10 Krey Boulevard Rensselaer, NY 12144
September 28, 2010
By Electronic Filing
Honorable Kimberly D. Bose, Secretary Federal Energy Regulatory Commission 888 First Street, NE
Washington, DC 20426
Re: New York Independent System Operator, Inc., Docket No. ER10-1866-000
Errata to Filing to Revise Provisions concerning Guarantee and Margin
Assurance Payments and Rules for Implementation of Improved Reference
Levels for Generators that Are Not Able to Complete their Minimum Run
Time Within the Dispatch Day and Request for Expedited Treatment
Dear Secretary Bose:
On July 21, 2010 the New York Independent System Operator, Inc. (“NYISO”)
submitted proposed tariff revisions to its Market Administration and Control Area Services
Tariff (“Services Tariff”) and Open Access Transmission Tariff (OATT) to revise provisions
concerning guarantee and margin assurance payments and rules for implementation of improved reference levels for generators that are not able to complete their minimum run time within the Dispatch Day (“July 23 Filing”). On August 10, 2010, the NYISO submitted an errata filing to correct minor typographical and administrative errors.
By this errata filing, the NYISO is revising two additional, minor typographical errors
and providing additional information to: i) assist in understanding exactly how Resources will be
compensated under the tariff provisions for Bid Production Cost Guarantee (“BPCG”) payments
and Day-Ahead Margin Assurance Payments (“DAMAP”) that are being proposed for revision in
this docket; and ii) to compare how such payments are calculated for the different Resources
eligible for them. Both clean and redlined versions of the proposed revised Sheets are attached
to this transmittal letter.
I.Errata Corrections
In Section 15.3.5.5, the calculation formula for the Performance-Based Adjustment to payments for Regulation Service providers, the NYISO inadvertently failed to correct the
reference to “Kpi” in the second to the last sentence of the section. The correct reference is “Ki.” Thus the second to last sentence in this paragraph should read:
The factor Ki shall initially be set at 1.0 for Limited Energy
Honorable Kimberly D. Bose September 28, 2010
Page 2
Storage Resources.
In Section 25.2.2.1, the section describing the exceptions to Generator eligibility for
DAMAP, the NYISO inadvertently inserted a new subsection identifier - 25.2.2.2 - rather than the correct identifier “(iii)” between the words “or” and the last clause of the paragraph, “an
Intermittent Power Resource that depends on wind as its fuel.” This filing corrects that minor typographical error.
II.Services Tariff Revision Detail
The detail provided below does not include the detailed explanation of the Day-Ahead
BPCG paid to Generators that was originally included in the July 21, 2010 filing letter. It also
discusses all Day-Ahead BPCG calculations before discussing the real-time BPCG calculations.
A. Day-Ahead BPCG
1. Imports (Section 18.3.)
As a general matter, Transmission Customers bidding to import Energy to the Day-Ahead
LBMP Market are entitled to a Day-Ahead BPCG if their LBMP revenue over the day does not
completely compensate them for the bid-cost of the Energy they are selling to the NYISO LBMP
Market. A new formula in Section 18.3.3 is proposed to describe this calculation. The BPCG
calculation for Imports has been calculated based on the formula previously found in Section
18.1.2 of Attachment C which was written with Generators rather than Transmission Customers
in mind.
An Importer’s BPCG is calculated as the sum over the day of differences every hour
between the Transmission Customer’s Decremental Bid in $/MWh (DecBidthDA) and the LBMP
received for the hour. DecBidthDA is the Decremental Bid provided by the Transmission
Customer (t) for every hour (h) of the proposed Day-Ahead Transaction schedule and LBMPthDA
is the hourly Day-Ahead LBMP at the appropriate Proxy Generator Bus for the Import
Transaction. If the importer’s daily revenues exceed its daily bid-costs the BPCG for the day is
set to zero.1
1 In the Section 18.3.3 calculation, this result appears when the sum of the hourly
differences between the Decremental Bids and the LBMPs over the day produces a negative
number.
Honorable Kimberly D. Bose September 28, 2010
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2. Demand Reduction Providers (Section 18.8)
Customers providing Demand Reduction as Energy in the Day-Ahead Market (Day-
Ahead Demand Reduction Providers or “DADRPs”) are eligible for a Day-Ahead BPCG if their
Day-Ahead LBMP revenue over the course of the day does not completely compensate them for
the bid-costs they experience to provide the Demand Reduction in real-time. These payments
are currently made pursuant to the formula contained in Section 18.2. A new formula in Section
18.8.2 and set of defined terms are included in proposed Section 18.8.1 as described in the July 21, 2010 filing to clarify this calculation.
DADRPs provide a three-part Bid that is analogous to a Generator’s three-part Bid. What a Generator submits as a Start-up Bid, a DADRP submits as a Curtailment Initiation Cost
(“CurInitCost”); a Generator’s Minimum Generation Bid is a DADRP’s Minimum Curtailment Cost (“MinCurCost”); and a Generator’s Incremental Energy Bid is a DADRP’s Incremental
Curtailment Cost (“IncrCurCost”). The NYISO will prorate the DADRP’s Curtailment Initiation Cost when the DADRP’s actual curtailment (“ActCur”) is less than its total Scheduled
Curtailment (“SchedCur”) over the day.
Thus, if the sum of the DADRP’s Curtailment Initiation Cost (prorated as necessary),
Minimum Curtailment Cost and its Incremental Curtailment Costs, for the actual curtailment
provided over the day, is less than the LBMP revenue received over the day, a BPCG is payable for the difference. Should the DADRP have multiple starts in a single day, the NYISO would add the Curtailment Initiation Cost (prorated as necessary), Minimum Curtailment Cost and
Incremental Curtailment Costs, as well as the LBMP revenue received, for the subsequent
period(s) of scheduled Demand Reduction to the daily BPCG calculation. This mirrors the
BPCG calculation used for Generators.
3. Demand-Side Resources (Section 18.10)
Demand Side Resources providing their Demand Reduction as Operating Reserves or
Regulation Service in the Day-Ahead Market are eligible for a BPCG if the revenue they receive for providing Operating Reserves or Regulation Service does not completely compensate them for their costs of providing Operating Reserves. These payments are currently made pursuant to Section 18.4.1 of Attachment C. A new formula and set of defined terms are included in the July 21, 2010 filing as new Section 18.10.2 to clarify this calculation.
Demand Side Resources, scheduled Day-Ahead to provide Demand Reduction as
Operating Reserves or Regulation Service, are eligible only for the hourly clearing price of the
product being providing - Operating Reserves and/or Regulation Service. Such Resources are
not paid for the Demand Reduction provided as a function of being called to convert Operating
Reserves to Demand Reduction (i.e. Energy). A Demand Side Resource’s Day-Ahead BPCG is
calculated as the higher of zero or the negative of the Net Ancillary Services Revenue payable
Honorable Kimberly D. Bose September 28, 2010
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over the day. Net Ancillary Service Revenue (“NASR”) will appear in the calculation described
below as a negative number if a BPCG for the day is payable. The hourly NASR for a Demand
Side Resource (“NASRthDA”) is the sum of the Regulation Service payments it received for
Regulation Service provided for the hour, less its Day-Ahead bid to provide that Regulation
Service plus the synchronized ten- and 30-minute Operating Reserves payments it received for
Operating Reserves provided for the hour, less its Day-Ahead bid to provide Operating Reserves
for the hour. In calculating the contribution of Regulation Service to the hourly NASR, the
NYISO will set to zero, any negative contribution -- in which the cost to provide Regulation
Service exceeds any Regulation Service payment received for Regulation Service provided for
the hour.
The NYISO does not protect a Regulation Service Bid for Generators providing only
Regulation Service.2 Setting to zero the Regulation Service contribution to the Demand Side
Resources’ hourly NASR when its Regulation Service revenue for the hour exceeds its bid-costs
for the hour provides comparable BPCG calculations for Demand Side Resources providing only
Regulation Service.
B. Real-Time BPCGs
1. Generators in Intervals other than Supplemental Event Intervals
(Section 18.4)
As a general matter, Generators are eligible for a BPCG for Energy and Ancillary
Services offered in the Real-Time Market when their real-time LBMP (and certain Ancillary
Service revenue described in the definition of the term NASRthDA in Section 18.2.2.1) does not
compensate them completely for the bid-costs of providing those services. The calculation
formula included in Section 18.4.2 makes use of existing terminology, revised where needed for
clarity.
The formula for non-Supplemental Event intervals reflects changes to the calculation of Start-up Cost (SUCgiRT) to clarify in Section 18.4.2 that a Generator that fails to operate to satisfy the longer of (a) its Day-Ahead or SRE schedule, or (b) the minimum run time specified in its accepted real-time Start-Up Bid, may have the real-time start-up component of its BPCG
payment prorated pursuant to rules found in the new Section 18.12 and described on page 19 of the July 21, 2010 filing letter. The other provisions in the definitions of SUCgiRT (ii and iii) have been relocated from paragraphs that originally followed the list of terms. These revisions are fully described on pages 14 through 16 of the July 21, 2010 filing letter.
2 See the definition of NASRthDA in Section 18.2.2.1, the calculation of a Generator’s
BPCG.
Honorable Kimberly D. Bose September 28, 2010
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2. Generators in Supplemental Event Intervals (Section 18.5)
As a general matter, Generators are eligible for the same interval-by-interval Energy and
Ancillary Services BPCG in real-time Supplemental Event intervals as they are in non-
Supplemental Event intervals other than start-up bid. The BPCG for Supplemental Event
intervals is not netted over the day, however. The BPCG payable for Supplemental Event
intervals is simply the sum of the BPCG payable in each Supplemental Event interval over the
day. Negative BPCG intervals (where the revenues exceed the costs) are zeroed out in the
Supplemental Event BPCG calculation. This calculation is currently being made pursuant to a
formula in Section 18.1.3. The new formula, in Section 18.5.2, provides additional detail on this
calculation.
This formula uses the terms used in the BPCG calculation for Generators in intervals
other than Supplemental Event intervals but for an amended term CgiRT. The amendment does
not exclude the Bid cost of Energy for intervals in which the Generator is ramp constrained down in the term CgiRT, as is more fully explained in the July 21, 2010 filing letter (page 16). A new
description of the existing term EIgiRT is provided for clarity and describes in detail the intervals included in this Section 18.5.2 calculation. Revisions to the term MGCgiRT are also described on page 16 of the July 21, 2010 filing letter.
3. Imports (Section 18.6)
As a general matter, Transmission Customers bidding to import Energy to the real-time LBMP Market are entitled to a real-time BPCG if their LBMP revenue over the day does not completely compensate them for the bid-cost of the Energy they are selling to the NYISO LBMP Market. The NYISO developed a new formula, in proposed Section 18.6.3, for the July 21, 2010 filing to describe this calculation. The real-time BPCG calculation for Imports has been
calculated based on the formula previously found in Section 18.1.2 of Attachment C and written with Generators rather than Transmission Customers in mind.
The real-time BPCG for a Transmission Customer bidding to import Energy to the realtime LBMP Market is calculated as the sum over the day of differences every hour between the Transmission Customer’s Decremental Bid in $/MWh (DecBidthRT), times the higher of zero and the excess of the real-time schedule over the Day-Ahead schedule for the Transaction
(SchImporttiRT - SchImporttiDA)). That is, if the Day-Ahead schedule exceeded the real-time
Energy import schedule, there would be no real-time BPCG payable. The DecBidthRT is the
Decremental Bid provided by the Transmission Customer (t) for every hour (h) of the real-time Transaction schedule and LBMPthRT is the hourly LBMP at the appropriate Proxy Generator Bus for the Import Transaction. If the difference between the Decremental Bids and the LBMPs over the day produces a negative number, the BPCG is set to zero.
Honorable Kimberly D. Bose September 28, 2010
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4. Long Start-up Time Generators with Aborted Start-ups (Section
18.7)
The NYISO has described the methodology it uses, in Section 18.7.2, to calculate the
BPCG payable to Long Start-Up Time Generators whose start-up sequence has been aborted by
the NYISO prior to completion of the start-up sequence and an actual start. The current Tariff
provisions for this payment are found in the last paragraph of Section 18 of the Services Tariff.
Since there are no revenues with which to offset the start-up costs of a Long Start-Up
Time Generators whose start-up sequence has been aborted by the NYISO, its BPCG is simply
its Start-Up Bid times the ratio of i) the portion of its start-up sequence that has been completed
to ii) the length of its entire start-up sequence. A Long Start-Up Time Generator whose start-up
sequence was aborted by the NYISO half way through its start-up time, will receive one half of
its Start-Up Bid as a BPCG. Generators file their start-up time with the NYISO as a static
parameter related to their activity in the Energy market.
5. Special Case Resources (Section 18.9)
The NYISO clarified existing language describing the BPCG payable to Special Case
Resources committed by the NYISO for a real-time event when the Minimum payment
Nomination over the period of requested performance or four hours, whichever is greater,
exceeds the LBMP revenue received. The revision to the existing language found in Section
18.3 does not add new substantive material. Rather it locates all BPCG rules for Special Case resources found in 5.12.11.1 into the new Section 18.9.
6. Demand-Side Resources (Section 18.11)
Demand Side Resources providing their Demand Reduction as Operating Reserves or
Regulation Service (“DSASPs”) in the Real-Time Market are eligible for a BPCG if the real-time
revenue they receive for providing Operating Reserves or Regulation Service does not
completely compensate them for their costs of providing Operating Reserves. These payments
are currently made pursuant to Section 18.4.2 of Attachment C. A new formula and set of
defined terms are included in the July 21, 2010 filing as new Section 18.11 to clarify this
calculation.
A Demand Side Resource’s BPCG for the day is calculated as the higher of zero or the
negative of the sum over the day of the differences in each interval between the total Net
Ancillary Services Revenue (“NASRdiTOT”) paid for that interval and that portion of the hourly
Net Ancillary Services Revenue paid Day-Ahead (“NASRdiDA”) applicable to the interval. The
NASRdiTOT is the sum of payments received as a result of being scheduled either Day-Ahead or
in real-time for the interval. It consists specifically of: i) the Regulation Service payments it
Honorable Kimberly D. Bose September 28, 2010
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received for Regulation Service provided for the hour based on a Performance Index of 1, less its Bid to provide that Regulation Service; plus the ii) synchronized ten- and 30-minute Operating Reserves payments it received for Operating Reserves provided for the hour, less its bid to
provide Operating Reserves for the hour. As in the Day-Ahead BPCG calculation for DSASPs, the NYISO calculates the contribution of Regulation Service to the hourly NASR as zero,
whenever the cost to provide Regulation Service exceeds any Regulation Service payment
received for Regulation Service provided for the hour thus treating Demand Side Resources and Generators scheduled only for Regulation Service comparably.
C. Day-Ahead Margin Assurance Payments
The NYISO proposed a new formula in Section 25.6.2 describing the calculation of the
Import Curtailment Guarantee payment. These payments are currently authorized by Section
4.5.3.2 of the Services Tariff. Pursuant to the new formula, a Transmission Customer with a
scheduled Import that has been curtailed by the ISO may be entitled to an Import Supplier
Guarantee. Such a payment is calculated interval by interval as the higher of zero or the product of i) the real-time LBMP less the higher of the importer’s Decremental Bid for the interval or zero and ii) the difference between the Energy injections scheduled by RTC15 and the Energy injections scheduled by RTD, converted to dollars/MW for the interval.
The real-time commitment software (RTC) commits external transactions hourly in the pass that it initializes at 15 minutes after the hour (RTC15). Import curtailments are reflected in reduced real-time dispatch (RTD) schedules. Thus, the importer’s Curtailment Guarantee is the interval by interval product of the megawatt reduction experienced as a result of the ISO
curtailment and the excess of the real-time LBMP over its bid, provided however, the Import Curtailment Guarantee will never be negative and will be the product of the real-time LBMP times the curtailed megawatts if the importer’s bid is negative.
Effective Date
The NYISO respectfully requests that the Commission review this errata filing to the
NYISO July 21, 2010 filing on an expedited basis, accept it as containing ministerial corrections and accept the attached sheets for filing with the same effective date as the Commission assigns to the tariff revisions that the NYISO submitted on July 21, 2010. Although the requested
effective date of September 30, 2010 is short of the sixty-day-prior notice period, the NYISO
submits that a September 30, 2010 effective date remains appropriate because of the minor
nature of these proposed changes.
The Commission has discretion to waive the sixty-day prior notice period and make tariff
Honorable Kimberly D. Bose September 28, 2010
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revisions effective before it closes when “good cause” is shown.3 Good cause for such a waiver exists for the changes to the tariff proposed herein because the software implementing these tariff revisions is interrelated and tied together in one deployment. The ministerial changes proposed
herein are consistent with the changes previously approved by NYISO stakeholders. The
NYISO has also noticed its Market Participants to this filing in the same manner it provided
notice of the original filing.
The NYISO will be filing a Motion to delay implementation for the proposed Late Day Start provisions of these Tariff revisions within the next day or two.
Service
The NYISO will send an electronic link to this filing to the official representative of each
of its customers, to each participant on its stakeholder committees, to the New York Public
Service Commission, and to the electric utility regulatory agency of New Jersey. In addition, the
complete filing will be posted on the NYISO’s website at www.nyiso.com. This is in accordance
with 18 C.F.R. 35.2(e).
3 See e.g., California Independent System Operator Corp., 113 FERC ¶61, 287 at PP 48-
50 (2005).
Honorable Kimberly D. Bose September 28, 2010
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Communications and Correspondence
All Communications and service in this proceeding should be directed to:
Robert E. Fernandez, General Counsel
Elaine D. Robinson, Director of Regulatory Affairs * Mollie Lampi, Assistant General Counsel
10 Krey Boulevard
Rensselaer, NY 12144
Tel: (518) 356-7530
Fax: (518) 356-7678
* Persons designated for receipt of service.
Respectfully submitted,
___________________ Mollie Lampi
Assistant General Counsel
New York Independent System Operator, Inc.
10 Krey Blvd.
Rensselaer, New York 12144 (518) 356 7530
mlampi@nyiso.com
