31.5Cost Allocation and Cost Recovery

31.5.1The Scope of Attachment Y Cost Allocation

31.5.1.1   Regulated Responses

The cost allocation principles and methodologies in this Attachment Y cover only

regulated transmission solutions to Reliability Needs, regulated transmission responses to

congestion identified in the CARIS, and regulated Public Policy Transmission Projects whether
proposed by a Responsible Transmission Owner or a Transmission Owner or Other Developer.
The cost allocation principles and methodology for: (i) regulated transmission solutions to
Reliability Needs are contained in Sections 31.5.3.1 and 31.5.3.2 of this Attachment Y, (ii)
regulated transmission responses to congestion identified in the CARIS are contained in Sections

31.5.4.1 and 31.5.4.2 of this Attachment Y, and (iii) regulated Public Policy Transmission Projects are contained in Sections 31.5.5 and 31.5.6 of this Attachment Y.

31.5.1.2   Market-Based Responses

The cost allocation principles and methodologies in this Attachment Y do not apply to market-based solutions to Reliability Needs, to market-based responses to congestion identified in the CARIS, or to Other Public Policy Projects. The cost of a market-based project shall be the responsibility of the developer of that project.

31.5.1.3   Interconnection Cost Allocation

The cost allocation principles and methodologies in this Attachment Y do not apply to the
interconnection costs of generation projects and merchant transmission projectsMerchant
Transmission Facilities.  Interconnection costs are determined and allocated in accordance with
Attachment P, Attachment S, Attachment X and Attachment Z of the ISO OATT.  Cost related to

the deliverability of a resource will be addressed under the ISO’s deliverability procedures in Attachment S of the ISO OATT.

31.5.1.4   Individual Transmission Service Requests

The cost allocation principles and methodologies in this Attachment Y do not apply to the cost of transmission expansion projects undertaken in connection with an individual request for Transmission Service.  The cost of such a project is determined and allocated in accordance with Section 3.7 or Section 4.5 of the ISO OATT.

31.5.1.5   LTP Facilities

The cost allocation principles and methodologies in this Attachment Y do not apply to the
cost of transmission projects included in LTPs or LTP updates.  Each Transmission Owner will
recover the cost of such transmission projects in accordance with its then existing rate recovery
mechanisms.

31.5.1.6   Regulated Non-Transmission Projects

Costs related to regulated non-transmission projects will be recovered by Responsible
Transmission Owners, Transmission Owners and Other Developers in accordance with the
provisions of New York Public Service Law, New York Public Authorities Law, or other
applicable state law.  Nothing in this section shall affect the Commission’s jurisdiction over the
sale and transmission of electric energy subject to the jurisdiction of the Commission.

31.5.1.7   Eligibility for Cost Allocation and Cost Recovery

Any entity, whether a Responsible Transmission Owner, Other Developer, or

Transmission Owner, shall be eligible for cost allocation and cost recovery as set forth in Section

31.5 of this Attachment Y and Rate Schedule 10 of the ISO OATT for any transmission project

proposed to satisfy an identified Reliability Need, regulated economic transmission project, or
Public Policy Transmission Project that is determined by the ISO to be eligible under Sections

31.2, 31.3, or 31.4, as applicable.  Interregional Transmission Projects identified in accordance
with the Interregional Planning Protocol, and that have been accepted in each region’s planning
process, shall be eligible for interregional cost allocation and cost recovery, as set forth in
Section 31.5 of this Attachment Y and Rate Schedule 10 of the ISO OATT.  The ISO’s share of
the cost of an Interregional Transmission Project selected pursuant to this Attachment Y to meet
a Reliability Need, congestion identified in the CARIS, or a Public Policy Transmission Need
shall be eligible for cost allocation consistent with the cost allocation methodology applicable to
the type of regional transmission project that would be replaced through the construction of such
Interregional Transmission Project.

31.5.2Cost Allocation Principles Required Under Order No. 1000

31.5.2.1In compliance with Commission Order No. 1000, the ISO shall implement

the specific cost allocation methodology in Section 31.5.3.2, 31.5.4.4, and

31.5.5.4 in accordance with the following Regional Cost Allocation Principles (“Order No. 1000 Regional Cost Allocation Principles”):

Regional Cost Allocation Principle 1:  The ISO shall allocate the cost of
transmission facilities to those within the transmission planning region that
benefit from those facilities in a manner that is at least roughly commensurate
with estimated benefits.  In determining the beneficiaries of transmission
facilities, the ISO’s CSPP will consider benefits including, but not limited to, the
extent to which transmission facilities, individually or in the aggregate provide for

maintaining reliability and sharing reserves, production cost savings and

congestion relief, and/or meeting Public Policy Requirements.

Regional Cost Allocation Principle 2:  The ISO shall not involuntarily allocate any of the costs of transmission facilities to those that receive no benefit from transmission facilities.

Regional Cost Allocation Principle 3:  In the event that the ISO adopts a benefit to cost threshold in its CSPP to determine which transmission facilities have
sufficient net benefits to be selected in a regional transmission plan for the
purpose of cost allocation, such benefit to cost threshold will not be so high that transmission facilities with significant positive net benefits are excluded from cost allocation.  If the ISO chooses to adopt such a threshold in its CSPP it will not
include a ratio of benefits to costs that exceeds 1.25 unless the ISO justifies and
the Commission approves a higher ratio.

Regional Cost Allocation Principle 4:  The ISO’s allocation method for the cost of a transmission facility selected pursuant to the process in the CSPP shall
allocate costs solely within the ISO’s transmission planning region unless another entity outside the region or another transmission planning region voluntarily
agrees to assume a portion of those costs.  Costs for an Interregional Transmission Project must be assigned only to regions in which the facility is physically
located.  Costs cannot be assigned involuntarily to another region.  The ISO shall not bear the costs of required upgrades in another region.

Regional Cost Allocation Principle 5:  The ISO’s cost allocation method and
data requirements for determining benefits and identifying beneficiaries for a

transmission facility shall be transparent with adequate documentation to allow a
stakeholder to determine how they were applied to a proposed transmission
facility, as consistent with confidentiality requirements set forth in this
Attachment Y and the ISO Code of Conduct in Attachment F of the OATT.
Regional Cost Allocation Principle 6:  The ISO’s CSPP provides a different cost
allocation method for different types of transmission facilities in the regional
transmission plan and each cost allocation method is set out clearly and explained
in detail in this Section 31.5.

31.5.2.2 In compliance with Commission Order No. 1000, the ISO shall implement

the specific cost allocation methodology in Section 31.5.7 of this Attachment Y in
accordance with the following Interregional Cost Allocation Principles:
Interregional Cost Allocation Principle 1:  The ISO shall allocate the cost of
new Interregional Transmission Projects to each region in which an Interregional
Transmission Project is located in a manner that is at least roughly commensurate
with estimated benefits of the Interregional Transmission Project in each of the
regions.  In determining the beneficiaries of Interregional Transmission Projects,
the ISO will consider benefits including, but not limited to, those associated with
maintaining reliability and sharing reserves, production cost savings and
congestion relief, and meeting Public Policy Requirements.
Interregional Cost Allocation Principle 2:  The ISO shall not involuntarily
allocate any of the costs of an Interregional Transmission Project to a region that
receives no benefit from an Interregional Transmission Project that is located in
that region, either at present or in a likely future scenario.

Interregional Cost Allocation Principle 3:  In the event that the ISO adopts a
benefit-cost threshold ratio to determine whether an Interregional Transmission
Project has sufficient net benefits to qualify for interregional cost allocation, this
ratio shall not be so large as to exclude an Interregional Transmission Project with
significant positive net benefits from cost allocation.  If the ISO chooses to adopt
such a threshold, they will not include a ratio of benefits to costs that exceeds 1.25
unless the Parties justify and the Commission approves a higher ratio.
Interregional Cost Allocation Principle 4:  The ISO’s allocation of costs for an
Interregional Transmission Project shall be assigned only to regions in which the
Interregional Transmission Project is located.  The ISO shall not assign costs
involuntarily to a region in which that Interregional Transmission Project is not
located.  The ISO shall, however, identify consequences for other regions, such as
upgrades that may be required in a third region.  The ISO’s interregional cost
allocation methodology includes provisions for allocating the costs of upgrades
among the beneficiaries in the region in which the Interregional Transmission
Project is located to the transmission providers in such region that agree to bear
the costs associated with such upgrades.

Interregional Cost Allocation Principle 5:  The ISO’s cost allocation

methodology and data requirements for determining benefits and identifying

beneficiaries for an Interregional Transmission Project shall be transparent with
adequate documentation to allow a stakeholder to determine how they were
applied to a proposed Interregional Transmission Project, as consistent with the

confidentiality requirements set forth in this Attachment Y and the ISO Code of Conduct in Attachment F of the OATT.

Interregional Cost Allocation Principle 6:  Though Order No. 1000 allows the ISO to provide a different cost allocation methodology for different types of
interregional transmission facilities, such as facilities needed for reliability,
congestion relief, or to achieve Public Policy Requirements, the ISO has chosen to adopt one interregional cost allocation methodology for all Interregional
Transmission Planning Projects.  The interregional cost allocation methodology is set out clearly and explained in detail in Section 31.5.7 of this Attachment Y.  The share of the cost related to any Interregional Transmission Project assigned to the ISO shall be allocated as described in Section 31.5.7.1.

31.5.3 Regulated Responses to Reliability Needs

31.5.3.1   Cost Allocation Principles

The ISO shall implement the specific cost allocation methodology in Section 31.5.3.2 of this

Attachment Y in accordance with the Order No. 1000 Regional Cost Allocation Principles as set
forth in Section 31.5.2.1.  This methodology shall apply to cost allocation for a regulated
transmission solution to an identified Reliability Need, including the ISO’s share of the costs of
an Interregional Transmission Project proposed as a regulated transmission solution to an
identified Reliability Need allocated in accordance with Section 31.5.7 of this Attachment Y.
The specific cost allocation methodology in Section 31.5.3.2 incorporates the following elements:

31.5.3.1.1The focus of the cost allocation methodology shall be on solutions to

Reliability Needs.

31.5.3.1.2Potential impacts unrelated to addressing the Reliability Needs shall not be

considered for the purpose of cost allocation for regulated solutions.

31.5.3.1.3 Primary beneficiaries shall initially be those Load Zones or Subzones

identified as contributing to the reliability violation.

31.5.3.1.4 The cost allocation among primary beneficiaries shall be based upon their

relative contribution to the need for the regulated solution.

31.5.3.1.5 The ISO will examine the development of specific cost allocation rules

based on the nature of the reliability violation (e.g., thermal overload, voltage, stability, resource adequacy and short circuit).

31.5.3.1.6Cost allocation shall recognize the terms of prior agreements among the

Transmission Owners, if applicable.

31.5.3.1.7Consideration should be given to the use of a materiality threshold for cost

allocation purposes.

31.5.3.1.8 The methodology shall provide for ease of implementation and

administration to minimize debate and delays to the extent possible.

31.5.3.1.9 Consideration should be given to the “free rider” issue as appropriate.

The methodology shall be fair and equitable.

31.5.3.1.10The methodology shall provide cost recovery certainty to investors to the

extent possible.

31.5.3.1.11The methodology shall apply, to the extent possible, to Gap Solutions.

31.5.3.1.12Cost allocation is independent of the actual triggered project(s), except

when allocating cost responsibilities associated with meeting a Locational

Minimum Installed Capacity Requirement (“LCR”), and is based on a separate process that results in NYCA meeting its LOLE requirement.

31.5.3.1.13 Cost allocation for a solution that meets the needs of a Target Year

assumes that backstop solutions of prior years have been implemented.

31.5.3.1.14 Cost allocation will consider the most recent values for LCRs.  LCRs must

be met for the Target Year.

31.5.3.2   Cost Allocation Methodology

The cost allocation mechanism under this Section 31.5.3.2 sets forth the basis for

allocating costs associated with a Responsible Transmission Owner’s regulated backstop solution or an Other Developer’s or Transmission Owner’s alternative regulated transmission solution
selected by the ISO as the more efficient or cost-effective transmission solution to an identified
Reliability Need.

The formula is not applicable to that portion of a project beyond the size of the solution
needed to provide the more efficient or cost effective solution appropriate to the Reliability Need
identified in the RNA.  Nor is the formula applicable to that portion of the cost of a regulated
transmission reliability project that is, pursuant to Section 25.7.12 of Attachment S to the ISO
OATT, paid for with funds previously committed by or collected from Developers for the
installation of System Deliverability Upgrades required for the interconnection of generation
projects or merchant transmission projectsClass Year Transmission Projects.
This Section 31.5.3.2 establishes the allocation of the costs related to resolving
Reliability Needs resulting from resource adequacy, BPTF thermal transmission security, BPTF
voltage security, dynamic stability, and short circuit issues.  Costs will be allocated in
accordance with the following hierarchy: (i) resource adequacy pursuant to Section 31.5.3.2.1,

(ii) BPTF thermal transmission security pursuant to Section 31.5.3.2.2, (iii) BPTF voltage

security pursuant to Section 31.5.3.2.3, (iv) dynamic stability pursuant to Section 31.5.3.2.4, and

(v) short circuit pursuant to Section 31.5.3.2.5.

31.5.3.2.1  Resource Adequacy Reliability Solution Cost Allocation Formula

For purposes of solutions eligible for cost allocation under this Section 31.5.3.2, this

section sets forth the cost allocation methodology applicable to that portion of the costs of the

solution attributable to resolving resource adequacy.  The same cost allocation formula is applied regardless of the project or sets of projects being triggered; however, the nature of the solution set may lead to some terms equaling zero, thereby dropping out of the equation.  To ensure that appropriate allocation to the LCR and non-LCR zones occurs, the zonal allocation percentages are developed through a series of steps that first identify responsibility for LCR deficiencies, followed by responsibility for remaining need.  The following formula shall apply to the
allocation of the costs of the solution attributable to resource adequacy:

Resource Adequacy Cost Allocation௜
=

LCRdef௜

Soln Size  +

+

Concident Peak௜
∗ (1 + IRM − LCRi)

௡ *

� Coincident Peak௞

௞=1

∗ (1 + IRM − LCRk)

Concident Peak௜
∗ (1 + IRM − LCRi)

௠ *

� Coincident Peak௟

௟=1

∗ (1 + IRM − LCRl)

Soln STWdef
Soln Size

Soln Cldef
Soln Size *100%

Where i is for each applicable zone, n represent the total zones in NYCA, m represents
the zones isolated by the binding interfaces, IRM is the statewide reserve margin, and where
LCR is defined as the locational capacity requirement in terms of percentage and is equal to zero
for those zones without an LCR requirement, LCRdefi is the applicable zonal LCR deficiency,
SolnSTWdef is the STWdef for each applicable project, SolnCIdef is the CIdef for each

applicable project, and Soln_Size represents the total compensatory MW addressed by each applicable project for all reliability cost allocation steps in this Section 31.5.3.2.
Three step cost allocation methodology for regulated reliability solutions:

31.5.3.2.1.1   Step 1 - LCR Deficiency

31.5.3.2.1.1.1 Any deficiencies in meeting the LCRs for the Target Year will be referred
to as the LCRdef.  If the reliability criterion is met once the LCR deficiencies
have been addressed, that is LOLE ≤ 0.1 for the Target Year is achieved, then the
only costs allocated will be those related to the LCRdef MW.  Cost responsibility
for the LCRdef MW will be borne by each deficient locational zone(s), to the
extent each is individually deficient.

For a single solution that addresses only an LCR deficiency in the applicable LCR zone, the equation would reduce to:

Allocation௜ =

LCRdef௜
Soln_Size ∗ 100%

Where i is for each applicable LCR zone, LCRdefi represents the applicable zonal LCR
deficiency, and Soln_Size represents the total compensatory MW addressed by the applicable
project.

31.5.3.2.1.1.2 Prior to the LOLE calculation, voltage constrained interfaces will be

recalculated to determine the resulting transfer limits when the LCRdef MW are
added.

31.5.3.2.1.2   Step 2 - Statewide Resource Deficiency.  If the reliability criterion is not
met after the LCRdef has been addressed, that is an LOLE > 0.1, then a NYCA
Free Flow Test will be conducted to determine if NYCA has sufficient resources
to meet an LOLE of 0.1.

31.5.3.2.1.2.1 If NYCA is found to be resource limited, the ISO, using the transfer limits
and resources determined in Step 1, will determine the optimal distribution of
additional resources to achieve a reduction in the NYCA LOLE to 0.1.

31.5.3.2.1.2.2 Cost allocation for compensatory MW added for cost allocation purposes
to achieve an LOLE of 0.1, defined as a Statewide MW deficiency (STWdef), will
be prorated to all NYCA zones, based on the NYCA coincident peak load.  The
allocation to locational zones will take into account their locational requirements.
For a single solution that addresses only a statewide deficiency, the equation
would reduce to:

Concident Peak௜ ∗ (1 + IRM − LCRi)

௡

Allocation௜ =� Coincident Peak௞ *

௞=1

∗ (1 + IRM − LCRk)

Soln STWdef

Soln Size

*100%

Where i is for each applicable zone, n is for the total zones in NYCA, IRM is the
statewide reserve margin, and LCR is defined as the locational capacity
requirement in terms of percentage and is equal to zero for those zones without an
LCR requirement, Soln STWdef is the STWdef for the applicable project, and
Soln_Size represents the total compensatory MW addressed by the applicable
project.

31.5.3.2.1.3   Step 3 - Constrained Interface Deficiency.  If the NYCA is not resource
limited as determined by the NYCA Free Flow Test, then the ISO will examine
constrained transmission interfaces, using the Binding Interface Test.

31.5.3.2.1.3.1 The ISO will provide output results of the reliability simulation program
utilized for the RNA that indicate the hours that each interface is at limit in each
flow direction, as well as the hours that coincide with a loss of load event.  These

values will be used as an initial indicator to determine the binding interfaces that are impacting LOLE within the NYCA.

31.5.3.2.1.3.2 The ISO will review the output of the reliability simulation program
utilized for the RNA along with other applicable information that may be
available to make the determination of the binding interfaces.

31.5.3.2.1.3.3   Bounded Regions are assigned cost responsibility for the compensatory
MW, defined as CIdef, needed to reach an LOLE of 0.1.

31.5.3.2.1.3.4 If one or more Bounded Regions are isolated as a result of binding

interfaces identified through the Binding Interface Test, the ISO will determine
the optimal distribution of compensatory MW to achieve a NYCA LOLE of 0.1.
Compensatory MW will be added until the required NYCA LOLE is achieved.

31.5.3.2.1.3.5 The Bounded Regions will be identified by the ISO’s Binding Interface
Test, which identifies the bounded interface limits that can be relieved and have
the greatest impact on NYCA LOLE. The Bounded Region that will have the
greatest benefit to NYCA LOLE will be the area to be first allocated costs in this
step.  The ISO will determine if after the first addition of compensating MWs the
Bounded Region with the greatest impact on LOLE has changed.  During this
iterative process, the Binding Interface Test will look across the state to identify
the appropriate Bounded Region.  Specifically, the Binding Interface Test will be
applied starting from the interface that has the greatest benefit to LOLE (the
greatest LOLE reduction per interface compensatory MW addition), and then
extended to subsequent interfaces until a NYCA LOLE of 0.1 is achieved.

31.5.3.2.1.3.6 The CIdef MW are allocated to the applicable Bounded Region isolated as
a result of the constrained interface limits, based on their NYCA coincident peaks.
Allocation to locational zones will take into account their locational requirements.
For a single solution that addresses only a binding interface deficiency, the
equation would reduce to:

Allocation௜ =

Concident Peak௜ ∗ (1 + IRM − LCRi)

௠

� Coincident Peak௟ ∗ (1 + IRM − LCRl)

௟=1

SolnCIdef

*Soln Size*100%

Where i is for each applicable zone, m is for the zones isolated by the binding

interfaces, IRM is the statewide reserve margin, and where LCR is defined as the locational capacity requirement in terms of percentage and is equal to zero for those zones without an LCR requirement, SolnCIdef is the CIdef for the
applicable project and Soln_Size represents the total compensatory MW
addressed by the applicable project.

31.5.3.2.2 BPTF Thermal Transmission Security Cost Allocation Formula

For purposes of solutions eligible for cost allocation under this Section 31.5.3.2, this
section sets forth the cost allocation methodology applicable to that portion of the costs of the solution attributable to resolving BPTF thermal transmission security issues.  If, after
consideration of the compensatory MW identified in the resource adequacy reliability solution cost allocation in accordance with Section 31.5.3.2.1, there remains a BPTF thermal transmission security issue, the ISO will allocate the costs of the portion of the solution attributable to
resolving the BPTF thermal transmission security issue(s) to the Subzones that contribute to the BPTF thermal transmission security issue(s) in the following manner.

31.5.3.2.2.1   Calculation of Nodal Distribution Factors.  The ISO will calculate the

nodal distribution factor for each load bus modeled in the power flow case

utilizing the output of the reliability simulation program that identified the

Reliability Need, including the NYCA generation dispatch and NYCA coincident
peak Load.  The nodal distribution factor represents the percentage of the Load
that flows across the facility subject to the Reliability Need.  The sign (positive or

negative) of the nodal distribution factor represents the direction of flow.

31.5.3.2.2.2   Calculation of Nodal Flow.  The ISO will calculate the nodal megawatt
flow, defined as Nodal Flow, for each load bus modeled in the power flow case
by multiplying the amount of Load in megawatts for the bus, defined as Nodal
Load, by the nodal distribution factor for the bus.  Nodal Flow represents the
number of megawatts that flow across the facility subject to the Reliability Need
due to the Load.

31.5.3.2.2.3   Calculation of Contributing Load and Contributing Flow.  The Nodal
Load for a load bus with a positive nodal distribution factor is a contributing
Load, defined as CLoad, and the Nodal Flow for that Load is contributing flow,
defined as CFlow.  To identify contributing Loads that have a material impact on
the Reliability Need, the ISO will calculate a contributing materiality threshold,
defined as CMT, as follows:

ܥܯܶ =

∑௠௞=1 ∑௅=1ܥܨ݈݋ݓ௅

௠

∑௞=1 ∑௅=1ܥܮ݋ܽ݀௅

Where m is for the total number of Subzones and n is for the total number of load buses in a given Subzone.

31.5.3.2.2.4   Calculation of Helping Load and Helping Flow.  The Nodal Load for a
load bus with a negative or zero nodal distribution factor is a helping Load,
defined as HLoad, and the Nodal Flow for that Load is helping flow, defined as
HFlow.  To identify helping Loads that have a material impact on the Reliability
Need, the ISO will calculate a helping materiality threshold, defined as HMT, as
follows:

ܪ𝐻 =

∑௠௞=1 ∑௅=1ܪ𝐻𝐻௅

௠

∑௞=1 ∑௅=1ܪ𝐻𝐻௅

Where m is for the total number of Subzones and n is for the total number of load buses in a given Subzone.

31.5.3.2.2.5   Calculation of Net Material Flow for Each Subzone.  The ISO will

identify material Nodal Flow for each Subzone and calculate the net material flow for each Subzone.  For each load bus, the Nodal Flow will be identified as
material flow, defined as MFlow, if the nodal distribution factor is (i) greater than or equal to CMT, or (ii) less than or equal to HMT.  The net material flow for each Subzone, defined as SZ_NetFlow, is calculated as follows:

௡

ܼܵ_ܰ݁ݐ𝑁𝑁௝ = � 𝑀𝑀௅

௅=1

Where j is for each Subzone and n is for the total number of load buses in a given Subzone.

31.5.3.2.2.6   Identification of Allocated Flow for Each Subzone.  The ISO will identify
the allocated flow for each Subzone and verify that sufficient contributing flow is
being allocated costs.  For each Subzone, if the SZ_NetFlow is greater than zero,
that Subzone has a net material contribution to the Reliability Need and the

SZ_NetFlow is identified as allocated flow, defined as SZ_AllocFlow.  If the
SZ_NetFlow is less than or equal to zero, that Subzone does not have a net
material contribution to the Reliability Need and the SZ_AllocFlow is zero for
that Subzone.  If the total SZ_AllocFlow for all Subzones is less than 60% of the total CFlow for all Subzones, then the CMT will be reduced and SZ_NetFlow
recalculated until the total SZ_AllocFlow for all Subzones is at least 60% of the total CFlow for all Subzones.

31.5.3.2.2.7   Cost Allocation for a Single BPTF Thermal Transmission Security Issue.
For a single solution that addresses only a BPTF thermal transmission security
issue, the equation for cost allocation would reduce to:

ܤܲ𝐵 ℎݎ݉𝑒 ܥ݋ݏ ܣ𝐴ܿ݅݊௝ =

ܼܵ_ܣ𝐴ܿ𝐴𝐴௝

௠

∑௞=1 ܼܵ_ܣ𝐴ܿ𝐴𝐴௞

ܵ𝑆𝑆ܵ𝑆݂
×

ܵ𝑆_ܵݖ

Where j is for each Subzone; m is for the total number of Subzones;

SZ_AllocFlow is the allocated flow for each Subzone; SolnBTSdef is the number of compensatory MW for the BPTF thermal transmission security issue for the applicable project; and Soln_Size represents the total compensatory MW
addressed by the applicable project.

31.5.3.2.2.8   Cost Allocation for Multiple BPTF Thermal Transmission Security Issues.
If a single solution addresses multiple BPTF thermal transmission security issues,
the ISO will calculate weighting factors based on the ratio of the present value of
the estimated costs for individual solutions to each BPTF thermal transmission
security issue.  The present values of the estimated costs for the individual
solutions shall be based on a common base date that will be the beginning of the
calendar month in which the cost allocation analysis is performed (the “Base

Date”).  The ISO will apply the weighting factors to the cost allocation calculated
for each Subzone for each individual BPTF thermal transmission security issue.
The following example illustrates the cost allocation for such a solution:
• A cost allocation analysis for the selected solution is to be performed during a
given month establishing the beginning of that month as the Base Date.
• The ISO has identified two BPTF thermal transmission security issues, Overload
X and Overload Y, and the ISO has selected a single solution (Project Z) to
address both BPTF thermal transmission security issues.

• The cost of a solution to address only Overload X (Project X) is Cost(X),

provided in a given year’s dollars.  The number of years from the Base Date to the year associated with the cost estimate of Project (X) is N(X).

• The cost of a solution to address only Overload Y (Project Y) is Cost(Y),

provided in a given year’s dollars.  The number of years from the Base Date to the year associated with the cost estimate of Project Y is N(Y).

• The discount rate, D, to be used for the present value analysis shall be the current

after-tax weighted average cost of capital for the Transmission Owners.

• Based on the foregoing assumptions, the following formulas will be used:

   Present Value of Cost (X) = PV Cost (X) = Cost (X) / (1+D)N(X)

   Present Value of Cost (Y) = PV Cost (Y) = Cost (Y) / (1+D)N(Y)

   Overload X weighting factor = PV Cost (X)/[PV Cost (X) + PV Cost (Y)]
   Overload Y weighting factor = PV Cost (Y)/[PV Cost (X) + PV Cost (Y)] • Applying those formulas, if:

Cost (X) = $100 Million and N(X) = 6.25 years

Cost (Y) = $25 Million and N(Y) = 4.75 years D = 7.5% per year

Then:

PV Cost (X) = 100/(1+0.075) 6.25   =  63.635 Million
PV Cost (Y) = 25/(1+0.075)4.75 =  17.732 Million

Overload X weighting factor = 63.635 / (63.635 + 17.732) = 78.21%
Overload Y weighting factor = 17.732 / (63.635 + 17.732) = 21.79%

•   Applying those weighing factors, if:

Subzone A cost allocation for Overload X is 15%
Subzone A cost allocation for Overload Y is 70%
Then:

Subzone A cost allocation % for Project Z =

(15% * 78.21%) + (70% * 21.79%) = 26.99%

31.5.3.2.2.9   Exclusion of Subzone(s) Based on De Minimis Impact.  If a Subzone is
assigned a BPTF thermal transmission security cost allocation less than a de
minimis dollar threshold of the total project costs, that Subzone will not be
allocated costs; provided however, that the total de minimis Subzones may not
exceed 10% of the total BPTF thermal transmission security cost allocation.  The
de minimis threshold is initially $10,000.  If the total allocation percentage of all
de minimis Subzones is greater than 10%, then the de minimis threshold will be
reduced until the total allocation percentage of all de minimis Subzones is less
than or equal to 10%.

31.5.3.2.3 BPTF Voltage Security Cost Allocation

If, after consideration of the compensatory MW identified in the resource adequacy cost
allocation in accordance with Section 31.5.3.2.1 and BPTF thermal transmission security cost
allocation in accordance with Section 31.5.3.2.2, there remains a BPTF voltage security issue,
the ISO will allocate the costs of the portion of the solution attributable to resolving the BPTF
voltage security issue(s) to the Subzones that contribute to the BPTF voltage security issue(s).
The cost responsibility for the portion (MW or MVAr) of the solution attributable to resolving
the BPTF voltage security issue(s), defined as SolnBVSdef, will be allocated on a Load-ratio
share to each Subzone to which each bus with a voltage issue is connected, as follows:

ܤܲ𝐵 ܸ𝑉𝑉݃ ܥ݋ݏ ܣ𝐴ܿ݅݊௝ =

ܥ݋𝐶𝐶݀𝐶 𝑃݇௝ ܵ𝑆𝑆ܵ𝑆݂
∑௞=1ܥ݋𝐶𝐶݀𝐶 𝑃݇௞ × ܵ𝑆_ܵݖ

Where j is for each Subzone; m is for the total number of Subzones that are subject to
BPTF voltage cost allocation; Coincident Peak is for the total peak Load for each Subzone;
SolnBVSdef is for the portion of the solution necessary to resolve the BPTF voltage security
issue(s); and Soln_Size represents the total compensatory MW addressed by the applicable
project.

31.5.3.2.4 Dynamic Stability Cost Allocation

If, after consideration of the compensatory MW identified in the resource adequacy cost allocation in accordance with Section 31.5.3.2.1, BPTF thermal transmission security cost
allocation in accordance with Section 31.5.3.2.2, and BPTF voltage security cost allocation in accordance with Section 31.5.3.2.3, there remains a dynamic stability issue, the ISO will allocate the costs of the portion of the solution attributable to resolving the dynamic stability issue(s) to all Subzones in the NYCA on a Load-ratio share basis, as follows:

ܦݕ𝐷𝐷 ܵ𝑆ܾ𝑆𝑆 ܥ݋ݏ ܣ𝐴ܿ݅݊௝ =

ܥ݋𝐶𝐶݀𝐶 𝑃݇௝ ܦݕ𝐷𝐷𝐷ܹ
∑௞=1ܥ݋𝐶𝐶݀𝐶 𝑃݇௞ × ܵ𝑆_ܵݖ

Where j is for each Subzone; m is for the total number of Subzones; Coincident Peak is
for the total peak Load for each Subzone; DynamicMW is for the megawatt portion of the
solution necessary to resolve the dynamic stability issue(s) for the applicable project; and
Soln_Size represents the total compensatory MW addressed by the applicable project.

31.5.3.2.5 Short Circuit Issues

If, after the completion of the prior reliability cost allocation steps, there remains a short circuit issue, the short circuit issue will be deemed a local issue and related costs will not be allocated under this process.

31.5.4Regulated Economic Projects

31.5.4.1   The Scope of Section 31.5.4

As discussed in Section 31.5.1 of this Attachment Y, the cost allocation principles and methodologies of this Section 31.5.4 apply only to regulated economic transmission projects (“RETPs”) proposed in response to congestion identified in the CARIS.

This Section 31.5.4 does not apply to generation or demand side management projects,
nor does it apply to any market-based projects.  This Section 31.5.4 does not apply to regulated
backstop solutions triggered by the ISO pursuant to the CSPP, provided, however, the cost
allocation principles and methodologies in this Section 31.5.4 will apply to regulated backstop
solutions when the implementation of the regulated backstop solution is accelerated solely to
reduce congestion in earlier years of the Study Period.  The ISO will work with the ESPWG to
develop procedures to deal with the acceleration of regulated backstop solutions for economic
reasons.

Nothing in this Attachment Y mandates the implementation of any project in response to the congestion identified in the CARIS.

31.5.4.2   Cost Allocation Principles

The ISO shall implement the specific cost allocation methodology in Section 31.5.4.4 of this Attachment Y in accordance with the Order No. 1000 Regional Cost Allocation Principles as set forth in Section 31.5.2.1.  The specific cost allocation methodology in Section 31.5.4.4
incorporates the following elements:

31.5.4.2.1The focus of the cost allocation methodology shall be on responses to

specific conditions identified in the CARIS.

31.5.4.2.2Potential impacts unrelated to addressing the identified congestion shall

not be considered for the purpose of cost allocation for RETPs.

31.5.4.2.3Projects analyzed hereunder as proposed RETPs may proceed on a market

basis with willing buyers and sellers at any time.

31.5.4.2.4 Cost allocation shall be based upon a beneficiaries pay approach.  Cost

allocation under the ISO tariff for a RETP shall be applicable only when a super majority of the beneficiaries of the project, as defined in Section 31.5.4.6 of this Attachment Y, vote to support the project.

31.5.4.2.5Beneficiaries of a RETP shall be those entities economically benefiting

from the proposed project.  The cost allocation among beneficiaries shall be based

upon their relative economic benefit.

31.5.4.2.6Consideration shall be given to the proposed project’s payback period.

31.5.4.2.7The cost allocation methodology shall address the possibility of cost

overruns.

31.5.4.2.8Consideration shall be given to the use of a materiality threshold for cost

allocation purposes.

31.5.4.2.9The methodology shall provide for ease of implementation and

administration to minimize debate and delays to the extent possible.

31.5.4.2.10Consideration should be given to the “free rider” issue as appropriate.  The

methodology shall be fair and equitable.

31.5.4.2.11The methodology shall provide cost recovery certainty to investors to the

extent possible.

31.5.4.2.12Benefits determination shall consider various perspectives, based upon the

agreed-upon metrics for analyzing congestion.

31.5.4.2.13 Benefits determination shall account for future uncertainties as appropriate

(e.g., load forecasts, fuel prices, environmental regulations).

31.5.4.2.14 Benefits determination shall consider non-quantifiable benefits as

appropriate (e.g., system operation, environmental effects, renewable integration).

31.5.4.3   Project Eligibility for Cost Allocation

The methodologies in this Section 31.5.4.3 will be used to determine the eligibility of a proposed RETP to have its cost allocated and recovered pursuant to the provisions of this
Attachment Y.

31.5.4.3.1 The ISO will evaluate the benefits against the costs (as provided by the

Developer) of each proposed RETP over a ten-year period commencing with the
proposed commercial operation date for the project.  The Developer of each
project will pay the cost incurred by the ISO to conduct the ten-year benefit/cost
analysis of its project.  The ISO, in conjunction with the ESPWG, will develop

methodologies for extending the most recently completed CARIS database as necessary to evaluate the benefits and costs of each proposed RETP.

31.5.4.3.2 The benefit metric for eligibility under the ISO’s benefit/cost analysis will

be expressed as the present value of the annual NYCA-wide production cost

savings that would result from the implementation of the proposed project,

measured for the first ten years from the proposed commercial operation date for the project.

31.5.4.3.3 The cost for the ISO’s benefit/cost analysis will be supplied by the

Developer of the project, and the cost metric for eligibility will be expressed as

the present value of the first ten years of annual total revenue requirements for the project, reasonably allocated over the first ten years from the proposed
commercial operation date for the project.

31.5.4.3.4 For informational purposes only, the ISO will also calculate the present

value of the annual total revenue requirement for the project over a 30 year period commencing with the proposed commercial operation date of the project.

31.5.4.3.5 To be eligible for cost allocation and recovery under this Attachment Y,

the benefit of the proposed project must exceed its cost measured over the first ten
years from the proposed commercial operation date for the project, and the
requirements of section 31.5.4.2 must be met.  The total capital cost of the project
must exceed $25 million.  In addition, a super-majority of the beneficiaries must
vote in favor of the project, as specified in Section 31.5.4.6 of this Attachment Y.

31.5.4.3.6 In addition to calculating the benefit metric as defined in Section

31.5.4.3.2, the ISO will calculate additional metrics to estimate the potential

benefits of the proposed project, for information purposes only, in accordance

with Section 31.3.1.3.5, for the applicable metric.  These additional metrics shall include those that measure reductions in LBMP load costs, changes to generator payments, ICAP costs, Ancillary Service costs, emissions costs, and losses.  TCC revenues will be determined in accordance with Section 31.5.4.4.2.3.  The ISO will provide information on these additional metrics to the maximum extent
practicable considering its overall resource commitments.

31.5.4.3.7 In addition to the benefit/cost analysis performed by the ISO under this

Section 31.5.4.3, the ISO will work with the ESPWG to consider the development
and implementation of scenario analyses, for information only, that shed
additional light on the benefit/cost analysis of a proposed project.  These
additional scenario analyses may cover fuel and load forecast uncertainty,
emissions data and the cost of allowances, pending environmental or other
regulations, and alternate resource and energy efficiency scenarios.  Consideration
of these additional scenarios will take into account the resource commitments of
the ISO.

31.5.4.4   Cost Allocation for Eligible Projects

As noted in Section 31.5.4.2 of this Attachment Y, the cost of a RETP will be allocated to
those entities that would economically benefit from implementation of the proposed project. This
methodology shall apply to cost allocation for a RETP, including the ISO’s share of the costs of
an Interregional Transmission Project proposed as a RETP allocated in accordance with Section

31.5.7 of this Attachment Y.

31.5.4.4.1The ISO will identify the beneficiaries of the proposed project over a ten-

year time period commencing with the proposed commercial operation date for the project.  The ISO, in conjunction with the ESPWG, will develop
methodologies for extending the most recently completed CARIS database as necessary for this purpose.

31.5.4.4.2 The ISO will identify beneficiaries of a proposed project as follows:

31.5.4.4.2.1   The ISO will measure the present value of the annual zonal LBMP load
savings for all Load Zones which would have a load savings, net of reductions in
TCC revenues, and net of reductions from bilateral contracts (based on available
information provided by Load Serving Entities to the ISO as set forth in
subsection 31.5.4.4.2.5 below) as a result of the implementation of the proposed
project.  For purposes of this calculation, the present value of the load savings will
be equal to the sum of the present value of the Load Zone’s load savings for each
year over the ten-year period commencing with the project’s commercial
operation date.  The load savings for a Load Zone will be equal to the difference
between the zonal LBMP load cost without the project and the LBMP load cost
with the project, net of reductions in TCC revenues and net of reductions from
bilateral contracts.

31.5.4.4.2.2   The beneficiaries will be those Load Zones that experience net benefits

measured over the first ten years from the proposed commercial operation date for
the project.  If the sum of the zonal benefits for those Load Zones with load
savings is greater than the revenue requirements for the project (both load savings
and revenue requirements measured in present value over the first ten years from

the commercial operation date of the project), the ISO will proceed with the

development of the zonal cost allocation information to inform the beneficiary voting process.

31.5.4.4.2.3   Reductions in TCC revenues will reflect the forecasted impact of the
project on TCC auction revenues and day-ahead residual congestion rents
allocated to load in each zone, not including the congestion rents that accrue to
any Incremental TCCs that may be made feasible as a result of this project.  This
impact will include forecasts of: (1) the total impact of that project on the
Transmission Service Charge offset applicable to loads in each zone (which may
vary for loads in a given zone that are in different Transmission Districts); (2) the
total impact of that project on the NYPA Transmission Adjustment Charge offset
applicable to loads in that zone; and (3) the total impact of that project on
payments made to LSEs serving load in that zone that hold Grandfathered Rights
or Grandfathered TCCs, to the extent that these have not been taken into account
in the calculation of item (1) above.  These forecasts shall be performed using the
procedure described in Appendix B to this Attachment Y.

31.5.4.4.2.4   Estimated TCC revenues from any Incremental TCCs created by a

proposed RETP over the ten-year period commencing with the project’s

commercial operation date will be added to the Net Load Savings used for the cost allocation and beneficiary determination.

31.5.4.4.2.5   The ISO will solicit bilateral contract information from all Load Serving
Entities, which will provide the ISO with bilateral energy contract data for
modeling contracts that do not receive benefits, in whole or in part, from LBMP

reductions, and for which the time period covered by the contract is within the
ten-year period beginning with the commercial operation date of the project.
Bilateral contract payment information that is not provided to the ISO will not be included in the calculation of the present value of the annual zonal LBMP savings in section 31.5.4.4.2.1 above.

31.5.4.4.2.5.1 All bilateral contract information submitted to the ISO must identify the
source of the contract information, including citations to any public documents
including but not limited to annual reports or regulatory filings

31.5.4.4.2.5.2 All non-public bilateral contract information will be protected in

accordance with the ISO’s Code of Conduct, as set forth in Section 12.4 of
Attachment F of the ISO OATT, and Section 6 of the ISO Services Tariff.

31.5.4.4.2.5.3 All bilateral contract information and information on LSE-owned
generation submitted to the ISO must include the following information:

(1)Contract quantities on an annual basis:

(a)For non-generator specific contracts, the Energy (in MWh) contracted to serve

each Zone for each year.

(b) For generator specific contracts or LSE-owned generation, the name of the

generator(s) and the MW or percentage output contracted or self-owned for use by Load in each Zone for each year.

(2)For all Load Serving Entities serving Load in more than one Load Zone, the

quantity (in MWh or percentage) of bilateral contract Energy to be applied to each

Zone, by year over the term of the contract.

(3)Start and end dates of the contract.

(4)Terms in sufficient detail to determine that either pricing is not indexed to LBMP,

or, if pricing is indexed to LBMP, the manner in which prices are connected to

LBMP.

(5)Identify any changes in the pricing methodology on an annual basis over the term

of the contract.

31.5.4.4.2.5.4 Bilateral contract and LSE-owned generation information will be used to
calculate the adjusted LBMP savings for each Load Zone as follows:
AdjLBMPSy,z, the adjusted LBMP savings for each Load Zone z in each year y, shall be calculated using the following equation:

ܣ݆𝐴𝐴௬,௭ = max �0, 𝑇y,z − � �ܤ𝐵b,y,z ∗ �1 − ܫ𝐼b,y,z�� − ܵܩy,z� ∗ �𝐿𝐿1y,z − 𝐿𝐿2y,z�

௕∈஻೤,೥

Where:

TLy,z is the total annual amount of Energy forecasted to be consumed by Load in year y in Load Zone z;

By,z is the set of blocks of Energy to serve Load in Load Zone z in year y that are sold under bilateral contracts for which information has been provided to the ISO that meets the requirements set forth elsewhere in this Section 31.5.4.4.2.5

BCLb,y,z is the total annual amount of Energy sold into Load Zone z in year y under bilateral contract block b;

Indb,y,z is the ratio of (1) the increase in the amount paid by the purchaser of Energy,

under bilateral contract block b, as a result of an increase in the LBMP in Load Zone z in year y
to (2) the increase in the amount that a purchaser of that amount of Energy would pay if the
purchaser paid the LBMP for that Load Zone in that year for all of that Energy (this ratio shall be

zero for any bilateral contract block of Energy that is sold at a fixed price or for which the cost of
Energy purchased under that contract otherwise insensitive to the LBMP in Load Zone z in year

y);

SGy,z is the total annual amount of Energy in Load Zone z that is forecasted to be served by LSE-owned generation in that Zone in year y;

LBMP1y,z is the forecasted annual load-weighted average LBMP for Load Zone z in year y, calculated under the assumption that the project is not in place; and
LBMP2y,z is the forecasted annual load-weighted average LBMP for Load Zone z in year y, calculated under the assumption that the project is in place.

31.5.4.4.2.6    NZSz, the Net Zonal Savings for each Load Zone z resulting from a given
project, shall be calculated using the following equation:

௉ௌ+9

ܰ𝑁௭ = max �0, � ��ܣ݆𝐴𝐴y,z − 𝑇ܴݒ𝑇݌𝑇y,z� ∗ ܦy��

௬=௉ௌ

Where:

PS is the year in which the project is expected to enter commercial operation; AdjLBMPSy,z is as calculated in Section 31.5.4.4.2.5;

TCCRevImpacty,z is the forecasted impact of TCC revenues allocated to Load Zone z in year y, calculated using the procedure described in Appendix B in Section 31.7 of this
Attachment Y; and

DFy is the discount factor applied to cash flows in year y to determine the present value of that cash flow in year PS.

31.5.4.4.3Load Zones not benefiting from a proposed RETP will not be allocated

any of the costs of the project under this Attachment Y.  There will be no “make whole” payments to non-beneficiaries.

31.5.4.4.4 Costs of a project will be allocated to beneficiaries as follows:

31.5.4.4.4.1   The ISO will allocate the cost of the RETP based on the zonal share of
total savings to the Load Zones determined pursuant to Section 31.5.4.4.2 to be
beneficiaries of the proposed project.  Total savings will be equal to the sum of
load savings for each Load Zone that experiences net benefits pursuant to Section

31.5.4.4.2.  A Load Zone’s cost allocation will be equal to the present value of the following calculation:

(Zonal Benefits)

Zonal Cost Allocation = Project Cost ∗ �

Total Zonal Benefits for zone with positive net benefits�

31.5.4.4.4.2   Zonal cost allocation calculations for a RETP will be performed prior to

the commencement of the ten-year period that begins with the project’s

commercial operation date, and will not be adjusted during that ten-year period.

31.5.4.4.4.3   Within zones, costs will be allocated to LSEs based on MWhs calculated
for each LSE for each zone using data from the most recent available 12 month
period.  Allocations to an LSE will be calculated in accordance with the following
formula:

LSE Intrazonal Cost Allocation = Zonal Cost Allocation ∗ � LSE Zonal MWh              �

Total Zonal MWh

31.5.4.4.5Project costs allocated under this Section 31.5.4.4 will be determined as

follows:

31.5.4.4.5.1   The project cost allocated under this Section 31.5.4.4 will be based on the
total project revenue requirement, as supplied by the Developer of the project, for
the first ten years of project operation.  The total project revenue requirement will
be determined in accordance with the formula rate on file at the Commission.  If
there is no formula rate on file at the Commission, then the Developer shall
provide to the ISO the project-specific parameters to be used to calculate the total
project revenue requirement.

31.5.4.4.5.2   Once the benefit/cost analysis is completed the amortization period and
the other parameters used to determine the costs that will be recovered for the
project should not be changed, unless so ordered by the Commission or a court of
applicable jurisdiction, for cost recovery purposes to maintain the continued
validity of the benefit/cost analysis.

31.5.4.4.5.3   The ISO, in conjunction with the ESPWG, will develop procedures to
allocate the risk of project cost increases that occur after the ISO completes its
benefit/cost analysis under this Attachment Y.  These procedures may include
consideration of an additional review and vote prior to the start of construction
and whether the developer should bear all or part of the cost of any overruns.

31.5.4.4.6 The Commission must approve the cost of a proposed RETP for that cost

to be recovered through Rate Schedule 10 of the ISO OATT.  The developer’s
filing of its project revenue requirement with the Commission pursuant to Rate
Schedule 10 must be consistent with the project proposal evaluated by the ISO
under this Attachment Y in order to be cost allocated to beneficiaries.

31.5.4.5   Collaborative Governance Process and Board Action

31.5.4.5.1 The ISO shall submit the results of its project benefit/cost analysis and

beneficiary determination to the ESPWG and TPAS, and to the identified

beneficiaries of the proposed RETP for comment.  The ISO shall make available
to any interested party sufficient information to replicate the results of the
benefit/cost analysis and beneficiary determination.  The information made
available will be electronically masked and made available pursuant to a process
that the ISO reasonably determines is necessary to prevent the disclosure of any
Confidential Information or Critical Energy Infrastructure Information contained
in the information made available.  Following completion of the review by the
ESPWG and TPAS of the project benefit/cost analysis, the ISO’s analysis
reflecting any revisions resulting from the TPAS and ESPWG review shall be
forwarded to the Business Issues Committee and Management Committee for
discussion and action.

31.5.4.5.2 Following the Management Committee vote, the ISO’s project benefit/cost

analysis and beneficiary determination will be forwarded, with the input of the
Business Issues Committee and Management Committee, to the ISO Board for
review and action.  In addition, the ISO’s determination of the beneficiaries’
voting shares will be forwarded to the ISO Board for review and action.  The
Board may approve the analysis and beneficiary determinations as submitted or
propose modifications on its own motion.  If any changes to the benefit/cost

analysis or the beneficiary determinations are proposed by the Board, the revised
analysis and beneficiary determinations shall be returned to the Management
Committee for comment.  If the Board proposes any changes to the ISO’s voting

share determinations, the Board shall so inform the LSE or LSEs impacted by the proposed change and shall allow such an LSE or LSEs an opportunity to comment on the proposed change.  The Board shall not make a final determination on the
project benefit/cost analysis and beneficiary determination until it has reviewed
the Management Committee comments.  Upon final approval of the Board,
project benefit/cost analysis and beneficiary determinations shall be posted by the ISO on its website and shall form the basis of the beneficiary voting described in Section 31.5.4.6 of this Attachment Y.

31.5.4.6   Voting by Project Beneficiaries

31.5.4.6.1 Only LSEs serving Load located in a beneficiary zone determined in

accordance with the procedures in Section 31.5.4.4 of this Attachment Y shall be
eligible to vote on a proposed project.  The ISO will, in conjunction with the
ESPWG, develop procedures to determine the specific list of voting entities for
each proposed project.  Prior to a vote being conducted, the Developer of the
RETP must have a completed System Impact Study or System Reliability Impact
Study, as applicable.

31.5.4.6.2The voting share of each LSE shall be weighted in accordance with its

share of the total project benefits, as allocated by Section 31.5.4.4 of this

Attachment Y.

31.5.4.6.3 The costs of a RETP shall be allocated under this Attachment Y if eighty

percent (80%) or more of the actual votes cast on a weighted basis are cast in favor of implementing the project.

31.5.4.6.4If the proposed RETP meets the required vote in favor of implementing

the project, and the project is implemented, all beneficiaries, including those voting “no,” will pay their proportional share of the cost of the project.

31.5.4.6.5 The ISO will tally the results of the vote in accordance with procedures set

forth in the ISO Procedures, and report the results to stakeholders.  Beneficiaries
voting against approval of a project must submit to the ISO their rationale for
their vote within 30 days of the date that the vote is taken.  Beneficiaries must
provide a detailed explanation of the substantive reasons underlying the decision,
including, where appropriate: (1) which additional benefit metrics, either
identified in the tariff or otherwise, were used; (2) the actual quantification of
such benefit metrics or factors; (3) a quantification and explanation of the net
benefit or net cost of the project to the beneficiary; and (4) data supporting the
metrics and other factors used.  Such explanation may also include uncertainties,
and/or alternative scenarios and other qualitative factors considered, including
state public policy goals.  The ISO will report this information to the Commission
in an informational filing to be made within 60 days of the vote.  The
informational filing will include: (1) a list of the identified beneficiaries; (2) the
results of the benefit/cost analysis; and (3) where a project is not approved,
whether the developer has provided any formal indication to the ISO as to the
future development of the project.

31.5.5Regulated Transmission Solutions to Public Policy Transmission Needs

31.5.5.1   The Scope of Section 31.5.5

As discussed in Section 31.5.1 of this Attachment Y, the cost allocation principles and
methodologies of this Section 31.5.5 apply only to regulated Public Policy Transmission
Projects.  This Section 31.5.5 does not apply to Other Public Policy Projects, including
generation or demand side management projects, or any market-based projects.  This Section

31.5.5 does not apply to regulated reliability solutions implemented pursuant to the reliability

planning process, nor does it apply to RETPs proposed in response to congestion identified in the
CARIS.

A regulated solution shall only utilize the cost allocation methodology set forth in Section

31.5.3 where it is:  (1) a Responsible Transmission Owner’s regulated backstop solution,  (2) an alternative regulated transmission solution selected by the ISO as the more efficient or cost
effective regulated transmission solution to satisfy a Reliability Need, or (3) seeking cost
recovery where it has been halted or cancelled pursuant to the provisions of Section 31.2.8.2.  A regulated economic transmission solution proposed in response to congestion identified in the CARIS, and approved pursuant to Section 31.5.4.6, shall only be eligible to utilize the cost
allocation principles and methodologies set forth in Section 31.5.4.

31.5.5.2Cost Allocation Principles

The ISO shall implement the specific cost allocation methodology in Section 31.5.5.4 of this Attachment Y in accordance with the Order No. 1000 Regional Cost Allocation Principles as set forth in Section 31.5.2.1.  The specific cost allocation methodology in Section 31.5.5.4
incorporates the following elements:

31.5.5.2.1The focus of the cost allocation methodology shall be on regulated Public

Policy Transmission Projects.

31.5.5.2.2Projects analyzed hereunder as Public Policy Transmission Projects may

proceed on a market basis with willing buyers and sellers at any time.

31.5.5.2.3Cost allocation shall be based on a beneficiaries pay approach.

31.5.5.2.4Project benefits will be identified in accordance with Section 31.5.5.4.

31.5.5.2.5Identification of beneficiaries for cost allocation and cost allocation

among those beneficiaries shall be according to the methodology specified in Section 31.5.5.4.

31.5.5.3   Project Eligibility for Cost Allocation

The Developer of a Public Policy Transmission Project will be eligible for cost allocation
in accordance with the process set forth in Section 31.5.5.4 when its project is selected by the
ISO as the more efficient or cost effective regulated Public Policy Transmission Project;
provided, however, that if the appropriate federal, state, or local agency(ies) rejects the selected
project’s necessary authorizations, or such authorizations are withdrawn, the costs the Developer
is eligible to recover under Section 31.4.12.1 shall be allocated in accordance with Section

31.5.5.4.3, except as otherwise determined by the Commission.  The Developer of the selected
regulated transmission solution may recover its costs in accordance with Section 31.5.6 and Rate
Schedule 10 of the ISO OATT.  If the Developer proposed its Public Policy Transmission Project
in response to a request by the NYPSC or Long Island Power Authority pursuant to Section

31.4.3.2 and its project was not selected by the ISO, the costs that the Developer is eligible to recover pursuant to Section 31.4.3.2 shall be allocated in accordance with Section 31.5.5.4.3, except as otherwise determined by the Commission.  The Developer may recover these costs in accordance with Section 31.5.6 and Rate Schedule 10 of the ISO OATT.

31.5.5.4   Cost Allocation for Eligible Projects

As noted in Section 31.5.5.2 of this Attachment Y, the identification of beneficiaries for
cost allocation and the cost allocation of a selected Public Policy Transmission Project will be
conducted in accordance with the process described in this Section 31.5.5.4.  This Section will
also apply to the allocation within New York of the ISO’s share of the costs of an Interregional
Transmission Project proposed as a solution to a Public Policy Transmission Need allocated in
accordance with Section 31.5.7 of this Attachment Y.  The establishment of a cost allocation
methodology and rates for a proposed solution that is undertaken by LIPA or NYPA as an

Unregulated Transmitting Utility to a Public Policy Transmission Need as determined in

Sections 31.4.2.1 through 31.4.2.3, as applicable, or an Interregional Transmission Project shall
occur pursuant to Section 31.5.5.4.4 through 31.5.5.4.6, as applicable.  Nothing herein shall
deprive a Transmission Owner or Other Developer of any rights it may have under Section 205
of the Federal Power Act to submit filings proposing any other cost allocation methodology to
the Commission or create any Section 205 filing rights for any Transmission Owner, Other
Developer, the ISO, or any other entity.  The ISO shall apply the cost allocation methodology
accepted by the Commission.  The cost allocation methodology that is accepted or approved by
the Commission for a particular Public Policy Transmission Project in accordance with this
Section 31.5.5.4 will be set forth in Appendix E (Section 31.8) of this Attachment Y.

31.5.5.4.1 If the Public Policy Requirement that results in the identification by the

NYPSC of a Public Policy Transmission Need prescribes the use of a particular
cost allocation and recovery methodology, then the ISO shall file that
methodology with the Commission within 60 days of the issuance by the NYPSC
of its identification of a Public Policy Transmission Need. Nothing herein shall
deprive a Transmission Owner or Other Developer of any rights it may have

under Section 205 of the Federal Power Act to submit filings proposing any other
cost allocation methodology to the Commission or create any Section 205 filing
rights for any Transmission Owner, Other Developer, the ISO, or any other entity.
If the Developer files a different proposed cost allocation methodology under
Section 205 of the Federal Power Act, it shall have the burden of demonstrating
that its proposed methodology is compliant with the Order No. 1000 Regional
Cost Allocation Principles taking into account the methodology specified in the
Public Policy Requirement.

31.5.5.4.2 Subject to the provisions of Section 31.5.5.4.1, the Developer may submit

to the NYPSC for its consideration - no later than 30 days after the ISO’s

selection of the regulated Public Policy Transmission Project - a proposed cost
allocation methodology, which may include a cost allocation based on load ratio
share, adjusted to reflect, as applicable, the Public Policy Requirement or Public
Policy Transmission Need, the party(ies) responsible for complying with the
Public Policy Requirement, and the party(ies) who benefit from the transmission
facility.

31.5.5.4.2.1   The NYPSC shall have 150 days to review the Developer’s proposed cost
allocation methodology and to inform the Developer regarding whether it
supports the methodology.

31.5.5.4.2.2.   If the NYPSC supports the proposed cost allocation methodology, the

Developer shall file that cost allocation methodology with the Commission for its
acceptance under Section 205 of the Federal Power Act within 30 days of the
NYPSC informing the Developer of its support.  The Developer shall have the

burden of demonstrating that the proposed cost allocation methodology is
compliant with the Order No. 1000 Regional Cost Allocation Principles.

31.5.5.4.2.3   If the NYPSC does not support the proposed cost allocation methodology,
then the Developer shall take reasonable steps to respond to the NYPSC’s
concerns and to develop a mutually agreeable cost allocation methodology over a
period of no more than 60 days after the NYPSC informing the Developer that it
does not support the methodology.

31.5.5.4.2.4   If a mutually acceptable cost allocation methodology is developed during
the timeframe set forth in Section 31.5.5.4.2.3, the Developer shall file it with the
Commission for acceptance under Section 205 of the Federal Power Act no later
than 30 days after the conclusion of the 60 day discussion period with the
NYPSC.  The Developer shall have the burden of demonstrating that the proposed
cost allocation methodology is compliant with the Order No. 1000 Regional Cost
Allocation Principles.

31.5.5.4.2.5   If no mutually agreeable cost allocation methodology is developed, the
Developer shall file its preferred cost allocation methodology with the
Commission for acceptance under Section 205 of the Federal Power Act no later
than 30 days after the conclusion of the 60 day discussion period with the
NYPSC.  The Developer shall have the burden of demonstrating that its proposed
methodology is compliant with the Order No. 1000 Regional Cost Allocation
Principles in consideration of the position of the NYPSC. The filing shall include
the methodology supported by NYPSC for the Commission’s consideration. If the
Developer elects to use the load ratio share cost allocation methodology

referenced below in Section 31.5.5.4.3, the Developer shall notify the

Commission of its intent to utilize the load ratio share methodology and shall include in its notice the NYPSC supported methodology for the Commission’s consideration.

31.5.5.4.3. Unless the Commission has accepted an alternative cost allocation

methodology pursuant to this Section, the ISO shall allocate the costs of the
Public Policy Transmission Project to all Load Serving Entities in the NYCA
using the default cost allocation methodology, based upon a load ratio share
methodology.

31.5.5.4.4 The NYISO will make any Section 205 filings related to this Section on

behalf of NYPA to the extent requested to do so by NYPA.  NYPA shall bear the
burden of demonstrating that such a filing is compliant with the Order No. 1000
Regional Cost Allocation Principles.  NYPA shall also be solely responsible for
making any jurisdictional reservations or arguments related to their status as non-
Commission-jurisdictional utilities that are not subject to various provisions of the
Federal Power Act.

31.5.5.4.5 The cost allocation methodology and any rates for cost recovery for a

proposed solution to a Public Policy Transmission Need undertaken by LIPA, as an Unregulated Transmitting Utility (for purposes of this section a “LIPA
project”), shall be established and recovered as follows:

31.5.5.4.5.1   For costs solely to LIPA customers. The cost allocation methodology and
rates to be established for a LIPA project, for which cost recovery will only occur
from LIPA customers, will be established pursuant to Article 5, Title 1-A of the

New York Public Authorities Law, Sections 1020-f(u) and 1020-s.  Prior to the
adoption of any cost allocation mechanism or rates for such a LIPA project, and
pursuant to Section 1020-f(u), the Long Island Power Authority’s Board of
Trustees shall request that the NYDPS provide a recommendation with respect to
the cost allocation methodology and rate that LIPA has proposed and the Board of
Trustees shall consider such recommendation in accordance with the requirements
of Section 1020-f(u).  Upon approval of the cost allocation mechanism and/or
rates by the Long Island Power Authority’s Board of Trustees, LIPA shall provide
to the ISO, for purposes of inclusion within the ISO OATT and filing with FERC
on an informational basis only, a description of the cost allocation mechanism and
the rate that LIPA will charge and collect within the Long Island Transmission
District.

31.5.5.4.5.2    For Costs for a LIPA Project That May be Allocated to Other

Transmission Districts.  A LIPA project that meets a Public Policy Transmission
Need as determined by the NYPSC pursuant to Section 31.4.2.3(iii) may be
allocated to market participants outside of the Long Island Transmission District.
The cost allocation methodology and rate for such a LIPA project shall be
established in accordance with the following procedures.  LIPA’s proposed cost
allocation methodology and/or rate shall be reviewed and approved by the Long
Island Power Authority’s Board of Trustees pursuant to Article 5, Title 1-A of the
New York Public Authorities Law, Sections 1020-f(u) and 1020-s.  Prior to the
adoption of any cost allocation mechanism or rates for such project and pursuant
to Section 1020-f(u), the Long Island Power Authority’s Board of Trustees shall

request that the NYDPS provide a recommendation with respect to the cost

allocation methodology and rate that LIPA has proposed and the Board of

Trustees shall consider such recommendation in accordance with the requirements
of Section 1020-f(u).  LIPA shall inform the ISO of the cost allocation
methodology and rate that has been approved by the Long Island Power
Authority’s Board of Trustees for filing with the Commission.
Upon approval by the Long Island Power Authority’s Board of Trustees, LIPA shall submit and request that the ISO file the LIPA cost allocation
methodology for approval with the Commission.  Any cost allocation
methodology for a LIPA project that allocates costs to market participants outside
of the Long Island Transmission District shall be reviewed as to whether there is
comparability in the derivation of the cost allocation for market participants such
that LIPA has demonstrated that the proposed cost allocation is compliant with
the Order No. 1000 cost allocation principles, there are benefits provided by the
project to market participants outside of the Long Island Transmission District,
and that the proposed allocation is roughly commensurate to the identified
benefits.

Article 5, Title 1-A of the New York Public Authorities Law, Sections

1020-f(u) and 1020-s, requires that LIPA’s rates be established at the lowest level
consistent with sound fiscal and operating practices of the Long Island Power
Authority and which provide for safe and adequate service. Upon approval of a
LIPA rate by the Long Island Power Authority’s Board of Trustees pursuant to
Section 1020-f(u), LIPA shall submit, and request that the ISO file, the LIPA rate

with the Commission for review under the same comparability standard as applied to the review of changes in LIPA’s TSC under Attachment H of this tariff.
In the event that the cost allocation methodology or rate approved by the Long Island Power Authority’s Board of Trustees did not adopt the NYDPS
recommendation, the NYDPS recommendation shall be included in the filing for the Commission’s consideration.

31.5.5.4.5.3    Support for Filing.  LIPA shall intervene in support of the filing(s) made
pursuant to Section 31.5.5.4.5 at the Commission and shall take the responsibility
to demonstrate that: (i) the cost allocation methodology and/or rate approved by
the Long Island Power Authority’s Board of Trustees meets the applicable
standard of comparability, and (ii) the Commission should accept such
methodology or rate for filing.  LIPA shall also be responsible for responding to,
and seeking to resolve, concerns about the contents of the filing that might be
raised in such proceeding.

31.5.5.4.5.4    Billing of LIPA Charges Outside of the Long Island Transmission District.
For Transmission Districts other than the Long Island Transmission District, the
ISO shall bill for LIPA, as a separate charge, the costs incurred by LIPA for a
solution to a Public Policy Transmission Need allocated using the cost allocation
methodology and rates established pursuant to Section 31.5.5.4.5.2 and accepted
for filing by the Commission and shall remit the revenues collected to LIPA each
Billing Period in accordance with the ISO’s billing and settlement procedures.

31.5.5.4.6 The inclusion in the ISO OATT or in a filing with the Commission of the

cost allocation and charges for recovery of costs incurred by NYPA or LIPA

related to a solution to a transmission need driven by a Public Policy Requirement
or Interregional Transmission Project as provided for in Sections 31.5.5.4.4 and

31.5.5.4.5 shall not be deemed to modify the treatment of such rates as nonjurisdictional pursuant to Section 201(f) of the FPA.

31.5.6 Cost Recovery for Regulated Projects

31.5.6.1   Cost Recovery for Regulated Transmission Project to Address a
Reliability Need

31.5.6.1.1 A Responsible Transmission Owner, a Transmission Owner, or an Other

Developer may recover in accordance with Rate Schedule 10 of the ISO OATT
the costs incurred with respect to the implementation of: (i) a regulated backstop
transmission solution proposed by a Responsible Transmission Owner pursuant to

Section 31.2.4.3.1 of this Attachment Y and the ISO/TO Reliability Agreement or
an Operating Agreement; (ii) an alternative regulated transmission solution that
the ISO has selected pursuant to Section 31.2.6.5.2 of this Attachment Y as the

more efficient or cost-effective solution to a Reliability Need; (iii) a regulated
transmission Gap Solution proposed by a Responsible Transmission Owner
pursuant to Section 31.2.11.4 of this Attachment Y; or (iv) an alternative

regulated transmission Gap Solution that has been determined by the appropriate state regulatory agency(ies) as the preferred solution(s) to a Reliability Need pursuant to Section 31.2.11.5 of Attachment Y of the ISO OATT.

31.5.6.1.2 If a regulated solution: (i) is eligible for cost recovery as described in

Section 31.5.6.1.1 and (ii) is not triggered or is halted pursuant to Sections 31.2.8
or 31.2.10.1.2 of this Attachment Y, the Responsible Transmission Owner,
Transmission Owner or Other Developer of that solution may recover the costs

that it eligible to recover pursuant to Sections 31.2.8 or 31.2.10.1.2 in accordance with Rate Schedule 10 of the ISO OATT.

31.5.6.1.3 Costs related to non-transmission regulated solutions to Reliability Needs

will be recovered by a Responsible Transmission Owner, Transmission Owner, or
Other Developer in accordance with the provisions of New York Public Service
Law, New York Public Authorities Law, or other applicable state law.  A
Responsible Transmission Owner, a Transmission Owner, or Other Developer
may propose and undertake a regulated non-transmission solution, provided that
the appropriate state agency(ies) has established cost recovery procedures
comparable to those provided in this tariff for regulated transmission solutions to
ensure the full and prompt recovery of all reasonably-incurred costs related to
such non-transmission solutions.  Nothing in this section shall affect the
Commission’s jurisdiction over the sale and transmission of electric energy
subject to the jurisdiction of the Commission.

31.5.6.2   Cost Recovery for Regulated Economic Transmission Project

A Transmission Owner or an Other Developer may recover in accordance with Rate Schedule 10 of the ISO OATT the costs incurred with respect to the implementation a regulated economic transmission project that has been
approved pursuant to Section 31.5.4.6 of this Attachment Y.

31.5.6.3   Cost Recovery for Regulated Transmission Project to Address a Public
Policy Transmission Need

31.5.6.3.1 A Transmission Owner or an Other Developer may recover in accordance

with Rate Schedule 10 of the ISO OATT the costs incurred with respect to the

implementation of: (i) a Public Policy Transmission Project that the ISO has
selected as the more efficient or cost-effective solution to a Public Policy
Transmission Need, or (ii) a Public Policy Transmission Project proposed by a
Developer in response to a request by the NYPSC or Long Island Power
Authority in accordance with Section 31.4.3.2 of Attachment Y of the ISO OATT. Such cost recovery will also include reasonable costs incurred by the Developer to provide a more detailed study or cost estimate for such project at the request of
the NYPSC, and to prepare the application required to comply with New York
Public Service Law Article VII, or any successor statute or any other applicable permits, and to seek other necessary authorizations.

31.5.6.3.2 If a regulated solution that: (i) is eligible for cost recovery as described in

Section 31.5.6.3.1 and (ii) is halted as described in Section 31.4.12.1 of this

Attachment Y, the Transmission Owner or Other Developer of that solution may recover the costs that it is eligible to recover pursuant to Section 31.4.12.1 in accordance with Rate Schedule 10 of the ISO OATT.

31.5.6.4   Cost Recovery for Interregional Transmission Project

A Responsible Transmission Owner, a Transmission Owner, or an Other Developer may
recover in accordance with Rate Schedule 10 of the ISO OATT the costs incurred with respect to
the implementation of the portion of an Interregional Transmission Project selected by the ISO in
the CSPP that is allocated to the NYISO region pursuant to Section 31.5.7 of Attachment Y of
the ISO OATT.

31.5.7Cost Allocation for Eligible Interregional Transmission Projects

31.5.7.1    Costs of Approved Interregional Transmission Projects

The cost allocation methodology reflected in this Section 31.5.7.1 shall be referred to as the “Northeastern Interregional Cost Allocation Methodology” (or “NICAM”), and shall not be modified without the mutual consent of the Section 205 rights holders in each region.

The costs of Interregional Transmission Projects, as defined in the Interregional Planning
Protocol, evaluated under the Interregional Planning Protocol and selected by ISO-NE, PJM and
the ISO in their regional transmission plans for purposes of cost allocation under their respective
tariffs shall, when applicable, be allocated to the ISO-NE region, PJM region and the ISO region
in accordance with the cost allocation principles of FERC Order No. 1000, as follows:

(a) To be eligible for interregional cost allocation, an Interregional Transmission

Project must be selected in the regional transmission plan for purposes of cost allocation in each of the transmission planning regions in which the transmission project is proposed to be located, pursuant to agreements and tariffs on file at FERC for each region. With respect to Interregional Transmission Projects and other transmission projects involving the ISO and PJM, the cost
allocation of such projects shall be in accordance with the Joint Operating Agreement (“JOA”) among and between the ISO and PJM.  With respect to Interregional Transmission Projects and other transmission projects involving the ISO and ISO-NE, the cost allocation for such projects shall be in accordance with this Section 31.5.7 of Attachment Y of the NYISO Open Access
Transmission Tariff and with the respective tariffs of ISO-NE.

(b) The share of the costs of an Interregional Transmission Project allocated to a

region will be determined by the ratio of the present value of the estimated costs of such region’s
displaced regional transmission project to the total of the present values of the estimated costs of

the displaced regional transmission projects in all regions that have selected the Interregional Transmission Project in their regional transmission plans.

(i) The present values of the estimated costs of each region’s displaced regional

transmission project shall be based on a common base date that will be the

beginning of the calendar month of the cost allocation analysis for the subject Interregional Transmission Project (the “Base Date”).

(ii) In order to perform the analysis in this Section 31.5.7.1(b), the estimated cost of

the displaced regional transmission projects shall specify the year’s dollars in which those estimates are provided.

(iii) The present value analysis for all displaced regional transmission projects shall

use a common discount rate. The regions having displaced projects will mutually
agree, in consultation with their respective transmission owners, and for purposes
of the ISO, its other stakeholders, on the discount rate to be used for the present
value analysis.

(iv) For the purpose of this allocation, cost estimates shall use comparable cost

estimating procedures.  In the Interregional Planning Stakeholder Advisory

Committee review process, the regions having displaced projects will review and
determine, in consultation with their respective transmission owners, and for
purposes of the NYISO, its other stakeholders, that reasonably comparable
estimating procedures have been used prior to applying this cost allocation.

(c) No cost shall be allocated to a region that has not selected the Interregional Transmission Project in its regional transmission plan.

(d)When a portion of an Interregional Transmission Project evaluated under the

Interregional Planning Protocol is included by a region (Region 1) in its regional transmission

plan but there is no regional need or displaced regional transmission project in Region 1, and the neighboring  region (Region 2) has a regional need or displaced regional project for  the
Interregional Transmission Project and selects the Interregional Transmission Project in its
regional transmission plan, all of the costs of the Interregional Transmission Project shall be
allocated to Region 2 in accordance with the NICAM and none of the costs shall be allocated to Region 1. However, Region 1  may voluntarily agree, with the mutual consent of the Section 205 rights holders in the other affected region(s) (including  the Long Island Power Authority and the New York Power Authority in the NYISO region) to  use  an alternative cost allocation method filed with and accepted by the Commission.

(e) The portion of the costs allocated to a region pursuant to the NICAM shall be

further allocated to that region’s transmission customers pursuant to the applicable provisions of
the region’s FERC-filed documents and agreements, for the ISO in accordance with Section

31.5.1.7 of Attachment Y of the ISO OATT.

(f)The following example illustrates the cost allocation for such an Interregional

Transmission Project:

•   A cost allocation analysis of the costs of Interregional Transmission Project Z is to be
performed during a given month establishing the beginning of that month as the Base
Date.

•   Region A has identified a reliability need in its region and has selected a transmission
project (Project X) as the preferred solution in its regional plan.  The estimated cost of

Project X is: Cost (X), provided in a given year’s dollars. The number of years from
the Base Date to the year associated with the cost estimate of Project (X) is:  N(X). • Region B has identified a reliability need in its region and has selected a transmission
project (Project Y) as the preferred solution in its Regional Plan.  The estimated cost
of Project Y is: Cost (Y), provided in a given year’s dollars. The number of years
from the Base Date to the year associated with the cost estimate of Project (Y) is:
N(Y).

• Regions A and B, through the interregional planning process have determined that an

Interregional Transmission Project (Project Z) will address the reliability needs in

both regions more efficiently and cost-effectively than the separate regional projects. The estimated cost of Project Z is:  Cost (Z). Regions A and  B have each determined that  Interregional Transmission Project Z is the preferred solution to their reliability needs and have adopted that Interregional  Transmission  Project in their respective regional plans in lieu of Projects X and Y respectively. If Regions A and B have
agreed to bear the costs of upgrades in other affected transmission planning regions, these costs will be considered part of Cost (Z).

•The discount rate used for all displaced regional transmission projects is:  D

•Based on the foregoing assumptions, the following formulas will be used:

   Present Value of Cost (X) = PV Cost (X) = Cost (X) / (1+D)N(X)

   Present Value of Cost (Y) = PV Cost (Y) = Cost (Y) / (1+D)N(Y)

   Cost Allocation to Region A = Cost (Z) x PV Cost (X)/[PV Cost (X) + PV
Cost (Y)]

   Cost Allocation to Region B = Cost (Z) x PV Cost (Y)/[PV Cost (X) + PV
Cost (Y)]

•   Applying those formulas, if:

Cost (X) = $60 Million and N(X) = 8.25 years Cost (Y) = $40 Million and N(Y) = 4.50 years Cost (Z) = $80 Million

D = 7.5%  per year
Then:

PV Cost (X) = 60/(1+0.075) 8.25   =  33.039 Million
PV Cost (Y) = 40/(1+0.075)4.50 =  28.888 Million

Cost Allocation to Region A = $80 x 33.039/(33.039 + 28.888) = $42,681 Million
Cost Allocation to Region B = $80 x 28.888/(33.039+28.888) = $37.319 Million

31.5.7.2    Other Cost Allocation Arrangements

(a) Except as provided in Section 31.5.7.2(b), the NICAM is the exclusive means by which any costs of an Interregional Transmission Project may be allocated between or among PJM, the ISO, and ISO-NE.

(b) Nothing in the FERC-filed documents of ISO-NE, the ISO or PJM shall preclude
agreement by entities with cost allocation rights under Section 205 of the Federal Power Act for
their respective regions (including  the Long Island Power Authority and the New York Power
Authority in the ISO region) to enter into separate agreements to  allocate the cost-of
Interregional Transmission Projects proposed to be located in their regions as an alternative to
the NICAM, or other transmission projects identified pursuant to assessments and studies
conducted pursuant to Section 6 of the Interregional Planning Protocol.  Such other cost-

allocation methodologies must be approved in each region pursuant to the Commission-approved rules in each region, filed with and accepted by the Commission, and shall apply only to the
region's share of the costs of an Interregional Transmission Project or other transmission projects pursuant to Section 6 of the Interregional Planning Protocol, as applicable.

31.5.7.3    Filing Rights

Nothing in this Section 31.5.7 will convey, expand, limit or otherwise alter any rights of ISO-NE, the ISO, PJM, each region’s transmission owners, market participants, or other entities to submit filings under Section 205 of the Federal Power Act regarding interregional cost
allocation or any other matter.

Where applicable, the regions have been authorized by entities that have cost allocation rights for their respective regions to implement the provisions of this Section 31.5.7.

31.5.7.4.   Merchant Transmission and Individual Transmission Owner Projects

Nothing in this Section 31.5.7 shall preclude the development of Interregional Transmission Projects that are funded solely by merchant transmission developers or by individual transmission owners.

31.5.7.5    Consequences to Other Regions from Regional or Interregional
Transmission Projects

Except as provided herein in Sections 31.5.7.1 and 31.5.7.2, or where cost responsibility
is expressly assumed by ISO-NE, the ISO or PJM in other documents, agreements or tariffs on
file with FERC, neither the ISO-NE region, the ISO region nor the PJM region shall be
responsible for compensating another region or each other for required upgrades or for any other
consequences in another planning region associated with regional or interregional transmission
facilities, including but not limited to, transmission projects identified pursuant to Section 6 of

the Interregional Planning Protocol and Interregional Transmission Projects identified pursuant to Section 7 of the Interregional Planning Protocol.