ML13329A930

State of New York Pre-Filed Hearing Exhibits NYS000481 Order Accepting IPEC Reliability Contingency Plans, Establishing Cost Allocation and Recovery, and Denying Requests for Rehearing

ML13329A930
Person / Time
Site:	Indian Point
Issue date:	11/04/2013
From:	State of NY, Public Service Commission
To:	Atomic Safety and Licensing Board Panel
SECY RAS
Shared Package
ML13329A927	List: ML13329A928 ML13329A930
References
50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01, RAS 25352
Download: ML13329A930 (81)

Text

NYS000481 Submitted: November 25, 2013 STATE OF NEW YORK PUBLIC SERVICE COMMISSION CASE 12-E-0503 - Proceeding on Motion of the Commission to Review Generation Retirement Contingency Plans.

ORDER ACCEPTING IPEC RELIABILITY CONTINGENCY PLANS, ESTABLISHING COST ALLOCATION AND RECOVERY, AND DENYING REQUESTS FOR REHEARING Issued and Effective: November 4, 2013

TABLE OF CONTENTS Page INTRODUCTION....................................................1 BACKGROUND......................................................8 Con Edison/NYPA February Filing............................8 A. TOTS Projects......................................8 B. EE/DR/CHP Programs................................10 DPS Staff Cost Allocation/Cost Recovery Proposal..........13 DISCUSSION.....................................................14 Statutory Authority.......................................14 Identification of Reliability Needs.......................18 Reliability Contingency Plan - Portfolio of Projects......22 A. TOTS Projects .....................................23 B. EE/DR/CHP Programs ................................25 Cost Allocation...........................................30 A. TOTS Projects .....................................31 B. EE/DR/CHP Programs ................................33 Cost Recovery.............................................34 A. TOTS Projects .....................................34 B. EE/DR/CHP Programs ...............................35 State Environmental Quality Review Act....................37 Requests for Rehearing....................................41 A. March 2013 Order..................................41

1. IPPNY ........................................41

2. Entergy ......................................42

3. Commission Determination .....................42

CASE 12-E-0503 B. April 2013 Order..................................43

1. IPPNY ........................................44

2. Entergy ......................................44

3. Commission Determination .....................45 CONCLUSION.....................................................45 Appendix A - Summaries of Notices and Comments

- ii -

STATE OF NEW YORK PUBLIC SERVICE COMMISSION At a session of the Public Service Commission held in the City of Albany on October 17, 2013 COMMISSIONERS PRESENT:

Audrey Zibelman, Chair Patricia L. Acampora Garry A. Brown Gregg C. Sayre Diane X. Burman CASE 12-E-0503 - Proceeding on Motion of the Commission to Review Generation Retirement Contingency Plans.

ORDER ACCEPTING IPEC RELIABILITY CONTINGENCY PLANS, ESTABLISHING COST ALLOCATION AND RECOVERY, AND DENYING REQUESTS FOR REHEARING (Issued and Effective November 4, 2013)

BY THE COMMISSION:

INTRODUCTION This proceeding was commenced through a November 2012 Order that directed the development of utility plans to address the reliability concerns that may arise from the retirement of electric generating facilities.1 In particular, the November 2012 Order recognized the significant reliability needs which could occur if the 2,040 MW of generating capacity at the Indian Point Energy Center (IPEC) were retired upon the expiration of 1

Case 12-E-0503, Generation Retirement Contingency Plans, Order Instituting Proceeding and Soliciting Indian Point Contingency Plan (issued November 30, 2012) (November 2012 Order).

CASE 12-E-0503 IPECs existing licenses.2 Given the uncertainty regarding whether Entergy will be able to obtain the necessary permits and approvals to keep [IPEC] operational over the long-term, the Commission sought a reliability contingency plan addressing those potential reliability needs.3 The November 2012 Order directed Consolidated Edison Company of New York, Inc. (Con Edison), as the transmission owner most directly affected by the closure of the IPEC, to develop such a plan in consultation with the New York Power Authority (NYPA), Department of Public Service Staff (DPS Staff), and other appropriate agencies.4 In response to the November 2012 Order, Con Edison and NYPA jointly submitted a filing on February 1, 2013 (Con Edison/NYPA February Filing). The Con Edison/NYPA February Filing, as described in more detail below, proposed an IPEC Reliability Contingency Plan whereby Con Edison, New York State Electric and Gas Corporation (NYSEG), and NYPA would pursue the initial development of three Transmission Owner Transmission Solution (TOTS) projects, while concurrently soliciting generation and transmission proposals (other than the TOTS projects) through a Request for Proposals (RFP) to be issued by NYPA. The Con Edison/NYPA February Filing further described an Energy Efficiency (EE)/Demand Reduction (DR) program to obtain 100 MW of peak demand reduction. The TOTS upgrades, the 100 MW 2

The IPEC, which is located in Buchanan New York, consists of two base-load nuclear generating units that are currently owned by Entergy Nuclear Indian Point 2, LLC, and Entergy Nuclear Indian Point 3, LLC (collectively, Entergy). The Nuclear Regulatory Commissions licenses for IPEC Unit 2 and Unit 3 expire on September 28, 2013, and December 12, 2015, respectively.

3 November 2012 Order, p. 3.

4 On January 14, 2013, and prior to submitting their plan, a meeting was held by Con Edison and NYPA to provide their preliminary concepts for a reliability contingency plan, and to obtain input from interested stakeholders.

CASE 12-E-0503 from EE and DR programs, and any projects accepted through the RFP process, were proposed as a portfolio to address a potential reliability need of approximately 1,450 MW that could arise in the 2016 summer period. Specifically, a June 1, 2016 reliability need date, when peak summer conditions could be expected to arise, was identified as an in-service date for projects that was consistent with the analysis performed as part of the 2012 Reliability Needs Assessment (RNA) conducted by the New York Independent System Operator, Inc (NYISO).5 The Con Edison/NYPA February Filing requested specific actions by the Commission, including: 1) an order in March 2013 requesting NYPA to issue an RFP for solutions to the potential energy reliability needs;6 2) an order in April 2013 authorizing the development of the 100 MW of EE and DR programs, the initial planning of the three TOTS projects, and the recovery of prudently incurred costs associated with planning the TOTS projects; and, 3) an order in September 2013 identifying a preferred set of transmission and/or generation projects for inclusion in the IPEC Reliability Contingency Plan, and making findings in connection with an authorization of cost allocation and cost recovery for such projects.7 5

The development of the June 2016 reliability need date, and of the extent of the potential need on that date, is discussed in more detail infra.

6 The November 2012 Order, and the Notice Soliciting Comments issued on February 13, 2013, sought comments, by February 22, 2013, on the first requested action item (i.e., the issuance of the NYPA RFP, and related matters).

7 The Con Edison/NYPA February Filing sought certain findings by the Commission, including findings that each of the TOTS projects would be a public policy project that meets the public policy requirements of New York State.

CASE 12-E-0503 On March 15, 2013, the Commission issued an order that responded to the first requested action in the Con Edison/NYPA February Filing.8 In particular, the March 2013 Order approved the proposal, subject to certain modifications, for NYPA to issue an RFP. The RFP was subsequently issued by NYPA on April 3, 2013, and responses to the RFP were received on or about May 20, 2013.

On April 19, 2013, the Commission responded to the second request in the Con Edison/NYPA February Filing, and approved, subject to conditions, Con Edison, NYSEG, and NYPAs preliminary planning related to the three TOTS projects.9 While preliminary planning was approved for the TOTS, as described in the Con Edison/NYPA February Filing, the recovery of planning costs was capped at $10 million for an initial period until the TOTS projects were analyzed further.10 In the April 2013 Order, Con Edison was also directed to work with the New York State Energy Research and Development Authority (NYSERDA) and NYPA, and to file a revised plan to secure permanent peak reduction from incremental EE and DR programs and other resources.

Finally, the Order directed DPS Staff to propose a cost 8

Case 12-E-0503, Generation Retirement Contingency Plans, Order Upon Review of Plan to Issue Request For Proposals (issued March 15, 2013) (March 2013 Order).

9 Case 12-E-0503, Generation Retirement Contingency Plans, Order Upon Review of Plan to Advance Transmission, Energy Efficiency, and Demand Response Projects (issued April 19, 2013) (April 2013 Order). On February 20, 2013, a notice was published in the State Register, inviting comments on the second requested action items by April 8, 2013.

10 At the time of the April 2013 Order, we declined to make the requested findings regarding consistency with public policy requirements, based on the unavailability of tariff provisions or procedures that could be applied. That conclusion, therefore, was without prejudice to a new request for findings, which could be made in this or another case before this Commission, or may be sought in another forum.

CASE 12-E-0503 allocation and cost recovery mechanism for the Commissions consideration.

In response to the April 2013 Order, a revised plan for EE and DR programs was filed on June 20, 2013, by Con Edison and NYPA, in consultation with NYSERDA. The plan was comprised of 100 MW of EE and DR, which would be pursued by Con Edison and NYSERDA, and 25 MW of Combined Heat and Power (CHP) projects to be administered by NYSERDA (collectively, the 125 MW Revised EE/DR/CHP Program). The 125 MW Revised EE/DR/CHP Program, along with 60 MW from other on-going projects identified by NYSERDA and NYPA, which had not been counted in the NYISOs 2012 RNA, were estimated to provide 185 MW of relief toward the potential reliability deficiency. DPS Staff also submitted a proposed cost allocation/cost recovery straw proposal on June 4, 2013 (DPS Staff June Straw Proposal). The 125 MW Revised EE/DR/CHP Program and the June Straw Proposal are discussed further below.

In this Order, we address, in part, the third and final requested action item in the Con Edison/NYPA February Filing by accepting a portfolio for inclusion in the IPEC Reliability Contingency Plan consisting of: 1) the three TOTS projects; and 2) the development of approximately 125 MW of EE/DR/CHP resources through the 125 MW Revised EE/DR/CHP Program. This portfolio, along with 60 MW from on-going EE, DR, and CHP activities, makes a total contribution of 185 MW from EE, DR, and CHP programs towards the potential reliability need CASE 12-E-0503 for 1450 MW in June 2016.11 We anticipate that the TOTS will contribute at least an additional 600 MW towards that need.

As noted above, the April 2013 Order approved the issuance of an RFP seeking proposals for generation or non-TOTS transmission projects which could be included in the IPEC Reliability Contingency Plan portfolio. In response to the RFP, a significant number of proposals were received, and these proposals have been evaluated by DPS Staff with the assistance of a consultant, The Brattle Group, Inc. (Brattle).

For the time being, however, we agree with DPS Staffs recommendation to defer the choice of which, if any, of the proposals responding to the NYPA RFP should be included in the IPEC Reliability Contingency Plan portfolio. We leave this issue open in light of the uncertainties presently affecting the wholesale generation markets. First, in the coming months, it is possible that the NYISO will establish a new Installed Capacity (ICAP) Zone in the Lower Hudson Valley to meet Locational Capacity Requirements. Second, the NYISO is developing new Demand Curves for use in setting ICAP prices in the NYISO-administered markets. Both of these actions are very likely to increase ICAP prices that generators can expect to 11 In connection with the filing of the 125 MW Revised EE/DR/CHP Program, additional DR and CHP projects providing a total of 60 MW have been identified, which are expected to be available by the summer 2016, but were not accounted for in the NYISOs 2012 RNA. For purposes of evaluating the portion of the reliability gap which is met by new EE, DR, and CHP activities, we will count the estimated results of these programs in the analysis. The programs providing these 60 MW, however, are already on-going and have an identified source of funding associated with them, so no action in this Order is needed for their implementation. The 60 MW from these programs breaks down as: (a) an additional 15 MW of peak demand reductions as part of a separate NYPA Build Smart NY Program, (b) an additional 15 MW of on-going CHP projects at NYPA, and (c) 30 MW of CHP projects through a NYSERDA program which has already been approved by the Commission.

CASE 12-E-0503 receive in the Lower Hudson Valley. At the same time, there are several merchant generating units, with a combined capacity of approximately 1,500 MW, which could serve this market, but have either been mothballed and are waiting to return to service if economic conditions improve, or have been subject to a forced outage or have been derated and require repair. With the potential to participate in a higher revenue stream, some of the owners of these units could decide in the near future to bring their units back into service. If so, these units would contribute to meeting the reliability needs, thus reducing the amount of resources necessary to include in the IPEC Reliability Contingency Plan portfolio.

As discussed below, we agree with DPS Staffs recommendation to include the TOTS projects and the EE, DR, and CHP projects described above in the portfolio of projects accepted for inclusion in the IPEC Reliability Contingency Plan.

If accepted now and, if timely implemented, the TOTS projects and the 125 MW Revised EE/DR/CHP Program provide a significant portion of the resources needed to address the potential reliability needs in the event IPEC is retired in December 2015.

This Order accepts this limited suite of projects as the appropriate least-cost and least-risk portfolio for the IPEC Reliability Contingency Plan at the present time.

This Order also addresses the method by which the costs associated with implementing the herein accepted components of the IPEC Reliability Contingency Plan should be allocated, and the mechanisms by which those costs should be recovered. Finally, we address the Requests for Rehearing of the March 2013 Order and the April 2013 Order. For the reasons discussed below, we deny these requests.

CASE 12-E-0503 BACKGROUND Con Edison/NYPA February Filing A. TOTS Projects The first component of the contingency plan proposed in the Con Edison/NYPA February Filing consisted of three TOTS projects that Con Edison and NYPA asserted could be implemented by the summer of 2016. In particular, Con Edison described its plan to develop a second Ramapo to Rock Tavern transmission line (Ramapo/Rock Tavern), and a Staten Island Unbottling (Staten Island) project. The third project, referred to as the Marcy South Series Compensation and Fraser to Coopers Corners Reconductoring (Marcy/Fraser) project, would be developed by NYPA and NYSEG.12 According to the Con Edison/NYPA February Filing, as updated on May 20, 2013, two of the TOTS projects (i.e., the Ramapo/Rock Tavern line and the Marcy/Fraser project) would increase the import capability into Southeastern New York by reducing the constraint on the Upstate New York/Southeast New York interface. This means that underutilized upstate capacity would be able to provide increased levels of energy to the downstate area and this increased capability would provide a reliability benefit. The third proposed TOTS, i.e., the Staten Island unbottling project, is designed to make generation on Staten Island, which is currently bottled, available to the grid and deliverable to Con Edisons Gowanus and Farragut transmission substations.13 12 The three TOTS are discussed in detail in Exhibits B, C, and D of the Con Edison/NYPA February Filing, and the update filed on May 20, 2013.

13 Generation that is bottled is physically interconnected, but cannot provide its full output to the grid due to transmission limitations.

CASE 12-E-0503 The Con Edison/NYPA February Filing sought full recovery of the costs, including any associated contractual cancellation costs, incurred by Con Edison and NYPA for these projects. Con Edison and NYPA provided estimates of the costs to halt the TOTS projects at selected intervals and of the costs to complete each of these projects. The total cost to complete these projects was initially estimated at approximately $511 million. Based on updates filed on May 20, 2013, the cost of the Staten Island project was revised downward, making the total estimated cost of the three TOTS projects approximately $447 million. According to the Con Edison/NYPA February Filing, the TOTS projects would ultimately be transferred to and owned by an entity identified as the New York Transmission Company (NY Transco).

Con Edison, together with the other New York investor-owned transmission companies, and NYPA and the Long Island Power Authority (LIPA) (collectively the New York Transmission Owners or NYTOs), are active participants in the process of creating the NY Transco. The NY Transcos purpose and structure are intended to address and overcome planning and cost allocation issues which have, to date, impeded the development of economic transmission projects. The NY Transco would be a new entity formed for the express purpose of developing transmission projects in the State. However, while the NY Transco has not yet been formed, on May 30, 2012, and in response to the New York State Energy Highway Request for Information, the NYTOs identified eighteen transmission projects throughout the State CASE 12-E-0503 that the NY Transco could develop.14 The identified projects included the three TOTS projects under consideration here.

B. EE/DR/CHP Programs The second component of the IPEC Reliability Contingency Plan, as initially presented by Con Edison and NYPA, included a targeted program to achieve 100 MW of permanent peak demand reduction by the summer of 2016. NYPA also identified 15 MW of on-going CHP projects that would be placed in-service by the summer of 2016.

The EE and DR components of the Con Edison/NYPA February Filing were subsequently supplanted with the 125 MW Revised EE/DR/CHP Program proposed by Con Edison and NYSERDA, in consultation with NYPA. The 125 MW Revised EE/DR/CHP Program, filed on June 20, 2013, seeks approval for 100 MW of peak EE/DR and fuel switching projects, which would be coordinated by Con Edison and NYSERDA, along with a 25 MW expanded CHP program that would be administered by NYSERDA.

The EE and DR components of the 125 MW Revised EE/DR/CHP Program would be located within Con Edisons service territory, and are broken down into 44 MW for load management, 40 MW for permanent demand reduction, and 16 MW for fuel switching, for a total of 100 MW. These projects are estimated to cost $219 million, and these costs are proposed to be 14 See, http://www.nyenergyhighway.com/RFIDocument/transmission/

index-2.html. The 18 projects identified by NY Transco could result in an estimated total investment of $2.9 billion in upgrades across the New York State transmission system.

Neither the creation of, nor the formation of, nor any specific property transfer to the NY Transco is under review in this Order.

CASE 12-E-0503 recovered through a surcharge on Con Edisons delivery customers.15 The Revised EE and DR components would be jointly implemented by Con Edison and NYSERDA, and are expected to result in a single point of entry for all participants, with a single application process. These programs would focus on large customers located within Con Edisons service territory.

Targeted customers would include: (1) customers with high peak demand; (2) project developers with potential large scale projects; (3) prior or existing Energy Efficiency Portfolio Standard participants that may be willing to expand the scope and depth of projects; and (4) customers capable of switching electric summer air conditioning load to steam or gas.

The Revised EE/DR/CHP Program also included a NYSERDA proposal for an Expanded NYSERDA CHP component for the Program.

This aspect of the Program is designed to achieve 25 MW of load reduction. The total cost to ratepayers of the 25 MW Expanded NYSERDA CHP Program is expected to be $66 million, which is broken down to include: 1) $40 million for customer incentives;

2) $16 million for Outreach Assistance Contractor activities; and, 3) $10 million for administrative functions such as NYSERDA staff salaries and State Cost Recovery Fee and Program Evaluation tasks. The total cost for the 125 MW of projects proposed for acceptance in the 125 MW Revised EE/DR/CHP Program would be approximately $285 million.

As part of the filing that included the 125 MW Revised EE/DR/CHP Program, NYSERDA indicated that the 25 MW of proposed CHP projects was in addition to the CHP projects that the 15 The surcharge would exclude NYPAs governmental customers who receive delivery service under Con Edisons PSC NO. 12 -

Electricity, since they already participate in the NYPA Build Smart NY Program.

CASE 12-E-0503 Commission previously approved.16 DPS Staff verified with NYSERDA that 30 MW of these previously approved CHP projects would be operational in Con Edisons service territory by June 2016, and that they were not included in the NYISOs 2012 RNA.

In addition, NYPA identified an additional 15 MW that would be achieved under NYPAs Build Smart NY program, which were not identified in the NYISOs 2012 RNA but would be in-service by the summer of 2016. These MW reductions would come from a mix of efficiency gains at state agencies and authorities, wastewater treatment plants in New York City, and campus-wide American Society of Heating, Refrigerating and Air Conditioning Engineers-Level II audits. All NYPA Energy Efficiency Program projects are funded through NYPA low-cost financing that is recovered directly from program participants.

As such, the cost of implementing these projects would not be funded through utility tariff charges.

Taken together, all of these projects, including the 15 MW of ongoing CHP projects NYPA identified in the Con Edison/NYPA February filing, would contribute toward meeting the calculated reliability deficiency needs.17 Cumulatively, the 125 MW of projects proposed in the Revised EE/DR/CHP Program, and 16 The Commissions previous approval was in Case 07-M-0548, Energy Efficiency Portfolio Standard - System Benefit Charge IV, Order Modifying Budgets and Targets for Energy Efficiency Portfolio Standard Programs and Providing Funding for Combined Heat and Power and Workforce Development Initiatives (issued December 17, 2012).

17 As noted above, NYSERDA and NYPA have identified other programs which have already been approved and are funded, but the results of which have not been counted in the NYISO RNA.

These programs should contribute approximately 60 MW towards the reliability goal associated with the IPEC Reliability Contingency Plan. See note 11, supra.

CASE 12-E-0503 the 60 MW from on-going projects18, would contribute 185 MW toward the potential reliability deficiency need.

On July 17, 2013, a notice was published in the State Register, inviting comments on the Revised EE/DR/CHP Program.

Various comments were received by the deadline of September 3, 2013.

DPS Staff Cost Allocation/Cost Recovery Proposal In response to the April 2013 Order, DPS Staff filed the June Straw Proposal, which described a methodology as to how the costs associated with implementing the transmission or generation solutions that are ultimately part of the IPEC Reliability Contingency Plan could be allocated and recovered from retail ratepayers. At the same time, DPS Staff also provided and sought comments on a draft Reimbursement Agreement prepared by NYPA, which NYPA described as a necessary component of the mechanism that will be needed to ensure full recovery of costs incurred in connection with the [TOTS] and with generation project(s), if any, selected pursuant to the April 3, 2012

[RFP].

DPS Staffs June Straw Proposal sought to allocate costs by applying a beneficiaries pay principle, whereby the ratepayers that receive the reliability benefits from the IPEC Reliability Contingency Plan would be assigned a proportionate cost recovery responsibility. The June Straw Proposal also attempted to maintain consistency, to the extent practicable, with the NYISOs tariff provisions for allocating the costs of a transmission solution selected to fulfill a need identified in a NYISO Reliability Needs Assessment.

Pursuant to the Notice of Second Technical Conference and Revised Comment Schedule, issued on July 2, 2013, initial comments were sought by July 22, 2013, and reply comments were 18 See, supra at note 11.

CASE 12-E-0503 sought by August 5, 2013. Several comments were received in response to this notice.

DISCUSSION Statutory Authority With this Order, the Commission accepts a Reliability Contingency Plan that identifies a portfolio of specific transmission and EE/DR/CHP projects that, when taken together, will significantly reduce New Yorkers vulnerability to the costs and disruptions that could occur upon the retirement of IPEC Unit 3 in December 2015. In addition, the Order establishes the methods and mechanisms for the allocation and recovery of the costs and benefits associated with the implementation of the IPEC Reliability Contingency Plan.

Comments have been received in this proceeding in response to several notices seeking comments. These notices are summarized, along with the comments, in Appendix A to this Order. Some commenters expressed concern that the DPS Staffs June Straw Proposal for allocating costs would intrude into Federal Energy Regulatory Commission (FERC)-regulated markets, and would interfere with NYISO operating and planning processes, as well as unnecessarily duplicate, preempt, or nullify portions of the NYISO tariff. Other commenters argued that FERC, and not the Commission, has jurisdiction over cost allocation. These commenters further argued that the Commission lacks authority under the Public Service Law (PSL) for establishing a cost allocation methodology, and that our jurisdiction has not been established on this issue. It is also noted that this Commission lacks jurisdiction over NYPA; that NYPA lacks the authority assumed in the June Straw Proposal; that the Commission has limited jurisdiction over LIPA; and finally, that FERC has exclusive jurisdiction over the proposed TOTS projects.

CASE 12-E-0503 However, others claim that cost allocation has been delegated to the Commission under the NYISOs compliance filing pertaining to FERCs Order 1000.

Contrary to some parties arguments, the Commissions authority to adopt and provide for the implementation of this IPEC Reliability Contingency Plan is well founded in the PSL.

In particular, section 5(2) of the PSL provides the Commission with authority to encourage all persons and corporations subject to its jurisdiction to formulate and carry out long-range programs, individually or cooperatively, for the performance of their public service responsibilities with economy, efficiency, and care for the public safety, the preservation of environmental values and the conservation of natural resources.19 Moreover, section 66(5) of the PSL provides the Commission with authority to address reliability concerns by prescribing the "safe, efficient and adequate property, equipment and appliances thereafter to be used, whenever the NYPSC determines that the utilitys existing equipment is unsafe, inefficient or inadequate.20 The Commission also has authority to "order reasonable improvements and extensions of the works, wires, poles, lines, conduits, 19 Section 5(2) of the PSL has been held to confer broad discretion to promote energy conservation. See, Multiple Intervenors v. NYPSC, 166 A.D.2d 140 (3rd Dept. 1991).

Furthermore, PSL §5(2) was determined to provide the Commission with jurisdiction to require utilities to file plans outlining how they would adapt to a competitive electric industry. See, Energy Association of New York State v. NYPSC, 169 Misc. 2d 924 (Supreme Ct. 1996)(noting that PSL §5(2) transformed the traditional role of the Commission from that of an instrument for a simple case-by-case consideration of rates requested by utilities to one charged with the duty of long-range planning for the public benefit).

20 PSL §66(5). "Electric corporations" are required to provide such service, instrumentalities and facilities as shall be safe and adequate. PSL §66(1).

CASE 12-E-0503 ducts and other reasonable devices, apparatus and property of...electric corporations and municipalities.21 Other provisions of the PSL also provide the Commission with authority over reliability.22 Moreover, the Commissions authority to protect or enhance reliability, as it exercises here by accepting the IPEC Reliability Contingency Plan, is expressly preserved under the Federal Power Act. As stated therein, FERCs authority to establish reliability standards shall [not] be construed to preempt any authority of any State to take action to ensure the safety, adequacy, and reliability of electric service within that State, as long as such action is not inconsistent with any

[FERC-approved] reliability standard, except that the State of New York may establish rules that result in greater reliability within that State, as long as such action does not result in lesser reliability outside the State than that provided by the

[FERC-approved] reliability standards.23 We find that the IPEC Reliability Contingency Plan usefully defines measures needed to ensure safety, adequacy, and reliability, and may result in greater reliability in New York than would otherwise exist under the FERC-approved reliability standards. Accordingly, our 21 PSL §66(2). The NYPSC has continuing jurisdiction over the "construction, operation and maintenance of all utility transmission lines. See, Matter of Stannard v. Axelrod, 100 Misc.2d 702 (Sup. Ct. Broome Co. 1979) (dismissing petition challenging the NYPSC's Order approving a 345 kilovolt transmission line).

22 See, PSL §§25(4) and 25-a(5) (allowing the NYPSC to impose penalties upon a public utility that fails to comply with regulations related to reliability); see also, PSL §126(1)(d)

(providing that before the NYPSC may site a major electric utility transmission facility, the Commission must find that such facility will serve the interests of electric system economy and reliability).

23 16 U.S.C. §824o(i)(3).

CASE 12-E-0503 authority to accept the IPEC Reliability Contingency Plan is not preempted by FERC or the NYISO planning process.

In addition, the Commission has authority to ensure that [a]ll charges made or demanded by any...electric corporation or municipality forelectricity or any service rendered or to be rendered, shall be just and reasonable and not more than allowed by law or by order of the commission.24 As the April 2013 Order stated, the Commission possesses the authority to develop a retail rate recovery mechanism that provides for the jurisdictional utilities to collect payments from their ratepayers for reliability-related activities.25 The Commission also concluded that this funding may be used to support actions taken by NYPA in support of their reliability-related activities undertaken in conjunction with the Indian Point Contingency Plan.26 The Commission further noted that it was not asserting jurisdiction over NYPA, the rates NYPA charges its customers, or wholesale transmission rates established by FERC. We conclude that these findings continue to adhere to the rulings in this Order.

With respect to cost allocation and recovery for the TOTS projects, however, we do not need to exercise our legal authority to decide the cost allocation and recovery issues. We understand from the NYTOs comments that the TOTS project developers, together with the other NYTOs which are proposed members of the NY Transco, intend to seek cost recovery for the TOTS through FERC-approved tariffs. The TOTS developers have also indicated that they intend to propose a cost allocation methodology to FERC that is consistent with the methodology developed by the NYTOs in connection with the NY Transco 24 PSL §65(1).

25 April 2013 Order, p. 10.

26 Id.

CASE 12-E-0503 concept. We concur with the NYTOs that cost recovery and allocation through a FERC tariff are appropriate for these projects, and we intend to support such an application regarding the TOTS projects in so far as the applications proposed revenue requirement reflects the cost estimates and cost allocation methodology set forth in the NYTOs filings in this proceeding. We urge the NYTOs to proceed as quickly as possible at FERC. In connection with that application, we will direct Con Edison, in consultation with NYPA, to supply a report on the progress of this application on or before June 30, 2014, and every six months thereafter.

Identification of Reliability Needs The reliability implications of retiring IPEC have been well documented by the NYISO. While the NYISO assumed that IPEC was available in the 2012 RNA base case, it performed a further analysis with IPEC unavailable. This analysis found that reliability violations would occur in 2016 if the Indian Point Plant were to be retired by the end of 2015.27 The NYISOs 2012 RNA transmission security analysis indicated that, without Indian Point, already constrained transfer limits into Southeastern New York would be further aggravated.28 In order to mitigate these overloads, the NYISO stated that compensatory megawatts would be needed in Zones G, H, I, J, or the western 27 New York Independent System Operator 2012 Reliability Needs Assessment, Final Report, dated September 18, 2012, p. 42.

28 Specifically, a transmission security analysis indicated overloaded conditions on the Leeds-Pleasant Valley and Athens-Pleasant Valley 345 kV lines, the Fraser-Coopers Corners and Rock Tavern-Ramapo 345 kV lines, and the Roseton-East Fishkill 345 kV line.

CASE 12-E-0503 portion of Zone K,29 amounting to 1,000 MW in 2016, noting that the amount of compensatory megawatts could increase depending on the location of the resource.30 Finally, the NYISOs 2012 RNA Indian Point Plant Retirement Scenario showed significant Loss of Load Expectation (LOLE)/resource adequacy violations if Indian Point were not available. Using the base case load forecast, the 2016 LOLE would be 0.48 days per year. This represented a significant violation of the 0.1 days per year criterion.31 The Con Edison/NYPA February Filing stated that it relied on the NYISOs 2012 RNA base case as the starting point for its analysis, noting that it is the NYISOs most recent evaluation of the bulk power system over the next ten years.32 According to the filing, the base case was then updated by adjusting for known additions and retirements since the NYISO analysis was performed. Specifically, the NYISOs 2012 RNA base case was adjusted by adding 320 MW associated with the rescission of a mothball notice by Astoria Generating Company, L.P.s Gowanus barges 1 and 4, and reducing the reliability deficiency need amount to reflect the effect of the 100 MW EE/DR 29 The location of these Zones in New York State can be understood from a map at the NYISO website. See, http://www.nyiso.com/public/markets_operations/market_data/map s/index.jsp.

30 New York Independent System Operator 2012 Reliability Needs Assessment, Final Report, dated September 18, 2012, p. 43.

31 The New York State bulk power system is planned to meet a LOLE that, at any given point in time, is less than or equal to a involuntary load disconnection that is not more frequent than 0.1 days per year. In other words, the bulk power system is planned so that there is sufficient transmission and generation such that the LOLE is no more than once every 10 years.

32 Con Edison notes that the RNA model and assumptions were a result of extensive stakeholder review.

CASE 12-E-0503 peak load reduction program proposed in the Con Edison/NYPA February Filing. The results of the analysis, as indicated in the Con Edison/NYPA February Filing, showed a deficiency of 950 MW, as compared to the NYISO 2012 RNA analysis, which showed a deficiency of approximately 1,000 MW.

As Con Edisons analysis was nearing completion, however, the retirement of the Danskammer generating facility was announced. Based on this announcement in January 2013, the effect of this retirement was estimated by Con Edison to increase the reliability needs by an additional 400-425 MW, making the total deficiency approximately 1,450 MW (or approximately 1,350 MW accounting for the effect of the initial proposed 100 MW EE/DR program).

In order to conduct an independent analysis and update of the reliability deficiency needs and to perform other work which would be useful for Staffs Contingency Plan analysis, as directed in the March 2013 Order, DPS Staff obtained the consulting services of Brattle. Thereafter, DPS Staff directed Brattle to analyze the reliability needs that would attend the retirement of the IPEC at the end of 2015. DPS Staff indicated that the updated base case in the analysis should model NRG Energy, Incs Astoria Gas Turbine Units 10 and 11, which are expected to return to service.33 Based on the analysis, DPS Staff confirmed the validity of the reliability needs identified in the Con Edison/NYPA February Filing, and that if IPEC Units 2 and 3 were to retire upon the expiration of its current licenses in 2013 and 2015, respectively, Southeast New York would not have enough capacity to avoid reliability violations in the summer of 2016.

33 On June 7, 2013, NRG Energy, Inc. filed, in Case 05-E-0889, a notice of intent to return Astoria Gas Turbine Units 10 and 11 to service.

CASE 12-E-0503 Contrary to parties claims, we find that the various analyses performed of the potential reliability impacts associated with the retirement of IPEC provide a sufficient record and a rational basis to identify a reliability deficiency need of approximately 1,450 MW. We reject, however, parties suggestions that the Commission should rely on the NYISO planning process to resolve these potential reliability needs, or that we should not plan for the contingency that IPEC may be retired.34 As observed in the March 2013 Order, the NYISOs process currently assumes that IPEC will remain available, and therefore, it is not conducting the reliability contingency planning that we are conducting now.35 We disagree that a reasonable planning approach under the circumstances should rely solely on market-based projects to appear, or that we should wait for the NYISO to trigger the need for the implementation of a reliability solution. In the event IPEC were unable to obtain the necessary consents and approvals to continue operating, or if Entergy could decide that continued operation of IPEC is not in its interest,36 there would unlikely be sufficient time to address the resulting reliability needs.

The requirement that the projects included in the IPEC Reliability Contingency Plan meet a firm in-service deadline of June 1, 2016 comports with the NYISOs identified reliability 34 We reiterate that the Commission is not making any determinations or taking any positions regarding the potential closure of the IPEC. See, November 2012 Order, fn 3.

35 Under the NYISOs procedures, it will not assume that IPEC will be unavailable until Entergy, the owner and operator of the IPEC, provides a retirement notice.

36 Entergy recently announced that due to economic factors it was retiring its Vermont Yankee nuclear reactor by the end of 2014, leaving regulators with as little as 16 months to address any reliability needs associated with the retirement.

See, http://www.nytimes.com/2013/08/28/science/entergy-announces-closing-of-vermont-nuclear-plant.html?_r=0 CASE 12-E-0503 need date under the IPEC retirement scenario. Therefore, the in-service requirement based on this date is consistent with the need to maintain safe and adequate service in the event IPEC is retired.

We also reject parties arguments that we have failed to reflect or accommodate market-based projects that are currently under development that could, when completed, contribute to meeting the identified reliability needs. The analysis of need took into account the most recent information available regarding proposed projects. To the extent any proposed projects have met the milestones established by the NYISOs planning criteria for inclusion in the RNA base case, those projects were assumed to be available.37 Reliability Contingency Plan - Portfolio of Projects The components of the IPEC Reliability Contingency Plan portfolio which we accept here will, according to DPS Staffs analysis, contribute toward the potential reliability need, while offering net benefits for ratepayers even if IPEC were to operate beyond December 2015. DPS Staff opines that it is in the public interest to pursue these projects, regardless of the contribution they make to the IPEC Reliability Contingency Plan.38 These projects include the three TOTS, which are estimated to provide at least 600 MW of reliability relief..

DPS Staff also recommends that we advance the proposal in the 37 Indeed, our decision to defer considerations of the proposals submitted under the NYPA RFP arises from our understanding that market conditions are changing and may result in the development of market-based solutions. See supra at Section I.

38 Con Edison referred to some of these projects as no regrets solutions to the retirement of the IPEC, meaning that the projects provide net benefits to ratepayers even if IPEC does not retire. See, Con Edison Filing of Supplemental Information Regarding its Ramapo to Rock Tavern Project (filed May 20, 2013).

CASE 12-E-0503 125 MW Revised EE/DR/CHP Program to achieve the estimated 100 MW associated with EE and DR programs and approximately 25 MW from new NYSERDA CHP programs, as being consistent with the public interest and prior Commission decisions.39 A. TOTS Projects Under DPS Staffs direction, Brattle examined the benefits and costs of the three TOTS projects. For this assignment, Brattle was asked to assume that IPEC continued to operate in order to determine whether potential net benefits would be associated with the TOTS projects under this more conservative assumption. To complete this evaluation, independent estimates of the resource cost savings were derived for each of the TOTS projects individually, as well as for all three combined.

To compare the TOTS costs and benefits, DPS Staff directed Brattle to convert the TOTS investment costs, as estimated by Con Edison and NYPA, into typical utility annual revenue requirements.40 The energy resource cost savings were modeled using General Electrics Multi-Area Production Simulations (GE MAPS). Capacity resource cost impacts were estimated by Brattle and DPS Staff based on the modeling of NYs existing and proposed capacity markets.

The net benefits of the TOTS were calculated as the difference between resource cost savings and the total revenue requirements associated with the projects. Because annual revenue requirements begin at their highest level and decrease 39 See, Case 10-M-0457, et al., System Benefits Charge IV, Order Continuing the System Benefits Charge and Approving an Operating Plan for a Technology and Market Development Portfolio of System Benefits Charge Funded Programs (issued October 24, 2011).

40 The revenue requirement includes estimates of on-going operation and maintenance costs and property taxes.

CASE 12-E-0503 each year, and because resource cost savings were estimated to increase over time, estimated net savings increase over time.

Thus, for the first 15 years of asset life, DPS Staff estimated net benefits to have a net present value (NPV) of approximately

$260 million in 2016 dollars. For the full 40 years of rate recovery, the NPV of net benefits was estimated to be approximately $670 million.41 DPS Staff indicates that if IPEC were retired, the estimated net benefits of the TOTS projects are expected to be higher.

From this information, DPS Staff concluded that, even if IPEC is not retired, the benefits of each TOTS project would be greater than its costs individually, and that the benefits for all three projects together would exceed their combined costs. DPS Staff also determined that the net benefits of the TOTS projects would be even greater if IPEC were not available in 2016 and beyond. Based on its findings that either scenario would provide net benefits for ratepayers, DPS Staff recommends that the TOTS projects should be pursued.

Implementing the three TOTS projects is expected to contribute at least 600 MW toward the reliability relief which may be necessary if IPEC is shut down. The reliability benefits of the Ramapo/Rock Tavern line and the Marcy/Fraser project would be created in greater or lesser measure whether or not IPEC retires. Further, even if IPEC does not retire, and the TOTS are not required to avoid reliability violations, the increased transfer capability from these projects would still provide economic benefits by supplying lower cost energy from upstate sources to downstate consumers. The Staten Island unbottling project responds to Con Edisons in-city contingency planning needs, by decreasing the amount of in-city capacity Con 41 DPS Staff notes that the estimates of annual benefits are more uncertain as more distant time periods are analyzed.

CASE 12-E-0503 Edison needs to operate its system securely. This will also allow certain generators to run more, saving system resource costs.

We agree with DPS Staffs recommendation and accept the inclusion of the three TOTS projects in the portfolio for the IPEC Reliability Contingency Plan. Significantly, DPS Staffs analysis shows that the net benefits for ratepayers are available even if IPEC is not retired. We expect that Con Edison, NYSEG, and NYPA will proceed with the necessary permitting and approvals to achieve the June 1, 2016 in-service date for each project.

We emphasize that the cost estimates provided by Con Edison, NYSEG, and NYPA for these projects were provided so that the projects could compete with the other projects that responded to the NYPA RFP. As such, the TOTS projects were proposed in a competitive environment, which we believe should have induced Con Edison, NYSEG, and NYPA to propose the most competitive price possible. We expect to retain the benefits of this competitive process for ratepayers. Therefore, Con Edison, NYSEG, and NYPA should hold their investment costs for these projects to the estimates which they supplied when the project proposals were made, and which are reported supra. The cost recovery sought for each project, as contemplated in this Order, should be limited to actual costs or to the estimates provided here, whichever is lower.

B. EE/DR/CHP Programs In the 125 MW Revised EE/DR/CHP Program, Con Edison and NYSERDA, in consultation with NYPA, proposed a suite of new EE and DR projects designed to achieve 100 MW of peak demand reduction. They assessed these projects using a Total Resource Cost test, with adjustments, to determine the potential benefits CASE 12-E-0503 compared to the costs.42 The results of the test indicated that the benefits were equal to the costs, even assuming IPEC remains in service. The Revised EE/DR/CHP Program further indicated that with IPEC retired, the revised EE and DR programs would be more cost effective.

The costs of customer incentives are expected, on average, to constitute half of the revised EE and DR program costs. Con Edison and NYSERDA propose that a robust and detailed accounting would be maintained. However, the details regarding this accounting were not provided in the Revised EE/DR/CHP Program. Accordingly, we will require Con Edison to consult with NYSERDA and DPS Staff, and to develop detailed accounting procedures, reporting requirements, and an implementation plan, and to file such documents with the Secretary.

DPS Staff conducted a review of the benefit/cost analysis jointly performed by Con Edison and NYSERDA. After modifying the analysis to reflect a better forecast of the wholesale market price of energy, a year-round accounting of costs and benefits (rather than just on summer weekdays), and a more accurate estimate of the length of the programs, DPS Staff estimated that the benefits of the EE and DR programs, which were identified as part of the 125 MW Revised EE/DR/CHP Program, exceeded the costs assuming IPEC remained in service. The net resource cost savings were estimated to be approximately $182 42 The test was set forth using the following formula:

Bene it NPV Energy LineLoss Capacity Environmental T D Cost NPV UtilityCosts CustomerCosts ProgramAdmin We note that the customer costs in the above formula are not paid by utility ratepayer funds, but rather by customers own funds.

CASE 12-E-0503 43 million over 15 years. The estimated net resource cost savings were greater assuming IPEC is retired.

DPS Staff therefore recommends that these EE and DR programs be included in the IPEC Reliability Contingency Plan.

We agree with DPS Staff that these EE and DR programs are worthwhile pursuing, given our expectation that the benefits of these projects will exceed the costs. Accordingly, we accept the EE and DR components (totaling 100 MW) of the 125 MW Revised EE/DR/CHP Program, as proposed by Con Edison and NYSERDA.

We disagree with parties that suggest the proposed EE and DR resources should be compared to the cost of the transmission and generation resources that were submitted for consideration as replacement resources for IPEC. Based on the cost effectiveness of the proposed EE and DR programs, such a comparison is unnecessary. These programs are reasonable to pursue, regardless of whether IPEC is retired.

An important consideration for some parties is the extent to which the EE and DR programs peak demand reduction efforts would be coordinated with NYSERDA and Con Edisons regular EE programs. We are persuaded that the programs will be appropriately coordinated. Moreover, the proposal has the characteristic that the incentives and program rules of the commercial and industrial programs will be uniform for both the Commissions Energy Efficiency Portfolio Standard (EEPS) kWh incentives and the incentives for the EE and DR programs which we are considering here. Other elements of these EE and DR programs, such as thermal energy storage and battery arrays, are new programs that will not affect existing EEPS programs.

43 The benefits of the EE and DR programs identified in the Revised EE/DR/CHP Program exceeded the costs, even with the environmental components removed. Thus, the $182 million estimate would be even higher if the environmental components were included.

CASE 12-E-0503 Entergy asserts that reliance on EE is a major deviation from reliability system planning that could threaten system reliability if the energy efficiency program does not achieve its projected gains. We agree that reliance on EE and DR programs is relatively new. Energy efficiency, however, is not so new as to be untested. New York and several other states have accumulated significant experience with EE over the last 20 years. In fact, EE results are routinely used in the NYISO planning process as load modifiers. We are confident that EE is a proven resource that can be relied upon for many purposes, including the one at hand - ensuring reliability in the event IPEC is retired.

Many other details have been suggested by commenters, including combining EE with renewable generation at a customer location, aggregation of small thermal storage projects, and providing extra incentives for Made in New York solutions.

Our primary goal here, however, is to obtain the peak MW reductions needed by 2016 to help protect against reliability violations which could stem from the retirement of the IPEC. We will therefore accept the proposal, as put forward by Con Edison, NYSERDA, and NYPA, without further imposing specific requirements such as these.

We recognize that the EE and DR programs would be jointly implemented by Con Edison and NYSERDA, and we seek to ensure appropriate coordination between the two entities. The proposal to maintain a single point of customer entry should assist in eliminating duplicative procedures and confusion for customers. We anticipate that Con Edison and NYSERDA will develop appropriate agreements to facilitate the provision of any necessary customer information and program funds from Con CASE 12-E-0503 Edison to NYSERDA.44 To the extent such agreements cannot be reached after consultation with DPS Staff, a petition should be filed with the Commission for resolution.

We also find that NYSERDAs Expanded CHP Program should be pursued to obtain 25 MW, which is in addition to the 30 MW that NYSERDA estimates will be achieved in Con Edisons service territory by June 2016 under the CHP Program already approved by the Commission. We recognize that promoting CHP resources has broad and deep support among environmental, governmental, and business interests. We find that committing further funding toward CHP projects will help to advance the Commissions objective of promoting CHP, and to reduce the reliability needs identified in the NYISOs September 18, 2012 RNA. We also concur with the parties that believe that DR and CHP should, in combination, form a substantial component of the resources that are developed as part of the response to the potential retirement of IPEC. To ensure proper accounting and reporting of the CHP aspects of the Revised EE/DR/CHP Program, Con Edison and NYSERDA should develop detailed accounting procedures, reporting requirements and an implementation plan, as we are requiring with respect to the EE and DR programs.

Finally, we acknowledge NYPAs Build Smart NY Program, and will count NYPAs 15 MW target toward the identified reliability needs under the IPEC Reliability Contingency Plan.

However, because this program will be funded through NYPA low cost financing that is recovered from the direct program participants, we do not need to approve the program or the 44 Con Edison shall establish by agreement with NYSERDA, procedures for the transfer of funds to NYSERDA to repay NYSERDA for the costs it incurs in implementing the portion of the Revised EE/DR/CHP Program for which NYSERAD has responsibility. The form of this agreement, and of any amendments to this agreement, shall be filed with the Secretary as a compliance filing.

CASE 12-E-0503 associated funding. We expect that NYPA will update the Commission in the event that changed circumstances affect the achievement of the target amount within the necessary time frame.

In this Order, we accept the 125 MW EE/DR/CHP program set forth by Con Edison, NYSERDA and NYPA, and we take account of approximately 60 MW of peak demand reduction which these parties expect to achieve from existing programs. We recognize these are modest goals for programs of this type. We believe there continues to be unrecognized, cost-effective opportunities for EE, DR, and CHP programs to meet a greater portion of the reliability needs which the IPEC Reliability Contingency Plan describes. We direct Con Edison, working with DPS Staff, NYPA, and NYSERDA, to intensify its efforts to identify and exploit these additional opportunities, and direct Con Edison to report on these efforts by February 15, 2014.

Cost Allocation As noted above, DPS Staff, at our direction, prepared and filed a proposed methodology for allocating and recovering costs associated with the IPEC Reliability Contingency Plan, which was the subject of two technical conferences and various comments. In general, the DPS Staffs June Straw Proposal recommended that the same cost allocation methodology should be used for each element of the IPEC Reliability Contingency Plan portfolio. In this Order, and as discussed below, we are sensitive to the particular characteristics of the various elements of the portfolio, and we do not conclude that the same cost allocation methodologies should be used for all portfolio elements. Instead, we prefer to tailor the cost allocation solutions in a more granular way so that each specific portfolio CASE 12-E-0503 element uses the methodology that best suits its particular characteristics.

A. TOTS Projects In conjunction with their proposal for the TOTS projects, Con Edison and NYPA, along with the other NYTOs, have urged that DPS Staffs June Straw Proposal methodology should not be used to allocate the costs associated with implementing those projects. Instead, Con Edison and NYPA urge that the TOTS costs should be allocated in proportion to the shares already agreed to by the NYTOs in the context of preparing their NY Transco proposal.45 As noted above, Con Edison, NYPA and the other NY Transco participants have jointly identified 18 transmission projects throughout the State which, if approved, could be undertaken to improve the States transmission system.

The three TOTS projects were among those identified by the proponents of the NY Transco.

In response to the NYTOs cost allocation proposal, various commenters argued that cost allocation should be based solely upon a reliability beneficiaries pay methodology and should be consistent with the NYISO approach for reliability solutions. Some commenters were specifically critical of the NY Transco approach based upon their belief that the benefits of the three TOTS projects will accrue to Southeastern New York alone, and, at the same time, will bring higher energy costs and emissions to Upstate New York. Commenters also argued that the derivation of the NY Transco method has not been explained, and 45 The NYTOs have agreed to a NY Transco cost allocation as follows: 5.4% for Central Hudson Gas & Electric Corp. (CHG&E),

38.3% for Con Edison, 16.7% for Long Island Power Authority (LIPA), 10.4% for Niagara Mohawk d.b.a. Nation Grid, 5.8% for New York State Electric & Gas (NYSEG), 3.4% for Orange &

Rockland Utilities (O&R), 16.9% for NYPA, and 3.1% for Rochester Gas & Electric Corp. (RG&E). See, NYTO comments, dated July 22, 2013.

CASE 12-E-0503 that its sponsors have not demonstrated that the method aligns allocated costs with benefits. Further, concerns were raised that the NY Transco method will lead to inconsistencies between TOTS solutions and non-TOTS solutions, thereby resulting in an unlevel playing field and divergence from the NYISO reliability cost allocation approach. Others contended that the NY Transco cost allocation method was previously rejected by the Commission in the April 2013 Order. Finally, some commenters urged that the public policy that is needed to define and sanction the benefits claimed for the TOTS projects has not been developed and that this proceeding was not intended as the forum in which this policy should be developed.

While we understand the commenters concerns regarding the potential for different cost allocation methods for different solutions, we recognize several factors which weigh in favor of utilizing the proposed NY Transco approach for the three TOTS projects. Specifically, the NY Transco allocation was voluntarily developed and approved by all of the NYTOs. We acknowledge that the NYTOs have achieved a significant milestone in reaching this consensus, as they have solved a problem that can hinder the construction of infrastructure across utility service territories. In this instance, however, that barrier has been surmounted. In addition, based upon the IPEC Reliability Contingency Plan analysis, the three proposed TOTS projects were found to provide net benefits both with and without IPEC in service. We also recognize that the benefits from resource adequacy solutions for the replacement of the IPEC, such as the TOTS, do not accrue solely to downstate consumers. Rather, we agree with the NYTOs that these solutions should also provide some reliability benefits statewide. Based on these factors, we find the proposed allocation of costs and CASE 12-E-0503 benefits to be reasonable, and support the use of the proposed NY Transco cost allocation methodology.

Finally, we note that the proposed NY Transco approach, which provides that a share of the project costs will be assumed by LIPA and NYPA, achieves a broader distribution of project costs than have been achieveable in the past. In this regard, it is significant that LIPA has already indicated its agreement with the NY Transco approach.46 For this reason, it appears unlikely that a jurisdictional challenge from LIPA will be made.

B. EE/DR/CHP Programs DPS Staffs June Straw Proposal was silent on cost allocation for EE, DR, and CHP projects. However, the EE/DR/CHP submissions by Con Edison and NYPA urge that the costs of these programs should be allocated to Con Edisons ratepayers, just as the costs of similar utility EE, DR, or CHP programs have been allocated in the past. No commenters raised specific opposition to Con Edisons proposal. While some commenters favored a single cost allocation approach for all solutions, some favored Con Edisons cost allocation proposal for these programs. NYC stated that cost allocation of EE/DR/CHP projects need not be the same as that afforded to generation and transmission projects. Rather, NYC contends that the benefits associated with EE/DR/CHP projects are so specific to the utility service territory in which they are located that costs associated with those measures should not be spread to other utilities.47 Con Edison will have the ability to target its EE/DR program to help relieve its local distribution system, thereby 46 NYTO comments on behalf of the NY Transco with respect the IPEC Reliability Contingency Plan, p.9 (filed July 22, 2013)(indicating LIPAs willingness to accept a proposed cost allocation of 16.7%).

47 Initial comments of NYC at page 7.

CASE 12-E-0503 deriving specific local benefits. The Revised EE/DR/CHP Program will also provide specific and direct benefits to Con Edison customers in the form of reduced obligations to procure resource capacity.

We agree that, as recommended by Con Edison and supported by NYC and other commenters, the proposed cost allocation treatment, as submitted by Con Edison and NYSERDA, should be adopted. Accordingly, we determine that all of the costs for the Revised EE/DR/CHP Programs implemented by Con Edison and NYSERDA, as discussed herein, should be allocated to Con Edison customers, as proposed in the 125 MW Revised EE/DR/CHP Program. The costs allocated hereunder are referred to as the Energy Efficiency/Demand Reduction/Combined Heat and Power Program Costs.

Cost Recovery A. TOTS Projects For TOTS projects, DPS Staff proposed that cost recovery be provided through rate base treatment of the transmission plant in the rate case of the TO building the project. Through that process, the developer TO would place the plant in service and then earn a return on and of its investment. DPS Staff initially proposed that the revenue requirement associated with the plant would be offset by payments from other beneficiary utilities over a term of 15-years (to match the term of the generation Power Purchase Agreement (PPA) in the RFP). Based on verbal comments received during its first technical conference, DPS Staff subsequently proposed that the payments would continue until the original book cost of the project was fully depreciated. DPS Staff further offered that, as an alternative to this proposal, a CASE 12-E-0503 final exit payment could be made by the beneficiary utility to the TO in a manner that does not increase costs to ratepayers.

Once costs are allocated to the other beneficiary utilities, DPS Staff proposed that the allocation of costs to service classes within each utility shall be conducted in the same manner as other transmission capital and operating costs.

Once allocated to the service class, DPS Staff proposed that the cost be recovered through class specific volumetric (kWh) and demand (kW) surcharges.

The NYTOs, however, disagree with DPS Staffs proposed approach and claim that the use of the NYISO tariff to allocate and recover transmission costs is more efficient. The NYTOs argue that the NY Transco charge will be recovered from retail ratepayers in a manner that resembles the current way investor owned NYTOs recover other NYISO charges, such as NYISO Rate Schedule 1 and the NYPA Transmission Adjustment Charge. The NYTOs further contend that their method provides greater certainty and transparency than the June Straw Proposal.

We commend DPS Staffs significant efforts in developing the June Straw Proposal. However, for the reasons discussed above, and for purposes of cost recovery for the TOTS projects, we support the NYTOs proposed cost allocation/recovery approach for these projects. We expect the NYTOs will file an allocation and recovery mechanism which reflects their allocation/recovery approach for review and approval by FERC. We also expect that this application will seek recovery of the initial planning costs, up to $10 million, authorized in the April 2013 Order, and other related costs in developing the IPEC Reliability Contingency Plan.

B. EE/DR/CHP Programs As discussed above, the 125 MW Revised EE/DR/CHP Program costs will be allocated to Con Edison. Con Edison and CASE 12-E-0503 NYSERDA proposed that Con Edison delivery customers pay a surcharge to cover the cost of these projects, after those costs have been incurred, through the Monthly Adjustment Clause (MAC) charge, as is done for its Targeted Demand Side Management Program and other demand response programs, exclusive of NYPAs governmental customers who receive delivery service under the Companys PSC No. 12 - Electricity.48 Con Edison and NYSERDA estimate that the cost of the Revised EE/DR/CHP Program will be approximately $285 million. While some of these costs, such as portions of the costs associated with measurement and verification and with reporting will be incurred after implementation of the employed program measures, it is reasonable to expect that the majority of the 125 MW Revised EE/DR/CHP Program costs will be incurred from 2014 through 2016.

The resulting cost impact in a given year, depending on the timing of the cost incurrence, could be as high as $100 million for Con Edisons delivery customers.

To better match the time when costs of the 125 MW Revised EE/DR/CHP Program are incurred with the time when its benefits will occur, DPS Staff recommends that the costs be amortized over a ten year period. This approach would also mitigate the potential rate increases associated with recovering the costs on an as-incurred basis. We are mindful of the immediate rate impacts associated with the many initiatives that are before us, both in this proceeding and in other on-going proceedings. Accordingly, we authorize Con Edison to amortize the cost of the 125 MW Revised EE/DR/CHP Program over ten years in order to mitigate its immediate rate impacts.

The MAC is used to collect various costs from all of Con Edisons delivery customers. Its use, as proposed here for a similar purpose, is appropriate and therefore adopted. To 48 See, Revised EE/DR/CHP Program, pp. 20-21.

CASE 12-E-0503 implement this directive, Con Edison shall file the requisite tariff leaves to allow for cost recovery of the 125 MW Revised EE/DR/CHP Program. In addition, however, we may revisit this cost recovery and amortization period when making final decisions in other proceedings that have an impact on rates, with the goal of minimizing the overall customer impacts.

State Environmental Quality Review Act Earlier in this proceeding, the Commission considered its obligations under the State Environmental Quality Review Act (SEQRA) and directed DPS Staff to prepare a Generic Environmental Impact Statement (GEIS). Notice of our Determination of Significance was issued on May 21, 2013. DPS Staff subsequently developed a Draft GEIS, which we accepted as complete by Order issued July 18, 2013.49 As required by SEQRA, a Notice of Completion of the Draft GEIS was published in the Environmental Notice Bulletin (ENB) on July 24, 2013, and comments were accepted until the close of business on August 23, 2013.

Two sets of comments were received through the public comment process. The Final GEIS summarizes all of the substantive comments and reflects revisions made in response to them. Specifically, the following substantive changes were made to the Draft GEIS following the review of the comments:

1. Descriptions of the US Power Generating Companys generation projects were clarified in Section 2.4.1.3 (Proposed Electricity Generation Projects).

49 Case 12-E-0503, Generation Retirement Contingency Plans, Order Adopting and Approving Issuance of a Draft Environmental Impact Statement (issued July 18, 2013).

CASE 12-E-0503

2. Disclosure that the FERC has approved a new local capacity zone covering NYISO Zones G-J was added to Section 4.15.6 (Electric Rates).

3. Discussion of the New York State Energy Plan was added as Section 4.11.4.

4. New subsections were added (Sections 4.11.5 and 5.4.13) to address the impacts of power outages on customers with special needs.

5. A new section in Chapter 6, Cumulative Impacts, was added to specifically address the potential overlap between Energy Highway projects and the IPEC Contingency Plan components.

6. The list of required generalized permits and approvals in Table 7-1 was expanded.

We then determined that the Final GEIS presented a complete and comprehensive assessment of the significant adverse environmental impacts, as well as the benefits, that could arise with the implementation of the IPEC Reliability Contingency Plan; that it conformed to the requirements of SEQRA; and that it adequately responded to all the substantive comments provided on the Draft GEIS. Therefore, on September 19, 2013, we accepted it as the Final GEIS for the proposed adoption of an IPEC Reliability Contingency Plan and directed that the Notice of Completion of the Final GEIS be published in the ENB in accordance with 6 NYCRR Part 617.50 The Final GEIS describes the possible environmental impacts associated with the proposed action that includes acceptance of the IPEC Reliability Contingency Plan. The Final GEIS study shows that construction and operation of the projects contemplated in the Contingency Plan may have impacts on environmental resources in New York. The resources that may be 50 Notice was published in the ENB on September 25, 2013.

CASE 12-E-0503 affected, depending on the ultimate design of the projects and the construction methods employed, could include land use patterns, water resources, plants and animals, agricultural resources, aesthetic resources, historic and archaeological resources, open space and recreation, critical environmental areas, air quality, transportation, energy, noise and odor, public health, community character, and socioeconomics. The exact extent of these impacts is not quantifiable due to: (1) the complexity of the multiple factors affecting electric system operations in New York; (2) the interaction of New York's power grid with those of other states; (3) the timing of and types of possible market responses; and, (4) the geographically distributed nature of the portfolio of transmission and generation projects included in the IPEC Reliability Contingency Plan, and the likelihood that future regulatory actions will impact the final layout and design of those facilities.

However, the Final GEIS allows us to evaluate the environmental impacts of the proposed action in the context of the conditions that are likely to exist if we did not provide for a Reliability Contingency Plan. By ensuring the reliable delivery of electricity in the event that the IPEC is retired, the IPEC Reliability Contingency Plan minimizes the economic, social, and environmental effects which could result from the loss of that particular source of supply.

We further find that, even if the IPEC remains available, the Final GEIS demonstrates that the likely environmental impacts of implementing the IPEC Reliability Contingency Plan are the typical impacts associated with generation and transmission facilities, and that well-accepted mitigation techniques may be utilized in the design and construction processes to minimize their effects.

CASE 12-E-0503 We note that these new projects may be subject to site-specific licensing and permitting requirements, and that individualized environmental assessments would be conducted in those other proceedings.51 On the basis of the foregoing, and the discussion set forth in the Final GEIS, we make the findings stated above regarding the environmental impacts of the proposed action and certify that:

(1) the requirements of the State Environmental Quality Review Act, as implemented by 6 NYCRR Part 617, have been met; (2) consistent with social, economic, and other essential considerations, from among the reasonable alternatives available, the action being undertaken is one that avoids or minimizes adverse environmental impacts to the maximum extent practicable, and that adverse environmental impacts will be avoided or minimized to the maximum extent practicable by incorporating as conditions to the decision those mitigative measures that were identified as practicable; and (3) as applicable to the coastal area, the action being undertaken is consistent with applicable policies set forth in 19 NYCRR §600.5, regarding development, fish and wildlife, agricultural lands, scenic quality, public access, recreation, flooding and erosion hazards, and water resources.

51 Specifically, the details of the Ramapo/Rock Tavern project, for which this Commission previously issued an Article VII certificate, will receive scrutiny in DPS Staffs review of Con Edisons Environmental Management and Construction Plan (EM&CP). The Marcy/Fraser project will also be evaluated by DPS Staff upon submittal of an EM&CP for the Marcy South elements, and the reconductoring component will be subject to SEQRA review prior to construction. The Staten Island project will also undergo SEQRA review.

CASE 12-E-0503 Requests for Rehearing A. March 2013 Order The March 15 Order accepted the Con Edison/NYPA February Filing as responsive to the November 2012 Order and consistent with Con Edisons responsibilities to ensure safe and adequate service.52 In particular, the Commission accepted Con Edison and NYPAs determination that the reliability need was 1,350 MW, net of Con Edisons 100 MW EE and DR program. The Commission therefore approved the proposal, subject to certain modifications, for NYPA to issue an RFP in order to solicit projects for inclusion in the IPEC Reliability Contingency Plan that could assist in meeting this reliability need.

1. IPPNY On April 5, 2013, IPPNY sought rehearing of the Commissions March 2013 Order on the basis that the record was deficient and the Commission lacked a rational basis to proceed.

IPPNY identified various deficiencies in the Con Edison/NYPA February Filing, including 1) the failure to take into account the status of proposed power plants and AC and DC transmission projects; 2) the failure to provide an analysis of the extent, timing, and characteristics of the reliability needs that would arise if IPEC were retired; 3) the failure to quantify the degree to which the TOTS would address the IPEC-related resource adequacy or reactive power impacts; 4) the failure to consider any alternative projects; 5) the failure to demonstrate that the TOTS are narrowly tailored to address IPEC-specific reliability needs; and, 6) the failure to protect New York consumers from unnecessarily incurring substantial costs.

IPPNY further claimed the Commission improperly assigned NYPA the role of initially screening RFP responses for completeness and conformance with RFP requirements. IPPNY 52 November 2012 Order, p. 3.

CASE 12-E-0503 contends that NYPA has a conflict of interest, given its involvement in the TOTS projects, which should preclude NYPA from serving any role in the review of the RFP responses.

In addition, IPPNY asserted that the Commission improperly favored the TOTS projects by establishing different cost recovery standards for the TOTS projects compared to the RFP respondents, and failing to recognize potential market-based solutions in accordance with the FERC-approved tariff. IPPNY also maintained that allowing the TOTS projects to provide good faith estimates, as a basis for recovering their costs, improperly favored the TOTS over RFP respondents that were required to submit not-to-exceed-values.

2. Entergy On April 11, 2013, Entergy also sought rehearing based on the grounds that the Commission lacked a rational basis to proceed due to deficiencies identified in the February 2013 Contingency Plan Filing. Entergy suggested that the Con Edison/NYPA February Filing must be supplemented before the Commission can proceed, and that the Commission erred in concluding that the reliability deficiency should be further updated and refined prior to the conclusion of DPS Staffs evaluation of RFP responses.53

3. Commission Determination We reject the claims by IPPNY and Entergy that the Commission lacked a rational basis to issue the March 2013 Order, which accepted the Con Edison/NYPA February Filing as responsive to our November 2013 Order, and approved Con Edison and NYPAs plan to issue an RFP for solutions to meet the reliability planning needs. Neither party disputes the NYISOs analysis that identified reliability violations of transmission security and resource adequacy criteria by the summer of 2016 if 53 March 2013 Order, p. 12.

CASE 12-E-0503 the IPEC units were retired at the expiration of their current licenses.54 The NYISOs 2012 Reliability Needs Assessment, as updated by the Con Edison/NYPA February Filing, provided a rational basis for the Commission to proceed with the issuance of an RFP. IPPNYs claimed deficiencies are summarized above and have been addressed in this Order.

With respect to the role of NYPA, we disagree that NYPA was improperly assigned the role of screening timely proposals for completeness and conformance with the RFP requirements. As we expected, DPS Staff conducted an independent review of all RFP responses in order to verify and confirm NYPAs screening results. Because DPS Staff was expected to and, in fact, has provided an independent and unbiased verification of qualifying RFP responses, we reject IPPNYs argument that NYPA was inappropriately allowed to act in this capacity.

Finally, we find that allowing the TOTS projects to proceed and to recover limited costs in advance of determining a preferred portfolio of resources was not discriminatory, or biased in favor of the TOTS projects. Allowing the TOs to recover some preliminary planning costs for the TOTS appropriately reflects the NYTOss statutory responsibilities to ensure safe and adequate service. Accordingly, the petitions for rehearing filed by IPPNY and Entergy with respect to the March 2013 Order are denied.

B. April 2013 Order The April 2013 Order approved, subject to conditions, Con Edison, NYSEG, and NYPAs preliminary planning related to the three TOTS projects. The recovery of preliminary planning costs was approved, up to $10 million, for an initial period until the TOTS projects were analyzed further. Con Edison was 54 March 2013 Order, p. 7.

CASE 12-E-0503 also directed to work with NYSERDA and NYPA, and to file a revised plan to secure permanent peak reduction from incremental EE/DR and other resources. The Order also directed DPS Staff to propose a cost allocation and cost recovery mechanism for the Commissions consideration.

1. IPPNY On May 17, 2013, IPPNY sought rehearing of the Commissions April 2013 Order, which it claimed improperly favored the TOTS projects and discriminated against RFP respondents. IPPNY claimed the Commission improperly authorized preliminary planning activities for the TOTS and the recovery of up to $10 million dollars in related costs. According to IPPNY, these actions provide the TOTS with a head start and a significant advantage when compared with RFP respondents. IPPNY further contended that the TOTS should be required to provide firm bids and prevented from recovering cost overruns.

2. Entergy On May 20, 2013, Entergy filed its request for rehearing, which reiterated many of the same arguments it raised with respect to the March 2013 Order. Entergy continued to assert that the Commission could not rationally undertake any of its actions without curing the alleged deficiencies in the record. Entergy suggests that the Commission hold its actions in abeyance until Con Edison and NYPA have fully identified and quantified the scope and magnitude of Indian Point-based system needs and the PSC has had an adequate opportunity to review those needs.55 Asserting that the Commission lacked a rational basis, Entergy also recognized that the 2012 RNA performed by the NYISO reaffirmed that reactive power needs would also result if 55 Entergy, p. 16.

CASE 12-E-0503 Indian Point were required to cease operations.56 Entergy suggested that the Commission cease reliability planning efforts in this proceeding until additional information is provided, including NYISO analyses delineating the full nature and extent of Indian Point-related system needs....57 In addition, Entergy submitted that the Commission lacked the statutory authority to allocate costs incurred by Con Edison to other utility customers in the State. Similarly, Entergy submitted that the Commissions authority prevented directing the utilities that were allocated costs from reimbursing NYPA.

3. Commission Determination In large part, the arguments advanced on rehearing of our April 2013 Order are the same as were brought forward in the petitions for rehearing of the March 2013 Order. As noted above, we have, in considering the Petition for Rehearing for the March 2013 Order, addressed these objections and found they lack merit. We also find that our authority to ensure rates are just and reasonable necessarily entails ensuring costs are allocated appropriately. Accordingly, the petitions for rehearing filed by IPPNY and Entergy with respect to the April 2013 Order are denied.

CONCLUSION As stated in previous orders, the potential retirement of the IPEC raises unique and significant reliability issues.

These reliability issues, which could threaten the public health, safety, and welfare, are compounded by the inability of existing processes and markets to fashion a timely response. In response to this problem, and, in particular, to fashion an 56 Entergy, p. 17.

57 Entergy, p. 25.

CASE 12-E-0503 appropriate response to the uncertainties associated with the potential retirement of the IPEC as early as December 2015, we sought the development of an IPEC Reliability Contingency Plan.

In this Order, we reviewed the plan developed in response to the Commissions earlier orders, and find that two components of this plan, i.e., the three Transmission Owners Transmission Solution projects and the 125 MW Revised EE/DR/CHP Program, should be accepted now and move as promptly as possible to implementation. We further find that the IPEC Reliability Contingency Plan, as proposed by Con Edison and NYPA, and as modified in this Order, and which includes these two components properly balances our reliability concerns with the costs to ratepayers, impacts on the environment, and other matters.

Accordingly, we conclude that the acceptance of the IPEC Reliability Contingency Plan will support the continued provision of safe and adequate service, and is in the public interest.

Because of uncertainties in the generation market, DPS Staff recommends and we agree that no action should be taken at this time regarding the potential generation solutions identified through the NYPA RFP which was issued in furtherance of the Plan. Con Edison, in consultation with NYPA, should continue to monitor the status of projects which may enter or rejoin the generation market, and to assess whether changed circumstances would justify an expansion of the portfolio approved in this Order for the IPEC Reliability Contingency Plan.

Further, to support the implementation of the IPEC Reliability Contingency Plan, which we are accepting in this Order, this proceeding has described the methodologies that will be used for cost allocation and recovery for projects which are part of the plan. This Order concludes that these methodologies CASE 12-E-0503 are just and reasonable and may be relied upon as the IPEC Reliability Contingency Plan is implemented.

The Commission orders:

1. The Indian Point Energy Center (IPEC) Reliability Contingency Plan (Plan), as described in the Consolidated Edison Company of New York, Inc. (Con Edison) and New York Power Authority (NYPA) February 1, 2013 Filing (Con Edison/NYPA February Filing), and as further described in the body of this Order, is an appropriate response to the potential reliability needs which could be associated with the retirement of the generation resources at IPEC, and such Plan, as modified through this Order, is accepted.

2. The portfolio currently accepted for the implementation of the IPEC Reliability Contingency Plan shall include two elements, i.e.:

a. The three Transmission Owner Transmission Solutions (TOTS) projects as described in the Con Edison/NYPA February Filing, as updated and discussed in the body of this Order; and

b. The 125 MW Revised Energy Efficiency/Demand Reduction/Combined Heat and Power (EE/DR/CHP) program, as described in the Con Edison/NYPA/New York State Energy Research and Development Authority (NYSERDA) filings, and discussed in the body of this Order.

3. Con Edison and New York State Electric and Gas Corporation (NYSEG) shall, and NYPA and NYSERDA are expected, to use their best efforts to undertake and timely complete their projects being undertaken as part of the IPEC Reliability Contingency Plan, as set forth in the body of this Order.

CASE 12-E-0503

4. As set forth in the body of this Order, Con Edison and NYSEG, in consultation with NYPA, should proceed as quickly as possible with an application to the Federal Energy Regulatory Commission for approval for the cost allocation and cost recovery for the TOTS projects. Con Edison and NYSEG, in consultation with NYPA, shall supply a report on the progress of this cost allocation and cost recovery application on or before June 30, 2014, and every six months thereafter.

5. Con Edison is directed to file tariff amendments, to be become effective on a temporary basis on or before March 1, 2014, on not less than 30 days notice, as are consistent with the provisions of this Order and necessary to effectuate the recovery of the Energy Efficiency/Demand Reduction/Combined Heat and Power Program Costs that have been allocated to Con Edison in this Order. Con Edison shall serve copies of this filing on all parties to this case. Any comments on the filing must be filed within 14 days of service of such filing. The tariff amendments specified in the filing shall not become effective on a permanent basis until approved by the Commission.

6. Con Edison shall consult with NYSERDA and Department of Public Service Staff, and file detailed accounting procedures, reporting requirements, and an implementation plan regarding the Revised Energy Efficiency/Demand Reduction/Combined Heat and Power Programs with the Secretary, as discussed in the body of this Order, within 90 days of this Order. Con Edison shall serve copies of this filing on all parties to this case. Any comments on the filing must be filed within 14 days of service of such filing.

7. Con Edison shall consult with NYSERDA, NYPA, and Department of Public Service Staff, and file a report with the Secretary on the identification of additional cost-effective CASE 12-E-0503 opportunities for energy efficiency, demand reduction, and combined heat and power programs, as discussed in the body of this Order, by February 15, 2014.

8. The requirements of Section 66(12)(b) of the Public Service Law as to newspaper publication of the tariff amendments described in Ordering Clause No. 5 are waived.

9. The Secretary may extend the deadlines set forth in this order upon good cause shown, provided the request for such extension is in writing and filed on a timely basis, which should be on at least one day's notice.

10. The developer transmission owners for the TOTS projects identified in this order shall construct and operate the TOTS projects in compliance with any environmental impact mitigation requirements established through the site-specific environmental permitting for such projects.

11. The petitions of Independent Power Producers of New York, Inc. for rehearing are denied.

12. The petitions of Entergy Nuclear Indian Point 2, LLC, Entergy Nuclear Indian Point 3, LLC, Entergy Nuclear Fitzpatrick, LLC, and Entergy Nuclear Operations, Inc. for rehearing are denied.

13. This proceeding is continued.

By the Commission, Kathleen H. Burgess Digitally Signed by Secretary New York Public Service Commission (SIGNED) KATHLEEN H. BURGESS Secretary CASE 12-E-0503 Appendix A

SUMMARY

OF NOTICES

1. To seek comments in this Case 12-E-0503, the Department issued four notices pursuant to the State Administrative Procedure Act (SAPA). The date of publication for these notices and a summary of the SAPAs are:

1) 2/20/2013 - The Public Service Commission (Commission) is considering portions of a filing made by Consolidated Edison Company of New York, Inc. and the New York Power Authority on February 1, 2013, concerning reliability contingency plans to address the potential retirement of the Indian Point Energy Center (Filing). The Commission is considering whether to adopt, modify, or reject, in whole or in part, the aspects of the Filing identified as items 2(a) through 2(e) on pages 3 to 4, as discussed at those pages and elsewhere in the Filing.

2) 6/5/2013 - The Public Service Commission (Commission) is considering a filing made by the Department of Public Service on June 4, 2013, concerning a proposed method for allocating and recovering the costs associated with the reliability contingency plans to address the potential retirement of the Indian Point Energy Center (Filing).

The Department of Public Service also included in the Filing a proposed Reimbursement Agreement to address the costs incurred by the New York Power Authority in connection with the Indian Point Energy Center reliability contingency plans. The Commission is considering whether to adopt, modify, or reject, in whole or in part, the Filing, and may address related matters.

3) 7/3/2013 - The Public Service Commission (Commission) is considering whether to adopt, modify, or reject, in whole or in part, proposed projects for inclusion in reliability contingency plan(s) to address the potential retirement of the Indian Point Energy Center, and may address related matters. The Commission is considering various proposed projects filed in Case 12-E-0503 between February 1, 2013, and June 13, 2013, by Consolidated Edison Company of New York, Inc., New York Power Authority and New York State Electric and Gas Corporation, Poseidon Transmission LLC, West Point Partners, LLC, Iberdrola USA Management Corporation,

CASE 12-E-0503 Appendix A Boundless Energy N.E., LLC, CPV Valley, LLC, Cricket Valley Energy Center LLC, GE Energy Financial Services, NRG Energy, Inc., US Power Generating Company, NYC Energy, LLC, Entergy Nuclear Power Marketing (on behalf of Entergy Nuclear Indian Point 2 LLC, Entergy Nuclear Indian Point 3 LLC, and Entergy Nuclear Operations, Inc.), CCI Roseton LLC, Selkirk Cogen Partners, L.P., and AES Energy Storage, LLC.

4) 7/17/2013 - The Public Service Commission (Commission) is considering whether to adopt, modify, or reject, in whole or in part, proposed energy efficiency, demand reduction, and combined heat and power projects filed in Case 12-E-0503 on June 20, 2013, by Consolidated Edison Company of New York, Inc., the New York Power Authority, and the New York State Energy Research and Development Authority (Filing). The Commission may address the June 20, 2013 Filing and related matters in developing reliability contingency plan(s) to address the potential retirement of the Indian Point Energy Center.

2. In addition, the Department issued its own notices for comments and to announce two technical conferences as follows:

2/13/2013 Notices Generation Retirement Contingency Plans, Notice Soliciting Comments 6/5/2013 Notices Proceeding on Motion of the Commission to Review Generation Retirement Contingency Plans, Notice Soliciting Comments and of Technical Conference 6/20/2013 Notices Generation Retirement Contingency Plans, Notice of Updated Information for Technical Conference 7/2/2013 Notices Generation Retirement Contingency Plans, Notice of Second Technical Conference and Revised Comment Schedule

3. The Department also sought comments in connection with its draft Generic Environmental Impact Statement as follows:

7/18/2013 Notices Generation Retirement Contingency Plans, Notice of Completion of Draft Generic Environmental Impact Statement CASE 12-E-0503 Appendix A

SUMMARY

OF COMMENTS African American Environmentalist Association:

The African American Environmentalist Association expresses support for the continued operation of IPEC.

Boilermakers Local Lodge No. 5 (Boilermakers):

The Boilermakers urge the Commission to abandon the development of a contingency plan for the retirement of the IPEC, and instead pursue needed investment in New York's energy infrastructure.

Boundless Energy NE, LLC:

Boundless Energy asserts that the NYTO proposal to cost allocate NYTO projects in the IPEC Contingency Plan in the same way as projects in the AC Transmission Proceeding (Case 12-T-0502) is premature and unfair. It suggests that inappropriate distinctions in cost allocation should not be made between NYTO projects and other transmission developers.

Business Council of New York State:

The Business Council of New York State requests that the Commission abandon its pursuit of an IPEC Reliability Contingency Plan and pursue a more deliberate, discerning approach towards planning for the retirement of New Yorks electric generating units.

Business Council of Westchester:

The Business Council of Westchester expresses its opposition to burdening Westchester County and New York City ratepayers with the $811 million cost to develop projects in compliance with the Indian Point contingency plan.

CASE 12-E-0503 Appendix A Bronx Chamber of Commerce:

The Bronx Chamber of Commerce maintains that the June Straw Proposal delivers only questionable benefits for the downstate regions, while placing an undue, harmful burden on the local economy.

Brookfield Renewable Energy Group (Brookfield):

Brookfield supports the IPEC contingency planning effort, but maintains that the plan did not provide an opportunity for the market to provide solutions to meet the potential need.

Brookfield is concerned that out-of-market approaches to planning have the potential to result in adverse consequences on the markets, impairing investor confidence and significantly increasing the risk profile of merchant generators that are crucial to the functioning of New York's electricity system.

Overall, Brookfield believes that the State should endeavor to address identified or contingent needs within market structures wherever possible.

Central Hudson Gas & Electric (Central Hudson):

Central Hudson asks the Commission to consider other benefits in cost allocation besides reliability. It asserts that the use of the new ICAP zone (NCZ) and the indicative Locational Capacity Requirements (LCR) as the basis for the allocation of transmission solutions is a misapplication of the NCZ LCR. Central Hudson maintains the TOTS projects provide the same benefits as AC Transmission and should be cost allocated as per the NY Transco method.

Cogen Technologies Linden Venture, LP (Cogen):

Cogen agrees that it is prudent for the Commission to work with stakeholders to develop a reliability contingency plan to address issues which may arise upon the closure of the IPEC.

CASE 12-E-0503 Appendix A Cogen supports the consideration of existing resources in the contingency plan and the availability of natural gas in developing the plan.

Consolidated Edison Company of New York, Inc. (Con Edison):

In its reply to comments on the Con Edison/NYPA February Filing, Con Edison stated that: 1) it appropriately identified the impact from on-going EE and CHP activities, 2) its proposed EE/DR program does target incremental reductions to peak demand,

3) the EE/DR program will allow a clear market signal to develop that encourages peak demand reduction, 4) the proposed incentive structure is complementary to existing utility and NYSERDA EEPS programs, 5) it has evaluated likely opportunities where the market can quickly deliver peak demand reductions, 6) program costs will be collected in arrears, and will cost between $150 to $300 million. Con Edison also provided additional details regarding its proposed Cost/Benefit test.

Consolidated Edison Solutions, Inc.:

Con Edison Solutions notes that the collection of transmission costs from all Load Serving Entities through a NYISO charge would be a departure from the historical practice of having the individual transmission owner recover its transmission costs as part of its delivery service charge from all its customers, regardless of whether such customers are purchasing their electricity from the utility or a competitive supplier such as Con Edison Solutions. In addition, transmission costs are not something that competitive suppliers can hedge or readily predict. Therefore, to the extent that the Commission approves the Filing, Con Edison Solutions requests that the Commission direct the various utilities participating in these projects to work with the NYISO to provide periodic estimates of the anticipated revenue requirements and resulting CASE 12-E-0503 Appendix A transmission rates that LSEs would be charged and that customers can expect to pay.

Consumer Power Advocates (CPA):

CPA argues for a balanced approach to address any reliability needs including a strong EE/DR program, with "market pricing mechanisms for EE/DR as the best way to insure balance between demand side and supply side solutions." CPA also argues that Distributed Generation and Combined Heat and Power systems also be included in the EE/DR program.

Cricket Valley Energy Center LLC (Cricket Valley):

Cricket Valley generally supports the Con Edison/NYPA Contingency Plan, but requests revisions to the proposed in-service date making it farther out in time. Cricket Valley also suggests the Plan is biased toward the TOTS and EE/DR programs, and seeks to have generation projects compete on an equal basis.

Empire Generating Co., LLC, et al.58:

The New York Generators argue that FERC has exclusive jurisdiction over the interstate transmission projects and wholesale generation projects proposed in this proceeding, thereby precluding the Commissions jurisdiction. The Straw Proposal, according to the New York Generators threatens to preclude or interfere with NYISO operations and planning process. They maintain that the Commissions jurisdiction over cost allocation has not been established.

58 Empire Generating Co, LLC, TC Ravenswood LLC, US Power Generating Company (parent company of Astoria Generating Company, L.P), PSEG Power New York LLC and PSEG Energy Resources and Trade LLC submitting jointly as the New York Generators.

CASE 12-E-0503 Appendix A Entergy Nuclear Indian Point 2, LLC, et al. (Entergy):

Entergy argues that the Con Edison/NYPA February Filing does not indicate the full nature of the reliability impacts that would be caused by an IPEC shutdown. Entergy notes that the NYISOs 2012 RNA indicates that there would be both resource adequacy and reactive power implications if Indian Point was required to cease operations, and points out that the Filing only quantifies the resource adequacy related needs.59 Entergy strongly opposes adoption of the IPEC Reliability Contingency Plan. Entergy first argues that the Plan has failed to provide all the information identified in the Commissions April 19, 2013 Order, and thus the Commission lacks basis for approving the plan. Entergy argues that insufficient system planning and analysis has been completed and in particular there is a lack of information about the extent, timing, and characteristics of system needs related to a possible IPEC closure. Entergy points out that IPEC retirement needs, as identified in the NYISOs 2012 Reliability Needs Assessment, include resource adequacy needs, transmission security needs and reactive power considerations. It argues the Con Edison/NYPA February Filing failed to consider transmission security needs and reactive power considerations. Further, Entergy argues the Commissions March 2013 Order (approving the RFP process) and April 19, 2013 Order (advancing transmission and EE/DR/CHP projects) were both issued irrespective of these non-resource considerations. Entergy also points out that although DPS staff confirmed at the July 15, 2013 Technical Conference that transmission security needs have been completed, no analyses were provided, including a quantification of the estimated level of transmission security violations that would occur with an IPEC retirement. Entergy points out that resource adequacy 59 Entergy comments, February 22, 2013, p. 11.

CASE 12-E-0503 Appendix A estimates provided by DPS Staff at the Technical Conference differed from the earlier Joint Plan calculation, providing further support, Entergy argues, that the core information identified in the Commissions November 2012 Order (i.e. the full extent, timing and characteristics of system needs) is lacking. Entergy concludes this point by arguing that absent this information, adoption of the EE/DR/CHP program would be arbitrary and capricious.

Entergy argues there is a lack of information regarding whether the Revised EE/DR/CHP Program, together with the TOTS projects, addresses IPEC-specific system needs. Entergys view is that the TOTS projects and EE/DR/CHP plan do not address the full scope of the system resource adequacy, transmission security, and reactive power considerations. Entergy opines that there has been a lack of portfolio-based analysis and that the TOTS projects and EE/DR/CHP plans, as well as the earlier plan, have failed to properly assess other alternatives and whether such alternatives could be implemented at a later time and/or at a lower cost to better protect New York consumers.

Entergy concludes by reiterating its view that the Commission lacks a rational basis to approve the EE/DR/CHP plan absent a full assessment of system needs, the quantification of the proposed solutions towards the needs and an assessment of alternatives, including timing and costs.

Entergy also suggests that even if the record was sufficient, the Revised EE/DR/CHP Program requires changes.

Entergy argues that the EE/DR/CHP plan should be properly evaluated within a broader competitive process. Entergy argues the EE/DR/CHP plan was erroneously separated from the RFP process required from the Commissions November 2012 Order.

While the earlier Con Edison/NYPA February Filing proposed that the TOTS Projects would subsequently be compared against RFP procured projects, Entergy argues that there have not been any CASE 12-E-0503 Appendix A provisions for the EE/DR/CHP plan to be evaluated against other options. Entergy recommends that the EE/DR/CHP plan also be assessed using the Comparative Evaluation Process for evaluating the TOTS Projects and RFP Projects against each other.

Entergy argues that the EE/DR/CHP plan must not supplant the EEPS Program. Entergy argues that further review is required to ensure the EE/DR/CHP plan would foster, and not supplant, existing EEPS programs and why those EEPS programs have not focused on the proposed incremental savings.

Entergy argues the projected schedule of MW reductions should be further reviewed. Entergy points out that the originally filed Joint Plan presented, in Entergys opinion, an overly aggressive MW reduction schedule that projects the 100 MW reduction from EE/DR/CHP to be accomplished by the end of 2015.

In particular, Entergy points out that the Joint Plan plans to achieve 34% of the MW savings during the first 21 months of the program with the remaining balance to be achieved during the 12 months of calendar year 2015. Entergy echoes the initial comments of New York City which opines that trends in efficient lighting programs suggest most efficiency gains from lighting come early in a program and then are increasingly difficult to attain. This, in Entergys view, conflicts with the projections of the Joint Plan, and Entergy recommends that the Commission, therefore, carefully scrutinize the reasonableness of the proposed MW attainment schedule.

Entergy requests that the Commission: (1) reject Section 2(e) of the Joint Plan, which finds the TOTs project meet public policy requirements, because neither the November 2012 Order, which defines the scope of this proceeding nor the EHI Task Force Blueprint, establish "public policy requirements" as defined by the NYISO in its October Compliance Filing even if the FERC ultimately accepted the NYISO's expansive definition in CASE 12-E-0503 Appendix A this regard; (2) direct Con Edison (with NYPA, to the extent deemed necessary) to expeditiously supplement the Joint Plan to provide information: (i) identifying in detail the full scope and nature of the reliability needs that would be triggered if the Indian Point facilities were required to cease operations; (ii) quantifying the degree to which each of its proposed solutions addresses each identified need; and (iii) identifying the timing and costs of other alternatives that also are viable options to address each identified need; and (3) defer any action on the Notice as it pertains to Sections2(a) through (d) of the Joint Plan until Con Edison supplements the Joint Plan.

Entergy argues that FERC has exclusive jurisdiction over rates, terms, and conditions of transmission service and wholesale generation service, and State law provides no basis for the Commission to implement the June Straw Proposal. It maintains two flawed assumptions exist in the Straw Proposal:

(1) markets forces will fail to provide a solution if IPEC ceases operations; and (2) the NYISOs reliability planning process will fail to address the problem. Entergy suggests the NYISO gap solutions are intended to solve this problem. It suggests there are no current reliability needs, and no proof that the IPEC cant be relicensed.

Environmental Defense Fund (EDF):

EDF commends the Commission for its vision in recognizing that energy efficiency, distributed renewable generation, demand response, and combined heat-and-power represent resources that can play a critical role in meeting system needs.

Hudson Valley Gateway Chamber of Commerce:

The Hudson Valley Gateway Chamber of Commerce raises concerns with the financial impacts of the June Straw Proposal.

CASE 12-E-0503 Appendix A H.Q. Energy Services (HQ):

HQ urges the Commission to adopt a RFP process that allows developers to propose in-service dates for their respective projects later than June 2016. Allowing for alternative in-service dates, HQ asserts, will encourage more developers to participate in the RFP process, thereby driving competition, lowering project costs and increasing options to alleviate reliability concerns.

Ian Ramcharitar:

Opposes the development of the IPEC Reliability Contingency Plan because it would add a surcharge to the existing rates, which he maintains are already too high.

Ice Energy Holdings Inc. (Ice Energy):

Ice Energy, which manufactures and develops thermal (ice) storage systems, strongly supports the Contingency Plan and the inclusion of thermal energy storage systems in the Plan. Ice Energy recommends the Plan be further modified as follows; Ice Energy argues that enhanced payments be added for projects or technologies that combine energy efficiency or demand response with customer-side distributed renewable energy resources, such as photovoltaic energy. Ice Energy takes exception to footnote 8 on page 9 of the Plan where Con Edison and NYSERDA state that further discussion is needed before Renewable Portfolio Standard-eligible renewables can be included. Ice Energy argues that innovation now allow multiple technologies to be deployed in a single project and that such combined systems should be entitled to enhanced payments to provide appropriate incentives for such clean energy transition.

Ice Energy recommends that the aggregation of smaller projects into one or more larger projects be explicitly allowed.

Ice Energy notes that the Plan language may be interpreted as CASE 12-E-0503 Appendix A implicitly allowing this but they recommend that aggregation be explicitly added to the Plan. They cite the language on page 4 of the Plan, which states the incentives will include a bonus for large projects and project aggregations by large customers. Ice Energy also notes the statement on page 5 of the Plan which indicates Con Edison will focus its recruitment on large commercial and industrial customers. Ice Energy comments that program objectives can also be accomplished by focusing on many smaller commercial and industrial customers and aggregating small projects into larger projects that can be monitored and controlled as one project. Ice Energy states, for example, that the definition of a large project could be one customer in excess of 1MW or more peak day demand, or could alternatively be defined as an aggregation of smaller customers into 1MW or more of peak day demand. Ice Energy further states that incentives should be payable to either an eligible electric customer paying into the IPEC Reliability Surcharge or to a project developer that aggregates multiple host sites in which all of the electric customers within the aggregation would otherwise qualify for individual payments.

Ice Energy recommends extra benefits for made in New York Solutions. Ice Energy argues that solutions manufactured in New York State provide substantial additional benefits that merit enhanced benefit premium payments. Procuring locally sourced equipment provides benefits, in Ice Energys opinion, of enhancing clean energy innovation, reducing greenhouse gases used in out of state shipping, and enhancing the states struggling tax base.

Ice Energy argues that where a technology or project provides more benefits to Con Edison than to a distributed host customer, Con Edison should pay more than the proposed 50-50 cost share allocation. Ice Energy takes exception to the Plans implicit assumption, in its opinion, that customer benefits CASE 12-E-0503 Appendix A from a project will, at all times, be equal to or greater than Con Edisons benefits. This, in Ice Energys view, is the basis for the footnote 6 on page 8 which states cost share for participants represents approximately half of total project costs. Ice Energy posits that this implicit assumption is not always true and cites an example where a customer installs a thermal storage system which allows for more efficient air conditioning operation. Ice Energy argues that in cases like these the energy savings and lower bill benefits to the customer can often be far outweighed by the benefit to the utility in terms of peak demand reduction, reduced need for transmission and distribution infrastructure, and environmental benefits from less fossil fuel consumption for required peaking generation.

Ice Energy concludes that Con Edison would be a free rider in these cases and that the proposed 50/50 sharing in these cases would lead to the project being non-cost-effective from the customer side, potentially killing such projects. Ice Energy recommends, therefore, that incentive payments are allowed to be graduated to increase customer payments in cases where the utility benefits more than the customer.

Ice Energy further argues that renewable energy should be included. Ice Energy reiterates that the peak day demand reduction benefits of renewable energy technology is well proven and should be included in the Plan, and that this should be done without the need for exhaustive study or further delay.

Independent Power Producers of New York, Inc. (IPPNY):

IPPNY, similar to Entergy, also argues that the Con Edison/NYPA February Filing fails to indicate the full nature of the reliability impacts that would be caused by an IPEC shutdown. IPPNY further states that Con Edisons proposal does not give market-based solutions an opportunity to respond to the IPEC reliability deficiency need. IPPNY contends that the IPEC CASE 12-E-0503 Appendix A Contingency Plan harms the competitive market and it is substantively deficient.

Jan Mayer:

Opposes the development of the IPEC Reliability Contingency Plan, which she contends will increase rates and have no benefits.

Long Island Power Authority (LIPA):

LIPA notes the Commissions limited jurisdiction over LIPA.

LIPA asserts DPS Staffs Straw Proposal has various differences from the NYISOs reliability cost allocation approach and does not address the beneficiaries pay principle.

Mary Ellen Furlong:

Ms. Furlong questions the timing of the IPEC Reliability Contingency Plan, which she characterizes as an attempt to sneak a ratepayer fee.

Matthew Fiorillo:

Mr. Fiorillo opposes the IPEC Reliability Contingency Plan and the June Straw Proposal as an unnecessary increase in electric rates.

Multiple Intervenors (MI):

MI argues that the Con Edison/NYPA February Filing fails to include an analysis, for planning purposes, of the extent, timing, and characteristics of the reliability needs that would arise if Indian Point Units 2 and 3 were retired, as required by the November 2012 Order. MI requests that the Commission reject the contingency plan submitted by Con Edison and NYPA as deficient. Additionally, if and when cost allocation issues are ripe for resolution in this proceeding, MI asks the Commission to adhere to the same beneficiaries pay principles that it has CASE 12-E-0503 Appendix A enumerated and followed very recently when confronted with the exact same issue (i.e., the incurrence of costs to solve a potential reliability problem created by the proposed closure of a generation facility).

MI focused its reply comments on Staffs June Straw Proposal, arguing first that the Commission should refrain from the unnecessary imposition of exorbitant costs on retail electricity customers, especially based on the incomplete record in this proceeding. MI argues that the purported contributions of individual projects such as the TOTS, and presumably (but not explicitly stated) the energy efficiency plan, are not clear and unproven. Secondly, MI argues that the NYTOs arguments opposing the Commissions prior approval of a reliability beneficiaries pay cost allocation methodology should be rejected. In a point related to this, MI states the IPEC reliability proceeding falls short of the requirements of FERC Order No. 1000 on Transmission Planning and Cost Allocation, which directs that transmission planning and cost allocation initiatives be broadly considered through legislative process or a broadly considered comprehensive regulated process. MI concludes that the Commissions possible approval of the TOTS projects or EE/DR/CHP plan is not being completed in response to a broad considered public process, but rather is being contemplated by a narrower desire to maintain reliability in the face of the possible closure of IPEC.

MI argues that the Commission should not approve the TOTS projects, but instead evaluate them thoroughly along with any RFP submitted projects. MI also continues to argue for the "beneficiaries pay" allocation policy. It also reiterates its initial comments that there was "inadequate justification for the proposed, substantial expenditures on energy efficiency (EE) and demand response (DR)."

CASE 12-E-0503 Appendix A MI argues against the NY Transco approach on the basis that: (a) the NY Transco concept has yet to be justified and does not yet exist; (b) it is unclear if NYPA or LIPA can participate in the NY Transco; (c) contrary to statements that NY Transco will be a public/private partnership, it appears to exclude any material private investment, thereby being funded primarily through ratepayers; (d) NY Transco has not been shown to be in the public interest; and, (e) the Commission has not approved the NY Transco concept. Therefore, MI posits that no basis exists to adopt the NY Transco cost allocation method.

MI argues the NY Transco cost allocation methodology in inconsistent with the Commissions prior ruling that allocation should be based upon reliability beneficiaries pay. The NY Transco cost allocation method, according to MI, is highly inequitable to Upstate NY customers as they are not beneficiaries of the IPEC Contingency Plan. It notes the Commission has allocated costs of Upstate NY generator closings to Upstate NY customers without considering allocating any costs to Downstate. It also suggests that benefits, other than reliability, are irrelevant to cost allocation given that the IPEC Contingency Plan was undertaken to address reliability concerns, and the Commission ruled that costs in this proceeding should be based on reliability beneficiaries pay. MI argues this proceeding is specifically limited to the potential closing of the IPEC, and as such is not invoking any statewide public policy, thereby making the argument that TOTS projects provide public policy benefits specious when no federal or State law or regulation or order has defined or sanctioned that public policy.

Municipal Electric Utilities Association (MEUA):

MEUA argues that the Commission should retain a beneficiaries pay model, such as the DPS June Straw Proposal.

MEUA contends the NY Transco allocation directly violates the CASE 12-E-0503 Appendix A April 2013 Order, which indicated that cost allocation should adhere to a beneficiaries pay principle. It also argues that NY Transco claims of benefits are unsupported on the record.

Derivation of the NY Transco cost allocation method has not been explained. Further, MEUA asserts that the NYTOs have not demonstrated that the NY Transco cost allocation satisfies FERCs cost allocation requirements.

Natural Resource Defense Council and Pace Energy and Climate Center (NRDC):

NRDC asserts that this proceeding presents an opportunity for the State to set an example for the nation on how to responsibly confront the potential retirement of baseload generation in a manner that maintains reliability through an innovative portfolio of diverse resourcesincluding a robust suite of investments in targeted energy efficiency, renewables, clean distributed generation, such as CHP, and demand response.

NRDC is concerned that the Con Edison/NYPA February Filing relies primarily on the 20th century model of large central generation and upgrades to transmission infrastructure. NRDC argues that while these conventional resources will likely be a component of the final contingency plan, they should only be considered after all cost-effective energy efficiency, distributed and other renewable generation, CHP and demand response is achieved.

New York Affordable Reliable Electricity Alliance:

The New York Affordable Reliable Electricity Alliance opposes the June Straw Proposal cost allocation. It maintains that the continued operation of the IPEC makes good sense for the State's energy supply and economy.

New York Battery and Energy Storage Technology Consortium, Inc.

(NY-BEST):

CASE 12-E-0503 Appendix A NY-BEST comments that distributed energy storage systems should be part of Con Ed's planned 100MW of Energy Efficiency/Demand Reduction/CHP. NY-BEST opines that distributed energy storage solutions are becoming commercially available, and offer the potential benefits of better balancing of transmission and distribution resources and deeper penetration of renewable resources. NY-BEST also points out that the generally smaller size of distributed storage systems compared to traditional generation and transmission and distribution solutions, and the ability to aggregate storage systems, offer advantages of easier and quicker deployment that can substantially contribute to reducing demand reduction by 100 MW by the summer of 2015 in the Con Edison territory."

New York City Hispanic Chamber of Commerce, Inc.:

The NYC Hispanic Chamber of Commerce expresses deep concern and opposition with the proposal to require Con Edison to spend nearly $1 billion of ratepayer money to find a replacement for the IPEC.

New York City Office of Long-Term Planning and Sustainability (NYC):

NYC argues that the Con Edison/NYPA February Filing does not indicate the full nature of the reliability impacts that would be caused by an IPEC shutdown. NYC also comments on Con Edisons filing pertaining to its analysis of the reliability needs that would arise from an IPEC shutdown stating that the discussion is provided but limited to the reference to the NYISO 2012 Reliability Needs Assessment.60 NYC claims that Con Edisons Plan does not include an identification and assessment 60 NYC comments, February 22, 2013, p. 13.

CASE 12-E-0503 Appendix A of the generation, transmission, and other resources.61 NYC also contends that there is no need for the Commission to burden the States ratepayers with hundreds of millions, or billions, of dollars of unnecessary costs on generation and transmission facilities that will not be needed in 2016.

With respect to EE/DR/CHP, NYC argues that the Commission should not apply the cost allocation methodology set forth in Staffs Straw Proposal to EE/DR/CHP projects. The City argues that EE/DR/CHP benefits projects are specific to the utility service territory in which they are located and that costs associated with those measures should not be spread to other utilities.

NYC argues that the Commission should not approve the Con Edison/NYPA February Filing. Instead, NYC recommends the following changes to the EE/DR program proposed in the contingency plan: 1) "before authorizing any expenditure of ratepayer funds, the PSC should direct Con Edison to engage in the preliminary fact-finding and analysis necessary to prove both the reasonableness of its proposals and that the load/demand reductions can actually be achieved;" 2) "if energy efficiency and demand response are to be part of the replacement for the output of IPEC, the most logical and appropriate approach would be to expand or increase funding for the [Energy Efficiency Portfolio Standard] programs, and to target such programs to affected downstate areas;" 3) "the PSC should not allow Con Edison to spend more on energy efficiency or other load reductions than it would cost to replace the capacity of IPEC;" 4) the "PSC [should] treat the [EE/DR] expense as a shareholder-provided capital investment for which its shareholders would receive the same rate of return applicable to its actual capital investments; 5) Should the PSC decide that 61 MI comments, February 22, 2013, p. 6; NYC comments, February 22, 2013, p. 13.

CASE 12-E-0503 Appendix A Con Edison should proceed with the EE/DR program, "the City recommends that the Companys effort be focused on supporting and incentivizing distributed generation (DG) projects throughout the City that could be completed by 2016 and that would, with greater likelihood, result in large-scale peak load reductions;" and, 6) Con Ed should continue to use the TRC test.

In the City's words, "Given the higher costs of the proposed program, the use of less demanding standards to measure cost-effectiveness is inappropriate and should not be adopted."

NYC argues that FERC has exclusive jurisdiction over interstate transmission service, including the TOTS. It also asserts that no studies have been performed to indicate Zones G-J are the only beneficiaries of the IPEC Reliability Contingency Plan. It notes the DPS Staff June Straw Proposal does not allocate costs to municipalities or cooperatives. However, NYC suggests that the EE/DR/CHP programs are locational specific, are moving separately in this proceeding and do not compete with generation or transmission, and is therefore fair to allocate the costs of EE/DR/CHP to Con Edisons service territory.

NYC also argues the Commission lacks jurisdiction over NYPA to recover NYPA costs incurred. NYC suggests that NYPA can procure new capacity on behalf of NYC only with NYCs express consent.

New York Energy Consumers Council, Inc.:

The New York Energy Consumers Council hopes the Commission will act responsibly and refuse to order the expenditure of any unnecessary ratepayer funds while the closure of Indian Point remains inconclusive.

CASE 12-E-0503 Appendix A New York State Assemblyman Alfred Graf:

Assemblyman Graf is concerned about the potential cost-shifting to the already beleaguered ratepayers on Long Island as the New York Power Authority, with Con Edison move forward with New York State Assemblyman McDonough:

Assemblyman McDonough expresses strong concerns with potential cost-shifting to Long Island.

New York State Assemblyman Joseph D. Morelle:

Assemblyman Morelle is concerned with the pace of this proceeding, and that ratepayers in one region of the State may wind up subsidizing ratepayers in another region of the State.

He is also concerned about the effects of a rate increase on business, families, and the economy.

New York State Assemblyman William A. Barclay:

Assemblyman Barclay conveys his strong concerns regarding the implementation of the Indian Point Contingency Plan and the cost that such a plan will have on New York ratepayers.

New York State Assemblyman Andrew R. Garbarino:

Assemblyman Garbarino has concerns with potential cost-shifting to Long Island ratepayers as part of the IPEC Reliability Contingency Plan.

New York State Department of Environmental Conservation (DEC):

DEC requests that the Commission give priority to environmentally beneficial projects such as renewable energy and repowering existing generation facilities. DEC also seeks to ensure adequate consideration of environmental factors.

CASE 12-E-0503 Appendix A New York State Energy Research and Development Authority (NYSERDA):

NYSERDA comments on the Con Edison/NYPA February Filing state that the proposed EE and DR programs include technology options and customer eligibility parameters that are inappropriately narrow while the proposed budget and ratepayer collections appear inappropriately expansive. While NYSERDA believes the 100 MW target is reasonable, it suggests options and opportunities to deliver 100 MW of EE and Load Management (LM) load reduction.

New York State Senator David Carlucci:

Senator Carlucci asserts that due to the uncertainty over the continued operation of Indian Point Energy Center, a comprehensive plan must be developed in the event the facility is retired.

New York State Senator George D. Maziarz:

Senator Maziarz expresses concern regarding the potential cost implications to ratepayer from the implementation of the IPEC Reliability Contingency Plan. In his view, these costs should not be allocated to Upstate ratepayers but should be focused on consumers in Westchester and New York City. He expresses additional concerns about the possibility that assets or resources of NYPA, which are created through the NYPA hydroelectric facilities in Western New York, will be directed to IPEC Reliability Contingency Plan investments, which are located in southeastern New York and which are unlikely to provide benefits to Western New York customers. Finally, Senator Maziarz objects to the magnitude of the costs of the facilities which could be a part of the Plan's portfolio, and especially where the recovery of some or all of these costs will require rate increases for NYPA customers. Senator Maziarz CASE 12-E-0503 Appendix A concludes by recommending that the investments approved in the Plan should be directed toward the construction of new transmission facilities so that power can more easily flow from Upstate and Western New York power plants to New York City customers.

New York State Senator Kevin S. Parker:

Senator Parker raises concerns regarding the proposal to require Con Edison ratepayers (along with other New York distribution utilities), to spend nearly $1 billion to find a replacement for the IPEC.

New York State Senator Mark Grisanti:

Senator Grisanti urges the Commission to consider the cost implications to the ratepayers of Upstate New York associated with the development and implementation of the IPEC Reliability Contingency Plan.

New York State Senator Ted OBrien:

Senator OBrien urges the Commission to consider the cost implications to Upstate New York ratepayers.

New York State Senator Timothy M. Kennedy:

Senator Kennedy argues that the contingency plan developed by Con Edison and the NYPA will burden ratepayers in Upstate New York with subsidizing projects that will solely benefit downstate customers.

New York Transmission Owners (on behalf of NY Transco):

The NYTOs argue that all NY Transco projects (with TOTS being a part) provide significant statewide benefits. The NYTOs maintain there are various benefits in the aggregate of all NY Transco projects in terms of added jobs, tax revenues, economic CASE 12-E-0503 Appendix A growth, emissions, energy market efficiency and reliability.

The NY Transco adjusted load ratio share cost allocation, they maintain, accounts for all benefits that may accrue upstate and downstate. The adjusted load ratio share Transco cost allocation assumes 75% of befits accrue Downstate versus 60% for a straight load ratio share. The NYTOs argue that the same cost allocation for transmission, generation, and DR does not accommodate different benefits because each (or at least transmission versus generation/DR) impact the system in different ways.

The NYTOs urge the Commission to endorse the NY Transco cost recovery proposal. NY Transco cost recovery method via the NYISO Tariff will apply to all loads and will obviate the need for contracts; and therefore will be more efficient and less problematic administratively than the DPS Straw Proposal to recover transmission costs. Irrespective of the methods chosen, the NYTOs request that the Commission ensure full cost recovery.

NRG Energy, Inc. (NRG):

NRG states in its comments that it understands that the New York Independent System Operators 2012 Reliability Needs Assessment concluded that violations of transmission security and resource adequacy criteria would occur in 2016 if the 2,000 MW Indian Point Plant were to be retired at the end of 2015.

NRG further notes that there would be dramatic and immediate reliability impacts.62 Nucor Steel Auburn, Inc.:

Nucor Steel supports DPS Staffs cost recovery Straw Proposal. Nucor Steel agrees with a beneficiaries pay approach, and an allocation based upon peak coincident demand 62 NRG comments, February 22, 2013, (no pages numbers on document but would be 2-3 if numbered).

CASE 12-E-0503 Appendix A and expanding it to non-transmission solutions (as opposed to the NYTO proposal which only applies to TOTS). Nucor Steel indicates there is a need to recognize and reconcile overlap between this proceeding and the AC Transmission upgrades case (12-T-0502) by affirming that reliability takes precedence for cost allocation. It also suggests that the exit payment mentioned in June Straw Proposal needs more detail.

Paul Heagerty:

Mr. Heagerty maintains that the possible addition of more electric generating plants in New York State could increase his power bill, while the IPEC already produces safe, reliable and clean energy already.

Pure Energy Infrastructure, LLC (Pure Energy):

Pure Energy proffers that the proposals for inclusion in the IPEC Reliability Contingency Plan need to be carefully managed and evaluated to ensure that low-cost, competitive and reliable transmission/generation solutions result. Pure Energy supports the use of the total resource cost test in conducting this evaluation. Pure Energy also advises that multi-unit, distributed generation resources offer unique reliability benefits, which the Commission should consider.

Queens Chamber of Commerce:

The Queens Chamber of Commerce expresses concern about the cost of the June Straw Proposal.

Retail Energy Supply Association (RESA):

RESA contends that this entire proceeding and the development and implementation of various transmission and generation reliability projects rest on the assumption and presumption that the Indian Point generating facility will fail CASE 12-E-0503 Appendix A to be relicensed and will be taken out of operation. Under these circumstances, RESA argues it would be prudent for the Commission to move in a cautious and deliberate manner that is reflective of the provisional nature of the entire need for these reliability projects. RESA supports the cost recovery methodologies presented in the DPS Staff June Straw Proposal.

According to RESA, including cost recovery in delivery rates is consistent with previous Commission cost recovery approaches such as Renewable Portfolio Standards and Energy Efficiency Portfolio Standards and is administratively simpler/more efficient, as opposed to the approach advocated by Con Edison, et al.

Richard Roberts:

Mr. Roberts opposes the IPEC Reliability Contingency Plan, which he characterizes as a dangerous and unnecessary path that would exacerbate the climate and air pollution challenges we already face, while at the same time costing us jobs and hurting New York's economy.

Robert Licata:

Opposes the development of the IPEC Reliability Contingency Plan because it would increase rates, which he maintains are already too high, while the IPEC provides an available source of energy.

Rockland Business Association:

The Rockland Business Association is concerned about the cost of the June Straw Proposal. It argues that there is a fundamental need for the IPEC's continued operation and the multitude of benefits it provides.

CASE 12-E-0503 Appendix A Sierra Club:

Sierra Club endorses Con Edisons aggressive approach to energy efficiency and demand resources. It urges the Commission to require a significantly robust approach to distributed renewable generation to fully capitalize on this useful and cost-effective resource. Sierra Club also encourages the Commission to ensure that the RFP is structured in a way that it will not result in a significant net increase in New Yorks greenhouse gas emissions, by carving out a significant role for renewable energy.

Steamfitters Local Union 638:

The Union is dismayed that, with major warning signs about climate change, the Commission would be spending so much time and taxpayer dollars on efforts to close Indian Point -a significant source of carbon-free electricity.

Thomas McCaffrey, Russell Warren, Phil Quesnel, Stephen Juravich, John Kaczor, Christine Rorrenberk, Anthony DeDonato, Neil Burke, Thomas Pulcher, Dan Johnson, Mario Digenova, Joseph Bubel, Michael Delvin, Richard Drake, J.A.

Tonkin, Maureen Bubel, Joe Pechacek, Debra Caltabiano, Edward DeGasperis, Roy Spangenberger, Thomas Opet, Lou Merlino, Rich Lamb, Stanhope Waterfield, Mike Harris, James Timone, Daniel Cooke, Leland Cerra, Joseph Rutz, Robert Herrmann, Harry Primrose, Tom Phillips, Cathy Izyk, Adam Kaczmarek, David Buyes, Benjamin Lawrence, Cheryl Croulet, Donald Croulet, Daniel Cooke, Theresa Motko, Tony Iraola, Brett Kenner, Peter Gunsch, Kelly Smith, Arun Thomas, Paul Platt, Kou John Hong, Deborah Fields, James Thompson, Robert Altadonna, Kai Lo, E. Dean Hewitt, Robert Heath, Dennis Skiffington, Ray Fucheck, et al.

These individuals urge the commission to abandon this proceeding as this process is not in the best interest of all New Yorkers. The potential costs in electric rates to plan for the potential closure of a facility that is intent on staying CASE 12-E-0503 Appendix A open for business is an inexcusable waste of our limited taxpayer dollars.

Town of Huntington, New York:

The Town supports the repowering of the existing Northport Power Station, which it argues should be included in the IPEC Reliability Contingency Plan.

Town of Putnam Valley, New York:

The Town requests that the Commission withdraw the contingency plan and the June Straw Proposal for cost recovery.

It maintains that the consequences of this plan will worsen the current fiscal stress that local governments currently face, and transfer unnecessary cost burdens to ratepayers in the region.

US Power Generating Company, LLC (USPowerGen):

USPowerGen identifies several technical inaccuracies in the descriptions of the USPowerGen projects discussed in the Indian Point Contingency Plan, Draft Generic Environmental Impact Statement July 2013.

Utility Workers Union of America Local 1-2:

The Utility Workers Union of America Local 1-2 supports the continued operation of the IPEC.

Westchester County Association:

The Westchester County Association expresses its deep concern with the June Straw Proposal, and that ratepayers will be saddled with $811 million in added costs for projects that will likely be deemed unnecessary, especially if the plan was solely developed for the purpose of replacing the power from Indian Point.

CASE 12-E-0503 Appendix A West Point Partners, LLC (West Point):

West Point maintains that several modifications to the plan proposed in the Con Edison/NYPA February Filing are needed in order to satisfy the requirements of the November 2012 Order.

First, West Point suggests that Con Edison should be directed to submit a supplement that assesses other projects now under development. Second, the plan should be modified so as to create a more level playing field between the TOTS and other projects.

White Plains Housing Authority:

The Housing Authority expresses its support that the IPEC should remain in service.