering interval ‘t’ of settlement hour ‘h’
Such that the day-ahead linked wheel failure charge for market participant ‘k’
during settlement hour ‘h’ for all intertie metering points ‘i’ may be formulated
with the above components as follows:
DA_LWFCk,h
=
For all intertie metering points and all metering intervals
during the settlement hour:
-1 x [The day-ahead linked wheel scheduling deviation
quantity.
Multiplied by:
MAXIMUM of:
The day-ahead price spread less the pre-dispatch price
spread or zero],
Where:
‘T’ is the set of all metering intervals ‘t’ in settlement hour ‘h’;
‘I’ is the set of all intertie metering points ‘i’.
3.8E.3
If a day-ahead linked wheel failure charge specified in section 3.8E.2 applies to a
linked wheel where a real-time import failure charge specified in section 3.8C.3
and/or a real-time export failure charge specified in section 3.8C.5 applies to the
same linked wheel, a charge shall apply to the market participant equal to the
lesser of:
3.8E.3.1
and
the day-ahead linked wheel failure charge specified in section 3.8E.2;
3.8E.3.2 the sum of the real-time import failure charge and the real-time export
failure charge, both subject to the scheduling deviation quantity between the
schedule of record and the pre-dispatch schedule, as follows:
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i
RT_EFC_DALWk,h + RT_IFC_DALWk,h
i
Where:
RT_EFC_DALWk,hi
=
RT_EFC_DALWk,hi
=
RT_IFC_DALWk,hi
=
RT_IFC_DALWk,hi
=
real-time export failure charge for the export portion of the day-ahead
linked wheel for the quantity failure from day-ahead to Pre-dispatch
real-time import failure charge for the import portion of the day-ahead
linked wheel for the quantity failure from day-ahead to Pre-dispatch
3.8F Day-Ahead Generator Withdrawal Charge
3.8F.1
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The IESO shall apply the day-ahead generator withdrawal charge specified in
section 3.8F.2 to a market participant who was deemed to have accepted the dayahead production cost guarantee in accordance with Section 5.8.4 of Chapter 7 for
any quantity of energy scheduled for injection at a metering point scheduled in the
schedule of record where:
3.8F.1.1
the market participant withdraws their commitment scheduled in the
schedule of record in the corresponding metering interval of the
corresponding settlement hour at the same metering point; and,
3.8F.1.2
the IESO has not determined, nor has the market participant
demonstrated to the satisfaction of the IESO, that the failure is due to
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bona fide and legitimate reasons as described in chapter 7,
section 7.5.8B.
3.8F.2
The day-ahead generator withdrawal charge shall be formulated as follows:
If withdrawal notification is received at or 4 hours prior to the first withdrawal hour in real
time (PD – 4), then the Withdrawal Charge is calculated as follows:
DA_GWCk,start
=
event
Where:
n
=
the set of all metering intervals ‘t’ in settlement hour ‘h’ for the total
number of hours with a schedule of record that are withdrawn
start event
=
the set of hours with a contiguous schedule of record
If withdrawal notification is received later than PD-4 or if the market participant does not notify
the IESO of their intent to withdraw and does not inject for the hours committed in the schedule of
record, then the withdrawal charge is calculated as follows:
DA_GWCk,start
=
event
Where:
n
=
the set of all metering intervals ‘t’ in settlement hour ‘h’ for the total
number of hours with a schedule of record for the start event that are
withdrawn
start event
=
the set of hours with a contiguous schedule of record
3.9
3.9.1
Hourly Uplift Settlement Amounts
The hourly settlement amounts defined by the preceding provisions of this
section 3 will result in an hourly settlement deficit that shall be recovered from
market participants as a whole through the hourly uplift. The total hourly uplift
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settlement amount for settlement hour ‘h’ (“HUSAh”) shall be determined
according to the following equation:
HUSAh
=
K (NEMSCk,h +ORSCk,h+ CAPRSCk,h +CMSCk,h +TRSCk,h
+RT_IOGk,h + DA_IOGk,h) + TCRFh – K (CRSSDk,h + R
ORSSDk,r,h +DA_IFCk,h +RT_IFCk,h +RT_EFCk,h)
over all ‘k’ market participants
NEMSCk,h = net energy market settlement credit for market
participant ‘k’ in settlement hour ‘h’
ORSCk,h = operating reserve market settlement credit for market
participant ‘k’ in settlement hour ‘h’
CAPRSCk,h = capacity reserve market settlement credit for market
participant ‘k’ in settlement hour ‘h’
CMSCk,h = congestion management settlement credit for market
participant ‘k’ in settlement hour ‘h’
TRSCk,h = transmission rights settlement credit for market
participant ‘k’ in settlement hour ‘h’
RT_IOGk,h = real-time intertie offer guarantee settlement credit for
the market participant associated with that boundary entity ‘k’ in
settlement hour ‘h’
DA_IOGk,h = day-ahead intertie offer guarantee settlement credit for
the market participant ‘k’ in settlement hour ‘h’
DA_IFCk,h= day-ahead import failure charge for the market
participant ‘k’ in settlement hour ‘h’
RT_IFCk,h = real-time import failure charge for the market
participant ‘k’ in settlement hour ‘h’
RT_EFCk,h= real-time export failure charge for the market
participant ‘k’ in settlement hour ‘h’
TCRFh = transmission charge reduction fund contribution in
settlement hour ‘h’
CRSSDk,h = capacity reserve settlement debit for operating
deviations for market participant ‘k’ in settlement hour ‘h’
ORSSDk,r,h = operating reserve settlement debit for operating
deviations for class r reserve for market participant ‘k’ in settlement
hour ‘h’
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Where:
‘K’ is the set of all market participants ‘k’
‘R’ is the set of each class r of operating reserve
………………………………….
4.7B Real-Time Generation Cost Guarantee Payments
4.7B.1
The IESO shall determine on a per-start basis, for each generation facility that has
met the eligibility criteria for the real-time generation cost guarantee specified in
sections 2.2, 5.7 and 6.3A of Chapter 7, the following:
4.7B.1.1
the sum of the following revenues earned in each dispatch interval
during the period from synchronisation until the end of the minimum
generation block run-time or the end of the minimum run-time,
whichever comes first:
a. energy market prices multiplied by the sum of the applicable AQEI
and any applicable physical allocation data, for energy injected up
to and including the minimum loading point; and
b. any congestion management settlement credit payments resulting
from the facility being constrained on in order to meet its minimum
loading point; and
4.7B.1.2
the applicable combined guaranteed costs for the specified generation
facility for the start to which the revenues determined in accordance
with 4.7B.1.1 apply. The combined guaranteed costs will be
calculated by the IESO and will be the sum of the following costs:
a. fuel costs for start up and ramp to minimum loading point
submitted by the market participant as outlined in section
2.2B.1.4, and
b. the offer price associated with the real-time dispatch multiplied by
the energy injected, to a maximum of the minimum loading point,
during the period from the beginning of the minimum generation
block run-time until the earlier of:

the end of the period representing minimum generation block
run-time; or

the end of the period representing minimum run-time.
The other costs that are to be considered in addition to those specified
in the definition of combined guaranteed cost are:
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a. incremental operating costs for start up and ramp to minimum
loading point; and
b. incremental maintenance costs for start up and ramp to minimum
loading point;
where both of these additional cost components are reported to the
IESO in the manner specified in the applicable market manual.
4.7B.2
If for each eligible generation facility the sum of the revenues calculated pursuant
to section 4.7B.1.1 is greater than or equal to the combined guaranteed costs
referred to in section 4.7B.1.2, then no additional payments are made in respect of
the eligible generation facility by the IESO.
4.7B.3
If for each eligible generation facility the sum of the revenues calculated pursuant
to section 4.7B.1.1 is less than the combined guaranteed costs referred to in
section 4.7B.1.2, then the IESO shall calculate that difference and shall include
that amount in the form of additional payments made in respect of the eligible
generation facility.
4.7B.4
A real-time generation cost guarantee shall not be paid for a generation unit with
respect to costs incurred or revenues accrued by that generation unit for which a
day-ahead production cost guarantee applies under section 4.7D.
………………………………
4.7D Day-Ahead Generation Cost Guarantee Payments
4.7D.1
The IESO shall determine on a per-start basis, for each generation unit that has
met the criteria set out in chapter 7, sections 5.8.4, a day-ahead production cost
guarantee consisting of the following components:
a.
Component 1 is any shortfall in payment on the delivered real-time
dispatch of the schedule of record and will be based upon the real-time
revenue received for that amount of energy in comparison with the
value as represented in the generator’s day-ahead offer for incremental
energy and speed-no-load costs;
b. Component 2 is the value of arranging the delivery (where the realtime offer is less than the day-ahead offer), or any gain (where the
real-time offer is greater than the day-ahead offer)2 for the portion
2
Where the real-time offer is equal to the day-ahead offer, the value/gain is equal to zero (0).
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of schedule of record quantity that is not implemented in the realtime dispatch schedule;
c. Component 3 is any income from real-time energy congestion
management settlement credit (CMSC) included in a generator’s
schedule of record delivered in real-time and will be used to
reduce the day-ahead production cost guarantee payment;
d. Component 4 is any income from real-time operating reserve in a
generator’s schedule of record that was not dispatched in real-time
and will be used to reduce the day-ahead production cost guarantee
payment; and
e. Component 5 is the as-offered start-up cost (as-offered value of
bringing an off-line generator on-line to minimum loading point).
4.7D.2
The IESO shall determine the type of schedule and which components described
in Section 4.7D.1 are included in the day-ahead production cost guarantee, for
each generation unit, as follows:
a.
Variant 1: If the generation unit is not operating from the previous
dispatch day into the current dispatch day, the day-ahead production
costs guarantee calculation for the current dispatch day includes
Components 1 through 5. Variant 1 occurs when:

the generation unit is not operating at the end of the previous
DACP dispatch day (Day-1 HE 24 indicates off-line status); or

the generation unit is operating at the end of the previous
DACP dispatch day (Day-1, HE 24 indicates on-line status)
but it is not operating into the current DACP dispatch day (Day
0, HE 1 indicates off-line status); or

the generation unit is scheduled to start later in the
current DACP dispatch day.
b.
Variant 2: If the generation unit is operating from the previous
dispatch day into the current dispatch day, to complete its minimum
generation block run-time the day-ahead production costs guarantee
calculation for the current dispatch day includes Components 1
through 4 but does not include Component 5. The day-ahead
production costs guarantee calculation also includes a clawback for
Component 1 and Component 3
c.
Variant 3: If a generation unit is operating from the previous dispatch
day into the current dispatch day and has completed its minimum
generation block run-time in the previous dispatch day, the day-ahead
production costs guarantee calculation for the current dispatch day
includes Components 1 through 4 but does not include Component 5.
Variant 3 occurs when:
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
the generation unit is operating from the previous
DACP dispatch day (Day-1, HE 24 indicates on-line
status) into the current DACP dispatch day (Day 0, HE
1 indicates on-line status) and has completed its
MGBRT in the previous DACP dispatch day; or

the generation unit is operating from the previous
DACP dispatch day (Day-1, HE 24 indicates on-line
status) into the current DACP dispatch day, (Day 0, HE
1 indicates on-line status) and has not completed its
MGBRT and is scheduled in the current DACP dispatch
day for hours in excess of completing its MGBRT from
the previous DACP dispatch day. Variant 3 in the
current DACP dispatch day is only for the hours in
excess of completing the MGBRT hours for the start
from the previous DACP dispatch day.
4.7D.3
The IESO shall calculate the day-ahead production cost guarantee components 1
through 4 for each interval in the schedule of record where the generator is
injecting into the IESO-controlled grid.
4.7D.4
The IESO shall calculate the day-ahead production cost guarantee components
based on the type of schedule described in Section 4.7D.2.1 as follows:
Component 1 – Variants 1, 2 and 3
Component 1 includes any shortfall in payment for the minimum of the generator’s schedule of
record, real-time constrained schedule and the allocated quantity of energy injected based upon the
real-time revenue received for that amount of energy in comparison with the costs as represented in
the generator’s day-ahead offer. Component 1 is calculated as follows:
PCG_COMP1k,hm,t
=
PCG_COMP1k,hm,t
=
All day-ahead costs excluding as-offered start-up costs for the minimum
of the generator’s schedule of record, real-time constrained scheduled
and the allocated quantity of energy injected over the interval minus all
real-time revenue received over the interval for that amount of energy
Component 1 Clawback – Variant 2
Component 1 Clawback recovers the day-ahead production cost guarantee Component 1 paid up to
the minimum loading point for the remaining hours of MGBRT. Component 1 Clawback– Variant 2 is
calculated as follows:
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PCG_COMP1_CBk,hm,t
=
All day-ahead costs excluding as-offered start-up costs up to the
minimum of the generation facility’s minimum loading point and the
allocated quantity of energy injected over the interval minus all real-time
revenue received over the interval for that amount of energy
PCG_COMP1_CBk,hm,t =
Component 2 – Variants 1, 2 and 3
If, as a result of economic selection, a portion of the schedule of record is not implemented in the
real-time dispatch schedule, the day-ahead production cost guarantee:

Guarantees the cost of arranging the delivery if the real-time offer price is
less than the day-ahead offer price; or

Subtracts any gain where the real-time offer price is greater than the dayahead offer price.

In the absence of a forced de-rating or a scheduled de-rating, if there are
no real-time energy offers for any portion of the day-ahead constrained
schedule, the real-time energy offers for that portion of energy will be set
to MMCP (Maximum Market Clearing Price) for the purposes of
calculating Component 2.

If the real-time energy offers for any portion of the day-ahead constrained
schedule is below $0.00 $/MWh (i.e. negative), the real-time energy offers
for that portion of energy will be set to $0.00 $/MWh for the purposes of
calculating Component 2.

Component 2 is calculated as follows:

As-offered day-ahead costs excluding as-offered start-up costs for the
difference between:
PCG_COMP2k,hm,t

the minimum of the generator’s schedule of record, the de-rated
value of the generation facility or the maximum of the real-time
constrained schedule and the allocated quantity of energy
injected; and

the minimum of the generator’s schedule of record and the derated value of the generation facility
=
over the interval minus all real-time energy offers (with a minimum limit
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of zero) over the interval for that amount of energy

PCG_COMP2k,hm,t
=

Where:
Let XBE k,hm,t be the function which calculates the area under the curve created by an n x 2
matrix (B) of offered price-quantity pairs:
where matrix (B) is energy offers submitted in real-time, represented as an N by 2 matrix of
price-quantity pairs for each market participant ‘k’ at metering point ‘m’ during metering
interval ‘t’ of settlement hour ‘h’ arranged in ascending order by the offered price in each
price quantity pair where offered prices ‘P’ are in column 1 and offered quantities ‘Q’ are in
column 2
Let XDA_BEk,hm,t be the function which calculates the area under the curve created by an n x
2 matrix (B) of offered price-quantity pairs:
where matrix (B) is energy offers submitted in pre-dispatch, represented as an N by 2 matrix of pricequantity pairs for each market participant ‘k’ at metering point ‘m’ during metering interval ‘t’ of
settlement hour ‘h’ arranged in ascending order by the offered price in each price quantity pair where
offered prices ‘P’ are in column 1 and offered quantities ‘Q’ are in column 2
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c*
=
the highest indexed row of matrix XDA_BE k,hm,t such that Qc* ≤
min[DA_DQSIk,hm,t, OPCAPk,hm,t,max(DQSIk,hm,t,AQEIk,hm,t)] ≤ Qn and
where Qc*-1 = min[DA_DQSIk,hm,t, OPCAPk,hm,t,max(DQSIk,hm,t,AQEIk,hm,t)]
and where if Qc* < Qc*-1, let Qc* = Qc*-1
d*
=
the highest indexed row of matrix XDA_BE k,hm,t such that Qd* ≤
min[DA_DQSIk,hm,t, OPCAPk,hm,t] ≤ Qn
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p*
=
the highest indexed row of matrix XBE k,hm,t such that Qp* ≤
min[DA_DQSIk,hm,t, OPCAPk,hm,t,max(DQSIk,hm,t,AQEIk,hm,t)] ≤ Qn and
where Qp*-1 = min[DA_DQSIk,hm,t, OPCAPk,hm,t,max(DQSIk,hm,t,AQEIk,hm,t)]
and where if Qp* < Qp*-1, let Qp* = Qp*-1
s*
=
the highest indexed row of matrix XBE k,hm,t such that Qs* ≤
min[DA_DQSIk,hm,t, OPCAPk,hm,t] ≤ Qn
Component 3 – Variants 1, 2 and 3

The day-ahead production cost guarantee payment for a generator will be
reduced by the income received from real time congestion management
settlement credits (CMSC) for the generator’s schedule of record
delivered in real-time.

The generator’s schedule of record will be measured against both the realtime constrained schedule and the real-time unconstrained schedule to
determine the amount of revenue from congestion management settlement
credits that should be included in the day-ahead production cost guarantee
calculation.

For any interval, there are six possible orderings of the amount of a
generation facility’s capacity that may be included in the schedule of
record, the real-time constrained schedule and the real-time unconstrained
schedule. The table below summarizes the six possible orderings and the
inclusion of Component 3 in the day-ahead production cost guarantee
calculation.

For the purposes of determining the applicable CMSC in Component 3,
the offer price is subject to Section 3.5.6.
Table: Ordering of Generator’s Capacity and Day-Ahead Production Cost Guarantee
Component 3
Scenario
Ordering
1
2
3
4
5
6
DQSI >= MQSI >= DA_DQSI
MQSI >= DQSI >= DA_DQSI
DQSI > DA_DQSI > MQSI
MQSI > DA_DQSI > DQSI
DA_DQSI >= DQSI > MQSI
DA_DQSI >= MQSI > DQSI
Component 3 - CMSC
Included?
N
N
Y (Partial CMSC)
Y (Partial CMSC)
Y (All CMSC)
Y (All CMSC)
Component 3 is calculated as follows :
PCG_COMP3k,hm,t
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credits (CMSC) for the generator’s schedule of record delivered in realtime over the interval
Component 3 is only calculated when:
 the real-time CMSC (TDk,h,105m,t) for the same interval is a value other than zero; and
 the mathematical sign of (DQSI-MQSI) is equal to the mathematical sign of (AQEI-MQSI).
Scenario 1
PCG_COMP3k,hm,t
=
0
=
0
=
Congestion management settlement credit calculated as per Section
3.5.
=
Congestion management settlement credit calculated as per Section
3.5.
Scenario 2
PCG_COMP3k,hm,t
Scenario 3
PCG_COMP3k,hm,t =
Scenario 4
PCG_COMP3k,hm,t =
Scenario 5
PCG_COMP3k,hm,t
Scenario 6
PCG_COMP3k,hm,t
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Component 3 Clawback – Variant 2

Component 3 Clawback – Variant 2 recovers the congestion management
settlement credits (CMSC) paid up to the minimum loading point for the
remaining hours of MGBRT. Component 3 Clawback – Variant 2 is
calculated as follows :
PCG_COMP3_
CBk,
h
Income received from real time congestion management settlement
credits (CMSC) from the minimum of generation unit’s
minimum loading point and the allocated quantity of
energy injected to the real-time unconstrained schedule
over the interval
=
m,t
Component 3 Clawback - Variant 2 is only calculated when:

the schedule of record is not less than both the real-time constrained schedule and the
real-time unconstrained schedule and the event is a constrained-on event (i.e.
Scenarios 3 and 5);

the minimum loading point is greater than the real-time unconstrained schedule; and

Component 3 (PCG_COMP3k,hm,t) for the same interval is a value other than zero.
Scenario 1
PCG_COMP3_CBk,hm,t
=
0
=
0
Scenario 2
PCG_COMP3_CBk,hm,t
Scenario 3
In Scenario 3, the clawback (PCG_COMP3_CBk,hm,t) is only calculated when the minimum
loading point is greater than the real-time unconstrained schedule.
PCG_COMP3_CBk,hm,t =
Scenario 4
PCG_COMP3_CBk,hm,t
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Scenario 5
In Scenario 5, the clawback (PCG_COMP3_CBk,hm,t) is only calculated when the minimum loading
point is greater than the real-time unconstrained schedule.
PCG_COMP3_CB
k,h
m,t
=
Scenario 6
PCG_COMP3_CBk,hm,t
=
0
Component 4 – Variants 1, 2 and 3
The day-ahead production cost guarantee payment for a generator will be reduced by the income
received from real-time operating reserve for the generator’s schedule of record not dispatched in
real-time.
Component 4 is calculated as follows:
=
net income received from real-time operating reserve over the interval for
the generator’s schedule of record not dispatched in real-time
r1
=
30-minute operating reserve
r2
=
10-minute non-spinning operating reserve
r3
=
10-minute spinning operating reserve
30R_SQRORr1,k,hm,t
=
PCG_COMP4k,hm,t
PCG_COMP4
k,hm,t
=
Where:
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10NS_SQRORr2,k,hm,t
=
10S_SQRORr3,k,hm,t
=
x*
y*
z*
=
the highest indexed row of matrix BRr1,k,hm,t, such that QRx* ≤
max[0,min(DA_DQSIk,hm,t – MQSIk,hm,t, SQRORr1,k,hm,t)] ≤ QRn and where
QR0 = 0
=
the highest indexed row of matrix BRr2,k,hm,t such that QRy* ≤
max[0,min(DA_DQSIk,hm,t – MQSIk,hm,t - 30R_SQRORr1,k,hm,t,
SQRORr2,k,hm,t)] ≤ QRn and where QR0 = 0
=
the highest indexed row of matrix BRr3,k,hm,t, such that QRz* ≤
max[0,min(DA_DQSIk,hm,t – MQSIk,hm,t - 30R_SQRORr1,k,hm,t 10NS_SQRORr1,k,hm,t, SQRORr3,k,hm,t)] ≤ QRn and where QR0 = 0
……………………………
Component 5 – Variant 1
Component 5 is the as-offered start-up cost incurred to bring an off-line generation unit
through all the unit specific start-up procedures, including synchronization
and ramp up to minimum loading point. Component 5 is calculated as follows:
PCG_COMP5k,
h
m,t
=
As-offered start-up cost submitted by the market participant for
the DACP start event.
The rules for calculating Component 5 are as follows:

3
Scenario 1: If the generation unit achieves minimum loading point within the first
6 intervals3 of the start of the DACP scheduled period, the full as-offered start-up
cost is considered.
The duration of an interval is 5 minutes.
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
Scenario 2: If the generation unit achieves minimum loading point between the
start of the 7th interval and before the start of the 18th interval of the start of the
DACP scheduled period, the as-offered start-up cost is calculated on a fractional
basis. The as-offered start-up cost is calculated based on the number of 5-minute
intervals the resource takes to achieve minimum loading point between the start of
the 7th interval and before the start of the 18th interval.

Scenario 3: If the generation unit achieves minimum loading point after
the 17th interval of the start of the DACP scheduled period (i.e. 18th
interval and onwards), the as-offered start-up cost is not considered.
Scenario 1
PCG_COMP5k,hm,t
=
Scenario 2
PCG_COMP5k,hm,t
=
Where
DA_INT
=
12
SUC_INT
=
number of 5-minute intervals between Interval 7 and 18 the market
participant takes to achieve minimum loading point.
=
0
Scenario 3
PCG_COMP5k,hm,t
Component 5 – Variants 2 and 3
Component 5 is not calculated for Variants 2 and 3.
4.7D.5
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If for each DACP start event for each eligible generation unit the sum of the
revenues referred to in section 4.7D.4 is greater than or equal to the sum of the
costs referred to in section 4.7D.4, then the IESO shall make no additional
payments in respect of the eligible generation facility.
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4.7D.6
If for each DACP start event for each eligible generation unit the sum of the
revenues referred to in section 4.7D.4 is less than the sum of the costs referred to
in section 4.7D.4, then the IESO shall include that amount in the form of
additional payments made in respect of the eligible generation facility.
4.7E
Day-Ahead Fuel Cost Compensation Settlement Amount
4.7E.1
In the event that the IESO, in order to maintain reliable operation of the IESOcontrolled grid requires a generation facility:

that was included in the schedule of record; and

for which the registered market participant for the generation facility is
deemed to have accepted the day-ahead production cost guarantee in
accordance with Section 5.8.4 of Chapter 7;
either to desynchronize from the IESO-controlled grid prior to the end of its
commitment scheduled in the schedule of record or not to synchronize to the
IESO-controlled grid, the market participant may, in accordance with chapter 7
section 6.3B, claim, in the manner specified in the applicable market manual,
reimbursement of financial losses related to the procurement of fuel for operation
at its minimum loading point for its commitment scheduled in the schedule of
record and which was not ultimately utilized by that generation facility.
4.7E.2
Where the IESO determines that claims made under section 4.7E.1 are valid, such
compensation claims will be applied to the market participant’s settlement
statement for the last trading day of each real-time market billing period after the
determination has been made.
4.7E.3
All claims made to the IESO pursuant to section 4.7E.1 may be subject to audit by
the IESO which may obligate the market participant to demonstrate or otherwise
make a binding declaration that the financial loss being claimed was not mitigated
through the actions of:
4.7E.4

the market participant;

an affiliate or subsidiary of the market participant; or

any other party that may have a commercial relationship with the market
participant where that commercial relationship involves compensation of
any kind that is directly related to the mitigation of the financial loss being
claimed.
The cumulative settlement amounts payable to market participants for each realtime energy market billing period under the provisions of section 4.7E.2 shall be
recovered from market participants in accordance with section 4.8.1.12.
PART 5 – IESO BOARD DECISION RATIONALE
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Market Rule Amendment Proposal
PART 1 – MARKET RULE INFORMATION
Identification No.:
MR-00375-R02
Subject:
Enhanced Day-Ahead Commitment Process (EDAC)
Title:
Market Rule True-up
Nature of Proposal:
Chapter:
11
Sections:
n/a
Alteration
Deletion
Addition
Appendix:
Sub-sections proposed for amending:
PART 2 – PROPOSAL HISTORY – PLEASE REFER TO MR-00375-R00
Version
Reason for Issuing
Version Date
Approved Amendment Publication Date:
Approved Amendment Effective Date:
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PART 3 – EXPLANATION FOR PROPOSED AMENDMENT
Provide a brief description of the following:



The reason for the proposed amendment and the impact on the IESO-administered markets if the
amendment is not made.
Alternative solutions considered.
The proposed amendment, how the amendment addresses the above reason and impact of the
proposed amendment on the IESO-administered markets.
Summary
Please refer to MR-00375-R00.
Background
Please refer to MR-00375-R00.
Discussion
It is proposed to modify the market rules in Chapter 11 Definitions in the following manner:

The definitions of schedule of record and pseudo-unit will be modified to improve clarity.

The definition of combined guaranteed costs was deleted in MR-00348 because it was no
longer used in the calculation of the day-ahead generation cost guarantee once the day-ahead
production cost guarantee became effective. However, Combined Guaranteed Costs are still
required in the calculation of the real-time generation cost guarantee. The definition will be reinstated.
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PART 4 – PROPOSED AMENDMENT
combined guaranteed costs means all fuel costs incurred by a generation facility up
to and including its minimum loading point, as defined in the applicable market
manual, including costs incurred by that generation facility to achieve
synchronization and once synchronized with the IESO-controlled grid to move to
the generation facility’s minimum loading point;
daily cascading hydroelectric dependency means there is a minimum hydraulic time
lag of less than 24 hours from a hydroelectric generation facility to one or more
adjacent upstream and/or downstream hydroelectric generation facilities operated by
the same registered market participant.
elapsed time to dispatch is the minimum amount of time, in minutes, between the time
at which a startup sequence is initiated for a generation unit and the time at which it
becomes dispatchable by reaching its minimum loading point. maximum number of
starts per day is the number of times that a unit can be started within a dispatch day;
maximum number of starts per day is the number of times that a unit can be started
within a dispatch day;
minimum generation block down time is the minimum time, in hours, between the time
a generation facility was last at its minimum loading point before de-synchronization
and the time the generation facility reaches its minimum loading point again after
synchronization;
pseudo-unit means a combined cycle generation facility that is modeled based on a
gas-to-steam relationship between generation units, and which is comprised of one
combustion turbine generation unit and a share of one steam turbine generation unit
at the same combined cycle generation facility;
schedule of record means the last valid set of results from the day-ahead
commitment process used by the IESO for the application of constraints and the
calculation of various day-ahead settlement amounts;
start-up cost is the value offered by the registered market participant to bring an offline resource to its minimum loading point;
speed no-load cost is the hourly value offered by the registered market participant to
maintain a generation facility synchronized with zero net energy injected into the
IESO-controlled grid;
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PART 5 – IESO BOARD DECISION RATIONALE
Insert Text Here
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Market Rule Amendment Proposal
PART 1 – MARKET RULE INFORMATION
Identification No.:
MR-00375-R03
Subject:
Enhanced Day-Ahead Commitment Process (EDAC)
Title:
Market Rule True-up
Nature of Proposal:
Chapter:
n/a
Sections:
various
Alteration
Deletion
Appendix:
Sub-sections proposed for amending:
Addition
7.5A
various
PART 2 – PROPOSAL HISTORY – PLEASE REFER TO MR-00375-R00
Version
Reason for Issuing
Version Date
Approved Amendment Publication Date:
Approved Amendment Effective Date:
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PART 3 – EXPLANATION FOR PROPOSED AMENDMENT
Provide a brief description of the following:



The reason for the proposed amendment and the impact on the IESO-administered markets if the
amendment is not made.
Alternative solutions considered.
The proposed amendment, how the amendment addresses the above reason and impact of the
proposed amendment on the IESO-administered markets.
Summary
Please refer to MR-00375-R00.
Background
Please refer to MR-00375-R00.
Discussion
It is proposed to amend Appendix 7.5 to reflect that the Production Cost Guarantee is now referred to
as Day-Ahead Production Cost Guarantee, and all references to EDAC have been replace with DACP.
Also amend this appendix to correct the errata in the numbering of section 6.11.
PART 4 – PROPOSED AMENDMENT
Table of Contents
Appendix 7.5A – The DACP Calculation Engine Process ................................5
1.1
Interpretation ......................................................................................5
2.
DACP Calculation Engine ...........................................................................5
2.1
Overview ............................................................................................5
3.
Inputs into the DACP Calculation Engine .................................................6
3.1
Demand Forecast ...............................................................................6
3.2
Energy Offers and Bids ......................................................................6
3.3
Operating Reserve Offers...................................................................6
3.4
Forecasts from Self-Scheduling Generation Facilities, Transitional
Scheduling Generators and Intermittent Generators ..........................6
3.5
Ramp up to Minimum Loading Point ..................................................7
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3.6
3.7
3.8
4.
Energy Limited Resources ................................................................. 7
Transmission Inputs ........................................................................... 7
Other Inputs ....................................................................................... 7
Pass 1: Constrained Commitment to Meet Average Demand ................. 8
4.1
Overview ............................................................................................ 8
4.2
Inputs for Pass 1 ................................................................................ 8
4.3
Optimization Objective for Pass 1 ...................................................... 8
4.4
Security Assessment.......................................................................... 9
4.5
Outputs from Pass 1 ........................................................................ 11
4.6
Glossary of Sets, Indices, Variables and Parameters for Pass 1 ..... 11
4.7
Objective Function ........................................................................... 26
4.8
Constraints Overview ....................................................................... 27
4.9
Bid/Offer Constraints Applying to Single Hours ................................ 27
4.10
Bid/Offer Inter-Hour/Multi-Hour Constraints ..................................... 32
4.11
Constraints to Ensure Schedules Do Not Violate Reliability
Requirements................................................................................... 37
4.12
Shadow Prices for Energy ................................................................ 42
5.0 Pass 2: Constrained Commitment to Meet Peak Demand..................... 43
5.1
Overview .......................................................................................... 43
5.2
Inputs into Pass 2 ............................................................................ 43
5.3
Optimization Objective for Pass 2 .................................................... 44
5.4
Security Assessment........................................................................ 44
5.5
Outputs from Pass 2 ........................................................................ 44
5.6
Glossary of Sets, Indices, Variables and Parameters for Pass 2 ..... 44
5.7
Evaluation of Generator Offers and Dispatchable Load Bids ........... 49
5.8
Objective Function ........................................................................... 50
5.9
Constraints Overview ....................................................................... 51
5.10
Bid/Offer Constraints Applying to Single Hours ................................ 51
5.11
Bid/Offer Inter-Hour/Multi-Hour Constraints ..................................... 56
5.12
Constraints to Ensure Schedules Do Not Violate Reliability
Requirements................................................................................... 59
6.
Pass 3: Constrained Scheduling to Meet Average Demand ................. 65
6.1
Overview .......................................................................................... 65
6.2
Inputs into Pass 3 ............................................................................ 65
6.3
Optimization Objective for Pass 3 .................................................... 65
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6.4
6.5
6.6
6.7
6.8
6.9
6.10
6.11
6.12
7.
Security Assessment ........................................................................65
Outputs from Pass 3 .........................................................................65
Glossary of Sets, Indices, Variables and Parameters for Pass 3 .....66
Objective Function ............................................................................72
Constraints Overview .......................................................................73
Bid/Offer Constraints Applying to Single Hours ................................73
Bid/Offer Inter-Hour/Multi-Hour Constraints......................................77
Constraints to Ensure Schedules Do Not Violate Reliability
Requirements ...................................................................................80
Shadow Prices .................................................................................85
Combined-Cycle Modeling .......................................................................88
7.1
Overview ..........................................................................................88
7.2
Modeling by DACP Calculation Engine ............................................88
Appendix 7.5A – The DACP Calculation
Engine Process
1.1
Interpretation
1.1.1
This appendix describes the DACP calculation engine process used to determine
commitments, constrained schedules, and shadow prices.
1.1.1.1
Commitment refers to the availability of generation facilities and
imports to provide energy and/or operating reserve and dispatchable
loads and exports to provide operating reserve.
1.1.1.2
The constrained schedules of the schedule of record are assessed in the
calculation of day-ahead production cost guarantees.
1.1.1.3
The shadow price of a location indicates the price of meeting an
infinitesmal amount of change in load at that location.
1.1.2
The mathematical description of the optimization algorithm of the DACP
calculation engine process is also described in this appendix.
1.1.3
The DACP calculation engine “outputs” described in this appendix refer to data
produced by DACP calculation engine and the IESO shall not be required to
publish such data except where expressly required by these market rules.
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2.
DACP Calculation Engine
2.1
Overview
2.1.1
The DACP calculation engine is a core component of the DACP process that
performs the functions of commitment and constrained scheduling over a 24-hour
period for energy and operating reserves, and the calculation of shadow prices.
The DACP calculation engine executes three passes to produce the final schedule
of record.
2.1.1.1
Pass 1, the Commitment Pass determines the initial set of
commitments and constrained schedules required to satisfy the average
forecast demand of the next day. Details of Pass 1 are described in
section 4.
2.1.1.2
Pass 2, the Reliability Pass ensures that if the resources committed by
Pass 1 are insufficient to satisfy peak forecast demand, additional
resources are committed and scheduled. Details of Pass 2 are described
in section 5.
2.1.1.3
Pass 3, the Scheduling Pass uses the commitments made in Passes 1
and 2 to determine the schedule of record and the associated
constrained schedules to meet average forecast demand. Details of
Pass 3 are described in section 6.
2.1.2
Since each pass provides constrained schedules, the DACP calculation engine will
iterate the calculations for constrained schedules with security assessments until
there are no security violations. The security assessment functionality is described
in section 4.4.
3.
Inputs into the DACP Calculation
Engine
3.1
Demand Forecast
3.1.1
The IESO shall prepare forecasts of the total demand in Ontario for each hour of
the next day. This hourly forecast will be modified by the DACP calculation
engine so that the expected consumption associated with dispatchable loads will
be removed. Average hourly demand forecasts will be used as inputs to Passes 1
and 3. Peak hourly demand forecasts will be used as inputs to Pass 2.
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3.2
Energy Offers and Bids
3.2.1
A registered market participant may submit an energy offer or energy bid and
associated dispatch data with respect to a given registered facility for each
dispatch hour of the next day for DACP. Energy offers, bids and dispatch data
shall be submitted in accordance to Chapter 7.
3.3
Operating Reserve Offers
3.3.1
A registered market participant may submit an offer and associated dispatch data
to provide each class of operating reserve for each dispatch hour of the next day
for DACP. Operating reserve offers and dispatch data shall be submitted in
accordance to Chapter 7.
3.4
Forecasts from Self-Scheduling Generation Facilities,
Transitional Scheduling Generators and Intermittent
Generators
3.4.1
The DACP calculation engine will take into account the expected output of selfscheduling generation facilities, transitional scheduling generators and
intermittent generators when committing resources to meet forecast demand for
the next day. The registered market participant representing such generation at
each location will inform the IESO of the amount of energy it expects to produce
in each hour of the next day as a function of price in accordance to Chapter 7.
3.5
Ramp up to Minimum Loading Point
3.5.1
In order for the DACP calculation engine to determine constrained schedules in
Pass 3 that account for the energy produced by generation facilities during
ramping to their minimum loading points, an approximate value of this energy
will be used. This energy will be represented by a fraction of the unit’s minimum
loading point in the hour prior to the first hour it is scheduled.
3.6
Energy Limited Resources
3.6.1
Energy limited resources constitute a subset of generation facilities that at times
can be limited in the amount of energy they can provide during each day.
3.6.2
An energy limited resource shall designate the daily limit on the amount of energy
it could be scheduled to generate over the course of the day.
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3.7
Transmission Inputs
3.7.1.
Transmission inputs are based on information prepared by the IESO for the
security assessment function of the DACP calculation engine described in section
4.4. These inputs include:
3.7.1.1
Internal transmission constraints;
3.7.1.2
Limits on imports and exports;
3.7.1.3
Loop flows; and
3.7.1.4
Transmission losses.
3.8
Other Inputs
3.8.1
The IESO shall also provide other inputs into the DACP calculation engine that
are necessary in order to ensure a solution that is consistent with system
reliability. These include:
3.8.1.1
Distribution of internal demand;
3.8.1.2
Distribution of imports, exports and loop flows;
3.8.1.3
Operating reserve requirements;
3.8.1.4
Must-run resources for other reliability purposes;
3.8.1.5
Regulation (AGC);
3.8.1.6
Voltage constraints;
3.8.1.7
Initializing assumptions regarding resources in operation; and
3.8.1.8
Costs of violations.
4.
Pass 1: Constrained Commitment to
Meet Average Demand
4.1
Overview
4.1.1
Pass 1 performs a least cost, security constrained, unit commitment and
constrained scheduling to meet the forecast average demand and IESO-specified
operating reserve requirements for each hour of the next day.
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4.1.2
This pass will use bids and offers and associated dispatch data submitted by
registered market participants to maximize the gains from trade (i.e., the
difference between the total price of bids submitted by market participants whose
bids were scheduled, and the total price of offers submitted by market participants
whose offers were scheduled). The optimization is subject to the constraints
accompanying those bids and offers, and constraints imposed by the IESO to
ensure reliable service.
4.2
Inputs for Pass 1
4.2.1
Inputs for Pass 1 include those described in section 3.
4.3
Optimization Objective for Pass 1
4.3.1
The objective function of Pass 1 is to maximize the gains from trade. This is
accomplished by maximizing the sum of the following quantities for each hour of
the trade day:
The value of:
Scheduled exports;
Less the offered costs of:
Scheduled operating reserve from exports;
The foregone opportunity due to scheduled load reductions;
Scheduled operating reserve from dispatchable load;
Scheduled hourly imports;
Scheduled operating reserve from imports;
Scheduled operating reserve from generation facilities;
Scheduled generation;
Hourly costs for speed no-load for committed generation facilities; and
Startup cost for committed generation facilities;
Less the cost of:
Scheduled violation variables.
4.3.2
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The cost for each violation variable for each hour is the hourly magnitude of the
violation variable multiplied by the price (in $ per MW per hour) for relaxing the
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particular constraint. The hourly cost associated with all violation variables is the
sum of the individual hourly costs for:
Projected load curtailment due to a supply deficit;
Scheduling additional load to offset surplus must-run generation facility requirements (the
minus sign is required since the violation price is negative);
Operating reserve requirement deficits;
All reserve area minimum operating reserve requirement deficits;
All reserve area operating reserve excesses above maximum requirements;
Pre-contingency and post-contingency limit violations for internal transmission facilities;
Pre-contingency limit violations for import or export interties; and
Exceeding the up or down ramp limits for the total net schedule change for imports and
exports.
4.4
Security Assessment
4.4.1
For constrained scheduling, the DACP calculation engine iterates a security
assessment function with the scheduling function. The scheduling function
produces schedules which are passed to the security assessment function. The
security assessment function determines losses and additional constraints which
feed back to the subsequent iteration of the scheduling function.
4.4.2
The security assessment function used by Pass 1 is common to all passes of the
DACP calculation engine process.
4.4.3
The security assessment function performs the following calculations and
analyses:
4.4.3.1
Base case solution: A base case solution function prepares a power
flow solution for each hour. This function automatically selects the
power system model state (i.e., breaker/switch status, tap positions,
desired voltages, etc) applicable to the forecast of conditions for the
hour and input schedules. An AC load flow program is used; however,
a DC load flow may be used should the AC load flow fail to converge.
4.4.3.2
Loss calculation: The solved power flow is used to calculate Ontario
transmission system losses, incremental loss factors and loss
adjustments to be used in the power balance constraint of the
scheduling function.
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4.4.3.3
Pre-contingency security assessment: Continuous thermal limits for all
monitored equipment and operating security limits are monitored to
check for pre-contingency limit violations. Violated limits are
linearized and incorporated as constraints for use by the scheduling
function.
4.4.3.4
Linear contingency analysis: A variation of the DC load flow is used
to simulate all valid contingencies, calculate post contingency flows
and check for limited time (i.e. emergency) thermal limit violations.
Violated limits are linearized and incorporated as constraints for use
by the scheduling function.
4.4.4
In the first iteration, before any processing by the security assessment functions,
an initial default set of incremental loss factors and loss adjustments is used in the
scheduling function. In this iteration, there are no transmission constraints from
the security assessment. In subsequent iterations, the outputs from the security
assessment function are used.
4.4.5
The IESO maintains sets of data as outlined in Appendix 7.5, section 2.4 for use
in the security assessment processes for the real-time market and operation. The
security assessment function will use this same set of data to obtain:
4.4.5.1
the power system model;
4.4.5.2
status of power system equipment;
4.4.5.3
list of contingencies to be simulated;
4.4.5.4
list of monitored equipment;
4.4.5.5
equipment thermal limits; and
4.4.5.6
operating security limits (angular stability, voltage stability and voltage decline).
4.4.6
Constraint violation variables, when violated indicate the type of problem that is
not allowing the optimization of the objective function to have a solution. The
equivalent constraint violation variables and their values as used in the real-time
market and described Appendix 7.5, section 4.12 are utilized by the DACP
calculation engine. Further details of these inputs for the DACP calculation
engine are described in section 4.6.2.4.
4.5
Outputs from Pass 1
4.5.1
The primary outputs of Pass 1 which are used in Pass 2 and other DACP
processes include the following:
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4.5.1.1
Commitments;
4.5.1.2
Constrained schedules for energy; and
4.5.1.3
Shadow prices for energy.
4.6
Glossary of Sets, Indices, Variables and Parameters for
Pass 1
4.6.1
Fundamental Sets and Indices
A
B
C
D
F
The set of all intertie zones a.
The set of buses b within Ontario, corresponding
to bids and offers at locations on the IESOcontrolled grid.
The set of contingencies conditions c to be
considered in the security assessment.
The set of buses d outside Ontario, corresponding
to bids and offers at intertie zones.
The set of transmission facilities (or groups of
transmission facilities) f in Ontario for which
constraints have been identified.
J
The set of all bids j. Each price-quantity pair of a
bid submitted by a market participant would be
represented by a unique element j in the set.
Jb
The subset of those bids j consisting of bids for a
dispatchable load resource at a bus b.
K
The set of all offers. Each price-quantity pair of
an offer submitted by a market participant would
be represented by a unique element k in the set.
Kb
The subset of those offers consisting of offers for a
generation facility at a bus b.
ORREG
The set of reserve areas, or regions, for which
minimum and maximum operating reserve
requirements have been defined. Each region r of
the set ORREG consists of a set of buses at which
operating reserve satisfying the minimum and
maximum operating reserve requirement for that
region may be located.
Zsch
The set of all interties (or groups of interties) z for
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which constraints have been identified.
4.6.2
a
An intertie zone.
b
A bus corresponding to bids and offers. A single
facility for which multiple energy bids are allowed
may be represented as multiple buses,
corresponding to the individual bids.
c
A contingency condition considered in the
security assessment.
d
A bus outside Ontario corresponding to bids and
offers in intertie zones.
f
A transmission facility for which a constraint has
been identified. This includes groups of
transmission facilities.
h
One of the day-ahead hours, from 1 to 24.
j
A bid or portion of a bid representing a single
price-quantity pair.
k
An offer or portion of an offer representing a
single price-quantity pair.
r
An operating reserve region within Ontario.
z
An intertie for which a constraint has been
identified. This includes groups of interties.
Variables and Parameters
4.6.2.1
Bid and Offer Inputs
Dispatchable Loads:
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QPRLj,h,b
An incremental quantity of reduction in energy
consumption that may be scheduled for a
dispatchable load in hour h at bus b in association
with bid j.
PPRLj,h,b
The lowest energy price at which the incremental
quantity of reduction in energy consumption
specified in bid j should be scheduled in hour h at
bus b.
10SQPRLj,h,b
The synchronized ten-minute operating reserve
quantity associated with bid j in hour h at bus b
for dispatchable loads qualified to do so.
10SPPRLj,h,b
The price of being scheduled to provided
synchronized ten-minute operating reserve
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associated with bid j in hour h at bus b, for
dispatchable loads qualified to do so.
10NQPRLj,h,b
The non-synchronized ten-minute operating
reserve quantity associated with bid j in hour h at
bus b for dispatchable loads qualified to do so.
10NPPRLj,h,b
The price of being scheduled to provide nonsynchronized ten-minute operating reserve
associated with bid j in hour h at bus b, for
dispatchable loads qualified to do so.
30RQPRLj,h,b
The thirty-minute operating reserve quantity
associated with bid j in hour h at bus b, for
dispatchable loads qualified to do so.
30RPPRLj,h,b
The price of being scheduled to provide thirtyminute operating reserve associated with bid j in
hour h at bus b, for dispatchable loads qualified to
do so.
ORRPRLb
The operating reserve ramp rate per minute for
reductions in load consumption at bus b.
URRPRLb
The maximum rate per minute at which a
dispatchable load that wishes to consume energy
at bus b can decrease its amount of energy
consumption.
DRRPRLb
The maximum rate per minute at which a
dispatchable load that wishes to consume energy
at bus b can increase its amount of load
consumption.
Exports:
QHXLj,h,a
The maximum quantity of energy for which an
export to intertie zone a in hour h may be
scheduled in association with bid j.
PHXLj,h,a
The highest price at which energy should be
scheduled for an export to intertie zone a in hour h
in association with bid j.
QX10Nj,h,a
The non-synchronized ten-minute operating
reserve quantity associated with bid j in hour h at
intertie zone a for an export qualified to do so.
PX10Nj,h,a
The price of being scheduled to provide nonsynchronized ten-minute operating reserve
associated with bid j in hour h at intertie zone a,
for an export qualified to do so.
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QX30Rj,h,a
The thirty-minute operating reserve quantity
associated with bid j in hour h at intertie zone a,
for an export qualified to do so.
PX30Rj,h,a
The price of being scheduled to provide thirtyminute operating reserve associated with bid j in
hour h at intertie zone a, for an export qualified to
do so.
ORRHXLa
The operating reserve ramp rate per minute for
exports at intertie zone a, as specified by the
IESO.
Dispatchable Generators:
Page 86 of 164
MinQPRGh,b
The minimum loading point which is the
minimum amount of energy that a generation
facility at bus b is willing to produce in hour h, if
scheduled to operate.
SUPRGh,b
The offered start up cost that a generation facility
at bus b incurs in order to start and synchronize in
hour h.
SNLh,b
The offered speed no-load cost to maintain a
generation facility synchronized with zero net
energy injected into the system in hour h.
MGOPRGh,b
The offered minimum generation cost for a
generation facility at bus b in order to operate at
its minimum loading point in hour h. This is
calculated as the sum of SNLh,b and the
incremental price, PPRGk,h,b for energy up to the
minimum loading point, MinQPRGh,b.
QPRGk,h,b
An incremental quantity of energy generation
(above and beyond the minimum loading point)
that may be scheduled at bus b in hour h in
association with offer k.
PPRGk,h,b
The lowest energy price at which incremental
generation should be scheduled at bus b in hour h
in association with offer k.
10SPPRGk,h,b
The offered price of being scheduled to provide
synchronized ten-minute operating reserve in hour
h at bus b in association with offer k.
10SQPRGk,h,b
The offered quantity of synchronized ten-minute
operating reserve in hour h at bus b in association
with offer k.
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10NPPRGk,h,b
The offered price of being scheduled to provide
ten-minute operating non-synchronized tenminute operating reserve in hour h at bus b in
association with offer k.
10NQPRGk,h,b
The offered quantity of non-synchronized tenminute operating reserve in association with offer
k.
30RPPRGk,h,b
The offered price of being scheduled to provide
thirty-minute operating reserve in association with
offer k.
30RQPRGk,h,b
The offered quantity of thirty-minute operating
reserve in hour h at bus b in association with offer
k.
ORRPRGb
The maximum operating reserve ramp rate per
minute at bus b.
MRTPRGb
The minimum generation block run time period
for which a generation facility at bus b must be
scheduled to operate if its offer to generate is
accepted.
MDTPRGb
The minimum generation block down time period
between the end of one period when a generation
facility at bus b is scheduled to operate and the
beginning of the next period when it is scheduled
to operate.
MaxStartsPRGb
The maximum number of times per day a
generation facility at bus b can be scheduled
tostart.
URRPRGb
The maximum rate per minute at which a
generation facility offering to produce at bus b can
increase the amount of energy it supplies.
DRRPRGb
The maximum rate per minute at which a
generation facility offering to produce at bus b can
decrease the amount of energy it supplies.
ELb
The daily limit on the amount of energy that an
energy limited resource at bus b may be scheduled
to generate over the course of the day (maximum
daily energy limit).
Imports:
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QHIGk,h,a
The maximum quantity of energy for which an
import from intertie zone a in hour h may be
scheduled in association with offer k.
PHIGk,h,a
The lowest price at which an import from intertie
zone a in hour h in association with offer k should
be scheduled.
QI10Nk,h,a
The non-synchronized ten-minute operating
reserve quantity associated with offer k in hour h
at intertie zone.
PI10Nk,h,a
The price of being scheduled to provide nonsynchronized ten-minute operating reserve
associated with offer k in hour h at intertie zone a.
QI30Rk,h,a
The non-synchronized thirty-minute operating
reserve quantity associated with offer k in hour h
at intertie zone.
PI30Rk,h,a
The price of being scheduled to provide nonsynchronized thirty-minute operating reserve
associated with offer k in hour h at intertie zone a.
ORRHIGa
4.6.2.2
Page 88 of 164
The operating reserve ramp rate per minute for
imports at intertie zone a, as specified by the
IESO.
Transmission and Security Inputs and Intermediate Variables
EnCoeffa,z
The coefficient for calculating the contribution of
scheduled energy flows (and operating reserve, in
the case of inflows) over intertie a which is part of
the intertie group z. EnCoeffa,z takes the value +1
to account for limits on scheduled flows into
Ontario and the value -1 to account for limits on
scheduled flows out of Ontario.
MaxExtSch z,h
The maximum flow limit over an intertie z in hour
h.
ExtDSCh
The maximum decrease in total net flows over all
interties from hour to hour, which limits the hourto-hour decreases in net imports (calculated as
imports less exports) from all the intertie zones.
ExtUSCh
The maximum increase in total net flows over all
interties from hour to hour, which limits the hourto-hour increases in net imports (calculated as
imports less exports) from all the intertie zones.
PFh,a
The anticipated inflow into Ontario from intertie
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zone a in hour h that result from loop flows.
MglLossh,b
The marginal impact on transmission losses
resulting from transmitting energy from the
reference bus to serve an increment of additional
load at the bus b in hour h.
LossAdjh
Any adjustment needed for hour h to correct for
any discrepancy between actual Ontario total
system losses using a base case power flow from
the security assessment function and system losses
that would be calculated using the marginal
transmission losses.
With1h,b
The total amount of withdrawals scheduled in
Pass 1 at each bus b in each hour h, for scheduled
dispatchable loads.
With1h,d
The total amount of withdrawals scheduled in
Pass 1 at each bus d in each hour h, for exports
and outflows associated with loop flows for buses
in intertie zones.
Inj1h,b
The total amount of injections scheduled in Pass 1
at each bus b in each hour h, for scheduled
generation.
Inj1h,d
The total amount of injections scheduled in Pass 1
at each bus d in each hour h, for imports and
inflows associated with loop flows for buses in
intertie zones.
PreConSFb,f,h
The fraction of energy injected at bus b which
flows on transmission facility f during hour h
under pre-contingency conditions.
AdjNormMaxFlowf,h
The maximum flow allowed on transmission
facility f in hour h as determined by the security
assessment for pre-contingency conditions.
SFb,f,c,h
The fraction of energy injected at bus b which
flows on a transmission facility f during hour h
under post-contingency conditions.
AdjEmMaxFlowf,c,h
The maximum flow allowed on transmission
facility f in hour h as determined by the security
assessment for post-contingency condition c.
4.6.2.3
Other Inputs
Distribution of Load, Imports and Exports and Loop Flows
LDFh,b
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distributed across Ontario, representing the
proportion of the load at bus b in hour h. This is
based on historical telemetry data.
AFLh
Average Ontario demand forecast in hour h with
the expected consumption associated with
dispatchable loads removed.
PFLh
Peak Ontario demand forecast in hour h with the
expected consumption associated with
dispatchable loads removed.
ProxyUPIWtd,a
The proportion of inflows associated with loop
flows from intertie zone a that shall be assigned to
each bus d in the control area in which that
intertie zone is located.
ProxyUPOWtd,a
The proportion of outflows associated with loop
flows from intertie zone a that shall be assigned to
each bus d in the control area in which that
intertie zone is located.
10ORConv
The factor applied to scheduled ten-minute
operating reserve for energy limited resources to
convert MW into MWh. This factor shall be 1.0.
30ORConv
The factor applied to scheduled thirty-minute
operating reserve for energy limited resources to
convert MW into MWh. This factor shall be 1.0.
Operating Reserve Requirements:
Page 90 of 164
TOT10Rh
Minimum requirement for the total amount of tenminute operating reserve.
TOT10Sh
The total amount of synchronized ten-minute
operating reserve required in hour h, which is a
percentage of the total ten-minute operating
reserve requirement.
TOT30Rh
Minimum requirement for the total amount of
thirty-minute operating reserve.
REGMin10Rr,h
The minimum requirement for ten-minute
operating reserve in region r in hour h.
REGMax10Rr,h
The maximum amount of ten-minute operating
reserve that may be provided in region r in hour h.
REGMin30Rr,h
The minimum requirement for thirty-minute
operating reserve in region r in hour h.
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REGMax30Rr,h
The maximum amount of thirty-minute operating
reserve that may be provided in region r in hour h.
Other Ancillary Service and Resource Initializing Assumptions:
MaxPRLh,b
The maximum amount of load reduction that a
dispatchable load can achieve at bus b in hour h.
MinPRGh,b
The minimum output for a generation facility at
bus b in hour h, that is the most restrictive of the
limits for regulation or voltage support, providing
AGC or due to outages.
MaxPRGh,b
The maximum output for a generation facility at
bus b in hour h, that is the most restrictive of the
limits for regulation or voltage support, providing
AGC or due to outages.
InitOperHrsb
The number of consecutive hours at the end of the
previous day for which the generation facility or
load at bus b was scheduled to operate.
4.6.2.4
Constraint Violation Price Inputs
PLdViol
The value that the DACP calculation engine will
assign to scheduling the forecast load. As
measured by the effect on the value of the
objective function, if the cost of serving that load
(in dollars per MWh) exceeds PLdViol, then that
load would not be scheduled. This is not
applicable to Pass 1 since PLdViol will exceed
maximum bid price allowed and no bid load could
be scheduled at this price. This equals the shortage
cost for energy applied in the real-time market.
PGenViol
The price at which additional load will be
included above the scheduled amount when the
amount of energy generation facilities produce at
their minimum loading points exceeds the amount
of load scheduled on the system. This equals the
negative of the shortage cost for energy applied in
the real-time market.
P10SViol
The price at which the overall minimum
synchronized ten-minute operating reserve
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requirement may be violated. This equals the
shortage cost for synchronized ten-minute
operating reserve applied in the real-time market.
Page 92 of 164
P10RViol
The price at which the overall minimum tenminute operating reserve requirement may be
violated. This equals the shortage cost for total
ten-minute operating reserve applied in the realtime market.
P30RViol
The price at which the overall minimum thirtyminute operating reserve requirement may be
violated. This equals the shortage cost for total
thirty-minute operating reserve applied in the
real-time market.
PREG10RViol
The price at which the regional minimum tenminute operating reserve requirements may be
violated. This equals the shortage cost for the
corresponding value applied in the real-time
market.
PXREG10RViol
The price at which the regional maximum tenminute operating reserve requirements may be
violated. This equals the shortage cost for the
corresponding value applied in the real-time
market.
PREG30RViol
The price at which the regional minimum thirtyminute operating reserve requirements may be
violated This equals the shortage cost for the
corresponding value applied in the real-time
market.
PXREG30RViol
The price at which the regional maximum thirtyminute operating reserve requirements may be
violated. This equals the shortage cost for the
corresponding value applied in the real-time
market.
PPreConITLViol
The price at which pre-contingency flows over
internal transmission may exceed that facility’s
limit. This equals the shortage cost for base case
security limits applied in the real-time market.
PITLViol
The price at which flows over an internal
transmission facility following a contingency may
exceed that facility’s limit. This equals the
shortage cost for contingency constrained security
limits applied in the real-time market.
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PPreConXTLViol
The price at which the pre-contingency import and
export intertie limits may be violated. This equals
the shortage cost for inter control area scheduling
limits applied in the real-time market.
PRmpXTLViol
The price at which the limit for hour to hour
changes (up and down) of total net scheduled
imports from intertie zones may be violated. This
equals the shortage cost for inter control area
scheduling limits applied in the real-time market.
4.6.2.5
Output Schedule and Commitment Variables
SHXL1j,h,d
The amount of exports scheduled in hour h in Pass
1 from intertie zone sink bus d in association with
each bid j.
SX10N1j,h,d
The amount of non-synchronized ten-minute
operating reserve scheduled from the export in
hour h in Pass 1 from intertie zone sink bus d in
association of bid j.
SX30R1j,h,d
The amount of thirty-minute operating reserve
scheduled from the export in hour h in Pass 1
from intertie zone sink bus d in association of bid
j.
SPRL1j,h,b
The amount of dispatchable load reduction
scheduled at bus b in hour h in Pass 1 in
association with each bid j at that bus.
10SSPRL1j,h,b
The amount of synchronized ten-minute operating
reserve that a qualified dispatchable load is
scheduled to provide at bus b in hour h in Pass 1
in association of bid j for this bus.
10NSPRL1j,h,b
The amount of non-synchronized ten-minute
operating reserve that a qualified dispatchable
load is scheduled to provide at bus b in hour h in
Pass 1 in association of bid j for this bus.
30RSPRL1j,h,b
The amount of thirty-minute operating reserve
that a qualified dispatchable load is scheduled to
provide at bus b in hour h in Pass 1 in association
of bid j for this bus.
SHIG1k,h,d
The amount of hourly imports scheduled in hour h
from intertie zone source bus d in Pass 1 in
association with each offer k.
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SI10N1k,h,d
The amount of imported ten-minute operating
reserve scheduled in hour h from intertie zone
source bus d in Pass 1 in association with each
offer k.
SI30R1k,h,d
The amount of imported thirty-minute operating
reserve scheduled in hour h from intertie zone
source bus d in Pass 1 in association with each
offer k.
SPRG1k,h,b
The amount scheduled for the generation facility
at bus b in hour h in Pass 1 in association with
each offer k at that bus. This is in addition to any
MinQPRG h,b, the minimum loading point, which
must also be committed.
OPRG1h,b
Represents whether the generation facility at bus b
has been scheduled in hour h in Pass 1.
IPRG1h,b
Represents whether the generation facility at bus b
has been scheduled to start in hour h in Pass 1.
10SSPRG1k,h,b
The amount of synchronized ten-minute operating
reserve that a qualified generation facility at bus b
is scheduled to provide in hour h in Pass 1 in
association of offer k for this bus.
10NSPRG1k,h,b
The amount of non-synchronized ten-minute
operating reserve that a qualified generation
facility at bus b is scheduled to provide in hour h
in Pass 1 in association of offer k for this bus.
30RSPRG1k,h,b
4.6.2.6
Page 94 of 164
The amount of thirty-minute operating reserve
that a qualified generation facility at bus b is
scheduled to provide in hour h in Pass 1 in
association of offer k for this bus.
Output Violation Variables
ViolCost1h
The cost incurred in order to avoid having the
Pass 1 schedules for hour h violate specified
constraints.
SLdViol1h
Projected load curtailment, that is, the amount of
load that cannot be met using offers scheduled or
committed in hour h in Pass 1.
SGenViol1h
The amount of additional load that must be
scheduled in hour h in Pass 1 to ensure that there
is enough load on the system to offset the mustrun requirements of generation facilities.
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S10SViol1h
The amount by which the overall synchronized
ten-minute operating reserve requirement is not
met in hour h of Pass 1 because the cost of
meeting that portion of the requirement was
greater than or equal to P10SViol.
S10RViol1h
The amount by which the overall ten-minute
operating reserve requirement is not met in hour h
of Pass 1 (above and beyond any failure to meet
the synchronized ten-minute operating reserve
requirement) because the cost of meeting that
portion of the requirement was greater than or
equal to P10RViol.
S30RViol1h
The amount by which the overall thirty-minute
operating reserve requirement is not met in hour h
of Pass 1 (above and beyond any failure to meet
the ten-minute operating reserve requirement)
because the cost of meeting that portion of the
requirement was greater than or equal to
P30RViol.
SREG10RViol1r,h
The amount by which the minimum ten-minute
operating reserve requirement for region r is not
met in hour h of Pass 1 because the cost of
meeting that portion of the requirement was
greater than or equal to PREG10RViol.
SREG30RViol1r,h
The amount by which the minimum thirty-minute
operating reserve requirement for region r is not
met in hour h of Pass 1 because the cost of
meeting that portion of the requirement was
greater than or equal to PREG30RViol.
SXREG10RViol1r,h
The amount by which the ten-minute operating
reserve scheduled for region r exceeds the
maximum required in hour h of Pass 1 because the
cost of meeting that the maximum requirement
limit was greater than or equal to PXREG10RViol.
SXREG30RViol1r,h
The amount by which the thirty-minute operating
reserve scheduled for region r exceeds the
maximum required in hour h of Pass 1 because the
cost of meeting the maximum requirement limit
was greater than or equal to PXREG30RViol.
SPreConITLViol1f,h
The amount by which pre-contingency flows over
facility f in hour h of Pass 1 exceed the normal
limit for flows over that facility, because the cost
of alternative solutions that would not result in
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such an overload was greater than or equal to
PPreConITLViol.
SITLViol1f,c,h
The amount by which flows over facility f that
would follow the occurrence of contingency c in
hour h of Pass 1 exceed the emergency limit for
flows over that facility, because the cost of
alternative solutions that would not result in such
an overload was greater than or equal to PITLViol.
SPreConXTLViol1z,h
The amount by which intertie flows over facility z
in hour h of Pass 1 exceed the normal limit for
flows over that facility, because the cost of
alternative solutions that would not result in such
an overload was greater than or equal to
PPreConXTLViol.
SURmpXTLViol1h
The amount by which the total net scheduled
import increase for hour h in Pass 1 exceeds the
up ramp limits, because the cost of alternative
solutions that would not result in violation was
greater than or equal to PRmpXTLViol.
SDRmpXTLViol1h
4.6.2.7
The amount by which the total net scheduled
import decrease in hour h of Pass 1 exceed the
down ramp limits, because the cost of alternative
solutions that would not result in violation was
greater than or equal to PRmpXTLViol.
Output Shadow Prices
Shadow Prices of Constraints:
SPL1h
The Pass 1 shadow price measuring the rate of
change of the objective function for a change in
load at the reference bus in hour h.
SPNormT1f,h
The Pass 1 shadow price measuring the rate of
change of the objective function for a change in
the limit, AdjNormMaxFlowf,h, on flows over
transmission facilities in normal conditions for
facility f in hour h.
SPEmT1f,c,h
The Pass 1 shadow price measuring the rate of
change of the objective function for a change in
the limit, AdjEmMaxFlowf,c,h, on flows over
transmission facilities in emergency conditions for
facility f in monitored contingency c in hour h.
Shadow Price for Energy:
Page 96 of 164
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LMP1h,b
4.6.2.8
The Pass 1 locational marginal price for energy at
each bus b in each hour h. It measures the offered
price of meeting an infinitesimal change in the
amount of load at that bus in that hour, or
equivalently, measures the value of an incremental
amount of supply at that bus in that hour in Pass 1.
Energy Ramp Rates
RmpRngMaxPRLj,b
The maximum load reduction to which the ramp
rates URRPRLj,b and DRRPRLj,b apply for a
dispatchable load at bus b. The largest
RmpRngMaxPRLj,b must be greater than or equal
to maximum load reduction bid.
URRPRLj,b
The maximum rate per minute at which a
dispatchable load at bus b can decrease its
consumption of energy while operating in the
range between RmpRngMaxPRLj-1,b and
RmpRngMaxPRLj,b .
DRRPRLj,b
The maximum rate per minute at which a
dispatchable load at bus b can increase its
consumption of energy while operating in the
range between RmpRngMaxPRLj-1,b and
RmpRngMaxPRLj,b.
RmpRngMaxPRGk,b
The maximum output level to which the ramp
rates URRPRGk,b and DRRPRGk,b apply for a
generation facility at bus b. The largest
RmpRngMaxPRGk,h,b must be greater than or equal
to maximum energy offered.
URRPRGk,b
The maximum rate per minute at which a
generation facility at bus b can increase its output
while operating in the range between
RmpRngMaxPRGk-1,b and RmpRngMaxPRGk,b.
DRRPRGk,b
The maximum rate per minute at which a
generation facility at bus b can decrease its output
in hour h while operating in the range between
RmpRngMaxPRGk-1,b and RmpRngMaxPRGk,b.
4.7
Objective Function
4.7.1
The optimization of the objective function in Pass 1 is to maximize the
expression:
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



1
1
1

, j(JSHXL j ,h,d  PHXL j ,h,d  SX10N j ,h,d  PX10N j ,h,d  SX30R j ,h,d  PX30R j ,h,d )
dDX
d





  SPRL1j ,h ,b  PPRL j ,h ,b



 jJ b

 

1
1

10NPPRL

10NSPRL

10SPPRL

10SSPRL

 


b
,
h
,
j
b
,
h
,
j
b
,
h
,
j
b
,
h
,
j
bB



 
1



 jJ b 30RSPRL j ,h ,b  30RPPRL j ,h ,b


1
1
1
  SHIG k ,h ,d  PHIG k ,h ,d  SI10N k ,h ,d  PI10N k ,h ,d  SI30Rk ,h ,d  PI30Rk ,h ,d ;

h 1,..., 24  d DI , kK d







1

  SPRG k ,h ,b  PPRG k ,h ,b



kK b





   OPRG h1,b  MGOPRG h ,b  IPRG h1,b  SUPRGh ,b


 bB 
10SSPRG k1,h ,b  10SPPRG k ,h ,b 10NSPRG k1,h ,b  10NPPRG k ,h ,b 








 kK b  30RSPRG 1  30RPPRG


k , h ,b
k , h ,b




1

 ViolCost h




where ViolCost1h is calculated as follows:
ViolCost h1  SLdViolh1  PLdViol  SGenViolh1  PGenViol
 S10SViol h1  P10SViol  S10RViol h1  P10RViol
 S30RViol h1  P30RViol
 SREG10RVio lr1,h  PREG10RVio l



  SREG30RVio lr1,h  PREG30RVio l 

  
1
rORREG   SXREG10RViol r ,h  PXREG10RViol 


  SXREG30RViol 1  PXREG30RViol 
r ,h


1
  SPreConITLViol f ,h ,  PPreConITLViol
f F

 SITLViol
f F ,cC
1
f ,c , h
 PITLViol
  SPreConXTLViol 1z ,h  PPreConXTLViol
zZ
 SURmpXTLViolh1  PRmpXTLViol
 SDRmpXTLViolh1  PRmpXTLViol.
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4.7.2
The Pass 1 maximization is subject to the constraints described in the next
section.
4.8
Constraints Overview
4.8.1
The constraints that apply to the optimization above can be broken into the
categories:
Single hour constraints to ensure that the schedules determined in the optimization do not
violate the parameters specified in the bids and offers submitted by registered
market participants;
Inter-hour and multi-hour constraints to ensure that the schedules determined in the
optimization do not violate the parameters specified in the bids and offers
submitted by registered market participants; and
Constraints to ensure that those schedules do not violate reliability criteria established by the
IESO.
4.9
Bid/Offer Constraints Applying to Single Hours
4.9.1
Status Variables and Capacity Constraints
4.9.1.1
A Boolean variable, OPRG1h,b indicates whether a dispatchable
generation facility at bus b is committed in hour h. A value of zero
indicates that a resource is not committed, while a value of one
indicates that it is committed. Therefore:
OPRGh1,b  0 or 1, for all hours h and buses b.
4.9.1.2
Must-run resources will be considered committed for all must-run
hours. Regulating units will be considered committed for all the hours
that they are regulating. Generation facilities with zero commitment
cost (i.e., their minimum loading points, start-up costs minimum
generation block run-times and minimum generation block down times
are zero) and hourly loads, imports and exports will be considered
committed for all the hours.
4.9.1.3
No schedule can be negative, nor can any schedule exceed the amount
of capacity offered for that service (energy and operating reserve).
Therefore:
0  SPRL1j ,h,b  QPRL j ,h,b ;
0  10SSPRL1j ,h,b  10SQPRL j ,h,b ;
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0  10NSPRL1j ,h,b  10NQPRL j ,h,b ;
0  30RSPRL1j ,h,b  30RQPRL j ,h,b ;
0  SHXL1j ,h,d  QHXL j ,h,d ;
0  SX10N 1j ,h,d  QX10N j ,h,d ;
0  SX30R1j ,h,d  QX30R j ,h,d ;
0  SHIG k1,h,d  QHIG k ,h,d ;
0  SI10N k1,h,d  QI10N k ,h,d ; and
0  SI30Rk1,h,d  QI30Rk ,h,d
for all bids j, offers k, hours h, buses b and intertie zones sink/source
bus d.
4.9.1.4
In the case of generation facilities, in addition to restrictions on their
schedules similar to those above, their schedules must be consistent
with their operating status as described above. Generation facilities
can be scheduled to produce energy and/or operating reserve only if
they are committed. Therefore:
0  SPRGk1,h,b  OPRGh1,b  QPRGk ,h,b ;
0  10SSPRGk1,h,b  OPRGh1,b  10SQPRGk ,h,b ;
0  10NSPRGk1,h,b  OPRGh1,b  10NQPRGk ,h,b ; and
0  30RSPRG k1,h,b  OPRGh1,b  30RQPRG k ,h,b
for all offers k, hours h, and buses b.
4.9.1.5
Page 100 of 164
In the case of linked wheeling transactions (the export bid and the
import offer have the same NERC tag identifier), the amount of
scheduled export energy must be equal to the amount of scheduled
import energy. Therefore:
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 SHXL

1
j ,h ,dx
jJ d
 SHIG
kkd
1
k ,h ,di
where dx and di are the respective buses of the export and import
schedules associated with the wheeling transactions.
4.9.1.6
The minimum and/or maximum output of internal resources may be
limited because of outages and/or de-ratings or in order for the units to
provide regulation or voltage support. These constraints will take the
form:
MinPRG h,b  MinQPRG h,b  OPRG h1,b 
4.9.1.7
kKb
1
k ,h ,b
 MaxPRGh,b .
Similarly, the maximum level of load reduction is the mechanism by
which a dispatchable load indicates any de-rating to its registered
maximum load reduction level due to mechanical or operational
adjustments to their equipment. The constraint will take the form:
 SPRL
1
j ,h ,b
jJ b
4.9.2
 SPRG
 MaxPRLh,b .
Operating Reserve Constraints
4.9.2.1
The total reserve (10-minute synchronized, 10-minute nonsynchronized and 30-minute) from committed dispatchable load
cannot exceed its ramp capability over 30 minutes. It cannot exceed
the total scheduled load (maximum load bid minus the load
reductions). These conditions can be enforced by the following two
constraints:
 (10SSPRL
1
j ,h ,b
jJ b
 10NSPRL1j ,h,b  30RSPRL1j ,h,b )
 30  ORRPRL b ; and
 (10SSPRL
1
j ,h ,b
jJ b

 (QPRL
jJ b
4.9.2.2
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 10NSPRL1j ,h ,b  30RSPRL1j ,h ,b )
j ,h ,b
 SPRL1j ,h ,b ).
In addition, this next constraint ensures that the total (10-minute
synchronized, 10-minute non-synchronized and 30-minute) from
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committed dispatchable load cannot exceed the dispatchable load’s
ramp capability to increase load reduction (schedules for hour, h=0 are
obtained from the initializing inputs listed in section 3.8):
 (10SSPRL
1
j ,h ,b
jJ b
 10NSPRL1j ,h ,b  30RSPRL1j ,h,b )

 
   QPRL j ,h1,b  SPRL1j ,h1,b  QPRL j ,h,b  SPRL1j ,h ,b

jJ b
 60  URRPRL b .
4.9.2.3
Finally, the total 10-minute synchronized, 10-minute no-synchronized
and 30-minute operating reserve from committed dispatchable load
cannot exceed the dispatchable load’s Pass 1 scheduled consumption:
 (10SSPRL
1
j ,h ,b
jJ b
 10NSPRL1j ,h ,b  30RSPRL1j ,h ,b )
 MaxPRLh ,b   SPRL1j ,h ,b .
jJ b
4.9.2.4
The amount of 10-minute synchronized reserve plus the 10-minute
non-synchronized reserve that a dispatchable load is scheduled to
provide cannot exceed the amount by which it can decrease its load
over 10 minutes, as limited by its operating reserve ramp rate. This
condition can be enforced by the following constraint:
10SSPRL
1
j ,h ,b
jJb
4.9.2.5
 10NSPRL1j ,h,b  10  ORRPRL b .
The total reserve (10-minute synchronized, 10-minute nonsynchronized and 30-minute) from committed generation facility
cannot exceed its ramp capability over 30 minutes. It cannot exceed
the remaining capacity (maximum offered generation minus the energy
schedule). These conditions can be enforced by the following two
constraints:
 (10SSPRG
kKb
1
k ,h ,b
 10NSPRGk1,h,b  30RSPRG k1,h ,b )
 30  ORRPRG b ; and
 (10SSPRG
kK b

 (QPRG
kK b
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1
k ,h ,b
 10NSPRGk1,h ,b  30RSPRG k1,h,b )
k ,h ,b
 SPRG k1,h ,b ).
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4.9.2.6
In addition, this next constraint ensures that the total (10-minute
synchronized, 10-minute non-synchronized and 30-minute) from
committed dispatchable generation facility cannot exceed the
generation facility’s ramp capability to increase generation (schedules
for hour, h=0 are obtained from the initializing inputs listed in section
3.8):
 (10SSPRG
kKb

1
k ,h ,b
 SPRG
kKb
 10NSPRGk1,h,b  30RSPRG k1,h,b )
1
j ,h1,b
 SPRG 1j ,h,b 


 60 1  0.5(OPRG h1,b  OPRG h11,b ) URRPRG b .
4.9.2.7
Finally, the total (10-minute synchronized, 10-minute nonsynchronized and 30-minute) from committed generation facility
cannot exceed its Pass 1 unscheduled capacity:
 (10SSPRG
kK b
1
k ,h ,b
 10NSPRGk1,h ,b  30RSPRG k1,h ,b )
 MaxPRGh ,b 
4.9.2.8
1
k ,h ,b
kKb
jJ d
1
j , h ,d
 (SX10N
jJ d
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 MinQPRG h ,b .
 10NSPRGk1,h,b )  10  ORRPRG b .
The total reserve (10-minute non-synchronized and 30-minute) from
hourly exports cannot exceed its ramp capability over 30 minutes. It
cannot exceed the total scheduled export. These conditions can be
enforced by the following two constraints:
 (SX10N
4.9.2.10
kK b
1
k ,h ,b
The amount of ten-minute operating reserve (both synchronized and
non-synchronized) that a generation facility is scheduled to provide
cannot exceed the amount by which it can increase its output over 10
minutes, as limited by its operating reserve ramp rate. This condition
can be enforced by the following constraint:
 (10SSPRG
4.9.2.9
 SPRG
1
j ,h ,d
 SX30R1j ,h,d )  30  ORRHXL d ; and
 SX30R1j ,h,d ) 
 SHXL
jJ d
1
j , h ,d
.
The amount of 10-minute non-synchronized reserve that hourly export
is scheduled to provide cannot exceed the amount by which it can
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decrease its load over 10 minutes, as limited by its operating reserve
ramp rate. This condition can be enforced by the following constraint:
 (SX10N
jJ d
4.9.2.11
)  10  ORRHXL d .
The total reserve (10-minute non-synchronized and 30-minute) from
hourly imports cannot exceed its ramp capability over 30 minutes. It
cannot exceed the remaining capacity (maximum import offer minus
scheduled energy import). These conditions can be enforced by the
following two constraints:
 (SI10N
1
k ,h , d
 SI30Rk1,h,d )  30  ORRHIG d ; and
 (SI10N
1
k ,h,d
 SI30Rk1,h,d ) 
kKd
kK d
4.9.2.12
1
j ,h ,d
 (QHIG
kK d
k ,h,d
 SHIG k1,h,d ).
The amount of 10-minute non-synchronized reserve that hourly import
is scheduled to provide cannot exceed the amount by which it can
increase the output over 10 minutes, as limited by its operating reserve
ramp rate. This condition can be enforced by the following constraint:
 SI10N
kKd
1
k ,h ,d
 10  ORRHIG d .
4.10
Bid/Offer Inter-Hour/Multi-Hour Constraints
4.10.1
Status Variables
4.10.1.1
A Boolean variable, IPRG1h,b, indicates that a generation facility at bus
b are scheduled to start up on hour h. A value of zero indicates that a
resource is not scheduled to start up, while a value of one indicates that
it is scheduled to start up. Therefore, for h > 1:
 1, if OPRGh11,b  0 and OPRGh1,b  1
IPRGh1,b  
 0, otherwise.
4.10.1.2
For h = 1, the determination of whether a resource was previously
operating must make reference to the initial conditions:
IPRG
4.10.2
Page 104 of 164
1
h,b
1, if InitOperHr sb  0 and OPRGh1,b  1

 0, otherwise.
Ramping
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4.10.2.1
Energy schedules for each resource cannot vary by more than an
hour’s ramping capacity for that resource. The energy schedule change
in the hour in which the unit is scheduled to start or shut down depends
on the unit ramp rate below its minimum loading point. Almost all
non-quick start units will need one or more hours to reach their
minimum loading point and to go down from minimum loading point
to zero. Since non-committed units must be assigned zero output and
committed units must operate at or above their minimum loading point,
it is assumed that these units will be at their minimum loading point at
the beginning of the first commitment hour and at the end of the hour
before shut down.
4.10.2.2
The following constraint uses the fact that the unit commitment status
changes from zero to one when the unit starts and stays at one for all
the hours the unit is committed and changes back to zero when the unit
shuts down. The left side of the inequality is the lower limit and the
right side of the inequality is the upper limit of the schedule for the
generating facility respectively.
 SPRG
kKb

1
k ,h1,b
 SPRG
1
k ,h ,b
 SPRG
1
k ,h1,b
kKb


kKb

 60 0.5(OPRG h1,b  OPRG h11,b )  1 DRRPRG b


 60 1  0.5(OPRG h1,b  OPRG h11,b ) URRPRG b .
4.10.2.3
It should be noted that this ramp up/down is in addition to the
minimum loading point. The unit commitment process handles the
minimum loading point change. This ramp only affects the incremental
change above the minimum loading point.
4.10.2.4
The dispatchable loads are considered committed in all hours. Similar
logic is applied to dispatchable loads to arrive at the following
constraint:
 QPRL
jJ b

j ,h ,b
 QPRL
j ,h1,b
jJ b
4.10.2.5
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
 SPRL1j ,h1,b  60  URRPRL h ,b
 QPRL
jJ b

j ,h1,b
 SPRL1j ,h ,b


 SPRL1j ,h1,b  60  DRRPRL h ,b .
The above two constraints apply for all hours from 1 to 24. In the
above two constraints the variables related to hour zero belong to the
last hour of the previous day and are obtained from the initializing
assumptions.
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4.10.2.6
The ramping rates in the ramping constraints must be adjusted to allow
the resource to:
a) Ramp down from its lower limit in hour (h-1) to its upper limit in
hour h.
b) Ramp up from its upper limit in hour (h-1) to its lower limit in
hour h.
4.10.2.7
This will allow a solution to be obtained when changes to the upper
and lower limits between hours are beyond the ramping capability of
the resources.
4.10.2.8
In the above ramping constraints, a single ramp up and a single ramp
down, URRPRGb and DRRPRGb for generation facilities and
URRPRLb and DRRPRLb for dispatchable loads are used. The ramp
rate is assumed constant over the full operating range of the
dispatchable load and generation facility. However, this is not the
case. Dispatchable load bids and generator offers will include multienergy ramp rates.
4.10.2.9
In the dispatchable load bids, multi-energy ramp rates would be
specified as:
a) RmpRngMaxPRLj, b shall designate the level of maximum load
reduction to which the ramp rates URRPRLj,b and DRRPRLj,b shall
apply. RmpRngMaxPRL5,b must be greater than or equal to
maximum load reduction bid.
b) URRPRLj,b shall designate the maximum rate per minute at which a
dispatchable load at bus b can increase load reduction while
operating in the range between RmpRngMaxPRLj-1,b and
RmpRngMaxPRLj,b. RmpRngMaxPRL0,b is equal to the minimum
load reduction.
c) DRRPRLj,b shall designate the maximum rate per minute at which a
dispatchable load at bus b can decrease load reduction while
operating in the range between RmpRngMaxPRLj-1,b and
RmpRngMaxPRLj,b. RmpRngMaxPRL0,b is equal to the minimum
load reduction.
4.10.2.10 The multi-energy ramp rates would be specified for generation
facilities as:
a) RmpRngMaxPRGk,b shall designate the maximum generation
output level to which the ramp rates URRPRGk,b and DRRPRGk,b
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shall apply. RmpRngMaxPRG5,b must be greater than or equal to
maximum generation output offered.
b) URRPRGk,b shall designate the maximum rate per minute at which
a generation facility at bus b can increase its output while
operating in the range between RmpRngMaxPRGk-1,b and
RmpRngMaxPRGk,b. RmpRngMaxPRG0,b is equal to its minimum
loading point.
c) DRRPRGk,b shall designate the maximum rate per minute at which
a generation facility at bus b can decrease its output while
operating in the range between RmpRngMaxPRGk-1,b and
RmpRngMaxPRGk,b. RmpRngMaxPRG0,b is equal to its minimum
loading point.
4.10.3
Minimum Generation Block Run Time and Minimum Generation Block Down
Time
4.10.3.1
Schedules for generators must observe minimum generation block run
times and minimum generation block down times. At the beginning of
the day, a generation facility’s previous day schedule is considered,
if 0 < InitOperHrsb < MRTPRGb, then that generation facility has yet
to complete its minimum generation block run time, and:
1
OPRG11,b , OPRG21,b ,..., OPRG min(
24, MRTPRGb  InitOperHrsb ),b  1.
4.10.3.2
During the day,
if OPRG1h,b = 1, OPRG1h+1,b = 0, and MDTPRGb > 1, then the
generation facility at bus b has been scheduled to shut down during
hour h + 1. It must be scheduled to remain off until it has completed its
minimum generation block down time or we reach the end of the day.
Therefore:
1
OPRG h12,b , OPRG h13,b ,..., OPRG min(
24,h MDTPRGb ),b  0.
And if OPRG1h,b = 0, OPRG1h+1,b = 1, and MRTPRGb > 1, then the
generation facility at bus b has been scheduled to start up during hour
h + 1. It must be scheduled to remain in operation until it has
completed its minimum generation block run time or we reach the end
of the day, so:
1
OPRGh12,b , OPRGh13,b ,..., OPRGmin(
24,h MRTPRGb ),b  1, and
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0, if InitOperHr sb  0

OPRG 01,b  
1, otherwise.
4.10.4
Energy Limited Resources
4.10.4.1
A constraint must be added in order to ensure that energy-limited units
are not scheduled to provide more energy than they have indicated
they are capable of providing. In addition to limiting energy schedules
over the course of the day to the energy limit specified for a unit, this
constraint must also ensure that units are not scheduled to provide
energy in amounts that would preclude them from providing reserve
when activated. Given these factors, therefore:
1

  OPRG
h 1

1
h ,b
 MinQPRG h ,b 
 SPRG
kK b
1
k ,h ,b






 10ORConv   10SSPRG k1,1,b   10NSPRGk1,1,b 
kK b
 kKb

1
 30ORConv  30RSPRG k ,1,b  ELb ;
kK b
2

  OPRG
h 1

1
h ,b
 MinQPRG h ,b 
 SPRG
kK b
1
k ,h ,b






 10ORConv   10SSPRG k1, 2,b   10NSPRGk1, 2,b 
kK b
 kKb

1
 30ORConv  30RSPRG k , 2,b  ELb ;
kK b

24

  OPRG
h 1

1
h ,b
 MinQPRG h ,b 
 SPRG
kK b
1
k ,h ,b






 10ORConv   10SSPRG k1, 24,b   10NSPRGk1, 24,b 
kK b
 kKb

1
 30ORConv  30RSPRG k , 24,b  ELb
kK b
for all buses b at which energy-limited resources are located. The
factors 10ORConv and 30ORConv are applied to scheduled ten-minute
and thirty-minute operating reserves for energy-limited resources to
convert MW into MWh. This factor is initially set to unity.
4.10.5
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4.10.5.1
To ensure that generation facilities are not scheduled to be cycled on
and off more than their specified maximum number in a day, the
following constraint is defined:
24
 IPRG
h 1
1
h ,b
 MaxStartsPRGb .
4.11
Constraints to Ensure Schedules Do Not Violate
Reliability Requirements
4.11.1
Load
4.11.1.1
For each hour of the DACP, the total amount of energy generated in
the DACP schedule, plus scheduled imports must be sufficient to meet
forecast demand, scheduled exports, and transmission losses consistent
with these schedules. It will be easiest to break the derivation of the
constraint that will ensure this occurs into several steps.
4.11.1.2
First, define the total amount of withdrawals scheduled in Pass 1 at
each bus b in each hour h, With1h,b, as the sum of:

the portion of the load forecast for that hour that has been allocated
to that bus;

all dispatchable load bid, net of the amount of load reduction
scheduled (since the dispatchable load is excluded from the
demand forecast by the DACP calculation engine);

exports from Ontario to each intertie zone sink bus; and

outflows from Ontario associated with loop flows between Ontario
and each intertie zone, allocated among the buses in the intertie
zones using the distribution factors developed for that purpose,
yielding:


Withh1,b  LDFh ,b  AFLh    QPRL j ,h ,b  SPRL1j ,h ,b ; and
 jJ b

1
1
Withh ,d   ( SHXL j ,h ,d )   ProxyUPOWtd ,a  min( 0, PFh ,a ).

jJ d
4.11.1.3
IMO-FORM-1087 v.11.0
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
aA
The total amount of injections scheduled in Pass 1 at each bus b in
each hour h, Inj1h,b, is the sum of

generation facilities scheduled at that bus;

imports into Ontario from each intertie zone source bus; and
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
inflows from Ontario associated with loop flows between Ontario
and each intertie zone, allocated among the buses in the intertie
zones using the distribution factors developed for that purpose:
Inj h1,b  OPRG h1,b  MinQPRG h ,b 
Inj h1,d 
4.11.1.4
 SHIG
kK d
1
k ,h ,d
 SPRG
kK b
1
k ,h ,b
; and
  ProxyUPIWtd ,a  max( 0, PFh ,a ).
aA
Injections and withdrawals at each bus must be multiplied by one plus
the marginal loss factor to reflect the losses (or reduction in losses)
that result when injections or withdrawals occur at locations other than
the reference bus. These loss-adjusted injections and withdrawals must
then be equal to each other, after taking into account any system loss
adjustment that is required due to the difference between average and
marginal losses. Load reduction associated with the demand constraint
violation will be subtracted from the total load and generation
reduction will be subtracted from total generation associated with the
demand constraint violation to ensure that the DACP calculation
engine will always produce a solution. These violation variables are
assigned a very high cost to limit their use to infeasible cases.
 (1  MglLoss
bB
h ,b
)Withh1,b   (1  MglLoss h,d )Withh1,d  SLdViolh1
  (1  MglLoss h,b ) Inj
bB
dD
1
h ,b
  (1  MglLoss h,d ) Injh1,d  SGenViolh1  LossAdjh .
dD
4.11.2
Operating Reserve
4.11.2.1
Sufficient operating reserve must be provided on the system to meet
system wide requirements for 10-minute synchronized reserve, tenminute operating reserve and thirty-minute operating reserve, as well
as all applicable regional minimum and maximum requirements for
operating reserve.
4.11.2.2
Therefore, taking into consideration the potential not to meet these
minimum and maximum requirements if the cost of meeting those
requirements becomes too high:

   10SSPRG
bB
Page 110 of 164
 kKb
 TOT10S h ;
1
k ,h ,b



     10SSPRL1j ,h ,b   S10SViol h1
 bB  jJ


 b

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



     10SSPRGk1,h ,b   S10RViol h1
 bB  kK

bB  jJ b

 b





    10NSPRGk1,h ,b      10NSPRL1j ,h ,b 
bB  kK b
 bB  jJ b





    SI10N k1,h ,d      SX10N 1j ,h ,d   TOT10Rh ; and
dD  kK d
 dD  jJ d

   10SSPRL

1
j ,h ,b
   10SSPRL
bB
 jJ b
1
j ,h ,b



     10SSPRG k1,h ,b   S30RViol h1
 bB  kK


 b



    (10NSPRGk1,h ,b  30RSPRG k1,h ,b ) 
bB  kK b



    (10NSPRL1j ,h ,b  30RSPRL1j ,h ,b ) 
bB  jJ b



    ( SI10N k1,h ,d  SI30Rk1,h ,d ) 
dD  kK d



    ( SX10N 1j ,h ,d  SX30R1j ,h ,d )   TOT30Rh
dD  jJ d

for all hours h, and




     10SSPRG k1,h ,b   SREG10RVio lr1,h



br  jJ b
 br  kKb





    10NSPRGk1,h ,b      10NSPRL1j ,h ,b 
br  kK b
 br  jJ b

 REGMin10R r ,h ;
   10SSPRL

1
j ,h ,b



     10SSPRG k1,h ,b   SXREG10RViolr1,h
 br  kK

br  jJ b

 b





    10NSPRGk1,h ,b      10NSPRL1j ,h ,b 
br  kK b
 br  jJ b

 REGMax10Rr ,h ;
   10SSPRL
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1
j ,h ,b
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



     10SSPRG k1,h ,b   SREG30RVio l r1,h
 br  kK

br  jJ b

 b



    (10NSPRG k1,h ,b  30RSPRG k1,h ,b ) 
br  kK b



    (10NSPRL1j ,h ,b  30RSPRL1j ,h ,b ) 
br  jJ b

 REGMin30R r ,h ; and
   10SSPRL
1
j , h ,b




     10SSPRG k1,h ,b   SXREG30RViolr1,h
 br  kK

br  jJ b

 b



    (10NSPRGk1,h ,b  30RSPRG k1,h ,b ) 
br  kK b



    (10NSPRL1j ,h ,b  30RSPRL1j ,h ,b ) 
br  jJ b

 REGMax30Rr ,h
   10SSPRL
1
j ,h ,b
for all hours h, and for all regions r in the set ORREG.
4.11.3
Internal Transmission Limits
4.11.3.1
The IESO must ensure that the set of DACP schedules produced by
Pass 1 of the DACP calculation engine would not violate any security
limits in either the pre-contingency state or after any contingency.
4.11.3.2
To develop the constraints to ensure that this occurs, the total amount
of energy scheduled to be injected at each bus and the total amount of
energy scheduled to be withdrawn at each bus will be used.
4.11.3.3
The security assessment function of the DACP calculation engine will
linearize binding (violated) pre-contingency limits on transmission
facilities within Ontario. The linearized constraints will take the form:
 PreConSF
bB
b , f ,h
( Inj h1,b  Withh1,b )   PreConSFd , f ,h ( Inj h1,d  Withh1,d )
 SPreConITLViol
dD
1
f ,h
 AdjNormMaxFlow f ,h
where D is the set of sink and source buses outside Ontario, for all
facilities f and hours h.
4.11.3.4
Page 112 of 164
Similarly, the linearized binding post-contingency limits will take the
form:
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 SF
bB
b , f ,c ,h
( Injh1,b  Withh1,b )   SFd , f ,c ,h ( Inj h1,d  Withh1,d )
 SITLViol
dD
1
f ,c , h
 AdjEmMaxFlow f ,c ,h
for all facilities f, hours h, and monitored contingencies c.
4.11.4
Intertie Limits and Constraints on Net Imports
4.11.4.1
The IESO must ensure that the set of DACP schedules produced by
Pass 1 of the DACP calculation engine would not violate any security
limits associated with interties between Ontario and intertie zones. To
ensure this, we must calculate the net amount of energy scheduled to
flow over each intertie in each hour and the amount of operating
reserve scheduled to be provided by resources in that control area.
This will be summed over all affected interties. The result will be
compared to the limit associated with that constraint. Consequently:


 
1
1
 EnCoeffa , z   ( SHIG k ,h ,d )  PFh ,a   ( SHXL j ,h ,d )   
dDX a , jJ d

 dDIa ,kK d
 


  SI10N k1,h ,d  SI30Rk1,h ,d




aA

0.5( EnCoeff  1) dDIa ,kK d

a,z


1
1



SX10N

SX30R
, jJ
j ,h ,d
j ,h ,d 



d

DX
a
d




 MaxExtSchz ,h




for all hours h, for all intertie zones a relevant to the constraint z
( EnCoeffa , z  0 ), and for all constraints z in the set Zsch.
4.11.4.2
IMO-FORM-1087 v.11.0
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In addition, changes in the net energy schedule over all interties cannot
exceed the limits set forth by the IESO for hour-to-hour changes in
those schedules. The net import schedule is summed over all interties
for a given hour. It cannot exceed the sum of net import schedule for
all interties for the previous hour plus the maximum permitted hourly
increase. It cannot be less than the sum of the net import schedule for
all interties for the previous hour minus the maximum permitted
hourly decrease. Violation variables are provided for both the up and
down ramp limits to ensure that the DACP calculation engine will
always find a solution. Therefore:
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

)   ( SHXL1j ,h 1,d )   ExtDSCh  SDRmpXTLViol h1
d D  kK d
jJ d



    ( SHIG k1,h ,a )   ( SHXL1j ,h ,d ) 
d D  kK d
jJ d



    ( SHIG k1,h 1,d )   ( SHXL1j ,h 1,d )   ExtUSCh  SURmpXTLViol h1
d D  kK d
jJ d

   (SHIG
1
k , h 1, d
for all hours h (schedules for hour, h=0 are obtained from the
initializing inputs listed in section 3.8).
4.12
Shadow Prices for Energy
4.12.1
The Pass 1 shadow price at each bus b in each hour h measures the offered price
of meeting an infinitesimal change in the amount of load at that bus in that hour,
or equivalently, measures the value of an incremental amount of generation at that
bus in that hour in Pass 1. The Pass 1 shadow price at each bus b in each hour h,
given the inputs and constraints into Pass 1, shall be calculated at internal
locations as:
1
h ,b
LMP
4.12.2

 PreConSFb , f ,h  SPNormT f1,h 


1

 1  MglLoss h ,b  SPLh   
1
.

SF

SPEmT


b , f ,c , h
f ,c , h

f 
 c


The first portion of the right-hand side of this equation measures the cost of
meeting load at bus b, incorporating the effect of marginal losses. It reflects the
quantity of energy that must be injected at the reference bus to meet additional
load at each bus b. The term in the summation reflects the cost of transmission
congestion resulting from an infinitesimal increase in withdrawals at each bus b
on each pre- and post-contingency internal transmission constraint. It is calculated
as the product of each:
Shadow price, which measures the impact on the cost on that constraint if there were a oneto-one correspondence between increases in load and flows on the constraint (i.e.,
if each MW of increased load caused an increase in 1 MW inflows over the
constraint); and
The shift factor for that bus and that constraint, which measures the actual impact of
additional withdrawals at each bus on flows over that constraint.
4.12.3
Page 114 of 164
Note that the term is multiplied by negative one since the shift factors for each
bus are defined in terms of the impact on a facility of an increment of generation
at that bus offset by an increment of load at the reference bus. For the purposes of
this equation, we need to know the impact on flows over that facility of an
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increment of load at each location offset by an increment of generation at each
bus. If we reverse the location of incremental load and generation, the impact on
flows on each facility will also be reversed.
5.0
Pass 2: Constrained Commitment to
Meet Peak Demand
5.1
Overview
5.1.1
Pass 2 performs a least cost, security constrained unit commitment and
constrained scheduling to meet the forecast peak demand and IESO-specified
operating reserve requirements.
5.1.2
In each hour, peak demand occurs for a fraction of that hour. If additional
commitment of generation facilities above those made in Pass 1 are required to
meet peak demand, these generation facilities would only need to be operating for
a fraction of the hour. Therefore, in Pass 2, the DACP calculation engine performs
least cost optimization with respect to minimizing commitment costs to satisfy
peak demand.
5.1.3
Imports and exports can only be scheduled on an hourly basis and generation
facilities and dispatchable loads can follow 5-minute dispatches to meet peak
demand. To account for this difference in scheduling, the incremental prices of
generator offers and dispatchable load bids will be evaluated on this basis against
import offers and export bids. This evaluation of generator offers and
dispatchable load bids is explained in detail in section 5.7.
5.1.4
Generation facilities already committed in Pass 1 is taken as committed in Pass 2.
These resources will be scheduled to no less than their minimum loading points.
Additional commitments of offers from generators are allowed.
5.1.5
Imports scheduled in Pass 1 must be scheduled to at least that value in Pass 2.
Additional hourly imports may be scheduled. Hourly exports may be scheduled to
a lower but not higher value than that determined in Pass 1. The import and export
components of linked wheel transactions can be scheduled higher or lower than
the schedules produced in Pass 1. The commitments and schedules calculated in
Pass 2 will be used in Pass 3.
5.2
Inputs into Pass 2
5.2.1
IMO-FORM-1087 v.11.0
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All inputs identified in section 3 will be used in Pass 2. In addition,
Pass 1 generation facility commitments, import schedules, exports
schedules and shadow prices will also be used as input into Pass 2.
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5.3
Optimization Objective for Pass 2
5.3.1
As for Pass 1, the gains from trade shall be maximized for Pass 2.
This is accomplished by maximizing the same objective function
described in section 4.3 used for Pass 1.
5.4
Security Assessment
5.4.1
The same security assessment is performed as described in section 4.4.
5.5
Outputs from Pass 2
5.5.1
The primary outputs of Pass 2 which are used in Pass 3 and other DACP
processes include the following:
5.5.1.1
Commitments; and
5.5.1.2
Constrained schedules for energy.
5.6
Glossary of Sets, Indices, Variables and Parameters for
Pass 2
5.6.1
Fundamental Sets and Indices
5.6.1.1
5.6.2
Same as those described in section 4.6.1.
Variables and Parameters
5.6.2.1
Bid and Offer Inputs
Same as those described in 4.6.2.1. In addition, the variables below are
used to account for the fact that generation facilities and dispatchable
loads are able to follow 5-minute dispatches to meet peak demand but
imports and exports are only scheduled on an hourly basis:
Page 116 of 164
PmtPRGk,h,b
The lowest incremental energy price at which an
incremental amount of energy should be
scheduled at bus b in hour h in association with
offer k to meet peak demand.
PmtPRLj,h,b
The lowest incremental energy price at which an
incremental quantity of reduction in energy
consumption should be scheduled at bus b in hour
h in association with bid j to meet peak demand.
PriceMultiplier
A bid and offer adjustment factor to account for
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the value of energy from dispatchable loads and
generation facilities dispatched on a 5-minute
basis to meet peak demand of any hour. This
factor shall be 12.
5.6.2.2
Transmission and Security Inputs and Intermediate Variables
Same as those described in 4.6.2.2.
5.6.2.3
Other Inputs
Same as those described in 4.6.2.3.
5.6.2.4
Constraint Violation Price Inputs
Same as those described in 4.6.2.4.
5.6.2.5
Variables determined in Pass 1 and Used in Pass 2
SHXL1j,h,d
The amount of exports scheduled in hour h in Pass
1 from intertie zone, d in association with each bid
j.
SHIG1k,h,d
The amount of imports scheduled in hour h in
Pass 1 from intertie zone d in associate with each
offer k.
OPRG1h,b
Indication of whether a generation facility at bus b
was scheduled to operate in hour h in Pass 1.
LMP1h,b
5.6.2.6
The Pass 1 locational marginal price for energy at
each bus b in each hour h.
Output Schedule and Commitment Variables
SHXL2j,h,d
The amount of exports scheduled in hour h in Pass
2 from intertie zone sink bus d in association with
each bid j.
SX10N2j,h,d
The amount of non-synchronized ten-minute
operating reserve scheduled from the export in
hour h in Pass 2 from intertie zone sink bus d in
association of bid j.
SX30R2j,h,d
The amount of thirty-minute operating reserve
scheduled from the export in hour h in Pass 2
from intertie zone sink bus d in association of bid
j.
SPRL2j,h,b
The amount of dispatchable load reduction
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scheduled at bus b in hour h in Pass 2 in
association with each bid j at that bus.
Page 118 of 164
10SSPRL2j,h,b
The amount of synchronized ten-minute operating
reserve that a qualified dispatchable load is
scheduled to provide at bus b in hour h in Pass 2
in association of bid j for this bus.
10NSPRL2j,h,b
The amount of non-synchronized ten-minute
operating reserve that a qualified dispatchable
load is scheduled to provide at bus b in hour h in
Pass 2 in association of bid j for this bus.
30RSPRL2j,h,b
The amount of thirty-minute operating reserve
that a qualified dispatchable load is scheduled to
provide at bus b in hour h in Pass 2 in association
of bid j for this bus.
SHIG2k,h,d
The amount of hourly imports scheduled in hour h
from intertie zone source bus d in Pass 2 in
association with each offer k.
SI10N2k,h,d
The amount of imported ten-minute operating
reserve scheduled in hour h from intertie zone
source bus d in Pass 2 in association with each
offer k.
SI30R2k,h,d
The amount of imported thirty-minute operating
reserve scheduled in hour h from intertie zone
source bus d in Pass 2 in association with each
offer k.
SPRG2k,h,b
The amount scheduled for the generation facility
at bus b in hour h in Pass 2 in association with
each offer k at that bus. This is in addition to any
MinQPRG h,b, the minimum loading point, which
must also be committed.
OPRG2h,b
Represents whether the generation facility at bus b
has been scheduled in hour h in Pass 2.
IPRG2h,b
Represents whether generation facility at bus b
has been scheduled to start in hour h in Pass 2.
10SSPRG2k,h,b
The amount of synchronized ten-minute operating
reserve that a qualified generation facility at bus b
is scheduled to provide in hour h in Pass 2 in
association of offer k for this bus.
10NSPRG2k,h,b
The amount of non-synchronized ten-minute
operating reserve that a qualified generation
facility at bus b is scheduled to provide in hour h
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in Pass 2 in association of offer k for this bus.
2
30RSPRG
5.6.2.7
The amount of thirty-minute operating reserve
that a qualified generation facility at bus b is
scheduled to provide in hour h in Pass 2 in
association of offer k for this bus.
Output Violation Variables
k,h,b
ViolCost2h
The cost incurred in order to avoid having the
Pass 2 schedules for hour h violate specified
constraints.
SLdViol2h
Projected load curtailment, that is, the amount of
load that cannot be met using offers scheduled or
committed in hour h in Pass 2.
SGenViol2h
The amount of additional load that must be
scheduled in hour h in Pass 2 to ensure that there
is enough load on the system to offset the mustrun requirements of generation facilities.
S10SViol2h
The amount by which the overall synchronized
ten-minute operating reserve requirement is not
met in hour h of Pass 2 because the cost of
meeting that portion of the requirement was
greater than or equal to P10SViol.
S10RViol2h
The amount by which the overall ten-minute
operating reserve requirement is not met in hour h
of Pass 2 (above and beyond any failure to meet
the synchronized ten-minute operating reserve
requirement) because the cost of meeting that
portion of the requirement was greater than or
equal to P10RViol.
S30RViol2h
The amount by which the overall thirty-minute
operating reserve requirement is not met in hour h
of Pass 2 (above and beyond any failure to meet
the ten-minute operating reserve requirement)
because the cost of meeting that portion of the
requirement was greater than or equal to
P30RViol.
SREG10RViol2r,h
The amount by which the minimum ten-minute
operating reserve requirement for region r is not
met in hour h of Pass 2 because the cost of
meeting that portion of the requirement was
greater than or equal to PREG10RViol.
SREG30RViol2r,h
The amount by which the minimum thirty-minute
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operating reserve requirement for region r is not
met in hour h of Pass 2 because the cost of
meeting that portion of the requirement was
greater than or equal to PREG30RViol.
SXREG10RViol2r,h
The amount by which the ten-minute operating
reserve scheduled for region r exceeds the
maximum required in hour h of Pass 2 because the
cost of meeting that the maximum requirement
limit was greater than or equal to PXREG10RViol.
SXREG30RViol2r,h
The amount by which the thirty-minute operating
reserve scheduled for region r exceeds the
maximum required in hour h of Pass 2 because the
cost of meeting the maximum requirement limit
was greater than or equal to PXREG30RViol.
SPreConITLViol2f,h
The amount by which pre-contingency flows over
facility f in hour h of Pass 2 exceed the normal
limit for flows over that facility, because the cost
of alternative solutions that would not result in
such an overload was greater than or equal to
PPreConITLViol.
SITLViol2f,c,h
The amount by which flows over facility f that
would follow the occurrence of contingency c in
hour h of Pass 2 exceed the emergency limit for
flows over that facility, because the cost of
alternative solutions that would not result in such
an overload was greater than or equal to PITLViol.
SPreConXTLViol2z,h
The amount by which intertie flows over facility z
in hour h of Pass 2 exceed the normal limit for
flows over that facility, because the cost of
alternative solutions that would not result in such
an overload was greater than or equal to
PPreConXTLViol.
SURmpXTLViol2h
The amount by which the total net scheduled
import increase for hour h in Pass 2 exceeds the
up ramp limits, because the cost of alternative
solutions that would not result in violation was
greater than or equal to PRmpXTLViol.
SDRmpXTLViol2h
The amount by which the total net scheduled
import decrease in hour h of Pass 2 exceed the
down ramp limits, because the cost of alternative
solutions that would not result in violation was
greater than or equal to PRmpXTLViol.
5.6.2.8
Page 120 of 164
Energy Ramp Rates
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Same as those in section 4.6.2.8.
5.7
Evaluation of Generator Offers and Dispatchable Load
Bids
5.7.1
All offers for generation facilities that were committed in Pass 1 will be evaluated
in Pass 2 as such:
5.7.1.1
PmtPRGk,h,b, designates the lowest incremental energy price at which
an incremental amount of energy should be scheduled at bus b in hour
h in association with offer k. It shall be set to:
PmtPRGk ,h,b  LMP 
1
h ,b
PPRGk ,h,b  LMPh1,b
PriceMulti plier
1
for PmtPRGk ,h,b  LMPh,b and
PmtPRGk ,h,b  PPRGh,b
1
for PmtPRGk ,h,b  LMPh,b .
5.7.1.2
5.7.2
All other elements of the offers will be used in Pass 2 as submitted.
All dispatchable load bids will be evaluated in Pass 2 as such:
5.7.2.1
PmtPRLj,h,b, designates the lowest incremental energy price at which
an incremental quantity of reduction in energy consumption specified
in bid j should be scheduled in hour h at bus b. It shall be set to:
PmtPRL j ,h,b  LMP 
1
h ,b
PPRL j ,h,b  LMPh1,b
PriceMulti plier
1
for PmtPRLj ,h,b  LMPh,b and
PmtPRLj ,h,b  PPRLh,b
1
for PmtPRL j ,h,b  LMPh,b .
5.7.2.2
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5.8
Objective Function
5.8.1
The optimization of the objective function in Pass 2 is to maximize the
expression:






2
2
2
  ( SHXL j ,h ,d  PHXL j ,h ,d  SX10N j ,h ,d  PX10N j ,h ,d  SX30R j ,h ,d  PX30R j ,h ,d )
dDX , jJ d

2


  SPRL j ,h ,b  PmtPRL j ,h ,b



 jJ b





10SSPRL2j ,h ,b  10SPPRL j ,h ,b 10NSPRL2j ,h ,b  10NPPRL j ,h ,b  
  

 bB  


2
jJ b 30RSPRL j , h ,b  30RPPRL j , h ,b






2
2
2
  SHIG k ,h ,d  PHIG k ,h ,d  SI10N k ,h ,d  PI10N k ,h ,d  SI30Rk ,h ,d  PI30Rk ,h ,d ;

h 1,..., 24  d DI , kK d







2
  SPRG k ,h ,b  PmtPRGk ,h ,b



kK b





   OPRG h2,b  MGCPRGh ,b  IPRG h2,b  SUCPRGh ,b


 bB 

10SSPRG k2,h ,b  10SPPRG k ,h ,b 10NSPRG k2,h ,b  10NPPRG k ,h ,b 







 kKb  30RSPRG 2  30RPPRG



k , h ,b
k , h ,b




2
 ViolCost h
 wh
2
ere ViolCost h is calculated as follows:



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
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ViolCost h2  SLdViolh2  PLdViol  SGenViolh2  PGenViol
 S10SViol h2  P10SViol  S10RViol h2  P10RViol
 S30RViol h2  P30RViol
 SREG10RVio lr2,h  PREG10RVio l



  SREG30RVio lr2,h  PREG30RVio l 

  
2
rORREG   SXREG10RViol r ,h  PXREG10RViol 


  SXREG30RViol 2  PXREG30RViol 
r ,h


2
  SPreConXTLViol z ,h  PPreConXTLViol


zZ
 SURmpXTLViol 2  PRmpXTLViol  SDRmpXTLViol 2  PRmpXTLViol
  SPreConITLViol 2f ,h  PPreConITLViol
f F

 SITLViol
f F ,cC
2
f ,c , h
 PITLViol.
5.8.2
The Pass 2 maximization is subject to the constraints described in the next
section.
5.9
Constraints Overview
5.9.1
The constraints applied to the Pass 2 optimization mirror those used in Pass 1 and
described in sections 4.8 through 4.11. They must be modified to:
Apply to schedules determined in Pass 2;
Reflect peak demand forecast compared to average demand forecast used in Pass 1; and
Reflect additional constraints limiting changes in internal resource (generation facilities and
dispatchable loads) commitments, import and export schedules determined in
Pass 1.
5.10
Bid/Offer Constraints Applying to Single Hours
5.10.1
Status Variables and Capacity Constraints
5.10.1.1
For the same reasons as discussed in section 4.9 for Pass 1:
OPRGh2,b  0 or 1, for all hours h and buses b;
0  SPRL2j ,h,b  QPRL j ,h,b ;
0  10SSPRL2j ,h,b  10SQPRL j ,h,b ;
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0  10NSPRL2j ,h,b  10NQPRL j ,h,b ;
0  30RSPRL2j ,h,b  30RQPRL j ,h,b ;
0  SI10N k2,h,d  QI10N k ,h,d ;
0  SI30Rk2,h,d  QI30Rk ,h,d ;
0  SHIG k2,h,d  QHIG k ,h,d ;
0  SHXL2j ,h,d  QHXL j ,h,d ;
0  SX10N 2j ,h,d  QX10N j ,h,d ;
0  SX30R 2j ,h,d  QX30R j ,h,d ;
0  SPRGk2,h,b  OPRGh2,b  QPRGk ,h,b ;
0  10SSPRGk2,h,b  OPRGh2,b  10SQPRGk ,h,b ;
0  10NSPRGk2,h,b  OPRGh2,b  10NQPRGk ,h,b ; and
0  30RSPRG k2,h,b  OPRGh2,b  30RQPRG k ,h,b
for all modified bids j, modified offers k, hours h, and buses b, and
intertie zones source/sink bus d.
5.10.1.2
In the case of linked wheeling transactions (the export bid and the
import offer have the same NERC tag identifier), the amount of
scheduled export energy must be equal to the amount of scheduled
import energy. Therefore:
 SHXL
jJ d
2
j ,h ,dx

 SHIG
kkd
2
k ,h ,di
where dx and di are the respective buses of the export and import
schedules associated with the wheeling transactions.
5.10.1.3
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The minimum and/or maximum output of the generation facilities may
be limited because of outages and/or de-ratings or in order for the units
to provide regulation or voltage support. These constraints will take
the form:
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MinPRG h,b  MinQPRG h,b  OPRG h2,b 
5.10.1.4
kKb
2
k ,h ,b
)  MaxPRGh,b .
Similarly, the maximum level of load reduction is the mechanism by
which a dispatchable load indicates any de-rating to its registered
maximum load reduction level due to mechanical or operational
adjustments to their facility. The constraint will take the form:
 SPRL
2
j ,h ,b
jJ b
5.10.2
 (SPRG
 MaxPRLh,b .
Operating Reserve Constraints
5.10.2.1
The total reserve (10-minute synchronized and non-synchronized and
30-minute) from committed dispatchable load cannot exceed its ramp
capability over 30 minutes. It cannot exceed the total scheduled load
(maximum load bid minus the load reductions). These conditions can
be enforced by the following two constraints:
 (10SSPRL
2
j ,h ,b
jJ b
 10NSPRL2j ,h ,b  30RSPRL2j ,h ,b )
 30  ORRPRL b ; and
 (10SSPRL
2
j ,h ,b
jJ b

 (QPRL
jJ b
5.10.2.2
 10NSPRL2j ,h ,b  30RSPRL2j ,h ,b )
j ,h ,b
 SPRL2j ,h ,b ).
In addition, this next constraint ensures that the total (10-minute
synchronized, 10-minute non-synchronized and 30-minute) from
committed dispatchable load cannot exceed the dispatchable load’s
ramp capability to increase load reduction (schedules for hour, h=0 are
obtained from the initializing inputs listed in section 3.8):
 (10SSPRL
2
j ,h ,b
jJ b
 10NSPRL2j ,h,b  30RSPRL2j ,h,b )

 
   QPRL j ,h1,b  SPRL2j ,h1,b  QPRL j ,h ,b  SPRL2j ,h ,b

jJ b
 60 URRPRL b .
Finally, the total (10-minute synchronized, 10-minute non5.10.2.3
synchronized and 30-minute) from committed dispatchable load
cannot exceed the dispatchable load’s Pass 2 scheduled consumption:
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 (10SSPRL
2
j ,h ,b
jJ b
 10NSPRL2j ,h ,b  30RSPRL2j ,h ,b )
 MaxPRLh ,b   SPRL2j ,h ,b .
jJ b
5.10.2.4
The amount of 10-minute synchronized and non-synchronized reserve
that a dispatchable load is scheduled to provide cannot exceed the
amount by which it can decrease its load over 10 minutes, as limited
by its operating reserve ramp rate. This condition can be enforced by
the following constraint:
10SSPRL
jJb
5.10.2.5
 10NSPRL2j ,h,b  10  ORRPRL b .
2
j ,h ,b
The total reserve (10-minute synchronized, 10-minute nonsynchronized and 30-minute) from committed generation facility
cannot exceed its ramp capability over 30 minutes. It cannot exceed
the remaining capacity (maximum offered generation minus the energy
schedule). These conditions can be enforced by the following two
constraints:
 (10SSPRG
kKb
2
k ,h ,b
 10NSPRGk2,h,b  30RSPRG k2,h,b )
 30  ORRPRG b ; and
 (10SSPRG
kK b

2
k ,h ,b
 (QPRG
kK b
5.10.2.6
 10NSPRGk2,h ,b  30RSPRG k2,h,b )
k ,h ,b
 SPRG k2,h ,b ).
In addition, this next constraint ensures that the total(10-minute
synchronized, 10-minute non-synchronized and 30-minute) from the
committed generation facility cannot exceed its ramp capability to
increase generation (schedules for hour, h=0 are obtained from the
initializing inputs listed in section 3.8):
 (10SSPRG
kKb

2
k ,h ,b
 SPRG
kKb

 10NSPRGk2,h,b  30RSPRG k2,h,b )
2
j ,h1,b
 SPRG 2j ,h,b 

 60 1  0.5(OPRG h2,b  OPRG h21,b ) URRPRG b .
5.10.2.7
Page 126 of 164
Finally, the total (10-minute synchronized, 10-minute nonsynchronized and 30-minute) from the committed generation facility
cannot exceed its Pass 2 unscheduled capacity:
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 (10SSPRG
2
k ,h ,b
kK b
 10NSPRGk2,h ,b  30RSPRG k2,h,b )
 MaxPRGh ,b 
5.10.2.8
kK b
2
k ,h ,b
 MinQPRG h ,b .
The amount of ten-minute operating reserve (both synchronized and
non-synchronized) that a generation facility is scheduled to provide
cannot exceed the amount by which it can increase its output over 10
minutes, as limited by its operating reserve ramp rate. This condition
can be enforced by the following constraint:
 (10SSPRG
2
k ,h ,b
kKb
5.10.2.9
 SPRG
 10NSPRGk2,h,b )  10  ORRPRG b .
The total reserve (10-minute non-synchronized and 30-minute) from
hourly exports cannot exceed its ramp capability over 30 minutes. It
cannot exceed the total scheduled export. These conditions can be
enforced by the following two constraints:
 (SX10N
2
j ,h ,d
 (SX10N
2
j ,h,d
jJ d
jJ d
 SX30R2j ,h,d )  30  ORRHXL d ; and
 SX30R 2j ,h,d ) 
 SHXL
jJ d
2
j ,h ,d
.
5.10.2.10 The amount of 10-minute non-synchronized reserve that an hourly
export is scheduled to provide cannot exceed the amount by which it
can decrease its load over 10 minutes, as limited by its operating
reserve ramp rate. This condition can be enforced by the following
constraint:
 SX10N
jJ d
2
j , h ,d
 10  ORRHXL d .
5.10.2.11 The total reserve (10-minute non-synchronized and 30-minute) from
hourly imports cannot exceed its ramp capability over 30 minutes. It
cannot exceed the remaining capacity (maximum import offer minus
scheduled energy import). These conditions can be enforced by the
following two constraints:
 (SI10N
2
k ,h ,d
 SI30Rk2,h,d )  30  ORRHIG d ; and
 (SI10N
2
k ,h ,d
 SI30Rk2,h,d ) 
kKd
kK d
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 (QHIG
kK d
k ,h ,d
 SHIGk2,h,d ).
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5.10.2.12 The amount of 10-minute non-synchronized reserve that hourly import
is scheduled to provide cannot exceed the amount by which it can
increase the output over 10 minutes, as limited by its operating reserve
ramp rate. This condition can be enforced by the following constraint:
 SI10N
kK d
2
k ,h ,d
 10  ORRHIG d .
5.11
Bid/Offer Inter-Hour/Multi-Hour Constraints
5.11.1
Status Variables
5.11.1.1
For the same reasons as discussed for Pass 1, for generation facilities
that are scheduled to start up, and for hour, h > 1:
1, if OPRGh21,b  0 and OPRGh2,b  1
IPRGh2,b  
 0, otherwise.
For h = 1:
1, if InitOperHr sb  0 and OPRGh2,b  1
IPRGh2,b  
 0, otherwise.
5.11.2
Ramping
5.11.2.1
Constraints limiting hour-to-hour changes in energy schedules are
congruous to those used in Pass 1. The left side of the inequality is the
lower limit and the right side of the inequality is the upper limit of the
schedule for the generating facility respectively.
 SPRG
kKb

 SPRG
kKb
5.11.2.2
Page 128 of 164
  600.5(OPRG
2
h ,b

 OPRG h21,b )  1 DRRPRG b
 SPRG 
kKb

2
k ,h1,b
2
k ,h ,b
2
k ,h1,b
  601  0.5(OPRG
2
h ,b

 OPRG h21,b ) URRPRG b .
Similarly, the ramping constraint for the dispatchable load will be as
follows:
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 QPRL
jJ b


 SPRL2j ,h1,b  60 URRPRL b
 QPRL
j ,h ,b
 QPRL
j ,h 1,b
jJ b

j ,h 1,b
jJ b
 SPRL2j ,h ,b


 SPRL2j ,h1,b  60  DRRPRL b .
5.11.2.3
The above two constraints apply for all hours from 1 to 24. In the
above two constraints the variables related to hour zero belong to the
last hour of the previous day and are obtained from the initializing
assumptions.
5.11.2.4
The ramping rates in the ramping constraints must be adjusted to allow
the resource to:
a) Ramp down from its lower limit in hour (h-1) to its upper limit in
hour h.
b) Ramp up from its upper limit in hour (h-1) to its lower limit in
hour h.
5.11.3
5.11.2.5
This will allow a solution to be obtained when changes to the upper
and lower limits between hours are beyond the ramping capability of
the resources.
5.11.2.6
In the above ramping constraints, a single ramp up and a single ramp
down, URRPRGb and DRRPRGb for generation facilities and
URRPRLb and DRRPRLb for dispatchable loads are used. The ramp
rate is assumed constant over the full operating range of the
dispatchable load and generation facility. However, this is not the
case. Dispatchable load bids and generator offers will include multienergy ramp rates. The multiple ramp rates are described in sections
4.10.2.8 and 4.10.2.9.
Minimum Generation Block Run-Time and Minimum Generation Block Down
Time
5.11.3.1
Constraints pertaining to minimum generation block run-times and
minimum generation block down times precisely mirror those used in
Pass 1. Therefore,
if 0 < InitOperHrsb < MRTPRGb, then
2
OPRG12,b , OPRG22,b ,..., OPRGmin(
24,MRTPRGb  InitOperHrsb ),b  1;
if OPRG2h,b = 1, OPRG2h+1,b = 0, and MDTPRGb > 1, then
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2
OPRGh22,b , OPRGh23,b ,..., OPRGmin(
24,h MDTPRGb ),b  0;
and
and if OPRG2h,b = 0, OPRG2h+1,b = 1, and MRTPRGb > 1, then
2
OPRGh22,b , OPRGh23,b ,..., OPRGmin(
24,h MRTPRGb ),b  1
for all hours h and buses b and
0, if InitOperHr sb  0

OPRG 02,b  
1, otherwise.
5.11.4
Energy Limited Resources
5.11.4.1
A constraint must be added in order to ensure that energy-limited units
are not scheduled to provide more energy than they have indicated
they are capable of providing. In addition to limiting energy schedules
over the course of the day to the energy limit specified for a unit, this
constraint must also ensure that units are not scheduled to provide
energy in amounts that would preclude them from providing reserve
when activated. Given those factors:
Therefore:
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1

  OPRG
h 1

2
h ,b
 MinQPRG h ,b 
 (SPRG
kK b
2
k , h ,b

) 



 10ORConv   10SSPRG k2,1,b   10NSPRGk2,1,b 
kK b
 kKb

2
 30ORConv  30RSPRG k ,1,b  ELb ;
kK b
2

  OPRG
h 1

2
h ,b
 MinQPRG h ,b 
 (SPRG
kK b
2
k , h ,b

) 



 10ORConv   10SSPRG k2, 2,b   10NSPRGk2, 2,b 
kK b
 kKb

2
 30ORConv  30RSPRG k , 2,b  ELb ;
kK b

24

  OPRG
h 1

2
h ,b
 MinQPRG h ,b 
 (SPRG
kK b
2
k , h ,b

) 



 10ORConv   10SSPRG k2, 24,b   10NSPRGk2, 24,b 
kK b
 kKb

2
 30ORConv  30RSPRG k , 24,b  ELb
kK b
for all buses b at which energy-limited resources are located. The
factors 10ORConv and 30ORConv are applied to scheduled ten-minute
and thirty-minute operating reserves for energy-limited resources to
convert MW into MWh. This factor is set to unity.
5.11.5
Maximum Number of Starts
5.11.5.1
To ensure that generation facilities are not scheduled to cycle on and
off more than their specified maximum number in a day, the following
constraints are defined:
24
 IPRG
h 1
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h ,b
 MaxStartsPRGb .
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5.12
Constraints to Ensure Schedules Do Not Violate
Reliability Requirements
5.12.1
Load
5.12.1.1
Load constraints are structured in the same manner as described in
section 4.11.1 for Pass 1.
5.12.1.2
The total amount of withdrawals scheduled in Pass 2 at each bus b in
each hour h, With2h,b, is the sum of:

the portion of the load forecast for that hour that has been allocated
to that bus;

all dispatchable load bid, net of the amount of load reduction
scheduled (since the dispatchable load is excluded from the
demand forecast by the DACP calculation engine);

exports from Ontario to each intertie zone sink bus; and

outflows from Ontario associated with loop flows between Ontario
and each intertie zone, allocated among the buses in the intertie
zones using the distribution factors developed for that purpose,
yielding:


Withh2,b  LDFh ,b  PFLh    QPRL j ,h ,b  SPRL2j ,h ,b ; and
 jJ b

2
2
Withh ,d   ( SHXL j ,h ,d )   ProxyUPOWtd ,a  min( 0, PFh ,a ).

jJ d
5.12.1.3
aA
The total amount of injections scheduled in Pass 2 at each bus b in
each hour h, Inj2h,b, is the sum of

generation facilities scheduled at that bus;

imports into Ontario from each intertie zone source bus; and

inflows from Ontario associated with loop flows between Ontario
and each intertie zone, allocated among the buses in the intertie
zones using the distribution factors developed for that purpose:
Inj h2,b  OPRG h2,b  MinQPRG h ,b 
Inj h2,d 
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
 (SHIG
kK d
2
k ,h ,d
 SPRG ; and
kK b
2
k , h ,b
)   ProxyUPIWtd ,a  max( 0, PFh ,a ).
aA
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5.12.1.4
Injections and withdrawals at each bus must be multiplied by one plus
the marginal loss factor to reflect the losses (or reduction in losses)
that result when injections or withdrawals occur at locations other than
the reference bus. These loss-adjusted injections and withdrawals must
then be equal to each other, after taking into account any system loss
adjustment that is required due to the difference between average and
marginal losses. Load reduction associated with the demand constraint
violation will be subtracted from the total load and generation
reduction associated with the demand constraint violation will be
subtracted from total generation to ensure that the calculation engine
will always produce a solution. These violation variables are assigned
a very high cost to limit their use to infeasible cases.
 (1  MglLoss
bB
h ,b
)Withh2,b   (1  MglLoss h ,b )Withh2,d  SLdViol h2
  (1  MglLoss h ,b ) Inj
bB
dD
2
h ,b
  (1  MglLoss h ,d ) Inj h2,d  SGenViolh2  LossAdj h .
dD
5.12.2
Operating Reserve
5.12.2.1
Sufficient operating reserve must be provided on the system to meet
system wide requirements for 10-minute synchronized reserve, tenminute operating reserve and thirty-minute operating reserve, as well
as all applicable regional minimum and maximum requirements for
operating reserve.
5.12.2.2
Therefore, taking into consideration the potential not to meet these
minimum and maximum requirements if the cost of meeting those
requirements becomes too high:

   10SSPRL
bB
 jJ b
 TOT10S h ;

2
j ,h ,b



     10SSPRG k2,h ,b   S10SViol h2
 bB  kK


 b




     10SSPRG k2,h ,b   S10RViol h2



bB  jJ b
 bB  kKb





    10NSPRGk2,h ,b      10NSPRL2j ,h ,b 
bB  kK b
 bB  jJ b





    SI10N k2,h ,d      SX10N 2j ,h ,d   TOT10Rh ; and
dD  kK d
 dD  jJ d

   10SSPRL
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
   10SSPRL
bB
2
j ,h ,b
 jJ b



     10SSPRG k2,h ,b   S30RViol h2
 bB  kK


 b



    (10NSPRGk2,h ,b  30RSPRG k2,h ,b ) 
bB  kK b



    (10NSPRL2j ,h ,b  30RSPRL2j ,h ,b ) 
bB  jJ b



    ( SI10N k2,h ,d  SI30Rk2,h ,d ) 
dD  kK d



    ( SX10N 2j ,h ,d  SX30R 2j ,h ,d )   TOT30Rh
dD  jJ d

for all hours h, and




     10SSPRG k2,h ,b   SREG10RVio lr2,h
 br  kK

br  jJ b

 b





    10NSPRGk2,h,b      10NSPRL2j ,h ,b 
br  kK b
 br  jJ b

 REGMin10R r ,h ;
   10SSPRL
2
j ,h ,b




     10SSPRGk2,h ,b   SXREG10RViolr2,h
 br  kK

br  jJ b

 b





    10NSPRGk2,h ,b      10NSPRL2j ,h ,b 
br  kK b
 br  jJ b

 REGMax10Rr ,h ;
   10SSPRL

2
j ,h ,b



     10SSPRGk2,h,b   SREG30RVio lr2,h



br  jJ b
 br  kKb



    (10NSPRGk2,h,b  30RSPRG k2,h,b ) 
br  kKb

   10SSPRL
2
j ,h ,b


    (10NSPRL2j ,h,b  30RSPRL2j ,h,b ) 
br  jJ b

 REGMin30r ,h ; and
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



     10SSPRGk2,h ,b   SXREG30RViolr2,h
 br  kK

br  jJ b

 b



    (10NSPRGk2,h ,b  30RSPRG k2,h ,b ) 
br  kK b



    (10NSPRL2j ,h ,b  30RSPRL2j ,h ,b ) 
br  jJ b

 REGMax30Rr ,h
   10SSPRL
2
j ,h ,b
for all hours h, and for all regions r in the set ORREG.
5.12.3
Internal Transmission Limits
5.12.3.1
The IESO must ensure that the set of DACP schedules produced by
Pass 2 of the calculation engine would not violate any security limits in
either the pre-contingency state or in any contingency. To develop the
constraints to ensure that this occurs, the total amount of energy
scheduled to be injected at each bus and the total amount of energy
scheduled to be withdrawn at each bus will be used.
5.12.3.2
Then the pre-contingency limits on transmission within Ontario will
not be violated if:
 PreConSF
b , f ,h
bB
( Inj h2,b  Withh2,b )   PreConSFd , f ,h ( Inj h2,d  Withh2,d )
dD
 SPreConITLViol
2
f ,h
 AdjNormMaxFlow f ,h
for all facilities f and hours h.
5.12.3.3
Post-contingency limits on transmission facilities within Ontario will
not be violated if:
 SF
bB
b , f ,c , h
( Injh2,b  Withh2,b )   SFd , f ,c ,h ( Injh2,d  Withh2,d )
 SITLViol
dD
2
f ,c , h
 AdjEmMaxFlow f ,c ,h
for all facilities f, hours h, and monitored contingencies c.
5.12.4
Intertie Limits and Constraints on Net Imports
5.12.4.1
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The calculation engine would not violate any security limits associated
with interties between Ontario and intertie zones. To ensure this, we
must calculate the net amount of energy scheduled to flow over each
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intertie in each hour and the amount of operating reserve scheduled to
be provided by resources in that control area. This will be summed
over all affected interties. The result will be compared to the limit
associated with that constraint. Consequently:


2
2
 EnCoeffa , z   ( SHIG k ,h,d )  PFh,a   SHXL j ,h ,d
dDX a , jJ d

 dDIa ,kK d

  SI10N k2,h,d  SI30Rk2,h,d



aA


dDI a ,kK d
0.5( EnCoeff  1)
a,z



  SX10N 2j ,h,d  SX30R 2j ,h,d 


 dDX a , jJ d


 MaxExtSchz ,h






 
 






for all hours h, for all intertie zones a relevant to the constraint z
( EnCoeffa , z  0 ), and for all constraints z in the set Zsch.
5.12.4.2
In addition, changes in the net energy schedule over all interties cannot
exceed the limits set forth by the IESO for hour-to-hour changes in
those schedules. The net import schedule is summed over all interties
for a given hour. It cannot exceed the sum of net import schedule for
all interties for the previous hour plus the maximum permitted hourly
increase. It cannot be less than the sum of the net import schedule for
all interties for the previous hour minus the maximum permitted
hourly decrease. Violation variables are provided for both the up and
down ramp limits to ensure that the calculation engine will always find
a solution. Therefore:


)   ( SHXL2j ,h1,d )   ExtDSCh  SDRmpXTLViolh2
dD  kK d
jJ d



    ( SHIG k2,h ,d )   ( SHXL2j ,h ,d ) 
dD  kK d
jJ d



    ( SHIG k2,h1,d )   ( SHXL2j ,h1,d )   ExtUSCh  SURmpXTLViolh2
dD  kK d
jJ d

   (SHIG
2
k ,h 1,d
for all hours h (schedules for hour, h=0 are obtained from the
initializing inputs listed in section 3.8).
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5.12.5
Intertie Schedule Limits Based on Pass 1 Output
5.12.5.1
Pass 2 will not reduce the amount of imported energy scheduled from
each intertie zone in any hour. Additional imports of energy may be
scheduled in Pass 2. Therefore, for imports that are not part of a linked
wheeling transaction:
SHIGk2,h,d  SHIGk1,h,d
for all offers k, hours h and intertie zones source bus d.
5.12.5.2
Pass 2 will not increase the amount of exported energy scheduled from
each intertie zone sink bus in any hour over the amount scheduled in
Pass 1.
5.12.5.3
Therefore, for exports that are not part of a linked wheeling
transaction:
SHXL2j ,h,d  SHXL1j ,h,d
for all modified bids j, hours h and intertie zones sink bus d.
5.12.5.4
Finally, the purpose of Pass 2 is to determine whether additional
generation facilities need to be committed to ensure that the IESO can
meet peak forecast load, given the resources committed in Pass 1 (and
if so, which resources are committed). Consequently, it will be
necessary to ensure that resources committed in Pass 1 are not decommitted in this pass. Therefore:
OPRGh2,b  OPRGh1,b
6.
Pass 3: Constrained Scheduling to
Meet Average Demand
6.1
Overview
6.1.1
Pass 3 performs a least cost, security constrained scheduling to meet the forecast
average demand and IESO-specified operating reserve requirements.
6.1.2
The commitment for generation and schedules for imports and exports, resulting
from Pass 2 are used to schedule the least cost set of resources (dispatchable
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loads, generation facilities, imports and exports) to meet average forecast demand
and IESO-specified operating reserve requirements, taking account of all
transmission limitations including intertie transfer limits.
6.1.3
Generation facilities committed in Passes 1 and 2 will be scheduled. There will be
no additional exports scheduled beyond what was scheduled in Pass 2. Imports
will not be scheduled below what was scheduled in Pass 2. The import and export
components of linked wheel transactions are allowed to go higher or lower than
schedules produced in Pass 2.
6.2
Inputs into Pass 3
6.2.1
Inputs for Pass 3 include those described in section 3.
6.2.2
In addition, commitments from Passes 1 and 2 and schedules from Pass 2 are used
as inputs.
6.3
Optimization Objective for Pass 3
6.3.1
As for Passes 1 and 2, the gains from trade shall be maximized for Pass 3. This is
accomplished by maximizing an objective function similar to that described in
4.3. The Pass 3 objective function is different in that it does not include the
variables for commitment. This is so because no more commitment is required for
Pass 3.
6.4
Security Assessment
6.4.1
The same security assessment is performed as described in section 4.4.
6.5
Outputs from Pass 3
6.5.1
The primary outputs of Pass 3 include the following:
4.5.1.1
Constrained schedules for energy for the schedule of record; and
4.5.1.2
Shadow prices.
6.6
Glossary of Sets, Indices, Variables and Parameters for
Pass 3
6.6.1
Fundamental Sets and Indices
6.6.1.1
6.6.2
Variables and Parameters
6.6.2.1
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Same as those described in section 4.6.1.
Bid and Offer Inputs
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Same as those described in 4.6.2.1.
6.6.2.2
Transmission and Security Inputs and Intermediate Variables
Same as those described in 4.6.2.2.
6.6.2.3
Other Inputs
Same as those described in 4.6.2.3.
6.6.2.4
Constraint Violation Price Inputs
Same as those described in 4.6.2.4.
6.6.2.5
Variables determined in Pass 2 and Used in Pass 3
SHXL2j,h,d
The amount of exports scheduled in hour h in Pass
2 from intertie zone, d in association with each bid
j.
SHIG2k,h,d
The amount of imports scheduled in hour h in
Pass 2 from intertie zone d in association with
each offer k.
OPRG2h,b
Indication of whether a generation facility at bus b
was scheduled to operate in hour h in Pass 2.
IPRG2h,b
Indication of whether a generation facility at bus b
was scheduled to start in hour h in Pass 2.
6.6.2.6
Output Schedule and Commitment Variables
SHXL3j,h,d
The amount of exports scheduled in hour h in Pass
3 from intertie zone sink bus d in association with
each bid j.
SX10N3j,h,d
The amount of non-synchronized ten-minute
operating reserve scheduled from the export in
hour h in Pass 3 from intertie zone sink bus d in
association of bid j.
SX30R3j,h,d
The amount of thirty-minute operating reserve
scheduled from the export in hour h in Pass 3
from intertie zone sink bus d in association of bid
j.
SPRL3j,h,b
The amount of dispatchable load reduction
scheduled at bus b in hour h in Pass 3 in
association with each bid j at that bus.
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10SSPRL3j,h,b
The amount of synchronized ten-minute operating
reserve that a qualified dispatchable load is
scheduled to provide at bus b in hour h in Pass 3
in association of bid j for this bus.
10NSPRL3j,h,b
The amount of non-synchronized ten-minute
operating reserve that a qualified dispatchable
load is scheduled to provide at bus b in hour h in
Pass 3 in association of bid j for this bus.
30RSPRL3j,h,b
The amount of thirty-minute operating reserve
that a qualified dispatchable load is scheduled to
provide at bus b in hour h in Pass 3 in association
of bid j for this bus.
SHIG3k,h,d
The amount of hourly imports scheduled in hour h
from intertie zone source bus d in Pass 2 in
association with each offer k.
SI10N3k,h,d
The amount of imported ten-minute operating
reserve scheduled in hour h from intertie zone
source bus d in Pass 3 in association with each
offer k.
SI30R3k,h,d
The amount of imported thirty-minute operating
reserve scheduled in hour h from intertie zone
source bus d in Pass 3 in association with each
offer k.
SPRG3k,h,b
The amount scheduled for the generation facility
at bus b in hour h in Pass 3 in association with
each offer k at that bus. This is in addition to any
MinQPRG h,b, the minimum loading point, which
must also be committed.
OPRG3h,b
Represents whether the generation facility at bus b
has been scheduled in hour h in Pass 3.
IPRG3h,b
Represents whether generation facility at bus b
has been scheduled to start in hour h in Pass 3.
RAMPUP_ENRG
The estimated fraction of a generation facility’s
minimum loading point in the hour prior to the first
hour it is scheduled. This value is used by the DACP
calculation engine to determine constrained schedules
in Pass 3 so that the energy produced by the
generation facility during ramping to their minimum
loading point is accounted for.
10SSPRG3k,h,b
The amount of synchronized ten-minute operating
reserve that a qualified generation facility at bus b
is scheduled to provide in hour h in Pass 3 in
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association of offer k for this bus.
3
10NSPRG
k,h,b
30RSPRG3k,h,b
6.6.2.7
The amount of non-synchronized ten-minute
operating reserve that a qualified generation
facility at bus b is scheduled to provide in hour h
in Pass 3 in association of offer k for this bus.
The amount of thirty-minute operating reserve
that a qualified generation facility at bus b is
scheduled to provide in hour h in Pass 2 in
association of offer k for this bus.
Output Violation Variables
ViolCost3h
The cost incurred in order to avoid having the
Pass 3 schedules for hour h violate specified
constraints.
SLdViol3h
Projected load curtailment, that is, the amount of
load that cannot be met using offers scheduled or
committed in hour h in Pass 3.
SGenViol3h
The amount of additional load that must be
scheduled in hour h in Pass 3 to ensure that there
is enough load on the system to offset the mustrun requirements of generation facilities.
S10SViol3h
The amount by which the overall synchronized
ten-minute operating reserve requirement is not
met in hour h of Pass 3 because the cost of
meeting that portion of the requirement was
greater than or equal to P10SViol.
S10RViol3h
The amount by which the overall ten-minute
operating reserve requirement is not met in hour h
of Pass 3 (above and beyond any failure to meet
the synchronized ten-minute operating reserve
requirement) because the cost of meeting that
portion of the requirement was greater than or
equal to P10RViol.
S30RViol3h
The amount by which the overall thirty-minute
operating reserve requirement is not met in hour h
of Pass 3 (above and beyond any failure to meet
the ten-minute operating reserve requirement)
because the cost of meeting that portion of the
requirement was greater than or equal to
P30RViol.
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SREG10RViol3r,h
The amount by which the minimum ten-minute
operating reserve requirement for region r is not
met in hour h of Pass 3 because the cost of
meeting that portion of the requirement was
greater than or equal to PREG10RViol.
SREG30RViol3r,h
The amount by which the minimum thirty-minute
operating reserve requirement for region r is not
met in hour h of Pass 3 because the cost of
meeting that portion of the requirement was
greater than or equal to PREG30RViol.
SXREG10RViol3r,h
The amount by which the ten-minute operating
reserve scheduled for region r exceeds the
maximum required in hour h of Pass 3 because the
cost of meeting that the maximum requirement
limit was greater than or equal to PXREG10RViol.
SXREG30RViol3r,h
The amount by which the thirty-minute operating
reserve scheduled for region r exceeds the
maximum required in hour h of Pass 3 because the
cost of meeting the maximum requirement limit
was greater than or equal to PXREG30RViol.
SPreConITLViol3f,h
The amount by which pre-contingency flows over
facility f in hour h of Pass 3 exceed the normal
limit for flows over that facility, because the cost
of alternative solutions that would not result in
such an overload was greater than or equal to
PPreConITLViol.
SITLViol3f,c,h
The amount by which flows over facility f that
would follow the occurrence of contingency c in
hour h of Pass 3 exceed the emergency limit for
flows over that facility, because the cost of
alternative solutions that would not result in such
an overload was greater than or equal to PITLViol.
SPreConXTLViol3z,h
The amount by which intertie flows over facility z
in hour h of Pass 3 exceed the normal limit for
flows over that facility, because the cost of
alternative solutions that would not result in such
an overload was greater than or equal to
PPreConXTLViol.
SURmpXTLViol3h
The amount by which the total net scheduled
import increase for hour h in Pass 3 exceeds the
up ramp limits, because the cost of alternative
solutions that would not result in violation was
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greater than or equal to PRmpXTLViol.
SDRmpXTLViol3h
6.6.2.8
The amount by which the total net scheduled
import decrease in hour h of Pass 2 exceed the
down ramp limits, because the cost of alternative
solutions that would not result in violation was
greater than or equal to PRmpXTLViol.
Output Shadow Prices
Shadow Prices of Constraints:
SPL3h
The Pass 3 shadow price measuring the rate of
change of the objective function for a change in
load at the reference bus in hour h.
SPNormT3f,h
The Pass 3 shadow price measuring the rate of
change of the objective function for a change in
the limit, AdjNormMaxFlowf,h, on flows over
transmission facilities in normal conditions for
facility f in hour h.
SPEmT3f,c,h
The Pass 3 shadow price measuring the rate of
change of the objective function for a change in
the limit, AdjEmMaxFlowf,c,h , on flows over
transmission facilities in emergency conditions for
facility f in monitored contingency c in hour h.
SPExtT3z,h
The Pass 3 shadow price measuring the rate of
change of the objective function for a change in
the limit, MaxExtSch z,h, on flows over
transmission facilities on the boundary between
Ontario and other control areas for each
constraint z in hour h.
SPRUExtT3h
The Pass 3 shadow price measuring the rate of
change of the objective function for a change in
the limit, ExtUSCh, on the upward change of the
sum of net imports over all interties from the
previous hour to hour h.
SPRDExtT3h
The Pass 3 shadow price measuring the rate of
change of the objective function for a change in
the limit, ExtDSCh, on the downward change of
the sum of net imports over all interties from the
previous hour to hour h.
SP10S3h
The Pass 3 shadow price measuring the rate of
change of the objective function for a change in
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the total synchronized ten-minute operating
reserve requirement, TOT10Sh, in hour h.
SP10R3h
The Pass 3 shadow price measuring the rate of
change of the objective function for a change in
the total ten-minute operating reserve
requirement, TOT10Rh, in hour h.
SP30R3h
The Pass 3 shadow price measuring the rate of
change of the objective function for a change in
the total thirty-minute operating reserve
requirement, TOT30Rh, in hour h.
SPREGMin10R3r,h
The Pass 3 shadow price measuring the rate of
change of the objective function for a change in
the minimum ten-minute operating reserve
requirement, REGMin10Rr,h, for region r in hour
h.
SPREGMin30R3r,h
The Pass 3 shadow price measuring the rate of
change of the objective function for a change in
the minimum thirty-minute operating reserve
requirement, REGMin30Rr,h, for region r in hour
h.
SPREGMax10R3r,h
The Pass 3 shadow price measuring the rate of
change of the objective function for a change in
the maximum ten-minute operating reserve limit,
REGMax10Rr,h, for region r in hour h.
SPREGMax30R3r,h
The Pass 3 shadow price measuring the rate of
change of the objective function for a change in
the maximum thirty-minute operating reserve
limit, REGMax30Rr,h, for region r in hour h.
Shadow Price for Energy:
LMP3h,b
6.6.2.9
The Pass 3 locational marginal price for energy at
each bus b in each hour h. It measures the offered
price of meeting an infinitesimal change in the
amount of load at that bus in that hour, or
equivalently, measures the value of an incremental
amount of supply at that bus in that hour in Pass 3.
Energy Ramp Rates
Same as those in section 4.6.2.8.
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6.7
Objective Function
6.7.1
The optimization of the objective function in Pass 3 is to maximize the
expression:
  ( SHXL3j ,h ,d  PHXL j ,h ,d  SX10N 3j ,h ,d  PX10N j ,h ,d  SX30R 3j ,h ,d  PX30R j ,h ,d )
dDX , jJ d



3
  SPRL j ,h ,b  PPRL j ,h ,b



 jJ b




3
3
  

10NSPRL j ,h ,b  10NPPRL j ,h ,b 10SSPRL j ,h ,b  10SPPRL j ,h ,b  
 bB  



3


30RSPRL

30RPPRL
j , h ,b
j , h ,b
 jJ b





3
3
3

SHIG

PHIG

SI10N

PI10N

SI30R

PI30R

;


k ,h ,d
k ,h ,d
k ,h ,d
k ,h,d
k ,h ,d
k ,h ,d
h 1,..., 24  d DI , kK d



3
  SPRG k ,h ,b  PPRG k ,h ,b



 kK b





  

10SSPRG k3,h ,b  10SPPRG k ,h ,b 10NSPRG k3,h ,b  10NPPRG k ,h ,b 
 bB  


3

30RSPRG

30RPPRG


k

K
b
k
,
h
,
b
k
,
h
,
b




3
 ViolCost h





where ViolCost3h is calculated as follows:
ViolCost h3  SLdViolh3  PLdViol  SGenViolh3  PGenViol
 S10SViolh3  P10SViol  S10RViol h3  P10RViol
 S30RViol h3  P30RViol
 SREG10RVio lr3,h  PREG10RVio l



  SREG30RVio lr3,h  PREG30RVio l 

  
3
rORREG   SXREG10RVi olr ,h  PXREG10RViol 


  SXREG30RViol 3  PXREG30RViol 
r
,
h


3
  SPreConXTLViol z ,h  PPreConXTLViol


zZ
 SURmpXTLViol 3  PRmpXTLViol  SDRmpXTLViol 3  PRmpXTLViol
  SPreConITLViol 3f ,h  PPreConITLViol
f F

 SITLViol
f F ,cC
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f ,c ,h
 PITLViol.
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6.8
Constraints Overview
6.8.1
Resources not already committed in Pass 2 will not be scheduled and the
constraints that require their inputs will be eliminated.
6.9
Bid/Offer Constraints Applying to Single Hours
6.9.1
Status Variables and Capacity Constraints
6.9.1.1
No schedule can be negative, nor can any schedule exceed the amount
of capacity offered for that service. Therefore:
0  SPRL3j ,h,b  QPRL j ,h,b ;
0  10SSPRL3j ,h,b  10SQPRL j ,h,b ;
0  10NSPRL3j ,h,b  10NQPRL j ,h,b ;
0  30RSPRL3j ,h,b  30RQPRL j ,h,b ;
0  SHXL3j ,h,d  QHXL j ,h,d ;
0  SX10N 3j ,h,d  QX10N j ,h,d ;
0  SX30R 3j ,h,d  QX30R j ,h,d ;
0  SHIG k3,h,d  QHIG k ,h,d ;
0  SI10N k3,h,d  QI10N k ,h,d ;
and
0  SI30Rk3,h,d  QI30Rk ,h,d ;
for all bids j, offers k, hours h, buses b and intertie zones source/sink
buses d.
6.9.1.2
In the case of generation facilities, in addition to restrictions on their
schedules similar to those above, their schedules must be consistent
with their operating status determined at the conclusion of Pass 2. To
simplify the writing of subsequent constraints, we will define the
following variable for buses where generation facilities are located:
OPRGh3,b  OPRGh2,b ; and
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IPRG h3,b  IPRG h2,b
which will indicate whether a resource at bus b may be scheduled to
operate or start in Pass 3 in hour h. Then:
0  SPRGk3,h,b  OPRGh3,b  QPRGk ,h,b ;
0  10SSPRGk3,h,b  OPRGh3,b  10SQPRGk ,h,b ;
0  10NSPRGk3,h,b  OPRGh3,b  10NQPRGk ,h,b ; and
0  30RSPRGk3,h,b  OPRGh3,b  30RQPRG k ,h,b
for all offers k, hours h, and buses b.
6.9.1.3
In the case of linked wheeling transactions (the export bid and the
import offer have the same NERC tag identifier), the amount of
scheduled export energy must be equal to the amount of scheduled
import energy. Therefore:
 SHXL
3
j ,h ,dx
jJ d

 SHIG
kkd
3
k ,h ,di
where dx and di are the respective buses of the export and import
schedules associated with the wheeling transactions.
6.9.1.4
The minimum and/or maximum output of the generation facilities may
be limited because of outages and/or de-ratings or in order for the units
to provide regulation or voltage support. These constraints will take
the form:
MinPRGh,b  MinQPRG h,b (OPRGh3,b )   SPRGk3,h,b  MaxPRGh,b .
kKb
6.9.1.5
Similarly, the maximum level of load reduction is the mechanism by
which a dispatchable load indicates any de-rating to its registered
maximum load reduction level due to mechanical or operational
adjustments to their facility. The constraint will take the form:
 SPRL
jJb
6.9.2
3
j ,h ,b
 MaxPRLh,b .
Operating Reserve Constraints
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6.9.2.1
The total reserve (10-minute synchronized, 10-minute nonsynchronized and 30-minute) from committed dispatchable load
cannot exceed its ramp capability over 30 minutes. It cannot exceed
the total scheduled load (maximum load bid minus the load
reductions). These conditions can be enforced by the following two
constraints:
 (10SSPRL
3
j ,h ,b
jJ b
 10NSPRL3j ,h,b  30RSPRL3j ,h ,b )
 30  ORRPRL b ; and
 (10SSPRL
3
j ,h ,b
jJ b

 (QPRL
jJ b
6.9.2.2
 10NSPRL3j ,h ,b  30RSPRL3j ,h ,b )
j ,h ,b
 SPRL3j ,h ,b ).
In addition, this next constraint ensures that the total(10-minute
synchronized, 10-minute non-synchronized and 30-minute) from
committed dispatchable load cannot exceed the dispatchable load’s
ramp capability to increase load reduction (schedules for hour, h=0 are
obtained from the initializing inputs listed in section 3.8):
 (10SSPRL
3
j ,h ,b
jJ b
 10NSPRL3j ,h,b  30RSPRL3j ,h ,b )

 
   QPRL j ,h1,b  SPRL3j ,h1,b  QPRL j ,h ,b  SPRL3j ,h,b

jJ b
 60  URRPRLb .
Finally, the total (10-minute synchronized, 10-minute non6.9.2.3
synchronized and 30-minute) from committed dispatchable load
cannot exceed the dispatchable load’s Pass 3 scheduled consumption:
 (10SSPRL
jJ b
3
j ,h ,b
 10NSPRL3j ,h ,b  30RSPRL3j ,h ,b )
 MaxPRLh ,b   SPRL3j ,h ,b .
jJ b
6.9.2.4
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The amount of 10-minute synchronized and 10-minute nonsynchronized reserve that a dispatchable load is scheduled to provide
cannot exceed the amount by which it can decrease its load over 10
minutes, as limited by its operating reserve ramp rate. This condition
can be enforced by the following constraint:
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10SSPRL
3
j ,h ,b
jJb
6.9.2.5
 10NSPRL3j ,h,b  10  ORRPRL b .
The total reserve (10-minute synchronized, 10-minute nonsynchronized and 30-minute) from a committed generation facility
cannot exceed its ramp capability over 30 minutes. It cannot exceed
the remaining capacity (maximum offered generation minus the energy
schedule). These conditions can be enforced by the following two
constraints:
 (10SSPRG
kKb
3
k ,h ,b
 10NSPRGk3,h,b  30RSPRG k3,h ,b )
 30  ORRPRG b ; and
 (10SSPRG
kKb

3
k ,h ,b
 (QPRG
kKb
6.9.2.6
 10NSPRGk3,h ,b  30RSPRG k3,h ,b )
k ,h ,b
 SPRGk3,h ,b ).
In addition, this next constraint ensures that the total (10-minute
synchronized, 10-minute non-synchronized and 30-minute) from a
committed generation facility cannot exceed its ramp capability to
increase generation (schedules for hour, h=0 are obtained from the
initializing inputs listed in section 3.8):
 (10SSPRG
kKb

3
k ,h ,b
 SPRG
kKb
 10NSPRGk3,h,b  30RSPRG k3,h,b )
3
j ,h1,b
 SPRG 3j ,h,b 


 60 1  0.5(OPRG h3,b  OPRG h31,b ) URRPRG b .
6.9.2.7
Finally, the total (10-minute synchronized, 10-minute nonsynchronized and 30-minute) from a committed generation facility
cannot exceed the its Pass 3 unscheduled capacity:
 (10SSPRG
kKb
3
k ,h ,b
 10NSPRGk3,h,b  30RSPRG k3,h,b )
 MaxPRGh ,b   SPRGk3,h,b  MinQPRG h,b .
kKb
6.9.2.8
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The amount of ten-minute operating reserve (both synchronized and
non-synchronized) that a generation facility is scheduled to provide
cannot exceed the amount by which it can increase its output over 10
minutes, as limited by its operating reserve ramp rate. This condition
can be enforced by the following constraint:
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 (10SSPRG
3
k ,h ,b
kKb
6.9.2.9
The total reserve (10-minute non-synchronized and 30-minute) from
hourly exports cannot exceed its ramp capability over 30 minutes. It
cannot exceed the total scheduled export. These conditions can be
enforced by the following two constraints:
 (SX10N
jJ d
jJ d
jJ d
3
j ,h ,d
 SX30R3j ,h,d ) 
 SHXL
jJ d
3
j ,h ,d
.
 10  ORRHXL d .
3
j , h ,d
The total reserve (10-minute non-synchronized and 30-minute) from
hourly imports cannot exceed its ramp capability over 30 minutes. It
cannot exceed the remaining capacity (maximum import offer minus
scheduled energy import). These conditions can be enforced by the
following two constraints:
 (SI10N
kKd
kKd
3
k ,h ,d
 SI30Rk3,h,d )  30  ORRHIG d ;
and
 (SI10N
6.9.2.12
 SX30R3j ,h,d )  30  ORRHXL d ;
The amount of 10-minute non-synchronized reserve that hourly export
is scheduled to provide cannot exceed the amount by which it can
decrease its load over 10 minutes, as limited by its operating reserve
ramp rate. This condition can be enforced by the following constraint:
 SX10N
6.9.2.11
3
j ,h , d
and
 (SX10N
6.9.2.10
 10NSPRGk3,h,b )  10  ORRPRG b .
3
k ,h ,d
 SI30Rk3,h,d ) 
 (QHIG
kKd
k , h ,d
 SHIGk3,h,d ).
The amount of 10-minute non-synchronized reserve that hourly import
is scheduled to provide cannot exceed the amount by which it can
increase the output over 10 minutes, as limited by its operating reserve
ramp rate. This condition can be enforced by the following constraint:
 SI10N
kKd
3
k ,h ,d
 10  ORRHIG d .
6.10
Bid/Offer Inter-Hour/Multi-Hour Constraints
6.10.1
Ramping
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6.10.1.1
Energy schedules for each resource cannot vary by more than an
hour’s ramping capacity for that resource. The energy schedule change
in the hour in which the unit is scheduled to start or shut down depends
on the unit ramp rate below its minimum loading point. Almost all
non-quick start generation facilities will need one or more hours to
reach their minimum loading point and to go down from minimum
loading point to zero. Since non-committed generation facilities must
be assigned zero output and committed units must operate at or above
their minimum loading point, it is assumed that these units will be at
their minimum loading point at the beginning of the first commitment
hour and at the end of the hour before shut down.
6.10.1.2
The following constraint uses the fact that the unit commitment status
changes from zero to one when the unit starts and stays at one for all
the hours the unit is committed and changes back to zero when the unit
shuts down. The left side of the inequality is the lower limit and the
right side of the inequality is the upper limit of the schedule for the
generating facility respectively.
 SPRG
kKb

3
k ,h1,b
 SPRG
3
k ,h ,b
 SPRG
3
k ,h1,b
kKb


kKb

 60 0.5(OPRG h3,b  OPRG h31,b )  1 DRRPRG b


 60 1  0.5(OPRG h3,b  OPRG h31,b ) URRPPRG b .
6.10.1.3
It should be noted that these ramp up/down rates apply to the operating
range above the minimum loading point of the generation facility.
6.10.1.4
Similar logic is applied to dispatchable loads to arrive at the following
constraint:
 QPRL
jJ b


 SPRL3j ,h1,b  60  URRPRL h,b
 QPRL
j ,h ,b
 QPRL
j ,h1,b
jJ b

j ,h1,b
jJ b
 SPRL3j ,h,b


 SPRL3j ,h1,b  60  DRRPRL h,b .
6.10.1.5
The above two constraints apply for all hours from 1 to 24. In the
above two constraints the variables related to hour zero belong to the
last hour of the previous day and are obtained from the initializing
assumptions.
6.10.1.6
The ramping rates in the ramping constraints must be adjusted to allow
the resource to:
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a) Ramp down from its lower limit in hour (h-1) to its upper limit in
hour h.
b) Ramp up from its upper limit in hour (h-1) to its lower limit in
hour h.
6.10.2
6.10.1.7
This will allow a solution to be obtained when changes to the upper
and lower limits between hours are beyond the ramping capability of
the resources.
6.10.1.8
In the above ramping constraints, a single ramp up and a single ramp
down, URRPRGb and DRRPRGb for generation facilities and
URRPRLb and DRRPRLb for dispatchable loads are used. The ramp
rate is assumed constant over the full operating range of the
dispatchable load and generation facility. However, this is not the
case. Dispatchable load bids and generator offers will include multienergy ramp rates. The multiple ramp rates are described in sections
4.10.2.8 and 4.10.2.9.
Energy Limited Resources
6.10.2.1
Page 152 of 164
Constraints applying to energy-limited resources are very similar to
the constraints used in Pass 1. Therefore:
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1

  OPRG
h 1

3
h ,b
 MinQPRG h ,b 
 SPRG
kKb
3
k ,h ,b






 10ORConv   10SSPRGk3,1,b   10NSPRGk3,1,b 
kKb
 kKb

3
 30ORConv  30RSPRG k ,1,b  ELb ;
kKb
2

  OPRG
h 1

3
h ,b
 MinQPRG h ,b 
 SPRG
kKb
3
k ,h ,b






 10ORConv   10SSPRGk3, 2,b   10NSPRGk3, 2,b 
kKb
 kKb

3
 30ORConv  30RSPRG k , 2,b  ELb ;
kKb

24

  OPRG
h 1

3
h ,b
 MinQPRG h ,b 
 SPRG
kKb
3
k ,h ,b






 10ORConv   10SSPRGk3, 24,b   10NSPRGk3, 24,b 
kKb
 kKb

3
 30ORConv  30RSPRG k , 24,b  ELb
kKb
for all hours h and for all buses b at which energy-limited resources
are located. The factors 10ORConv and 30ORConv are applied to
scheduled ten-minute operating reserve and thirty-minute operating
reserves for energy-limited resources to convert MW into MWh. This
factor is set to unity.
6.11
Constraints to Ensure Schedules Do Not Violate
Reliability Requirements
6.11.1
Load
6.11.1.1
The total amount of withdrawals scheduled in Pass 3 at each bus b in
each hour h, With3h,b, is the sum of:

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the portion of the load forecast for that hour that has been allocated
to that bus;
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
all dispatchable load bid, net of the amount of load reduction
scheduled (since the dispatchable load is excluded from the
demand forecast by the DACP calculation engine);

exports from Ontario to each intertie zone sink bus; and

outflows from Ontario associated with loop flows between Ontario
and each intertie zone, allocated among the buses in the intertie
zones using the distribution factors developed for that purpose,
yielding:


Withh3,b  LDFh ,b  PFLh    QPRL j ,h ,b  SPRL3j ,h ,b ; and
 jJ b

3
3
Withh ,d   ( SHXL j ,h ,d )   ProxyUPOWtd ,a  min( 0, PFh ,a ).

jJ d
6.11.1.2

aA
The total amount of injections scheduled in Pass 3 at each bus b in
each hour h, Inj3h,b, is the sum of

generation scheduled at that bus;

imports into Ontario from each intertie zone source bus; and

inflows from Ontario associated with loop flows between Ontario
and each intertie zone, allocated among the buses in the intertie
zones using the distribution factors developed for that purpose:
Inj h3,b  (OPRG h3,b  RAMPUP _ ENRG  IPRG h31,b ) MinQPRG h,b

 SPRG ; and
3
k ,h ,b
kK b
Inj
6.11.1.3
Page 154 of 164
3
h ,d

 (SHIG
kK d
3
k ,h ,d
)   ProxyUPIWtd ,a  max( 0, PFh,a ).
aA
Injections and withdrawals at each bus must be multiplied by one plus
the marginal loss factor to reflect the losses (or reduction in losses)
that result when injections or withdrawals occur at locations other than
the reference bus. These loss-adjusted injections and withdrawals must
then be equal to each other, after taking into account any system loss
adjustment that is required due to the difference between average and
marginal losses. Load reduction associated with the demand constraint
violation will be subtracted from the total load and generation
reduction associated with the demand constraint violation will be
subtracted from total generation to ensure that the calculation engine
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will always produce a solution. These violation variables are assigned
a very high cost to limit their use to infeasible cases.
 (1  MglLoss
bB
h ,b
)Withh3,b   (1  MglLoss h ,b )Withh3,d  SLDViol h3
  (1  MglLoss h ,b ) Inj
bB
dD
3
h ,b
  (1  MglLoss h ,d ) Inj h3,d
dD
 SGenViol  LossAdj h .
3
h
6.11.2
Operating Reserve
6.11.2.1
Sufficient operating reserve must be provided on the system to meet
system wide requirements for 10-minute synchronized reserve, tenminute operating reserve and thirty-minute operating reserve, as well
as all applicable regional minimum and maximum requirements for
operating reserve.
6.11.2.2
Therefore, taking into consideration the potential not to meet these
minimum and maximum requirements if the cost of meeting those
requirements becomes too high:

   10SSPRL
bB
 jJb
 TOT10S h ;

3
j ,h ,b
   10SSPRL
bB
 jJ b
3
j ,h ,b



     10SSPRGk3,h ,b   S10SViolh3
 bB  kK


 b




     10SSPRG k3,h ,b   S10RViol h3
 bB  kK


 b





    10NSPRGk3,h ,b      10NSPRL3j ,h ,b 
bB  kK b
 bB  jJ b





    SI10N k3,h ,d      SX10N 3j ,h ,d 
dD  kK d
 dD  jJ d

 TOT10Rh ; and
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



     10SSPRG k3,h ,b   S 30 RViol h3
 bB  kK

bB  jJ b

 b



    (10NSPRGk3,h ,b  30RSPRG k3,h ,b ) 
bB  kK b

   10SSPRL
3
j ,h ,b


    (10NSPRL3j ,h ,b  30RSPRL3j ,h ,b ) 
bB  jJ b



    ( SI10N k3,h ,d  SI30Rk3,h ,d ) 
dD  kK d



    ( SX10N 3j ,h ,d  SX30R 3j ,h ,d ) 
dD  jJ d

 TOT30Rh
for all hours h; and




     10SSPRGk3,h ,b   SREG10RVio lr3,h
 br  kK

br  jJ b

 b





    10NSPRGk3,h ,b      10NSPRL3j ,h ,b 
br  kKb
 br  jJb

 REGMin10 Rr ,h ;
   10SSPRL

3
j ,h ,b



     10SSPRGk3,h ,b   SXREG10RViolr3,h
 br  kK

br  jJ b

 b





    10NSPRGk3,h ,b      10NSPRL3j ,h ,b 
br  kKb
 br  jJb

 REGMax10 Rr ,h ;
   10SSPRL

3
j ,h ,b



     10SSPRGk3,h,b   SREG30RVio lr3,h
 br  kK

br  jJ b

 b



    (10NSPRGk3,h,b  30RSPRG k3,h,b ) 
br  kKb

   10SSPRL
3
j ,h ,b


    (10NSPRL3j ,h,b  30RSPRL3j ,h,b ) 
br  jJ b

 REGMin30Rr ,h ; and
Page 156 of 164
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



     10SSPRGk3,h ,b   SXREG30RViolr3,h
 br  kK

br  jJ b

 b



    (10NSPRGk3,h ,b  30RSPRG k3,h ,b ) 
br  kKb

   10SSPRL
3
j ,h ,b


    (10NSPRL3j ,h ,b  30RSPRL3j ,h ,b ) 
br  jJ b

 REGMax30Rr ,h
for all hours h, and for all regions r in the set ORREG.
6.11.3
Internal Transmission Limits
6.11.3.1
The IESO must ensure that the set of DACP schedules produced by
Pass 3 of the calculation engine would not violate any security limits in
either the pre-contingency state or in any contingency. To develop the
constraints to ensure that this occurs, the total amount of energy
scheduled to be injected at each bus and the total amount of energy
scheduled to be withdrawn at each bus will be used.
6.11.3.2
Then the pre-contingency limits on transmission within Ontario will
not be violated if:
 PreConSF
b , f ,h
bB
( Injh3,b  Withh3,b )   PreConSFd , f ,h ( Injh3,d  Withh3,d )
dD
 SPreConITLViol
3
f ,h
 AdjNormMaxFlow f ,h
for all facilities f and hours h.
6.11.3.3
Post-contingency limits on transmission facilities within Ontario will
not be violated if:
 SF
bB
b , f ,c ,h
( Injh3,b  Withh3,b )   SFd , f ,c ,h ( Injh3,d  Withh3,d )
 SITLViol
dD
3
f ,c ,h
 AdjEmMaxFlow f ,c ,h
for all facilities f, hours h, and monitored contingencies c.
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6.11.4
Intertie Transmission Limits and Constraints on Net Imports
6.11.4.1
The calculation engine would not violate any security limits associated
with interties between Ontario and intertie zones. To ensure this, we
must calculate the net amount of energy scheduled to flow over each
intertie in each hour and the amount of operating reserve scheduled to
be provided by resources in that control area. This will be summed
over all affected interties. The result will be compared to the limit
associated with that constraint. Consequently:


3
3
 EnCoeffa , z   ( SHIG k ,h ,d )  PFh ,a   SHXL j ,h ,d
dDX a , jJ d

 dDIa ,kKd

3
  SI10N k ,h ,d  SI30Rk3,h ,d



aA


dDIa ,kK d
0.5( EnCoeff  1)
a,z



  SX10N 3j ,h ,d  SX30R3j ,h ,d 


 dDX a , jJ d

 MaxExtSchz ,h






 
 





for all hours h, for all intertie zones a relevant to the constraint z
( EnCoeffa , z  0 ), and for all constraints z in the set Zsch.
6.11.4.2
Page 158 of 164
In addition, changes in the net energy schedule over all interties cannot
exceed the limits set forth by the IESO for hour-to-hour changes in
those schedules. The net import schedule is summed over all interties
for a given hour. It cannot exceed the sum of net import schedule for
all interties for the previous hour plus the maximum permitted hourly
increase. It cannot be less than the sum of the net import schedule for
all interties for the previous hour minus the maximum permitted
hourly decrease. Violation variables are provided for both the up and
down ramp limits to ensure that the calculation engine will always find
a solution. Therefore:
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

)   ( SHXL3j ,h 1,d )   ExtDSCh  SDRmpXTLViol h3
d D  kK d
jJ d



    ( SHIG k3,h ,d )   ( SHXL3j ,h ,d ) 
d D  kK d
jJ d



    ( SHIG k3,h 1,d )   ( SHXL3j ,h 1,d )   ExtUSCh  SURmpXTLViol h3
d D  kK d
jJ d

   (SHIG
3
k , h 1, d
for all hours h (schedules for hour, h=0 are obtained from the
initializing inputs listed in section 3.8).
6.11.5
Intertie Schedule Limits Based on Pass 2 Outputs
6.11.5.1
Pass 3 will not reduce the amount of imported energy scheduled from
each intertie zone in any hour. Additional imports of energy may be
scheduled in Pass 3, Therefore, for imports that are not part of a linked
wheeling transaction:
SHIGk3,h,d  SHIGk2,h,d
for all offers k, hours h and intertie zones source bus d, and:
6.11.5.2
Pass 3 will not increase the amount of exported energy scheduled from
each intertie zone in any hour to the amount scheduled in Pass 2.
6.11.5.3
Therefore, for exports that are not part of a linked wheeling
transaction:
SHXL3j ,h,d  SHXL2j ,h,d .
6.12
Shadow Prices
6.12.1
The IESO shall also determine energy and operating reserve prices in Pass 3 that
will be published for informational purposes.
6.12.2
Shadow Energy Prices
6.12.2.1
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The Pass 3 shadow price at each bus b in each hour h shall be
calculated at buses in Ontario as:
Page 159 of 164
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LMPh3,b
6.12.3

 1  MglLoss h , b  SPL3h 


 PreConSFb, f , h  SPNormTf3, h 



   SFb, f , c , h  SPEmTf3, c , h .

f F 
 cC

Shadow Energy Prices at Intertie Zones
6.12.3.1
The Pass 3 shadow price at each intertie zone a in each hour h is
calculated
as:
ExtLMPh3,d
 1  MglLoss h ,d 



3
3
3
SPLh    PreConSFd , f ,h  SPNormTf ,h   ( SFd , f ,c ,h  SPEmTf ,c ,h )  
f F 
cC
 .

  ( EnCoeffa , z  SPExtTz3,h )  SPRUExtTh3  SPRDExtTh3

 zZ sch

6.12.4
6.12.3.2
The first component of this calculation, the cost of meeting load at
each intertie zone reflecting marginal losses incurred in transmitting
energy from the reference bus to that intertie zone, is the same as the
first component of the previous equation. The second component of
this calculation determines the effect of congestion on internal
transmission facilities on the price at each bus.
6.12.3.3
The last three components of this calculation are new. They reflect the
impact of limits on imports or exports, which are not relevant for the
calculation of shadow energy prices, but which are relevant for the
calculation of prices at intertie zones. To illustrate why these
components are as they are, let us first review some preceding
definitions. There are two categories of limits on external transactions:
limits on the net flows of energy scheduled over any given intertie or
set of interties, operating reserve imports scheduled over any given
intertie or set of interties, or combinations of these; and limits on hourto-hour changes in net flows over all interties. The set containing
limits of the first type was previously denoted as Zsch, while the other
two constraints set an upper limit on increases and decrease in net
flows. Finally, recall that the factor EnCoeffa,z describes the impact of
imported energy and operating reserve from intertie zone a on one of
these constraints z.
Shadow 30-Minute Reserve Prices
6.12.4.1
Page 160 of 164
Shadow prices can also be calculated for each bus, reflecting the
marginal contribution that each category of operating reserve would
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have if provided at that bus to increasing the value of the objective
function. For each bus b, define ORREGb as the subset of ORREG
consisting of regions that include bus b. The Pass 3 price of thirtyminute operating reserve at a given bus b, L30RP3h,b, is the shadow
price of the total thirty-minute operating reserve constraint, plus the
shadow prices of all of the constraints requiring a minimum amount of
thirty-minute operating reserve to be provided by resources in regions
that include that bus, minus the shadow prices of all the constraints
limiting the amount of thirty-minute operating reserve that can be
provided by resources in regions that include that bus; given these
definitions:
L30RPh3,b
 SP30Rh3 
6.12.5
 SPREGMin30R
3
r ,h
rORREGb

 SPREGMax30R
3
r ,h
rORREGb
.
Shadow 10-Minute Non-synchronized Reserve Prices
6.12.5.1
The Pass 3 price of 10-minute non-synchronized reserve at a given bus
b, L10NP3h,b, is the shadow price of the total ten- and thirty-minute
operating reserve constraints, plus the shadow prices of all of the
constraints requiring a minimum amount of ten- or thirty-minute
operating reserve to be provided by resources in regions that include
that bus, minus the shadow prices of all the constraints limiting the
amount of ten- or thirty-minute operating reserve that can be provided
by resources in regions that include that bus:
L10NPh3,b
 SP10Rh3  SP30Rh3

 SPREGMin10R
rORREGb

 SPREGMax10R
rORREGb
6.12.6
3
r ,h
3
r ,h
 SPREGMin 30 Rr3,h


 SPREGMax30Rr3,h .
Shadow 10-Minute Synchronized Reserve Prices
6.12.6.1
IMO-FORM-1087 v.11.0
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Finally, the Pass 3 price of 10-minute synchronized reserve at a given
bus b, L10SP3h,b, is the shadow price of the total ten- and thirty-minute
operating reserve constraints and the total 10-minute synchronized
reserve constraint, plus the shadow prices of all of the constraints
requiring a minimum amount of ten- or thirty-minute operating
reserve or 10-minute synchronized reserve to be provided by resources
in regions that include that bus, minus the shadow prices of all the
constraints limiting the amount of ten- or thirty-minute operating
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reserve or 10-minute synchronized reserve that can be provided by
resources in regions that include that bus:
L10SPh3,b
 SP10S h3  SP10Rh3  SP30Rh3

 SPREGMin10R
3
r ,h
rORREGb

 SPREGMax10R
3
r ,h
rORREGb
6.12.7


 SPREGMax30Rr3,h .
Shadow Operating Reserve Prices at Intertie Zones
6.12.7.1
Shadow operating reserve prices can also be calculated for intertie
zones. These prices need to take into account the shadow prices of
constraints in the set Zsch, as some of these constraints will limit the
amount of operating reserve that can be imported into Ontario. They
do not need to take into account the shadow prices of constraints
associated with lower limits on the amount of operating reserve that
must be supplied within regions of Ontario or upper limits on the
amount of operating reserve that may be supplied within regions of
Ontario, since imported operating reserve will not affect either of
these types of constraints. Nor do they need to take into account the
shadow price for the hour-to-hour change in net energy flow over all
interties, as these constraints will only affect the amount of energy that
can be scheduled to flow into or out of Ontario.
6.12.7.2
The Pass 3 price of thirty-minute operating reserve at a given intertie
zone a, Ext30RP3h,a, is the shadow price of the total thirty-minute
operating reserve constraint, minus the product of:

the impact that imports of operating reserve from that intertie zone
have on each constraint limiting the import of operating reserve
from that intertie zone, and

the shadow price of that constraint, summed over all constraints:
Ext30RPh3,a  SP30Rh3 
6.12.7.3
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 SPREGMin30 Rr3,h
0.5( ENCoeff
zZ sch
a, z
 1) SPExtTz3,h .
The Pass 3 price of ten-minute operating reserve at a given intertie
zone a, Ext10RP3h,a, is the shadow price of the total ten- and thirtyminute operating reserve constraints, minus the product of:
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
the impact that imports of operating reserve from that intertie zone
have on each constraint limiting the import of operating reserve
from that intertie zone, and

the shadow price of that constraint, summed over all constraints:
Ext10RPh3,a  SP10Rh3  SP30Rh3 
6.12.7.4
0.5( ENCoeff
zZ sch
a, z
 1) SPExtTz3,h .
There is no need to calculate a price for 10-minute synchronized
reserve at intertie zones, since 10-minute synchronized reserve cannot
be imported.
7.
Combined-Cycle Modeling
7.1
Overview
7.1.1
Registered market participants with combined-cycle plants of one or more
combustion turbines and one steam turbine may choose to have the associated
generation facilities modeled as one or more pseudo-units. Each pseudo-unit
comprises of a single combustion turbine and a share of the steam turbine
capacity. Inputs for pseudo-units used by the DACP calculation engine are
described in Chapter 7, section 2.2.6G.
7.2
Modeling by DACP Calculation Engine
7.2.1
The pseudo-units are independently scheduled in each pass subject to the
optimization objective function described in sections 4.3, 5.3 and 6.3 respectively.
However, the security assessment described in section 4.4 is performed for each
generation facility of the combined-cycle plant.
7.2.2
As the security assessment function iterates with the scheduling function of the
DACP calculation engine, the output relationship of each combustion turbine and
its share of output from the steam turbine is respected. This output relationship is
described as follows:
7.2.2.1
For a combined-cycle plant with i combustion turbines and one steam
turbine, it is represented by i pseudo-units.
7.2.2.2
For each pseudo-unit i, let psti,k represent the percentage of the pseudounit’s schedule that relates to the steam turbine in association with
offer k.
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7.2.2.3
Then for each pseudo-unit i, the percentage of the pseudo-unit’s
schedule that relates to the combustion turbine i is (100% - psti,k).
7.2.2.4
For a given pseudo-unit schedule SPSUk,h for hour h and k offers its
associated combustion turbine schedule is:
 SPSU k ,h  (100%  psti,k ).
k
7.2.2.5
And the steam turbine schedule of the pseudo-unit plant for hour h is:
 SPSU k ,h  (100%  psti,k ).
i
k
PART 5 – IESO BOARD DECISION RATIONALE
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