April 21, 2017

By Electronic Delivery

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. ER17-____-
000; Proposed Tariff Revisions to Clarify and Enhance Transmission
Constraint Pricing

Dear Secretary Bose:

In accordance with Section 205 of the Federal Power Act1 and Part 35 of the regulations
of the Federal Energy Regulatory Commission (“Commission”), the New York Independent
System Operator, Inc. (“NYISO”) submits proposed revisions to its Market Administration and
Control Area Services Tariff (“Services Tariff”) and Open Access Transmission Tariff
(“OATT”) to clarify and enhance the operation of its transmission constraint pricing logic.2

The NYISO Management Committee approved the proposed revisions, without

opposition, on March 29, 2017.  The NYISO respectfully requests an effective date for the
proposed revisions of June 20, 2017 (i.e., sixty days from the date of this filing letter).

I.Documents Submitted

The NYISO respectfully submits the following documents with this filing letter:

1.A clean version of the proposed revisions to the Services Tariff (“Attachment I”);

2.A blacklined version of the proposed revisions to the Services Tariff

(“Attachment II”);

3.A clean version of the proposed revisions to the OATT (“Attachment III”); and

4.A blacklined version of the proposed revisions to the OATT (“Attachment IV”).

1 16 U.S.C. § 824d.

2 Capitalized terms not otherwise defined herein shall have the meaning specified in Section 2 of the Services Tariff and Section 1 of the OATT.

Honorable Kimberly D. Bose April 21, 2017

Page 2

II.Background

The NYISO’s Security Constrained Unit Commitment (“SCUC”) and Real-Time Market software dispatch and pricing algorithms utilize Transmission Shortage Cost values to establish an upper bound on the Shadow Price used to calculate Locational Based Marginal Prices.
Having an upper bound allows the software to produce efficient and timely dispatch results by concluding its search for solutions to a given transmission constraint and establishing a price in the face of a transmission constraint that either cannot be solved or can only be solved at a
Shadow Price higher than the established upper bound.

The NYISO first implemented a Transmission Shortage Cost in June 2007.3  Initially, the Transmission Shortage Cost consisted of a single upper bound of $4,000 per MWh.  With
additional experience and analysis, the NYISO determined that using graduated price values could improve market efficiency.  Unlike a single price, a graduated pricing mechanism
establishes a series of upper bounds based on the severity of a transmission constraint
“shortage.”4  On February 11, 2016, the NYISO modified its transmission constraint pricing logic with the implementation of a graduated Transmission Shortage Cost.5

On August 29, 2016, the NYISO’s Market Monitoring Unit (“MMU”) presented a market report for the second quarter of 2016 at the Market Issues Working Group (“MIWG”) meeting. The presentation raised several questions concerning transmission constraint Shadow Price levels following the implementation of the graduated Transmission Shortage Cost.  This led
stakeholders to request additional information and prompted the NYISO to commence an
internal analysis of its transmission constraint pricing software.

As a result of its preliminary internal assessment, the NYISO issued a “Notice of

Potential Market Problem” regarding the graduated Transmission Shortage Cost on October 6,

3 See Docket No. ER07-720-000, New York Independent System Operator, Inc., Revisions to its Market Administration and Control Area Services Tariff and its Open Access Transmission Tariff to Apply an Upper Limit on Transmission Shortage Costs Reflected in Locational Based Marginal Prices (April 5, 2007); New York Independent System Operator, Inc., 119 FERC ¶ 61,237 (2007); and Docket No. ER07-720-001, supra, Letter Order (January 11, 2008).

4 In the context of a transmission constraint, a “shortage” represents the absence of available

resource capacity to relieve a transmission constraint for less than the prescribed Transmission Shortage Cost value.

5 See Docket No. ER15-485-000, New York Independent System Operator, Inc., Proposed Tariff Amendments to Revise Transmission Shortage Costs (November 25, 2014); and Docket No. ER15-485-
000, supra, Letter Order (January 15, 2015).  The Services Tariff currently defines the “Transmission Shortage Cost” as “a series of quantity/price points that define the maximum Shadow Price of a particular Constraint that will be used in calculating LBMP.  The Transmission Shortage Costs are set at $350/MWh for shortages above zero and less than or equal to 5MW, $2350/MWh for shortages above 5MW and less than or equal to 20MW, and $4000/MWh for shortages above 20MW.”

Honorable Kimberly D. Bose April 21, 2017

Page 3

2016.6  The notice indicated the existence of an inconsistency between the Services Tariff and
the transmission constraint pricing software.  Namely, the software does not apply the graduated
Transmission Shortage Cost in certain circumstances that are not described in the Services
Tariff.7

The graduated Transmission Shortage Cost is applied to constraints associated with

transmission facilities and Interfaces that have a non-zero constraint reliability margin (“CRM”)8
value and where sufficient resource capacity is available to fully resolve the transmission
constraint prior to the execution of the economic dispatch processes that determine prices and
schedules.9  For transmission constraints related to transmission facilities and Interfaces that fail
the preliminary screening mechanism, as well constraints related to transmission facilities and
Interfaces with a zero value CRM, the current software applies only a single $4,000 per MWh
value.  In these cases, the current software establishes the Shadow Price for such transmission
constraints consistent with the Bids of resources available to provide relief toward resolving the
transmission constraint, subject to a maximum allowable Shadow Price of $4,000 per MWh.

The Services Tariff also does not describe the logic used by the NYISO’s software to

resolve infeasible transmission constraints in the economic dispatch.10  This logic resolves such
infeasibilities by adjusting the otherwise applicable limit for an infeasible transmission constraint
commensurate with the amount of resource capacity that is available to provide relief.  This logic

6 Section 3.5.1 of the Services Tariff establishes various notification and procedural requirements for potential Market Problems.  The notice complied with these requirements.

7 Further details regarding the current transmission constrain pricing software logic is provided in a presentation by the NYISO at the October 19, 2016 MIWG meeting, available at:

http://www.nyiso.com/public/webdocs/markets_operations/committees/bic_miwg/meeting_materials/201
6-10-19/Transmission%20Constraint%20Pricing%2010192016%20MIWG%20FINAL%20vUpdate.pdf.

8 The CRM defines a value below the maximum physical limit on a transmission facility or

Interface that is used by the NYISO’s market software as the effective limit when making economic

commitment and dispatch determinations.  CRM values are normally 20 MW or larger, but are zero for a limited number of internal transmission facilities and effectively zero for all external interfaces.

9 Prior to executing the economic dispatch, the current software conducts a preliminary screen to
determine whether sufficient resource capacity is available to resolve each transmission constraint.  This
preliminary screen is conducted without regard to the value of Bids submitted by resources and without
consideration of other constraints that must simultaneously be resolved (e.g., other transmission
constraints and Operating Reserve and Regulation Service requirements).  If this preliminary screen
indicates that there is insufficient resource capacity available to resolve a particular transmission
constraint, the constraint is guaranteed to be infeasible in the economic dispatch.  In these cases, the
current software does not apply the graduated Transmission Shortage Cost to such a transmission
constraint.  Instead, the current software applies a single $4,000 per MWh Shadow Price cap.

10 The logic for resolving infeasible transmission constraints, which is sometimes referred to as “constraint relaxation,” has been in place since the NYISO’s inception.  It has been utilized in SCUC
since 1999 and in the real-time scheduling system (i.e., Real-Time Commitment and Real-Time Dispatch) since it was implemented in 2005.  Although not currently described in the NYISO’s tariffs, this logic is briefly described in Section 4.3.2 of the NYISO Day-Ahead Scheduling Manual.

Honorable Kimberly D. Bose April 21, 2017

Page 4

applies to all infeasible transmission constraints regardless of whether they are subject to the
graduated Transmission Shortage Cost or the single $4,000 per MWh Shadow Price cap.11

On November 3, 2016, the NYISO concluded that the inconsistency between its

transmission constraint pricing software and the Services Tariff constituted a Market Problem because it had a material impact on the NYISO-administered markets.  On January 6, 2017, the NYISO filed a waiver request with the Commission due to this inconsistency.12  In its waiver request, the NYISO committed to working with its stakeholders to expeditiously consider tariff revisions and software enhancements to resolve the inconsistency.13

This filing represents the culmination of those efforts.  The proposed revisions include

both enhancements to the current transmission constraint pricing logic, as well as tariff revisions to ensure that this enhanced logic is fully described in the Services Tariff.  Commission
acceptance of the proposed revisions and implementation thereof by the NYISO will terminate the going forward need for the previously requested tariff waiver related to the NYISO’s
transmission constraint pricing.

III.Description of the Proposed Tariff Revisions

The NYISO proposes to revise its current transmission constraint pricing logic to: (i)

apply the graduated Transmission Shortage Cost to all transmission facilities and Interfaces with a non-zero CRM value;14 and (ii) revise the current value assigned to the second “step” of the graduated Transmission Shortage Cost from $2,350 per MWh to $1,175 per MWh.  The NYISO also proposes tariff revisions to ensure that the revised transmission constraint pricing logic is fully described in the Services Tariff.

A. Transmission Shortage Cost Definition

The NYISO proposes to revise the definition of “Transmission Shortage Cost” in Section

2.20 of the Services Tariff to remove the details regarding the pricing values associated

therewith.  The NYISO proposes to relocate the details regarding the Transmission Shortage Cost pricing values to Section 17.1.4 of Attachment B of the Services Tariff.

11 For transmission constraints subject to the graduated Transmission Shortage Cost, the software accounts for the 20 MW of relief that is provided by the first two “steps” of this pricing mechanism when determining the applicable level of relaxation necessary to make the constraint feasible.

12 See Docket No. ER17-758-000, New York Independent System Operator, Inc., Request for Tariff Waiver (January 6, 2017).

13 Id. at 10-12.

14 To broaden the application of the graduated Transmission Shortage Cost to all transmission facilities and Interfaces with a non-zero CRM value, the NYISO will, on the effective date of the
proposed tariff revisions, discontinue use of the current preliminary screening mechanism described above that results in the application of only the single $4,000 per MWh Shadow Price cap to certain transmission constraints associated with such transmission facilities and Interfaces.

Honorable Kimberly D. Bose April 21, 2017

Page 5

The NYISO proposes to delete the substance of the duplicative definition of the term

“Transmission Shortage Cost” in Section 1.20 of the OATT and replace it with a cross reference to corresponding definition of that term in the Services Tariff.

B. Section 17.1.4 of Attachment B of the Services Tariff

The NYISO proposes to revise Section 17.1.4 of Attachment B of the Services Tariff to
more fully describe the NYISO’s transmission constraint pricing logic.  The proposed revisions
clearly identify the difference in the logic applied depending on whether a transmission facility
or Interface has a zero or non-zero CRM value.  The proposed revisions also describe the
existing software logic for resolving infeasible transmission constraints.  The NYISO also
proposes to clarify the existing provision that authorizes temporary changes to the transmission
constraint pricing values in certain limited circumstances to expressly include an obligation to
notify Market Participants of any temporary changes implemented pursuant to this provision.

The applicable transmission constraint pricing logic applied is dependent on whether the transmission facility or Interface has a zero or non-zero CRM value.  For all transmission
facilities and Interfaces that have a non-zero CRM value, the graduated Transmission Shortage Cost mechanism will apply.  For transmission facilities and Interfaces that have a zero value CRM, the single $4,000 per MWh Shadow Price cap will apply.

1. Transmission Constraint Pricing Logic for Facilities and Interfaces with a Non-
Zero CRM Value

For transmission facilities and Interfaces that have a non-zero CRM value, the

transmission constraint pricing logic will utilize the graduated Transmission Shortage Cost

mechanism.  The mechanism consists of both a demand curve and a Shadow Price cap.  The first
two “steps” of the graduated Transmission Shortage Cost are implemented as a demand curve,
providing a total of 20 MW of additional resource capacity to help resolve applicable
transmission constraints - 5 MW of resource capacity available at a cost of $350 per MWh and,
as proposed, an additional 15 MW of resource capacity available at $1,175 per MWh.15  The
amount covered by the demand curve portion of the mechanism (i.e., 20 MW) represents the
minimum CRM value that is applied to transmission facilities and Interfaces that have a non-zero
CRM value.16  The final “step” of the graduated Transmission Shortage Cost operates as a
Shadow Price cap of $4,000 per MWh.  As such, the transmission constraint pricing logic will, if
needed, continue to pursue available resource capacity to resolve a transmission constraint at a

15 As further described below, the NYISO proposes to revise the current value assigned to the
second “step” of the graduated Transmission Shortage Cost from $2,350 per MWh to $1,175 per MWh.

16 The NYISO maintains a list of transmission facilities and Interfaces that identifies both those facilities and Interfaces that utilize a CRM value greater than 20 MW, as well as those that have a zero value CRM.  This list is available at:

http://www.nyiso.com/public/webdocs/markets_operations/market_data/power_grid_info/Constraint_Reli
ability_Margin_CRM.pdf.

Honorable Kimberly D. Bose April 21, 2017

Page 6

cost greater than $1,175 per MWh based on resource Bids and establish prices consistent with such Bids, subject to a maximum allowable Shadow Price of $4,000 per MWh.17

Certain stakeholders have urged the NYISO to revise the treatment of the third “step” of the graduated Transmission Shortage Cost to utilize a demand curve construct rather than a cost capping mechanism.  These stakeholders contend that such an implementation may obviate the need for using the constraint relaxation logic for these transmission constraints.

The logic for resolving infeasible transmission constraints has been in place since the

NYISO’s inception and is heavily integrated into the NYISO’s existing market software.

Removing this logic would be a significant undertaking and require substantial software

redesign.  Such an effort could potentially take years to ultimately implement.  Pursuit of such an
effort at this time in lieu of the proposed revisions would unnecessarily delay the ability to
resolve the present inconsistency between the transmission constraint pricing software logic and
the Services Tariff provisions describing such logic.  This would indefinitely extend the
continued need for the NYISO’s previously requested tariff waiver regarding this matter.  This
would also unnecessarily prolong marketplace uncertainty regarding the NYISO’s transmission
constraint pricing and market outcomes resulting therefrom to the detriment of all market
participants.

The NYISO has committed to exploring further enhancements to its transmission
constraint pricing with stakeholders beginning later this year.  This assessment will include
reviewing potential modifications to the manner in which the third “step” of the graduated
Transmission Shortage Cost is applied in the NYISO’s market software and/or other
enhancements that may reduce the need to utilize constraint relaxation (e.g., the potential
development of more constraint-specific pricing values).  The NYISO requests that the
Commission accept the current structure of the graduated Transmission Shortage Cost.
Discussions regarding any changes thereto should be deferred to the upcoming stakeholder
process that will assess potential future enhancements to the NYISO’s transmission constraint
pricing logic.

2. Value of the Second “Step” of the Graduated Transmission Shortage Cost

In seeking to broaden the application of the graduated Transmission Shortage Cost, the
NYISO also reassessed the current value assigned to the second “step” of this mechanism (i.e.,
$2,350 per MWh).  The NYISO established this value because it is equal to the total, cascaded
cost of going short 10-minute total reserves in both the East of Central-East and Southeastern
New York (“SENY”) reserve regions.18  Establishing equivalent shortage costs for these

17 To maintain consistency between prices and schedules, if a resource is available to provide

relief, but its costs exceed $4,000 per MWh, the Shadow Price for the transmission constraint is capped at $4,000 per MWh and the resource is not dispatched to provide relief.

18 See Docket No. ER15-1061-000, New York Independent System Operator, Inc., Proposed Tariff
Revisions to Ancillary Service Demand Curves and the Transmission Shortage Cost at 11-12 (February
18, 2015).

Honorable Kimberly D. Bose April 21, 2017

Page 7

scenarios was intended to ensure that the market software viewed limiting transmission shortages to 20 MW or less and avoiding shortages of 10-minute total reserves in the East of Central-East and SENY reserve regions as equally important.  Actual operating experience since the
implementation of the graduated Transmission Shortage Cost mechanism, however, has
demonstrated that the potential need for trade-offs between securing transmission constraints or avoiding a simultaneous shortage of 10-minute total reserves in both the East of Central-East and SENY reserve regions is likely not a practical concern.

This operating experience has demonstrated that a more appropriate value for the second
“step” of the graduated Transmission Shortage Cost mechanism should provide an efficient price
signal to recognize that avoiding exhaustion of the CRM is a higher priority than avoiding a
shortage of 10-minute total reserves in the East of Central-East reserve region, which has an
assigned shortage cost of $775 per MWh.19  The proposed value of $1,175 per MWh provides an
appropriate price signal that recognizes this relative priority in resolving Constraints without
establishing an unnecessarily high price to reflect system conditions in such circumstances.20
This proposed revision is intended to provide for the use of a value that more appropriately
reflects expected system conditions and needs during periods when this pricing value is likely to
be relevant, as determined based on actual operating experience since the graduated pricing
mechanism was implemented.

3. Transmission Constraint Pricing Logic for Facilities and Interfaces with a Zero
Value CRM

The proposed revisions to Section 17.1.4 also clarify the current transmission constraint
pricing logic applicable to transmission facilities and Interfaces that have a zero value CRM.
These transmission constraints are subject to a single $4,000 per MWh Shadow Price cap.

This construct is consistent with the structure of the graduated Transmission Shortage
Cost mechanism.  The first two “steps” of the graduated Transmission Shortage Cost are
designed to price use of the CRM to assist in resolving transmission constraints.  Thus, these
interim pricing values would not logically apply to transmission facilities and Interfaces without
a CRM.  For these facilities and Interfaces, any shortage would go beyond the applicable
physical limit of the facility.  Consistent with the graduated Transmission Shortage Cost,
shortages of this magnitude are subject to the $4,000 per MWh Shadow Price cap.

19 See Section 15.4.7(f) of Rate Schedule 4 of the Services Tariff.

20 The proposed value of $1,175 per MWh is consistent with the initial value that was proposed by the NYISO and approved by the Commission prior to the NYISO’s implementation of it revised shortage pricing in November 2015.  See Docket No. ER15-485-000, supra, Proposed Tariff
Amendments to Revise Transmission Shortage Costs (November 25, 2014); and Docket No. ER15-485-
000, supra, Letter Order (January 15, 2015).

Honorable Kimberly D. Bose April 21, 2017

Page 8

The transmission constraint pricing logic in these cases does not include the demand

curve functionality included as part of the graduated Transmission Shortage Cost mechanism.21

4. Resolution of Infeasible Transmission Constraints

The proposed revisions to Section 17.1.4 also describe the existing logic utilized by the
NYISO’s software to resolve infeasible transmission constraints in the economic dispatch.
Infeasible transmission constraints represent circumstances in which insufficient resource
capacity is available to resolve a given constraint at its otherwise applicable limit in the software.

When faced with these circumstances, the NYISO’s software has, since its inception, included logic for resolving such infeasibilities.  If an infeasible transmission constraint is identified in the economic dispatch, the infeasibility is resolved by adjusting the otherwise applicable limit for the constraint consistent with the quantity of resource capacity that is
available.  The software resolves the infeasibility by adjusting the otherwise applicable limit to the value that is achievable by the available resource capacity, plus 0.2 MW.

For an infeasible transmission constraint that is subject to the graduated Transmission

Shortage Cost mechanism, the additional 20 MW of available resource capacity provided by the demand curve functionality included as part of such mechanism is accounted for in determining the limit adjustment that is necessary to resolve the infeasibility.

IV.Effective Date

The NYISO respectfully requests an effective date of June 20, 2017 (i.e., sixty days from the date of this filing) for the proposed tariff revisions.

Commission acceptance, and NYISO implementation, of the proposed revisions will terminate the going forward need for the previously requested tariff waiver regarding the NYISO’s transmission constraint pricing logic.22

V.Requisite Stakeholder Approval

The proposed tariff amendments were approved by the NYISO Management Committee, without opposition, on March 29, 2017.  The NYISO’s Board of Directors approved the
proposed revisions on April 11, 2017.

21 Internal transmission facilities with a zero value CRM consist primarily of export-constrained generation pockets where the transmission system infrastructure was generally designed to provide only the capability necessary to accommodate delivering the generation output within such areas to the system. Applying the graduated Transmission Shortage Cost to these transmission facilities could result in
anomalous and undesirable negative price outcomes in certain circumstances without providing the
affected generation facilities the ability to Bid in a manner that would minimize their curtailment risk if the applicable transmission facilities become constrained.

22 See Docket No. ER17-758-000, supra, Request for Tariff Waiver (January 6, 2017).

Honorable Kimberly D. Bose April 21, 2017

Page 9

The NYISO has also reviewed the proposed revisions to its transmission constraint

pricing logic with the MMU.  The MMU has authorized the NYISO to indicate that the MMU
supports the proposed changes as appropriate, reasonable and a material improvement to the
current logic.  The MMU, however, continues to urge the NYISO to pursue further
enhancements, including the assessment of implementing constraint-specific pricing mechanisms
and further reducing use of the current transmission constraint relaxation logic.  The NYISO
understands that the MMU is likely to file comments in response to the NYISO’s proposal to
further describe its position.

VI.Communications and Correspondence

All communications and service in this proceeding should be directed to:

Robert E. Fernandez, General Counsel

Raymond Stalter, Director, Regulatory Affairs *Garrett E. Bissell, Senior Attorney

10 Krey Boulevard

Rensselaer, NY 12144

Telephone:  518-356-6107
Email: gbissell@nyiso.com

*Person designated for receipt of service.

VII.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 State Public
Service Commission, and to the New Jersey Board of Public Utilities.  In addition, the complete
filing will be posted on the NYISO’s website at www.nyiso.com.

Honorable Kimberly D. Bose April 21, 2017

Page 10

VIII.Conclusion

The NYISO respectfully requests that the Commission accept the proposed revisions to
the Services Tariff and the OATT that are attached hereto with an effective date of June 20,
2017.

Respectfully submitted,

/s/ Garrett E. Bissell

Garrett E. Bissell
Senior Attorney

New York Independent System Operator, Inc.

cc:Michael Bardee

Nicole Buell

Anna Cochrane
Kurt Longo

David Morenoff
Daniel Nowak
Larry Parkinson

J. Arnold Quinn
Douglas Roe

Kathleen Schnorf
Jamie Simler

Gary Will

Attachment I

2.20Definitions - T

Tangible Net Worth: The value, determined by the ISO, of all of a Customer’s assets less both:

(i) the amount of the Customer’s liabilities and (ii) all of the Customer’s intangible assets,

including, but not limited to, patents, trademarks, franchises, intellectual property, and goodwill.

Testing Period: An ISO approved period of time during which a Generator is testing equipment
and during which unstable operation prevents the unit from accurately following its base points.

Third Party Transmission Wheeling Agreements ("Third Party TWAs"): A Transmission
Wheeling Agreement, as amended, between Transmission Owners or between a Transmission
Owner and an entity that is not a Transmission Owner.  Third Party TWAs are associated with
the purchase (or sale) of Energy, Capacity, and/or Ancillary Services for the benefit of an entity
that is not a Transmission Owner.  All Third Party TWAs are listed in Table 1 A of Attachment
L to the ISO OATT, and are designated in the “Treatment “column of Table 1A, as “Third Party
TWA.”

Total Transfer Capability ("TTC"): The amount of electric power that can be transferred over the interconnected transmission network in a reliable manner.

Trading Hub: A virtual location in a given Load Zone, modeled as a Generator bus and/or Load
bus, for scheduling Bilateral Transactions in which both the POI and POW are located within the
NYCA.

Trading Hub Energy Owner: A Customer who buys energy in a Bilateral Transaction in which the POW is a Trading Hub, or who sells energy in a Bilateral Transaction in which the POI is a
Trading Hub.

Transaction: The purchase and/or sale of Energy or Capacity, or the sale of Ancillary Services. A Transaction bid into the Energy market to sell or purchase Energy or to schedule a Bilateral Transaction includes a Point of Injection and a Point of Withdrawal.

Transfer Capability: The measure of the ability of interconnected electrical systems to reliably move or transfer power from one area to another over all transmission facilities (or paths)
between those areas under specified system conditions.

Transmission Congestion Contract Component (“TCC Component”): A component of the Operating Requirement, calculated in accordance with Section 26.4.2 of Attachment K to this Services Tariff.

Transmission Congestion Contracts ("TCCs"): The right to collect or obligation to pay Congestion Rents in the Day-Ahead Market for Energy associated with a single MW of
transmission between a specified POI and POW.  TCCs are financial instruments that enable Energy buyers and sellers to hedge fluctuations in the price of transmission.

Transmission Customer: Any entity (or its designated agent) that requests or receives
Transmission Service pursuant to a Service Agreement and the terms of the ISO OATT.

Transmission District: The geographic area in which a Transmission Owner, including LIPA, is obligated to serve Load, as well as the customers directly interconnected with the transmission facilities of the Power Authority of the State of New York.

Transmission Facilities Under ISO Operational Control: The transmission facilities of the Transmission Owners listed in Appendix A-1 of the ISO/TO Agreement (“Listing of
Transmission Facilities Under ISO Operational Control”) and listed in Appendix A-1 of an
Operating Agreement (“NTO Transmission Facilities Under ISO Operational Control”) that are subject to the Operational Control of the ISO.  This listing may be amended from time-to-time as specified in the ISO/TO Agreement and Operating Agreements.

Transmission Facilities Requiring ISO Notification: The transmission facilities of the

Transmission Owners listed in Appendix A-2 of the ISO/TO Agreement (“Listing of

Transmission Facilities Requiring ISO Notification”) and listed in Appendix A-2 of an Operating
Agreement (“NTO Transmission Facilities Requiring ISO Notification”) whose status of
operation must be provided to the ISO by the Transmission Owners (for the purposes stated in
the ISO Tariffs and in accordance with the ISO Tariffs, ISO/TO Agreement, and/or Operating
Agreements) prior to the Transmission Owners making operational changes to the state of these
facilities.  This listing may be amended from time-to-time as specified in the ISO/TO Agreement
and Operating Agreements.

Transmission Facility Agreement (“TFA”): Agreements governing the use of specific or

designated transmission facilities charges to cover all, or a portion, of the costs to install, own, operate, or maintain  transmission facilities, to the customer under the agreement and that have provisions to provide Transmission Service utilizing said transmission facilities.  All
Transmission Facility Agreements are listed in Attachment L. Table 1A, and are designated in the “Treatment” column as “Facility Agmt. - MWA.”

Transmission Fund ("T-Fund"): The mechanism used under the current NYPP Agreement to
compensate the Member Systems for providing Transmission Service for economy Energy
Transactions over their transmission systems.  Each Member System is allocated a share of the
economy Energy savings in dollars assigned to the fund that is based on the ratio of their
investment in transmission facilities to the sum of investments in transmission and generation
facilities.

Transmission Owner: The public utility or authority (or its designated agent) that owns

facilities used for the transmission of Energy in interstate commerce and provides Transmission Service under the Tariff.

Transmission Owner’s Monthly Transmission System Peak: The maximum hourly firm

usage as measured in megawatts (“MW”) of the Transmission Owner’s transmission system in a calendar month.

Transmission Reliability Margin (“TRM”): The amount of TTC reserved by the ISO to ensure the interconnected transmission network is secure under a reasonable range of uncertainties in system conditions.

Transmission Service: Point-To-Point Network Integration or Retail Access Transmission Service provided under the ISO OATT.

Transmission Service Charge (“TSC”): A charge designed to ensure recovery of the embedded cost of a transmission system owned by a Member System.

Transmission Shortage Cost: A pricing mechanism utilized in determining the Shadow Price of a particular transmission Constraint that will be used in calculating LBMP in accordance with Section 17.1.4 of Attachment B of this ISO Services Tariff.

Transmission System: The facilities operated by the ISO that are used to provide Transmission Services under the ISO OATT.

Transmission Usage Charge (“TUC”): Payments made by the Transmission Customer to cover
the cost of Marginal Losses and, during periods of time when the transmission system is
constrained, the marginal cost of Congestion.  The TUC is equal to the product of:  (1) the
LBMP at the POW minus the LBMP at the POI (in $/MWh); and (2) the scheduled or delivered
Energy (in MWh).

Transmission Wheeling Agreement (“TWA”): The Agreements listed in Table 1A  of

Attachment L to the ISO OATT governing the use of specific or designated transmission

facilities that are owned, controlled or operated by an entity for the transmission of Energy in interstate commerce. TWAs between Transmission Owners have been modified such that all TWAs between Transmission Owners are now MWAs.

17.1LBMP Calculation

The Locational Based Marginal Prices (“LBMPs” or “prices”) for Suppliers and Loads in
the Real-Time Market will be based on the system marginal costs produced by the Real-Time
Dispatch (“RTD”) program and during intervals when certain conditions exist at Proxy
Generator Buses, the Real-Time Commitment (“RTC”) program.  LBMPs for Suppliers and
Loads in the Day-Ahead Market will be based on the system marginal costs produced by the
Security Constrained Unit Commitment (“SCUC”).  LBMPs calculated by SCUC and RTD will
incorporate the incremental dispatch costs of Resources that would be scheduled to meet an
increment of Load and, to the extent that tradeoffs exist between scheduling providers to produce
Energy or reduce demand, and scheduling them to provide Regulation Service or Operating
Reserves, LBMPs shall reflect the effect of meeting an increment of Load, given those tradeoffs,
at each location on the Bid Production Cost associated with those services.  As such, those
LBMPs may incorporate:  (i) Bids for Regulation Service or Operating Reserves; or (ii) shortage
costs associated with the inability to meet a Regulation Service or Operating Reserves
requirement under the Regulation Service Demand Curve set forth in Rate Schedule 3 of this
ISO Services Tariff and Operating Reserve Demand Curves and Scarcity Reserve Demand Curve
set forth in Rate Schedule 4 of this ISO Services Tariff.

Additionally, for the purpose of calculating Real-Time LBMPs when RTD is committing
and dispatching Resources meeting Minimum Generation Levels and capable of starting in ten
minutes pursuant to Section 4.4.2.4 of this ISO Services Tariff, RTD shall include in the
incremental dispatch cost of each such Resource a start-up cost based on the Start-Up Bid of
each such Resource and shall assume for each such Resource a zero downward response rate.

17.1.1LBMP Bus Calculation Method

System marginal costs will be utilized in an ex ante computation to produce DayAhead and Real-Time LBMP bus prices using the following equations.
The LBMP at bus i can be written as:

Where:

=LBMP at bus i in $/MWh

=the system marginal price at the Reference Bus

=      Marginal Losses Component of the LBMP at bus i which is the marginal
cost of losses at bus i relative to the Reference Bus

=      Congestion Component of the LBMP at bus i which is the marginal cost of
Congestion at bus i relative to the Reference Bus

The Marginal Losses Component of the LBMP at any bus i is calculated using the equation:

Where:

=      delivery factor for bus i to the system Reference Bus and:

Where:

L=      NYCA losses; and

=      injection at bus i

The Congestion Component of the LBMP at bus i is calculated using the equation:

Where:

K=        the set of Constraints;

=       Shift Factor for bus i on Constraint k in the pre- or post-

Contingency case which limits flows across that Constraint (the Shift

Factor measures the incremental change in flow on Constraint k, expressed in per unit, for an increment of injection at bus i and a corresponding
withdrawal at the Reference Bus); and

=the Shadow Price of Constraint k expressed in $/MWh, provided however,

this Shadow Price shall not exceed the Transmission Shortage Cost.

Substituting the equations forandinto the first equation yields:

LBMPs will be calculated for the Day-Ahead and the Real-Time Markets.  In the DayAhead Market, the three components of the LBMP at each location will be calculated from the SCUC results and posted for each of the twenty four (24) hours of the next day.  The Real-Time LBMPs will be calculated and posted for each execution of RTD.

17.1.1.1   Determining Shift Factors and Incremental System Losses

For the purposes of pricing and scheduling, Shift Factors, GFik, and loss delivery factors,
DFi, will reflect expected power flows, including expected unscheduled power flows.  When
determining prices and schedules, SCUC, RTC and RTD shall include both the expected power
flows resulting from NYISO interchange schedules (see Section 17.1.1.1.2), and expected
unscheduled power flows (see Section 17.1.1.1.1).  All NYCA Resource, NYCA Load and Proxy
Generator Bus Shift Factors and loss delivery factors will incorporate internal and coordinated

external transmission facility outages, power flows due to schedules, and expected unscheduled power flows.

17.1.1.1.1 Determining Expected Unscheduled Power Flows

In the Day-Ahead Market, expected unscheduled power flows will ordinarily be

determined based on historical, rolling 30-day on-peak and off-peak averages.  To ensure

expected unscheduled power flows accurately reflect anticipated conditions, the frequency

and/or period used to determine the historical average may be modified by the NYISO to address market rule, system topology, operational, or other changes that would be expected to
significantly impact unscheduled power flows.  The NYISO will publicly post the Day-Ahead on-peak and off-peak unscheduled power flows on its web site.

In the Real-Time Market, expected unscheduled power flows will ordinarily be

determined based on current power flows, modified to reflect expected changes over the realtime scheduling horizon.

17.1.1.1.2 Determining Expected Power Flows Resulting from NYISO Interchange
Schedules

In the Day-Ahead Market, for purposes of scheduling and pricing, SCUC will establish expected power flows for the ABC interface, JK interface and Branchburg-Ramapo
interconnection based on the following:

a.Consolidated Edison Company of New York’s Day-Ahead Market hourly election

under OATT Attachment CC, Schedule C;

b. The percentage of PJM-NYISO scheduled interchange that is expected to flow

over the Branchburg-Ramapo interconnection.  The expected flow may also be adjusted by a MW offset to reflect expected operational conditions;

c.The percentage of PJM-NYISO scheduled interchange (if any) that is expected to

flow over the ABC interface; and

d.The percentage of PJM-NYISO scheduled interchange (if any) that is expected to

flow over the JK interface.

The terms “ABC interface” and “JK interface” have the meaning ascribed to them in Schedule C to Attachment CC to the OATT.

The NYISO shall post the percentage values it is currently using to establish Day-Ahead
and real-time expected Branchburg-Ramapo interconnection, ABC interface and JK interface
flows for purposes of scheduling and pricing on its web site.  If the NYISO determines it is
necessary to change the posted Branchburg-Ramapo, ABC or JK percentage values, it will
provide notice to its Market Participants as far in advance of the change as is practicable under
the circumstances.

In the Day-Ahead Market, scheduled interchange that is not expected to flow over the ABC interface, JK interface or Branchburg-Ramapo interconnection (or on Scheduled Lines) will be expected to flow over the NYISO’s other interconnections.  Expected flows over the NYISO’s other interconnections will be determined consistent with the expected impacts of scheduled interchange and consistent with shift factors and delivery factors calculated in
accordance with Section 17.1.1.1, above.

For pricing purposes, flows in the Real-Time Market will be established for the ABC
interface, JK interface, and Branchburg-Ramapo interconnection based on the current flow,
modified to reflect the expected incremental impacts of changes to interchange schedules over
the forward scheduling horizon in a manner that is consistent with the method used to establish
Day-Ahead power flows over these facilities.  Expected flows over the NYISO’s other

interconnections will be determined based on the current flow, modified to reflect the expected incremental impacts of changes to interchange schedules over the forward scheduling horizon, and shall be consistent with shift factors and delivery factors calculated in accordance with
Section 17.1.1.1, above.

17.1.1.1.3 Scheduled Lines and Chateauguay Interconnection with Hydro Quebec

For purposes of scheduling and pricing, the NYISO expects that power flows will

ordinarily match the interchange schedule at Scheduled Lines, and at the NYCA’s Chateauguay interconnection with Hydro Quebec, in both the Day-Ahead and Real-Time Markets.

17.1.2 Real-Time LBMP Calculation Procedures

For each RTD interval, the ISO shall use the procedures described below in Sections

17.1.2.1-17.1.2.1.4 to calculate Real-Time LBMPs at each Load Zone and Generator bus.  The LBMP bus and zonal calculation procedures are described in Sections 17.1.1 and 17.1.5 of this Attachment B, respectively.  Procedures governing the calculation of LBMPs at Proxy Generator Buses are set forth below in Section 17.1.6 of this Attachment B.

17.1.2.1   General Procedures

17.1.2.1.1 Overview

The ISO shall calculate Real-Time Market LBMPs using the three passes of each RTD
run, except as noted below in Section 17.1.2.1.3.  A new RTD run will initialize every five
minutes and each run will produce prices and schedules for five points in time (the optimization
period).  Only the prices and schedules determined for the first time point of the optimization
period will be binding.  Prices and schedules for the other four time points of the optimization
period are advisory.

Each RTD run shall, depending on when it occurs during the hour, have a bid

optimization horizon of fifty, fifty-five, or sixty minutes beyond the first, or binding, point in
time that it addresses.  The posting time and the first time point in each RTD run, which
establishes binding prices and schedules, will be five minutes apart.  The remaining points in
time in each optimization period can be either five, ten, or fifteen minutes apart depending on
when the run begins within the hour.  The points in time in each RTD optimization period are
arranged so that they parallel as closely as possible RTC’s fifteen minute evaluations.
For example, the RTD run that posts its results at the beginning of an hour (“RTD0”) will initialize at the fifty-fifth minute of the previous hour and produce schedules and prices over a fifty-five minute optimization period.  RTD0 will produce binding prices and schedules for the RTD interval beginning when it posts its results (i.e., at the beginning of the hour) and ending at the first time point in its optimization period (i.e., five minutes after the hour).  It will produce advisory prices and schedules for its second time point, which is ten minutes after the first time point in its optimization period, and advisory prices and schedules for its third, fourth and fifth time points, each of which would be fifteen minutes apart.  The RTD run that posts its results at five minutes after the beginning of the hour (“RTD5”) will initialize at the beginning of the hour and produce prices over a fifty minute optimization period.  RTD5 will produce binding prices and schedules for the RTD interval beginning when it posts its results (i.e., at five minutes after the hour) and ending at the first time point in its optimization period (i.e., ten minutes after the hour.)  It will produce advisory prices and schedules for its second time point (which is five minutes after the first time point), and advisory prices and schedules for its third, fourth and fifth time points, each of which would be fifteen minutes apart.  The RTD run that posts its results at ten minutes after the beginning of the hour (“RTD10”) will initialize at five minutes after the

beginning of the hour and produce prices over a sixty minute optimization period.  RTD10 will
produce binding prices and schedules for the interval beginning when it posts its results (i.e., at
ten minutes after the hour) and ending at the first time point in its optimization period (i.e.,
fifteen minutes after the hour.)  It will produce advisory prices and schedules for its second,
third, fourth and fifth time points, each of which would be fifteen minutes after the preceding
time point.

17.1.2.1.2 Description of the Real-Time Dispatch Process

17.1.2.1.2.1The First Pass

The first RTD pass consists of a least bid cost, multi-period co-optimized dispatch for
Energy, Regulation Service and Operating Reserves that treats all Fixed Block Units that are
committed by RTC, or are otherwise instructed to be online or remain online by the ISO as if
they were blocked on at their UOLN or UOLE, whichever is applicable.  Resources meeting
Minimum Generation Levels and capable of being started in ten minutes that have not been
committed by RTC are treated as flexible (i.e. able to be dispatched anywhere between zero (0)
MW and their UOLN or UOLE, whichever is applicable).  The first pass establishes “physical
base points” (i.e., real-time Energy schedules) and real-time schedules for Regulation Service
and Operating Reserves for the first time point of the optimization period.  Physical base points
and schedules established for the first time point shall be binding and shall remain in effect until
the results of the next run are posted.  Physical base points and schedules established for all
subsequent time points shall be advisory.  The first pass also produces information that is used to
calculate the RTD Base Point Signals that the ISO sends to Suppliers.

When establishing physical base points, the ISO shall assume that each Generator will move toward the physical base point established during the first pass of the prior RTD run at its specified response rate.

17.1.2.1.2.1.1 Upper and Lower Dispatch Limits for Dispatchable Resources Other
Than Intermittent Power Resources That Depend on Wind as Their Fuel

When setting physical base points for a Dispatchable Resource at the first time point, the
ISO shall ensure that they do not fall outside of the bounds established by the Dispatchable
Resource’s lower and upper dispatch limits.  A Dispatchable Resource’s dispatch limits shall be
determined based on whether it was feasible for it to reach the physical base point calculated by
the last RTD run given its: (A) metered output level at the time that the RTD run was initialized;

(B) response rate; (C) minimum generation level; and (D) UOLN or UOLE, whichever is

applicable.  If it was feasible for the Dispatchable Resource to reach that base point, then its

upper and lower dispatch limits shall reflect the highest and lowest output levels it could achieve over the next RTD interval, given its UOLN or UOLE, as applicable, and starting from its
previous base point.  If it was not feasible for the Dispatchable Resource to reach that base point, then its upper and lower dispatch limits shall reflect the highest and lowest output levels it could achieve over the next RTD interval, given its UOLN or UOLE, as applicable, but instead starting from the feasible output level closest to its previous base point.

When setting physical base points for a Dispatchable Resource at later time points, the ISO shall ensure that they do not fall outside of the bounds established by the Resource’s lower and upper dispatch limits for that time point.  A Resource’s dispatch limits at later time points shall be based on its: (A) dispatch limits from the first time point; (B) response rate; (C)
minimum generation; and (D) UOLN or UOLE, whichever is applicable.

The upper dispatch limit for a Dispatchable Resource at later time points shall be

determined by increasing the upper dispatch limit from the first time point at the Resource’s

response rate, up to its UOLN or UOLE, whichever is applicable.  The lower dispatch limit for a Dispatchable Resource at later time points shall be determined by decreasing the lower dispatch limit from the first time point at the Resource’s response rate, down to its minimum generation level or to a Demand Side Resource’s Demand Reduction level.

The RTD Base Point Signals sent to Dispatchable Resources shall be the same as the physical base points determined above.

17.1.2.1.2.1.2 Upper and Lower Dispatch Limits for Intermittent Power Resources
That Depend on Wind as Their Fuel

For all time points of the optimization period, the Lower Dispatch Limit shall be zero and the Upper Dispatch Limit shall be the Wind Energy Forecast for that Resource.  For Intermittent Power Resources depending on wind as their fuel in commercial operation as of January 1, 2002 with a name plate capacity of 12 MWs or fewer, the Upper and Lower Dispatch Limits shall be the output level specified by the Wind Energy Forecast.

17.1.2.1.2.1.3. Setting Physical Basepoints for Fixed Generators

When setting physical base points for Self-Committed Fixed Generators in any time point, the ISO shall consider the feasibility of the Resource reaching the output levels that it specified in its self-commitment request for each time point in the RTD run given: (A) its metered output at the time that the run was initialized; and (B) its response rate.

When setting physical base points for ISO-Committed Fixed Generators in any time

point, the ISO shall consider the feasibility of the Resource reaching the output levels scheduled

for it by RTC for each time point in the RTD run given: (A) its metered output at the time that the run was initialized; and (B) its response rate.

The RTD Base Point Signals sent to Self-Committed Fixed Generators shall follow the quarter hour operating schedules that those Generators submitted in their real-time self-
commitment requests

The RTD Base Point Signals sent to ISO-Committed Fixed Generators shall follow the
quarter hour operating schedules established for those Generators by RTC, regardless of their
actual performance.  To the extent possible, the ISO shall honor the response rates specified by
such Generators when establishing RTD Base Point Signals.  If a Self-Committed Fixed
Generator’s operating schedule is not feasible based on its real-time self-commitment requests
then its RTD Base Point Signals shall be determined using a response rate consistent with the
operating schedule changes.

17.1.2.1.2.2    The Second Pass

The second RTD pass consists of a least bid cost, multi-period, co-optimized dispatch for
Energy, Regulation Service, and Operating Reserves that treats all Fixed Block Units that are
committed by RTC, all Resources meeting Minimum Generation Levels and capable of starting
in ten minutes that have not been committed by RTC and all units otherwise instructed to be
online or remain online by the ISO, as flexible (i.e., able to be dispatched anywhere between zero

(0) MW and their UOLN or UOLE, whichever is applicable), regardless of their minimum run-
time status.  The second pass calculates real-time Energy prices and real-time Shadow Prices for
Regulation Service and Operating Reserves that the ISO shall use for settlement purposes
pursuant to Article 4, Rate Schedule 15.3, and Rate Schedule 15.4 of this ISO Services Tariff

respectively.  The ISO will not use schedules for Energy, Regulation Service and Operating Reserves established in the second pass to dispatch Resources.

The upper and lower dispatch limits used for ISO-Committed Fixed and Self-Committed Fixed Resources shall be the same as the physical base points calculated in the first pass.

17.1.2.1.2.2.1 Upper and Lower Dispatch Limits for Dispatchable Resources Other
Than Intermittent Power Resources That Depend on Wind as Their Fuel

The upper dispatch limit for the first time point of the second pass for a Dispatchable

Resource shall be the higher of: (A) its upper dispatch limit from the first pass; or (B) its “pricing
base point” from the first time point of the prior RTD interval adjusted up within its Dispatchable
range for any possible ramping since that pricing base point was issued less the higher of: (i) the
physical base point established during the first pass of the RTD immediately prior to the previous
RTD minus the Resource’s metered output level at the time that the current RTD run was
initialized, or (ii) zero.

The lower dispatch limit for the first time point of the second pass for a Dispatchable

Resource shall be the lower of: (A) its lower dispatch limit from the first pass; or (B) its “pricing base point” from the first time point of the prior RTD interval adjusted down within its
Dispatchable range to account for any possible ramping since that pricing base point was issued plus the higher of: (i) the Resource’s metered output level at the time that the current RTD run was initialized minus the physical base point established during the first pass of the RTD
immediately prior to the previous RTD; or (ii) zero.

The upper dispatch limit for the later time points of the second pass for a Dispatchable
Resource shall be determined by increasing its upper dispatch limit from the first time point at
the Resource’s response rate, up to its UOLN or UOLE, whichever is applicable.  The lower
dispatch limit for the later time points of the second pass for such a Resource shall be determined

by decreasing its lower dispatch limit from the first time point at the Resource’s response rate, down to its minimum generation level.

17.1.2.1.2.2.2 Upper and Lower Dispatch Limits for Intermittent Power Resources
That Depend on Wind as Their Fuel

For the first time point and later time points for Intermittent Power Resources that depend
on wind as their fuel, the Lower Dispatch Limit shall be zero and the Upper Dispatch Limit shall
be the Wind Energy Forecast for that Resource.  For Intermittent Power Resources depending on
wind as their fuel in commercial operation as of January 1, 2002 with a name plate capacity of

12 MWs or fewer, the Upper and Lower Dispatch Limits shall be the output level specified by the Wind Energy Forecast.

17.1.2.1.2.3The Third Pass

The third RTD pass is reserved for future use.

17.1.2.1.3 Variations in RTD-CAM

When the ISO activates RTD-CAM, the following variations to the rules specified above in Sections 17.1.2.1.1 and 17.1.2.1.2 shall apply.

First, if the ISO enters reserve pickup mode: (i) the ISO will produce prices and

schedules for a single ten minute interval  (not for a multi-point co-optimization period); (ii) the ISO shall set Regulation Service schedules to zero as described in Rate Schedule 15.3 of this ISO Services Tariff; (iii) the ISO will have discretion to make additional Generator commitments before executing the three RTD passes; and (iv) the ISO will have discretion to allow the RTD Base Point Signal of each Dispatchable Generator to be set to the higher of the Generator’s
physical base point or its actual generation level.

Second, if the ISO enters maximum generation pickup mode: (i) the ISO will produce

prices and schedules for a single five minute interval (not for a multi-point co-optimization

period); (ii) the ISO shall set Regulation Service schedules to zero as described in Rate Schedule

15.3 of this ISO Services Tariff; (iii) the ISO will have discretion to make additional Generator
commitments in the affected area before executing the three RTD passes; and (iv) the ISO will
have discretion to either move the RTD Base Point Signal of each Generator within the affected
area towards its UOLE at its emergency response rate or set it at a level equal to its physical base
point.

Third, if the ISO enters basepoints ASAP - no commitments mode it will produce prices and schedules for a single five minute interval (not for a multi-point co-optimization period).
Fourth, if the ISO enters basepoints ASAP - commit as needed mode: (i) the ISO will produce price and schedules for a single five minute interval (not for a multi-point co-
optimization period); and (ii) the ISO may make additional commitments of Generators that are capable of starting within ten minutes before executing the three RTD passes.
Fifth, and finally, if the ISO enters re-sequencing mode it will solve for a ten-minute optimization period consisting of two five-minute time points.

17.1.2.1.4 The Real-Time Commitment (“RTC”) Process and Automated Mitigation

Attachment H of this Services Tariff shall establish automated market power mitigation
measures that may affect the calculation of Real-Time LBMPs.  To the extent that these
measures are implemented they shall be incorporated into the RTC software through the
establishment of a second, parallel, commitment evaluation that will assess the impact of the
mitigation measures.  The first evaluation, referred to as the “RTC evaluation,” will determine
the schedules and prices that would result using an original set of offers and Bids before any

additional mitigation measures, the necessity for which will be considered in the RTC

evaluation, are applied.  The second evaluation, referred to as the “RT-AMP” evaluation, will

determine the schedules and prices that would result from using the original set of offers and bids
as modified by any necessary mitigation measures.  Both evaluations will follow the rules
governing RTC’s operation that are set forth in Article 4 and this Attachment B to this ISO
Services Tariff.

In situations where Attachment H specifies that real-time automated mitigation measures
be utilized, the ISO will perform the two parallel RTC evaluations in a manner that enables it to
implement mitigation measures one RTC run (i.e., fifteen minutes) in the future.  For example,
RTC15 and RT-AMP15 will perform Resource commitment evaluations simultaneously.  RT-
AMP15 will then apply the mitigation “impact” test, account for reference bid levels as
appropriate and determine which Resources are actually to be mitigated.  This information will
then be conveyed to RTC30 which will make Resource commitments consistent with the
application of the mitigation measures (and will thus indirectly be incorporated into future RTD
runs).

17.1.3 Day-Ahead LBMP Calculation Procedures

LBMPs in the Day-Ahead Market are calculated using five passes.  The first two passes
are commitment and dispatch passes; the last three are dispatch only passes.
Pass 1 consists of a least cost commitment and dispatch to meet Bid Load and reliable operation of the NYS Power System that includes Day-Ahead Reliability Units.
It consists of several steps.  Step 1A is a complete Security Constrained Unit
Commitment (“SCUC”) to meet Bid Load.  At the end of this step, committed Fixed Block
Units, Imports, Exports, Virtual Supply, Virtual Load, Demand Side Resources and non-Fixed

Block Units are dispatched to meet Bid Load with Fixed Block Units treated as dispatchable on a
flexible basis.  For mitigation purposes, LBMPs are calculated from this dispatch.  Following
Step 1A, SCUC tests for automated mitigation procedure (“AMP”) activation.
If AMP is activated, Step 1B tests to determine if the AMP will be triggered by
mitigating offer prices subject to mitigation that exceed the conduct threshold to their respective
reference prices.  These mitigated offer prices together with all originally submitted offer prices
not subject to automatic mitigation are then used to commit generation and dispatch energy to
meet Bid Load.  This step is another iteration of the SCUC process.  At the end of Step 1B,
committed Fixed Block Units, Imports, Exports, Virtual Supply, Virtual Load, Demand Side
Resources, and non-Fixed Block Units are again dispatched to meet Bid Load using the same
mitigated or unmitigated Bids used to determine the commitment to meet Bid Load, with Fixed
Block Units treated as dispatchable on a flexible basis.  For mitigation purposes, LBMPs are
again calculated from this dispatch.  The LBMPs determined at the end of Step 1B are compared
to the LBMPs determined at the end of Step 1A to determine the hours and zones in which the
impact test is met.

In Step 1C, generation offer prices subject to mitigation that exceed the conduct threshold
are mitigated for those hours and zones in which the impact test was met in Step 1B.  The
mitigated offer prices, together with the original unmitigated offer price of units whose offer
prices were not subject to mitigation, or did not trigger the conduct or impact thresholds, are used
to commit generation and dispatch energy to meet Bid Load.  This step is also a complete
iteration of the SCUC process.  At the end of Step 1C, committed Fixed Block Units, Imports,
Exports, virtual supply, virtual load, Demand Side Resources, and non-Fixed Block Units are

again dispatched to meet Bid Load, with Fixed Block Units treated as dispatchable on a flexible basis.  For mitigation purposes, LBMPs are again calculated from this dispatch.
All Demand Side Resources and non-Fixed Block Units committed in the final step of Pass 1 (which could be either step 1A, 1B, or 1C depending on activation of and the AMP) are blocked on at least to minimum load in Passes 4 through 6.  The resources required to meet local system reliability are determined in Pass 1.

Pass 2 consists of a least cost commitment and dispatch of Fixed Block Units, Imports,

Exports, Demand Side Resources and non-Fixed Block Units to meet forecast Load requirements
in excess of Bid Load, considering the Wind Energy Forecast, that minimizes the cost of
incremental Minimum Generation and Start Up Bids, given revenues for Minimum Generation
Energy based on LBMPs calculated in Pass 1, and assumes all Fixed Block Units are
dispatchable on a flexible basis.  Incremental Import Capacity needed to meet forecast Load
requirements is determined in Pass 2.  Fixed Block Units committed in this pass are not included
in the least cost dispatches of Passes 5 or 6.  Demand Side Resources and non-Fixed Block Units
committed in this step are blocked on at least to minimum Load in Passes 4 through 6.
Intermittent Power Resources that depend on wind as their fuel committed in this pass as a result
of the consideration of the Wind Energy Forecast are not blocked in Passes 5 or 6.
Pass 3 is reserved for future use.

Pass 4 consists of a least cost dispatch to forecast Load.  It is not used to set schedules or
prices.  It is used for operational purposes and provides a dispatch of Fixed Block Units, Imports,
Exports, Demand Side Resources and non-Fixed Block Units committed in Passes 1 or 2.
Incremental Import Capacity committed in Pass 2 is re-evaluated and may be reduced if no
longer required.

Pass 5 consists of a least cost dispatch of Fixed Block Units, Imports, Exports, Virtual
Supply, Virtual Load, Demand Side Resources and non-Fixed Block Units committed to meet Bid Load, based where appropriate on offer prices as mitigated in Pass 1.  Fixed Block Units are treated as dispatchable on a flexible basis.  LBMPs used to settle the Day-Ahead Market are
calculated from this dispatch.  The Shadow Prices used to compute Day-Ahead Market clearing prices for Regulation Service and for Operating Reserves in Rate Schedules 3 and 4 of this ISO Services Tariff are also calculated from this dispatch.  Final schedules for all Imports, Exports, Virtual Supply, Virtual Load, Demand Side Resources and non-Fixed Block Units in the DayAhead Market are calculated from this dispatch.

Pass 6 consists of a least cost dispatch of all Day-Ahead committed Resources, Imports, Exports, Virtual Supply, Virtual Load, based where appropriate on offer prices as mitigated in Pass 1, with the schedules of all Fixed Block Units committed in the final step of Pass 1 blocked on at maximum Capacity.  Final schedules for Fixed Block Units in the Day-Ahead Market are calculated from this dispatch.

17.1.4 Determination of Transmission Shortage Cost

The applicable Transmission Shortage Cost depends on whether a particular transmission Constraint is associated with a transmission facility or Interface that includes a non-zero
constraint reliability margin value.  The ISO shall establish constraint reliability margin values for transmission facilities and Interfaces.  Non-zero constraint reliability margin values
established by the ISO shall be equal to or greater than 20 MW.

For transmission facilities and Interfaces with a non-zero constraint reliability margin

value, SCUC, RTC and RTD shall include consideration of a two step demand curve consisting
of up to an additional 5 MW of available resource capacity at a cost of $350/MWh and up to an

additional 15 MW of available resource capacity at a cost of $1,175/MWh when evaluating transmission Constraints associated with such facilities and Interfaces.  In no event, however, shall the Shadow Price for such transmission Constraints exceed $4,000/MWh.

For transmission facilities and Interfaces with a constraint reliability margin value of

zero, the Shadow Price for transmission Constraints associated with such facilities and Interfaces shall not exceed $4,000/MWh.  SCUC, RTC and RTD shall not include consideration of the
available resource capacity provided by the two step demand curve described above for such
transmission Constraints.

In evaluating all transmission Constraints, the ISO will determine whether sufficient

available resource capacity exists to solve each transmission Constraint at its applicable limit.  If
sufficient available resource capacity does not exist to solve the transmission Constraint at its
otherwise applicable limit, the ISO shall increase the applicable limit for such transmission
Constraint to an amount achievable by the available resource capacity plus 0.2 MW.  For
transmission facilities and Interfaces with a non-zero constraint reliability margin value, the ISO
shall account for the 20 MW of available resource capacity from the two step demand curve
described above in determining: (i) whether sufficient available resource capacity exists to solve
transmission Constraints associated with such facilities and Interfaces at their otherwise
applicable limit; and (ii) the extent of any limit adjustment required to solve such transmission
Constraints.

The ISO may periodically evaluate the Transmission Shortage Cost to determine whether
it is necessary to modify the Transmission Shortage Cost to avoid future operational or reliability
problems.  The ISO will consult with its Market Monitoring Unit after it conducts this
evaluation.  If the ISO determines that it is necessary to modify the Transmission Shortage Costs

in order to avoid future operational or reliability problems the resolution of which would

otherwise require recurring operator intervention outside normal market scheduling procedures,
in order to avoid among other reliability issues, a violation of NERC Interconnection Reliability
Operating Limits or System Operating Limits, it may temporarily modify it for a period of up to
ninety days, provided however the NYISO shall file such change with the Commission pursuant
to Section 205 of the Federal Power Act within 45 days of such modification.  If circumstances
reasonably allow, the ISO will consult with its Market Monitoring Unit, the Business Issues

Committee, the Commission, and the PSC before implementing any such modification.  In all circumstances, the ISO will: (i) consult with those entities as soon as reasonably possible after implementing a temporary modification and shall explain the reasons for the change; and (ii) notify Market Participants of any temporary modification.

The responsibilities of the ISO and the Market Monitoring Unit in evaluating and

modifying the Transmission Shortage Cost, as necessary are addressed in Attachment O, Section

30.4.6.8.1 of this Market Services Tariff (“Market Monitoring Plan”).

17.1.5Zonal LBMP Calculation Method

The computation described in Section 17.1.1 of this Attachment B is at the bus level.  An eleven (11) zone model will be used for the LBMP billing related to Loads.  The LBMP for a zone will be a Load weighted average of the Load bus LBMPs in the Load Zone.  The Load weights which will sum to unity will be calculated from the load bus MW distribution.  Each component of the LBMP for a zone will be calculated as a Load weighted average of the Load bus LBMP components in the zone.  The LBMP for a zone j can be written as:

where:

=LBMP for zone j,

is the Marginal Losses Component of the LBMP for zone j;

is the Congestion Component of the LBMP for zone j;

n =number of Load buses in zone j for which LBMPs are

calculated; and

Load weighting factor for bus i.

The NYISO also calculates and posts zonal LBMP for four (4) external zones for

informational purposes only.  Settlements for External Transactions are determined using the
Proxy Generator Bus LBMP. Each external zonal LBMP is equal to the LBMP of the Proxy
Generator Bus associated with that external zone.  The table below identifies which Proxy
Generator Bus LBMP is used to determine each of the posted external zonal LBMPs.

ExternalExternal Zone

ZonePTID

HQ61844

NPX61845

OH61846
PJM 61847

Proxy Generator Bus

HQ_GEN_WHEEL

N.E._GEN_SANDY_POND O.H._GEN_BRUCE

PJM_GEN_KEYSTONE

Proxy Generator
Bus PTID

23651

24062

24063

24065

Consistent with the ISO Services Tariff, LBMPs at Proxy Generator Buses are determined using calculated bus prices as described in this Section 17.1.

17.1.6Real Time LBMP Calculation Methods for Proxy Generator Buses, Non-

Competitive Proxy Generator Buses and Proxy Generator Buses Associated with Designated Scheduled Lines

17.1.6.1   Definitions

Interface ATC Constraint:  An Interface ATC Constraint exists when proposed economic

transactions over an Interface between the NYCA and the Control Area with which one or more Proxy Generator Bus(es) are associated would exceed the transfer capability for the Interface or for an associated Proxy Generator Bus.

Interface Ramp Constraint:  An Interface Ramp Constraint exists when proposed interchange schedule changes pertaining to an Interface between the NYCA and the Control Area with which one or more Proxy Generator Bus(es) are associated would exceed any Ramp Capacity limit imposed by the ISO for the Interface or for an associated Proxy Generator Bus.

NYCA Ramp Constraint: A NYCA Ramp Constraint exists when proposed interchange

schedule changes pertaining to the NYCA as a whole would exceed any Ramp Capacity limits in place for the NYCA as a whole.

Proxy Generator Bus Constraint: Any of an Interface ATC Constraint, an Interface Ramp Constraint, or a NYCA Ramp Constraint (individually and collectively).

External Interface Congestion: The product of:  (i) the portion of the Congestion Component of the LBMP at a Proxy Generator Bus that is associated with a Proxy Generator Bus Constraint and (ii) a factor, between zero and 1, calculated pursuant to ISO Procedures.

Proxy Generator Bus Border LBMP: The LBMP at a Proxy Generator Bus minus External Interface Congestion at that Proxy Generator Bus.

Unconstrained RTD LBMP:  The LBMP as calculated by RTD less any congestion associated with a Proxy Generator Bus Constraint.

17.1.6.2   General Rules

Transmission Customers and Customers with External Generators and Loads can bid into
the LBMP Market or participate in Bilateral Transactions.  Those with External Generators may
arrange LBMP Market sales and/or Bilateral Transactions with Internal or External Loads and
External Loads may arrange LBMP Market purchases and/or Bilateral Transactions with Internal
Generators.

The Generator and Load locations for which LBMPs will be calculated will initially be
limited to a pre-defined set of Proxy Generator Buses.  LBMPs will be calculated for each Proxy

Generator Bus within this limited set.  When an Interface with multiple Proxy Generator Buses is
constrained, the ISO will apply the constraint to all of the Proxy Generator Buses located at that
Interface. Except as set forth in Sections 17.1.6.3 and 17.1.6.4, the NYISO will calculate the
three components of LBMP for Transactions at a Proxy Generator Bus as provided in the  tables
below.

When determining the External Interface Congestion, if any, to apply to determine the LBMP for RTD intervals that bridge two RTC intervals, the NYISO shall use the External Interface Congestion associated with the second (later) RTC interval.

17.1.6.2.1 Pricing rules for Dynamically Scheduled Proxy Generator Buses

The pricing rules for Dynamically Scheduled Proxy Generator Buses are to be determined.

17.1.6.2.2 Pricing rules for Variably Scheduled Proxy Generator Buses

The pricing rules for Variably Scheduled Proxy Generator Buses are provided in the following table.

RuleProxy Generator Bus Constraint

No.affecting External Schedules at location a

1Unconstrained in RTC15, Rolling RTC and

RTD

2The Rolling RTC used to schedule External

Transactions in a given 15-minute interval is subject to a Proxy Generator Bus

Constraint

Direction of Proxy
Generator Bus

Constraint

N/A

Into NYCA or out of NYCA

(Import or Export)

Real-Time Pricing Rule
(for location a)

Real-Time LBMPa = RTD LBMPa

Real-Time LBMPa = RTD LBMPa + Rolling RTC External Interface Congestiona

17.1.6.2.3 Pricing rules for Proxy Generator Buses that are not Dynamically
Scheduled or Variably Scheduled

The pricing rules for Proxy Generator Buses that are not Dynamically Scheduled or Variably Scheduled Proxy Generator Buses are provided in the following table.

RuleProxy Generator Bus Constraint affecting

No.External Schedules at location a

1Unconstrained in RTC15, Rolling RTC and

RTD

3RTC15 is subject to a Proxy Generator Bus

Constraint

Direction of Proxy
Generator Bus

Constraint

N/A

Into NYCA or out of NYCA

(Import or Export)

Real-Time Pricing Rule
(for location a)

Real-Time LBMPa = RTD LBMPa

Real-Time LBMPa = RTD LBMPa +
RTC15 External Interface Congestiona

17.1.6.3   Rules for Non-Competitive Proxy Generator Buses and Associated
Interfaces

Real-Time LBMPs for an Interface that is associated with one or more Non-Competitive
Proxy Generator Buses or for a Non-Competitive Proxy Generator Bus shall be determined as
provided in the tables below.  Non-Competitive Proxy Generator Buses are identified in Section

4.4.4 of the Services Tariff.

17.1.6.3.1 Pricing rules for Non-Competitive, Dynamically Scheduled Proxy
Generator Buses

The pricing rules for Non-Competitive, Dynamically Scheduled Proxy Generator Buses are to be determined.

17.1.6.3.2 Pricing rules for Non-Competitive, Variably Scheduled Proxy Generator
Buses

The pricing rules for Non-Competitive, Variably Scheduled Proxy Generator Buses are provided in the following table.

RuleProxy Generator Bus Constraint

No.affecting External Schedules at location a

1Unconstrained in RTC15, Rolling RTC and

RTD

Direction of Proxy
Generator Bus

Constraint

N/A

Real-Time Pricing Rule
(for location a)

Real-Time LBMPa = RTD LBMPa

4The Rolling RTC used to schedule External

Transactions in a given 15-minute interval is subject to an Interface ATC or Interface RampConstraint

5The Rolling RTC used to schedule External

Transactions in a given 15-minute interval is subject to an Interface ATC or Interface Ramp Constraint

Into NYCAIf Rolling RTC Proxy Generator

(Import)Bus LBMPa > 0, then Real-Time

LBMPa = RTD LBMPa + Rolling RTC External Interface

Congestiona

Otherwise, Real-Time LBMPa =
Minimum of (i) RTD LBMPa and
(ii) zero

Out of NYCAIf Rolling RTC Proxy Generator

(Export)Bus LBMPa < 0, then Real-Time

LBMPa = RTD LBMPa + Rolling RTC External Interface

Congestiona

Otherwise, Real-Time LBMPa = RTD LBMPa

17.1.6.3.3 Pricing rules for Non-Competitive Proxy Generator Buses that are not
Dynamically Scheduled or Variably Scheduled Proxy Generator Buses

The pricing rules for Non-Competitive Proxy Generator Buses that are not Dynamically
Scheduled or Variably Scheduled Proxy Generator Buses are provided in the following table.

RuleProxy Generator Bus Constraint

No.affecting External Schedules at location a

1Unconstrained in RTC15, Rolling RTC and

RTD

6RTC15 is subject to an Interface ATC or

Interface Ramp Constraint

7RTC15 is subject to an Interface ATC or

Interface Ramp Constraint

Direction of Proxy
Generator Bus

Constraint

N/A

Into NYCA (Import)

Out of NYCA (Export)

Real-Time Pricing Rule
(for location a)

Real-Time LBMPa = RTD LBMPa

If RTC15 Proxy Generator Bus
LBMPa > 0, then Real-Time

LBMPa = RTD LBMPa + RTC15
External Interface Congestiona

Otherwise, Real-Time LBMPa =
Minimum of (i) RTD LBMPa and
(ii) zero

If RTC15 Proxy Generator Bus
LBMPa < 0, then Real-Time

LBMPa = RTD LBMPa + RTC15
External Interface Congestiona

Otherwise, Real-Time LBMPa = RTD LBMPa

17.1.6.4   Special Pricing Rules for Proxy Generator Buses Associated with
Designated Scheduled Lines

Real-Time LBMPs for the Proxy Generator Buses associated with designated Scheduled
Lines shall be determined as provided in the tables below.  The Proxy Generator Buses that are
associated with designated Scheduled Lines are identified in Section 4.4.4 of the Services Tariff.

17.1.6.4.1 Pricing rules for Dynamically Scheduled Proxy Generator Buses that are
associated with Designated Scheduled Lines

The pricing rules for Dynamically Scheduled Proxy Generator Buses that are associated with designated Scheduled Lines are to be determined.

17.1.6.4.2 Pricing rules for Variably Scheduled Proxy Generator Buses that are
associated with Designated Scheduled Lines

The pricing rules for Variably Scheduled Proxy Generator Buses that are associated with designated Scheduled Lines are provided in the following table.

RuleProxy Generator Bus Constraint affecting

No.External Schedules at location a

1Unconstrained in RTC15, Rolling RTC and

RTD

4The Rolling RTC used to schedule External

Transactions in a given 15-minute interval is subject to an Interface ATC Constraint

5The Rolling RTC used to schedule External

Transactions in a given 15-minute interval is subject to an Interface ATC Constraint

Direction of Proxy
Generator Bus

Constraint

N/A

Into NYCA (Import)

Out of NYCA (Export)

Real-Time Pricing Rule
(for location a)

Real-Time LBMPa = RTD LBMPa

If Rolling RTC Proxy Generator Bus LBMPa > 0, then Real-Time LBMPa = RTD LBMPa + Rolling RTC External Interface

Congestiona

Otherwise, Real-Time LBMPa =
Minimum of (i) RTD LBMPa and
(ii) zero

If Rolling RTC Proxy Generator Bus LBMPa < 0, then Real-Time LBMPa = RTD LBMPa + Rolling RTC External Interface

Congestiona

Otherwise, Real-Time LBMPa = RTD LBMPa )

17.1.6.4.3 Pricing rules for Proxy Generator Buses that are associated with

Designated Scheduled Lines that are not Dynamically Scheduled or Variably Scheduled Proxy Generator Buses

The pricing rules for Proxy Generator Buses that are associated with designated

Scheduled Lines that are not Dynamically Scheduled or Variably Scheduled Proxy Generator Buses, are provided in the following table.

RuleProxy Generator Bus Constraint affecting

No.External Schedules at location a

1Unconstrained in RTC15, Rolling RTC and

RTD

6RTC15 is subject to an Interface ATC

Constraint

Direction of Proxy
Generator Bus

Constraint

N/A

Into NYCA (Import)

Real-Time Pricing Rule
(for location a)

Real-Time LBMPa = RTD LBMPa

If RTC15 Proxy Generator Bus
LBMPa > 0, then Real-Time

LBMPa = RTD LBMPa + RTC15
External Interface Congestiona

Otherwise, Real-Time LBMPa =
Minimum of (i) RTD LBMPa and
(ii) zero

RuleProxy Generator Bus Constraint affecting

No.External Schedules at location a

7RTC15 is subject to an Interface ATC

Constraint

Direction of Proxy
Generator Bus

Constraint

Out of NYCA (Export)

Real-Time Pricing Rule
(for location a)

If RTC15 Proxy Generator Bus
LBMPa < 0, then Real-Time

LBMPa = RTD LBMPa + RTC15
External Interface Congestiona

Otherwise, Real-Time LBMPa = RTD LBMPa

17.1.6.5   Method of Calculating Marginal Loss and Congestion Components of

Real-Time LBMP at Non-Competitive Proxy Generator Buses and Proxy Generator Buses that are Subject to the Special Pricing Rule for
Designated Scheduled Lines

Under the conditions specified below, the Marginal Losses Component and the Congestion Component of the Real-Time LBMP, calculated pursuant to the preceding paragraphs in Sections 17.1.6.3 and 17.1.6.4, shall be constructed as follows:

When the Real-Time LBMP is set to zero and that zero price was not the result of using the RTD, RTC or SCUC-determined LBMP;

and

where:

=     The marginal Bid cost of providing Energy at the reference
Bus, as calculated by RTD for that 5-minute interval; and

=    The Marginal Losses Component of the LBMP as calculated by RTD  for that 5-minute interval at the NonCompetitive Proxy Generator Bus or Proxy Generator Bus associated with a designated Scheduled Line.

Attachment II

2.20Definitions - T

Tangible Net Worth: The value, determined by the ISO, of all of a Customer’s assets less both:

(i) the amount of the Customer’s liabilities and (ii) all of the Customer’s intangible assets,

including, but not limited to, patents, trademarks, franchises, intellectual property, and goodwill.

Testing Period: An ISO approved period of time during which a Generator is testing equipment
and during which unstable operation prevents the unit from accurately following its base points.

Third Party Transmission Wheeling Agreements ("Third Party TWAs"): A Transmission
Wheeling Agreement, as amended, between Transmission Owners or between a Transmission
Owner and an entity that is not a Transmission Owner.  Third Party TWAs are associated with
the purchase (or sale) of Energy, Capacity, and/or Ancillary Services for the benefit of an entity
that is not a Transmission Owner.  All Third Party TWAs are listed in Table 1 A of Attachment
L to the ISO OATT, and are designated in the “Treatment “column of Table 1A, as “Third Party
TWA.”

Total Transfer Capability ("TTC"): The amount of electric power that can be transferred over the interconnected transmission network in a reliable manner.

Trading Hub: A virtual location in a given Load Zone, modeled as a Generator bus and/or Load
bus, for scheduling Bilateral Transactions in which both the POI and POW are located within the
NYCA.

Trading Hub Energy Owner: A Customer who buys energy in a Bilateral Transaction in which the POW is a Trading Hub, or who sells energy in a Bilateral Transaction in which the POI is a
Trading Hub.

Transaction: The purchase and/or sale of Energy or Capacity, or the sale of Ancillary Services. A Transaction bid into the Energy market to sell or purchase Energy or to schedule a Bilateral Transaction includes a Point of Injection and a Point of Withdrawal.

Transfer Capability: The measure of the ability of interconnected electrical systems to reliably move or transfer power from one area to another over all transmission facilities (or paths)
between those areas under specified system conditions.

Transmission Congestion Contract Component (“TCC Component”): A component of the Operating Requirement, calculated in accordance with Section 26.4.2 of Attachment K to this Services Tariff.

Transmission Congestion Contracts ("TCCs"): The right to collect or obligation to pay Congestion Rents in the Day-Ahead Market for Energy associated with a single MW of
transmission between a specified POI and POW.  TCCs are financial instruments that enable Energy buyers and sellers to hedge fluctuations in the price of transmission.

Transmission Customer: Any entity (or its designated agent) that requests or receives
Transmission Service pursuant to a Service Agreement and the terms of the ISO OATT.

Transmission District: The geographic area in which a Transmission Owner, including LIPA, is obligated to serve Load, as well as the customers directly interconnected with the transmission facilities of the Power Authority of the State of New York.

Transmission Facilities Under ISO Operational Control: The transmission facilities of the Transmission Owners listed in Appendix A-1 of the ISO/TO Agreement (“Listing of
Transmission Facilities Under ISO Operational Control”) and listed in Appendix A-1 of an
Operating Agreement (“NTO Transmission Facilities Under ISO Operational Control”) that are subject to the Operational Control of the ISO.  This listing may be amended from time-to-time as specified in the ISO/TO Agreement and Operating Agreements.

Transmission Facilities Requiring ISO Notification: The transmission facilities of the

Transmission Owners listed in Appendix A-2 of the ISO/TO Agreement (“Listing of

Transmission Facilities Requiring ISO Notification”) and listed in Appendix A-2 of an Operating
Agreement (“NTO Transmission Facilities Requiring ISO Notification”) whose status of
operation must be provided to the ISO by the Transmission Owners (for the purposes stated in
the ISO Tariffs and in accordance with the ISO Tariffs, ISO/TO Agreement, and/or Operating
Agreements) prior to the Transmission Owners making operational changes to the state of these
facilities.  This listing may be amended from time-to-time as specified in the ISO/TO Agreement
and Operating Agreements.

Transmission Facility Agreement (“TFA”): Agreements governing the use of specific or

designated transmission facilities charges to cover all, or a portion, of the costs to install, own, operate, or maintain  transmission facilities, to the customer under the agreement and that have provisions to provide Transmission Service utilizing said transmission facilities.  All
Transmission Facility Agreements are listed in Attachment L. Table 1A, and are designated in the “Treatment” column as “Facility Agmt. - MWA.”

Transmission Fund ("T-Fund"): The mechanism used under the current NYPP Agreement to
compensate the Member Systems for providing Transmission Service for economy Energy
Transactions over their transmission systems.  Each Member System is allocated a share of the
economy Energy savings in dollars assigned to the fund that is based on the ratio of their
investment in transmission facilities to the sum of investments in transmission and generation
facilities.

Transmission Owner: The public utility or authority (or its designated agent) that owns

facilities used for the transmission of Energy in interstate commerce and provides Transmission Service under the Tariff.

Transmission Owner’s Monthly Transmission System Peak: The maximum hourly firm

usage as measured in megawatts (“MW”) of the Transmission Owner’s transmission system in a calendar month.

Transmission Reliability Margin (“TRM”): The amount of TTC reserved by the ISO to ensure the interconnected transmission network is secure under a reasonable range of uncertainties in system conditions.

Transmission Service: Point-To-Point Network Integration or Retail Access Transmission Service provided under the ISO OATT.

Transmission Service Charge (“TSC”): A charge designed to ensure recovery of the embedded cost of a transmission system owned by a Member System.

Transmission Shortage Cost: A series of quantity/price points that defines the maximum

pricing mechanism utilized in determining the Shadow Price of a particular transmission

Constraint that will be used in calculating LBMP in accordance with Section 17.1.4 of

Attachment B of this ISO Services Tariff.  The Transmission Shortage Costs are set at

$350/MWh for shortages above zero and less than or equal to 5MW, $2350/MWh for shortages
above 5MW and less than or equal to 20MW, and $4000/MWh for shortages above 20MW.

Transmission System: The facilities operated by the ISO that are used to provide Transmission Services under the ISO OATT.

Transmission Usage Charge (“TUC”): Payments made by the Transmission Customer to cover
the cost of Marginal Losses and, during periods of time when the transmission system is
constrained, the marginal cost of Congestion.  The TUC is equal to the product of:  (1) the
LBMP at the POW minus the LBMP at the POI (in $/MWh); and (2) the scheduled or delivered
Energy (in MWh).

Transmission Wheeling Agreement (“TWA”): The Agreements listed in Table 1A  of

Attachment L to the ISO OATT governing the use of specific or designated transmission

facilities that are owned, controlled or operated by an entity for the transmission of Energy in interstate commerce. TWAs between Transmission Owners have been modified such that all TWAs between Transmission Owners are now MWAs.

17.1LBMP Calculation

The Locational Based Marginal Prices (“LBMPs” or “prices”) for Suppliers and Loads in
the Real-Time Market will be based on the system marginal costs produced by the Real-Time
Dispatch (“RTD”) program and during intervals when certain conditions exist at Proxy
Generator Buses, the Real-Time Commitment (“RTC”) program.  LBMPs for Suppliers and
Loads in the Day-Ahead Market will be based on the system marginal costs produced by the
Security Constrained Unit Commitment (“SCUC”).  LBMPs calculated by SCUC and RTD will
incorporate the incremental dispatch costs of Resources that would be scheduled to meet an
increment of Load and, to the extent that tradeoffs exist between scheduling providers to produce
Energy or reduce demand, and scheduling them to provide Regulation Service or Operating
Reserves, LBMPs shall reflect the effect of meeting an increment of Load, given those tradeoffs,
at each location on the Bid Production Cost associated with those services.  As such, those
LBMPs may incorporate:  (i) Bids for Regulation Service or Operating Reserves; or (ii) shortage
costs associated with the inability to meet a Regulation Service or Operating Reserves
requirement under the Regulation Service Demand Curve set forth in Rate Schedule 3 of this
ISO Services Tariff and Operating Reserve Demand Curves and Scarcity Reserve Demand Curve
set forth in Rate Schedule 4 of this ISO Services Tariff.

Additionally, for the purpose of calculating Real-Time LBMPs when RTD is committing
and dispatching Resources meeting Minimum Generation Levels and capable of starting in ten
minutes pursuant to Section 4.4.2.4 of this ISO Services Tariff, RTD shall include in the
incremental dispatch cost of each such Resource a start-up cost based on the Start-Up Bid of
each such Resource and shall assume for each such Resource a zero downward response rate.

17.1.1LBMP Bus Calculation Method

System marginal costs will be utilized in an ex ante computation to produce DayAhead and Real-Time LBMP bus prices using the following equations.
The LBMP at bus i can be written as:

Where:

=LBMP at bus i in $/MWh

=the system marginal price at the Reference Bus

=      Marginal Losses Component of the LBMP at bus i which is the marginal
cost of losses at bus i relative to the Reference Bus

=      Congestion Component of the LBMP at bus i which is the marginal cost of
Congestion at bus i relative to the Reference Bus

The Marginal Losses Component of the LBMP at any bus i is calculated using the equation:

Where:

=      delivery factor for bus i to the system Reference Bus and:

Where:

L=      NYCA losses; and

=      injection at bus i

The Congestion Component of the LBMP at bus i is calculated using the equation:

Where:

K=        the set of Constraints;

=       Shift Factor for bus i on Constraint k in the pre- or post-

Contingency case which limits flows across that Constraint (the Shift

Factor measures the incremental change in flow on Constraint k, expressed in per unit, for an increment of injection at bus i and a corresponding
withdrawal at the Reference Bus); and

=the Shadow Price of Constraint k expressed in $/MWh, provided however,

this Shadow Price shall not exceed the Transmission Shortage Cost.

Substituting the equations forandinto the first equation yields:

LBMPs will be calculated for the Day-Ahead and the Real-Time Markets.  In the DayAhead Market, the three components of the LBMP at each location will be calculated from the SCUC results and posted for each of the twenty four (24) hours of the next day.  The Real-Time LBMPs will be calculated and posted for each execution of RTD.

17.1.1.1   Determining Shift Factors and Incremental System Losses

For the purposes of pricing and scheduling, Shift Factors, GFik, and loss delivery factors,
DFi, will reflect expected power flows, including expected unscheduled power flows.  When
determining prices and schedules, SCUC, RTC and RTD shall include both the expected power
flows resulting from NYISO interchange schedules (see Section 17.1.1.1.2), and expected
unscheduled power flows (see Section 17.1.1.1.1).  All NYCA Resource, NYCA Load and Proxy
Generator Bus Shift Factors and loss delivery factors will incorporate internal and coordinated

external transmission facility outages, power flows due to schedules, and expected unscheduled power flows.

17.1.1.1.1 Determining Expected Unscheduled Power Flows

In the Day-Ahead Market, expected unscheduled power flows will ordinarily be

determined based on historical, rolling 30-day on-peak and off-peak averages.  To ensure

expected unscheduled power flows accurately reflect anticipated conditions, the frequency

and/or period used to determine the historical average may be modified by the NYISO to address market rule, system topology, operational, or other changes that would be expected to
significantly impact unscheduled power flows.  The NYISO will publicly post the Day-Ahead on-peak and off-peak unscheduled power flows on its web site.

In the Real-Time Market, expected unscheduled power flows will ordinarily be

determined based on current power flows, modified to reflect expected changes over the realtime scheduling horizon.

17.1.1.1.2 Determining Expected Power Flows Resulting from NYISO Interchange
Schedules

In the Day-Ahead Market, for purposes of scheduling and pricing, SCUC will establish expected power flows for the ABC interface, JK interface and Branchburg-Ramapo
interconnection based on the following:

a.Consolidated Edison Company of New York’s Day-Ahead Market hourly election

under OATT Attachment CC, Schedule C;

b. The percentage of PJM-NYISO scheduled interchange that is expected to flow

over the Branchburg-Ramapo interconnection.  The expected flow may also be adjusted by a MW offset to reflect expected operational conditions;

c.The percentage of PJM-NYISO scheduled interchange (if any) that is expected to

flow over the ABC interface; and

d.The percentage of PJM-NYISO scheduled interchange (if any) that is expected to

flow over the JK interface.

The terms “ABC interface” and “JK interface” have the meaning ascribed to them in Schedule C to Attachment CC to the OATT.

The NYISO shall post the percentage values it is currently using to establish Day-Ahead
and real-time expected Branchburg-Ramapo interconnection, ABC interface and JK interface
flows for purposes of scheduling and pricing on its web site.  If the NYISO determines it is
necessary to change the posted Branchburg-Ramapo, ABC or JK percentage values, it will
provide notice to its Market Participants as far in advance of the change as is practicable under
the circumstances.

In the Day-Ahead Market, scheduled interchange that is not expected to flow over the ABC interface, JK interface or Branchburg-Ramapo interconnection (or on Scheduled Lines) will be expected to flow over the NYISO’s other interconnections.  Expected flows over the NYISO’s other interconnections will be determined consistent with the expected impacts of scheduled interchange and consistent with shift factors and delivery factors calculated in
accordance with Section 17.1.1.1, above.

For pricing purposes, flows in the Real-Time Market will be established for the ABC
interface, JK interface, and Branchburg-Ramapo interconnection based on the current flow,
modified to reflect the expected incremental impacts of changes to interchange schedules over
the forward scheduling horizon in a manner that is consistent with the method used to establish
Day-Ahead power flows over these facilities.  Expected flows over the NYISO’s other

interconnections will be determined based on the current flow, modified to reflect the expected incremental impacts of changes to interchange schedules over the forward scheduling horizon, and shall be consistent with shift factors and delivery factors calculated in accordance with
Section 17.1.1.1, above.

17.1.1.1.3 Scheduled Lines and Chateauguay Interconnection with Hydro Quebec

For purposes of scheduling and pricing, the NYISO expects that power flows will

ordinarily match the interchange schedule at Scheduled Lines, and at the NYCA’s Chateauguay interconnection with Hydro Quebec, in both the Day-Ahead and Real-Time Markets.

17.1.2 Real-Time LBMP Calculation Procedures

For each RTD interval, the ISO shall use the procedures described below in Sections

17.1.2.1-17.1.2.1.4 to calculate Real-Time LBMPs at each Load Zone and Generator bus.  The LBMP bus and zonal calculation procedures are described in Sections 17.1.1 and 17.1.5 of this Attachment B, respectively.  Procedures governing the calculation of LBMPs at Proxy Generator Buses are set forth below in Section 17.1.6 of this Attachment B.

17.1.2.1   General Procedures

17.1.2.1.1 Overview

The ISO shall calculate Real-Time Market LBMPs using the three passes of each RTD
run, except as noted below in Section 17.1.2.1.3.  A new RTD run will initialize every five
minutes and each run will produce prices and schedules for five points in time (the optimization
period).  Only the prices and schedules determined for the first time point of the optimization
period will be binding.  Prices and schedules for the other four time points of the optimization
period are advisory.

Each RTD run shall, depending on when it occurs during the hour, have a bid

optimization horizon of fifty, fifty-five, or sixty minutes beyond the first, or binding, point in
time that it addresses.  The posting time and the first time point in each RTD run, which
establishes binding prices and schedules, will be five minutes apart.  The remaining points in
time in each optimization period can be either five, ten, or fifteen minutes apart depending on
when the run begins within the hour.  The points in time in each RTD optimization period are
arranged so that they parallel as closely as possible RTC’s fifteen minute evaluations.
For example, the RTD run that posts its results at the beginning of an hour (“RTD0”) will initialize at the fifty-fifth minute of the previous hour and produce schedules and prices over a fifty-five minute optimization period.  RTD0 will produce binding prices and schedules for the RTD interval beginning when it posts its results (i.e., at the beginning of the hour) and ending at the first time point in its optimization period (i.e., five minutes after the hour).  It will produce advisory prices and schedules for its second time point, which is ten minutes after the first time point in its optimization period, and advisory prices and schedules for its third, fourth and fifth time points, each of which would be fifteen minutes apart.  The RTD run that posts its results at five minutes after the beginning of the hour (“RTD5”) will initialize at the beginning of the hour and produce prices over a fifty minute optimization period.  RTD5 will produce binding prices and schedules for the RTD interval beginning when it posts its results (i.e., at five minutes after the hour) and ending at the first time point in its optimization period (i.e., ten minutes after the hour.)  It will produce advisory prices and schedules for its second time point (which is five minutes after the first time point), and advisory prices and schedules for its third, fourth and fifth time points, each of which would be fifteen minutes apart.  The RTD run that posts its results at ten minutes after the beginning of the hour (“RTD10”) will initialize at five minutes after the

beginning of the hour and produce prices over a sixty minute optimization period.  RTD10 will
produce binding prices and schedules for the interval beginning when it posts its results (i.e., at
ten minutes after the hour) and ending at the first time point in its optimization period (i.e.,
fifteen minutes after the hour.)  It will produce advisory prices and schedules for its second,
third, fourth and fifth time points, each of which would be fifteen minutes after the preceding
time point.

17.1.2.1.2 Description of the Real-Time Dispatch Process

17.1.2.1.2.1The First Pass

The first RTD pass consists of a least bid cost, multi-period co-optimized dispatch for
Energy, Regulation Service and Operating Reserves that treats all Fixed Block Units that are
committed by RTC, or are otherwise instructed to be online or remain online by the ISO as if
they were blocked on at their UOLN or UOLE, whichever is applicable.  Resources meeting
Minimum Generation Levels and capable of being started in ten minutes that have not been
committed by RTC are treated as flexible (i.e. able to be dispatched anywhere between zero (0)
MW and their UOLN or UOLE, whichever is applicable).  The first pass establishes “physical
base points” (i.e., real-time Energy schedules) and real-time schedules for Regulation Service
and Operating Reserves for the first time point of the optimization period.  Physical base points
and schedules established for the first time point shall be binding and shall remain in effect until
the results of the next run are posted.  Physical base points and schedules established for all
subsequent time points shall be advisory.  The first pass also produces information that is used to
calculate the RTD Base Point Signals that the ISO sends to Suppliers.

When establishing physical base points, the ISO shall assume that each Generator will move toward the physical base point established during the first pass of the prior RTD run at its specified response rate.

17.1.2.1.2.1.1 Upper and Lower Dispatch Limits for Dispatchable Resources Other
Than Intermittent Power Resources That Depend on Wind as Their Fuel

When setting physical base points for a Dispatchable Resource at the first time point, the
ISO shall ensure that they do not fall outside of the bounds established by the Dispatchable
Resource’s lower and upper dispatch limits.  A Dispatchable Resource’s dispatch limits shall be
determined based on whether it was feasible for it to reach the physical base point calculated by
the last RTD run given its: (A) metered output level at the time that the RTD run was initialized;

(B) response rate; (C) minimum generation level; and (D) UOLN or UOLE, whichever is

applicable.  If it was feasible for the Dispatchable Resource to reach that base point, then its

upper and lower dispatch limits shall reflect the highest and lowest output levels it could achieve over the next RTD interval, given its UOLN or UOLE, as applicable, and starting from its
previous base point.  If it was not feasible for the Dispatchable Resource to reach that base point, then its upper and lower dispatch limits shall reflect the highest and lowest output levels it could achieve over the next RTD interval, given its UOLN or UOLE, as applicable, but instead starting from the feasible output level closest to its previous base point.

When setting physical base points for a Dispatchable Resource at later time points, the ISO shall ensure that they do not fall outside of the bounds established by the Resource’s lower and upper dispatch limits for that time point.  A Resource’s dispatch limits at later time points shall be based on its: (A) dispatch limits from the first time point; (B) response rate; (C)
minimum generation; and (D) UOLN or UOLE, whichever is applicable.

The upper dispatch limit for a Dispatchable Resource at later time points shall be

determined by increasing the upper dispatch limit from the first time point at the Resource’s

response rate, up to its UOLN or UOLE, whichever is applicable.  The lower dispatch limit for a Dispatchable Resource at later time points shall be determined by decreasing the lower dispatch limit from the first time point at the Resource’s response rate, down to its minimum generation level or to a Demand Side Resource’s Demand Reduction level.

The RTD Base Point Signals sent to Dispatchable Resources shall be the same as the physical base points determined above.

17.1.2.1.2.1.2 Upper and Lower Dispatch Limits for Intermittent Power Resources
That Depend on Wind as Their Fuel

For all time points of the optimization period, the Lower Dispatch Limit shall be zero and the Upper Dispatch Limit shall be the Wind Energy Forecast for that Resource.  For Intermittent Power Resources depending on wind as their fuel in commercial operation as of January 1, 2002 with a name plate capacity of 12 MWs or fewer, the Upper and Lower Dispatch Limits shall be the output level specified by the Wind Energy Forecast.

17.1.2.1.2.1.3. Setting Physical Basepoints for Fixed Generators

When setting physical base points for Self-Committed Fixed Generators in any time point, the ISO shall consider the feasibility of the Resource reaching the output levels that it specified in its self-commitment request for each time point in the RTD run given: (A) its metered output at the time that the run was initialized; and (B) its response rate.

When setting physical base points for ISO-Committed Fixed Generators in any time

point, the ISO shall consider the feasibility of the Resource reaching the output levels scheduled

for it by RTC for each time point in the RTD run given: (A) its metered output at the time that the run was initialized; and (B) its response rate.

The RTD Base Point Signals sent to Self-Committed Fixed Generators shall follow the quarter hour operating schedules that those Generators submitted in their real-time self-
commitment requests

The RTD Base Point Signals sent to ISO-Committed Fixed Generators shall follow the
quarter hour operating schedules established for those Generators by RTC, regardless of their
actual performance.  To the extent possible, the ISO shall honor the response rates specified by
such Generators when establishing RTD Base Point Signals.  If a Self-Committed Fixed
Generator’s operating schedule is not feasible based on its real-time self-commitment requests
then its RTD Base Point Signals shall be determined using a response rate consistent with the
operating schedule changes.

17.1.2.1.2.2    The Second Pass

The second RTD pass consists of a least bid cost, multi-period, co-optimized dispatch for
Energy, Regulation Service, and Operating Reserves that treats all Fixed Block Units that are
committed by RTC, all Resources meeting Minimum Generation Levels and capable of starting
in ten minutes that have not been committed by RTC and all units otherwise instructed to be
online or remain online by the ISO, as flexible (i.e., able to be dispatched anywhere between zero

(0) MW and their UOLN or UOLE, whichever is applicable), regardless of their minimum run-
time status.  The second pass calculates real-time Energy prices and real-time Shadow Prices for
Regulation Service and Operating Reserves that the ISO shall use for settlement purposes
pursuant to Article 4, Rate Schedule 15.3, and Rate Schedule 15.4 of this ISO Services Tariff

respectively.  The ISO will not use schedules for Energy, Regulation Service and Operating Reserves established in the second pass to dispatch Resources.

The upper and lower dispatch limits used for ISO-Committed Fixed and Self-Committed Fixed Resources shall be the same as the physical base points calculated in the first pass.

17.1.2.1.2.2.1 Upper and Lower Dispatch Limits for Dispatchable Resources Other
Than Intermittent Power Resources That Depend on Wind as Their Fuel

The upper dispatch limit for the first time point of the second pass for a Dispatchable

Resource shall be the higher of: (A) its upper dispatch limit from the first pass; or (B) its “pricing
base point” from the first time point of the prior RTD interval adjusted up within its Dispatchable
range for any possible ramping since that pricing base point was issued less the higher of: (i) the
physical base point established during the first pass of the RTD immediately prior to the previous
RTD minus the Resource’s metered output level at the time that the current RTD run was
initialized, or (ii) zero.

The lower dispatch limit for the first time point of the second pass for a Dispatchable

Resource shall be the lower of: (A) its lower dispatch limit from the first pass; or (B) its “pricing base point” from the first time point of the prior RTD interval adjusted down within its
Dispatchable range to account for any possible ramping since that pricing base point was issued plus the higher of: (i) the Resource’s metered output level at the time that the current RTD run was initialized minus the physical base point established during the first pass of the RTD
immediately prior to the previous RTD; or (ii) zero.

The upper dispatch limit for the later time points of the second pass for a Dispatchable
Resource shall be determined by increasing its upper dispatch limit from the first time point at
the Resource’s response rate, up to its UOLN or UOLE, whichever is applicable.  The lower
dispatch limit for the later time points of the second pass for such a Resource shall be determined

by decreasing its lower dispatch limit from the first time point at the Resource’s response rate, down to its minimum generation level.

17.1.2.1.2.2.2 Upper and Lower Dispatch Limits for Intermittent Power Resources
That Depend on Wind as Their Fuel

For the first time point and later time points for Intermittent Power Resources that depend
on wind as their fuel, the Lower Dispatch Limit shall be zero and the Upper Dispatch Limit shall
be the Wind Energy Forecast for that Resource.  For Intermittent Power Resources depending on
wind as their fuel in commercial operation as of January 1, 2002 with a name plate capacity of

12 MWs or fewer, the Upper and Lower Dispatch Limits shall be the output level specified by the Wind Energy Forecast.

17.1.2.1.2.3The Third Pass

The third RTD pass is reserved for future use.

17.1.2.1.3 Variations in RTD-CAM

When the ISO activates RTD-CAM, the following variations to the rules specified above in Sections 17.1.2.1.1 and 17.1.2.1.2 shall apply.

First, if the ISO enters reserve pickup mode: (i) the ISO will produce prices and

schedules for a single ten minute interval  (not for a multi-point co-optimization period); (ii) the ISO shall set Regulation Service schedules to zero as described in Rate Schedule 15.3 of this ISO Services Tariff; (iii) the ISO will have discretion to make additional Generator commitments before executing the three RTD passes; and (iv) the ISO will have discretion to allow the RTD Base Point Signal of each Dispatchable Generator to be set to the higher of the Generator’s
physical base point or its actual generation level.

Second, if the ISO enters maximum generation pickup mode: (i) the ISO will produce

prices and schedules for a single five minute interval (not for a multi-point co-optimization

period); (ii) the ISO shall set Regulation Service schedules to zero as described in Rate Schedule

15.3 of this ISO Services Tariff; (iii) the ISO will have discretion to make additional Generator
commitments in the affected area before executing the three RTD passes; and (iv) the ISO will
have discretion to either move the RTD Base Point Signal of each Generator within the affected
area towards its UOLE at its emergency response rate or set it at a level equal to its physical base
point.

Third, if the ISO enters basepoints ASAP - no commitments mode it will produce prices and schedules for a single five minute interval (not for a multi-point co-optimization period).
Fourth, if the ISO enters basepoints ASAP - commit as needed mode: (i) the ISO will produce price and schedules for a single five minute interval (not for a multi-point co-
optimization period); and (ii) the ISO may make additional commitments of Generators that are capable of starting within ten minutes before executing the three RTD passes.
Fifth, and finally, if the ISO enters re-sequencing mode it will solve for a ten-minute optimization period consisting of two five-minute time points.

17.1.2.1.4 The Real-Time Commitment (“RTC”) Process and Automated Mitigation

Attachment H of this Services Tariff shall establish automated market power mitigation
measures that may affect the calculation of Real-Time LBMPs.  To the extent that these
measures are implemented they shall be incorporated into the RTC software through the
establishment of a second, parallel, commitment evaluation that will assess the impact of the
mitigation measures.  The first evaluation, referred to as the “RTC evaluation,” will determine
the schedules and prices that would result using an original set of offers and Bids before any

additional mitigation measures, the necessity for which will be considered in the RTC

evaluation, are applied.  The second evaluation, referred to as the “RT-AMP” evaluation, will

determine the schedules and prices that would result from using the original set of offers and bids
as modified by any necessary mitigation measures.  Both evaluations will follow the rules
governing RTC’s operation that are set forth in Article 4 and this Attachment B to this ISO
Services Tariff.

In situations where Attachment H specifies that real-time automated mitigation measures
be utilized, the ISO will perform the two parallel RTC evaluations in a manner that enables it to
implement mitigation measures one RTC run (i.e., fifteen minutes) in the future.  For example,
RTC15 and RT-AMP15 will perform Resource commitment evaluations simultaneously.  RT-
AMP15 will then apply the mitigation “impact” test, account for reference bid levels as
appropriate and determine which Resources are actually to be mitigated.  This information will
then be conveyed to RTC30 which will make Resource commitments consistent with the
application of the mitigation measures (and will thus indirectly be incorporated into future RTD
runs).

17.1.3 Day-Ahead LBMP Calculation Procedures

LBMPs in the Day-Ahead Market are calculated using five passes.  The first two passes
are commitment and dispatch passes; the last three are dispatch only passes.
Pass 1 consists of a least cost commitment and dispatch to meet Bid Load and reliable operation of the NYS Power System that includes Day-Ahead Reliability Units.
It consists of several steps.  Step 1A is a complete Security Constrained Unit
Commitment (“SCUC”) to meet Bid Load.  At the end of this step, committed Fixed Block
Units, Imports, Exports, Virtual Supply, Virtual Load, Demand Side Resources and non-Fixed

Block Units are dispatched to meet Bid Load with Fixed Block Units treated as dispatchable on a
flexible basis.  For mitigation purposes, LBMPs are calculated from this dispatch.  Following
Step 1A, SCUC tests for automated mitigation procedure (“AMP”) activation.
If AMP is activated, Step 1B tests to determine if the AMP will be triggered by
mitigating offer prices subject to mitigation that exceed the conduct threshold to their respective
reference prices.  These mitigated offer prices together with all originally submitted offer prices
not subject to automatic mitigation are then used to commit generation and dispatch energy to
meet Bid Load.  This step is another iteration of the SCUC process.  At the end of Step 1B,
committed Fixed Block Units, Imports, Exports, Virtual Supply, Virtual Load, Demand Side
Resources, and non-Fixed Block Units are again dispatched to meet Bid Load using the same
mitigated or unmitigated Bids used to determine the commitment to meet Bid Load, with Fixed
Block Units treated as dispatchable on a flexible basis.  For mitigation purposes, LBMPs are
again calculated from this dispatch.  The LBMPs determined at the end of Step 1B are compared
to the LBMPs determined at the end of Step 1A to determine the hours and zones in which the
impact test is met.

In Step 1C, generation offer prices subject to mitigation that exceed the conduct threshold
are mitigated for those hours and zones in which the impact test was met in Step 1B.  The
mitigated offer prices, together with the original unmitigated offer price of units whose offer
prices were not subject to mitigation, or did not trigger the conduct or impact thresholds, are used
to commit generation and dispatch energy to meet Bid Load.  This step is also a complete
iteration of the SCUC process.  At the end of Step 1C, committed Fixed Block Units, Imports,
Exports, virtual supply, virtual load, Demand Side Resources, and non-Fixed Block Units are

again dispatched to meet Bid Load, with Fixed Block Units treated as dispatchable on a flexible basis.  For mitigation purposes, LBMPs are again calculated from this dispatch.
All Demand Side Resources and non-Fixed Block Units committed in the final step of Pass 1 (which could be either step 1A, 1B, or 1C depending on activation of and the AMP) are blocked on at least to minimum load in Passes 4 through 6.  The resources required to meet local system reliability are determined in Pass 1.

Pass 2 consists of a least cost commitment and dispatch of Fixed Block Units, Imports,

Exports, Demand Side Resources and non-Fixed Block Units to meet forecast Load requirements
in excess of Bid Load, considering the Wind Energy Forecast, that minimizes the cost of
incremental Minimum Generation and Start Up Bids, given revenues for Minimum Generation
Energy based on LBMPs calculated in Pass 1, and assumes all Fixed Block Units are
dispatchable on a flexible basis.  Incremental Import Capacity needed to meet forecast Load
requirements is determined in Pass 2.  Fixed Block Units committed in this pass are not included
in the least cost dispatches of Passes 5 or 6.  Demand Side Resources and non-Fixed Block Units
committed in this step are blocked on at least to minimum Load in Passes 4 through 6.
Intermittent Power Resources that depend on wind as their fuel committed in this pass as a result
of the consideration of the Wind Energy Forecast are not blocked in Passes 5 or 6.
Pass 3 is reserved for future use.

Pass 4 consists of a least cost dispatch to forecast Load.  It is not used to set schedules or
prices.  It is used for operational purposes and provides a dispatch of Fixed Block Units, Imports,
Exports, Demand Side Resources and non-Fixed Block Units committed in Passes 1 or 2.
Incremental Import Capacity committed in Pass 2 is re-evaluated and may be reduced if no
longer required.

Pass 5 consists of a least cost dispatch of Fixed Block Units, Imports, Exports, Virtual
Supply, Virtual Load, Demand Side Resources and non-Fixed Block Units committed to meet Bid Load, based where appropriate on offer prices as mitigated in Pass 1.  Fixed Block Units are treated as dispatchable on a flexible basis.  LBMPs used to settle the Day-Ahead Market are
calculated from this dispatch.  The Shadow Prices used to compute Day-Ahead Market clearing prices for Regulation Service and for Operating Reserves in Rate Schedules 3 and 4 of this ISO Services Tariff are also calculated from this dispatch.  Final schedules for all Imports, Exports, Virtual Supply, Virtual Load, Demand Side Resources and non-Fixed Block Units in the DayAhead Market are calculated from this dispatch.

Pass 6 consists of a least cost dispatch of all Day-Ahead committed Resources, Imports, Exports, Virtual Supply, Virtual Load, based where appropriate on offer prices as mitigated in Pass 1, with the schedules of all Fixed Block Units committed in the final step of Pass 1 blocked on at maximum Capacity.  Final schedules for Fixed Block Units in the Day-Ahead Market are calculated from this dispatch.

17.1.4 Determination of Transmission Shortage Cost

The Transmission Shortage Costs represent the limits on system costs associated with
efficient dispatch to meet a particular Constraint.  It is the maximum Shadow Price that will be
used in calculating LBMPs under various levels of relaxationThe applicable Transmission
Shortage Cost depends on whether a particular transmission Constraint is associated with a
transmission facility or Interface that includes a non-zero constraint reliability margin value.  The
ISO shall establish constraint reliability margin values for transmission facilities and Interfaces.
Non-zero constraint reliability margin values established by the ISO shall be equal to or greater
than 20 MW.

For transmission facilities and Interfaces with a non-zero constraint reliability margin
value, SCUC, RTC and RTD shall include consideration of a two step demand curve consisting
of up to an additional 5 MW of available resource capacity at a cost of $350/MWh and up to an
additional 15 MW of available resource capacity at a cost of $1,175/MWh when evaluating
transmission Constraints associated with such facilities and Interfaces.  In no event, however,
shall the Shadow Price for such transmission Constraints exceed $4,000/MWh.
For transmission facilities and Interfaces with a constraint reliability margin value of zero, the Shadow Price for transmission Constraints associated with such facilities and Interfaces shall not exceed $4,000/MWh.  SCUC, RTC and RTD shall not include consideration of the available resource capacity provided by the two step demand curve described above for such transmission Constraints.

In evaluating all transmission Constraints, the ISO will determine whether sufficient

available resource capacity exists to solve each transmission Constraint at its applicable limit.  If
sufficient available resource capacity does not exist to solve the transmission Constraint at its
otherwise applicable limit, the ISO shall increase the applicable limit for such transmission
Constraint to an amount achievable by the available resource capacity plus 0.2 MW.  For
transmission facilities and Interfaces with a non-zero constraint reliability margin value, the ISO
shall account for the 20 MW of available resource capacity from the two step demand curve
described above in determining: (i) whether sufficient available resource capacity exists to solve
transmission Constraints associated with such facilities and Interfaces at their otherwise
applicable limit; and (ii) the extent of any limit adjustment required to solve such transmission
Constraints.

The ISO may periodically evaluate the Transmission Shortage Costs to determine

whether it is necessary to modify the Transmission Shortage Costs to avoid future operational or
reliability problems.  The ISO will consult with its Market Monitoring Unit after it conducts this
evaluation.  If the ISO determines that it is necessary to modify the Transmission Shortage Costs
in order to avoid future operational or reliability problems the resolution of which would
otherwise require recurring operator intervention outside normal market scheduling procedures,
in order to avoid among other reliability issues, a violation of NERC Interconnection Reliability
Operating Limits or System Operating Limits, it may temporarily modify it for a period of up to
ninety days, provided however the NYISO shall file such change with the Commission pursuant
to Section 205 of the Federal Power Act within 45 days of such modification.  If circumstances
reasonably allow, the ISO will consult with its Market Monitoring Unit, the Business Issues
Committee, the Commission, and the PSC before implementing any such modification.  In all
circumstances, the ISO will: (i) consult with those entities as soon as reasonably possible after
implementing a temporary modification and shall explain the reasons for the change; and (ii)
notify Market Participants of any temporary modification.

The responsibilities of the ISO and the Market Monitoring Unit in evaluating and modifying the Transmission Shortage Costs, as necessary are addressed in Attachment O, Section 30.4.6.8.1 of this Market Services Tariff (“Market Monitoring Plan”).

17.1.5Zonal LBMP Calculation Method

The computation described in Section 17.1.1 of this Attachment B is at the bus level.  An
eleven (11) zone model will be used for the LBMP billing related to Loads.  The LBMP for a
zone will be a Load weighted average of the Load bus LBMPs in the Load Zone.  The Load
weights which will sum to unity will be calculated from the load bus MW distribution.  Each

component of the LBMP for a zone will be calculated as a Load weighted average of the Load bus LBMP components in the zone.  The LBMP for a zone j can be written as:

where:

=LBMP for zone j,

is the Marginal Losses Component of the LBMP for zone j;

is the Congestion Component of the LBMP for zone j;

n =number of Load buses in zone j for which LBMPs are

calculated; and

Load weighting factor for bus i.

The NYISO also calculates and posts zonal LBMP for four (4) external zones for

informational purposes only.  Settlements for External Transactions are determined using the
Proxy Generator Bus LBMP. Each external zonal LBMP is equal to the LBMP of the Proxy
Generator Bus associated with that external zone.  The table below identifies which Proxy
Generator Bus LBMP is used to determine each of the posted external zonal LBMPs.

ExternalExternal Zone

ZonePTID

HQ61844

NPX61845

OH61846
PJM 61847

Proxy Generator Bus

HQ_GEN_WHEEL

N.E._GEN_SANDY_POND O.H._GEN_BRUCE

PJM_GEN_KEYSTONE

Proxy Generator
Bus PTID

23651

24062

24063

24065

Consistent with the ISO Services Tariff, LBMPs at Proxy Generator Buses are determined using calculated bus prices as described in this Section 17.1.

17.1.6Real Time LBMP Calculation Methods for Proxy Generator Buses, Non-

Competitive Proxy Generator Buses and Proxy Generator Buses Associated with Designated Scheduled Lines

17.1.6.1   Definitions

Interface ATC Constraint:  An Interface ATC Constraint exists when proposed economic

transactions over an Interface between the NYCA and the Control Area with which one or more Proxy Generator Bus(es) are associated would exceed the transfer capability for the Interface or for an associated Proxy Generator Bus.

Interface Ramp Constraint:  An Interface Ramp Constraint exists when proposed interchange schedule changes pertaining to an Interface between the NYCA and the Control Area with which one or more Proxy Generator Bus(es) are associated would exceed any Ramp Capacity limit imposed by the ISO for the Interface or for an associated Proxy Generator Bus.

NYCA Ramp Constraint: A NYCA Ramp Constraint exists when proposed interchange

schedule changes pertaining to the NYCA as a whole would exceed any Ramp Capacity limits in place for the NYCA as a whole.

Proxy Generator Bus Constraint: Any of an Interface ATC Constraint, an Interface Ramp Constraint, or a NYCA Ramp Constraint (individually and collectively).

External Interface Congestion: The product of:  (i) the portion of the Congestion Component of the LBMP at a Proxy Generator Bus that is associated with a Proxy Generator Bus Constraint and (ii) a factor, between zero and 1, calculated pursuant to ISO Procedures.

Proxy Generator Bus Border LBMP: The LBMP at a Proxy Generator Bus minus External Interface Congestion at that Proxy Generator Bus.

Unconstrained RTD LBMP:  The LBMP as calculated by RTD less any congestion associated with a Proxy Generator Bus Constraint.

17.1.6.2   General Rules

Transmission Customers and Customers with External Generators and Loads can bid into
the LBMP Market or participate in Bilateral Transactions.  Those with External Generators may
arrange LBMP Market sales and/or Bilateral Transactions with Internal or External Loads and
External Loads may arrange LBMP Market purchases and/or Bilateral Transactions with Internal
Generators.

The Generator and Load locations for which LBMPs will be calculated will initially be
limited to a pre-defined set of Proxy Generator Buses.  LBMPs will be calculated for each Proxy

Generator Bus within this limited set.  When an Interface with multiple Proxy Generator Buses is
constrained, the ISO will apply the constraint to all of the Proxy Generator Buses located at that
Interface. Except as set forth in Sections 17.1.6.3 and 17.1.6.4, the NYISO will calculate the
three components of LBMP for Transactions at a Proxy Generator Bus as provided in the  tables
below.

When determining the External Interface Congestion, if any, to apply to determine the LBMP for RTD intervals that bridge two RTC intervals, the NYISO shall use the External Interface Congestion associated with the second (later) RTC interval.

17.1.6.2.1 Pricing rules for Dynamically Scheduled Proxy Generator Buses

The pricing rules for Dynamically Scheduled Proxy Generator Buses are to be determined.

17.1.6.2.2 Pricing rules for Variably Scheduled Proxy Generator Buses

The pricing rules for Variably Scheduled Proxy Generator Buses are provided in the following table.

RuleProxy Generator Bus Constraint

No.affecting External Schedules at location a

1Unconstrained in RTC15, Rolling RTC and

RTD

2The Rolling RTC used to schedule External

Transactions in a given 15-minute interval is subject to a Proxy Generator Bus

Constraint

Direction of Proxy
Generator Bus

Constraint

N/A

Into NYCA or out of NYCA

(Import or Export)

Real-Time Pricing Rule
(for location a)

Real-Time LBMPa = RTD LBMPa

Real-Time LBMPa = RTD LBMPa + Rolling RTC External Interface Congestiona

17.1.6.2.3 Pricing rules for Proxy Generator Buses that are not Dynamically
Scheduled or Variably Scheduled

The pricing rules for Proxy Generator Buses that are not Dynamically Scheduled or Variably Scheduled Proxy Generator Buses are provided in the following table.

RuleProxy Generator Bus Constraint affecting

No.External Schedules at location a

1Unconstrained in RTC15, Rolling RTC and

RTD

3RTC15 is subject to a Proxy Generator Bus

Constraint

Direction of Proxy
Generator Bus

Constraint

N/A

Into NYCA or out of NYCA

(Import or Export)

Real-Time Pricing Rule
(for location a)

Real-Time LBMPa = RTD LBMPa

Real-Time LBMPa = RTD LBMPa +
RTC15 External Interface Congestiona

17.1.6.3   Rules for Non-Competitive Proxy Generator Buses and Associated
Interfaces

Real-Time LBMPs for an Interface that is associated with one or more Non-Competitive
Proxy Generator Buses or for a Non-Competitive Proxy Generator Bus shall be determined as
provided in the tables below.  Non-Competitive Proxy Generator Buses are identified in Section

4.4.4 of the Services Tariff.

17.1.6.3.1 Pricing rules for Non-Competitive, Dynamically Scheduled Proxy
Generator Buses

The pricing rules for Non-Competitive, Dynamically Scheduled Proxy Generator Buses are to be determined.

17.1.6.3.2 Pricing rules for Non-Competitive, Variably Scheduled Proxy Generator
Buses

The pricing rules for Non-Competitive, Variably Scheduled Proxy Generator Buses are provided in the following table.

RuleProxy Generator Bus Constraint

No.affecting External Schedules at location a

1Unconstrained in RTC15, Rolling RTC and

RTD

Direction of Proxy
Generator Bus

Constraint

N/A

Real-Time Pricing Rule
(for location a)

Real-Time LBMPa = RTD LBMPa

4The Rolling RTC used to schedule External

Transactions in a given 15-minute interval is subject to an Interface ATC or Interface RampConstraint

5The Rolling RTC used to schedule External

Transactions in a given 15-minute interval is subject to an Interface ATC or Interface Ramp Constraint

Into NYCAIf Rolling RTC Proxy Generator

(Import)Bus LBMPa > 0, then Real-Time

LBMPa = RTD LBMPa + Rolling RTC External Interface

Congestiona

Otherwise, Real-Time LBMPa =
Minimum of (i) RTD LBMPa and
(ii) zero

Out of NYCAIf Rolling RTC Proxy Generator

(Export)Bus LBMPa < 0, then Real-Time

LBMPa = RTD LBMPa + Rolling RTC External Interface

Congestiona

Otherwise, Real-Time LBMPa = RTD LBMPa

17.1.6.3.3 Pricing rules for Non-Competitive Proxy Generator Buses that are not
Dynamically Scheduled or Variably Scheduled Proxy Generator Buses

The pricing rules for Non-Competitive Proxy Generator Buses that are not Dynamically
Scheduled or Variably Scheduled Proxy Generator Buses are provided in the following table.

RuleProxy Generator Bus Constraint

No.affecting External Schedules at location a

1Unconstrained in RTC15, Rolling RTC and

RTD

6RTC15 is subject to an Interface ATC or

Interface Ramp Constraint

7RTC15 is subject to an Interface ATC or

Interface Ramp Constraint

Direction of Proxy
Generator Bus

Constraint

N/A

Into NYCA (Import)

Out of NYCA (Export)

Real-Time Pricing Rule
(for location a)

Real-Time LBMPa = RTD LBMPa

If RTC15 Proxy Generator Bus
LBMPa > 0, then Real-Time

LBMPa = RTD LBMPa + RTC15
External Interface Congestiona

Otherwise, Real-Time LBMPa =
Minimum of (i) RTD LBMPa and
(ii) zero

If RTC15 Proxy Generator Bus
LBMPa < 0, then Real-Time

LBMPa = RTD LBMPa + RTC15
External Interface Congestiona

Otherwise, Real-Time LBMPa = RTD LBMPa

17.1.6.4   Special Pricing Rules for Proxy Generator Buses Associated with
Designated Scheduled Lines

Real-Time LBMPs for the Proxy Generator Buses associated with designated Scheduled
Lines shall be determined as provided in the tables below.  The Proxy Generator Buses that are
associated with designated Scheduled Lines are identified in Section 4.4.4 of the Services Tariff.

17.1.6.4.1 Pricing rules for Dynamically Scheduled Proxy Generator Buses that are
associated with Designated Scheduled Lines

The pricing rules for Dynamically Scheduled Proxy Generator Buses that are associated with designated Scheduled Lines are to be determined.

17.1.6.4.2 Pricing rules for Variably Scheduled Proxy Generator Buses that are
associated with Designated Scheduled Lines

The pricing rules for Variably Scheduled Proxy Generator Buses that are associated with designated Scheduled Lines are provided in the following table.

RuleProxy Generator Bus Constraint affecting

No.External Schedules at location a

1Unconstrained in RTC15, Rolling RTC and

RTD

4The Rolling RTC used to schedule External

Transactions in a given 15-minute interval is subject to an Interface ATC Constraint

5The Rolling RTC used to schedule External

Transactions in a given 15-minute interval is subject to an Interface ATC Constraint

Direction of Proxy
Generator Bus

Constraint

N/A

Into NYCA (Import)

Out of NYCA (Export)

Real-Time Pricing Rule
(for location a)

Real-Time LBMPa = RTD LBMPa

If Rolling RTC Proxy Generator Bus LBMPa > 0, then Real-Time LBMPa = RTD LBMPa + Rolling RTC External Interface

Congestiona

Otherwise, Real-Time LBMPa =
Minimum of (i) RTD LBMPa and
(ii) zero

If Rolling RTC Proxy Generator Bus LBMPa < 0, then Real-Time LBMPa = RTD LBMPa + Rolling RTC External Interface

Congestiona

Otherwise, Real-Time LBMPa = RTD LBMPa )

17.1.6.4.3 Pricing rules for Proxy Generator Buses that are associated with

Designated Scheduled Lines that are not Dynamically Scheduled or Variably Scheduled Proxy Generator Buses

The pricing rules for Proxy Generator Buses that are associated with designated

Scheduled Lines that are not Dynamically Scheduled or Variably Scheduled Proxy Generator Buses, are provided in the following table.

RuleProxy Generator Bus Constraint affecting

No.External Schedules at location a

1Unconstrained in RTC15, Rolling RTC and

RTD

6RTC15 is subject to an Interface ATC

Constraint

Direction of Proxy
Generator Bus

Constraint

N/A

Into NYCA (Import)

Real-Time Pricing Rule
(for location a)

Real-Time LBMPa = RTD LBMPa

If RTC15 Proxy Generator Bus
LBMPa > 0, then Real-Time

LBMPa = RTD LBMPa + RTC15
External Interface Congestiona

Otherwise, Real-Time LBMPa =
Minimum of (i) RTD LBMPa and
(ii) zero

RuleProxy Generator Bus Constraint affecting

No.External Schedules at location a

7RTC15 is subject to an Interface ATC

Constraint

Direction of Proxy
Generator Bus

Constraint

Out of NYCA (Export)

Real-Time Pricing Rule
(for location a)

If RTC15 Proxy Generator Bus
LBMPa < 0, then Real-Time

LBMPa = RTD LBMPa + RTC15
External Interface Congestiona

Otherwise, Real-Time LBMPa = RTD LBMPa

17.1.6.5   Method of Calculating Marginal Loss and Congestion Components of

Real-Time LBMP at Non-Competitive Proxy Generator Buses and Proxy Generator Buses that are Subject to the Special Pricing Rule for
Designated Scheduled Lines

Under the conditions specified below, the Marginal Losses Component and the Congestion Component of the Real-Time LBMP, calculated pursuant to the preceding paragraphs in Sections 17.1.6.3 and 17.1.6.4, shall be constructed as follows:

When the Real-Time LBMP is set to zero and that zero price was not the result of using the RTD, RTC or SCUC-determined LBMP;

and

where:

=     The marginal Bid cost of providing Energy at the reference
Bus, as calculated by RTD for that 5-minute interval; and

=    The Marginal Losses Component of the LBMP as calculated by RTD  for that 5-minute interval at the NonCompetitive Proxy Generator Bus or Proxy Generator Bus associated with a designated Scheduled Line.

Attachment III

1.20Definitions - T

Tangible Net Worth:  The value, determined by the ISO, of all of a Customer’s assets less both:

(i) the amount of the Customer’s liabilities and (ii) all of the Customer’s intangible assets,

including, but not limited to, patents, trademarks, franchises, intellectual property, and goodwill.

Third Party Sale: Any sale for resale in interstate commerce to a power purchaser that is not
designated as part of Network Load under the Network Integration Transmission Service.

Third Party Transmission Wheeling Agreements (“Third Party TWAs”): A Transmission
Wheeling Agreement, as amended, between Transmission Owners or between a Transmission
Owner and an entity that is not a Transmission Owner.  Third Party TWAs are associated with
the purchase (or sale) of Energy, Capacity, and/or Ancillary Services for the benefit of an entity
that is not a Transmission Owner.   All Third Party TWAs are listed in Attachment L, Table 1A,
and are designated in the “Treatment “column of Table 1A, as “Third Party TWA.”

Total Transfer Capability (“TTC”):  The amount of electric power that can be transferred over the interconnected transmission network in a reliable manner.

Trading Hub: A virtual location in a given Load Zone, modeled as a Generator bus and/or Load
bus, for scheduling Bilateral Transactions in which both the POI and POW are located within the
NYCA.

Trading Hub Energy Owner: A Customer who buys energy in a Bilateral Transaction in which the POW is a Trading Hub, or who sells energy in a Bilateral Transaction in which the POI is a
Trading Hub.

Transaction:  The purchase and/or sale of Energy or Capacity, or the sale of Ancillary Services. A Transaction bid into the Energy market to sell or purchase Energy or to schedule a Bilateral Transaction includes a Point of Injection and a Point of Withdrawal.

Transfer Capability:  The measure of the ability of interconnected electrical systems to reliably move or transfer power from one area to another over all transmission facilities (or paths)
between those areas under specified system conditions.

Transmission Congestion Contract Component (“TCC Component”):  As defined in the ISO Services Tariff.

Transmission Congestion Contracts (“TCCs”):  The right to collect or obligation to pay Congestion Rents in the Day-Ahead Market for Energy associated with a single MW of
transmission between a specified POI and POW.  TCCs are financial instruments that enable Energy buyers and sellers to hedge fluctuations in the price of transmission.

Transmission Customer:  Any Eligible Customer (or its designated agent) that (i) executes a
Service Agreement, or (ii) requests in writing that the ISO file with the Commission a proposed
unexecuted Service Agreement to receive Transmission Service under Part 3, 4 and/or 5 of the
Tariff.

Transmission District: The geographic area in which a Transmission Owner, including LIPA, is obligated to serve Load, as well as the customers directly interconnected with the transmission facilities of the Power Authority of the State of New York.

Transmission Facility Agreement (“TFA”): Agreements governing the use of specific or

designated transmission facilities charges to cover all, or a portion, of the costs to install, own, operate, or maintain transmission facilities, to the customer under the agreement and that have provisions to provide Transmission Service utilizing said transmission facilities.  All
Transmission Facility Agreements are listed in Attachment L. Table 1A, and are designated in the “Treatment” column as “Facility Agmt. - MWA.”

Transmission Facilities Under ISO Operational Control: The transmission facilities of the Transmission Owners listed in Appendix A-1 of the ISO/TO Agreement (“Listing of
Transmission Facilities Under ISO Operational Control”) and listed in Appendix A-1 of an
Operating Agreement (“NTO Transmission Facilities Under ISO Operational Control”) that are subject to the Operational Control of the ISO.  This listing may be amended from time-to-time as specified in the ISO/TO Agreement and Operating Agreements.