31.4Cost Allocation and Cost Recovery

31.4.1The Scope of Attachment Y Cost Allocation

31.4.1.1Regulated Responses

The cost allocation principles and methodologies in this Attachment Y cover only regulated transmission solutions to Reliability Needs and regulated transmission responses to congestion identified in the CARIS, whether proposed by a Responsible Transmission Owner or a Transmission Owner or Other Developer.  The cost allocation principles and methodology covering regulated transmission solutions to Reliability Needs are contained in Sections 31.4.2.1 and 31.4.2.2 of this Attachment Y.  The separate cost allocation principles and methodology covering regulated transmission responses to congestion identified in the CARIS are contained in Sections 31.4.3.1 and 31.4.3.2 of this Attachment Y.

31.4.1.2Market-Based Responses

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

31.4.1.3Interconnection Cost Allocation

The cost allocation principles and methodologies in this Attachment Y do not apply to the interconnection costs of generation and merchant transmission projects.  Interconnection costs are determined and allocated in accordance with Attachment S and Attachment X and Attachment Z of the NYISO OATT.

31.4.1.4Individual 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 NYISO OATT.

31.4.1.5LTP 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.

31.4.1.6Regulated Non-Transmission Solutions to Reliability Needs

Costs related to regulated non-transmission reliability 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.

31.4.2Regulated Responses to Reliability Needs

31.4.2.1Cost Allocation Principles

Cost allocation for regulated transmission solutions to Reliability Needs shall be determined by the NYISO based upon the principle that beneficiaries should bear the cost responsibility. The specific cost allocation methodology, to be developed by the NYISO in consultation with the ESPWG, will incorporate the following elements:

31.4.2.1.1The focus of the cost allocation methodology shall be on solutions to violations of specific Reliability Criteria.

31.4.2.1.2Potential impacts unrelated to addressing the Reliability Needs shall not be considered for the purpose of cost allocation for regulated solutions.

31.4.2.1.3Primary beneficiaries shall initially be those Transmission Districts identified as contributing to the reliability violation.

31.4.2.1.4The cost allocation among primary beneficiaries shall be based upon their relative contribution to the need for the regulated solution.

31.4.2.1.5The NYISO 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).

31.4.2.1.6Cost allocation among Transmission Districts shall recognize the terms of prior agreements among the Transmission Owners, if applicable.

31.4.2.1.7Consideration should be given to the use of a materiality threshold for cost allocation purposes.

31.4.2.1.8The methodology shall provide for ease of implementation and administration to minimize debate and delays to the extent possible.

31.4.2.1.9Consideration should be given to the “free rider” issue as appropriate.  The methodology shall be fair and equitable.

31.4.2.1.10The methodology shall provide cost recovery certainty to investors to the extent possible.

31.4.2.1.11The methodology shall apply, to the extent possible, to Gap Solutions.

31.4.2.1.12Cost allocation is independent of the actual triggered project(s), except when allocating Minimum Locational Capacity Requirement (“LCR”) cost responsibilities, and is based on a separate process that results in NYCA meeting its LOLE requirement.

31.4.2.1.13The target year is the year in which a need will be met by a backstop solution(s).

31.4.2.1.14The trigger year is the year in which the backstop solution must begin to be implemented, driven by the project lead time.

31.4.2.1.15Cost allocation for a solution that meets the needs of a target year assumes that backstop solutions of prior years have been implemented.

31.4.2.1.16Cost allocation will consider the most recent values for LCRs.  LCR must be met for the target year. 

31.4.2.2Cost Allocation Methodology

31.4.2.2.1General Reliability Solution Cost Allocation Formula:

The cost allocation mechanism for regulated transmission reliability projects, whether proposed by a Responsible Transmission Owner or a Transmission Owner or Other Developer, would be used as a basis for allocating costs associated with projects that are triggered to meet Reliability Needs identified in the RNA.  The formula is not applicable to that portion of a project oversized beyond the smallest technically feasible solution that meets 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 NYISO 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 or merchant transmission projects. 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.  This cost allocation process can be applied to any solution or set of solutions that involve single or multiple cost allocation steps.  One formula can be applied to any solution set:

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.

Three step cost allocation methodology for regulated reliability solutions:

31.4.2.2.1.1Step 1 - LCR Deficiency

31.4.2.2.1.1.1Any 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:

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

31.4.2.2.1.1.2Prior to the LOLE calculation, voltage constrained interfaces will be recalculated to determine the resulting transfer limits when the LCRdef MW are added.

31.4.2.2.1.2Step 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.

31.4.2.2.1.2.1If NYCA is found to be resource limited, the NYISO, 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.

31.4.2.2.1.2.2Cost 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:

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 SolnSize represents the total compensatory MW addressed by the applicable project.

31.4.2.2.1.3Step 3 - Constrained Interface Deficiency.  If the NYCA is not resource limited as determined by the NYCA Free Flow Test, then the NYISO will examine constrained transmission interfaces, using the Binding Interface Test.

31.4.2.2.1.3.1The NYISO 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.

31.4.2.2.1.3.2NYISO 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.

31.4.2.2.1.3.3Zone(s) within areas isolated from the rest of NYCA as a result of constrained interface limits (the “Bounded Regions”) are assigned cost responsibility for the compensatory MW, defined as CIdef, needed to reach an LOLE of 0.1.

31.4.2.2.1.3.4If one or more Bounded Regions are isolated as a result of binding interfaces identified through the Binding Interface Test, the NYISO 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

31.4.2.2.1.3.5The Bounded Regions will be identified by the NYISO’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 NYISO 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.

31.4.2.2.1.3.6The 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:

Allocationi =		Coincident Peaki x (1+IRM-LCRi)	SolnCIdef	
		 Coincident Peakl x (1+IRM-LCRl)	Soln Size

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 So1nSize represents the total compensatory MW addressed by the applicable project.

31.4.2.2.1.4If, after the completion of Steps 1 through 3, there is a thermal or voltage security issue that does not cause an LOLE violation, it will be deemed a local issue and related costs will not be allocated under this process.

31.4.2.2.1.5Costs related to the deliverability of a resource will be addressed under the NYISO’s deliverability procedures.

31.4.2.2.1.6This cost allocation methodology would be used for any projects required to meet Reliability Needs identified in the RNA that are triggered prior to January 1, 2016.  Costs associated with any projects triggered on or after January 1, 2016 will be allocated according to a methodology, which, after proper consideration within the NYISO stakeholder process, will be filed by the NYISO for FERC approval prior to January 1, 2016, in accordance with the NYISO governance process.  The filing may provide for a continuation of the forgoing methodology or a revised methodology.

31.4.3Regulated Economic Projects

31.4.3.1The Scope of Section 31.4.3

As discussed in Section 31.4.1 of this Attachment Y, the cost allocation principles and methodologies of this Section 31.4.3 apply only to regulated economic transmission projects proposed in response to congestion identified in the CARIS.  This Section 31.4.3 does not apply to generation or demand side management projects, nor does it apply to any market-based projects.  This Section 31.4.3 does not apply to regulated backstop solutions triggered by the NYISO pursuant to the Comprehensive Reliability Planning Process, provided, however, the cost allocation principles and methodologies in this Section 31.4.3 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 NYISO 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. 

31.4.3.2Cost Allocation Principles

Cost allocation for regulated transmission responses to NYISO studies of future congestion shall be determined by the NYISO based upon the principle that beneficiaries should bear the cost responsibility.  The specific cost allocation methodology in Section 31.4.3.4 incorporates the following elements:

31.4.3.2.1The focus of the cost allocation methodology shall be on responses to specific conditions identified in studies of future congestion.

31.4.3.2.2Potential impacts unrelated to addressing the identified congestion shall not be considered for the purpose of cost allocation for regulated economic projects.

31.4.3.2.3Economic projects that were previously analyzed can proceed on a market basis with willing buyers and sellers at any time.

31.4.3.2.4Cost allocation shall be based upon a beneficiaries pay approach.  Cost allocation under the NYISO tariff for a regulated economic project shall be applicable only when a super majority of the beneficiaries of the project, as defined in Section 31.4.3.6 of this Attachment Y, vote to support the project.

31.4.3.2.5Beneficiaries of a regulated economic project shall be those entities economically benefiting from the proposed project.  The cost allocation among beneficiaries shall be based upon their relative economic benefit.

31.4.3.2.6Consideration shall be given to the proposed project’s payback period.

31.4.3.2.7The cost allocation methodology shall address the possibility of cost overruns.

31.4.3.2.8Consideration shall be given to the use of a materiality threshold for cost allocation purposes.

31.4.3.2.9The methodology shall provide for ease of implementation and administration to minimize debate and delays to the extent possible.

31.4.3.2.10Consideration should be given to the “free rider” issue as appropriate.  The methodology shall be fair and equitable.

31.4.3.2.11The methodology shall provide cost recovery certainty to investors to the extent possible.

31.4.3.2.12Benefits determination shall consider various perspectives, based upon the agreed-upon metrics for analyzing congestion.

31.4.3.2.13Benefits determination shall account for future uncertainties as appropriate (e.g., load forecasts, fuel prices, environmental regulations).

31.4.3.2.14Benefits determination shall consider non-quantifiable benefits as appropriate (e.g., - system operation, environmental effects, renewable integration).

31.4.3.3Project Eligibility for Cost Allocation

The methodologies in this Section 31.4.3.3 will be used to determine the eligibility of a regulated economic transmission project to have its cost allocated and recovered pursuant to the provisions of this Attachment Y. 

31.4.3.3.1The NYISO will evaluate the benefits and costs of each regulated economic transmission project 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 NYISO to conduct the ten-year cost/benefit analysis of its project.  The NYISO, in conjunction with the ESPWG, will develop methodologies for extending the CSPP study period database as necessary to evaluate the benefits and costs of each regulated economic transmission project.

31.4.3.3.2The benefit metric for eligibility under the NYISO’s cost/benefit 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.

31.4.3.3.3The cost for the NYISO’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 annual total revenue requirement for the project, reasonably allocated over the first ten years from the proposed commercial operation date for the project.

31.4.3.3.4For informational purposes only, the NYISO 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.

31.4.3.3.5To 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.  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 31.4.3.6 of this Attachment Y.

31.4.3.3.6In addition to the eligibility benefit metric used in its benefit/cost analysis, the NYISO will calculate the additional metrics to estimate the potential benefits of the proposed project, for information purposes only, in accordance with Section 31.3.1.3, 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 31.4.3.4.2.3.  The NYISO will provide information on these additional metrics to the maximum extent practicable considering its overall resource commitments.

31.4.3.3.7In addition to the benefit/cost analysis performed by the NYISO under this Section 31.4.3.3, the NYISO will work with the ESPWG to consider the development and implementation of scenario analyses, for information only, that shed additional light on the cost and benefit 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 annual resource commitments of the NYISO.

31.4.3.4Cost Allocation for Eligible Projects

As noted in Section 31.4.3.2 of this Attachment Y, the cost of a regulated economic transmission project will be allocated to those entities that would economically benefit from implementation of the proposed project.

31.4.3.4.1The NYISO 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 NYISO, in conjunction with the ESPWG, will develop methodologies for extending the CSPP study period database as necessary for this purpose.

31.4.3.4.2The NYISO will identify beneficiaries of a proposed project as follows:

31.4.3.4.2.1The NYISO 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 NYISO as set forth in subsection (iv) 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.

31.4.3.4.2.2The beneficiaries will be those load zones who 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 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 NYISO will proceed with the development of the zonal cost allocation information to inform the beneficiary voting process.

31.4.3.4.2.3Net 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, excluding 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.  Calculations of net reductions in TCC revenues will be detailed in the  NYISO manualsThese forecasts shall be performed using the procedure described in Appendix B to this Attachment Y.

31.4.3.4.2.4Estimated TCC revenues from any Incremental TCCs created by a proposed regulated economic transmission project 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.

31.4.3.4.2.5The NYISO will solicit bilateral contract information from all Load Serving Entities, which will provide the NYISO with bilateral energy contract data for modeling contracts that aredo not indexedreceive benefits, in whole or in part, fromto 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 NYISO will not be included in the calculation of the present value of the annual zonal LBMP savings in section (i) above.  Details regarding the information provided on bilateral contracts will be set forth in the NYISO manuals.

31.4.3.4.2.5.1      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

31.4.3.4.2.5.2      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 OATT, and Article 6 of the Services Tariff.

31.4.3.4.2.5.3      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.

31.4.3.4.2.5.4      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:

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 31.4.3.4.2.5

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.

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

Where:

PS is the year in which the project is expected to enter commercial operation;

AdjLBMPSy,z is as calculated in Section 31.4.3.4.2.5;

TCCRevImpacty,z is the forecasted impact of TCC revenues allocated to Load Zone z in year y, calculated using the procedure described in Appendices 30.6 to 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.

31.4.3.4.3Load zones not benefiting from a proposed project 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.

31.4.3.4.4Costs of a project will be allocated to beneficiaries as follows:

31.4.3.4.4.1For each load zone that would benefit from a proposed project, as determined pursuant to Section 31.4.3.4.2, the NYISO will allocate the cost of the project based on the zonal share of total savings.  Total savings will be equal to the sum of load savings for each load zone that experiences net benefits pursuant to Section 31.4.3.4.2.  A load zone’s cost allocation will be equal to the present value of the following calculation:

31.4.3.4.4.2Zonal cost allocation calculations for a project 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.

31.4.3.4.4.3Within zones, costs will be allocated to Load Serving Entities based on MWhs calculated for each LSE for each zone using the most recent calendar year data.  Allocations to an LSE will be calculated in accordance with the following formula:

31.4.3.4.5Project costs allocated under this Section 31.4.3.4 will be determined as follows:

31.4.3.4.5.1The project cost allocated under this Section 31.4.3.4 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 FERC.  If there is no formula rate on file at FERC, then the developer shall provide to the NYISO the project-specific parameters to be used to calculate the total project revenue requirement.

31.4.3.4.5.2Once the cost benefit analysis is completed the amortization period and the other parameters used for cost allocation for the project should not be changed, unless so ordered by FERC or a court of applicable jurisdiction, for cost recovery purposes to maintain the continued validity of the cost benefit analysis.

31.4.3.4.5.3The NYISO, in conjunction with the ESPWG, will develop procedures to allocate the risk of project cost increases that occur after the NYISO 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 over-runs.

31.4.3.4.6FERC must approve the cost of a proposed economic transmission project for that cost to be recovered through the NYISO tariff.  The developer’s filing with FERC must be consistent with the project proposal evaluated by the NYISO under this Attachment Y in order to be cost allocated to beneficiaries.

31.4.3.5Collaborative Governance Process and Board Action

31.4.3.5.1The NYISO shall submit the results of its project cost/benefit analysis and beneficiary determination to the ESPWG for comment.  The NYISO shall make available to any interested party sufficient information to replicate the results of the cost/benefit analysis and beneficiary determination.  The information made available will be electronically masked and made available subject to such other terms and conditions that the NYISO may reasonably determine are necessary to prevent the disclosure of any Confidential Information or Critical Energy Infrastructure Information contained in the information made available.  Following completion of that review, the NYISO’s analysis reflecting the revisions resulting from the TPAS and ESPWG review shall be forwarded to the Business Issues Committee and Management Committee for discussion and action.

31.4.3.5.2Following the Management Committee vote, the NYISO’s project cost/benefit analysis and beneficiary determination will be forwarded, with the input of the Business Issues Committee and Management Committee, to the NYISO Board for review and action.  The Board may approve the analysis and beneficiary designations as submitted or propose modifications on its own motion.  If any changes are proposed by the Board, the revised analysis and beneficiary designations shall be returned to the Management Committee for comment.  The Board shall not make a final determination on the project cost/benefit analysis and beneficiary designation until it has reviewed the Management Committee comments.  Upon final approval of the Board, project cost/benefit analysis and beneficiary designations shall be posted by the NYISO on its website and shall form the basis of the beneficiary voting described in Section 31.4.3.6 of this Attachment Y. 

31.4.3.6Voting by Project Beneficiaries

31.4.3.6.1Only Load Serving Entities determined to be beneficiaries of a proposed project in accordance with the procedures in Section 31.4.3.4 of this Attachment Y shall be eligible to vote on a proposed project.  The NYISO will, in conjunction with the ESPWG, develop procedures to determine the specific list of voting entities for each proposed project.

31.4.3.6.2The voting share of each Load Serving Entity shall be weighted in accordance with its share of the total project benefits, as allocated by Section 31.4.3.4 of this Attachment Y.

31.4.3.6.3For a regulated economic transmission project to have its cost allocated under this Attachment Y, eighty (80) percent or more of the actual votes cast on a weighted basis must be cast in favor of implementing the project.

31.4.3.6.4If the project 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.

31.4.3.6.5The NYISO will tally the results of the vote in accordance with procedures set forth in the NYISO manuals, and report the results to stakeholders.  Beneficiaries voting against approval of a project must submit to the NYISO 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 NYISO 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 cost/benefit analysis; and (3) where a project is not approved, whether the developer has provided any formal indication to the NYISO as to the future development of the project. 

31.4.4Cost Recovery for Regulated Projects

Responsible Transmission Owners, Transmission Owners and Other Developers will be entitled to full recovery of all reasonably incurred costs, including a reasonable return on investment and any applicable incentives, related to the development, construction, operation and maintenance of regulated projects, including Gap Solutions, undertaken pursuant to Section 31.2.6.4 of this Attachment Y to meet a Reliability Need. The costs of a regulated reliability project to be recovered pursuant to this Section 16 will be reduced by any amounts that, pursuant to Section 25.7.12 of Attachment S to the NYISO OATT, have been previously committed by or collected from Developers for the installation of System Deliverability Upgrades required for the interconnection of generation or merchant transmission projects. Transmission Owners and Other Developers will be entitled to recovery of costs associated with the implementation of a regulated economic transmission project in accordance with the provisions of Section 31.4.3 of this Attachment Y.

31.4.4.1The Responsible Transmission Owner, Transmission Owner or Other Developer will receive cost recovery for a regulated solution it undertakes to meet a Reliability Need pursuant to Section 31.2.6.4 of this Attachment Y that is subsequently cancelled in accordance with the criteria established pursuant to Section 31.3 of this Attachment Y.  Such costs will include reasonably incurred costs through the time of cancellation, including any forward commitments made.

31.4.4.2The Responsible Transmission Owner, Transmission Owner or Other Developer will recover its costs described in this Section 31.4.4 incurred with respect to the implementation of a regulated transmission solution in accordance with the provisions of Rate Schedule 10 of this tariff.  Provided further that cost recovery for regulated transmission projects undertaken by a TO pursuant to this Attachment Y shall be in accordance with the provisions of the Agreement Between the New York Independent System Operator, Inc. and the New York Transmission Owners on the Comprehensive Planning Process.

31.4.4.3Costs related to regulated non-transmission reliability 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.  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 same and transmission of electric energy subject to the jurisdiction of the Commission.

31.4.4.4For a regulated economic transmission project that meets the requirements of Section 31.4.3 of this Attachment Y, the Transmission Owner or Other Developer shall have the right to make a filing with FERC, under Section 205 of the Federal Power Act, for approval of its costs associated with implementation of the project.  The filing of the Transmission Owner or Other Developer must be consistent with its project proposal made to and evaluated by the NYISO under Section 31.4.3 of this Attachment Y.  The period for cost recovery, if any is approved, will be determined by FERC and will begin if and when the project begins commercial operation.  Upon request by NYPA, the NYISO will make a filing on behalf of NYPA.

31.4.4.5To the extent that Incremental TCCs are created as a result of a regulated economic transmission project that has been approved for cost recovery under the NYISO Tariff, those Incremental TCCs that can be sold will be auctioned or otherwise sold by the NYISO.  The NYISO shall determine the amount of Incremental TCCs that may be awarded to an Expansion in accordance with the provisions of Section 19.2.2 of Attachment M of the NYISO OATT. The NYISO will use these revenues to offset the revenue requirements for the project.  The Incremental TCCs shall continue to be sold for the depreciable life of the project, and the revenues offset will commence upon the first payment of revenues related to a sale of Incremental TCCs on or after the charge for a specific regulated economic project is implemented.

Filed May 19, 2009 to comply with order of the Federal Energy Regulatory Commission, Docket No. OA08-52-002, issued October 16, 2008, 125 FERC ¶ 61,068 (2008). Proposed effective date: May 19, 2009.

Filed December 11, 2009 to comply with order of the Federal Energy Regulatory Commission, Docket Nos. OA08-004,-006, issued October 15, 2009, 129 FERC ¶ 61,044 (2009).  Proposed effective date: December 14, 2009.

Filed April 13, 2010 to comply with order of the Federal Energy Regulatory Commission, Docket Nos. OA08-52-004 and-006, issued October 15, 2009, 129 FERC ¶ 61,044 (2009). Proposed effective date: April 13, 2010.