David T. Doot Secretary September 25, 2015
VIA ELECTRONIC MAIL
TO: MEMBERS AND ALTERNATES OF THE NEPOOL PARTICIPANTS COMMITTEE
RE: Supplemental Notice of October 2, 2015 NEPOOL Participants Committee Meeting
Pursuant to Section 6.6 of the Second Restated New England Power Pool Agreement, supplemental notice is hereby given that a meeting of the NEPOOL Participants Committee will be held on Friday, October 2, 2015 at 10:00 a.m. at The Colonnade Hotel, 120 Huntington Avenue, Boston, MA. The Participants Committee meeting will be held in the Huntington Ballroom for the purposes set forth on the attached agenda and posted with the meeting materials at http://nepool.com/NPC_2015.php. For your information, this meeting will be recorded, as are all the NEPOOL Participants Committee meetings.
We remind you of two items requiring your attention at this time:
• Agenda and supporting materials need to be identified and assembled by Friday, October 16 for the upcoming meetings among the members, the ISO Directors, and the State officials. Those meetings will take place before the November 6, 2015 Participants Committee meeting at the Hilton Logan Boston Airport Hotel. The format for the Board and state official discussions will continue to be separate meetings organized along modified Sector lines. The ISO staff has explained that it must circulate the background materials to its Board early that following week and it needs some time to assemble and consolidate all necessary materials.
• We need each Sector to identify for us no later than Friday, October 23, 2015 the voting member that has been chosen to represent that Sector in 2016. Please review the memorandum concerning the selection process for next year’s Committee officers that is included with this notice.
Hotel rooms in Boston during this time period are very limited and the NEPOOL block of rooms is full. If you wish to reserve a room at The Colonnade Hotel, please contact the hotel directly to check on availability or to be put on a wait list (617-424-7000). If you are having difficulty finding a room in Boston, please contact Cindy Jacobs ([email protected]/860-275-0246) and she will try to assist you.
Respectfully yours,
/s/ David T. Doot, Secretary NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING
FINAL AGENDA
1. To approve the preliminary minutes of the Participants Committee meeting held on September 11. The draft minutes of the September 11 meeting are marked to show changes from the prior draft circulated with the initial notice.
2. To adopt and approve all actions recommended by the Technical Committees set forth on the Consent Agenda included with this supplemental notice and posted on the NEPOOL website. Please note that Consent Agenda Item No. 2 has been removed and will be discussed as Item 6.a.
3. To receive an ISO Chief Executive Officer Report.
4. To receive an ISO Chief Operating Officer Report.
4A. To receive an ISO 2015 Q2 Quarterly Markets Report. The IMM’s summary presentation will be circulated and posted with the additional materials for the meeting.
5. To consider, and take action, as appropriate, on the following proposed budgets:
a. 2016 ISO-NE Operating and Capital Budgets; and
b. 2016 NESCOE Budget.
Background materials and draft resolutions are included with this supplemental notice.
6. To consider, and to take action as appropriate on, the following Reliability Committee- recommended values for the 2019/2020 Capacity Commitment Period (FCA10):
a. the Hydro-Quebec Interconnection Capability Credits (HQICC Values); and
b. the New England Installed Capacity Requirement (ICR), Net ICR, the capacity requirement values for the System-Wide Capacity Demand Curve (Demand Curve) and the Southeast New England Local Sourcing Requirement (LSR) (together, the ICR Values).
Background materials and draft resolutions are included and posted with this supplemental notice.
7. To receive a report on current matters relating to regional wholesale power and transmission arrangements that are pending before the regulators and the courts, including the following:
a. To receive a report, and to determine next NEPOOL steps, if any, with respect to, the FERC’s September 17 NOPR on Connected Entity Data (RM15-23). A summary and presentation will be circulated in advance of the meeting.
The litigation report will also be posted in advance of the meeting.
8. To receive reports from committees and subcommittees.
9. To transact such other business as may properly come before the meeting. NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3517
PRELIMINARY
A meeting of the NEPOOL Participants Committee was held beginning at 10:00 a.m. on Friday, September 11, 2015 at the Seaport Hotel and World Trade Center, Boston, MA. A quorum determined in accordance with the Second Restated NEPOOL Agreement was present and acting throughout the meeting. Attachment 1 identifies the members, alternates, and temporary alternates attending the meeting.
Mr. Joel Gordon, Chairman, presided and Mr. David Doot, Secretary, recorded.
VOTE ON SLATE OF CANDIDATES FOR ISO BOARD
The Committee began the meeting with members agreeing to go into Executive Session to consider a proposed slate of candidates for election to the ISO Board. Members were reminded that the reason for consideration of the slate in Executive Session was to maintain the identity of the candidates being considered for membership on the ISO Board in confidence until there was a final ISO Board decision on the slate. That slate, which was identified in a confidential package of materials that was circulated to the members and alternates of the Committee in advance of the meeting, was presented on behalf of the Joint
Nominating Committee (JNC) by Mr. Barney Rush, with comments from the Participants
Committee Officers who were members of the JNC. Following that presentation, Mr. Rush and all ISO representatives and all guests present left the meeting.
EXECUTIVE SESSION
The slate was then discussed among the voting representatives. Following discussion in Executive Session, the following motion was duly made, seconded and voted by written ballot per prior agreement of the Participants Committee: NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3518
RESOLVED, that the Participants Committee endorses the slate of candidates for the ISO Board that has been recommended by the Joint Nominating Committee and presented to the Participants Committee in Executive Session at this meeting.
GENERAL SESSION
Following the tabulation of the written ballots, the Committee came out of Executive
Session, were and was rejoined by ISO representatives and guests.
Mr. Gordon welcomed the members, alternates and guests who were present. He recognized with appreciation, Chairperson Margaret Curran, President of the New England
Conference of Public Utilities Commissioners (NECPUC), stating this was her last meeting as
NECPUC President, as her term was ending at the end of the month and to Mr. Edward
McNamara, whose NECPUC term was also ending.
Mr. Gordon also announced that the motion to endorse the slate of candidates for election to the ISO Board passed with a vote exceeding the 70% of the aggregate Sector
Voting Shares required under the Participants Agreement. Mr. Gordon reminded the
Committee that the ISO Board would vote on the Committee-endorsed confidential slate at its
September Board meeting, and again urged Participants to keep the identity of the slate confidential until the ISO Board announced publicly the election of the slate. He indicated that a copy of the ISO announcement would be circulated to the Committee following its issuance.
Then, acknowledging the timing of this meeting, the Committee held a moment of silence in recognition and honor of those that lost their lives on September 11, 2002 and to their loved ones. NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3519
APPROVAL OF MINUTES OF AUGUST 7, 2015 MEETING
Mr. Gordon referred the Committee to the preliminary minutes of the August 7, 2015 meeting that had been circulated and posted in advance of the meeting. Following motion duly made and seconded, the preliminary minutes of the August 7, 2015 meeting were unanimously approved with an abstention noted by Marble River.
CONSENT AGENDA
Mr. Gordon referred the Committee to the Consent Agenda that was circulated in advance of the meeting. Following motion duly made and seconded, the Consent Agenda was unanimously approved, without discussion or comment.
WINTER SEASONAL CLAIMED CAPABILITY FOR MONTHY RECONFIGURATION AUCTIONS PROPOSAL
Mr. Gordon reported that this item was being considered earlier on the agenda, as it would have been on the Consent Agenda, but for the timing of the Markets Committee meetingrecommendation. He referred the Committee to the materials circulated in advance of the meeting regarding revisions to Market Rule 1 to allow a resource’s Qualified Capacity used in monthly reconfiguration auctions during the Winter delivery period to be updated from the value established for the applicable third Annual Reconfiguration Auction (ARA3). He reported that the revisions were proposed by NRG Power Marketing LLC (NRG) at the
September 2-3, 2015 Markets Committee meeting, and recommended unanimously for approval by the Participants Committee approval, with several abstentions noted.
The following motion was duly made and seconded:
RESOLVED, that the Participants Committee supports revisions to Market Rule 1 to allow a resource’s Qualified Capacity used for monthly reconfiguration auctions in the winter delivery period to be NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3520
updated from the value established for the applicable third Annual Reconfiguration Auction, as recommended by the Markets Committee at its September 2-3, 2015 meeting, and as circulated to this Committee in advance of the meeting, together with such non- substantive changes as may be agreed to after the meeting by the Chair and Vice-Chair of the Markets Committee.
The Committee considered and unanimously approved the motion with an abstention noted by Energy America. Mr. Gordon expressed appreciation to the Committee and the ISO for working together through the stakeholder process. He reported that the ISO and NEPOOL willwould jointly file jointly on September 14 the proposed Market Rule 1 changes with the
FERC on September 14, requesting an October 13 effective date, which would allow the revisions to be effective for the December ARA3 for the 2016/17 Capacity Commitment
Period.
REPORT OF THE ISO CHIEF EXECUTIVE OFFICER
Mr. Gordon van Welie, ISO Chief Executive Officer (CEO), referred the Committee to the written summaries of the ISO Board and Board Committee meetings that had occurred since the last Participants Committee meeting, which were circulated and posted in advance of the meeting. There were no questions or comments on the ISO Board summaries.
REPORT OF THE ISO CHIEF OPERATING OFFICER
Dr. Vamsi Chadalavada, ISO Chief Operating Officer (COO), referred the Committee to the September COO report addressing August operations, which was circulated in advance of the meeting and posted on the NEPOOL and ISO websites. Focusing on highlights, he stated that, in August: (i) Energy Market value was $425 million, up $52 million from July
2015, and up $46 million from August 2014; (ii) natural gas average prices were 19.1% higher NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3521 than July 2015 average prices; (iii) Real-Time Hub locational marginal prices (LMPs) on average were 39% higher than July 2015 LMPs; (iv) average (peak hour) Day-Ahead cleared physical Energy, as a percentage of forecasted load, was 98.2% in August 2015, down from
99% in July 2015; and (v) Net Commitment Period Compensation (NCPC) totaled $5.6 million (1.7% of the total Energy Market value), up $475,000 from July 2015 and down
$104,000 from August 2014. Of that $5.6 million in NCPC, he reported that $4.5 million was for first contingency payments (down $472,000 from July) and $1.1 million for second contingency payments (up $871,000 from July 2015), which were almost all incurred on one day in Northeastern Massachusetts (NEMA). Voltage support payments for August were
$12,000, down $147,000 from July.
Turning to highlights of the Forward Capacity Market (FCM), Dr. Chadalavada reported the following: Installed Capacity Requirement (ICR) development discussions were continuing at the Power Supply Planning Committee (PSPC), with a FERC filing planned on or before November 10; new resource qualification packages were being reviewed by the
Internal Market Monitor (IMM) and System Planning, with Qualification Determinations
Notifications (QDNs) to be sent to Participants by September 25; permanent and static de-list bids also were being reviewed by the IMM with those QDNs to be sent to Participants also by
September 25; and the Non-Price Retirement Request window was open and would close on
October 12, with no significant retirement requests received to date.
Dr. Chadalavada then referred the Committee to an update from the 2014/15 Winter
Reliability Program, which he stated would be included in each monthly report until all results of the Program had been reported. He said there was no change from the prior month. NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3522
Updating the Committee on system operations, Dr. Chadalavada reported that Action 1 was taken under Operating Procedure No. 4 (Action During Aa Capacity Deficiency) (OP-4) on September 9. The Action was declared late in the day, when load had been forecasted to be about 23,800 MW but actual loads trended 400-500 MW higher than forecast. He said that, at 16:36, the region lost about 400-500 MW of supply across the HQ Phase II tie due to a transmission contingency, which required the ISO to have a short-duration reserve deficiency that ISO operators properly addressed through OP-4 Action 1. He said that an OP-4 Action letter would be circulated to Participants Committee members and alternates. In response to clarifying questions regarding the event, Dr. Chadalavada stated that the loads and dew points were trendinged higher than forecasted and it was a combination of the 400-500 MW of extra load for that region, compounded by the loss of Phase II, that caused the reserve deficiency.
Dr. Chadalavada was asked to identify the impact of solar energy on peak loads. He explained that there was a material impact on the peaks and that the ISO was studying the issue to assess the magnitude of that impact, as reflected in the 2016 Work Plan. The ISO expected to have some data analyzed by the second quarter of 2016, with that analysis to be reflected in the subsequent load forecasts. He said that load forecasts needed to be considered in two parts: (1) the short-term forecast to be used for operations; and (2) the long-range forecast to be used by planning both for calculating ICR and for transmission planning purposes.
In follow up to a request from the prior month’s report, Dr. Chadalavada continued to decline to identify the load levels within NEMA that generally result in higher out-of-merit commitments, pending legal advice as to the timing and content of any permissible disclosure. NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3523
Regarding a statement concerning, and the ISO’s operational plan to deal with, a forecasted capacity deficiency in NEMA in 2016/17, Dr. Chadalavada stated that was still a work in progress. He explained in response that, with the delayed in-service dates for the Footprint
Salem Harbor project, the ISO had identified that NEMA will have a deficiency of about 200
MW that the ISO needed to address with local transmission owners.
Dr. Chadalavada reported that, beginning that week, and continuing through the end of
October, Participants should expect several gas pipeline maintenance outages. Pipelines were expected to all be back in-service for the Winter Period. He estimated that limited natural gas transportation could reduce by up to 3,500 MW the natural gasgas-fired capacity available to meet demand in September, and by as much as 4,500-5,500 MW during October. The result heHe expected that would beresult in the need to call on production from oil and coal-fired units.
2016/17 BUSINESS PRIORITIES / WORK PLAN
Mr. Gordon referred the Committee to the 2016/17 Draft Work Plan and related business priorities materials circulated in advance of the meeting. He explained that discussion of the forthcomingfollowing year’s Work Plan had been accelerated this yearin
2015 as part of the initiative to align the annual business planning process more closely towith the approval of the ISO’s budgets covering those periods. He stated that the Work Plan reflected significant input provided by NEPOOL through the business priorities efforts recently concluded, including the input that was provided to the Sector Vice-Chairs during June and
July, and the ISO’s meaningful response to that input. NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3524
Reviewing the process, Mr. Gordon stated that, following the discussion of business priories with regulators and the ISO at the NECPUC Symposium and the Participants
Committee June Summer Meeting, NEPOOL oOfficers solicited input from each of their
Sectors and then worked together to prepare the 2016 NEPOOL Business Priorities memomemorandum. With that memomemorandum in hand, the oOfficers met with ISO management in August to discuss NEPOOL’s business priorities in an effort to ensure that the
ISO work plan reflected those priorities. Following that meeting, the ISO prepared its Draft
Work Plan. He noted that he also shared the 2016 NEPOOL Business Priorities memomemorandum with leadership of both the New England States Committee on Electricity
(NESCOE) and NECPUC. In response to the NEPOOL memomemorandum and the ISO
Draft Work Plan, NESCOE prepared and shared with the ISO and NEPOOL its reaction and suggestions. He said that the Officers met with ISO management and representatives of
NESCOE and NECPUC on September 1 to discuss an earlier draft of the ISO’s Work Plan.
With input from NEPOOL and NESCOE, the ISO adjusted its Work Plan and it had been circulated to the entire NEPOOL membership for broader input and discussion. He noted that the ISO 2016 Operating and Capital Budgets would be discussed at this meeting as well. He said the Participants Committee would vote on those bBudgets at the October 2 Participants
Committee meeting, but had not voted previously, and there were no plans this year for a vote, on the ISO’s Work Plan.
Ms. Heather Hunt, NESCOE Executive Director, referred the Committee to NESCOE’s preliminary comments on the Draft Work Plan circulated with the meeting materials in advance of the meeting. She expressed appreciation to the ISO for the States’ opportunity to NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3525 provide comments on the Work Plan, and to NEPOOL for its efforts to identify its business priorities to be considered concurrently with the ISO’s draft Work Plan. She stated that
NESCOE provided its written comments before the organizations could discuss together the economic study that NEPOOL indicated it was seeking in its priorities. She said NESCOE was working on a white paper that would explore the various regulatory mechanisms available to the States to help realize their policy preferences and directives. Following that white paper, NESCOE expected to do a scenario analysis, and would communicate closely with
NEPOOL and the ISO to maximize the value of the various analyses that were contemplated.
Ms. Rachel Goldwasser, NECPUC Executive Director, echoed appreciation for NECPUC being included in the business planning process that NEPOOL pushed to occur earlier in the year. She said NECPUC found the process to be helpful, thoughtful and engaging. She stated that NECPUC looked forward to continuing with the accelerated process going forward.
Mr. Gordon stated that this was the first time that NEPOOL had not only moved up the Work Plan discussion, but had tried independently and proactively to identify NEPOOL’s priorities for consideration in the ISO’s Work Plan. He encouraged Committee members to provide him or any of the otherNEPOOL oOfficers their ideas for improvement or ways to make the process more transparent.
Planning / Operations Activities
Dr. Chadalavada then reviewed the draft 2016 Work Plan circulated in advance of the meeting. He highlighted several of the key Planning / Operations activities, including:
• Annual Economic Study ¨ Review potential impacts of emerging public policy directives on performance of the New England markets and power system. NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3526
¨ Study scope definition efforts, with NEPOOL and the States to help shape, to be completed before the end of the first quarter (Q1) 2016. 2016 Economic Study requests must be submitted by April 1, 2016. • Capacity Zones Modeling ¨ Overview of the expected power system topology for the 2020/21 Capacity Commitment Period (FCA11) to be presented by the ISO in November 2015, and willwould include a review of existing zones, discussion of relevant constraints, and factors that could trigger the use of these zones in FCA11. ¨ Existing capacity deliverability standard (Overlapping Impact Test) to be reviewed with stakeholders the in December 2015. ¨ Regional transfer limits willwould be updated in Q1 2016. ¨ Any changes or updates to Capacity Zones for FCA11 willwould be identified in Q1/Q2 2016, with FCA11 zonal requirements to be determined in Q2/Q3 2016. ¨ Following discussion on zonal requirements for FCA11, ISO to continue dialogue with stakeholders on potential for persistence of zones for FCA12 and beyond. ¨ Members expressed appreciation to the ISO for responding positively to the feedback provided by NEPOOL concerning the timing and process for Capacity Zones modeling. They explained that earlier identification of potential Capacity Zones would be very helpful to the market. • Generator Interconnection Improvements ¨ The ISO planned to work with stakeholders to improve the interconnection process by Q1 2016. The objective of any improvements would be to reduce the time to complete system impact studies for new inverter-based generators and to address the Interconnection Queue backlog, particularly for generators in weak areas of the system (Northern and Western Maine). ¨ Address curtailment and performance issues in system operations for inverter-based generators and ensure the region satisfies modeling and performance requirements being introduced by new NERC standards. ¨ He said that the ISO planned to make a presentation on generator interconnection issues and the overlapping impact test in December 2015. Responding to questions on the generator interconnection improvements, he committed to review with the NEPOOL Officers the appropriate forum for presenting these issues and any suggested changes. Mr. Doot clarified that, as reported in the Litigation Report, more general issues of generator interconnection process improvement nationwide had been raised with the NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3527
FERC, but that the issue for discussion under the Work Plan was to focus specifically on New England’s needs and processes. • Regional System Plan (RSP) 2016 ¨ In response to stakeholder feedback, the ISO planned to change the RSP cycle to a biennial rather than an annual process, with no RSP planned for 2016. ¨ Data contained in the RSP would continue to be available to stakeholders consistent with current data release schedules (annually, quarterly, etc.). ¨ To support the timing change, the ISO planned to review related Tariff changes with the Transmission Committee and file them at FERC in Q4 2015/ early 2016.
Related to key activities identified by Dr. Chadalavada in the meeting, a member expressed appreciation for the ISO’s efforts to clarify cyber security issues being considered by the national and regional reliability organizations and in trying to work through those issues both to ensure avoidance of any unnecessary costs and proper compensation to those who arewould be required to incur incremental costs to satisfy cyber security reliability standard issues.
Market Design – FCM Related
Dr. Chadalavada then reviewed key FCM-related market design activities, including:
• Resource Retirement Reforms ¨ The ISO would propose changes to the rules related to resource retirements, including modifications to the non-price retirement and permanent de-list bid structure, as well as the timing for submitting information available to the markets. ¨ Stakeholder process was underway, with a FERC filing targeted for the end of 2015 and implementation targeted for FCA11. • Treatment of Resources Retained for Reliability ¨ The ISO would evaluate modifications for treatment of resources retained for reliability. NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3528
¨ Stakeholder process would not begin until after the Resource Retirement Reforms project was completed and implementation would be targeted for no earlier than FCA12. • Zonal Demand Curves ¨ The ISO was developing a revised zonal demand curve proposal for FCA11, including conforming changes to FCA pricing rules. ¨ Stakeholder process was expected to begin in Q3 2015, with a FERC filing targeted for Q2 2016 and implementation targeted for FCA11. • Reconfiguration Auctions & CSO Bilaterals under Zonal Demand Curves ¨ Reconfiguration auction (RA) and CSO Bilateral rules to be developed upon completion of Zonal Demand Curve changes. ¨ Stakeholder process expected to begin in Q1 2017, with the first annual RA for the Capacity Commitment Period beginning June 2020. • FCM Qualification Modifications and Clarifications ¨ ISO was developing changes to aspects of the FCA and reconfiguration auction qualification processes, including minor qualification changes for resources, expanding those MWs eligible to satisfy reconfiguration and bilateral requirements, reducing resource size requirements, and identifying miscellaneous qualification-related clarifications. ¨ Stakeholder process expected to begin by Q4 2015, with a FERC filing targeted for Q1 2016 and implementation targeted for 2016. • Auction Format Evaluation ¨ As requested by NEPOOL, the ISO was planning to evaluate the FCA’s descending clock auction format and alternatives. Evaluation would include the impacts of the format, timing and review of de-list bids and supply offers. ¨ Initial scoping discussion expected to occur in Q4 2015, with next steps to be determined based on that discussion. Market Design – Price Formation
Turning to price formation activities, Dr. Chadalavada reviewed the following key activities:
• Sub-hourly Real-Time Settlement ¨ The ISO was developing sub-hourly settlement for Real-Time markets (Energy, Reserves, and Regulation) for generation and Dispatchable Asset Related Demand and External Transactions to align settlement and dispatch frequency (5-minute basis). NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3529
¨ Stakeholder process underway, with a FERC filing targeted for Q1 2016 and implementation targeted for Q1/Q2 2017. • Day-Ahead Reserve Market ¨ The ISO was evaluating design changes to the Day-Ahead Market to procure and price Operating Reserves in co-optimized Day-Ahead Energy and Reserve Markets. ¨ Stakeholder process expected to begin in Q4 2016 and timing of implementation to be evaluated during proposal development (but not expected to occur before Q1 2019).
Dr. Chadalavada stated, in response to a question as to whether and when the ISO planned to address the issue of multi-hour system ramp pricing, which was in the 2015 Work
Plan, the ISO’s view that the Day-Ahead co-optimization of Reserves would produce more direct reliability benefits, especially during the winter period. He clarified that activity concerning multi-hour system ramp pricing was still planned, but that it was being delayed to occur later than the time covered by the Work Plan.
Dr. Chadalavada concluded his presentation by cautioning that, regardless of how thorough and thoughtful all were in assembling the Work Plan, certain changes in circumstances beyond the control of the ISO, NEPOOL or the States could materially impact the Plan. He cited by way of example the potential impact of a Supreme Court ruling on demand resource integration (EPSA v. FERC, et al). He stated the Work Plan could not realistically identify the level of activity that would be required under all possible scenarios and some scenarios would have the potential to impact the timing of the consideration and implementation of some of the priority items discussed. He added that, as it had always been done in the past, the regional would have to adjust the Work Plan, if and as needed, to respond to all requirements later imposed by regulators. NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3530
In response to a comment that the NCPC cost allocation project was not listed in the next six quarters, Dr. Chadalavada stated that primary focus was on the 3 major market-related activities: sloped zonal demand curves, resource retirement reforms, and the day-aheadDay-
Ahead co-optimization of rReserves, with some projects unfortunately pushed back as a result.
Mr. Doot noted that, throughout discussions of the Work Plan, there had been repeated questions as to whether more work could be planned or accomplished if the ISO expanded its resources. The ISO had consistently responded that the critical path was largely dictated by the availability of personnel the most knowledgeable and necessary to ensuring that the various changes all fit together appropriately, and adding more resources was not likely to materially change the schedule for priority items.
REPORT ON 2016 ISO-NEISO OPERATING AND CAPITAL BUDGETS AND 2016 NESCOE BUDGET
Mr. Kenneth Dell Orto, Budget & Finance Subcommittee Chair, referred the
Committee to the 2016 ISO Operating and Capital Budgets (2016 ISO Budgets) materials circulated in advance of the meeting. He outlined the following stakeholder process for review of the 2016 ISO Budgets that was followed in accordance with the 2013 ISO Budget settlement:
• Presentation and discussion with Regulators at the 2015 NECPUC Symposium; • Presentation and discussion at the Participants Committee Summer Meeting in June; • Management review of feedback from the stakeholder meetings and the ISO Board and incorporation of initiatives into the 2016 ISO Budgets; • Presentation and discussion of updates to the proposed 2016 ISO Budgets at the August 26 Budget & Finance Subcommittee meeting; • Meeting between ISO and state representatives on August 27 and the States’ submission of written questions for review by the ISO; and NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3531
• Presentation and discussion at the September 11 Participants Committee meeting.
He explained that a final NEPOOL vote was scheduled for the October 2 Participants
Committee meeting.
Mr. Robert Ludlow, ISO Chief Financial & Compliance Officer, then continued discussion on the review process. He reported that, on September 25, the ISO would share with NEPOOL the projected impact on the rates across the various ISO aAdministrative tTariff schedules. Under the process agreed to in settlement, the States had until September
25 to provide comments to the ISO, and the ISO had until October 8 to respond to those comments. He indicated that the ISO would post on its website all of the States’ questions received on the 2016 Budget proposal and answers thereto. The ISO Board, with the benefit of NEPOOL’s October vote and all of the other input received, would then consider and vote on the 2016 ISO Budgets in mid-October, with a Tariff filing shortly thereafter and a FERC order on that filing by years’the end of December 2015.
Mr. Ludlow explained that the proposed 2016 ISO oOperating bBudget was largely consistent with the budget that was discussed in June. He highlighted key costs drivers of the budget changes from the prior year, including the following: cyber security, market monitoring, licensing costs, and other inflationary increases. He summarized that the proposed
2016 ISO oOperating bBudget (excluding depreciation and the true-up for past years) was
3.9% (or $7 million) higher than the 2015 Operating bBudget. He stated that the final 2016
Operating and Capital bBudgets willwould reflect the results of the ongoing priorities and work plan discussions with stakeholders. He reported that, in total, the 2016 ISO revenue requirement would be 9.6% higher than in 2015, 5.7% of which was attributable to a smaller NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3532 year-end true-up -- the 2014 revenue requirement true-up included in the 2016 revenue requirement, would be a $0.6 million reduction versus the $9.8 million 2013 true-up reduction that was included in the 2015 revenue requirement.
Turning to the 2016 Capital Budget, Mr. Ludlow reviewed that the proposed budget was $1 million below the 2015 Capital Budget, and maintained spending at $27 million for major projects in development, including: wind integration, FCA10, divisional accounting, and zonal load forecast.
Turning to the 2016 NESCOE Budget, Mr. Dell Orto referred the Committee to the
NESCOE materials posted in advance of the meeting. He reported that the total NESCOE
Budget for 2016 was $2.2 million. He said that the 2016 NESCOE Budget was presented at the August 26 Subcommittee meeting and was consistent with NESCOE’s previously approved
5-year pro forma budget. He reported that the proposed Schedule 5 rate of collections for
2016 waswould be $0.00290 per kW times Monthly Regional Network Load.
Mr. Gordon re-emphasized that the 2016 Budgets would be voted at the October 2
Committee meeting. He urged members to raise any questions or concerns in advance of the vote directly with Messrs. Dell Orto and/or Ludlow. He stated that, if needed, another
Subcommittee meeting would be scheduled to consider any additional questions or concerns raised.
In response to a question, Mr. Ludlow confirmed that there would be no change in how the 2016 NESCOE Budget would be collected under ISO Schedule 5 from prior years.
In response, the MMWEC representative indicated that his company, as it had done in the NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3533 past, would oppose the 2016 NESCOE Budget because of its long-standing position that states should be paying those costs and not transmission customers under the ISO Tariff.
REVISIONS TO ISO-NE OPERATING PROCEDURE NO. 14
Mr. Donald Gates, NEPOOL Reliability Committee Chair, referred the Committee to the materials circulated in advance of the meeting regarding revisions to ISO Operating
Procedure No. 14 (OP-14 Revisions). He stated that OP-14 specifies, among other things, technical requirements for generators in the ISO’s market system. The OP-14 Revisions were designed to address how distributed generation would be treated, and included some other clean-up changes to defined terms. The focus of the OP-14 Revisions was to provide for the aggregation of “dispersed power resources” (i.e., distributed generation) that are connecting to the existing system through a common point of interconnection for the purpose of determining whether a 5 MW threshold (used to determine whether certain OP-14 requirements will apply to the resources) is reached. By requiring the aggregation of dispersed power resources, more distributed generation would become operationally visible to the ISO, which was the reason cited by the ISO for the OP-14 Revisions.
Mr. Gates reported that the ISO presented the OP-14 Revisions to the Reliability
Committee at multiple meetings and for a vote at that Committee’s August 18, 2015 meeting.
The Reliability Committee voted to recommend Participants Committee support for the rRevisions based on a show of hands, with numerous oppositions and abstentions noted. Prior to the vote on the OP-14 Revisions, SunEdison proposed an amendment to those Revisions that would have allowed for the aggregation of distributed power resources of affiliates only.
That motion to amend failed with a vote of approximately 54% in favor. Mr. Gordon noted NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3534 that SunEdison planned to present its proposed amendment to the Participants Committee for consideration and vote. SunEdison had also raised the issue of whether the OP-14 Revisions should be filed with the FERC as changes to rates, terms and conditions of service.
The following motion was duly made and seconded:
RESOLVED, that the Participants Committee supports the proposed OP- 14 Revisions, as recommended by the Reliability Committee and as reflected in the materials distributed to the Participants Committee for its September 11, 2015 meeting, together with such non-substantive changes as may be agreed to after the meeting by the Chair and Vice- Chair of the Reliability Committee.
The Committee then discussed the Proposal. The SunEdison representative stated that, while his company supported the ISO’s reliability objective, he thought there must be alternative means to achieve that objective without over-burdening small, unaffiliated distributed generation (DG). He believed the OP-14 Revisions would unnecessarily burden small DG. He then described SunEdison’s amendment, which allowed for the aggregation of
DG under 5 MW only for affiliated facilities. He also thought that this issue could benefit from further discussion among Participants and with the ISO before a vote and sought more time to explore a solution. Another representative of the Alternative Resources Sector said he shared SunEdison’s concerns and thought that a deferral of the vote might be appropriate.
Representatives then stated they would offer a motion to defer if needed. A member asked whether the ISO would agree to a short deferral to try to resolve this issue. In response, Mr.
Raymond Hepper, ISO Counsel, noted that the Participants Agreement provided generally for a one-month deferral of action on a proposal and that the ISO would not object to such a deferral here. A Publicly Owned Entity representative noted his Sector’s opposition to the
ISO proposal because of its effect on generating facilities that would otherwise be Settlement- NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3535
Only Resources under the Tariff. He thought there should be further discussion of what was needed and then inclusion of those requirements in the Market Rules. Also, from a process standpoint, the representative questioned whether the ISO’s proposedOP-14 rRevisions would be a change in rates, terms and conditions of the Tariff through an Operating Procedure. A representative in support of the deferral asked the ISO to consider operational issues and whether there was a better way to address them and expressinged his hope that the ISO would change the way it was proposing to get the needed operational visibility. Another representative questioned whether the OP-14 Revisions would even address the desired operational needs and recommended that Participants and the ISO look further for a better solution, noting her plans to meet and discuss these issues with the ISO in the near future. A
Generation representative expressed his company’s concerns about the burdens the ISO’s proposal would put on DG. Several members stated they would not oppose the deferral, but suggested the need for a broader discussion of the 5 MW threshold for Settlement-Only
Resource eligibility in light of increased DG on the system and encouraged DG representatives to identify a way to get the ISO the needed information. Noting timing challenges, Mr.
Hepper said the ISO would not object to the OP-14 Revisions being deferred to the November
6 Participants Committee meeting to give everyone more time to work on a solution. He added that the ISO needed an additional opportunity to discuss internally how else it might obtain the data it needs.
Mr. Gordon then asked if there was any objection to deferring this item to the
November Participants Committee meeting. No objection was raised and, by acclimation, consideration of the motion was deferred to the November 6 Participants Committee meeting NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3536 pending further ISO and Technical Committee consideration of concerns in connection with the proposed changes.
REMOVAL OF REVIEW BOARD ARRANGEMENTS
Mr. Doot referred the Committee to the materials circulated in advance of the meeting to approve for balloting proposed amendments to the NEPOOL Agreement (a proposed 129th
Agreement Amending the New England Power Pool Agreement (129th Agreement)) and to the
Participants Agreement (Amendment No. 9, and together with the 129th Agreement, the
Amendments) to eliminate the Review Board arrangements. He reviewed that thisthe status of the Review Board hasd been a topic of discussion over the past several years, since the
Review Board had not been called on for any matters for more than six years, and questions arose every year in connection with NEPOOL Budget discussions, why NEPOOL continued to incur expenses for the Review Board. At the direction of the NEPOOL Officers, NEPOOL
Counsel worked with the Budget & Finance Subcommittee and the Review Board Liaison
Committee to identify appropriate amendments to the governing documents for the elimination of the Review Board. He stated that if the Amendments were approved in balloting, the only reference to the Review Board would be in those provisions that would continue to provide for indemnification of the Review Board Members for losses incurred as a result of service on the Review Board. He reported that the Amendments were proposed to become effective on
January 1, 2016. He stated the Review Board Liaison Committee and the Budget & Finance
Subcommittee both considered the Amendments without comment or objection.
Mr. Doot reported that, in response to NEPOOL Counsel’s request for feedback on the proposed Amendments, a request was made that NEPOOL consider adding or retaining some NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3537 form of alternative dispute resolution (ADR) mechanism to resolve disputes regarding
NEPOOL Generation Information System (GIS) rules and implementation. He stated that, unlike Market Rules and Tariff provisions, GIS matters were not subject to the jurisdiction of the FERC (which resolved disputes over all Tariff changes). Likewise, GIS matters were not subject to the general ADR provisions set forth in the ISO-NEISO Tariff. Accordingly, if the
Review Board arrangements were removed, there would be no specifically identified ADR provisions for Participants to resolve disputes on GIS matters.
He requested Committee guidance on whether it wished to consider a GIS-specific
ADR mechanism, and, if so, how it would like to identify such a mechanism. Mr. Doot clarified that this issue was not raised in opposition to the elimination of the Review Board, nor was a delay sought on its elimination, but rather the request was to address this matter if the Committee decidesd to support eliminating the Review Board. He noted that an ADR mechanism specifically tailored for GIS-related disputes, could be accomplished separately and possibly included within the GIS rules rather than in the Restated NEPOOL Agreement.
The following motion was duly made and seconded:
RESOLVED that the Participants Committee authorizes and directs the Balloting Agent (as defined in the Second Restated NEPOOL Agreement) to circulate ballots for the approval of changes to the Second Restated NEPOOL Agreement and Participants Agreement (that remove the NEPOOL Review Board), together with such non-material changes therein as the Chair of the Review Board Liaison Committee may approve, to each Participant for execution by its voting member or alternate on this Committee or such Participant’s duly authorized officer.
In response to the request for guidance on a specifically-tailored GIS ADR mechanism, members expressed support for, and opposition to, consideration of such a mechanism. Those supporting consideration thought it important to continue to have, or at least consider having, NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3538 a mechanism for a last review by an independent body, as is available with matters subject to
FERC jurisdiction. Those opposing consideration expressed reservations that an ADR mechanism to meet or exceed the ability of the Participants Committee to address grievances with respect to GIS matters could be identified and preferred instead to terminate the process with Participants Committee consideration. Emphasizing that all possible outcomes remained on the table, Mr. Gordon announced that he had asked Mr. Dell Orto, and Mr. Dell Orto had agreed, to lead efforts to develop a recommendation for Participants Committee consideration at a later meeting.
After discussion and clarification, theThe Committee then considered and approved the resolution to ballot the Amendments, with an opposition by EnerNOC, and an abstention by
Marble River, noted.
Mr. Gordon urged Participants to promptly return their ballots on the 129th
Agreement, which were circulated at the meeting and by e-mail to members and alternates.
LITIGATION REPORT
Mr. Doot referred the Committee to the September 9 Litigation Report that had been circulated and posted the day before the meeting. He highlighted the continued high level of activity, particularly in a month that is traditionally the FERC’s quietest. He indicated that the agenda for the FERC open meeting the following week included consideration of matters related to the Winter Reliability Program jump ball and the requests for rehearing on a number of other winter operations issues. Mr. Hepper clarified that FERC had noticed those proceedings in connection with a winter readiness report that it had requested of all the
ISOs/RTOs, and that the jump ball decision, he expected, would be issued no later than NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3539
Monday, September 14, which was the date jointly requested for that order. It was also noted that FERC was planning to issue a general order concerning price formation at that meeting.
COMMITTEE REPORTS
Officers from each of the Technical Committees reported on the schedule for
Committee meetings in September. Ms. Allison DiGrande reported that the Markets
Committee was continuing discussions on resource retirement issues and would be starting discussions on the zonal demand curves. Mr. Jose Rotger reported that the Transmission
Committee was scheduled to discuss on September 24 in Westborough interconnection queue issues, changes to Schedule 22 and 23 and the generator interconnection process, and changes to Attachment K related to the resource retirement provisions to eliminate price retirement.
Mr. Stein reported that the Reliability Committee was scheduled to review at its September 15 meeting the ISO’s presentation of the reliability aspects of proposed changes to resource retirements. Mr. Dell Orto reported that the next Budget & Finance Subcommittee meeting was scheduled to meet onfor October 9 as a teleconference meeting.
OTHER BUSINESS
Mr. Doot reminded members that the next Participants Committee meeting was onscheduled for October 2 at the Colonnade Hotel in Boston. He stated that the November 6 meeting with the ISO Board and Sector breakout meetings was scheduled at the Hilton Logan
Hotel in Boston. He asked that the Sectors meet to provide any questions, agenda topics, and supporting materials for the ISO Board in advance of the Sector meetings. He reported the
2015 Annual Meeting was scheduled onfor December 4 at the Colonnade Hotel. He reminded NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft 3540 the Committee of the 2016 Officer Elections and to consider their Sector Vice-Chairs for that election over the next several weeks.
There being no further business, the meeting adjourned at 12:23 p.m.
Respectfully submitted,
______David T. Doot, Secretary NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft ATTACHMENT 1
PARTICIPANTS COMMITTEE MEMBERS AND ALTERNATES PARTICIPATING IN THE SEPTEMBER 11, 2015 MEETING
SECTOR/ PARTICIPANT NAME MEMBER NAME ALTERNATE NAME PROXY GROUP American PowerNet Management Supplier Mary Smith Ashburnham Municipal Light Plant Publicly Owned Chung Liu Associated Industries of Massachusetts End User Roger Borghesani Belmont Municipal Light Department Publicly Owned Phil Smith Boylston Municipal Light Department Publicly Owned Chung Liu BP Energy Company Supplier Nancy Chafetz (tel) Brookfield Energy Company Supplier Aleksander Mitreski Calpine Energy Services, LP Supplier John Flumerfelt Brett Kruse Central Maine Power Company Transmission Sue Clary (tel) Chester Municipal Electric Light Department Publicly Owned Phil Smith Chicopee Municipal Lighting Plant Publicly Owned Chung Liu Citigroup Energy Inc. Supplier Barry Trayers (tel) CLEAResult Consulting, Inc. AR Doug Hurley Concord Municipal Light Plant Publicly Owned Phil Smith Connecticut Municipal Electric Energy Coop. Publicly Owned Brian Forshaw Conservation Law Foundation End User Jerry Elmer Consolidated Edison Energy, Inc. Supplier Jeff Dannels CPV Towantic, LLC Generation Daniel Pierpont Danvers Electric Division Publicly Owned Phil Smith Dominion Energy Marketing, Inc. Generation Jim Davis DTE Energy Trading, Inc. Supplier Nancy Chafetz (tel) Dynegy Marketing and Trade, LLC Supplier Bill Fowler Emera Maine Transmission Jeff Jones (tel) Jose Rotger Stacy Dimou Andrew McCullough Energy America, LLC Supplier Nancy Chafetz (tel) EnerNOC, Inc. AR Herb Healy Entergy Nuclear Power Marketing, LLC Generation Ken Dell Orto Essential Power, LLC Generation M.Q. Riding (tel) Bill Fowler Eversource Energy Transmission James Daly Dave Errichetti (tel) Exelon Generation Company Supplier Steve Kirk Bill Fowler Galt Power, Inc. Supplier Nancy Chafetz (tel) GDF SUEZ Energy Marketing NA, Inc. Generation Thomas Kaslow Generation Group Member Generation Dennis Duffy Abby Krich Bob Stein Georgetown Municipal Light Department Publicly Owned Phil Smith Granite Ridge/Merrill Lynch Supplier Bill Fowler Groton Electric Light Department Publicly Owned Chung Liu Groveland Electric Light Department Publicly Owned Phil Smith H.Q. Energy Services (U.S.) Inc. Supplier Louis Guilbault Bob Stein Harvard Dedicated Energy Limited End User Mary Smith Roger Borghesani Paul Peterson High Liner Foods (USA) Incorporated End User William P. Short III Hingham Municipal Lighting Plant Publicly Owned Phil Smith Holden Municipal Light Department Publicly Owned Chung Liu Hudson Light and Power Department Publicly Owned Chung Liu Hull Municipal Lighting Plant Publicly Owned Chung Liu Industrial Energy Consumer Group End User Don Sipe Ipswich Municipal Light Department Publicly Owned Chung Liu Jericho Power, LLC AR Phil Smith Long Island Lighting Company (LIPA) Supplier William Killgoar Littleton (MA) Electric Light & Water Department Publicly Owned Phil Smith Littleton (NH) Water & Light Department Publicly Owned Craig Kieny (tel) -
. NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #1 Marked to Show Changes from Sep 18, 2015 draft ATTACHMENT 1
PARTICIPANTS COMMITTEE MEMBERS AND ALTERNATES PARTICIPATING IN THE SEPTEMBER 11, 2015 MEETING
SECTOR/ PARTICIPANT NAME MEMBER NAME ALTERNATE NAME PROXY GROUP Maine Public Advocate Office End User Paul Peterson Maine Skiing, Inc. End User Don Sipe Mansfield Municipal Electric Department Publicly Owned Chung Liu Marblehead Municipal Light Department Publicly Owned Chung Liu Marble River, LLC Supplier Steve Garwood Massachusetts Attorney General’s Office (MA AG) End User Fred Plett Christina Belew (tel) Mass. Development Finance Agency Publicly Owned Phil Smith Mass. Municipal Wholesale Electric Company (MMWEC) Publicly Owned Chung Liu Merrimac Municipal Light Department Publicly Owned Phil Smith Middleborough Gas and Electric Department Publicly Owned Chung Liu Middleton Municipal Electric Department Publicly Owned Phil Smith National Grid Transmission Timothy Brennan Timothy Martin New Hampshire Electric Cooperative (NHEC) Publicly Owned Steve Kaminski (tel) Brian Forshaw New Hampshire Office of Consumer Advocate (NH OCA) End User Paul Peterson NextEra Energy Resources, LLC Generation Michelle Gardner Noble Americas Gas & Power Corp. Supplier Becky Merola NRG Power Marketing LLC Generation Dave Cavanaugh (tel) Peter Fuller Pascoag Utility District Publicly Owned Phil Smith Paxton Municipal Light Department Publicly Owned Chung Liu Peabody Municipal Light Plant Publicly Owned Chung Liu PowerOptions, Inc. End User Cindy Arcate Princeton Municipal Light Department Publicly Owned Chung Liu PSEG Energy Resources & Trade LLC Supplier Joel Gordon Repsol Energy North America Company Supplier Nancy Chafetz (tel) Rowley Municipal Lighting Plant Publicly Owned Phil Smith Russell Municipal Light Dept Publicly Owned Chung Liu Shrewsbury Electric & Cable Operations Publicly Owned Chung Liu Small Load Response Group Member AR Doug Hurley Small Renewable Generation Group AR Erik Abend (tel) South Hadley Electric Light Department Publicly Owned Chung Liu Sterling Municipal Electric Light Department Publicly Owned Chung Liu Stowe Electric Department Publicly Owned Phil Smith SunEdison (First Wind Energy Marketing, Inc.) AR John Keene Bob Stein Tangent Energy Solutions Provisional Member Brad Swalwell (tel) Taunton Municipal Light Department Publicly Owned Phil Smith Templeton Municipal Lighting Plant Publicly Owned Chung Liu The Energy Consortium End User Roger Borghesani Mary Smith Paul Peterson TransCanada Power Marketing Ltd. Generation Dan Congel (tel) Union of Concerned Scientists End User Francis Pullaro (tel) United Illuminating Company Transmission Christian Belcheck Utility Services, Inc. End User Paul Peterson Vermont Electric Cooperative Publicly Owned Craig Kieny (tel) Vermont Energy Investment Corporation AR Doug Hurley Vermont Public Power Supply Authority Publicly Owned David Mullett Vitol Inc. Supplier Joe Wadsworth Wakefield Municipal Gas and Light Department Publicly Owned Chung Liu Wallingford DPU Electric Division Publicly Owned Phil Smith Wellesley Municipal Light Plant Publicly Owned Phil Smith West Boylston Municipal Lighting Plant Publicly Owned Chung Liu Westfield Gas & Electric Light Department Publicly Owned Phil Smith
-
. NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #2
CONSENT AGENDA
From the notice of actions of the September 15, 2015 Reliability Committee1 meeting, dated September 17, 2015, which has been previously circulated:
1. Revisions to OP-18 (Clarification and Updates Following OP-18 WG Review)
Support revisions to ISO New England Operating Procedure No. 18 (Metering and Telemetering Criteria) (OP-18), including updates and clarifications proposed following OP-18 Working Group review, as recommended by the Reliability Committee at its September 15, 2015 meeting, with such further non-substantive changes as the Chair and Vice-Chair of the Reliability Committee may approve.
The motion to recommend Participants Committee support was approved unanimously.
2. REMOVED FROM CONSENT AGENDA. FCA10 HQICC VALUES TO BE DISCUSSED AS AGENDA ITEM #6.a
HQICC Values - FCA10 (2019/20 Capability Period)
Support the following megawatt values that represent the Hydro-Québec Interconnection Capability Credit (HQICC) for the Forward Capacity Auction for the 2019/20 Capacity Commitment Period:
HQICC Values 2019/2020 Capacity Commitment Period Month (MW) June 975 July 975 August 975 September 975 October 975 November 975 December 975 January 975 February 975 March 975 April 975 May 975
The motion to recommend Participants Committee support was approved, with two oppositions (one each in the Generation and Supplier Sectors) and four abstentions (Generation Sector - 2, Supplier Sector - 2) noted.
1 Reliability Committee Notices of Actions are posted on the ISO website at: http://iso- ne.com/committees/reliability/reliability-committee. NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #2
CONSENT AGENDA (cont.)
From the notice of actions of the September 2-3, 2015 Markets Committee2 meeting, dated September 4, 2015, which has been previously circulated:
3. Revisions to Market Ru1e 1 (MR1) and Manual M-RPA (Simultaneous RTDR/RTEG Audits)
Support revisions to Market Rule 1 and Manual M-RPA (Registration and Performance Auditing) to modify the simultaneous auditing rules for Real-Time Demand Response (RTDR) and Real-Time Emergency Generation (RTEG) Resources, as recommended by the Markets Committee at its September 2-3, 2015 meeting, with such further non- substantive changes as the Chair and Vice-Chair of the Markets Committee may approve.
The motion to recommend Participants Committee support was approved unanimously.
4. Revisions to MR1 (Modified Demand Response Baseline Methodologies)
Support revisions to Market Rule 1 to implement a new Demand Response Baseline methodology (implementing, in place of the current “90/10 baseline methodology, a “mean 10 of 10” methodology for non-holiday weekdays and “mean 5 of 5” methodology for weekend ), as recommended by the Markets Committee at its September 2-3, 2015 meeting, with such further non-substantive changes as the Chair and Vice-Chair of the Markets Committee may approve.
The motion to recommend Participants Committee support was approved unanimously.
5. Revisions to Appendix F to MR1 (NCPC Modifications)
Support revisions to Appendix F to Market Rule 1 to address NCPC design-related issues identified following implementation of the Energy Market Offer Flexibility changes, as recommended by the Markets Committee at its September 2-3, 2015 meeting, with such further non-substantive changes as the Chair and Vice-Chair of the Markets Committee may approve.
The motion to recommend Participants Committee support was approved, with one opposition in the Generation Sector noted.
2 Markets Committee Notices of Actions are posted on the ISO website at: http://www.iso- ne.com/committees/markets/markets-committee. -2- NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #3 Addl Materials Circulated 9/30/15
Summary of ISO New England Board and Committee Meetings
October 2, 2015 Participants Committee Meeting
Since the last update, the System Planning and Reliability Committee met in Boston on September 10. The Compensation and Human Resources Committee, the Markets Committee, the Nominating and Governance Committee, the Audit and Finance Committee, and the Board of Directors each met on September 17 in Holyoke.
The System Planning and Reliability Committee met to prepare for the 2015 Regional System Plan public meeting. The Committee reviewed the schedule for the meeting and discussed comments received on the Plan.
The Compensation and Human Resources Committee reviewed national compensation survey data regarding projected merit and promotional increase budgets. After reviewing information specific to the utility industry, all-industry data, and data from other system operators, the Committee approved a 2.75% merit increase and a .75% promotional/equity increase for 2016. The increases were within the survey ranges, with the objective of ensuring the competitiveness of the Company’s compensation. The Committee also received an update on the renewal of employee health benefits for 2016.
The Markets Committee received reports from the internal and external market monitors, and the COO’s report on reliability costs. The Committee discussed the cause of day-ahead price spikes in New Hampshire at the end of August, and NCPC costs. There was a general discussion concerning seasonal trends in the level of system load. The Committee discussed the structural competitiveness of the Locational Forward Reserve Market and potential changes to the market rules. Next, the Committee reviewed management’s response to the issues raised in the market monitors’ annual reports. Finally, the Committee discussed the challenges of siting new supply resources and the timing of the capacity market auction process and the state siting review process.
The Nominating and Governance Committee adopted resolutions electing the slate of directors, as approved by the NEPOOL Participants Committee at its last meeting. The Committee then undertook its annual review of the risks that fall within the scope of the Committee’s oversight of Company operations, and performed the related annual corporate governance review. Finally, the Committee conducted its biennial consideration of the committee charter to confirm compliance. NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #3 Addl Materials Circulated 9/30/15
The Audit and Finance Committee convened for an update on cyber security issues, and a review of the physical security and business continuity plan.
The Board of Directors received reports from the Committees and the CEO. During the Nominating and Governance Committee report, the Board elected Mses. Abernathy and Brown, and Mr. Shapiro as Directors for three-year terms, elected Phil Shapiro as Chair, and approved committee assignments as follows:
. Audit and Finance Committee: Ms. VanZandt and Messrs. Rush and Wilson, with Mr. Wilson to serve as Chair;
. Compensation and Human Resources Committee: Messrs. Denis, Hill and Levy, with Mr. Denis to serve as Chair;
. Markets Committee: Ms. Abernathy and Messrs. Denis, Hill and Rush, with Mr. Hill to serve as Chair;
. Nominating and Governance Committee: Mses. Brown and Abernathy and Messrs. Levy and Shapiro, with Ms. Brown to serve as Chair;
. System Planning and Reliability Committee: Mses. Brown and VanZandt and Messrs. Levy and Wilson, with Ms. VanZandt to serve as Chair;
. Joint Nominating Committee: Mses. Abernathy and Brown and Messrs. Denis, Levy, Shapiro and Wilson, with Mr. Levy to serve as Chair.
The Board also elected the Company’s officers for the upcoming year. Next, the Board discussed the 2016 budgets and the remaining stakeholder process, noting that the vote on the budgets will take place after receiving input from the NEPOOL Participants Committee and the states. Finally, the Board approved a proposed amendment to the Participants Agreement eliminating the Review Board, and previewed potential risk management topics for discussion at the November meeting.
2 OCTOBER 2, 2015 | BOSTON, MA
NEPOOL PARTICIPANTS COMMITTEE 10/02/15 MEETING, AGENDA ITEM #4
NEPOOL Participants Committee Report
October 2015
Vamsi Chadalavada EXECUTIVE VICE PRESIDENT AND CHIEF OPERATING OFFICER
ISO-NE PUBLIC NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Table of Contents • Highlights Page 3 • System Operations Page 10 • Market Operations Page 21 • Back-Up Detail Page 38 – Load Response Page 39 – New Generation Page 41 – Forward Capacity Market Page 48 – Reliability Costs - Net Commitment Period Compensation (NCPC) Operating Costs Page 54 – Regional System Plan (RSP) & Interregional Planning Page 85 – Operable Capacity Analysis – Fall 2015 Page 112 – Operable Capacity Analysis – Preliminary Winter 2015/16 Page 119 – Operable Capacity Analysis – Appendix Page 126
ISO-NE PUBLIC 2 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Highlights
• Day-Ahead (DA), Real-Time (RT) Prices and Transactions – Energy Market Value was $328M over the period, down $97M from August 2015 and down $64M from September 2014 – September natural gas prices over the period were 31% higher than August 2015 average values – Average RT Hub Locational Marginal Prices (LMPs) over the period were 4.9% higher than August 2015 averages – Average September 2015 natural gas prices and RT Hub LMPs over the period were down 7% and up 3%, respectively, from September 2014 averages • Average DA cleared physical energy in the peak hours as percent of forecasted load was 98.4% during September, up from 98.2% during August All data through September 23 (RT NCPC through September 21) except where otherwise noted. Underlying natural gas data furnished by:
*DA Cleared Physical Energy is the sum of Generation and Net Imports cleared in the DA Energy Market
ISO-NE PUBLIC 3 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Highlights, cont.
• Daily Net Commitment Period Compensation (NCPC) – September NCPC payments totaled $15.6M, up $9.9M from August and up $9.3M from September 2014 • September NCPC payments attributable to the RT evaluation of non fast-start units that cleared DA totaled $6.7M – First Contingency payments totaled $3.9M, down $621K from August • $3.8M paid to internal resources, down $579K from August – $277K charged to DALO, $3.6M to RT Deviations • $93K paid to resources at external locations, down $42K from August – $1K charged to DALO at external locations, $92K to RT Deviations – Second Contingency payments totaled $11.6M, up $10.6M from the August total of $1.1M • Primarily due to reliability commitments for NEMA • Reallocation to network load anticipated – Voltage payments were $26K, up $14K from August – NCPC payments over the period as percent of Energy Market value were 4.7%
ISO-NE PUBLIC 4 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Highlights, cont.
• Regional System Plan 2015 (RSP15) is scheduled for issuance to the ISO Board by September 29 • 2015 economic planning studies are underway. All three study requests are focused on the impacts of wind integration. • New resource qualification is complete. The IMM and System Planning Qualification Notification Determinations were sent on September 26. • Changes to the RSP process are being proposed such that the next RSP would be issued in 2017
ISO-NE PUBLIC 5 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Forward Capacity Market (FCM) Highlights
• CCP #6 (2015-2016) – Termination discussions continue with late non-commercial resources • CCP #7 (2016-2017) – Third bilateral transaction window will be December 1-7, 2015 – Third reconfiguration auction will be March 1-3, 2016 • Based on results of the second reconfiguration auction, entering the CCP, the Transmission Security Analysis margin for NEMA/Boston will be about 356 MW short. Operations is working with the Local Control Centers to address this deficiency. • CCP #8 (2017-2018) – Second bilateral transaction window will be May 2-6, 2016 – Second reconfiguration auction will be August 1-3, 2016 • CCP #9 (2018-2019) – First bilateral transaction window will be April 1-7, 2016 – First reconfiguration auction will be June 1-3, 2016
CCP – Capacity Commitment Period
ISO-NE PUBLIC 6 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 FCM Highlights, cont.
• CCP #10 (2019-2020) – Installed Capacity and Local Sourcing Requirements have been developed. FERC filing to be made no later than November 10. – New resource qualification complete. The IMM and System Planning Qualification Notification Determinations were sent on September 26. – Non-price retirement window is open and will close on October 12 • To date, only two retirements were received (0.085 MW and 27 MW) – Forward Capacity Auction #10 will commence on February 8, 2016
ISO-NE PUBLIC 7 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Highlights, cont.
• The lowest 50/50 and 90/10 Fall Operable Capacity Margin is projected for week beginning November 21, 2015. • The lowest 50/50 and 90/10 Winter Operable Capacity Margin is projected for week beginning January 9, 2016.
ISO-NE PUBLIC 8 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 2014/15 Winter Reliability Program Update (No Change from Prior Month) • Dual Fuel Commissioning (DFC) Program – Participation: • 6 Units submitted intent to commission Dual Fuel Capability – 4 units for 2014/15 (1,039 MW) – 2 units for 2015/16 (735 MW) • Total winter seasonal claimed capability added is 1,774 MW – DFC Activity and related NCPC: • Units commissioned (as of July 31st): 3 successful, 1 outstanding • Total NCPC Commissioning Cap: $5.7M – 2014/15: $3.56M – 2015/16: $2.19M • NCPC Incurred (Nov 1-July 31): $1.0M • Remaining Commissioning Cap for 2014/15: $0.8M
ISO-NE PUBLIC 9 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4
SYSTEM OPERATIONS
ISO-NE PUBLIC 10 NEPOOL PARTICIPANTS COMMITTEE System Operations 0CT 2, 2015 MEETING, AGENDA ITEM #4
Weather Boston Temperature – Above Normal (+3.0°) Hartford Temperature – Above Normal ( +2.9) Patterns Max: 96°F, Min: 48°F Max: 96°F, Min: 40°F Precipitation 1.5” – Below Normal Precipitation 2.43” - Below Normal Normal - 3.23” Normal – 3.87”
Peak Load: 24,272 MW Sep 8, 2015 Hour Ending 17:00
M/ LCC 2: 9/8/15 Capacity Deficiency 13:15 – 21:00
OP-4 & M/LCC 2 : 9/10/15 Capacity Deficiency M/LCC 2: 16:45 – 22:00 OP-4 Action 1: 16:45 – 18:15 NPCC Simultaneous Activation of Reserve Events:
Date Area MW
9/4/15 NYISO 604
9/5/15 ISO-NE 725
9/9/15 ISO-NE 500
9/19/15 NBPSO 325
ISO-NE PUBLIC 11 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 System Operations
Minimum Generation Warnings & Events:
Minimum Generation Warning 9/14/15 04:00 – 9/14/15 16:00 Interchange Cuts Only Minimum Generation Warning 9/15/15 00:01 – 9/15/15 07:00 Interchange Cuts and SS Denied Minimum Generation Warning 9/20/15 23:00 – 9/21/15 07:00 Interchange Cuts Only
Minimum Generation Warning 9/24/15 02:14 – 9/24/15 06:00 Interchange Cuts Only
Minimum Generation Warning 9/27/15 05:00 – 9/24/15 10:00 None
Minimum Generation Warning 9/28/15 00:01 – 9/28/15 06:00 Interchange Cuts Only
ISO-NE PUBLIC 12 NEPOOL PARTICIPANTS COMMITTEE 2015 System Operations - Load Forecast Accuracy0CT 2, 2015 MEETING, AGENDA ITEM #4 Dashboard Indicator
Month J F M A M J J A S O N D Avg Rest of Year Goal < 1.5% Mo Avg 1.70 1.31 1.37 1.59 1.76 1.88 1.91 1.88 1.80 1.69 Day Max 5.66 3.47 3.35 3.93 4.53 5.64 4.41 3.63 5.31 4.44 Summer Goal < 2.6% Day Min 0.65 0.57 0.44 0.74 0.63 0.75 0.60 0.51 0.57 0.61 Summer Goal 2.60 2.60 2.60 Rest of Year Goal 1.50 1.50 1.50 1.50 1.50 1.50 1.50 1.50 1.50 Rest of Year Actual 1.70 1.31 1.37 1.59 1.76 1.80 1.59
Summer Actual 1.88 1.91 1.88ISO-NE PUBLIC 1.89 13 NEPOOL PARTICIPANTS COMMITTEE 2015 System Operations - Load Forecast Accuracy0CT 2, 2015 MEETING, cont. AGENDA ITEM #4 Dashboard Indicator
Month J F M A M J J A S O N D Avg Rest of Year Goal < 1.5% Mo Avg 1.84 1.32 1.36 1.32 2.34 2.52 2.29 2.16 2.08 1.92 Day Max 6.13 4.31 4.31 3.40 7.15 11.57 7.80 4.97 7.91 6.40 Summer Goal < 2.6% Day Min 0.00 0.08 0.00 0.03 0.53 0.22 0.06 0.01 0.03 0.11 Summer Goal 2.60 2.60 2.60 Rest of Year Goal 1.50 1.50 1.50 1.50 1.50 1.50 1.50 1.50 1.50 Rest of Year Actual 1.84 1.32 1.36 1.32 2.34 2.08 1.72
Summer Actual 2.52 2.29 2.16ISO-NE PUBLIC 2.32 14 NEPOOL PARTICIPANTS COMMITTEE 2015 System Operations - Load Forecast Accuracy0CT 2, 2015 MEETING, cont. AGENDA ITEM #4
Target = 50% Plus/Minus = 5%
J F M A M J J A S O N D Avg Above % 37.8 40.2 52.8 39.4 45.6 43.9 38.8 45.4 43.8 43 Below % 62.2 59.8 47.2 60.6 54.4 56.1 61.2 54.6 56.2 57 Avg Above 143.4 147 169.7 130.2 215.1 158.9 185.8 201 180.8 171 Avg Below -235.8 -208.2 -146.1 -179.5 -157.4 -212.7 -247.6 -243.8 -185.7 -202 Avg All -81 -57 17 -49 34 -55 -70 -39 ISO2-NE PUBLIC -33 15 NEPOOL PARTICIPANTS COMMITTEE 2015 System Operations - Load Forecast Accuracy0CT 2, 2015 MEETING, cont. AGENDA ITEM #4
ISO-NE PUBLIC 16 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Monthly Recorded Net Energy for Load (NEL) and Weather Normalized NEL
Net EnergyGR:nel for Load (NEL) WeatherGR:wnnel Normalized NEL
14,000 14,000
13,000 13,000
12,000 Partial 12,000 11,000
11,000
GWh GWh 10,000 10,000 9,000
8,000 9,000
7,000 8,000 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
2012 2013 2014 2015 2012 2013 2014 2015 Ann Tot (TWh): 128.1 129.4 127.2 95.5 Ann Tot (TWh): 128.2 127.8 127.1 85.6
NEPOOL NEL is the total net energy required to serve load and is analogous to ‘RT system load’. NEL is calculated as: Generation – pumping load + net interchange where imports are positively signed. Current month’s data may be preliminary. Weather normalized NEL may be reported on a one-month lag.
ISO-NE PUBLIC 17 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Monthly Peak Loads and Weather Normalized Seasonal Peak History
GR:PeakEnergySystem Peak Load Sep 8: Weather Normalized Seasonal Peaks 24,308 MWh GR:SeasonalPeak 28,000 30,000 27,000 26,000 29,000 25,000 28,000 24,000 27,000 23,000 26,000 22,000
MW 25,000 MW 21,000 24,000 20,000 19,000 23,000 18,000 22,000 17,000 21,000 F F 16,000 20,000 15,000 20032004 2005 20062007 2008 2009 20102011 2012 20132014 2015 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC Summer Winter 2012 2013 2014 2015 Winter beginning in year displayed
F – designates forecasted values, which are updated in April/May of the following year; represents “gross forecast”
ISO-NE PUBLIC 18 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Wind Power Forecast Error Statistics: MAE
Dashboard Indicator
Yearly Fleet Performance targets
Ideally, MAE and Bias would be both equal to zero. As is typical, MAE increases with the forecast horizon. MAE and Bias for the fleet of wind power resources are less due to offsetting errors. Across all time frames, the ISO-NE/GH forecast is very good compared to industry standards, and MAE continues to be well within the yearly performance targets specified in the forecast RFP.
ISO-NE PUBLIC 19 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Wind Power Forecast Error Statistics: Bias
Dashboard Indicator
Yearly Fleet Performance targets
Ideally, MAE and Bias would be both equal to zero. Positive bias means less windpower was actually available compared to forecast. Negative bias means more windpower was actually available compared to forecast. Across all time frames, the ISO-NE/GH forecast is very good compared to industry standards, and monthly values for September are within yearly performance targets specified in the forecast RFP.
ISO-NE PUBLIC 20 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4
MARKET OPERATIONS
ISO-NE PUBLIC 21 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Daily DA and RT ISO-NE Hub Prices and Input Fuel Prices: September 1-23, 2015
GR:Hubwgas $150.00 $30.00 Relatively High loads (24,000+ MW) that exceeded forecast $120.00 $24.00
$90.00 $18.00
$60.00 $12.00
Fuel($/MMBtu) Price Electricity Prices ($/MWh)Prices Electricity $30.00 $6.00
$0.00 $0.00
09/01/15 09/03/15 09/05/15 09/07/15 09/09/15 09/11/15 09/13/15 09/15/15 09/17/15 09/19/15 09/21/15 09/23/15
RT LMP DA LMP Natural Gas Underlying natural gas data furnished by:
Average price difference over this period (DA-RT): $-3.99 Average price difference over this period ABS(DA-RT): $11.20 Average percentage difference over this period ABS(DA-RT)/RT Average LMP: 30% Gas price is average of Massachusetts delivery points
ISO-NE PUBLIC 22 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 DA LMPs Average by Zone & Hub, September 2015
$100 GR:DA_Bar ( 2.2%) 0.1% 0.4% ( 0.3%) 2.5% 0.6% 0.4% 10.5%
$80
$60
$40 $/MWh
$20
$0
$-20 Hub ME NH VT CT RI SEMA WCMA NEMA
LMP Congestion Marginal Losses
ME - Maine RI – Rhode Island NH – New Hampshire SEMA – Southeastern Massachusetts VT – Vermont WCMA – Western/Central Massachusetts CT – Connecticut NEMA – Northeastern Massachusetts
ISO-NE PUBLIC 23 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 RT LMPs Average by Zone & Hub, September 2015
$100 GR:RT_Bar ( 7.1%) ( 3.7%) ( 1.5%) 0.4% 1.0% 2.1% ( 0.1%) 4.7%
$80
$60
$40 $/MWh
$20
$0
$-20 Hub ME NH VT CT RI SEMA WCMA NEMA
LMP Congestion Marginal Losses
ISO-NE PUBLIC 24 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Definitions
Day-Ahead Concept Definition The sum of day-ahead cleared load Day-Ahead Load Obligation (DALO) (including pump load), exports, and virtual purchases (excluding bulk losses) The sum of day-ahead cleared generation Day-Ahead Cleared Physical Energy and cleared net imports
ISO-NE PUBLIC 25 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Components of Cleared DA Supply and Demand – Last Three Months
Supply Demand
22,500GR:Graph36L 22,500GR:Graph36R 20,000 20,000
17,500 17,500
15,000 15,000
12,500 12,500
10,000 10,000 Avg Hourly MW Hourly Avg Avg Hourly MW Hourly Avg 7,500 7,500
5,000 5,000
2,500 2,500
0 0 JUL2015 AUG2015 SEP2015 JUL2015 AUG2015 SEP2015
Gen Imports Fixed Dem PrSens Dem Decs Incs DA Fcst Load Losses Exports Act Load
Gen – Generation Fixed Dem – Fixed Demand Incs – Increment Offers PrSens Dem – Price Sensitive Demand DA Fcst Load – Day-Ahead Forecast Load Decs – Decrement Bids Act Load – Actual Load
ISO-NE PUBLIC 26 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Components of RT Supply and Demand – Last Three Months
Supply Demand
22,500GR:Graph37L 22,500GR:Graph37R 20,000 20,000
17,500 17,500
15,000 15,000
12,500 12,500
10,000 10,000 Avg Hourly MW Hourly Avg Avg Hourly MW Hourly Avg 7,500 7,500
5,000 5,000
2,500 2,500
0 0 JUL2015 AUG2015 SEP2015 JUL2015 AUG2015 SEP2015
Gen Imports Load Exports DA Fcst Load
ISO-NE PUBLIC 27 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 DAM Volumes vs. RT Actual Load (Peak Hour): Monthly and Daily
140% 140%
130% 130%
120% 120%
110% 110%
100% 100%
90% 90% % of RT Actual Load Actual of RT %
80% Load RT Actualof % 80%
70% 70%
60% 60%
15 14 15 15 14 15 15 15 14 15 15 14 15 ------Sep Sep Sep Sep Sep Sep Sep Sep Sep Sep Sep Sep Sep Sep Sep Sep Sep Sep Sep Sep Sep Sep Sep ------1 2 3 4 5 6 7 8 9 Jul Jan Jun Oct 10 11 12 13 14 15 16 17 18 19 20 21 22 23 Apr Sep Feb Sep Dec Aug Nov Mar May
DA Bid Fixed DA Bid Fixed DA Bid Price DALO DA Phys Clrd Energy DA Bid Price 100% DALO
Note: Percentages were derived for the peak hour of each day (shown on right), then averaged over the month (shown on left). Values at hour of forecasted peak load.
ISO-NE PUBLIC 28 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 DA vs. RT Load Obligation: September, This Year vs. Last Year
Monthly,GR:Graph26 Last 13 Months Daily,GR:Graph27 This Year vs. Last Year
99.1% 104% 99.0% 103% 98.9% 102% 98.8% 101% 98.7% 100% 98.6% 99% 98.5% 98% 98.4% 97% 98.3% 96%
98.2% 95% DA %DA RT of DA %DA RT of 98.1% 94% 98.0% 93% 97.9% 92% 97.8% 91% 97.7% 90% 97.6% 89% 97.5% 88% 97.4%
9/ 19/ 29/ 39/ 49/ 59/ 69/ 79/ 89/ 99/109/119/129/139/149/159/169/179/189/199/209/219/229/239/249/259/269/279/289/299/30
SEP2014 DEC2014 JAN2015 FEB2015 JUN2015 JUL2015 SEP2015 OCT2014NOV2014 MAR2015 APR2015MAY2015 AUG2015 Last_Year This_Year
*Hourly average values
ISO-NE PUBLIC 29 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 DA Volumes as % of Forecast (Peak Hour)
GR:dapce_dalo_pct_fxlo_fpk_mly_smallMonthly, Last 13 Months GR:dapce_dalo_pct_fxlo_fpk_dly_smallDaily: This Month 105% 112%
108% 103%
104% 101% 100%
99.0% 96.0%
92.0% 97.0%
88.0% PercentageForecast Peak of Load 95.0% PercentageForecast Peak of Load 84.0%
93.0% 80.0%
SEP2014 DEC2014 JAN2015 FEB2015 JUN2015 JUL2015 SEP2015 OCT2014NOV2014 MAR2015 APR2015MAY2015 AUG2015 01SEP1502SEP1503SEP1504SEP1505SEP1506SEP1507SEP1508SEP1509SEP1510SEP1511SEP1512SEP1513SEP1514SEP1515SEP1516SEP1517SEP1518SEP1519SEP1520SEP1521SEP1522SEP1523SEP15
DA Cleared Physical Energy DALO DA Cleared Physical Energy DALO 100% line 100% line
*Forecasted peak hour is reflected.
ISO-NE PUBLIC 30 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 DA Cleared Physical Energy Difference from RT System Load at Peak Hour* GR:dapce_delta_fpk_dly_bar 1,500
1,000
500 DA Higher DA 0 DA DA Lower
-500
MWh -1,000
-1,500
-2,000
-2,500
-3,000
01SEP201502SEP201503SEP201504SEP201505SEP201506SEP201507SEP201508SEP201509SEP201510SEP201511SEP201512SEP201513SEP201514SEP201515SEP201516SEP201517SEP201518SEP201519SEP201520SEP201521SEP201522SEP201523SEP2015 *Negative values indicate DA Cleared Physical Energy value below its RT counterpart. Forecast peak hour reflected.
ISO-NE PUBLIC 31 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 DA vs. RT Net Interchange September 2015 vs. September 2014
Hourly AverageGR:Graph32 by Day, Last Year Hourly AverageGR:Graph33 by Day, This Year
3,500 3,500 3,000 3,000
2,500 2,500
2,000 2,000
1,500 1,500
Net Net MWh Net MWh 1,000 1,000
500 500
0 0
01SEP14 02SEP14 03SEP14 04SEP14 05SEP14 06SEP14 07SEP14 08SEP14 09SEP14 10SEP14 11SEP14 12SEP14 13SEP14 14SEP14 15SEP14 16SEP14 17SEP14 18SEP14 19SEP14 20SEP14 21SEP14 22SEP14 23SEP14 24SEP14 25SEP14 26SEP14 27SEP14 28SEP14 29SEP14 30SEP14 01SEP15 02SEP15 03SEP15 04SEP15 05SEP15 06SEP15 07SEP15 08SEP15 09SEP15 10SEP15 11SEP15 12SEP15 13SEP15 14SEP15 15SEP15 16SEP15 17SEP15 18SEP15 19SEP15 20SEP15 21SEP15 22SEP15 23SEP15
Day-Ahead Real-Time Day-Ahead Real-Time
Net Interchange is the sum of daily imports minus the sum of daily exports Positive values are net imports
ISO-NE PUBLIC 32 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Variable Production Cost of Natural Gas: Monthly GR:Var_Cost_Gas_Mly $200
$160
$120
$80
$40
$0
SEP2013 JAN2014FEB2014 JUL2014 SEP2014 JAN2015FEB2015 JUL2015 SEP2015 OCT2013NOV2013DEC2013 MAR2014APR2014MAY2014JUN2014 AUG2014 OCT2014NOV2014DEC2014 MAR2015APR2015MAY2015JUN2015 AUG2015
Var Cost Gas
Underlying natural gas data furnished by:
Note: Assumes proxy heat rate of 7,800,000 Btu/MWh for natural gas units.
ISO-NE PUBLIC 33 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Variable Production Cost of Natural Gas: Daily
GR:Var_Cost_Gas_Dly $240
$200
$160
$120
$80
$40
$0
01SEP201502SEP201503SEP201504SEP201505SEP201506SEP201507SEP201508SEP201509SEP201510SEP201511SEP201512SEP201513SEP201514SEP201515SEP201516SEP201517SEP201518SEP201519SEP201520SEP201521SEP201522SEP201523SEP2015
Var Cost Gas
Underlying natural gas data furnished by:
Note: Assumes proxy heat rate of 7,800,000 Btu/MWh for natural gas units.
ISO-NE PUBLIC 34 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Hourly DA LMPs, September 1-23, 2015
HourlyGR:DA_Hrly Day-Ahead LMPs
$600
Various binding constraints $500 associated with the planned Binding Boston Import outage of the 282-602 (West constraint due to the outage of Medway-Sudbury) line the 282-602 and S145E (Salem- $400 Railyard) lines
$300
$200 $/MWh
$100
$0
$-100
$-200
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hub ME NH VT CT RI SEMA NEMA WCMA
ISO-NE PUBLIC 35 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Hourly RT LMPs, September 1-23, 2015
HourlyGR:RT_Hrly Real-Time LMPs
Tight capacity with binding reserve and transmission $600 Tight capacity with binding constraints (at Kingston St.) and relatively high loads reserve constraints with loads (24,000+ MW) that exceeded forecast; exceeding forecast $500 Additional factors included: Unplanned unit outages (affecting Sept. 8); Binding constraint at Orrington and trip of Phase II pole 1 (affecting Sept. 9); $400 OP-4, Action 1 implemented on Sept. 9
$300
Tight capacity with binding
$200 reserve constraints $/MWh
$100
$0
$-100
$-200
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hub ME NH VT CT RI SEMA NEMA WCMA
ISO-NE PUBLIC 36 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 System Unit Availability
Annual/Monthly Weighted Equivalent Availability Factor (WEAF) 100
95
90
85
80
System System WEAF 75
70
65
60 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual
2013 2014 2015
Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec YTD 2015 97 89 88 84 79 94 96 96 88 90 2014 87 92 84 76 77 95 96 95 93 81 82 95 88 2013 89 87 85 76 81 90 90 92 88 80 81 92 86 2012 93 92 88 75 83 93 95 95 91 76 80 89 88 Data as of 9/28/15
ISO-NE PUBLIC 37 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4
BACK-UP DETAIL
ISO-NE PUBLIC 38 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4
LOAD RESPONSE
ISO-NE PUBLIC 39 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Capacity Supply Obligation (CSO) MW by Demand Resource Type for October 2015 Seasonal Load Zone RTDR* RTEG** On Peak Peak Total ME 115.9 4.0 119.2 0.0 239.2 NH 7.4 12.3 75.3 0.0 95.0 VT 28.5 4.2 99.3 0.0 132.0 CT 73.1 88.2 74.3 310.7 546.3 RI 10.9 13.0 158.6 0.0 182.5 SEMA 11.0 9.7 205.9 0.0 226.7 WCMA 30.1 21.3 206.5 46.2 304.1 NEMA 30.9 3.4 375.1 0.0 409.4 Total 307.9 156.1 1,314.2 356.9 2,135.1 * Real Time Demand Response ** Real Time Emergency Generation NOTE: CSO values include T&D loss factor (8%) and, as applicable, a reserve margin gross-up of either 14.3% or 16.1%, respectively, for portions of resources that selected a multi-year obligation in the FCA 1 or FCA 2. Otherwise, reserve margin gross-ups were discontinued with FCA 3. ISO-NE PUBLIC 40 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4
NEW GENERATION
ISO-NE PUBLIC 41 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 New Generation Update Based on Queue as of 9/28/15
• One new project with a rating of 15 MW has applied for interconnection study since the last update • The project consists of a new photovoltaic plant that is expected to be in service in 2016 • One project went commercial and two withdrew from the queue, resulting in a net decrease in new generation projects of 267 MW • In total, 84 generation projects are currently being tracked by the ISO, totaling approximately 11,100 MW
ISO-NE PUBLIC 42 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Actual and Projected Annual Capacity Additions By Supply Fuel Type and Demand Resource Type
4,000
3,500 Demand Response - Passive 3,000 Demand Reponse - 2,500 Active Wind/Other Renewables 2,000
1,500 Oil 1,000
Megawatts(MW) Natural Gas/Oil 500 0 Natural Gas -500 -1,000 2015 2016 2017 2018 2019 2020
Total % of 2015 2016 2017 2018 2019 2020 MW Total1 Demand Response - Passive 157 -12 330 196 0 0 670 6.3 Demand Response - Active 3 -868 -37 -433 0 0 -1,335 -12.6 Wind & Other Renewables 68 686 928 644 1,516 698 4,540 42.8 Oil 0 0 0 0 0 0 0 0.0 Natural Gas/Oil2 0 10 346 2,475 615 870 4,316 40.7 Natural Gas 180 123 745 210 1,149 0 2,407 22.7 Totals 408 -61 2,312 3,092 3,280 1,568 10,598 100.0 1 Sum may not equal 100% due to rounding 2 The projects in this category are dual fuel, with either gas or oil as the primary fuel
• 2015 values include the 148 MW of generation that has gone commercial in 2015 • DR reflects changes from the initial FCM Capacity Supply Obligations in 2010-11 ISO-NE PUBLIC 43 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Actual and Projected Annual Generator Capacity Additions By State
3,500
3,000 Vermont
2,500 Rhode Island
2,000 New Hampshire
1,500 Maine
Megawatts(MW) 1,000 Massachusetts
500 Connecticut
0 2015 2016 2017 2018 2019 2020
Total % of 2015 2016 2017 2018 2019 2020 MW Total1 Vermont 3 140 0 30 0 97 270 2.4 Rhode Island 27 22 29 0 1,430 0 1,508 13.4 New Hampshire 81 15 79 0 0 0 175 1.6 Maine 43 481 813 607 999 601 3,544 31.5 Massachusetts 10 40 1,098 1,061 788 870 3,867 34.3 Connecticut 84 121 0 1,631 63 0 1,899 16.9 Totals 248 819 2,019 3,329 3,280 1,568 11,263 100.0 1 Sum may not equal 100% due to rounding
• 2015 values include the 148 MW of generation that has gone commercial in 2015
ISO-NE PUBLIC 44 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 New Generation Projection By Fuel Type
Total Green Yellow No. of Capacity No. of Capacity No. of Capacity Fuel Type Projects (MW) Projects (MW) Projects (MW) Biomass/Wood Waste 1 37 0 0 1 37 Hydro 5 35 0 0 5 35 Landfill Gas 1 2 0 0 1 2 Natural Gas 15 2,359 0 0 15 2,359 Natural Gas/Oil 16 4,316 0 0 16 4,316 Oil 0 0 0 0 0 0 Solar 10 238 1 10 9 228 Wind 36 4,128 6 280 30 3,848 Total 84 11,115 7 290 77 10,825
•Projects in the Natural Gas/Oil category may have either gas or oil as the primary fuel •Green denotes projects with a high probability of going into service • Yellow denotes projects with a lower probability of going into service or new applications
ISO-NE PUBLIC 45 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 New Generation Projection By Operating Type
Total Green Yellow No. of Capacity No. of Capacity No. of Capacity Operating Type Projects (MW) Projects (MW) Projects (MW) Baseload 3 102 0 0 3 102 Intermediate 24 5,396 0 0 24 5,396 Peaker 21 1,489 1 10 20 1,479 Wind Turbine 36 4,128 6 280 30 3,848 Total 84 11,115 7 290 77 10,825
• Green denotes projects with a high probability of going into service • Yellow denotes projects with a lower probability of going into service or new applications
ISO-NE PUBLIC 46 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 New Generation Projection By Operating Type and Fuel Type
Total Baseload Intermediate Peaker Wind Turbine No. of Capacity No. of Capacity No. of Capacity No. of Capacity No. of Capacity Fuel Type Projects (MW) Projects (MW) Projects (MW) Projects (MW) Projects (MW) Biomass/Wood Waste 1 37 1 37 0 0 0 0 0 0 Hydro 5 35 0 0 4 10 1 25 0 0 Landfill Gas 1 2 1 2 0 0 0 0 0 0 Natural Gas 15 2,359 1 63 11 2,098 3 198 0 0 Natural Gas/Oil 16 4,316 0 0 9 3,288 7 1,028 0 0 Oil 0 0 0 0 0 0 0 0 0 0 Solar 10 238 0 0 0 0 10 238 0 0 Wind 36 4,128 0 0 0 0 0 0 36 4,128 Total 84 11,115 3 102 24 5,396 21 1,489 36 4,128
• Projects in the Natural Gas/Oil category may have either gas or oil as the primary fuel
ISO-NE PUBLIC 47 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4
FORWARD CAPACITY MARKET
ISO-NE PUBLIC 48 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Capacity Supply Obligation FCA 6
Annual Bilateral for Annual Bilateral for Annual Bilateral FCA Proration ARA 1 ARA 2 ARA 3 ARA 1 ARA 2 for ARA 3 Resource Resource Type Type *CSO CSO **Change CSO Change CSO Change CSO Change CSO Change CSO Change CSO Change
MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW
Active 2,001.510 1,918.662 -82.848 1,368.608 -550.054 1,271.984 -96.624 1,085.347 -186.64 842.791 -242.56 789.366 -53.425 638.393 -150.973 Demand Demand Passive 1,643.334 1,553.054 -90.280 1,521.535 -31.519 1,521.535 0.000 1,516.504 -5.03 1,700.586 184.08 1,694.766 -5.82 1,687.458 -7.308 Demand
Demand Total 3,644.844 3,471.716 -173.128 2,890.143 -581.573 2,793.519 -96.624 2,601.851 -191.67 2,543.377 -58.47 2,484.132 -59.245 2,325.851 -158.281
Non- 28,881.01 29,866.098 27,957.613 -1,908.485 28,121.731 164.118 28,343.440 221.709 28,442.424 98.98 28,727.16 284.73 153.859 28,971.511 90.492 Intermittent 9 Generator
Intermittent 891.069 840.563 -50.506 827.047 -13.516 828.252 1.205 829.219 0.97 820.743 -8.48 777.924 -42.819 754.101 -23.823
29,658.94 Generator Total 30,757.167 28,798.176 -1,958.991 28,948.778 150.602 29,171.692 222.914 29,271.643 99.95 29,547.9 276.26 111.043 29,725.612 66.669 3
Import Total 1,924.000 1,768.111 -155.889 1,768.111 0.000 1,641.821 -126.290 1,616.821 -25.00 1,399.037 -217.78 1,337.037 -62 1,337.037 0
33,480.11 ***Grand Total 36,326.011 34,038.003 -2,288.008 33,607.032 -430.971 33,607.032 0.000 33,490.315 -116.72 33,490.32 0.00 -10.208 33,388.5 -91.612 2
Net ICR (NICR) 33,456 33,456 0 33,456 0 33,456 0 33,114 -342 33,114 0.00 33,391 277 33,391 0
* Real-time Emergency Generators (RTEG) CSO not capped at 600.000 MW
** Change columns contain the changes in CSO amount resulting from the specific FCM Event as well as adjustments for Delisted MW released according to MR 1, Section 13.2.5.2, and changes that occurred (terminations, etc.) prior to the event reported in the column.
*** Grand Total reflects both CSO Grand Total and the net total of the Change Column.
ISO-NE PUBLIC 49 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Capacity Supply Obligation FCA 7
Annual Bilateral for Annual Bilateral Annual Bilateral FCA Proration ARA 1 ARA 2 ARA 3 ARA 1 for ARA 2 for ARA 3 Resource Resource Type Type *CSO CSO **Change CSO Change CSO Change CSO Change CSO Change CSO Change CSO Change
MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW
Active Demand 1,116.698 1,043.719 -72.979 944.27 -99.45 932.721 -11.549 781.206 -151.52 671.28 -109.926 Demand
Passive Demand 1,631.335 1,519.740 -111.595 1,519.311 -0.43 1,543.793 24.482 1,544.276 0.48 1,544.119 -0.157
Demand Total 2,748.033 2,563.459 -184.574 2,463.581 -99.88 2,476.514 12.933 2,325.482 -151.03 2,215.399 -110.083
Non- 30,704.578 28,146.837 -2,557.741 28,127.044 -19.79 28,523.002 395.958 28,307.339 -215.66 28,791.131 483.792 Intermittent Generator
Intermittent 936.913 893.710 -43.203 903.244 9.53 913.083 9.839 838.626 -74.46 824.833 -13.793
Generator Total 31,641.491 29,040.547 -2,600.944 29,030.288 -10.26 29,436.085 405.797 29,145.965 -290.12 29,615.964 469.999
Import Total 1,830.000 1,606.862 -223.138 1,606.862 0.00 1,616.401 9.539 1,576.401 -40.00 1,576.401 0
***Grand Total 36,219.524 33,210.868 -3,008.656 33,100.731 -110.14 33,529.000 428.269 33,047.848 -481.15 33,407.764 359.916
Net ICR (NICR) 32,968 32,968 0 33,529 561 33,529 0 33,529 0.00 33,529 0
* Real-time Emergency Generators (RTEG) CSO not capped at 600.000 MW
** Change columns contain the changes in CSO amount resulting from the specific FCM Event as well as adjustments for Delisted MW released according to MR 1, Section 13.2.5.2, and changes that occurred (terminations, etc.) prior to the event reported in the column.
*** Grand Total reflects both CSO Grand Total and the net total of the Change Column.
ISO-NE PUBLIC 50 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Capacity Supply Obligation FCA 8
Annual Bilateral for Annual Bilateral for Annual Bilateral for FCA ARA 1 ARA 2 ARA 3 ARA 1 ARA 2 ARA 3 Resource Resource Type Type *CSO CSO Change CSO Change CSO Change CSO Change CSO Change CSO Change
MW MW MW MW MW MW MW MW MW MW MW MW MW
Active Demand 1,080.079 887.493 -192.59 896.202 8.709 Demand Passive Demand 1,960.517 1,958.874 -1.64 1,956.663 -2.211
Demand Total 3,040.596 2,846.367 -194.23 2,852.865 6.498
Non- 28,547.813 28,523.796 -24.02 28,667.121 143.325 Intermittent Generator
Intermittent 876.925 898.955 22.03 921.922 22.967
Generator Total 29,424.738 29,422.751 -1.99 29,589.043 166.292
Import Total 1,237.034 1,237.034 0.00 1,375.53 138.496
***Grand Total 33,702.368 33,506.152 -196.22 33,817.438 311.286
Net ICR (NICR) 33,855 34,061 206.00 34,061 0
* Real-time Emergency Generators (RTEG) CSO not capped at 600.000 MW
** Change columns contain the changes in CSO amount resulting from the specific FCM Event as well as adjustments for Delisted MW released according to MR 1, Section 13.2.5.2, and changes that occurred (terminations, etc.) prior to the event reported in the column.
*** Grand Total reflects both CSO Grand Total and the net total of the Change Column.
ISO-NE PUBLIC 51 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Capacity Supply Obligation FCA 9
Annual Bilateral Annual Bilateral for Annual Bilateral for FCA ARA 1 ARA 2 ARA 3 for ARA 1 ARA 2 ARA 3 Resource Resource Type Type *CSO CSO Change CSO Change CSO Change CSO Change CSO Change CSO Change
MW MW MW MW MW MW MW MW MW MW MW MW MW
Active Demand 647.26 Demand Passive Demand 2,156.151
Demand Total 2,803.411
Non- 29,550.564 Intermittent Generator
Intermittent 891.616
Generator Total 30,442.18
Import Total 1,449
***Grand Total 34,694.591
Net ICR (NICR) 34,189
* Real-time Emergency Generators (RTEG) CSO not capped at 600.000 MW
** Change columns contain the changes in CSO amount resulting from the specific FCM Event as well as adjustments for Delisted MW released according to MR 1, Section 13.2.5.2, and changes that occurred (terminations, etc.) prior to the event reported in the column.
*** Grand Total reflects both CSO Grand Total and the net total of the Change Column.
ISO-NE PUBLIC 52 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Active/Passive Demand Response CSO Totals by Commitment Period
Commitment Period Active/ Passive Existing New Grand Total
Active 1246.399 603.675 1850.074 2010-11 Passive 119.211 584.277 703.488 Grand Total 1365.61 1187.952 2553.562 Active 1768.392 184.99 1953.382 2011-12 Passive 719.98 263.25 983.23 Grand Total 2488.372 448.24 2936.612 Active 1726.548 98.227 1824.775 2012-13 Passive 861.602 211.261 1072.863 Grand Total 2588.15 309.488 2897.638 Active 1794.195 257.341 2051.536 2013-14 Passive 1040.113 257.793 1297.906 Grand Total 2834.308 515.134 3349.442 Active 2062.196 41.945 2104.141 2014-15 Passive 1264.641 221.072 1485.713 Grand Total 3326.837 263.017 3589.854 Active 1935.406 66.104 2001.51 2015-16 Passive 1395.885 247.449 1643.334 Grand Total 3331.291 313.553 3644.844 Active 1116.468 0.23 1116.698 2016-17 Passive 1386.56 244.775 1631.335 Grand Total 2503.028 245.005 2748.033 Active 1066.593 13.486 1080.079 2017-18 Passive 1619.147 341.37 1960.517 Grand Total 2685.74 354.856 3040.596 Active 565.866 81.394 647.26 2018-19 Passive 1870.549 285.602 2156.151 Grand Total 2436.415 366.996 2803.411
ISO-NE PUBLIC 53 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4
RELIABILITY COSTS – NET COMMITMENT PERIOD COMPENSATION (NCPC) OPERATING COSTS
ISO-NE PUBLIC 54 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 What are Daily NCPC Payments?
• Payments made to resources whose hourly commitment and dispatch by ISO-NE resulted in a shortfall between the resource’s offered value in the Energy and Regulation Markets and the revenue earned from output over the course of the day • Typically, this is the result of some out-of-merit operation of resources occurring in order to protect the overall resource adequacy and transmission security of specific locations or of the entire control area
ISO-NE PUBLIC 55 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Definitions
1st Contingency NCPC Reliability costs paid to eligible resources that are providing first Payments contingency (1stC) protection (including low voltage, system operating reserve, and load serving) either system-wide or locally 2nd Contingency NCPC Reliability costs paid to resources providing capacity in constrained areas to Payments respond to a local second contingency. They are committed based on 2nd Contingency (2ndC) protocols, and are also known as Local Second Contingency Protection Resources (LSCPR) Voltage NCPC Payments Reliability costs paid to resources operated by ISO-NE to provide voltage support or control in specific locations
Distribution NCPC Reliability costs paid to units dispatched at the request of local transmission Payments providers for purpose of managing constraints on the low voltage (distribution) system. These requirements are not modeled in the DA Market software Delisted Units Resources within the control area that have requested to be classified as a non-installed capacity (ICAP) resource, and as such, are not required to offer their capacity into the DA Energy Market OATT Open Access Transmission Tariff
ISO-NE PUBLIC 56 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Charge Allocation Key
Allocation Market Allocation Category / OATT System 1st Market DA 1st C (excluding at external nodes) is allocated to system DALO. Contingency RT 1st C (at all locations) is allocated to System ‘Daily Deviations’. Daily Deviations = sum of(generator deviations, load deviations, generation obligation deviations at external nodes, increment offer deviations) External DA 1st Market DA 1st C at external nodes (from imports, exports, Incs and Decs) are Contingency allocated to activity at the specific external node or interface involved Zonal 2nd Market DA and RT 2nd C NCPC are allocated to load obligation in the Reliability Contingency Region (zone) served System Low OATT (Low) Voltage Support NCPC is allocated to system Regional Network Load Voltage and Open Access Same-Time Information Service (OASIS) reservations Zonal High OATT High Voltage Control NCPC is allocated to zonal Regional Network Load Voltage Distribution - PTO OATT Distribution NCPC is allocated to the specific Participant Transmission Owner (PTO) requesting the service System – Other Market Includes GPA, Min Generation Emergency, and Generator and DARD NCPC
ISO-NE PUBLIC 57 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Year-Over-Year Total NCPC Dollars and Energy
GR:Graph23NCPC Dollars GR:Graph23mNCPC Energy*
$80 1,000
$70 900 800 $60 700 $50 600
$40 500
GWh Millions 400 $30 300 $20 200 $10 100
$0 0 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC
2012 2013 2012 2013 2014 2015 2014 2015
* NCPC Energy GWh reflect the DA and/or RT economic minimum loadings of all units receiving DA or RT NCPC credits, assessed during hours in which they are NCPC-eligible. All NCPC components (1st Contingency, 2nd Contingency, Voltage, and RT Distribution) are reflected.
ISO-NE PUBLIC 58 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 DA and RT NCPC Charges
SEP-15GR:Graph01 Total = $15.58 M GR:Graph02Last 13 Months
$75
$60
43% $45
Millions $30
$15 57%
$0
SEP2014 DEC2014 JAN2015 FEB2015 JUN2015 JUL2015 SEP2015 OCT2014NOV2014 MAR2015 APR2015MAY2015 AUG2015
Day-Ahead Real-Time Day-Ahead Real-Time
ISO-NE PUBLIC 59 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 NCPC Charges by Type
GR:Graph03 SEP-15 Total = $15.58 M GR:Graph04 Last 13 Months
$75 25% $60
$45 0%
Millions $30
$15
$0 75%
SEP14 DEC14 JAN15 FEB15 JUN15 JUL15 SEP15 OCT14 NOV14 MAR15 APR15 MAY15 AUG15
1st C 2nd C 1st C 2nd C Voltage Voltage Distrib
1st C – First Contingency 2nd C – Second Contingency Distrib – Distribution Voltage – Voltage
ISO-NE PUBLIC 60 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Daily NCPC Charges by Type
GR:ncpc_bytype_stack_dly $1.9 $1.8 $1.7 $1.6 $1.5 $1.4 $1.3 $1.2 $1.1 $1.0
$0.9 Millions $0.8 $0.7 $0.6 $0.5 $0.4 $0.3 $0.2 $0.1 $0.0
01SEP201502SEP201503SEP201504SEP201505SEP201506SEP201507SEP201508SEP201509SEP201510SEP201511SEP201512SEP201513SEP201514SEP201515SEP201516SEP201517SEP201518SEP201519SEP201520SEP201521SEP201522SEP201523SEP2015
1st C 2nd C Voltage
ISO-NE PUBLIC 61 NEPOOL PARTICIPANTS COMMITTEE 0.8% 0CT 2, 2015 MEETING, AGENDA ITEM #4 NCPC Charges by Allocation
GR:xpie_ncpc_chgs_alloc_catSEP-15 Total = $15.58 M GR:xchart_ncpc_chgs_alloc_catLast 13 Months 0.0% $40.0
20% $32.0
$24.0
5.1% Millions $16.0 0.2%0.0% $8.0
75% $0.0 1.8%
SEP14 DEC14 JAN15 FEB15 JUN15 JUL15 SEP15 4.2% OCT14 NOV14 MAR15 APR15 MAY15 AUG15
System 1stC Ext DA 1stC System 1stC Ext DA 1stC Zonal 2ndC System Low V Zonal 2ndC System Low V Zonal High V Dist - PTO Zonal High V Dist - PTO System Other System Other
ISO-NE PUBLIC 62 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 RT First Contingency Charges by Deviation Type
GR:pie_firstc_rt_bydevSEP-15 Total = $3.64 M GR:chart_firstc_rt_bydev_13moLast 13 Months
6.9% 14.1% $10 $9 $8 $7 7.8% $6 $5
Millions $4 $3 $2 $1 $0 71.2%
SEP14 DEC14 JAN15 FEB15 JUN15 JUL15 SEP15 OCT14 NOV14 MAR15 APR15 MAY15 AUG15
Gen Import Gen Import Inc Load Inc Load
Gen – Generator deviations Inc – Increment Offer deviations Imp – Import deviations Load – Load obligation deviations
ISO-NE PUBLIC 63 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 LSCPR Charges by Zone
GR:lscpr_charges_byzone_13mo $12.0 $11.0
$10.0
$9.0
$8.0
$7.0
$6.0 Millions $5.0
$4.0
$3.0
$2.0
$1.0
$0.0
SEP14 DEC14 JAN15 FEB15 JUN15 JUL15 SEP15 OCT14 NOV14 MAR15 APR15 MAY15 AUG15
CT ME NEMA NH RI SEMA VT WCMA CT – Connecticut Region SEMA – Southeast Massachusetts Region ME – Maine Region WCMA – Western/Central Massachusetts Region NH – New Hampshire Region NEMA – Northeast Massachusetts Region RI – Rhode Island Region EXT – External Locations VT – Vermont Region ISO-NE PUBLIC 64 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 NCPC Charges for Voltage Support and High Voltage Control
GR:var_charges_stack_13mo $1.3 $1.2
$1.1
$1.0
$0.9
$0.8
$0.7
Millions $0.6
$0.5
$0.4
$0.3
$0.2
$0.1
$0.0
SEP14 DEC14 JAN15 FEB15 JUN15 JUL15 SEP15 OCT14 NOV14 MAR15 APR15 MAY15 AUG15
DA LV NCPC RT LV NCPC DA HV NCPC
ISO-NE PUBLIC 65 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 NCPC Charges by Type
GR:NCPC_StackValue of Charges
$175 $174.6 $158.7 $150
$125
$100 $89.6
Millions $75
$50
$25
$15.6
$14.7
$11.3 $11.5
$9.9
$9.4
$6.4
$5.6 $5.2 $0
2013 2014 2015 JAN2015 FEB2015 JUL2015 SEP2015 MAR2015 APR2015 MAY2015 JUN2015 AUG2015 OCT2015 NOV2015 DEC2015
1st C 2nd C Distr Voltg
ISO-NE PUBLIC 66 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 NCPC Charges as Percent of Energy Market
NCPC ByGR:NCPC_pct_Stack Type as Percent of Energy Market
5.0%
4.7% 4.1%
4.0% 3.8%
3.0%
2.3%
Percent
2.0% 2.0%
2.0% 1.9%
1.8%
1.4%
1.3% 1.1%
1.0% 0.8%
0.0%
2013 2014 2015 JAN2015 FEB2015 JUL2015 SEP2015 MAR2015 APR2015 MAY2015 JUN2015 AUG2015 OCT2015 NOV2015 DEC2015
1st C 2nd C Distr Voltg
ISO-NE PUBLIC 67 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 First Contingency NCPC Charges
GR:Graph19Value of Charges % ofGR:Graph20 Energy Market Value
$140 4.0% $135.2
$120
3.0% $100 $98.9
$80
2.0%
1.9%
Millions 1.6%
$60 1.6%
$53.7
1.5%
1.3%
1.3%
1.2%
1.2% 1.1% $40 1.1%
1.0% 1.0% 0.7%
$20
$9.2 $9.3
$8.6
$4.8
$4.5 $4.3 $4.6 $4.5 $3.9 $0 0.0%
2013 2014 2015 2013 2014 2015
JAN2015 FEB2015 JUL2015 SEP2015 JAN2015 FEB2015 APR2015 JUN2015 JUL2015 SEP2015 OCT2015 DEC2015 APR2015 JUN2015 OCT2015 DEC2015 MAR2015 MAY2015 AUG2015 NOV2015 MAR2015 MAY2015 AUG2015 NOV2015
Note: Energy Market value is the hourly locational product of load obligation and price in the DA Market plus the hourly locational product of price and RT Load Obligation Deviation in the RT Market
ISO-NE PUBLIC 68 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Second Contingency NCPC Charges
GR:Graph21Value of Charges % ofGR:Graph22 Energy Market Value
$40 4.0%
$38.0
3.5% $32.8 $32.4 3.2%
$30 2.5% 2.4%
$20
1.9% Millions
1.6% $11.6
$10 0.7%
$7.0 0.8%
0.7% 0.7%
$4.9
0.5%
$4.6
0.4%
0.3%
$2.0
$1.1
$0.9
0.1% 0.1% 0.1% $0.5 $0 $0.2 0.0%
2013 2014 2015 2013 2014 2015
JAN2015 FEB2015 APR2015 JUN2015 JUL2015 SEP2015 OCT2015 DEC2015 JAN2015 FEB2015 APR2015 JUN2015 JUL2015 SEP2015 OCT2015 DEC2015 MAR2015 MAY2015 AUG2015 NOV2015 MAR2015 MAY2015 AUG2015 NOV2015
Note: Energy Market value is the hourly locational product of load obligation and price in the DA Market plus the hourly locational product of price and RT Load Obligation Deviation in the RT Market
ISO-NE PUBLIC 69 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Voltage and Distribution NCPC Charges
GR:Graph17Value of Charges % ofGR:Graph18 Energy Market Value
$40 4.0%
$30 3.0% $21.8
$20 2.0% Millions
$10 1.0%
$7.0
$3.1
0.3%
$1.3
0.1% 0.1%
$0.8 0.1% 0.1%
0.1% 0.1%
$0.5 0.0%
$0.2 $0.2 0.0%
$0.0 $0.0 $0.0 0.0% 0.0% 0.0% $0 $0.1 0.0%
2013 2014 2015 2013 2014 2015
JAN2015 FEB2015 APR2015 JUN2015 JUL2015 SEP2015 OCT2015 DEC2015 JAN2015 FEB2015 APR2015 JUN2015 JUL2015 SEP2015 OCT2015 DEC2015 MAR2015 MAY2015 AUG2015 NOV2015 MAR2015 MAY2015 AUG2015 NOV2015
Note: Energy Market value is the hourly locational product of load obligation and price in the DA Market plus the hourly locational product of price and RT Load Obligation Deviation in the RT Market
ISO-NE PUBLIC 70 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 DA vs. RT Pricing
The following slides outline: • This month vs. prior year’s average LMPs and fuel costs • Reserve Market results • DA cleared load vs. RT load • Zonal and total incs and decs • Self-schedules • DA vs. RT net interchange
ISO-NE PUBLIC 71 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 DA vs. RT LMPs ($/MWh)
Arithmetic Average Year 2013 NEMA CT ME NH VT RI SEMA WCMA Hub Day-Ahead $56.90 $55.43 $54.48 $55.98 $55.36 $57.80 $57.02 $56.38 $56.43 Real-Time $56.32 $55.90 $53.23 $55.15 $55.08 $56.10 $56.43 $56.12 $56.06 RT Delta % -1.0% 0.8% -2.3% -1.5% -0.5% -2.9% -1.0% -0.5% -0.7% Year 2014 NEMA CT ME NH VT RI SEMA WCMA Hub Day-Ahead $64.98 $64.10 $61.95 $64.12 $63.82 $64.98 $64.71 $64.66 $64.57 Real-Time $64.03 $63.11 $59.04 $61.48 $61.60 $63.34 $63.45 $63.29 $63.32 RT Delta % -1.5% -1.5% -4.7% -4.1% -3.5% -2.5% -2.0% -2.1% -1.9%
September-14 NEMA CT ME NH VT RI SEMA WCMA Hub Day-Ahead $34.32 $34.47 $33.53 $34.29 $33.92 $35.29 $34.18 $34.23 $34.10 Real-Time $36.38 $38.40 $35.66 $36.19 $35.70 $36.05 $35.99 $36.12 $36.04 RT Delta % 6.0% 11.4% 6.4% 5.6% 5.3% 2.2% 5.3% 5.5% 5.7% September-15 NEMA CT ME NH VT RI SEMA WCMA Hub Day-Ahead $36.58 $33.00 $32.37 $33.14 $33.22 $33.90 $33.29 $33.21 $33.09 Real-Time $38.81 $37.23 $34.46 $35.72 $36.54 $37.44 $37.87 $37.04 $37.08 RT Delta % 6.1% 12.8% 6.5% 7.8% 10.0% 10.4% 13.8% 11.5% 12.1% Annual Diff. NEMA CT ME NH VT RI SEMA WCMA Hub Yr over Yr DA 6.6% -4.3% -3.5% -3.4% -2.1% -3.9% -2.6% -3.0% -3.0% Yr over Yr RT 6.7% -3.0% -3.4% -1.3% 2.3% 3.9% 5.2% 2.6% 2.9%
ISO-NE PUBLIC 72 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Monthly Average Fuel Price and RT Hub LMP Indexes
3.000 GR:Graph25
2.000 March 2003=1.000March 1.000
0.000
JUN2003SEP2003DEC2003JUN2004SEP2004DEC2004JUN2005SEP2005DEC2005JUN2006SEP2006DEC2006JUN2007SEP2007DEC2007JUN2008SEP2008DEC2008JUN2009SEP2009DEC2009JUN2010SEP2010DEC2010JUN2011SEP2011DEC2011JUN2012SEP2012DEC2012JUN2013SEP2013DEC2013JUN2014SEP2014DEC2014JUN2015SEP2015DEC2015 MAR2003 MAR2004 MAR2005 MAR2006 MAR2007 MAR2008 MAR2009 MAR2010 MAR2011 MAR2012 MAR2013 MAR2014 MAR2015 MAR2016
Natural Gas Hub RT LMP Underlying natural gas data furnished by:
ISO-NE PUBLIC 73 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Monthly Average Fuel Price and RT Hub LMP
$30.00 GR:hubwgas_mly_smd $200.00
$27.00
$24.00 $160.00
$21.00
$18.00 $120.00
$15.00
$/MMBtu (Fuel) $12.00 $80.00 $/MWh (Electricity)
$9.00
$6.00 $40.00
$3.00
$0.00 $0.00
JUN2003SEP2003DEC2003JUN2004SEP2004DEC2004JUN2005SEP2005DEC2005JUN2006SEP2006DEC2006JUN2007SEP2007DEC2007JUN2008SEP2008DEC2008JUN2009SEP2009DEC2009JUN2010SEP2010DEC2010JUN2011SEP2011DEC2011JUN2012SEP2012DEC2012JUN2013SEP2013DEC2013JUN2014SEP2014DEC2014JUN2015SEP2015DEC2015 MAR2003 MAR2004 MAR2005 MAR2006 MAR2007 MAR2008 MAR2009 MAR2010 MAR2011 MAR2012 MAR2013 MAR2014 MAR2015 MAR2016
Natural Gas Hub RT LMP Underlying natural gas data furnished by:
ISO-NE PUBLIC 74 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 New England, NY, and PJM Real Time Prices
GR:three_pools_prices_mlyMonthly, Last 13 Months GR:three_pools_prices_dlyDaily: This Month
$130 $110 $120 $100 $110 $90 $100 $80 $90 $70 $80 $60 $70 $60 $50 $50 $40
$40 $30 Electricity Prices ($/MWh)Electricity $30 Prices ($/MWh)Electricity $20 $20 $10 $10 $0
SEP2014 DEC2014 JAN2015 FEB2015 JUN2015 JUL2015 SEP2015 OCT2014NOV2014 MAR2015APR2015MAY2015 AUG2015 01SEP1502SEP1503SEP1504SEP1505SEP1506SEP1507SEP1508SEP1509SEP1510SEP1511SEP1512SEP1513SEP1514SEP1515SEP1516SEP1517SEP1518SEP1519SEP1520SEP1521SEP1522SEP1523SEP15
ISO-NE NY-ISO PJM ISO-NE NY-ISO PJM
*Note: Hourly average prices are shown. *Note: Hourly average prices are shown.
ISO-NE PUBLIC 75 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 New England, NY, and PJM Real Time Prices (Peak Hour)
GR:three_pools_prices_fpk_mlyMonthly, Last 13 Months GR:three_pools_prices_fpk_dlyDaily: This Month
$170 $500 $160 $150 $140 $400 $130 $120 $110 $300 $100 $90 $80 $200 $70
$60 Electricity Prices ($/MWh)Electricity
Electricity Prices ($/MWh)Electricity $100 $50 $40 $30 $0
SEP2014 DEC2014 JAN2015 FEB2015 JUN2015 JUL2015 SEP2015 OCT2014NOV2014 MAR2015APR2015MAY2015 AUG2015 01SEP1502SEP1503SEP1504SEP1505SEP1506SEP1507SEP1508SEP1509SEP1510SEP1511SEP1512SEP1513SEP1514SEP1515SEP1516SEP1517SEP1518SEP1519SEP1520SEP1521SEP1522SEP1523SEP15
ISO-NE NY-ISO PJM ISO-NE NY-ISO PJM
*Forecasted New England peak hour is reflected.
ISO-NE PUBLIC 76 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Reserve Market Results – September 2015 • Maximum potential Forward Reserve Market payments of $4.9M were reduced by credit reductions of $158K, failure-to- reserve penalties of $381K and failure-to-activate penalties of $0, resulting in a net payout of $4.4M or 89% of maximum – Rest of System: $1.85M/$1.94M (95%) – Southwest Connecticut: $0.26M/$0.35M (73%) – Connecticut: $1.07M/$1.22M (88%) – NEMA: $1.21M/$1.41M (86%) • $7.3M total Real-Time credits were reduced by $2.4M in Forward Reserve Energy Obligation Charges for a net of $4.9M in Real-Time Reserve payments – Rest of System: 92 hours, $3.2M – Southwest Connecticut: 92 hours, $960K – Connecticut: 92 hours, $276K – NEMA: 95 hours, $500K * “Failure to reserve” results in both credit reductions and penalties in the Locational Forward Reserve Market.
ISO-NE PUBLIC 77 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 LFRM Charges to Load by Load Zone ($)
LFRM ChargesGR:Graph39 by Zone, Last 13 Months
$25.0
$20.0
$15.0 Millions
$10.0
$5.0
$0.0
SEP14 JAN15 FEB15 JUL15 SEP15 OCT14 NOV14 DEC14 MAR15 APR15 MAY15 JUN15 AUG15
CT ME NEMA NH RI SEMA VT WCMA
ISO-NE PUBLIC 78 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Zonal Increment Offers and Cleared Amounts
SeptemberGR:Graph28 Monthly Totals by Zone
120,000
110,000
100,000
90,000
80,000
70,000
60,000 MWh 50,000
40,000
30,000
20,000
10,000
0
2014 2015 2014 2015 2014 2015 2014 2015 2014 2015 2014 2015 2014 2015 2014 2015 2014 2015
Hub ME NH VT CT RI SEMA WCMA NEMA
Cleared Offered
ISO-NE PUBLIC 79 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Zonal Decrement Bids and Cleared Amounts
SeptemberGR:Graph29 Monthly Totals by Zone
60,000
50,000
40,000
30,000 MWh
20,000
10,000
0
2014 2015 2014 2015 2014 2015 2014 2015 2014 2015 2014 2015 2014 2015 2014 2015 2014 2015
Hub ME NH VT CT RI SEMA WCMA NEMA
Cleared Bid
ISO-NE PUBLIC 80 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Total Increment Offers and Decrement Bids
ZonalGR:Graph30 Level, Last 13 Months
1,000,000
900,000
800,000
700,000
600,000
500,000 MWh 400,000
300,000
200,000
100,000
0
INC INC INC INC INC INC INC INC INC INC INC INC INC
DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC DEC
JUL2015
SEP2014 FEB2015 SEP2015
DEC2014 JAN2015
OCT2014 APR2015 JUN2015
NOV2014 AUG2015
MAR2015 MAY2015
Cleared Bid/Offered Data excludes nodal offers and bids
ISO-NE PUBLIC 81 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Dispatchable vs. Non-Dispatchable Generation
Total MonthlyGR:Graph31 Energy; Dispatchable % Shown
14,000
12,000
41.2% 45.4%
10,000
40.9%
49.7%
41.2%
22.8% 38.9%
34.1%
42.0% 39.7%
8,000 19.9%
17.1%
46.0% GWh 6,000
4,000
2,000
0
SEP2014 JAN2015 FEB2015 JUL2015 SEP2015 OCT2014 NOV2014 DEC2014 MAR2015 APR2015 MAY2015 JUN2015 AUG2015
Non-Dispatchable Dispatchable
* Dispatchable MWh here are defined to be generation output that is not self-scheduled (i.e, not self-committed or ‘must run’ by the customer). ISO-NE PUBLIC 82 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Rolling Average Peak Energy Rent (PER)
$0.20 GR:rolling_avg_per_big
$0.17
$0.16
$0.13 $0.13 $0.13
$0.12
$0.10 $0.10 $0.10 $0.09
$0.09 $/KW-Month $0.08
$0.05 $0.05 $0.05 $0.04 $0.04
$0.00 NEW SEP14 OCT14 NOV14 DEC14 JAN15 FEB15 MAR15 APR15 MAY15 JUN15 JUL15 AUG15 SEP15 monthSLIDE Rest-of-Pool Rolling Average PER is currently calculated as a rolling twelve month average of individual monthly PER values for the twelve months preceding the obligation month. Individual monthly PER values are published to the ISO web site here: Home > Markets > Other Markets Data > Forward Capacity Market > Reports and are subject to resettlement. ISO-NE PUBLIC 83 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 PER Adjustments
GR:fcm_per_adj_byzone_big $5.0 $4.7
$4.0 $3.6 $3.6 $3.6
$3.0 $2.7 $2.7 $2.7 $2.5
$2.4 Millions($) $2.0
$1.3 $1.3 $1.3 $1.1 $1.0
$0.0 NEW SEP14 OCT14 NOV14 DEC14 JAN15 FEB15 MAR15 APR15 MAY15 JUN15 JUL15 AUG15 SEP15 month SLIDE Rest-of-Pool
PER Adjustments are reductions to Forward Capacity Market monthly payments resulting from the rolling average PER.
ISO-NE PUBLIC 84 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4
REGIONAL SYSTEM PLAN (RSP) AND INTERREGIONAL PLANNING
ISO-NE PUBLIC 85 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 RSP15 and the RSP Process
• RSP15 will be sent to the Board on September 29 and we anticipate Board approval by November • Changes to the OATT, including Attachment K, are being proposed in response to stakeholder requests – Issue RSP no less than once every three years – It is the ISO’s intent to issue the next RSP in 2017, pending further input from stakeholders – Change the timing of the RSP page turn, Public Meeting, and issuance from specific dates to better coordinate with stakeholder schedules, ISO workloads, and the processes of neighboring systems – A meeting is scheduled with the TC for October 27 to seek stakeholder input
ISO-NE PUBLIC 86 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Planning Advisory Committee (PAC)
• Tentative October 22 PAC Agenda: – RSP Project List Update – Keene Road 2015 Economic Study Update – Maine 2023 Needs Update – Essex STATCOM Replacement – Transmission Operators PAC – TOPAC • NHT Local System Plan (LSP) • Emera LSP • NGrid LSP • UI LSP • NU/NSTAR LSP • CMP LSP • VELCO • CTMEC (tentative)
ISO-NE PUBLIC 87 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Distributed Generation Forecast Working Group (DGFWG)
• ISO is working with DG resources seeking participation in the FCM • ISO is working with the transmission owners, distribution owners, the states, and IEEE to resolve interconnection issues • ISO will continue participation in DOE projects that support operational and planning forecasts of PV • ISO is surveying utilities on a monthly basis for total PV capacity by service territory in support of operational load forecasting activities • ISO will continue to work with DGFWG stakeholders to improve data collection processes
ISO-NE PUBLIC 88 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Environmental Matters
• Environmental Advisory Group teleconference scheduled for November 3 to discuss the final EPA Clean Power Plan and other environmental matters
ISO-NE PUBLIC 89 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Economic Studies
• ISO is conducting three 2015 economic studies of wind integration scenarios – Study of the Keene Road Area – Study utilizing the Strategic Transmission Analysis results – Study of offshore wind expansion • Studies will be given priority by the ISO – Draft results for the Keene Road Area will be discussed with the PAC on October 22 – PAC discussions of other draft results are planned for PAC by late 2015 or early 2016 – Final reports completed after consultation with the PAC • Studies will compare the performance of the future system with additional representative future system improvements – Studies will not include detailed transmission planning analysis including system impact study results • ISO may form special economic study working groups that will supplement PAC discussions via conference calls – PAC presentations will be structured to discuss the general PAC economic study issues upfront – More technical discussions will be reviewed with PAC members as a last meeting agenda item
ISO-NE PUBLIC 90 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 RSP Project Stage Descriptions
Stage Description 1 Planning and Preparation of Project Configuration 2 Pre-construction (e.g., material ordering, project scheduling) 3 Construction in Progress 4 In Service
ISO-NE PUBLIC 91 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Connecticut River Valley Status as of 9/28/15
Project Benefit: Addresses system needs in the Connecticut River Corridor in Vermont
Expected Present Upgrade In-Service Stage Rebuild 115 kV line K31, Coolidge-Ascutney Oct-17 1 Ascutney Substation - Add a +50/-25 MVAR dynamic reactive device Oct-17 1 Hartford Substation - Split 25 MVAR capacitor bank into two 12.5 MVAR banks Oct-17 1 Chelsea Station - Rebuild to a three-breaker ring bus Oct-17 1
Note: The above listing focuses on major transmission line construction and rebuilding.
ISO-NE PUBLIC 92 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 NEEWS: Interstate Reliability Project Status as of 9/28/15 Plan Benefit: Improves New England reliability by increasing transfer limits of three critical interfaces Expected Present Upgrade In-Service Stage Build New 345 kV Line 3271 Card - Lake Road Dec-15 4 Card 345 kV Substation Expansion Dec-15 4 Lake Road 345 kV Substation Expansion Dec-15 3 Build New 345 kV Line 341 Lake Road to CT/RI Border Dec-15 3 Build New 345 kV Line 341 CT/RI Border to West Farnum Dec-15 3 West Farnum 345 kV Substation Additions (New Line Terminations) Dec-15 3 New Sherman Road 345 kV Substation Dec-15 3 West Farnum 115 kV Substation Upgrades Sep-14 4 Reconductor 345 kV Line 328 West Farnum to Sherman Road Dec-15 3 Riverside Substation Relay Upgrades Sep-14 4 Woonsocket Substation Relay Upgrades Sep-14 4 Hartford Avenue Substation Relay Upgrades Sep-14 4 Build New 345 kV Line 366 West Farnum to MA/RI Border Dec-15 3 Build New 345 kV Line 366 MA/RI Border to Millbury 3 Dec-15 3 Millbury 3 Substation Expansion Dec-15 3 Carpenter Hill Substation Relay Upgrades Dec-15 3
ISO-NE PUBLIC 93 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 New Hampshire/Vermont 10-Year Upgrades Status as of 9/28/15
Project Benefit: Addresses Needs in New Hampshire and Vermont
Expected Present Upgrade In-Service Stage Eagle Substation Add: 345/115 kV autotransformer Dec-16 2 Littleton Substation Add: Second 230/115 kV autotransformer Oct-14 4 New C-203 230 kV line tap to Littleton NH Substation Nov-14 4 New 115 kV overhead line, Fitzwilliam-Monadnock Dec-16 2 New 115 kV overhead line, Scobie Pond-Huse Road Dec-15 3 New 115 kV overhead/submarine line, Madbury-Portsmouth Dec-17 2 New 115 kV overhead line, Scobie Pond-Chester Dec-15 3 New 115 kV overhead line, Coolidge-Ascutney Dec-16 1
Note: The above listing focuses on major transmission line construction and rebuilding.
ISO-NE PUBLIC 94 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 New Hampshire/Vermont 10-Year Upgrades, cont. Status as of 9/28/15
Project Benefit: Addresses Needs in New Hampshire and Vermont
Expected Present Upgrade In-Service Stage Saco Valley Substation - Add two 25 MVAR dynamic reactive devices Dec-16 3 Rebuild 115 kV line K165, W157 tap Eagle-Power Street May-15 4 Rebuild 115 kV line H137, Merrimack-Garvins Jun-13 4 Rebuild 115 kV line D118, Deerfield-Pine Hill Nov-14 4 Oak Hill Substation - Loop in 115 kV line V182, Garvins-Webster Apr-15 4* Uprate 115 kV line G146, Garvins-Deerfield Mar-15 4 Uprate 115 kV line P145, Oak Hill-Merrimack May-14 4
* Placed in-service ahead of schedule Note: The above listing focuses on major transmission line construction and rebuilding.
ISO-NE PUBLIC 95 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 New Hampshire/Vermont 10-Year Upgrades, cont. Status as of 9/28/15
Project Benefit: Addresses Needs in New Hampshire and Vermont
Expected Present Upgrade In-Service Stage Upgrade 115 kV line H141, Chester-Great Bay Nov-14 4 Upgrade 115 kV line R193, Scobie Pond-Kingston Tap Mar-15 4* Upgrade 115 kV line T198, Keene-Monadnock Nov-13 4 Upgrade 345 kV line 326, Scobie Pond-NH/MA Border Dec-13 4 Upgrade 115 kV line J114-2, Greggs - Rimmon Dec-13 4 Upgrade 345 kV line 381, between MA/NH border and NH/VT border Jun-13 4
* Placed in-service ahead of schedule Note: The above listing focuses on major transmission line construction and rebuilding.
ISO-NE PUBLIC 96 NEPOOL PARTICIPANTS COMMITTEE Greater Hartford and Central Connecticut (GHCC)0CT 2, 2015 MEETING, AGENDA ITEM #4 Projects* Status as of 9/28/15 Plan Benefit: Addresses long-term system needs in the four study sub-areas of Greater Hartford, Middletown, Barbour Hill and Northwestern Connecticut and increases western Connecticut import capability Expected Present Upgrade In-Service Stage Add a 2nd 345/115 kV autotransformer at Haddam substation and reconfigure the 3-terminal 345 kV 348 line into two 2-terminal lines Dec-16 3 Terminal equipment upgrades on the 345 kV line between Haddam Neck and Beseck (362) Dec-17 1 Redesign the Green Hill 115 kV substation from a straight bus to a ring bus and add two 115 kV 25.2 MVAR capacitor banks Dec-17 2 Add a 37.8 MVAR capacitor bank at the Hopewell 115 kV substation Dec-16 2 Separation of 115 kV double circuit towers corresponding to the Branford – Branford RR line (1537) and the Branford to North Haven (1655) line and adding a 115 kV breaker at Branford 115 kV substation Dec-17 2 Increase the size of the existing 115 kV capacitor bank at Branford Substation from 37.8 to 50.4 MVAR Dec-17 2 Separation of 115 kV double circuit towers corresponding to the Middletown – Pratt and Whitney line (1572) and the Middletown to Haddam (1620) line Dec-17 2 * Replaces the NEEWS Central Connecticut Reliability Project ISO-NE PUBLIC 97 NEPOOL PARTICIPANTS COMMITTEE Greater Hartford and Central Connecticut (GHCC)0CT 2, 2015 MEETING, AGENDA ITEM #4 Projects, cont.* Status as of 9/28/15 Plan Benefit: Addresses long-term system needs in the four study sub-areas of Greater Hartford, Middletown, Barbour Hill and Northwestern Connecticut and increases western Connecticut import capability
Expected Present Upgrade In-Service Stage Terminal equipment upgrades on the 115 kV line from Middletown to Dooley (1050) Jun-15 4 Terminal equipment upgrades on the 115 kV line from Middletown to Portland (1443) Jun-15 4 Add a new 115 kV underground cable from Newington to Southwest Hartford and associated terminal equipment including a 2% series reactor Dec-18 2 Add a 115 kV 25.2 MVAR capacitor at Westside 115 kV substation Dec-16 2 Loop the 1779 line between South Meadow and Bloomfield into the Rood Avenue substation and reconfigure the Rood Avenue substation Dec-17 2 Reconfigure the Berlin 115 kV substation including two new 115 kV breakers and the relocation of a capacitor bank Dec-18 2 Reconductor the 115 kV line between Newington and Newington Tap (1783) Dec-18 2
* Replaces the NEEWS Central Connecticut Reliability Project
ISO-NE PUBLIC 98 NEPOOL PARTICIPANTS COMMITTEE Greater Hartford and Central Connecticut0CT (GHCC) 2, 2015 MEETING, AGENDA ITEM #4 Projects, cont.* Status as of 9/28/15 Plan Benefit: Addresses long-term system needs in the four study sub-areas of Greater Hartford, Middletown, Barbour Hill and Northwestern Connecticut and increases western Connecticut import capability Expected Present Upgrade In-Service Stage Separation of 115 kV DCT corresponding to the Bloomfield to South Meadow (1779) line and the Bloomfield to North Bloomfield (1777) line and add a breaker at Bloomfield 115 kV substation Dec-17 2 Separation of 115 kV DCT corresponding to the Bloomfield to North Bloomfield (1777) line and the North Bloomfield – Rood Avenue – Northwest Hartford (1751) line and add a breaker at North Bloomfield 115 kV substation Dec-17 2 Install a 115 kV 3% reactor on the 115 kV line between South Meadow and Southwest Hartford (1704) Dec-18 2 Replace the existing 3% series reactors on the 115 kV lines between Southington and Todd (1910) and between Southington and Canal (1950) with a 5% series reactors Dec-17 2 Replace the normally open 19T breaker at Southington 115 kV with a normally closed 3% series reactor Dec-17 2 Add a 345 kV breaker in series with breaker 5T at Southington Dec-17 2
* Replaces the NEEWS Central Connecticut Reliability Project ISO-NE PUBLIC 99 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Greater Hartford and Central Connecticut Projects, cont.* Status as of 9/28/15
Plan Benefit: Addresses long-term system needs in the four study sub-areas of Greater Hartford, Middletown, Barbour Hill and Northwestern Connecticut and increases western Connecticut import capability
Expected Present Upgrade In-Service Stage Add a new control house at Southington 115 kV substation Dec-17 2 Add a new 115 kV line from Frost Bridge to Campville Dec-18 2 Separation of 115 kV DCT corresponding to the Frost Bridge to Campville (1191) line and the Thomaston to Campville (1921) line and add a breaker at Campville 115 kV substation Dec-18 2 Upgrade the 115 kV line between Southington and Lake Avenue Junction (1810-1) Dec-17 2 Add a new 345/115 kV autotransformer at Barbour Hill substation Jan-16 3 Add a 345 kV breaker in series with breaker 24T at the Manchester 345 kV substation Jan-16 3 Reconductor the 115 kV line between Manchester and Barbour Hill (1763) Dec-16 2
* Replaces the NEEWS Central Connecticut Reliability Project ISO-NE PUBLIC 100 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Southwest Connecticut (SWCT) Projects Status as of 9/28/15 Plan Benefit: Addresses long-term system needs in the four study sub-areas of Frost Bridge/Naugatuck Valley, Housatonic Valley/Plumtree – Norwalk, Bridgeport, New Haven – Southington and improves system reliability Expected Present Upgrade In-Service Stage Add a 25.2 MVAR capacitor bank at the Oxford substation Dec-16 2 Add 2 x 25 MVAR capacitor banks at the Ansonia substation Dec-17 1 Close the normally open 115 kV 2T circuit breaker at Baldwin substation Dec-17 2 Rebuild Bunker Hill to a 9-breaker substation in breaker-and-a-half configuration Dec-17 1 Reconductor the 115 kV line between Bunker Hill and Baldwin Junction (1575) Dec-17 1 Loop the 1990 line in and out the Bunker Hill substation Dec-17 1 Expand Pootatuck (formerly known as Shelton) substation to 4-breaker ring bus configuration and add a 30 MVAR capacitor bank at Pootatuck Dec-18 1 Loop the 1570 line in and out the Pootatuck substation Dec-18 1 Replace two 115 kV circuit breakers at the Freight substation Dec-15 2
ISO-NE PUBLIC 101 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Southwest Connecticut Projects, cont. Status as of 9/28/15 Plan Benefit: Addresses long-term system needs in the four study sub-areas of Frost Bridge/Naugatuck Valley, Housatonic Valley/Plumtree – Norwalk, Bridgeport, New Haven – Southington and improves system reliability
Expected Present Upgrade In-Service Stage Add two 14.4 MVAR capacitor banks at the West Brookfield substation Dec-17 1 Add a new 115 kV line from Plumtree to Brookfield Junction Dec-18 1 Reconductor the 115 kV line between West Brookfield and Brookfield Junction (1887) Dec-18 1 Reduce the existing 25.2 MVAR capacitor bank at the Rocky River substation to 14.4 MVAR Dec-18 1 Reconfigure the 1887 line into a three-terminal line (Plumtree - W. Brookfield - Shepaug) Dec-18 1 Reconfigure the 1770 line into 2 two-terminal lines (Plumtree - Stony Hill and Stony Hill - Bates Rock) Dec-18 1 Install a synchronous condenser (+25/-12.5 MVAR) at Stony Hill Dec-18 1 Relocate an existing 37.8 MVAR capacitor bank at Stony Hill to the 25.2 MVAR capacitor bank side Dec-17 1
ISO-NE PUBLIC 102 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Southwest Connecticut Projects, cont. Status as of 9/28/15 Plan Benefit: Addresses long-term system needs in the four study sub-areas of Frost Bridge/Naugatuck Valley, Housatonic Valley/Plumtree – Norwalk, Bridgeport, New Haven – Southington and improves system reliability Expected Present Upgrade In-Service Stage Relocate the existing 37.8 MVAR capacitor bank from 115 kV B bus to 115 kV A bus at the Plumtree substation Dec-17 1 Add a 115 kV circuit breaker in series with the existing 29T breaker at the Plumtree substation Dec-17 2 Terminal equipment upgrade at the Newtown substation (1876) Dec-15 3 Rebuild the 115 kV line from Wilton to Norwalk (1682) and upgrade Wilton substation terminal equipment Dec-16 1
Reconductor the 115 kV line from Wilton to Ridgefield Junction (1470-1) Dec-17 1 Reconductor the 115 kV line from Ridgefield Junction to Peaceable (1470-3) Dec-17 1
ISO-NE PUBLIC 103 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Southwest Connecticut Projects, cont. Status as of 9/28/15 Plan Benefit: Addresses long-term system needs in the four study sub areas of Frost Bridge/Naugatuck Valley, Housatonic Valley/Plumtree – Norwalk, Bridgeport, New Haven – Southington and improves system reliability
Expected Present Upgrade In-Service Stage Add 2 x 20 MVAR capacitor banks at the Hawthorne substation Mar-16 3 Upgrade the 115 kV bus at the Baird substation Dec-17 2 Upgrade the 115 kV bus system and 11 disconnect switches at the Dec-14 4 Pequonnock substation Add a 345 kV breaker in series with the existing 11T breaker at the East Dec-15 3 Devon substation Rebuild the 115 kV lines from Baird to Congress (8809A / 8909B) Dec-18 2 Rebuild the 115 kV lines from Housatonic River Crossing (HRX) to Barnum Dec-19 1 to Baird (88006A / 89006B)
ISO-NE PUBLIC 104 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Southwest Connecticut Projects, cont. Status as of 9/28/15 Plan Benefit: Addresses long-term system needs in the four study sub areas of Frost Bridge/Naugatuck Valley, Housatonic Valley/Plumtree – Norwalk, Bridgeport, New Haven – Southington and improves system reliability
Expected Present Upgrade In-Service Stage Remove the Sackett phase shifter Dec-17 1 Install a 7.5 ohm series reactor on 1610 line at the Mix Avenue substation Dec-17 2 Add 2 x 20 MVAR capacitor banks at the Mix Avenue substation Dec-17 2 Separate the 3827 (Beseck to East Devon) and 1610 (Southington to June Dec-18 1 to Mix Avenue) double circuit towers Upgrade the 1630 line relay at North Haven and Wallingford 1630 terminal Dec-16 2 equipment Rebuild the 115 kV lines from Devon Tie to Milvon (88005A / 89005B) Dec-16 3 Replace two 115 kV circuit breakers at Mill River Dec-14 4
ISO-NE PUBLIC 105 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Greater Boston Projects Status as of 9/28/15 Plan Benefit: Addresses long-term system needs in the Greater Boston area and improves system reliability Expected Present Upgrade In-Service Stage Install new 345 kV line from Scobie to Tewksbury Dec-17 1 Reconductor the Y-151 115 kV line from Dracut Junction to Power Street Dec-17 1 Reconductor the M-139 115 kV line from Tewksbury to Pinehurst and Jun-17 1 associated work at Tewksbury Reconductor the N-140 115 kV line from Tewksbury to Pinehurst and Jun-17 1 associated work at Tewksbury Reconductor the F-158N 115 kV line from Wakefield Junction to Dec-15 3 Maplewood and associated work at Maplewood Reconductor the F-158S 115 kV line from Maplewood to Everett Dec-17 1 Install new 345 kV cable from Woburn to Wakefield Junction, install two new 160 MVAR variable shunt reactors and associated work at Wakefield Dec-18 1 Junction and Woburn Refurbish X-24 69 kV line from Millbury to Northboro Road Dec-15 3 Reconductor W-23W 69 kV line from Woodside to Northboro Road Jun-16 1
ISO-NE PUBLIC 106 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Greater Boston Projects, cont. Status as of 9/28/15 Plan Benefit: Addresses long-term system needs in the Greater Boston area and improves system reliability
Expected Present Upgrade In-Service Stage Separate X-24 and E-157W DCT Oct-16 1 Separate Q-169 and F-158N DCT Dec-15 3 Reconductor M-139/211-503 and N-140/211-504 115 kV lines from May-17 1 Pinehurst to North Woburn tap Install new 115 kV station at Sharon to segment three 115 kV lines from May-17 1 West Walpole to Holbrook Install third 115 kV line from West Walpole to Holbrook Dec-16 1 Install new 345 kV breaker in series with the 104 breaker at Stoughton Dec-16 1 Install new 230/115 kV autotransformer at Sudbury and loop the 282-602 Dec-15 3 230 kV line in and out of the new 230 kV switchyard at Sudbury Install a new 115 kV line from Sudbury to Hudson Dec-18 1
ISO-NE PUBLIC 107 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Greater Boston Projects, cont. Status as of 9/28/15 Plan Benefit: Addresses long-term system needs in the Greater Boston area and improves system reliability
Expected Present Upgrade In-Service Stage Replace 345/115 kV autotransformer, 345 kV breakers, and 115 kV Dec-17 1 switchgear at Woburn Install a 345 kV breaker in series with breaker 104 at Woburn Dec-16 1 Reconfigure Waltham by relocating PARs, 282-507 line, and a breaker May-16 2 Upgrade 533-508 115 kV line from Lexington to Hartwell and associated Dec-15 2 work at the stations Install a new 115 kV 54 MVAR capacitor bank at Newton Dec-16 1 Install a new 115 kV 36.7 MVAR capacitor bank at Sudbury Dec-16 1 Install a second Mystic 345/115 kV autotransformer and reconfigure the bus Dec-16 1 Install a 115 kV breaker on the West bus at K Street Dec-16 1 Install 115 kV cable from Mystic to Chelsea Dec-17 1 Split 110-522 and 240-510 DCT from Baker Street to Needham for a Dec-17 1 portion of the way and install a 115 kV cable for the rest of the way
ISO-NE PUBLIC 108 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Greater Boston Projects, cont. Status as of 9/28/15 Plan Benefit: Addresses long-term system needs in the Greater Boston area and improves system reliability
Expected Present Upgrade In-Service Stage Install a second 115 kV cable from Mystic to Woburn to create a bifurcated Dec-17 1 211-514 line Open lines 329-510/511 and 250-516/517 at Mystic and Chatham, Dec-16 1 respectively. Operate K Street as a normally closed station Upgrade Kingston to create a second normally closed 115 kV bus tie and Dec-17 1 reconfigure the 345 kV switchyard Relocate the Chelsea capacitor bank to the 128-518 termination postion Dec-17 2
ISO-NE PUBLIC 109 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Greater Boston Projects, cont. Status as of 9/28/15 Plan Benefit: Addresses long-term system needs in the Greater Boston area and improves system reliability
Expected Present Upgrade In-Service Stage Upgrade North Cambridge to mitigate 115 kV 5 and 10 stuck breaker Jun-16 1 contingencies Upgrade Edgar 115 kV station to BPS standards Dec-20 1 Upgrade Dover 115 kV station to BPS standards Dec-20 1 Upgrade East Cambridge 115 kV station to BPS standards Dec-19 1 Upgrade West Methuen 115 kV station to BPS standards Jun-18 1 Upgrade Medway 115 kV station to BPS standards Dec-19 1 Install a 200 MVAR STATCOM at Coopers Mills TBD 1 Install a 115 kV 36.7 MVAR capacitor bank at Hartwell May-17 1 Install a 345 kV 160 MVAR shunt reactor at K Street May-18 1 Install a 115 kV breaker in series with the 5 breaker at Framingham Jun-17 1 Install a 115 kV breaker in series with the 29 breaker at K Street Dec-16 1
ISO-NE PUBLIC 110 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Status of Tariff Studies 120
100 98 95 95 93 92 93 4 93 10 89 6 5 4 4 7 4 80 24 24 25 22 24 24 27 26 69 Distribution 67 64 4 62 63 4 Executed IA 60 3 4 4 15 10 13 14 16 14 11 Negotiating IA 22 0 12 22 0 0 Facility Study 18 21 22 0 0 0 0 0 Sys. Impact Study 40 22 17 18 Number ofProjects 8 25 7 7 8 26 26 28 Optional Study 1 7 0 0 0 28 0 0 0 Feasibility Study 0 9 7 11 0 21 0 Scoping 21 21 21 0 0 0 20 19 17 0 16 17 17 0 0 0 0 4 24 24 17 7 6 5 4 20 10 10 5 5 6 8 7 7 4 6 0 Sep-14 Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 8,268 8,311 8,355 9,579 10,597 11,208 11,367 10,458 12,186 12,140 11,250 11,380 11,113 MW MW MW MW MW MW MW MW MW MW MW MW MW Generator Project Status
https://irtt.iso-ne.com/external.aspx Note: As of September 2015, there are 7 ETU’s in SIS Note: September 2015 based on partial data
ISO-NE PUBLIC 111 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4
OPERABLE CAPACITY ANALYSIS Fall 2015
ISO-NE PUBLIC 112 NEPOOL PARTICIPANTS COMMITTEE Fall 2015 Operable Capacity Analysis 0CT 2, 2015 MEETING, AGENDA ITEM #4 50/50 Load Forecast (Reference) November - 20152 November - 20152 CSO SCC Generator Operable Capacity MW 1 29,769 32,837 OP CAP From OP-4 RTDR (+) 443 443 OP CAP From OP-4 RTEG (+) 192 192 Operable Capacity Generator with OP-4 DR and RTEG 30,404 33,472 External Node Available Net Capacity, CSO imports minus firm capacity 1,226 1,226 exports (+) Non Commercial Capacity (+) 20 20 Non Gas-fired Planned Outage MW (-) 4,990 5,222 Gas Generator Outages MW (-) 1,578 1,656 Allowance for Unplanned Outages (-) 5 3,600 3,600 Generation at Risk Due to Gas Supply (-) 4 459 607 Net Capacity (NET OPCAP SUPPLY MW) 3 21,023 23,633 Peak Load Forecast MW(adjusted for Other Demand Resources) 2 18,988 18,988 Operating Reserve Requirement MW 2,375 2,375 Operable Capacity Required (NET LOAD OBLIGATION MW) 21,363 21,363 Operable Capacity Margin 3 (340) 2,270 1 Generator Operable Capacity is based on data as of September 18, 2015 and does not include Capacity associated with Settlement Only Generators, Passive and Active Demand Response, and external capacity. SCC value is based on data as of September 18, 2015 2 Load based on 2015 CELT report and week with lowest Operable Capacity Margin, week beginning November 21, 2015. 3 Includes OP4 actions associated with RTEG and RTDR 4 Total of (Gas at Risk MW) – (Gas Gen Outages MW) 5 Allowance For Unplanned Outage MW is based on the month corresponding to the day with the lowest Operable Capacity Margin for the week.
ISO-NE PUBLIC 113 NEPOOL PARTICIPANTS COMMITTEE Fall 2015 Operable Capacity Analysis 0CT 2, 2015 MEETING, AGENDA ITEM #4 90/10 Load Forecast (Extreme) November - 20152 November - 20152 CSO SCC Generator Operable Capacity MW 1 29,769 32,837 OP CAP From OP-4 RTDR (+) 443 443 OP CAP From OP-4 RTEG (+) 192 192 Operable Capacity Generator with OP-4 DR and RTEG 30,404 33,472 External Node Available Net Capacity, CSO imports minus firm capacity 1,226 1,226 exports (+) Non Commercial Capacity (+) 20 20 Non Gas-fired Planned Outage MW (-) 4,990 5,222 Gas Generator Outages MW (-) 1,578 1,656 Allowance for Unplanned Outages (-) 5 3,600 3,600 Generation at Risk Due to Gas Supply (-) 4 274 402 Net Capacity (NET OPCAP SUPPLY MW) 3 21,208 23,838 Peak Load Forecast MW(adjusted for Other Demand Resources) 2 19,588 19,588 Operating Reserve Requirement MW 2,375 2,375 Operable Capacity Required (NET LOAD OBLIGATION MW) 21,963 21,963 Operable Capacity Margin 3 (755) 1,875 1 Generator Operable Capacity is based on data as of September 18, 2015 and does not include Capacity associated with Settlement Only Generators, Passive and Active Demand Response, and external capacity. SCC value is based on data as of September 18, 2015 2 Load based on 2015 CELT report and week with lowest Operable Capacity Margin, week beginning November 21, 2015. 3 Includes OP4 actions associated with RTEG and RTDR 4 Total of (Gas at Risk MW) – (Gas Gen Outages MW) 5 Allowance For Unplanned Outage MW is based on the month corresponding to the day with the lowest Operable Capacity Margin for the week.
ISO-NE PUBLIC 114 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Fall 2015 Operable Capacity Analysis (MW) 50/50 Forecast (Reference)
ISO-NE 2015 OPERABLE CAPACITY ANALYSIS - - with RTDR and RTEG - 50/50 FORECAST
3,500
2,500
1,500
500
(500) Operable Capacity Margin (MW) Margin Capacity Operable
(1,500)
Oct
Oct Oct Oct Oct
Nov Nov Nov
Nov
-
- - - -
- - -
-
3
7
24 31 10 17
14 21 28
October 3, 2015 - December 4, 2015, W/B Saturday
ISO-NE PUBLIC 115 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Fall 2015 Operable Capacity Analysis (MW) 90/10 Forecast (Extreme)
ISO-NE 2015 OPERABLE CAPACITY ANALYSIS - - with RTDR and RTEG - 90/10 FORECAST
3,500
2,500
1,500
500
(500) Operable Capacity Margin (MW) Margin Capacity Operable
(1,500)
Oct Oct Oct Oct
Oct
Nov
Nov Nov Nov
- - - -
-
-
- - -
3
7
10 24 17 31
14 21 28
October 3, 2015 - December 4, 2015 W/B Saturday
ISO-NE PUBLIC 116 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Fall 2015 Operable Capacity Analysis (MW) 50/50 Forecast (Reference)
ISO-NE 2015 OPERABLE CAPACITY ANALYSIS CSO 50/50 RWT_COO_AMS 9/18/15 9:35 CSO _OCT_2015_100 50/50 October 2, 2015 - 50/50 FORECAST using CSO values with RTDR and RTEG SCC 90/10 This analysis is a tabulation of weekly assessments shown in one single table. The information shows the operable capacity situation under assumed conditions for each week. It is not expected that the system peak will occur every week during June, July, and August and M id September.
GAS OPCAP NON-GAS GENERAT ALLOWANCE OPCAP FROM MARGIN w/ OPCAP FROM OPCAP MARGIN EXTERNAL NON PLANNED OR FOR PEAK LOAD OPER RESERVE OPCAP OP4 ACTIVE OP4 actions OP4 REAL- w/ OP4 actions STUDY WEEK AVAILABLE NODE AVAIL COMMERCIAL OUTAGES CSO OUTAGES UNPLANNED GAS AT NET OPCAP FORECAST REQUIREMENT NET LOAD MARGIN REAL-TIME DR through OP4 TIME EMER. through OP4 Step (Week Beginning, OPCAP MW CAPACITY MW CAPACITY MW MW CSO MW OUTAGES MW RISK MW SUPPLY MW MW MW OBLIGATION MW MW MW Step 2 MW GEN MW 6 MW Saturday) [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14] [15] [16] 10/3/2015 30,298 878 0 5,869 1,095 2,800 0 21,412 16,195 2,375 18,570 2,842 308 3,150 156 3,306 10/10/2015 30,298 878 0 5,443 1,303 2,800 0 21,630 16,232 2,375 18,607 3,023 308 3,331 156 3,487 10/17/2015 30,298 878 0 6,485 623 2,800 0 21,268 17,178 2,375 19,553 1,715 308 2,023 156 2,179 10/24/2015 30,298 724 0 6,299 623 2,800 0 21,300 17,551 2,375 19,926 1,374 308 1,682 156 1,838 10/31/2015 30,298 624 20 6,223 1,350 3,600 0 19,769 15,631 2,375 18,006 1,763 308 2,071 156 2,227 11/7/2015 29,769 950 20 5,598 1,189 3,600 0 20,352 17,881 2,375 20,256 96 443 539 192 731 11/14/2015 29,769 1,226 20 5,509 1,622 3,600 0 20,284 18,233 2,375 20,608 (324) 443 119 192 311 11/21/2015 29,769 1,226 20 4,990 1,578 3,600 459 20,388 18,988 2,375 21,363 (975) 443 (532) 192 (340) 11/28/2015 29,769 1,226 30 2,940 783 3,200 2,159 21,943 19,725 2,375 22,100 (157) 443 286 192 478 (1,843) 1. Available OPCAP MW based on resource Capacity Supply Obligations, CSO. Does not include Settlement Only Generators. 2. External Node Available Capacity MW based on the sum of external Capacity Supply Obligations (CSO) imports and exports. 3. New resources and generator improvements that have acquired a CSO but have not become commercial. 4.Non-Gas Planned Outages is the total of Non Gas-fired Generator/DARD Outages for the period. This value would also include any known long-term Non Gas-fired Forced Outages. 5. All Planned Gas-fired generation outage for the period. This value would also include any known long-term Gas-fired Forced Outages. 6. Allowance for Unplanned Outages includes forced outages and maintenance outages scheduled less than 14 days in advance per ISO New England Operating Procedure No. 5 Appendix A. 7. Generation at Risk due to Gas Supply pertains to gas fired capacity expected to be at risk during cold weather conditions or gas pipeline maintenance outages. 8. Net OpCap Supply MW Available (1 + 2 + 3 - 4 - 5 - 6 - 7 = 8) 9. Peak Load Forecast as provided in the 2015 CELT Report and adjusted for Passive Demand Resources. http:/ / www.iso-ne.com/ system-planning/ system-plans-studies/ celt 10. Operating Reserve Requirement based on 125% of first largest contingency plus 50% of the second largest contingency. 11. Total Net Load Obligation per the formula(9 + 10 = 11) 12. Net OPCAP Margin MW = Net Op Cap Supply MW minus Net Load Obligation (8 - 11 = 12) 13. OP 4 Action 2 Real-time Demand Response based on OP4 Appendix A. Reserve Margins and Distribution Loss Factor Gross Ups are Included. 14. OPCAP Margin taking into account Real Time Demand Response through OP4 Step 2 (12 + 13 = 14) 15. OP 4 Action 6 Emergency Generation Response without the Voltage Reduction requiring > 10 Minutes based on OP4 Appendix A. Real Time Emergency Generation is capped at 600MW. Reserve Margins and Distribution Loss Factor Gross Ups are Included. 16. OPCAP Margin taking into account Real Time Demand Response and Real Time Emergency Generation through OP4 Step 6 (14 + 15 = 16) This does not include Emergency Energy Transactions (EETs).
ISO-NE PUBLIC 117 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Fall 2015 Operable Capacity Analysis (MW) 90/10 Forecast (Extreme)
ISO-NE 2015 OPERABLE CAPACITY ANALYSIS CSO 50/50 RWT_COO_AMS 9/18/15 9:45 CSO _OCT_2015_100 90/10 October 2, 2015 - 90/10 FORECAST using CSO values with RTDR and RTEG SCC 90/10 This analysis is a tabulation of weekly assessments shown in one single table. The information shows the operable capacity situation under assumed conditions for each week. It is not expected that the system peak will occur every week during June, July, and August and M id September.
GAS OPCAP NON-GAS GENERAT ALLOWANCE OPCAP FROM MARGIN w/ OPCAP FROM OPCAP MARGIN EXTERNAL NON PLANNED OR FOR NET LOAD OPCAP OP4 ACTIVE OP4 actions OP4 REAL- w/ OP4 actions STUDY WEEK AVAILABLE NODE AVAIL COMMERCIAL OUTAGES CSO OUTAGES UNPLANNED GAS AT NET OPCAP PEAK LOAD OPER RESERVE OBLIGATION MARGIN REAL-TIME DR through OP4 TIME EMER. through OP4 Step (Week Beginning, OPCAP MW CAPACITY MW CAPACITY MW MW CSO MW OUTAGES MW RISK MW SUPPLY MW FORECAST MW REQUIREMENT MW MW MW MW Step 2 MW GEN MW 6 MW Saturday) [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14] [15] [16] 10/3/2015 30,298 878 0 5,869 1,095 2,800 0 21,412 16,714 2,375 19,089 2,323 308 2,631 156 2,787 10/10/2015 30,298 878 0 5,443 1,303 2,800 0 21,630 16,752 2,375 19,127 2,503 308 2,811 156 2,967 10/17/2015 30,298 878 0 6,485 623 2,800 0 21,268 17,725 2,375 20,100 1,168 308 1,476 156 1,632 10/24/2015 30,298 724 0 6,299 623 2,800 0 21,300 18,109 2,375 20,484 816 308 1,124 156 1,280 10/31/2015 30,298 624 20 6,223 1,350 3,600 0 19,769 16,128 2,375 18,503 1,266 308 1,574 156 1,730 11/7/2015 29,769 950 20 5,598 1,189 3,600 0 20,352 18,448 2,375 20,823 (471) 443 (28) 192 164 11/14/2015 29,769 1,226 20 5,509 1,622 3,600 0 20,284 18,811 2,375 21,186 (902) 443 (459) 192 (267) 11/21/2015 29,769 1,226 20 4,990 1,578 3,600 274 20,573 19,588 2,375 21,963 (1,390) 443 (947) 192 (755) 11/28/2015 29,769 1,226 30 2,940 783 3,200 1,810 22,292 20,346 2,375 22,721 (429) 443 14 192 206 (4,223) 1. Available OPCAP MW based on resource Capacity Supply Obligations, CSO. Does not include Settlement Only Generators. 2. External Node Available Capacity MW based on the sum of external Capacity Supply Obligations (CSO) imports and exports. 3. New resources and generator improvements that have acquired a CSO but have not become commercial. 4. Non-Gas Planned Outages is the total of Non Gas-fired Generator/DARD Outages for the period. This value would also include any known long-term Non Gas-fired Forced Outages. 5. All Planned Gas-fired generation outage for the period. This value would also include any known long-term Gas-fired Forced Outages. 6. Allowance for Unplanned Outages includes forced outages and maintenance outages scheduled less than 14 days in advance per ISO New England Operating Procedure No. 5 Appendix A. 7. Generation at Risk due to Gas Supply pertains to gas fired capacity expected to be at risk during cold weather conditions or gas pipeline maintenance outages. 8. Net OpCap Supply MW Available (1 + 2 + 3 - 4 - 5 - 6 - 7 = 8) 9. Peak Load Forecast as provided in the 2015 CELT Report and adjusted for Passive Demand Resources. http:/ / www.iso-ne.com/ system-planning/ system-plans-studies/ celt 10. Operating Reserve Requirement based on 125% of first largest contingency plus 50% the second largest contingency. 11. Total Net Load Obligation per the formula(9 + 10 = 11) 12. Net OPCAP Margin MW = Net Op Cap Supply MW minus Net Load Obligation (8 - 11 = 12) 13. OP 4 Action 2 Real-time Demand Response based on OP4 Appendix A. Reserve Margins and Distribution Loss Factor Gross Ups are Included. 14. OPCAP Margin taking into account Real Time Demand Response through OP4 Step 2 (12 + 13 = 14) 15. OP 4 Action 6 Emergency Generation Response without the Voltage Reduction requiring > 10 Minutes based on OP4 Appendix A. Real Time Emergency Generation is capped at 600MW. Reserve Margins and Distribution Loss Factor Gross Ups are Included. 16. OPCAP Margin taking into account Real Time Demand Response and Real Time Emergency Generation through OP4 Step 6 (14 + 15 = 16) This does not include Emergency Energy Transactions (EETs).
ISO-NE PUBLIC 118 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4
OPERABLE CAPACITY ANALYSIS Preliminary Winter 2015/16
ISO-NE PUBLIC 119 NEPOOL PARTICIPANTS COMMITTEE Winter 2015/16 Operable Capacity Analysis 0CT 2, 2015 MEETING, AGENDA ITEM #4 50/50 Load Forecast (Reference) January - 20162 January –20162 CSO SCC Generator Operable Capacity MW 1 29,899 32,837 OP CAP From OP-4 RTDR (+) 423 423 OP CAP From OP-4 RTEG (+) 174 174 Operable Capacity Generator with OP-4 DR and RTEG 30,496 33,434 External Node Available Net Capacity, CSO imports minus firm capacity 1,226 1,226 exports (+) Non Commercial Capacity (+) 35 35 Non Gas-fired Planned Outage MW (-) 662 694 Gas Generator Outages MW (-) 0 0 Allowance for Unplanned Outages (-) 5 2,800 2,800 Generation at Risk Due to Gas Supply (-) 4 3,828 4,254 Net Capacity (NET OPCAP SUPPLY MW) 3 24,467 26,947 Peak Load Forecast MW(adjusted for Other Demand Resources) 2 21,077 21,077 Operating Reserve Requirement MW 2,375 2,375 Operable Capacity Required (NET LOAD OBLIGATION MW) 23,452 23,452 Operable Capacity Margin 3 1,015 3,495 1 Generator Operable Capacity is based on data as of September 18, 2015 and does not include Capacity associated with Settlement Only Generators, Passive and Active Demand Response, and external capacity. SCC value is based on data as of September 18, 2015 2 Load based on 2015 CELT report and week with lowest Operable Capacity Margin, week beginning January 9, 2016. 3 Includes OP4 actions associated with RTEG and RTDR 4 Total of (Gas at Risk MW) – (Gas Gen Outages MW) 5 Allowance For Unplanned Outage MW is based on the month corresponding to the day with the lowest Operable Capacity Margin for the week.
ISO-NE PUBLIC 120 NEPOOL PARTICIPANTS COMMITTEE Winter 2015/16 Operable Capacity Analysis 0CT 2, 2015 MEETING, AGENDA ITEM #4 90/10 Load Forecast (Extreme) January- 20162 January - 20162 CSO SCC Generator Operable Capacity MW 1 29,899 32,837 OP CAP From OP-4 RTDR (+) 423 423 OP CAP From OP-4 RTEG (+) 174 174 Operable Capacity Generator with OP-4 DR and RTEG 30,496 33,434 External Node Available Net Capacity, CSO imports minus firm capacity 1,226 1,226 exports (+) Non Commercial Capacity (+) 35 35 Non Gas-fired Planned Outage MW (-) 662 694 Gas Generator Outages MW (-) 0 0 Allowance for Unplanned Outages (-) 5 2,800 2,800 Generation at Risk Due to Gas Supply (-) 4 4,631 5,145 Net Capacity (NET OPCAP SUPPLY MW) 3 23,664 26,056 Peak Load Forecast MW(adjusted for Other Demand Resources) 2 21,737 21,737 Operating Reserve Requirement MW 2,375 2,375 Operable Capacity Required (NET LOAD OBLIGATION MW) 24,112 24,112 Operable Capacity Margin 3 (448) 1,944 1 Generator Operable Capacity is based on data as of September 18, 2015 and does not include Capacity associated with Settlement Only Generators, Passive and Active Demand Response, and external capacity. SCC value is based on data as of September 18, 2015 2 Load based on 2015 CELT report and week with lowest Operable Capacity Margin, week beginning January 9, 2016. 3 Includes OP4 actions associated with RTEG and RTDR 4 Total of (Gas at Risk MW) – (Gas Gen Outages MW) 5 Allowance For Unplanned Outage MW is based on the month corresponding to the day with the lowest Operable Capacity Margin for the week.
ISO-NE PUBLIC 121 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Winter 2015/16 Operable Capacity Analysis (MW) 50/50 Forecast (Reference)
ISO-NE 2015-16 OPERABLE CAPACITY ANALYSIS - - with RTDR and RTEG - 50/50 FORECAST
6,000
5,000
4,000
3,000
2,000
1,000
Operable Capacity Margin (MW) Margin Capacity Operable 0
(1,000)
Jan Jan Jan
Jan Jan
Mar
Mar Feb Feb Feb Mar Mar
Feb
Dec
Dec Dec Dec
- - -
- -
-
------
-
-
- - -
2 9
5
6
5
30 16 23
12 13 20 27 19 26
19 26 12
December 5, 2015 - April 1, 2016, W/B Saturday
ISO-NE PUBLIC 122 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Winter 2015/16 Operable Capacity Analysis (MW) 90/10 Forecast (Extreme)
ISO-NE 2015-16 OPERABLE CAPACITY ANALYSIS - - with RTDR and RTEG - 90/10 FORECAST
6,000
5,000
4,000
3,000
2,000
1,000
Operable Capacity Margin (MW) Margin Capacity Operable 0
(1,000)
Jan Jan
Jan Jan Jan
Mar Mar Mar
Feb Mar
Feb Feb Feb
Dec Dec Dec
Dec
- -
- - -
- - -
- -
- - -
- - -
-
2 9
5
6
5
16 23 30
19 12 26
13 20 27
12 19 26
December 5, 2015 - April 1, 2016 W/B Saturday
ISO-NE PUBLIC 123 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Winter 2015/16 Operable Capacity Analysis (MW) 50/50 Forecast (Reference)
ISO-NE 2015-16 OPERABLE CAPACITY ANALYSIS CSO 50/50 RWT_COO_AMS 9/18/15 9:35 CSO _OCT_2015_100 50/50 October 2, 2015 - 50/50 FORECAST using CSO values with RTDR and RTEG SCC 90/10 This analysis is a tabulation of weekly assessments shown in one single table. The information shows the operable capacity situation under assumed conditions for each week. It is not expected that the system peak will occur every week during June, July, and August and M id September.
GAS OPCAP NON-GAS GENERAT ALLOWANCE OPCAP FROM MARGIN w/ OPCAP FROM OPCAP MARGIN EXTERNAL NON PLANNED OR FOR PEAK LOAD OPER RESERVE OPCAP OP4 ACTIVE OP4 actions OP4 REAL- w/ OP4 actions STUDY WEEK AVAILABLE NODE AVAIL COMMERCIAL OUTAGES CSO OUTAGES UNPLANNED GAS AT NET OPCAP FORECAST REQUIREMENT NET LOAD MARGIN REAL-TIME DR through OP4 TIME EMER. through OP4 Step (Week Beginning, OPCAP MW CAPACITY MW CAPACITY MW MW CSO MW OUTAGES MW RISK MW SUPPLY MW MW MW OBLIGATION MW MW MW Step 2 MW GEN MW 6 MW Saturday) [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14] [15] [16] 12/5/2015 29,899 1,226 30 1,471 1,209 3,200 2,229 23,046 19,951 2,375 22,326 720 423 1,143 174 1,317 12/12/2015 29,899 1,226 30 809 900 3,200 2,581 23,665 20,247 2,375 22,622 1,043 423 1,466 174 1,640 12/19/2015 29,899 1,226 30 801 654 3,200 2,870 23,630 20,258 2,375 22,633 997 423 1,420 174 1,594 12/26/2015 29,899 1,226 35 694 161 3,200 3,494 23,611 20,322 2,375 22,697 914 423 1,337 174 1,511 1/2/2016 29,899 1,226 35 662 0 2,800 3,741 23,957 20,602 2,375 22,977 980 423 1,403 174 1,577 1/9/2016 29,899 1,226 35 662 0 2,800 3,828 23,870 21,077 2,375 23,452 418 423 841 174 1,015 1/16/2016 29,899 1,226 35 621 0 2,800 3,828 23,911 21,077 2,375 23,452 459 423 882 174 1,056 1/23/2016 29,899 1,226 35 587 0 2,800 3,785 23,988 21,077 2,375 23,452 536 423 959 174 1,133 1/30/2016 29,899 1,226 35 587 0 3,100 3,655 23,818 20,850 2,375 23,225 593 423 1,016 174 1,190 2/6/2016 29,899 1,226 35 631 0 3,100 3,568 23,861 20,577 2,375 22,952 909 423 1,332 174 1,506 2/13/2016 29,899 1,226 35 631 0 3,100 3,481 23,948 20,547 2,375 22,922 1,026 423 1,449 174 1,623 2/20/2016 29,899 1,226 35 327 0 3,100 3,394 24,339 20,279 2,375 22,654 1,685 423 2,108 174 2,282 2/27/2016 29,899 1,226 37 731 0 2,200 2,715 25,516 19,269 2,375 21,644 3,872 423 4,295 174 4,469 3/5/2016 29,899 1,226 37 761 1,156 2,200 1,106 25,939 18,912 2,375 21,287 4,652 423 5,075 174 5,249 3/12/2016 29,899 1,226 37 742 916 2,200 894 26,410 18,712 2,375 21,087 5,323 423 5,746 174 5,920 3/19/2016 29,899 1,226 37 2,053 501 2,200 404 26,004 18,339 2,375 20,714 5,290 423 5,713 174 5,887 3/26/2016 29,899 1,226 37 2,934 822 2,700 0 24,706 17,762 2,375 20,137 4,569 423 4,992 174 5,166 (1,843) 1. Available OPCAP MW based on resource Capacity Supply Obligations, CSO. Does not include Settlement Only Generators. 2. External Node Available Capacity MW based on the sum of external Capacity Supply Obligations (CSO) imports and exports. 3. New resources and generator improvements that have acquired a CSO but have not become commercial. 4.Non-Gas Planned Outages is the total of Non Gas-fired Generator/DARD Outages for the period. This value would also include any known long-term Non Gas-fired Forced Outages. 5. All Planned Gas-fired generation outage for the period. This value would also include any known long-term Gas-fired Forced Outages. 6. Allowance for Unplanned Outages includes forced outages and maintenance outages scheduled less than 14 days in advance per ISO New England Operating Procedure No. 5 Appendix A. 7. Generation at Risk due to Gas Supply pertains to gas fired capacity expected to be at risk during cold weather conditions or gas pipeline maintenance outages. 8. Net OpCap Supply MW Available (1 + 2 + 3 - 4 - 5 - 6 - 7 = 8) 9. Peak Load Forecast as provided in the 2015 CELT Report and adjusted for Passive Demand Resources. http:/ / www.iso-ne.com/ system-planning/ system-plans-studies/ celt 10. Operating Reserve Requirement based on 125% of first largest contingency plus 50% of the second largest contingency. 11. Total Net Load Obligation per the formula(9 + 10 = 11) 12. Net OPCAP Margin MW = Net Op Cap Supply MW minus Net Load Obligation (8 - 11 = 12) 13. OP 4 Action 2 Real-time Demand Response based on OP4 Appendix A. Reserve Margins and Distribution Loss Factor Gross Ups are Included. 14. OPCAP Margin taking into account Real Time Demand Response through OP4 Step 2 (12 + 13 = 14) 15. OP 4 Action 6 Emergency Generation Response without the Voltage Reduction requiring > 10 Minutes based on OP4 Appendix A. Real Time Emergency Generation is capped at 600MW. Reserve Margins and Distribution Loss Factor Gross Ups are Included. 16. OPCAP Margin taking into account Real Time Demand Response and Real Time Emergency Generation through OP4 Step 6 (14 + 15 = 16) This does not include Emergency Energy Transactions (EETs).
ISO-NE PUBLIC 124 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Winter 2015/16 Operable Capacity Analysis (MW) 90/10 Forecast (Extreme)
ISO-NE 2015-16 OPERABLE CAPACITY ANALYSIS CSO 50/50 RWT_COO_AMS 9/18/15 9:45 CSO _OCT_2015_100 90/10 October 2, 2015 - 90/10 FORECAST using CSO values with RTDR and RTEG SCC 90/10 This analysis is a tabulation of weekly assessments shown in one single table. The information shows the operable capacity situation under assumed conditions for each week. It is not expected that the system peak will occur every week during June, July, and August and M id September.
GAS OPCAP NON-GAS GENERAT ALLOWANCE OPER OPCAP FROM MARGIN w/ OPCAP FROM OPCAP MARGIN EXTERNAL NON PLANNED OR FOR PEAK LOAD RESERVE OPCAP OP4 ACTIVE OP4 actions OP4 REAL- w/ OP4 actions STUDY WEEK AVAILABLE NODE AVAIL COMMERCIAL OUTAGES CSO OUTAGES UNPLANNED GAS AT NET OPCAP FORECAST REQUIREMENT NET LOAD MARGIN REAL-TIME DR through OP4 TIME EMER. through OP4 Step (Week Beginning, OPCAP MW CAPACITY MW CAPACITY MW MW CSO MW OUTAGES MW RISK MW SUPPLY MW MW MW OBLIGATION MW MW MW Step 2 MW GEN MW 6 MW Saturday) [1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14] [15] [16] 12/5/2015 29,899 1,226 30 1,471 1,209 3,200 1,755 23,520 20,579 2,375 22,954 566 423 989 174 1,163 12/12/2015 29,899 1,226 30 809 900 3,200 2,435 23,811 20,883 2,375 23,258 553 423 976 174 1,150 12/19/2015 29,899 1,226 30 801 654 3,200 2,865 23,635 20,895 2,375 23,270 365 423 788 174 962 12/26/2015 29,899 1,226 35 694 161 3,200 3,729 23,376 20,960 2,375 23,335 41 423 464 174 638 1/2/2016 29,899 1,226 35 662 0 2,800 4,446 23,252 21,248 2,375 23,623 (371) 423 52 174 226 1/9/2016 29,899 1,226 35 662 0 2,800 4,631 23,067 21,737 2,375 24,112 (1,045) 423 (622) 174 (448) 1/16/2016 29,899 1,226 35 621 0 2,800 4,631 23,108 21,737 2,375 24,112 (1,004) 423 (581) 174 (407) 1/23/2016 29,899 1,226 35 587 0 2,800 4,631 23,142 21,737 2,375 24,112 (970) 423 (547) 174 (373) 1/30/2016 29,899 1,226 35 587 0 3,100 4,446 23,027 21,503 2,375 23,878 (851) 423 (428) 174 (254) 2/6/2016 29,899 1,226 35 631 0 3,100 4,075 23,354 21,222 2,375 23,597 (243) 423 180 174 354 2/13/2016 29,899 1,226 35 631 0 3,100 4,075 23,354 21,192 2,375 23,567 (213) 423 210 174 384 2/20/2016 29,899 1,226 35 327 0 3,100 3,519 24,214 20,916 2,375 23,291 923 423 1,346 174 1,520 2/27/2016 29,899 1,226 37 731 0 2,200 3,149 25,082 19,877 2,375 22,252 2,830 423 3,253 174 3,427 3/5/2016 29,899 1,226 37 761 1,156 2,200 1,252 25,793 19,509 2,375 21,884 3,909 423 4,332 174 4,506 3/12/2016 29,899 1,226 37 742 916 2,200 936 26,368 19,303 2,375 21,678 4,690 423 5,113 174 5,287 3/19/2016 29,899 1,226 37 2,053 501 2,200 1,166 25,242 18,920 2,375 21,295 3,947 423 4,370 174 4,544 3/26/2016 29,899 1,226 37 2,934 822 2,700 104 24,602 18,325 2,375 20,700 3,902 423 4,325 174 4,499 (4,223) 1. Available OPCAP MW based on resource Capacity Supply Obligations, CSO. Does not include Settlement Only Generators. 2. External Node Available Capacity MW based on the sum of external Capacity Supply Obligations (CSO) imports and exports. 3. New resources and generator improvements that have acquired a CSO but have not become commercial. 4. Non-Gas Planned Outages is the total of Non Gas-fired Generator/DARD Outages for the period. This value would also include any known long-term Non Gas-fired Forced Outages. 5. All Planned Gas-fired generation outage for the period. This value would also include any known long-term Gas-fired Forced Outages. 6. Allowance for Unplanned Outages includes forced outages and maintenance outages scheduled less than 14 days in advance per ISO New England Operating Procedure No. 5 Appendix A. 7. Generation at Risk due to Gas Supply pertains to gas fired capacity expected to be at risk during cold weather conditions or gas pipeline maintenance outages. 8. Net OpCap Supply MW Available (1 + 2 + 3 - 4 - 5 - 6 - 7 = 8) 9. Peak Load Forecast as provided in the 2015 CELT Report and adjusted for Passive Demand Resources. http:/ / www.iso-ne.com/ system-planning/ system-plans-studies/ celt 10. Operating Reserve Requirement based on 125% of first largest contingency plus 50% the second largest contingency. 11. Total Net Load Obligation per the formula(9 + 10 = 11) 12. Net OPCAP Margin MW = Net Op Cap Supply MW minus Net Load Obligation (8 - 11 = 12) 13. OP 4 Action 2 Real-time Demand Response based on OP4 Appendix A. Reserve Margins and Distribution Loss Factor Gross Ups are Included. 14. OPCAP Margin taking into account Real Time Demand Response through OP4 Step 2 (12 + 13 = 14) 15. OP 4 Action 6 Emergency Generation Response without the Voltage Reduction requiring > 10 Minutes based on OP4 Appendix A. Real Time Emergency Generation is capped at 600MW. Reserve Margins and Distribution Loss Factor Gross Ups are Included. 16. OPCAP Margin taking into account Real Time Demand Response and Real Time Emergency Generation through OP4 Step 6 (14 + 15 = 16) This does not include Emergency Energy Transactions (EETs).
ISO-NE PUBLIC 125 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4
OPERABLE CAPACITY ANALYSIS Appendix
ISO-NE PUBLIC 126 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Possible Relief Under OP4 based on OP4 Appendix A OP 4 Amount Assumed Action Page 1 of 2 Obtainable Under OP 4 Number Action Description (MW) 1 Implement Power Caution and advise Resources with a CSO to prepare to provide 0 1 capacity and notify “Settlement Only” generators with a CSO to monitor reserve pricing to meet those obligations. Begin to allow depletion of 30-minute reserve. 600 2 Dispatch real time Demand Resources. October 308 3 November 4433 December - March 4233 3 Voluntary Load Curtailment of Market Participants’ facilities. 40 2 4 Implement Power Watch 0 5 Schedule Emergency Energy Transactions and arrange to purchase Control Area-to- 1,000 Control Area Emergency 6 Voltage Reduction requiring > 10 minutes 135 4 Dispatch real time Emergency Generation October 156 3 November 1923 3 December - March 174
NOTES: 1. Based on Summer Ratings. Assumes 25% of total MW Settlement Only units <5 MW will be available and respond. 2. The actual load relief obtained is highly dependent on circumstances surrounding the appeals, including timing and the amount of advanced notice that can be given. 3. The RTDR and RTEG MW values are based on FCM results as of September 18, 2015. 4. The MW values are based on a 26,930 MW system load and the most recent voltage reduction test % achieved.
ISO-NE PUBLIC 127 NEPOOL PARTICIPANTS COMMITTEE 0CT 2, 2015 MEETING, AGENDA ITEM #4 Possible Relief Under OP4 based on OP4 Appendix A
OP 4 Action Page 2 of 2 Amount Assumed Obtainable Number Action Description Under OP 4 (MW) 7 Request generating resources not subject to a Capacity Supply Obligation to 0 voluntary provide energy for reliability purposes 8 Voltage Reduction requiring 10 minutes or less 269 4
9 Transmission Customer Generation Not Contractually Available to Market 5 Participants during a Capacity Deficiency.
Voluntary Load Curtailment by Large Industrial and Commercial Customers. 200 2
10 Radio and TV Appeals for Voluntary Load Curtailment Implement Power 200 2 Warning
11 Request State Governors to Reinforce Power Warning Appeals. 100 2
Total October 3,013 MW November 3,184 MW December - March 3,146 MW
NOTES: 1. Based on Summer Ratings. Assumes 25% of total MW Settlement Only units <5 MW will be available and respond. 2. The actual load relief obtained is highly dependent on circumstances surrounding the appeals, including timing and the amount of advanced notice that can be given. 3. The RTDR and RTEG MW values are based on FCM results as of September 18, 2015. 4. The MW values are based on a 26,930 MW system load and the most recent voltage reduction test % achieved. ISO-NE PUBLIC 128 OCT 2, 2015 MEETING, AGENDA ITEM #4A NEPOOL PC MEETING | OCTOBER 2, 2015
IMM Report on 2015 Q2 Market Performance
Report Highlights
Jeff McDonald, Ph.D. VICE PRESIDENT, MARKET MONITORING
ISO-NE PUBLIC OCT 2, 2015 MEETING, AGENDA ITEM #4A Total wholesale cost decreased
6 30
5 25
4 20
3 15 $/MMBtu
Costs (Billions of $) of (Billions Costs 2 10
1 5
- - Q1 2013 Q2 2013 Q3 2013 Q4 2013 Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015
Energy Capacity NCPC Ancillary Services Natural Gas
• Decrease in cost (compared to Q2 of prior years) due primarily to historically low natural gas price.
ISO-NE PUBLIC 2 OCT 2, 2015 MEETING, AGENDA ITEM #4A Price of natural gas during 2015Q2 was at historic low
• Algonquin price shown above. • Quarterly average natural gas price the lowest since March 2003.
ISO-NE PUBLIC 3 OCT 2, 2015 MEETING, AGENDA ITEM #4A Low price of natural gas resulted in significant decrease in energy price
Percent Percent Change Q2 Change Q2 Q2 2015 Q1 2015 Q2 2014 2015 to Q1 2015 to Q2 2015 2014 Real-Time Load (GWh) 29,074 33,614 -14% 29,315 -1%
Weather Normalized Real-Time Load (GWh) 29,145 32,440 -10% 29,571 -1%
Peak Real-Time Load (MW) 20,895 20,583 2% 21,263 -2%
Average Day-Ahead Hub LMP ($/MWh) $24.84 $84.84 -71% $39.92 -38%
Average Real-Time Hub LMP ($/MWh) $23.89 $81.97 -71% $38.16 -37%
Average Natural Gas Price ($/MMBtu) $2.23 $11.37 -80% $4.22 -47%
ISO-NE PUBLIC 4 OCT 2, 2015 MEETING, AGENDA ITEM #4A Uplift payments increased considerably compared to 2014 Q2
Q2 2015 Q1 2015 Q2 2014 Economic (i.e., First Contingency) Payments $13,409,171 $27,170,420 $8,725,181 Second Contingency Payments $12,811,332 $6,300,736 $5,189,803 Voltage Payments $256,094 $2,580,235 $2,422,387 Distribution Payments $17,879 $22,317 $459,252 Total $26,494,476 $36,073,708 $16,796,623
• Both First Contingency and Local Second Contingency payments increased significantly compared to the same quarter in 2014 • The increase in Economic NCPC payments compared to Q2 2014 was due to lower real-time prices and posturing of limited energy generating resources. • The increase in Local Second Contingency Protection NCPC payments was attributable to an increase in payments to units providing local reliability protection in the NEMA Boston load zone.
ISO-NE PUBLIC 5 OCT 2, 2015 MEETING, AGENDA ITEM #4A Forward Reserve Market Auction for Summer 2015
Auction Clearing Price for TMNSR and TMOR ($/MW-month) Summer Winter Summer Location Product 2014 2014/2015 2015 CT TMOR 12,709 8,990 5,834 NEMA/Boston TMOR 12,709 8,990 14,000 SWCT TMOR 12,709 8,990 5,834 Systemwide TMNSR 12,709 8,990 5,834 Systemwide TMOR 12,709 8,990 5,834
• Supply was structurally competitive (based on the RSI) except for TMOR in the SW Connecticut and NEMA/Boston zones. • The amount of supply offered to meet the TMOR requirement in NEMA/Boston was insufficient which resulted in the zone pricing at the cap price. • The Winter 2015/2016 auction cleared at $5,434/MW-month across all products and zones.
ISO-NE PUBLIC 6 OCT 2, 2015 MEETING, AGENDA ITEM #4A Analysis of Structural Competitiveness in the FRM Auction Offer RSI in the FRM for TMNSR (system-wide) and TMOR (zones)
Procurement Offer RSI TMNSR Offer RSI TMOR Offer RSI TMOR Offer RSI TMOR Offer RSI TMOR Period (System-wide) (ROS) (SWCT) (CT) (NEMA)
Summer 2012 241 189 N/A 114 N/A Winter 2012-13 193 132 244 134 N/A
Summer 2013 94 138 N/A 99 N/A Winter 2013-14 89 136 58 123 N/A Summer 2014 96 124 85 87 N/A
Winter 2014-15 107 186 84 215 N/A
Summer 2015 117 158 69 122 12
Winter 2014-15 109 154 283 382 N/A
• Evaluation of structural competitiveness in the Forward Reserve Market indicates 5 of the last 8 auctions were not, in some products and zones, structurally competitive (RSI < 100 noted in red). • Further analysis of offers and resulting market prices is currently underway.
ISO-NE PUBLIC 7 OCT 2, 2015 MEETING, AGENDA ITEM #4A Recommendations
• Develop an automated framework to address the conflict between energy market power mitigation and the requirement for FRM resources to observe the threshold price. – Temporary manual process is currently in place.
• Address the exercise of market power through premature retirement in the FCM. – This effort is currently underway.
• Account for corporate affiliations in structural competitiveness tests. – The new Pivotal Supplier Test for FCM will incorporate such relationships. – Other similar tests relying on portfolio structure should also include the affiliation relationship.
ISO-NE PUBLIC 8 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5 MEMORANDUM
TO: NEPOOL Participants Committee Members and Alternates
FROM: Paul Belval, NEPOOL Counsel
DATE: September 25, 2015
RE: ISO New England Inc. (“ISO”) 2016 Operating and Capital Budgets New England States Committee on Electricity (“NESCOE”) 2016 Budget
At its October 2, 2015 meeting, the NEPOOL Participants Committee (the “NPC”) will be asked to vote on the ISO’s proposed 2016 operating and capital budgets (collectively, the “ISO Budgets”) and on NESCOE’s 2016 operating budget (the “NESCOE Budget”). We have included with this memorandum background materials regarding these Budgets.
The ISO 2016 Budgets
The ISO Budgets were prepared according to the processes included in the Participants Agreement and in the Settlement Agreement with state agencies in FERC Dockets Nos. ER13-185 and ER13-192. The ISO presented its preliminary budgets at the NECPUC conference in June. The ISO next presented the ISO Budgets to the NEPOOL Budget & Finance Subcommittee (the “Subcommittee”) at its August 26 meeting. The ISO then presented those ISO Budgets to New England state agencies and attorneys general on August 27. Mr. Ludlow also provided an overview of the ISO Budgets at the September 11 NPC meeting and offered to answer any questions that NPC members may have on the ISO Budgets. On September 9, certain New England state regulators and consumer advocates provided questions on the ISO Budgets, which the ISO answered on September 17.
The following documents relating to the ISO Budgets are included with this material: • A summary presentation of the ISO Budgets; • The questions provided to the ISO by certain state agencies and the ISO’s responses to those questions;1 and • The ISO’s September 23 memo regarding the allocation of its projected costs among the ISO Tariff Schedules.
The updated version of the detailed presentation on the ISO Budgets that was provided to the Subcommittee is available at this link: http://www.iso-ne.com/event-details?eventId=126010.
According to the ISO, the updates from materials previously reviewed with the Subcommittee that are reflected in the revised presentation included with this transmittal memorandum affected the
1 The questions and responses are also posted on the ISO website at the following link: http://www.iso-ne.com/event-details?eventId=126010
92173362.2 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5 following slides: 5, 6, 11,14, 19, 20, 21, 22, 25, 37, 51, 60, 63, 64,65, 113 and 115. The updates to the ISO’s operating budget result in an overall net decrease in the budget of $125,000, all of which is attributable to finalizing the negotiations for medical, life and disability insurance premiums, which are lower than the amounts estimated in the original budget. In addition, the ISO Board approved a 2.75% merit increase in compensation (rather than the 3% in the original budget) and a 0.75% promotional increase in compensation (rather than the 0.5% promotional increase in the original budget), which has no net effect on the operating budget. The 2016 operating budget reflects a 3.8 percent increase over the 2015 operating budget. After accounting for the true-up mechanism in the ISO Tariff, the revenue requirement to fund the 2016 operating budget (i.e., the amount collected under the ISO administrative cost tariff) will increase by 9.6 percent over the amount collected in 2015 (due largely to the fact that 2015 collections included a significant true-up reduction).
The budgets included with this memorandum also reflect some minor changes to the ISO’s 2016 capital budget from the draft reviewed with the Subcommittee. Specifically, two new capital projects were added: Power System Modeling Management Initiatives and NX9/NX12D- Generator Voltage Data. Both projects were chartered in August after the budget presentation to the Subcommittee was prepared. There was also a minor reallocation of costs from 2015 to 2016 for Wind Integration Phase II/ Do Not Exceed Dispatch and Zonal Load Forecast projects. The funding for these projects will result in a decrease in the Other Emerging Work capital budget item. This resulted in changes to slides 88 and 89 and new slides 94 and 95 in the presentation. Also, as a result of the addition of the two new slides, the original slide numbers after slide 95 have changed.
The following form of resolution can be used by the NPC on this matter:
RESOLVED, that the Participants Committee supports the Year 2016 operating budget and capital budget proposed by the ISO, as presented at this meeting.
The NESCOE 2016 Budget
Ms. Heather Hunt, the Executive Director of NESCOE, joined the Subcommittee’s August 26 meeting and informed the Subcommittee that NESCOE expected the NESCOE Budget for 2016 to be approximately $2,200,259, slightly less than the $2,317,455 included in the five-year pro forma projections provided to the NPC in March 2012 and accepted by the FERC. That fact was reported at the last NPC meeting as well. A summary presentation regarding the NESCOE Budget is also included with this memorandum.
The following form of resolution can be used by the NPC in its consideration of the proposed 2016 NESCOE Budget:
RESOLVED, that the Participants Committee supports the 2016 NESCOE budget, as proposed by NESCOE at this meeting, as the Year 2016 operating budget for NESCOE. cc: R. Ludlow C. Arnold H. Hunt NEPOOL Budget & Finance Subcommittee
-2-
92173362.2 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a OCTOBER 2, 2015
ISO New England Proposed 2016 Operating and Capital Budgets
NEPOOL Participants Committee Meeting
Robert Ludlow VP, CHIEF FINANCIAL & COMPLIANCE OFFICER
ISO-NE PUBLIC NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a
INTRODUCTION AND OVERVIEW
ISOISO--NE PUBLIC 2 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a 2016 Budget Review Process • At both the June 7, 2015 meeting with the New England Conference of Public Utilities Commissioners (NECPUC), and the June 22, 2015 NEPOOL Summer Meeting, management presented and reviewed the preliminary operating and capital budgets for 2016. • The proposed budget in this presentation is in line, overall, with the services and funding included in the preliminary budget presented in June. • The ISO reviewed the 2016 proposed Operating and Capital Budgets: – With the NEPOOL Budget & Finance Sub-committee on August 26th. – With the State Agencies on August 27th. • State Agencies’ submitted questions on ISO-NE’s proposed budget on September 9th. • ISO-NE responded to the State Agencies’ questions on September 17th. • State Agencies’ may submit comments regarding any proposed adjustments to the proposed budget by September 28th. • ISO-NE responses to State Agencies‘ comments and proposed adjustments are due on or about October 8th.
ISOISO--NE PUBLIC 3 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a 2016 Budget Review Process (cont.) • For further detail on ISO-NE’s 2016 budget, please see the presentation provided to the NEPOOL Budget and Finance Subcommittee at the August 26, 2015 meeting, which was updated on September 23, 2015. These presentations can be found at http://www.iso- ne.com/committees/participants/budget-finance and filtering by the 8/26/2015 Meeting Date. The September 23 update was for: • Employee benefit costs which were reduced by a net $125,000 including an actual medical benefits increase of 3% compared to the planned increase of 6%, which was partially offset by higher than planned cost for the renewal of Life and Disability Insurance. • The ISO-NE Board approval of 2016 Merit and Promotion increases of 2.75% and 0.75%, respectively, compared to the presented 3.0% and 0.5%. This change resulted in no overall impact to the budget, only a movement in the budgeted pools. • The 2016 Capital Budget, which had no overall change from $27.0 million was updated to include two newly chartered projects, Power System Modeling Management Initiatives and NX9/NX12D – Generator Voltage Data, which have budgeted costs in 2016. Changes were also made to amounts between years for Wind Integration Phase II/Do Not Exceed Dispatch and the Zonal Load Forecast projects with the balance of the above noted adjustments coming from Other Emerging Work. • ISO-NE Board of Directors will vote on the Budgets subsequent to today’s meeting. • ISO-NE will file 2016 Budgets with FERC on or about October 16th. ISOISO--NE PUBLIC 4
NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a Overview of 2016 Operating Budget
• The 2016 budget includes funding to execute on prior decisions/orders: – Our focus will be the execution of decisions already made to support existing services (i.e., increasing Cyber Security threats, Market Monitoring workload driven by the Forward Capacity Market (FCM) and the enhancement of data gathering, analysis tools and capabilities, and other FCM Reforms and changes). • The 2016 operating budget includes adjustments to the previous year’s budget as follows: – Cost reductions from previous year’s budget (e.g., one time studies, non- recurring costs, other efficiencies). – Increases to fund committed costs (e.g., Cyber Security Costs, Market Monitoring, Computer Services, Forward Capacity Market Reforms, Medical and Defined Contribution plans and benefit costs, and NERC/NPCC Fees). – Reallocation of resources for 2016 priorities and work and other miscellaneous increases. – Costs of maintaining competitive compensation. • Proposed budget includes a 2.75% merit increase, with 0.75% for equity and promotional increases.
ISOISO--NE PUBLIC 5
NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a Overview of 2016 Operating Budget (cont.)
• The proposed operating budget, including depreciation, excluding the true-up for past years, represents an increase of 3.8% (or $6.8 million) over the 2015 budget. • The final 2016 Operating and Capital budgets, including resourcing, will reflect the results of the ongoing priorities and work plan discussions with stakeholders. • In total the 2016 estimated revenue requirement is a 9.6% increase over 2015, of which 5.7% is attributed to the year- over-year change in the true-up. – The 2014 revenue requirement true-up, included in the 2016 revenue requirement, is a reduction of $0.6M as compared to the 2013 true-up, included in the 2015 revenue requirement, which was a reduction of $9.8M.
ISOISO--NE PUBLIC 6 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a Future Operating Budgets, Initiatives, and Risks
• In developing the 2016 budgets, management contained costs and kept the budget increase to a minimum and in line with the preliminary budget presented in June. This was accomplished through: – a level funding approach to the Defined Benefit Pension Plan. – A reduction in our reliance on contractors and consultants; absorbing more of the work previously performed by vendors. – Reallocating resources to new initiatives in the Energy Management System, System Operations, and Market Operations areas.
ISOISO--NE PUBLIC 7 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a
Future Operating Budgets, Initiatives, and Risks (cont.)
• Looking to 2017 and beyond the potential for material risks and increased resource requirements is driven by continued Cyber Security threats, FERC Order 1000, and wholesale electric market enhancements.
• Management realizes the need to balance regulatory requirements, stakeholder needs, and being pro-active in addressing cyber security threats while limiting budget increases to what is necessary. Accordingly, management has: – Focused on how best to reallocate resources to emerging priorities and to drive additional efficiency in the organization. – Prioritized competing proposals for market enhancements and the on- going resource commitment these often require once in place.
ISOISO--NE PUBLIC 8 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a
SUMMARY BUDGET INFORMATION
ISOISO--NE PUBLIC 9 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a Summary Budget Information % % % % % (Budget Amounts are in Millions) 2016 Change 2015 Change 2014 Change 2013 Change 2012 Change 2011
Operating Budget Before Depreciation $152.2 3.8% $146.6 4.0% $140.9 4.0% $135.5 9.4% $123.9 5.4% $117.5
Capital Budget (1) 27.0 (3.6%) 28.0 0.0% 28.0 (4.4%) 29.3 4.6% 28.0 5.7% 26.5
Total Cash Budget $179.2 2.6% $174.6 3.4% $168.9 2.5% $164.8 8.5% $151.9 5.5% $144.0
Operating Budget Before Depreciation $152.2 3.8% $146.6 4.0% $140.9 4.0% $135.5 9.4% $123.9 5.4% $117.5
Depreciation 33.0 3.9% 31.7 11.6% 28.4 (0.4%) 28.5 5.2% 27.1 4.6% 25.9
Revenue Requirement Before True-up 185.2 3.8% 178.3 5.3% 169.3 3.2% 164.0 8.6% 151.0 5.3% 143.4
True up (0.6) (9.8) 1.9 0.9 (7.4) (9.7)
Revenue Requirement $184.6 9.6% $168.5 (1.6%) $171.2 3.8% $164.9 14.8% $143.6 7.4% $133.7
Forecast – GWhs (2) 139.6 (0.6%) 140.4 1.1% 138.9 0.0% 138.9 0.7% 138.0 4.2% 132.4
$/KWh Rate $0.00132 10.2% $0.00120 (2.5%) $0.00123 3.6% $0.00119 14.4% $0.00104 3.0% $0.00101
Average Monthly Consumer Cost (3) $0.99 $0.90 $0.92 $0.89 $0.78 $0.76
(1) 2014 Capital Budget includes the Backup Control Center (BCC) Data Center Transition Project; however, it excludes the BCC Project, which is funded by tax-exempt bonds (2) 2016 Forecast based on May 2015 CELT Report. All other years based on CELT Report for the applicable year, which can be found on www.iso-ne.com. (3) Based on average consumption of 750 kWh per month.
ISO-NE PUBLIC 10 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a New England Wholesale Electricity Costs(a)
2008 2009 2010 2011 2012 2013 2014
$ Mil. ¢/kWh $ Mil. ¢/kWh $ Mil. ¢/kWh $ Mil. ¢/kWh $ Mil. ¢/kWh $ Mil. ¢/kWh $ Mil. ¢/kWh Wholesale market costs Energy (LMPs)(b) $12,085 9.1 $5,884 4.6 $7,284 5.6 $6,695 4.9 $5,193 3.9 $8,009 6.0 $9,079 6.9
Ancillaries(c) $366 0.3 $190 0.1 $164 0.1 $39 0.0 $56 0.0 $155 0.1 $330 0.3
Capacity(d) $1,505 1.1 $1,768 1.4 $1,647 1.3 $1,345 1.0 $1,195 0.9 $1,057 0.8 $1,063 0.8
Subtotal $13,956 10.5 $7,842 6.1 $9,095 7.0 $8,079 5.9 $6,444 4.8 $9,220 6.9 $10,472 8.0 Transmission $869 0.7 $1,155 0.9 $1,417 1.1 $1,378 1.0 $1,532 1.1 $1,806 1.3 $1,815 1.4 charges(e) RTO costs(f) $124 0.1 $116 0.1 $145 0.1 $130 0.1 $139 0.1 $167 0.1 $165 0.1
Total $14,949 11.3 $9,113 7.1 $10,657 8.2 $9,588 7.0 $8,115 6.0 $11,193 8.3 $12,452 9.5
(a) Average annual costs are based on the 12 months beginning January 1 and ending December 31. Costs in millions = the dollar value of the costs to New England wholesale market load servers for ISO-administered services. Cents/kWh = the value derived by dividing the dollar value (indicated above) by the real-time load obligation. These values are presented for illustrative purposes only. (b) Energy values are derived from wholesale market pricing. (c) Ancillaries include first- and second-contingency Net Commitment-Period Compensation (NCPC), forward reserves, real-time reserves, regulation service, and a reduction for the Marginal Loss Revenue Fund. (d) Capacity charges are those associated with the Forward Capacity Market. (e) Transmission charges reflect the collection for transmission owners’ revenue requirements and tariff-based reliability services, including black-start capability and voltage support. In 2014, the cost of payments made to these generators for reliability services under the ISO’s tariff was $41.8 million. (f) RTO costs are the costs to run and operate ISO New England Inc. and are based on actual collections as determined under Section IV of the ISO New England Inc. Transmission, Markets, and Services Tariff.
ISO-NE PUBLIC 11 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a Snapshot of New England Retail Electricity Rates Average retail price of electricity to residential customers January 2013, January 2014 and January 2015
State January 2013 January 2014 January 2015 (cents/kWh) (cents/kWh) (cents/kWh)
Connecticut 17.05 18.29 21.00
Maine 14.49 14.45 15.62
Massachusetts 14.28 16.83 20.80
New Hampshire 16.01 16.54 19.15
Rhode Island 14.80 17.56* 17.72
Vermont 16.50 16.94 16.48
Source: U.S. Energy Information Administration (EIA) Electric Power Monthly * The January 2014 monthly average retail price of electricity for Rhode Island was replaced with the 2014 annual average due to a discrepancy in the January 2014 monthly average reported by EIA.
ISO-NE PUBLIC 12 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a 2016 Budget Components (cont.)
Note: Items in yellow above represent the estimate that was included in the 2016 Preliminary budget presented in June 2015.
ISO-NE PUBLIC 13 * NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a
CAPITAL BUDGET
ISO-NE PUBLIC 14 NEPOOL PARTICIPANTS COMMITTEE Capital Budget OCT 2, 2015 MEETING, AGENDA ITEM #5.a 2016 Expenditures
Major Projects In Development:
Wind Integration Phase II / Do Not Exceed (DNE) Dispatch $2.5M Forward Capacity Auction (FCA) 10 $0.6M Divisional Accounting $0.5M Zonal Load Forecast $0.2M Power System Modeling Management Initiatives $0.1M NX9/NX12D – Generator Voltage Data $0.1M In Planning/Conceptual Design Forward Capacity Auction (FCA) 11 $3.0M Sub-hourly Settlements $2.5M Fast Start Pricing $2.5M Submission of Financial Transmission Rights (FTR) for Clearing $1.8M 2016 Issues Resolution Project $1.5M Expand Energy Offers for Pumps $0.9M Quarterly Release Projects 2016 $0.8M Asset Characteristic Database & User Interface Re-Design $0.7M Continued Next Page
ISO-NE PUBLIC 15 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a Capital Budget 2016 Expenditures (cont.)
In Planning/Conceptual Design (Continued): Energy Management Platform Customs Elimination $0.6M Operations Document Management System $0.6M Transmart Rewrite $0.5M Web Enhancements 2016 $0.5M Asset Registration Automation $0.5M Dynamic Interchange Adjustment Tool $0.3M Oracle 12c Upgrade $0.1M Case Snapshot Enhancements for Market Operator Interface $0.1M Price Responsive Demand $0.1M Non-Project Capital Expenditures $3.7M Other Emerging Work $1.8M Capital Interest $0.5M Total 2016 Capital Budget $27.0M
ISO-NE PUBLIC 16 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a
ISO/RTO FINANCIAL COMPARISON
ISO-NE PUBLIC 17 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a Financial Results Summary
ISO/RTO Financial Summary - 2014 Actual Results Operating Expense and Capital Expenditures for Calendar Year 2014, and Outstanding Debt as of December 31, 2014 (1) (Amounts in Millions)
ISO-NE (2) NYISO CAISO IESO (3)(4) PJM MISO SPP ERCOT Operating Expense - 2014 $ 163.1 $ 174.3 $ 214.4 $ 165.9 $ 330.4 $ 310.3 $ 210.3 $ 178.8
Less: Amortization & Depreciation (25.8) (26.7) (39.7) (19.5) (57.1) (50.0) (51.0) (26.6)
Regulatory Fees (5.4) (12.3) - - (55.4) (41.0) (16.3) (14.4)
Grant Expenses - (3.8) ------
Net Operating Expense - 2014 $ 131.9 $ 131.6 $ 174.8 $ 146.4 $ 217.9 $ 219.3 $ 142.9 $ 137.8
Other Financial Data
Capital Expenditures for 2014 $ 33.5 $ 24.6 $ 26.0 $ 22.9 $ 31.1 $ 46.5 $ 23.6 $ 23.9
Outstanding Debt as of 12/31/2014 $ 115.4 $ 104.6 $ 201.6 $ 90.0 $ 47.8 $ 200.0 $ 272.3 $ 71.0
Actual full-time equivalent headcount as of 12/31/2014 567.5 533.0 587.0 457.5 671.0 838.0 572.0 682.0
(1) Applicable amounts were taken from each entity's 2014 audited financial statements (2) ISO-NE Amortization & Depreciation and Capital Expenditures are presented on a cash-flow basis (3) Amounts are in Canadian dollars (4) IESO excludes regional System Planning function and costs which were provided by Ontario Power Authority during 2014
ISO-NE PUBLIC 18 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a State Agencies' Questions regarding 2016 proposed ISO-NE Budget following the August 27, 2015 budget review meeting for 2016 (1) Please provide the latest copy of ISO-NE’s FERC Form 1. Hard copy sent via U.S. Mail.
(2) Please provide the most recent copy of ISO-NE's Form 990. Hard copy sent via U.S. Mail.
(3) Please fill in the numbers of FTEs for ISO Budgeted, actual and new FTE positions, by area:
Area 12/31/ 12/31/ 6/30/ 2015 2016 2016 new 2013 2014 2015 Budget Budget for FY162 Actual Actual Actual Approved Request1 Systems Ops 105.5 103.0 107.0 107.5 108.0 0.5 System Planning 62.0 62.0 62.5 66.0 66.0 Market Ops 80.0 80.0 80.0 81.0 81.0 Market Dev 20.0 22.0 21.0 22.0 22.0 Info Services 148.5 154.5 163.0 163.5 170.0 6.5 Program Mgt & 31.0 31.0 29.5 34.0 33.5 (0.5) Bus Architecture Mkt Monitoring 19.0 17.0 18.0 20.0 22.0 2.0 Legal Services 14.0 15.0 15.0 15.0 15.0 External Affairs & 17.0 18.0 17.0 18.0 18.0 Corp Comm Compliance, Risk 41.0 44.0 42.0 45.0 44.0 Mgmt., Finance, & Internal Audit Human Resources 13.0 12.0 12.0 14.0 14.0 CEO, COO & 5.0 5.0 5.0 5.0 5.0 support Building Services 4.0 4.0 4.0 4.0 5.0 Less: Vacancy N/A N/A N/A (18.0) (18.0) N/A Totals 560.0 567.5 576.0 577.0 585.5 8.5
a. For the "actual" columns, please provide the number of FTEs actually hired and working at ISO NE on the date, separated out by area. Done. b. For "budget approved" column, please provide the FTE levels approved for each area for that budget year. Done. c. For "New" columns, please provide the FTE positions sought to be fully funded above the fully funded FTE positions from the prior year for the specific budget
1 During 2015 a position was moved from Finance to Building Services, accounting for the reduction in the 2016 Budget (compared to 2015 Budget) for Compliance, Risk Mgt, Finance, & Internal Audit line and the corresponding increase in the Building Services line. 2 2016 requested headcount includes two employees going from part-time to full-time (one in System Operations and one in Information Services), while an employee in Program Management is going from full-time to part-time. Each of these changes is reflected as 0.5 FTE in the budget.
Page 1 of 9 ISO-NE PUBLIC NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a
year for each area. In other words, the total request less the assumed vacancy rate. Done.
(4) Please provide the actual vacancy rates from 2010-2015 and the vacancy rates used in your budgets from 2010-2016.
Note: For 2015, the Actual Average Vacancy % is year-to-date through August.
(5) From FY2013-FY2015, ISO-NE has added sixty and one-half (60.5) [actual number is 43.5] new, funded FTE positions in its budgets, and now seeks to add an additional 8.5 FTEs for FY2016. Please breakout and provide the salary and burden cost for 60.5 [43.5] FTE positions added in FY2013-FY2015 and the salary and burden cost for the additional 8.5 FTE positions proposed for FY2016.
Gross HC Gross HC Identified Gross Cost of Change New HC 2012 551.5 2013 577.5 26.0 $2,714,100 2014 585.5 8.0 $ 961,900 2015 595.0 9.5 $1,138,100 2013-15 43.5 2016 603.5 8.5 $1,060,000
(6) During the June 2015 NECPUC presentation, ISO-NE Management stated that ISO-NE would not seek to add additional FTE positions for its FY2017 budget. Does ISO-NE still agree to that commitment? That is our current intention, but it is subject to changes in workload brought about by regulatory and other exigent priorities.
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(7) Please explain in detail how many current employees' duties were eliminated and redirected to new tasks for purposes of the 2016 budget request (if any), and identify which area those positions were located within.
Within the 2016 proposed budget, approximately 8 FTEs were reallocated to new work, including 6 in Market Operations and 2 in System Planning. This was accomplished through a combination of efficiencies gained or the discontinuation of other work previously performed. Additionally, internal ISO employees will assume work previously performed by contractors, under both the operating and capital budgets, including Market Operations (operating and capital), Legal (operating), and System Planning (operating).
These amounts are included in the $3.8 million of Efficiencies, Reductions, and Other Non-Recurring costs included on page 22 of the 2016 Budget Presentation made at the August meetings with the NEPOOL Budget and Finance Subcommittee and New England State Agencies. These items helped contribute to containing costs in the 2016 budget.
(8) Please identify the number of FTE positions that are funded in the capital budget by area for FY2014 and FY2015 and as proposed for FY2016. Please also provide the actual number of employees funded in the capital budget employed as of 6/30 at the end of FY2014 and FY2015. A sample chart is: Area FY2014 FY2014 FY2015 FY2015 FY2016 budget 6/30/2014 budget 6/30/2015 budget actual actual Information 29.5 37.5 31.5 29.0 32.0 Services Program 15.5 14.0 16.5 16.0 16.0 Management Market - - - - 6.0 Operations Total 45.0 51.5 48.0 45.0 54.0
Please explain why these positions are funded as part of the capital budget rather than the operating budget.
ISO-NE funds and accounts for these positions under the capital budget based on its accounting policy. ISO-NE capitalizes internal software development costs as required by the Cost of Computer Service Software Development Topic of the FASB ASC and in conformity with accounting principles generally accepted in the United States of America.
It should be noted that no one employee’s actual or budgeted time or costs go entirely to capital. Hours worked and the related cost of an employee’s time worked is only
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allocated to capital when his or her work on a specific capital project falls under the ISO’s accounting policy for capitalizing internal labor and is based on timesheet coding that all ISO-NE employees are required to complete on a weekly basis. The above numbers represent the equivalent FTEs of all actual and budgeted employees’ time on internal capital development work.
In no case is the same cost for capitalized labor (actual or budgeted) applied to both operating and capital; it is one or the other.
(9) Please provide a brief written explanation of the differences between salaries, performance incentive bonuses, merit increases and promotional increases and identify where each category is reflected in the budget. Please also provide the ranges of percentage increases for performance incentive bonuses, merit increases and promotional increases awarded in FY2014 and FY2015 and proposed for the FY2016 budget.
All of these items are included in the Salaries line of the budget, with the exception of any salaries that have been budgeted as capital, which are included in the cost of the relevant capital project.
Salaries are the annualized compensation paid to employees on a biweekly basis. These increase by application of Merit Increases. Each year, ISO-NE budgets a pool of dollars for merit (performance-based) increases. Top performers receive a larger increase, while the bottom performers receive no increase. The entire program is limited by the budgeted pool, which was 3.0% of eligible employees’ base salaries in each of 2014 and 2015, and is budgeted at 2.75% for 2016.
The other means of increasing salaries is through Promotional Increases. These are paid when an employee is promoted or when the ISO makes a market adjustment. Again, each year ISO-NE establishes a pool of dollars for these increases, which constrains their use. In each of 2014 and 2015, 0.5% was budgeted for promotional increases. The 2016 budget includes 0.75% for promotional increases.
See the response to Question 11 regarding Performance Incentive Bonuses.
(10) Provide copies of the criteria and/or metrics used to determine eligibility for incentive compensation for both executives and nonexecutives.
The same criteria apply to both executives and non-executives with regard to the annual performance incentive. To be eligible, an employee must be hired prior to October 1 of the plan year and have an overall performance rating higher than “Clearly Below Expectations.” For example, an employee hired on or after October 1, 2015 will not be eligible for a 2015 Plan year incentive. Incentives are paid in March of the following year.
The specific formula for the Annual Performance Incentive is Corporate Score x Individual Performance Factor x Salary Percentage x Annual Base Salary = Award.
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Corporate Score means achievement level on the ISO New England Annual Corporate Scorecard, as determined by the Board of Directors. Individual Performance Factor is the factor within the range that corresponds to the employee's Annual Performance Appraisal Rating, as listed in Chart A. Salary Percentage is the percent associated with the employee’s group classification as listed in Chart B.
CHART A Annual Performance Appraisal Rating Individual Performance Factor Exceeds Expectations 101% - 120% Meets Expectations 71% - 100% Requires Some Improvement to Fully Meet 40% - 70% Expectations Clearly Below Expectations 0%
CHART B Employee Group Classification Salary Percentage COO & CEO 50% Vice Presidents 25% Exempt Employees: Grades E – J 16% Exempt Employees: Grades A – D 10% Non-Exempt Employees 6.5%
(11) For fiscal years 2014, 2015 and 2016, what percentage of full-time employees received: (a) 100% of their eligible performance incentive bonus? (b) 90% of their eligible performance incentive bonus? (c) 75% of their eligible performance incentive bonus? (d) 50% of their eligible performance incentive bonus? (e) 0% (none) of their eligible performance incentive bonus?
NOTE: Incentives for the fiscal year are paid in March of the following year. For example, the fiscal 2014 bonus was paid in March 2015, and the fiscal 2015 incentives will be calculated and paid in March 2016.
Percentage of employees Percentage of employees receiving this level for receiving this level for fiscal Percentage of fiscal 2013 2014 potential bonus: (Paid 2014) (Paid 2015) 100% or more 7.3% 7.3% 90%- 99% 18.8% 17.7% 75% -89% 69.3% 71.8% 50% - 74% 1.8% 2.8% 1% - 49% 0.4% 0.3% 0% 0.0%1 0.1%2 1 This figure excludes 4 employees managed out of the ISO due to poor performance. 2 This figure excludes 5 employees managed out of the ISO due to poor performance.
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(12) Provide the last three years of funding statements on the ISO-NE 401(k) plan. Please see the following links to ISO NE’s Annual Financial Reports, which contain the Audited Financial Statements, and refer to the specified footnotes for the ISO’s matching policy for the 401(k) plan and the annual matching contribution amounts made to fulfill the plan requirements.
2014 – Footnote 7 http://www.iso-ne.com/static- assets/documents/2015/04/2014_financial_statements.pdf 2013 –Footnote 6 http://www.iso-ne.com/static- assets/documents/aboutiso/fin/finstmnts/2013_financial_statements.pdf 2012 – Footnote 6 http://www.iso-ne.com/static- assets/documents/aboutiso/fin/finstmnts/2013_financial_statements.pdf
(13) Provide the latest three years of actuarial statements for all postretirement benefit plans offered by ISO–NE.
Please see the following links to ISO NE’s Annual Financial Reports, which contain the Audited Financial Statements, and refer to the specified footnotes for the ISO’s actuarial calculations and values for the Pension and Post Retirement Benefit plans. 2014 – Footnote 5 http://www.iso-ne.com/static- assets/documents/2015/04/2014_financial_statements.pdf 2013 –Footnote 5 http://www.iso-ne.com/static- assets/documents/aboutiso/fin/finstmnts/2013_financial_statements.pdf 2012 – Footnote 5 http://www.iso-ne.com/static- assets/documents/aboutiso/fin/finstmnts/2013_financial_statements.pdf
(14) Please provide the specific rate impacts from the proposed revenue requirements from the proposed 2016 budget, preferably in the form of a redline markup of the various tariffs. Revised rates will not be available until October.
(15) (13) From page 21 of proposed budget, please provide a breakdown of the $0.8 million expense between current medical expenses, retiree medical expenses, pension expense, and any other benefit expenses.
The amounts are as follows:
Medical and Dental: $0.5 million Retiree Medical: $0.2 million Pension: $0.1 million
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(16) (14) From page 25 of proposed budget, please provide an explanation and discussion on the $2.5 million interest expense together with detailed work papers showing its calculation.
Please see Footnote 4 of the ISO’s Audited Financial Statements (contained in the 2014 Annual Report found at http://www.iso-ne.com/static- assets/documents/2015/04/2014_financial_statements.pdf) for borrowing rate information, pricing schedules and applicable fees on each type of debt described below. Debt Type Interest Expense* Private Placement Notes $2,195,632 MA Tax Exempt Bonds 212,254 CT Tax Exempt Bonds 280,100 Working Capital Line 102,862 Financial Transmission Rights Line of Credit 243,065 Capitalized Interest (included in Capital Budget) (500,000)
Net Interest Expense $2,533,913
* Includes fees on loans and interest expense
(17) (15) From page 58 of proposed budget, please provide copies of all source materials on the “level funding approach” given to ISO-NE from its actuaries and investment consulting firm. These documents were prepared for our Board Audit and Finance Committee by our actuaries, Sibson Consulting. They were intended solely for Board deliberation and, in addition, are marked copyright protected by Sibson. While they cannot be shared, we can note that the materials covered accounting liability under ASC 715, the funding target under PPA, and the funding target under MAP-2/HAFTA. Funding scenarios were also considered (both deterministic and stochastic). With the benefit of this information, the Board Audit and Finance Committee adopted the level funding approach tied currently to $10 million per year. The Board, as plan fiduciary, believes that this approach will reduce funding volatility and ensure adequate plan funding.
(18) (16) From page 113 of proposed budget, please provide the inflation rate increase used in calculating this pro-forma budget and all source materials used in developing this rate.
2016 is based on the budget presented. The 2017 operating budget assumes a 4.0% inflationary rate, while the 2018 and 2019 operating budgets assume 3.0% inflation for each year.
(19) (17) Provide a worksheet explaining the difference between the actual 2014 capital expenditures of $27.2 million and the sum of the “Project-To-Date” cost of $8.518
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million and the “Current Year (2014) Cost to Complete“ cost of $6.033 million [See, page 113 of the Proposed Budget].
It appears the $8.518 million and $6.033 million amounts noted above are from page 113 of the 2015 Budget presented in August of 2014, and subsequently updated in September 2014. That slide is focused on spending in 2015, not 2014. Specifically, the slide was intended to show the specific projects and line items making up the $28.0 million proposed 2015 capital budget and the total estimated costs of these projects across all years during which spending was incurred or would be incurred. Accordingly, the slide shows that $8.518 million was spent through July 2014 on the listed projects, and $6.033 million was forecast to be spent through the remainder of 2014 on those projects. As noted on footnote (1), the 2014 number ($6.033) only related to projects that had budgeted costs in 2015 and beyond.
The $27.2 million actual capital spending in 2014, as seen on slide 87 of the 2016 budget presentation, reflects the total actual amount of capital spent in 2014. That includes the $6.033 million, but also includes money spent on projects that finished or were entirely contained within 2014. The details of the $27.2 million spending for 2014 can be found in the Fourth Quarter 2014 Capital Budget update filing made in February 2015 at http://www.iso-ne.com/static-assets/documents/2015/02/er15-___-000_2-12- 15_4th_qtr_cap_bdgt_rpt.pdf.
(20) (18) From pages 83-85 of proposed budget, the actual depreciation expenses for 2012 to 2014, and highly probable for 2015, were significantly less than the budgeted amounts. Please explain why ISO-NE is proposing depreciation expense of $33 million for the 2016, which is approximately $7.5 million higher than the average of the actual amounts for 2012 to 2014, despite a proposed decrease in 2016 capital budget and previous actual capital expenditures being less than projected amounts.
ISO-NE builds its depreciation expense budget based on the assets that are currently in- service and those that are projected in the upcoming year’s Capital Budget using the projected implementation dates expected for those projects. For any capital expenditures that do not have an established in-service date, we use a half-year convention method and assume a half year’s depreciation on those capital expenditures.
We believe that this methodology is reasonable, given that not all in-service dates are known at the time we prepare the budget (12 months in advance). However, this methodology may create significant variances in our budgeted depreciation expense given the timing as well as shifting priorities imposed by the Commission or other pressing needs. Moreover, projects often cross calendar years, resulting in the ISO spending funds on these projects that that will not begin to depreciate in the same year of the spending. Therefore, while the projected capital spending may be lower in 2016, there are a number of projects from previous years’ spending which we expect to go into service in 2016 and begin depreciating with minimal capital spend in 2016.
Last, we have no equity and rely on a very modest working capital line amount to fund timing differences of expenditures vs collections as well as to fund any under-collections
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in a given year. The ISO Tariff is designed such that any over-collection or underspending is fully refunded to market participants through the true-up mechanism.
(21) (19) With respect to slide 14, bottom four rows, please explain the factors that led to the 2011 to 2016 growth percentages, calculated as follows:
(a) 5.4% growth Forecast GWh: Load growth forecast comes from the annual CELT reports and is presumably accurate. (b) 38% growth ISO– NE Revenue Requirement. This number is accurate, but includes true-ups from prior years’ under- or over-collections. As a result, it can fluctuate considerably from year to year and the true-up portion is not reflective of the actual Revenue Requirement. The Revenue Requirement before true-up is a better measure. (c) 30% growth $/kWh. See below. (d) 30% growth Average Consumer Cost. The numbers in (c) and (d) are accurate insofar as they involve simple division of the ISO’s Revenue Requirement by load. If you disagree with the above calculations, please explain why and provide revised calculations. ISO-NE doesn’t disagree with the calculations. However, whether load grows or shrinks, the markets must be developed and administered, the transmission system planned and operated, and ISO-NE must respond to new challenges, like cyber security threats.
In fact, we expect load to decrease further in part due to state investments in distributed resources, demand response, and energy efficiency. The resulting hybrid grid, in which a growing percentage of resources are “behind the meter,” may actually increase the challenges of maintaining reliability and, consequently, our budget.
(22) (20) Do you agree ISO-NE revenue requirement has grown approximately 5X faster than energy levels since 2011 (long term trend)? Please explain. See above.
(23) (21) Please explain whether similar growth percentages for these factors were experienced by the other RTOs.
ISO-NE does not track this information, but does track actual spending by ISOs and RTOs. See Appendix 2 of the Budget Presentation.
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To: NEPOOL Budget & Finance Subcommittee and Participants Committee
From: Bob Ludlow and Cheryl Arnold
Date: September 23, 2015
Projected 2016 Revenue Requirement for ISO New England Administrative Cost Tariff Subject: Schedules
To help our Participants prepare their 2016 budgets and consistent with information provided in previous years, this memo includes a preliminary indication of ISO-NE’s 2016 costs and related tariff schedules. Specifically, the memo includes (1) the estimated 2016 Revenue Requirement, including the final true-up for 2014, and a comparison to the 2015 Revenue Requirement (see Exhibit 1 below), (2) the Draft 2016 Revenue Requirement by activity (see Exhibit 2), and (3) the Draft 2016 Rate Components (Exhibit 3). Both Exhibits 2 and 3 are attached and, in their final form, will be part of the ISO’s budget filing with the FERC. The cost assignment and allocation mechanisms that were utilized in the Draft 2016 tariff schedules were established as part of the settlement that has been in effect for the last fourteen years.
Overall Change in Revenue Requirement As shown in Exhibit 1 below, the overall Revenue Requirement has increased by $16.0 million year-over-year, from $168.5M for 2015 to $184.5M for 2016. The change includes a $6.8 million increase for the revenue requirement before taking into account the change in prior year true- ups. Prior year true-ups resulted in an increase of $9.2M. The 2015 tariff included a $9.8M revenue requirement decrease for the final 2013 true-up, while the 2016 tariff will include a decrease of $0.6M as a result of the final 2014 true-up.
Draft Exhibit 1 ISO New England Revenue Requirement By Tariff Schedule 2016 Estimated Amount vs. 2015 ACT Filed Amount
Sch 1 Sch 2 Sch 3 Total
2016 Revenue Requirement Before Prior Year True Ups $ 44,360,392 $ 84,722,023 $ 56,068,806 $ 185,151,221 2015 Revenue Requirement Before Prior Year True Ups 42,327,088 81,019,153 54,968,671 178,314,912
$ Increase/(Decrease) from 2015 to 2016 2,033,304 3,702,870 1,100,135 6,836,309 % Increase/(Decrease) from 2015 to 2016 4.8% 4.6% 2.0% 3.8%
2016 Revenue Requirement Prior Year True Ups-Under/(Over) Collect $ 1,688,404 $ (2,348,713) $ 38,565 $ (621,744) 2015 Revenue Requirement Prior Year True Ups-Under/(Over) Collect (4,386,346) (3,053,121) (2,338,408) (9,777,875)
$ Increase/(Decrease) from 2015 to 2016 6,074,750 704,408 2,376,973 9,156,131
2016 Revenue Requirement Including Prior Year True-Ups $ 46,048,796 $ 82,373,310 $ 56,107,371 $ 184,529,477 2015 Revenue Requirement Including Prior Year True-Ups 37,940,742 77,966,032 52,630,263 168,537,037
$ Increase/(Decrease) from 2015 to 2016 8,108,054 4,407,278 3,477,108 15,992,440 % Increase/(Decrease) from 2015 to 2016 21.4% 5.7% 6.6% 9.5%
ISO New England Inc. ISO-NE Public One Sullivan Road, Holyoke, MA 01040-2841 www.iso-ne.com T 413 535 4000 F 413 535 4024 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a Memo Regarding Proposed 2016 Revenue Requirement September 23, 2015 Page 2
Change in Revenue Requirement by Schedule Before true-ups in 2016 and 2015, the 2016 Revenue Requirement reflects an overall increase of $6.8M or 3.8% over the 2015 Revenue Requirement. By tariff schedule, the changes are: Schedule 1, a $2.0M or 4.8% increase; Schedule 2, a $3.7M or 4.6% increase; and Schedule 3, a $1.1M or 2.0% increase.
The Tariff Schedule 1 increase of $2.0M is attributable to: Funding for items that impact all three tariff schedules, including an increase for: Compensation (annual Merit and Promotion) and Benefits (Healthcare, Life & Disability Insurance, Defined Contribution Plan, and Post-retirement medical cost increases); Cyber Security Improvements; Computer Service Licensing and Maintenance; and Depreciation Expense for in service projects including Critical Infrastructure Protection v5 Compliance and Business Continuity Planning Phase III – Remote Desktop. Depreciation Expense for the Coordinated Transaction Scheduling project which is largely allocated to Schedule 1 and for Generation Control Application Production Part 1 which is allocated evenly between Schedules 1 and 2.
The Tariff Schedule 2 increase of $3.7M is attributable to: Funding for items that impact all three tariff schedules, as noted above in the explanation for Schedule 1. Funding for Market Monitoring including the enhancement of monitoring capabilities through improvements in processes, data gathering, and analysis for systems improvements. Depreciation Expense for the Business Continuity Planning Phase III – Markets Infrastructure project which is largely allocated to Schedule 2, the Generation Control Application Production Part 1 project, which is allocated evenly between Schedules 1 and 2, and the Wind Integration Phase II / Do Not Exceed (DNE) Dispatch project which is allocated evenly between Schedules 2 and 3.
The Tariff Schedule 3 increase of $1.1M includes: Funding for items that impact all three tariff schedules, as noted above in the explanation for Schedule 1. Funding for Forward Capacity Market (FCM) Reforms in Market Development, required updated calculations for Cost of New Entry in System Planning, and FCM review work in Market Operations. Schedule 3 also includes Market Monitoring FCM driven workload related to De-list reviews, non-price retirements, Pay for Performance, and an update to the Offer Review Trigger Price. Depreciation Expense for the Forward Capacity Auction 10 project and the Wind Integration Phase II / Do Not Exceed (DNE) Dispatch project which is allocated evenly between Schedules 2 and 3. The increase was lessened by an overall reduction in Depreciation Expense for Schedule 3 as a result of previously implemented projects becoming fully depreciated during 2016, including Synchrophasor Infrastructure and Data Utilization (SIDU), Energy Management System Upgrade and Enhancements, and Forward Capacity Market Enhancements 2012.
The ISO 2016 Revenue Requirement will be reviewed and voted on at the October 2, 2015 NPC meeting. Should you have any questions regarding the information provided in this memo, do not hesitate to contact us.
ISO New England Inc. ISO-NE Public One Sullivan Road, Holyoke, MA 01040-2841 www.iso-ne.com T 413 535 4000 F 413 535 4024 Exhibit 2 DRAFT NEPOOL PARTICIPANTS COMMITTEE Page 1 of 7 OCT 2, 2015 MEETING, AGENDA ITEM #5.a
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 307 Administration-CEO 2 12651 Indirect Administrative Support Total Dir Labor $ 8,127,546 $ 1,751,325 $ 4,206,094 $ 2,170,126 3 12652 NEPOOL Committee Support Total Dir Labor 14,971 3,226 7,748 3,997 4 12654 National Committee Support Total Dir Labor 10,926 2,354 5,654 2,917 5 12657 Indirect Administrative Support for BCC Total Dir Labor 981,729 211,543 508,056 262,130 6 Total 9,135,171 1,968,449 4,727,551 2,439,171 7 8 302 Finance 9 11601 Payroll Administration Total Dir Labor 366,853 79,050 189,850 97,953 10 11701 Accounts Payable Total Dir Labor 199,569 43,003 103,279 53,287 11 11702 Procurement Total Dir Labor 479,629 103,351 248,213 128,065 12 11901 Billing for Transmission and Energy Settlements Total Dir Labor 68,142 14,683 35,264 18,195 13 12001 Budgeting and Forecasting Total Dir Labor 498,264 107,366 257,857 133,041 14 12005 Credit Admininstration Total Dir Labor 333,866 71,941 172,779 89,145 15 12017 Forward Capacity Market (FCM) Reforms Alloc-Fixed 810,821 - - 810,821 16 12101 Ledger Closing, Financial Statements and Tax Reporting Total Dir Labor 589,983 127,130 305,323 157,531 17 12201 Treasury and Cash Management Total Dir Labor 2,539,144 547,135 1,314,035 677,974 18 92004 Depreciation Expense 2004 Assets Alloc-Fixed 43,160 8,988 22,535 11,637 19 92005 Depreciation Expense 2005 Assets Alloc-Fixed 802,617 169,813 417,365 215,439 20 92006 Depreciation Expense 2006 Assets Total Dir Labor 570,733 122,993 295,354 152,386 21 92007 Depreciation Expense 2007 Assets Total Dir Labor 162,196 34,953 83,937 43,306 22 92008 Depreciation Expense 2008 Assets Alloc-Fixed 15,026 6,888 5,368 2,770 23 92009 Depreciation Expense 2009 Assets Alloc-Fixed 11,454 5,155 4,155 2,144 24 92010 Depreciation Expense 2010 Assets Alloc-Fixed 103,190 24,473 51,323 27,395 25 92011 Depreciation Expense 2011 Assets Alloc-Fixed 619,573 151,324 216,674 251,575 26 92012 Depreciation Expense 2012 Assets Alloc-Fixed 2,372,346 573,449 878,234 920,664 27 92013 Depreciation Expense 2013 Assets Alloc-Fixed 8,434,369 1,703,917 3,679,657 3,050,794 28 92014 Depreciation Expense 2014 Assets Alloc-Fixed 8,246,713 2,117,577 2,905,411 3,223,724 29 92015 Depreciation Expense 2015 Assets Alloc-Fixed 10,260,470 3,506,762 4,551,536 2,202,173 30 92016 Depreciation Expense 2016 Assets Alloc-Fixed 1,240,806 233,257 565,856 441,693 31 99707 Amortization of Land Recovery Alloc-Fixed 54,396 10,516 19,353 24,527 32 99995 NPCC/NERC Dues Alloc-Fixed 5,892,615 - - 5,892,615 33 99996 Operating Contingency Total Dir Labor 700,000 150,836 362,258 186,906 34 99996 Operating Contingency Total Dir Labor 1,100,000 237,028 569,262 293,710 35 99998 Payroll & Other Accruals Total Dir Labor 10,864,472 2,341,079 5,622,484 2,900,909 36 Total 57,380,408 12,492,669 22,877,361 22,010,378 37 38 108 Building Services 39 12664 Building Maintenance Total Dir Labor 3,109,354 670,004 1,609,125 830,225 40 Total 3,109,354 670,004 1,609,125 830,225 41 42 310 Enterprise Risk Management 43 22701 Enterprise Risk Mgmnt - Admin Alloc-Fixed 2,282 760 760 762 44 22703 Bus Cont Pl Prog Admin & Support Alloc-Fixed 141,205 47,021 47,021 47,162 45 22704 Record Retention Services Alloc-Fixed 80,512 26,810 26,810 26,891 46 22705 Corporate Scorecard Alloc-Fixed 31,379 10,449 10,449 10,481 47 22706 Document Management Services Alloc-Fixed 109,826 43,930 32,948 32,948 48 22708 Adminstration Total Dir Labor 15,689 3,381 8,119 4,189 49 22709 Management Total Dir Labor 94,137 20,285 48,717 25,135 50 22710 Employee Development Total Dir Labor 15,689 3,381 8,119 4,189 51 22711 Forward Capacity Market (FCM) Cap Adjustments Total Dir Labor 21,509 4,635 11,131 5,743 52 22712 Risk Policy Assessments Total Dir Labor 15,689 3,381 8,119 4,189 53 22713 MEC/Financials Total Dir Labor 31,379 6,762 16,239 8,378 54 22714 Analysis Total Dir Labor 125,515 27,046 64,956 33,514 55 22716 Financial Assurance Management (FAM) Rebuild Total Dir Labor 109,826 23,665 56,836 29,325 56 22719 Human Performance Improvement Total Dir Labor 9,894 2,132 5,120 2,642 57 22720 Business Process Change Management Total Dir Labor 125,515 27,046 64,956 33,514 58 22721 Corp Strategic Risk Total Dir Labor 23,534 5,071 12,179 6,284 59 22725 OSHA procedures Total Dir Labor 15,689 3,381 8,119 4,189 60 22727 ERM Business Analysis Total Dir Labor 62,758 13,523 32,478 16,757 61 23003 Safety / Security / Facilities Total Dir Labor 78,447 16,904 40,597 20,946 62 23006 Business Continuity Planning Total Dir Labor 47,068 10,142 24,358 12,568 63 25006 Business Process Maintenance Alloc-Fixed 19,625 8,831 8,831 1,963 64 25011 Corrective Action/Preventive Action Alloc-Fixed 179,175 59,665 59,665 59,845 65 25014 EtQ Tools Dev & Support Total Dir Labor 106,530 22,955 55,131 28,444 66 25015 Coord Tariff Change Committee (TCC) Total Dir Labor 54,117 11,661 28,006 14,450 67 25017 Scorecard Operational Excellence Excercise -- I.3.9 Process Total Dir Labor 31,379 6,762 16,239 8,378 68 Total 1,548,371 409,579 695,906 442,885
ISO-NE Public Exhibit 2 DRAFT NEPOOL PARTICIPANTS COMMITTEE Page 2 of 7 OCT 2, 2015 MEETING, AGENDA ITEM #5.a
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 301 Human Resources 2 12661 Employee Affairs (Recreation Committee) Total Dir Labor 21,821 4,702 11,292 5,826 3 12701 Recruiting/Interviewing Total Dir Labor 553,457 119,259 286,420 147,778 4 12801 Employee Relations Total Dir Labor 8,943 1,927 4,628 2,388 5 12901 Benefit Administration Total Dir Labor 1,139,839 245,613 589,879 304,347 6 12951 Compensation Total Dir Labor 501,581 108,081 259,574 133,927 7 12961 HR - General Total Dir Labor 1,124,146 242,231 581,758 300,157 8 12962 HR - Training Total Dir Labor 1,049,652 226,179 543,206 280,266 9 13410 Power Training & Development Total Dir Labor 1,176,010 253,407 608,598 314,005 10 13411 Markets Training & Development Total Dir Labor 375,057 80,817 194,096 100,144 11 13412 People Training & Development Total Dir Labor 580,066 124,993 300,191 154,883 12 13413 Business Skills Trng & Dev Total Dir Labor 167,452 36,083 86,658 44,711 13 13414 Technology Trng & Development Total Dir Labor 812,849 175,153 420,658 217,038 14 Total 7,510,873 1,618,445 3,886,959 2,005,469 15 16 306 Legal Department 17 8301 Federal Regulatory Total Dir Labor 265,674 57,247 137,489 70,937 18 12426 Interconnection Agreements Alloc-Fixed 29,038 - 14,519 14,519 19 12502 Board of Directors Total Dir Labor 448,228 96,584 231,963 119,681 20 12504 ISO Tariff Litigation Total Dir Labor 72,595 15,643 37,569 19,384 21 12505 Administration of OATT (Open Access Transmission Tariff) Alloc-Fixed 339,894 339,894 - - 22 12508 Energy Markets / Complaints / Rule Changes Alloc-Fixed 58,076 - 58,076 - 23 12509 Market Monitoring and Sanctions Alloc-Fixed 87,114 - 43,557 43,557 24 12512 BSAI - General Corporate Total Dir Labor 80,002 17,239 41,402 21,361 25 12513 Miscellaneous Labor Matters Total Dir Labor 120,003 25,858 62,103 32,042 26 12514 NEPOOL Participants Committee Total Dir Labor 100,674 21,693 52,100 26,881 27 12517 Administrative and Clerical Support Total Dir Labor 450,091 96,986 232,927 120,178 28 12520 Market Monitoring Rules/Regulations Alloc-Fixed 290,381 - 116,152 174,229 29 12521 Billing Disputes Total Dir Labor 126,291 27,213 65,357 33,721 30 12523 NEPOOL Information Policy Total Dir Labor 36,298 7,821 18,784 9,692 31 12542 Transmission Upgrades CT Alloc-Fixed 29,992 - 20,994 8,998 32 12543 Independent Market Advisor Alloc-Fixed 900,000 - 630,000 270,000 33 12544 FERC Proceedings Total Dir Labor 209,877 45,224 108,614 56,039 34 12552 S&G - General Corporate Total Dir Labor 234,992 50,636 121,611 62,745 35 12559 General Corporate Total Dir Labor 901,039 194,156 466,298 240,585 36 12563 Regulatory Matters Total Dir Labor 49,992 10,772 25,872 13,348 37 12572 205 General Proceedings Total Dir Labor 29,992 6,463 15,521 8,008 38 12573 206 General Proceedings Total Dir Labor 29,992 6,463 15,521 8,008 39 12574 Market Rule 1 Proceedings Total Dir Labor 479,994 103,429 248,402 128,163 40 12587 Capacity Market Development Alloc-Fixed 509,797 - - 509,797 41 12588 Web Content Management Total Dir Labor 571,803 123,212 295,914 152,676 42 12594 Maine Transmission Siting Alloc-Fixed 35,005 - 24,504 10,502 43 12595 NEEWS Transmission Siting Alloc-Fixed 1,370 - 959 411 44 12609 FTR Clearing Alloc-Fixed 60,002 - 30,001 30,001 45 12663 Public Information Total Dir Labor 1,393,147 300,196 720,969 371,983 46 12669 Government Affairs Total Dir Labor 1,719,920 370,609 890,078 459,234 47 Total 9,661,273 1,917,340 4,727,255 3,016,678 48 49 305 Internal Audit 50 15001 Indirect Management Duties Total Dir Labor 126,067 27,165 65,241 33,661 51 15002 Personnel Management Total Dir Labor 19,659 4,236 10,174 5,249 52 15003 Budget & Forecasting Total Dir Labor 14,744 3,177 7,630 3,937 53 15004 Audit Follow-up Activities Total Dir Labor 68,805 14,826 35,607 18,371 54 15005 Audit & Finance Committee Total Dir Labor 62,564 13,481 32,378 16,705 55 15006 Internal Audit Business Process Update Total Dir Labor 5,898 1,271 3,052 1,575 56 15007 Annual Audit Work Plan Total Dir Labor 34,402 7,413 17,804 9,186 57 15008 Training Total Dir Labor 39,317 8,472 20,347 10,498 58 15020 Internal Audit - Finance Total Dir Labor 26,688 5,751 13,811 7,126 59 15021 Perfomance Measurements Total Dir Labor 24,573 5,295 12,717 6,561 60 15022 Vendor Contracts Total Dir Labor 9,829 2,118 5,087 2,624 61 15023 Wire Transfers Total Dir Labor 11,795 2,542 6,104 3,149 62 15031 Employee Expense Reporting Total Dir Labor 11,795 2,542 6,104 3,149 63 15040 Operations Total Dir Labor 98,293 21,180 50,868 26,245 64 15065 Wind Integration Project Alloc-Fixed 49,146 19,659 19,659 9,829 65 15085 Information Technology Total Dir Labor 336,697 72,552 174,245 89,901 66 15131 NAMS Support Total Dir Labor 4,915 1,059 2,543 1,312 67 15133 Satellite Reviews Total Dir Labor 70,704 15,235 36,590 18,879 68 15134 SCADA Operations Reviews Total Dir Labor 72,422 15,605 37,479 19,337 69 15161 External Audit- Pension Audit Total Dir Labor 62,251 13,414 32,215 16,621 70 15162 External Audit- Financial Audit Total Dir Labor 110,352 23,779 57,108 29,465 71 15166 External Audit -Pricing Module Certification Alloc-Fixed 25,168 - 25,168 - 72 15175 External Audit - Info Technology Total Dir Labor 15,488 3,337 8,015 4,135 73 15186 External Audit - SSAE 16 Direct Support Total Dir Labor 24,573 5,295 12,717 6,561 74 25702 External Audit - SSAE 16 Alloc-Fixed 458,064 - 458,064 - 75 28160 MS Universal Access Gateway Review Total Dir Labor 42,906 9,245 22,204 11,456 76 Total 1,827,115 298,649 1,172,931 355,535
ISO-NE Public Exhibit 2 DRAFT NEPOOL PARTICIPANTS COMMITTEE Page 3 of 7 OCT 2, 2015 MEETING, AGENDA ITEM #5.a
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 701 COO-Adm 2 19001 NEPOOL Committee Support Total OPS Labor 57,751 15,478 27,693 14,579 3 19002 Regional Committee Support Total OPS Labor 31,400 8,416 15,057 7,927 4 19003 National Committee Support Total OPS Labor 57,656 15,453 27,648 14,555 5 19005 Indirect Supervision/Clerical Support Total OPS Labor 1,284,522 344,271 615,973 324,278 6 19009 Renewable Resource Integration Alloc-Fixed 114,197 - - 114,197 7 Total 1,545,526 383,618 686,372 475,537 8 9 10 105 System Operations - Administration 11 14404 NEPOOL Committee Support SOA Labor 12,256 4,233 5,689 2,334 12 14405 Indirect Supervision/Clerical Support SOA Labor 350,021 120,897 162,480 66,644 13 14407 Regional Committee Support SOA Labor 12,256 4,233 5,689 2,334 14 14408 National Committee Support SOA Labor 39,692 13,710 18,425 7,557 15 Total 414,226 143,074 192,284 78,869 16 17 101 Operations 18 14001 Generation Dispatch Alloc-Fixed 3,880,735 - 3,259,817 620,918 19 14002 Transmission Operations Alloc-Fixed 3,326,344 2,661,075 166,317 498,952 20 14304 Advanced Scheduling and Forecasting Alloc-Fixed 1,669,702 83,485 1,319,065 267,152 21 14402 Operations Training Alloc-Fixed 1,139,161 455,665 455,665 227,832 22 14413 Operations Support Training & Development Alloc-Fixed 269,900 107,960 107,960 53,980 23 14564 Indirect Supervision/Clerical Support OPS Labor 1,387,703 387,955 768,284 231,464 24 14702 Procedure Documentation Alloc-Fixed 536,178 214,471 214,471 107,236 25 Total 12,209,722 3,910,611 6,291,578 2,007,533 26 27 702 Reliability and Operations Services 28 14703 NEPOOL Committee Support OS Labor 440,571 244,723 85,173 110,675 29 14706 Indirect Supervision/Clerical Support OS Labor 21,933 12,183 4,240 5,510 30 14711 ISO TMS Tariff - Section 2 - (OATT) and Agreements Support Alloc-Fixed 207,354 69,049 69,049 69,256 31 14715 Non DOE Funded/Unallowable Alloc-Fixed 216,552 - - 216,552 32 14813 ICP Policy/Pedure Alloc-Fixed 98,411 39,364 39,364 19,682 33 Total 984,821 365,320 197,826 421,675 34 35 703 Reliability and Operations Compliance 36 14801 Compliance Monitoring Alloc-Fixed 659,625 263,850 263,850 131,925 37 14803 Regional Committee Support OS Labor 18,140 9,070 - 9,070 38 14804 National Committee Support OS Labor 146,408 73,204 - 73,204 39 14806 Employee Development Alloc-Fixed 9,841 5,466 1,903 2,472 40 14808 Change Management Alloc-Fixed 49,205 22,142 4,921 22,142 41 14809 Tariff Compliance Alloc-Fixed 49,205 14,762 29,523 4,921 42 14810 NERC Self Certifications Alloc-Fixed 98,411 83,649 - 14,762 43 14812 NPCC MP Referral Alloc-Fixed 19,682 7,873 7,873 3,936 44 14814 Compliance Risk Assessment Total Dir Labor 19,682 4,242 10,186 5,255 45 14815 Identifications and Description of Internal Controls Total Dir Labor 196,822 42,415 101,855 52,551 46 Total 1,267,021 526,673 420,110 320,239 47 48 103 Operations Support Services 49 14301 Contract Administration and Scheduling Alloc-Fixed (60,000) (6,000) (42,000) (12,000) 50 14452 Regional Committee Support TSO Labor 9,665 3,129 4,621 1,915 51 14453 National Committee Support TSO Labor 127,286 41,208 60,853 25,224 52 14454 Indirect Supervision/Clerical Support TSO Labor 493,763 159,852 236,061 97,850 53 14462 General Systems Operations Support TSO Labor 134,044 43,396 64,085 26,564 54 14476 Process Automation for On-Call Support of Control Room Alloc-Fixed 270,626 270,626 - - 55 18361 Transmission Studies, Operations, OASIS Support Alloc-Fixed 2,400,403 1,920,323 120,020 360,060 56 18381 Transmission Outage Appl - Short Term Alloc-Fixed 1,082,505 866,004 54,125 162,376 57 18382 Trans Out Ap Lg Term Alloc-Fixed 1,089,030 - - 1,089,030 58 Total 5,547,323 3,298,538 497,765 1,751,020 59 60 System Operations Support 61 14469 C10/C30 Audits Alloc-Fixed 134,044 - 107,236 26,809 62 14470 Resource Performance Monitoring Alloc-Fixed 134,044 - 107,236 26,809 63 14750 NEPOOL Committee Support Alloc-Fixed 134,044 43,396 64,085 26,564 64 14751 Regional Committee Support Alloc-Fixed 12,560 4,066 6,005 2,489 65 14753 Indirect Supervision/Clerical Support Alloc-Fixed 134,044 43,396 64,085 26,564 66 14757 Winter Reliability Project Alloc-Fixed 224,962 - 44,992 179,969 67 Total 773,699 90,858 393,637 289,204 68 69 415 Market Operations - Adm 70 19101 NEPOOL Committee Support MOA Labor 33,475 - 23,433 10,043 71 19103 National Committee Support MOA Labor 14,021 - 9,815 4,206 72 19104 Indirect Supervision/Clerical Support MOA Labor 937,732 - 656,412 281,319 73 19105 Employee Development MOA Labor 6,471 - 4,530 1,941 74 19112 Settlements - Customer Service MOA Labor 18,003 - 12,602 5,401 75 19120 CEII Requests Total Dir Labor 25,885 5,578 13,396 6,911 76 Total 1,035,587 5,578 720,187 309,822
ISO-NE Public Exhibit 2 DRAFT NEPOOL PARTICIPANTS COMMITTEE Page 4 of 7 OCT 2, 2015 MEETING, AGENDA ITEM #5.a
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 404 Market Monitoring 2 16101 Market Power Monitoring and Mitigation Alloc-Fixed 3,591,744 - 2,514,220 1,077,523 3 16102 Regulatory Activities Alloc-Fixed 365,402 - 255,781 109,621 4 16111 Employee Development MMM Labor 254,824 - 178,377 76,447 5 16114 Maintenance / Troubleshooting Software MMM Labor 761 - 533 228 6 16115 Analysis & Internal Reports MMM Labor 232,458 - 162,720 69,737 7 16121 FCM Market Monitoring Alloc-Fixed 219,822 - - 219,822 8 Total 4,665,011 - 3,111,632 1,553,379 9 10 416 Market Operations 11 21901 Day Ahead Market Administration Alloc-Fixed 345,499 - 345,499 - 12 21902 Real Time Price Verification Alloc-Fixed 345,499 - 345,499 - 13 21904 NEPOOL Committee Support MA Labor 4,551 - 4,407 144 14 21907 Indirect Supervision/Clerical Support MA Labor 456,984 - 442,553 14,431 15 21908 Employee Development MA Labor 33,707 - 32,643 1,064 16 21913 Data Collection/Report Writing Alloc-Fixed 337,072 - 337,072 - 17 21915 FTR/Auction Administration Alloc-Fixed 303,365 - 303,365 - 18 21916 Forward Reserve Market - Administration Alloc-Fixed 33,707 - - 33,707 19 21917 Real Time Price Finalization Alloc-Fixed 176,963 - 176,963 - 20 21951 FCM Annual Reconfiguration Auction Administration Alloc-Fixed 33,707 - - 33,707 21 21953 FCM Monthly Administration Alloc-Fixed 176,963 - - 176,963 22 Total 2,248,016 - 1,988,000 260,016 23 24 401 Market Anaylsis & Settlements 25 1701 Billing Statements - Energy Alloc-Fixed 87,109 - 87,109 - 26 1702 Billing Statements - Transmission Alloc-Fixed 72,682 72,682 - - 27 1713 Billing Statements - ISO Tariff Total Dir Labor 23,955 5,162 12,397 6,396 28 1714 Billable Tariff Re-billings Alloc-Fixed 72,410 72,410 - - 29 2039 BITT and Business Tools Alloc-Fixed 2,178 327 1,307 544 30 2047 Score Card Alloc-Fixed 10,616 1,570 5,171 3,875 31 2048 FCM Alloc-Fixed 211,240 - - 211,240 32 2049 Product Testing Alloc-Fixed 21,777 - 17,422 4,355 33 2051 Legal Support Alloc-Fixed 23,138 - 11,569 11,569 34 2052 FERC Data Request Alloc-Fixed 544 - 272 272 35 2054 MAS - Markets Development Support Alloc-Fixed 2,994 - 1,497 1,497 36 2005 Customer Service STLM Labor 119,775 17,712 58,347 43,716 37 2007 Admin support - NEPOOL Committees STLM Labor 16,877 2,496 8,222 6,160 38 2008 Admin support (ISO) STLM Labor 77,966 11,530 37,980 28,456 39 2009 Indirect Supervision/Clerical Support STLM Labor 790,516 116,902 385,090 288,525 40 2010 Employee Development STLM Labor 107,798 15,941 52,512 39,344 41 2013 FTR Administration Alloc-Fixed 24,772 - 24,772 - 42 2014 Billing Statements - NCPC Alloc-Fixed 258,878 - 129,439 129,439 43 2020 Billing Disputes Total Dir Labor 12,522 2,698 6,480 3,343 44 2021 Analysis & Reporting Total Dir Labor 241,728 52,088 125,097 64,544 45 2022 Demand Response Alloc-Fixed 7,078 - - 7,078 46 2024 ASM Regulation Alloc-Fixed 31,577 - - 31,577 47 2025 ASM Locational Forward Reserve Alloc-Fixed 111,881 - - 111,881 48 2026 Batch Processing Total Dir Labor 32,122 6,922 16,623 8,577 49 2030 ARR Administration Alloc-Fixed 2,450 - 2,205 245 50 2032 Billing STLM Labor 59,888 8,856 29,173 21,858 51 2033 Market Analysis Alloc-Fixed 184,563 - 184,563 - 52 Total 2,609,034 387,294 1,197,248 1,024,492 53 54 Market Operations Support Services 55 3000 Hourly Settlements Support Alloc-Fixed 263,183 - 131,592 131,592 56 3002 Monthly Settlements Support Alloc-Fixed 108,370 54,185 - 54,185 57 3003 Market Analysis Support Alloc-Fixed 774 - 774 - 58 3004 Generation & Load Admin Support Alloc-Fixed 193,982 - 193,982 - 59 3005 Demand Resource Admin Support Alloc-Fixed 97,533 - 97,533 - 60 3006 Customer Service Alloc-Fixed 154,814 - 154,814 - 61 3007 NEPOOL Committees Support Alloc-Fixed 2,632 - 1,316 1,316 62 3008 Admin Support Alloc-Fixed 57,281 - 57,281 - 63 3009 Indirect Supervision (Principal Analysts only) Alloc-Fixed 86,696 - 86,696 - 64 3010 Employee Development Alloc-Fixed 15,791 - 15,791 - 65 3011 Release Checkout and Support Alloc-Fixed 1,858 - 1,858 - 66 3012 FERC Data Request Alloc-Fixed 44,896 - 44,896 - 67 3013 Tariff Change Coordination (TCC) Total Dir Labor 155 33 80 41 68 3014 Markets Development Support Alloc-Fixed 10,063 - 5,031 5,031 69 3015 Market Administration Support Alloc-Fixed 1,084 - 1,084 - 70 Total 1,039,110 54,218 792,726 192,165
ISO-NE Public Exhibit 2 DRAFT NEPOOL PARTICIPANTS COMMITTEE Page 5 of 7 OCT 2, 2015 MEETING, AGENDA ITEM #5.a
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 406 Market Services 2 16001 Participant/membership support Alloc-Fixed 65,096 - 32,548 32,548 3 16006 Call Support (Ask ISO) Alloc-Fixed 853,752 221,976 563,477 68,300 4 16404 NEPOOL Committee Support MS Labor 86,134 - 77,521 8,613 5 16414 Direct Customer Contact MS Labor 159,795 - 143,815 15,979 6 16419 Asset Registration Implemented Alloc-Fixed 244,377 - 244,377 - 7 16420 Asset Registration Review Alloc-Fixed 210,670 - 210,670 - 8 16422 Claimed Capability Audits Alloc-Fixed 33,707 - 33,707 - 9 16424 Demand Resource Audits Alloc-Fixed 185,390 - 185,390 - 10 16425 DR Registration Implemented Alloc-Fixed 33,707 - 33,707 - 11 16429 Business Analysis - Process Improvement Alloc-Fixed 155 - 139 15 12 16434 QMS/CAPA Process and Procedure Updates Total Dir Labor 252,804 54,479 130,826 67,499 13 16435 Resource Performance Monitoring Alloc-Fixed 33,707 - 33,707 - 14 Total 2,159,294 276,455 1,689,884 192,955 15 16 410 Market Training and Reliability Contracts 17 16021 Training Development Alloc-Fixed 858,368 - 429,184 429,184 18 16024 Training Delivery Alloc-Fixed 8,166 - 4,083 4,083 19 16433 Passive Resource Performance and M&V Review Alloc-Fixed 33,707 - 33,707 - 20 Total 900,242 - 466,975 433,267 21 22 203 Resource Adequacy 23 14313 National Committee Support PSR Labor 41,007 4,456 2,069 34,482 24 14315 Employee Development PSR Labor 139,271 15,133 7,028 117,110 25 17101 Analysis Alloc-Fixed 709,940 - 496,958 212,982 26 17131 Calculate Objective Capability Alloc-Fixed 317,359 - - 317,359 27 17231 Regulatory Filings Alloc-Fixed 33,807 - - 33,807 28 17241 Transmission Plan Admin Support Alloc-Fixed 33,807 16,903 16,903 - 29 17251 Regional Bulk Power System Assessment Alloc-Fixed 304,260 152,130 152,130 - 30 17331 NEPOOL Committee Support PSR Labor 105,953 11,513 5,347 89,094 31 17361 Regional Committee Support PSR Labor 35,140 3,818 1,773 29,548 32 17401 Indirect Supervisory Activities PSR Labor 169,953 18,467 8,577 142,909 33 17402 Project Management Alloc-Fixed 236,647 236,647 - - 34 17403 TCA Application Review Alloc-Fixed 70,857 - - 70,857 35 17405 Energy Efficiency Forecast Alloc-Fixed 67,613 - - 67,613 36 17406 North American Energy Standards Board (NAESB) Alloc-Fixed 36,873 - 18,437 18,437 37 17408 MA-EEAC Total Dir Labor 36,873 7,946 19,082 9,845 38 17501 FCA - Evaluate Existing Resource De-list Bids Alloc-Fixed 73,097 - - 73,097 39 17502 FCA - Preliminary Review of Show of Interest Applications Alloc-Fixed 140,710 - - 140,710 40 17503 FCA - New Resource Qualification Support Alloc-Fixed 295,797 - - 295,797 41 17504 FCA - Perform Transmission / Topology Assessments Alloc-Fixed 101,420 - - 101,420 42 17505 FCA - Perform Existing Resource Qualification Alloc-Fixed 208,323 - - 208,323 43 17507 FCA - Auctions & Filings Alloc-Fixed 809,626 - - 809,626 44 17508 FCA - Annual Reconfiguration Auction Support/Reliability Reviews Alloc-Fixed 73,097 - - 73,097 45 18101 Develop Load Forecast Alloc-Fixed 315,198 63,040 63,040 189,119 46 18121 Operations Forecast Support Alloc-Fixed 67,613 13,523 13,523 40,568 47 18131 Other Load Forecasting Activities Alloc-Fixed 33,807 6,761 6,761 20,284 48 Total 4,458,046 550,337 811,628 3,096,081 49 50 204 System Planning 51 18150 Regional Transmission Expansion Plan Alloc-Fixed 887,395 665,546 221,849 - 52 18152 States Requests Alloc-Fixed 149,323 74,661 37,331 37,331 53 18401 Regional Activities Alloc-Fixed 11,245 11,245 - - 54 18501 Regulatory Activities Alloc-Fixed 17,158 17,158 - - 55 18521 Employee Development SP Labor 2,024 502 359 1,163 56 18531 Indirect Supervision/Clerical Support SP Labor 161,485 40,091 28,629 92,765 57 Total 1,228,630 809,204 288,168 131,258 58 59 205 Transmission Planning 60 11201 System Design Task Force Alloc-Fixed 3,524 3,524 - - 61 18201 Transmission System Assessment Alloc-Fixed 3,469,289 3,469,289 - - 62 18261 Transmission Tariff Information Requirements Alloc-Fixed 9,758 9,758 - - 63 18301 NEPOOL Administrative Support - Schedule 1 Tariff Alloc-Fixed 76,625 76,625 - - 64 18331 SIS Preparatory Arrangements Alloc-Fixed 3,524 3,524 - - 65 18333 General SIS/FS Alloc-Fixed 655,879 655,879 - - 66 18334 Indirect Supervision/Clerical Support TP Labor 366,454 366,454 - - 67 18335 Regulatory Activities - NPCC TP Labor 99,979 99,979 - - 68 18336 National Activities TP Labor 78,398 78,398 - - 69 18337 Regulatory Activities TP Labor 109,597 109,597 - - 70 18338 Employee Development TP Labor 116,462 116,462 - - 71 18341 NERC Compliance TP Labor 11,717 11,717 - - 72 18343 FERC Order 1000 Alloc-Fixed 319,257 - - 319,257 73 18344 Transmission Planning Siting Support Alloc-Fixed 6,233 - - 6,233 74 Total 5,326,697 5,001,206 - 325,490
ISO-NE Public Exhibit 2 DRAFT NEPOOL PARTICIPANTS COMMITTEE Page 6 of 7 OCT 2, 2015 MEETING, AGENDA ITEM #5.a
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 304 Program Management 2 801 Program Management - Administration Total Dir Labor 824,303 177,621 426,586 220,096 3 1661 ISO Program Management Alloc-Fixed 342,618 - 239,833 102,785 4 25002 PMO Support Alloc-Fixed 16,548 4,964 5,792 5,792 5 25902 Coordinated Transaction Scheduling - O&M Alloc-Fixed 116,869 81,808 35,061 - 6 25914 Divisional Accounting (for Market Participants) Total Dir Labor 66,825 14,400 34,583 17,843 7 25919 Alternative Technologies & Regulation Market Alloc-Fixed 39,711 - - 39,711 8 25926 Hourly Market Alloc-Fixed 154,814 61,925 46,444 46,444 9 25938 Asset Registration Automation Total Dir Labor 16,720 3,603 8,653 4,464 10 25940 Non-Reimburseable Smart Grid SIDU Observation Period Alloc-Fixed 90,029 13,504 13,504 63,021 11 25943 Submission of FTRs for Clearing Alloc-Fixed 33,856 - - 33,856 12 25953 ICCP and ED Network Upgrades Alloc-Fixed 95,782 86,204 - 9,578 13 Total 1,798,076 444,030 810,455 543,591 14 15 315 Business Architecture and Technology 16 21201 Business Architecture and Technology Total Dir Labor 2,246,284 484,030 1,162,477 599,778 17 21203 Employee Development Total Dir Labor 49,100 10,580 25,410 13,110 18 Total 2,295,384 494,610 1,187,887 612,888 19 20 408 Market Development 21 21001 Market Development Total Dir Labor 2,128,297 458,606 1,101,417 568,274 22 21002 Administration Total Dir Labor 183,849 39,616 95,144 49,089 23 21003 Employee Development Total Dir Labor 13,780 2,969 7,131 3,679 24 21007 Budget/Forecast Support Total Dir Labor 61,283 13,205 31,715 16,363 25 21009 Increased Scope of Impact Analysis Alloc-Fixed 99,999 26,000 65,999 8,000 26 22656 Energy, Reserve, and Regulation Markets Alloc-Fixed 765,429 - 574,072 191,357 27 Total 3,252,636 540,396 1,875,478 836,763 28 29 407 Markets Committee Relations & Rule Integration 30 22602 NEPOOL Committee Meetings & Support Alloc-Fixed 619,376 - 309,688 309,688 31 22607 NEPOOL Markets Committee Administration Total Dir Labor 121,485 26,178 62,870 32,438 32 Total 740,862 26,178 372,558 342,126 33 34 409 Demand Resource Strategy 35 22401 Administration Total Dir Labor 87,011 18,749 45,029 23,233 36 22402 Working Group Meetings and Support Total Dir Labor 21,899 4,719 11,333 5,847 37 22404 Price Responsive Demand Alloc-Fixed 179,796 - 143,837 35,959 38 Total 288,706 23,468 200,199 65,039 39 40 210 IT Management 41 6517 Employee Development - Hardware/Software Total Dir Labor 95,555 20,590 49,451 25,514 42 6519 Indirect Supervision and Clerical Support Total Dir Labor 3,118,865 672,054 1,614,047 832,764 43 6552 Security Total Dir Labor 405,253 87,324 209,723 108,206 44 6556 Budget Preparation, Tracking & Forecast Total Dir Labor 145,731 31,402 75,417 38,911 45 6557 Information Technology Committee Total Dir Labor 18,277 3,938 9,459 4,880 46 22501 Change Management Support Alloc-Fixed 187,538 84,392 84,392 18,754 47 22505 Administrative Alloc-Fixed 352,172 119,738 116,217 116,217 48 Total 4,323,391 1,019,439 2,158,705 1,145,247 49 50 201 IT System/Network & Desktop 51 6510 Desktop Support - Hardware Total Dir Labor 399,247 86,030 206,615 106,602 52 6511 Desktop Support - Software Total Dir Labor 796,785 171,691 412,345 212,749 53 6512 Host Computer - Hardware Alloc-Fixed 1,146,315 - 859,736 286,579 54 6513 Host Computer - Software Alloc-Fixed 1,763,842 - 1,322,882 440,961 55 6514 Networking - Hardware Total Dir Labor 816,849 176,015 422,728 218,106 56 6516 Communications Total Dir Labor 1,678,847 361,758 868,822 448,267 57 6550 Data Communications Support Total Dir Labor 270,398 58,265 139,934 72,199 58 6602 Help Desk Support Total Dir Labor 335,290 72,248 173,516 89,525 59 6615 Host Computer Monitoring Alloc-Fixed 1,254,513 - 627,257 627,257 60 6616 Desktop Support Total Dir Labor 499,800 107,697 258,652 133,451 61 6617 System Administration - Unix Total Dir Labor 678,400 146,182 351,079 181,139 62 6618 System Administration - Windows Total Dir Labor 838,710 180,725 434,042 223,943 63 6619 Systems Support Misc Total Dir Labor 85,170 18,352 44,076 22,741 64 6620 Systems Support - Security Total Dir Labor 245,577 52,917 127,089 65,571 65 6621 Network Support Total Dir Labor 415,081 89,442 214,809 110,830 66 6622 Network/Systems Compliance Total Dir Labor 11,019 2,374 5,703 2,942 67 6623 Asset Management Total Dir Labor 421,020 90,721 217,882 112,416 68 Total 11,656,862 1,614,419 6,687,166 3,355,277
ISO-NE Public Exhibit 2 DRAFT NEPOOL PARTICIPANTS COMMITTEE Page 7 of 7 OCT 2, 2015 MEETING, AGENDA ITEM #5.a
Line Activity Code Allocation Self-Funding Tariff No. No. Description Factor (1) Total (2) Schedule 1 Schedule 2 Schedule 3 (a) (b) (c) (d) (e) (f) (g)
1 212 IT Cyber Security 2 6539 Policy/Procedures Program Total Dir Labor 55,939 12,054 28,949 14,936 3 6540 Security Compliance and Reporting Total Dir Labor 2,169,684 467,524 1,122,835 579,325 4 6540A Controls Assessment Total Dir Labor 39,245 8,456 20,310 10,479 5 6540B Virus/Malware Reporting and Response Total Dir Labor 19,622 4,228 10,155 5,239 6 6540D Intrusion Monitoring and Response Total Dir Labor 98,111 21,141 50,774 26,197 7 6540E System Compliance Enhancement Total Dir Labor 156,978 33,826 81,238 41,915 8 6541 Security SW Tools Program Total Dir Labor 333,579 71,880 172,631 89,069 9 6543 Critical Infrastructure Protection WG (NERC) Total Dir Labor 6,677 1,439 3,455 1,783 10 6544 Infragrad (FBI) Total Dir Labor 97,632 21,038 50,526 26,069 11 6546 Internal Audit Support Total Dir Labor 19,622 4,228 10,155 5,239 12 6547 Security Training Total Dir Labor 19,622 4,228 10,155 5,239 13 6548 CIP Compliance & Monitoring Total Dir Labor 212,070 45,697 109,748 56,625 14 Total 3,228,782 695,739 1,670,930 862,113 15 16 211 IT Enterprise Applications Support 17 6571 DBA Support - MOPS Total Dir Labor 2,396,535 516,406 1,240,233 639,896 18 6591 Data Architect - MOPS Total Dir Labor 256,136 55,192 132,553 68,391 19 6594 IT Data Analyst Total Dir Labor 265,629 57,238 137,466 70,925 20 6595 IT WEB Application Support Total Dir Labor 722,943 155,780 374,131 193,032 21 6596 IT Data Governance Total Dir Labor 150,067 32,336 77,661 40,069 22 21706 IT Markets Software Development - Enterprise Total Dir Labor 439,846 94,778 227,625 117,443 23 21801 Software Support - Settlements Alloc-Fixed 554,480 - 443,584 110,896 24 21802 Software Support - Publishing Alloc-Fixed 258,139 - 206,512 51,628 25 21803 Software Support - Finance Alloc-Fixed 255,909 - 204,727 51,182 26 21804 Software Support - Mitigation Alloc-Fixed 451,110 - 360,888 90,222 27 21805 Software Support - TSO Total Dir Labor 352,451 75,946 182,397 94,107 28 21806 Software Support - Enterprise Total Dir Labor 1,001,874 215,884 518,481 267,509 29 21807 Software Support - Planning Alloc-Fixed 475,646 - 380,517 95,129 30 21808 Training Delivery to NON-IT Alloc-Fixed 330,952 - 264,762 66,190 31 21809 Tools Alloc-Fixed 144,875 - 115,900 28,975 32 21811 Single Sign On Support Alloc-Fixed 79,608 - 63,686 15,922 33 21816 CMS Support Total Dir Labor 212,483 45,786 109,962 56,735 34 21818 Discoverer Support Total Dir Labor 103,576 22,319 53,602 27,656 35 21819 Ceridian Support Total Dir Labor 79,608 17,154 41,198 21,256 36 21821 Compliance Management Total Dir Labor 53,072 11,436 27,465 14,171 37 Total 8,584,936 1,300,255 5,163,349 2,121,333 38 39 102 IT Energy Management Systems 40 21600 Indirect Supervision and Administration Total Dir Labor 361,281 77,849 186,967 96,465 41 21601 Power System Modeling Total Dir Labor 29,012 6,251 15,014 7,746 42 21603 Applications Support Total Dir Labor 607,099 130,818 314,180 162,101 43 21604 DTS Support Alloc-Fixed 1,544,494 1,235,595 308,899 - 44 21605 DAM Support Alloc-Fixed 1,000,980 200,196 600,588 200,196 45 21606 Real-time Market Support Alloc-Fixed 2,092,680 418,536 1,255,608 418,536 46 21607 Forecast Support Alloc-Fixed 101,360 20,272 60,816 20,272 47 Total 5,736,905 2,089,517 2,742,072 905,316 48 49 213 IT Enterprise Applications Development 50 6518 Employee Development - Software Total Dir Labor 18,375 3,960 9,509 4,906 51 21702 IT Corporate Application Support Alloc-Fixed 75,435 - 15,087 60,348 52 21707 Application Analysis and Conceptual Design Alloc-Fixed 1,074,003 - 859,202 214,801 53 21709 Technology Evaluation and Selection Alloc-Fixed 17,788 - 14,230 3,558 54 21710 Indirect Supervision and Administration Alloc-Fixed 531,681 - 425,344 106,336 55 21711 EWR and CAPA Analysis Alloc-Fixed 171,124 - 136,899 34,225 56 Total 1,888,404 3,960 1,460,272 424,173 57 58 216 IT Power System Modeling Management 59 21650 Indirect Supervision and Administration Total Dir Labor 111,703 24,072 57,806 29,825 60 21651 Power System Modeling Alloc-Fixed 861,609 344,643 344,643 172,322 61 21652 System Application Support Alloc-Fixed 176,841 70,737 70,737 35,368 62 21654 NX9 Administration Alloc-Fixed 481,016 192,406 192,406 96,203 63 21655 ICCP Support Alloc-Fixed 698,834 279,534 279,534 139,767 64 21656 Transmission Project Management Alloc-Fixed 23,590 18,872 4,718 - 65 21657 Model On Demand Admin Alloc-Fixed 340,984 - - 340,984 66 21658 Model on Demand Case Requests Alloc-Fixed 77,129 - - 77,129 67 Total 2,771,706 930,264 949,844 891,598 68 69 70 Total ISO $ 185,151,221 $ 44,360,392 $ 84,722,023 $ 56,068,806
ISO-NE Public NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a Exhibit 3
Table 8 Draft 2016 Rate Components (1)
Tariff Schedule Jan. 1, 2016 (a) (b)
Schedule 1 Network Load (per kW-hour) $0.00026
Schedule 2 TU Bids (Virtual Inc/Dec) Submitted $0.00500 Cleared $0.06000
FTR Bids Submitted $2.02863 Cleared $2.62374
TU's Block 1 - 1st 12,500 $0.66437 Block 2 - Next 27,000 $0.60397 Block 3 - Over 39,500 $0.54358
Volumetric Block 1 - 1st 250,000 $0.28296 Block 2 - Next 1,250,000 $0.25723 Block 3 - Over 1,500,000 $0.23151
Schedule 3 R-T NCP Load Obligation $0.20313 Export Rate $0.40000
(1) From Exh 3, RCL-7, Sch 3.
ISO-NE Public NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a Addl Materials Circulated 9/30/15
September 29, 2015 David J. Vitale Chairman ISO New England One Sullivan Road Holyoke, MA 01040
Re: Comments on proposed 2016 ISO New England Budget
Dear Chairman Vitale:
On behalf of the undersigned New England state agencies, we hereby offer comments regarding the ISO New England (“ISO-NE or “ISO”) proposed 2016 administrative and capital budgets. We welcome this opportunity to provide direct feedback to you regarding the budgets.
We deeply appreciated the ISO-NE Board of Directors’ (“Board”) Board's attendance at the budget briefing in June, and commend you and your fellow Board members for your efforts to keep cost increases within reasonable limits. We appreciate that the overall cost increase was restricted to 3.9% for the operating budget. We also appreciate the change to a level funding approach for the defined benefit pension liability, as it will ease the volatility of the expense.
The processes that have been developed to date, and the efforts of all parties involved, have helped to limit our comments to two areas. First, we wish to propose a timing change in the states' review of ISO's budget, to accommodate the Board's calendar and better align the purpose of the process. Second, we wish to express our repeated, and continuing concerns about the sustained, rapid growth in staffing levels.
I. The Budget Review Process Should Occur Sooner in Order to Provide the Board with the States' Position When the Board Discusses the Budget.
We believe the new budget review procedure has resulted in a much more cooperative and productive process. However, we propose that this review process be modified to occur earlier, so that the States' comments are submitted to the Board prior to the Board's in-person meeting on the budget. We realize that the Board met and reviewed the budget on September 17, more than a week before the States' comments were due. We also understand that the Board will receive the States' comments, management's response and the results of the NEPOOL Participants' Committee vote prior to acting on the budget by written consent (electronically) in mid-October. We
NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a Daniel J. Vitale Addl Materials Circulated 9/30/15 Chairman, ISO New England September 29, 2015 Page 2
would like to modify this process so that the Board has the benefit of the States' comments and ISO management's response when it meets and deliberates in person on the budget.
The Settlement Agreement provides that the State Parties:
may submit comments regarding any proposed adjustments to the proposed budget within five weeks after the August budget presentation meeting but no later than September 25. ISO-NE shall respond in writing to any written comments and proposed adjustments within two weeks of receipt, but no later than five business days before the ISO-NE Board of Directors votes on the proposed budgets.
The intent of providing written comments was to provide the ISO NE Board with the opportunity to consider and discuss the States' concerns prior to voting on the budget. Moreover, as last year's comments and this year's comments should demonstrate, knowledge of the questions submitted is not dispositive of the States' position on a budget. To comply with the intent of the Settlement Agreement, and to provide the Board with the States' views during the Board's in-person review of the budget, we request that the process be modified to ensure that the Board has the States' comments prior to reviewing the budget in person.
II. The Continuing Escalation of Staff
With this budget, ISO-NE will have added 52 full-time, funded employees since FY 2013.1 As the first substantive term in the 2013 Settlement Agreement, ISO-NE agreed that it would rely:
to the greatest extent possible on its current employee complement to perform all existing and proposed new projects, and shall document its efforts to do so as set forth below.
Section II.A of the Settlement Agreement. An additional 52 full-time, funded positions does not appear to comport with this obligation. Moreover, this continuing escalation of staff is not sustainable.
1 As of December 31, 2012, ISO-NE had 539.5 FTEs. By the end of 2013, ISO-NE employed 560 FTEs, and by the end of 2014, had 567.5 employees. Pursuant to last year's budget, ISO has 577 funded FTE positions for this year, of which 576 were filed by June 30, 2015. From FY2013 to FY2015, ISO-NE added 43.5 new funded FTE positions in its budgets, and now seeks to add an additional 8.5 FTEs for FY 2016, for a total of an additional 52 full-time, funded positions since FY2013.
NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a Daniel J. Vitale Addl Materials Circulated 9/30/15 Chairman, ISO New England September 29, 2015 Page 3
As part of its oral presentation in June 2015, ISO management stated that it would not seek additional FTE positions for its FY 2017 budget. When asked to confirm this commitment, management responded "That is our current intention, but it is subject to changes in workload brought about by regulatory and other exigent priorities." Every state agency and most businesses have workload changes and exigent priorities, and yet do not have the ability to add employees when a significant new directive arises. Rather, as new directives are introduced, other priorities must make way or other efficiencies must be explored.
We ask you to address this repeated, multi-year concern. The growth in full-time employees served as one of the major drivers for the challenge to the budget that resulted in the Settlement Agreement now governing this budget review process. We are available to meet with management or the Board on this issue if it would assist in resolving this continuing issue.
CONCLUSION
The undersigned New England State Agencies are heartened by the progress made during this year’s budget review. However, we ask that the process for next year's budget review be rescheduled so you have the benefit of our comments before you deliberate and discuss the budget in person, and we look forward to discussing this proposal with management. We also respectfully request that you consider and address our continuing concern with the escalation of staffing levels at ISO NE.
Respectfully submitted,
_/s/ Arthur H. House______/s/ Elin Swanson Katz______Arthur H. House Elin Swanson Katz Chairman Consumer Counsel Public Utilities Regulatory Authority Office of Consumer Counsel Ten Franklin Square Ten Franklin Square New Britain, CT 06051 New Britain, CT 06051
_/s/ George Jepsen______/s/ Ed McNamara______George Jepsen Ed McNamara Attorney General Regional Policy Director Office of the Attorney General Vermont Department of Public Service 55 Elm Street 112 State Street Hartford, CT 06105 Montpelier, VT 05620
NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.a Daniel J. Vitale Addl Materials Circulated 9/30/15 Chairman, ISO New England September 29, 2015 Page 4
_/s/ Leo J. Wold______/s/ Susan Chamberlin______Leo J. Wold, Assistant Attorney General Susan Chamberlin Rhode Island Department of Attorney General Consumer Advocate 150 South Main Street Office of the Consumer Advocate Providence, RI 02903 21 South Fruit Street For Peter F. Kilmartin, Attorney General Concord, NH 03301 of the State of Rhode Island and the Rhode Island Division of Public Utilities and Carriers
NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.b
New England States Committee on Electricity
2016 Budget Presentation NEPOOL Budget & Finance Subcommittee August 26, 2015 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.b
Background: Budget Review
Term Sheet Provision: “… the annual review of its [NESCOE’s] proposed budgets by at least the NEPOOL Participants Committee will be limited to considerations of accounting and reconciliation, so long as spending remains within the boundaries established by those frameworks….. NESCOE will develop an operating budget recommendation for each year in consultation with NEPOOL, the PTO Administrative Committee and ISO-NE within the boundaries of the then-approved five year budget framework …”
Proposed 2016 budget conforms to: 1) Boundaries of previously reviewed 5-year pro forma (2013 - 2017) supported in March 2012 by NEPOOL & filed and accepted by the FERC 2) NESCOE commitment not to seek an increase over pro forma budget of more than 10% in any 1 year - 2016 proposed budget is less than 2016 pro forma budget As with prior audits, following calendar year 2014, independent auditor concluded NESCOE books conform to generally accepted accounting principles 2 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.b
Background: Policy Priorities
Term Sheet Provision Governing Identification of Policy Priorities
“Each year NESCOE will produce a Report to the New England Governors that will document its accomplishments from the preceding year and its projected policy priorities for the coming two years. This report will include a full accounting of spending by NESCOE during the preceding year and proposed budgets for each of the upcoming two years.”
Consistent with Term Sheet, 2014 Report to the New England Governors:
Reviewed work in 2014 Projected policy priorities Provided spending from prior year Projected budget information for upcoming two years
3 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.b
Projected Policy Priorities
In March 2014, NESCOE provided to the Governors the 2014 Annual Report to New England Governors
Report simultaneously released to NEPOOL & ISO-NE & circulated to the NEPOOL Participants Committee on March 11, 2015
NESCOE identified forward looking policy priorities at Section V, pages 30-34.
4 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.b
Projected Policy Priori es, Update
FERC Order 1000: Participate in DC Circuit Court of Appeals proceedings on state public policy-related provisions and further action as necessary Participate in development of implementation details in connection with competitive transmission
Transmission Planning/Analysis, Transmission Cost Estimation and Containment Practices: Continue to seek progress on enhancing consistency in regional system planning by improving development of base cases Continue to seek improvement in transmission cost estimation and containment practices (some but not complete overlap with Order 1000 implementation)
Zonal Demand Curve Matters: Participate in the satisfactory resolution of matters related to the zonal demand curve
Accommodation of Public Policy in Markets: Ensure that consumers receive the full benefits of state policies and consumer investment in all forms of power generation technologies through the DG Forecast used appropriately in transmission planning, markets and operations Defend NESCOE’s narrowly tailored renewable resource exemption in connection with New England generators’ challenge in the DC Circuit Court of Appeals Continue to advance means to track environmental attributes of low carbon power resources that are able to satisfy state policy requirements and objectives to ensure they are accounted for properly 5 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.b
NESCOE Organization & Misc.
Employees Diversity in academic training, skills; blend of private & public sector experience Current total employee level: 5 Near-term resume solicitation with return to 6 employees in Quarter 4
Web Site Overhaul almost complete Focus on functionality, document accessibility, user ease in connection with searches Preview: nescoe.net
Office Space 4 Bellows Road, Westborough, MA Current lease runs through September 2015, renewing now Also provides small group meeting space needs Small room in Portsmouth, New Hampshire Current lease runs through end of 2015, plan on renewing
6 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.b
Organizational matters, Con’t.
Technical Consultants Technical consultants, such as transmission engineers and economists, assist NESCOE in the regular course of business in analyzing ISO-NE studies & data
Continue work with technical consultants to conduct independent analysis to inform policymakers’ decisions on key issues. Looking ahead, primary growth in spending will relate to increased use of consultants to conduct independent analysis for policymakers. For example,
Wilson Energy Economics - assistance with economic analysis PeterGFlynn, LLC - New England transmission cost and infrastructure expertise Reishus Consulting, LLC - electric industry research and analysis
Legal Counsel Litigation is not the primary means by which NESCOE seeks to accomplish its objectives & thus, greater resource & focus on technical consulting
FERC Counsel: McCarter & English LLP
7 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.b
5 Year Pro Forma
Proposed 2016 budget conforms to 2016 budget in 5 year Pro Forma Framework
2016 Projected Budget in 5 Year Pro Forma: $2,317,455 (supported by NPC in March 2012 & filed and accepted by the FERC) 2016 Proposed Budget: $2,200,259 2015 Budget, for reference: $2,093,615
In relation to 2016 Pro Forma, 2016 Proposed Budget reflects:
Reduction in assumed health and other benefits expenses based on experience In general administrative items, slight decrease in travel and slight increase in rent
8 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.b
5 Year Pro Forma, for reference
9 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.b
2016 Proposed Budget
10 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.b
2014 & 2015 Spending & Implications for 2016
Unspent funds in any year credited toward future year Expenses increasing over time, commensurate with increased substantive activity & analysis
2014 Total Spending: $1,347,320 *
2015 Spending to end of June: $ 630,449
2015 Projected Year End: $1,448,310 * reflects expected increased litigation-related expenses primarily arising from participation in matters before the D.C. Circuit Court of Appeals (a first for NESCOE) following conclusion of FERC proceedings; incremental legal expenses may arise if 2015 sees another set of year-end complaints
* Cumulative prior years’ true up, including 2014, will be reflected in the 2016 revenue requirement and rates (see following slide). Any 2015 true up will be reflected in the 2017 revenue requirement and rates.
11 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.b
2016 Projected Billing Rate
With thanks to ISO-NE for calculations -
2016 Budget: $2,200,259
Less Prior Years’ True Up: ($1,493,842)
Total Revenue Recovery: $ 706,417
Divided by Total Network Load: 243,679,448 (total network load from 2015 ISO-NE Tariff; no escalation or reduction used in calculation)
2016 Schedule 5 Estimated Rate: $0.00290
12 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #5.b
Thank you. Questions?
13 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6 MEMORANDUM
TO: NEPOOL Participants Committee Members and Alternates
FROM: Eric Runge, NEPOOL Counsel
DATE: September 25, 2015
RE: Consideration of HQICC and ICR Values
At the October 2, 2015 Participants Committee meeting, you will be asked to vote on the megawatt values to be used for the 2019/20 Capacity Commitment Period (“FCA10”) for : (i) the Hydro-Quebec Interconnection Capability Credit (the “HQICC Values”)1; and (ii) a proposed Installed Capacity Requirement (“ICR”) value and related values (collectively, the “ICR Values”). The ICR Values include the Net ICR2 and the capacity requirement values for the System-Wide Capacity Demand Curve and the Southeast New England (“SENE”) Local Sourcing Requirement (“LSR”).
The HQICC and ICR Values initially were proposed by the ISO and, at its September 15, 2015 meeting, the Reliability Committee voted and recommended Participants Committee support for both the HQICC and ICR Values in separate votes.3 Although there was not a lot of controversy over the HQICC and ICR Values at the Reliability Committee or Power Supply Planning Committee, some Participants wanted a discussion of them, particularly regarding: (i) the Cross Sound Cable and its relationship to the HQICC and ICR Values, and (ii) how distributed generation and its assumed performance is factored into the ICR Values.
The recommended HQICC Values are 975 MW/month for each month of the 2019/20 Capacity Commitment Period. The ICR Values proposed by the ISO for the 2019/20 Capacity Commitment Period are as follows:
♦ 35,126 MW - ICR; ♦ 34,151 MW - Net ICR; ♦ 33,076 MW - 1-in-5 LOLE Demand Curve capacity value; ♦ 37,053 MW - 1-in-87 LOLE Demand Curve capacity value; and ♦ 10,028 MW - SENE LSR.
1 The HQICC Values were originally on the Consent Agenda (Item No. 2) but were removed at the request of the Long Island Power Authority. The ICR Values were placed directly on the discussion agenda following Participant requests received prior to the September 18 circulation of the Consent Agenda and initial notice of the October 2 meeting.
2 The NET ICR is the ICR minus the values for the Hydro-Quebec Interconnection Capability Credit (the “HQICC Values”). 3 The RC vote to recommend support for the HQICC Values passed by show of hands with 2 oppositions (1 each in the Generation and Supplier Sectors) and 4 abstentions (Generation Sector - 2, Supplier Sector - 2). The vote to recommend support for the ICR Values passed by show of hands with 3 oppositions (Generation Sector - 2, Supplier Sector - 1) and 9 abstentions (AR Sector - 5, End User Sector - 2, Supplier Sector - 2).
92162080.3 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6
The following resolutions could be used for Participants Committee consideration of these items:
RESOLVED, that the Participants Committee supports the proposed HQICC Values for the 2019/20 Capacity Commitment Period, as recommended by the Reliability Committee and as reflected in the materials distributed to the Participants Committee for its October 2, 2015 meeting, together with [any changes agreed to at the meeting and] such non-substantive changes as may be agreed to after the meeting by the Chair and Vice-Chair of the Reliability Committee.
RESOLVED, that the Participants Committee supports the proposed ICR Values for the 2019/20 Capacity Commitment Period, as recommended by the Reliability Committee and as reflected in the materials distributed to the Participants Committee for its October 2, 2015 meeting, together with [any changes agreed to at the meeting and] such non-substantive changes as may be agreed to after the meeting by the Chair and Vice-Chair of the Reliability Committee.
92062575.3 -2- . 92162080.3 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a RELIABILITY COMMITTEE MEETING
SEPTEMBER 15, 2015 | WESTBOROUGH, MA
2019/20 FCA Tie Benefits Study
Fei Zeng RESOURCE ADEQUACY
NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Objective
• To review the tie benefits results for the 2019/20 Forward Capacity Auction (FCA10)
– Total tie benefits for New England – Tie benefits contribution from individual or group of interconnection(s) • Maritimes (New Brunswick) • HQ Phase II • Highgate • New York AC ties • Cross Sound Cable (CSC)
2 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Highlight of Major Assumptions • Detailed study assumptions were presented to the PSPC on May 25, 2015 – http://www.iso-ne.com/static- assets/documents/2015/05/2019_fca_tie_benefits_study_assumptions.pdf
– Updates to the internal interface transfer limits according to the values presented to the Reliability Committee on June 17, 2015 • https://smd.iso-ne.com/operations- services/ceii/rc/2015/06/a9_transfer_capability_update.pdf
• Identification of capacity zones • For FCA 10, only Southeast New England (SENE) is identified as an import- constrained capacity zone, therefore the SENE interface limit is relaxed for this study – http://www.iso-ne.com/static- assets/documents/2015/06/fca10_zone_formation.pdf • Northern New England (NNE) is not an export-constrained capacity zone, therefore the North/South interface is modeled in this study – http://www.iso-ne.com/static- assets/documents/2015/08/pspc_081415_a3.0_fca10_zone_formation2.pdf
3
NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a
Summary of FCA10 Tie Benefits Study Results
• Total tie benefits – TB_Total = 1,990 MW
• Tie benefits for New Brunswick ties – TB_NB = 519 MW
• Tie benefits for HQ Phase II – TB_PH-II = 975 MW
• Tie benefits for Highgate – TB_HG = 142 MW
• Tie benefits for NY AC ties – TB_NY-AC = 354MW
• Tie benefits for Cross Sound Cable – TB_CSC = 0 MW
4 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Recap of Calculation Process
• Process 1.0 – Calculate the tie benefits values for all possible interconnection states using isolated New England system as the reference • Process 2.0 – Calculate initial total tie benefits for New England from all neighboring control areas • Process 3.0 – Calculate initial tie benefits for each individual neighboring control area – Pro-rate tie benefits values of individual control areas based on the total tie benefits, if necessary • Process 4.0 – Calculate initial tie benefits for individual interconnection or group of interconnections – Pro-rate tie benefits values of individual interconnection or group of interconnections based on the individual control area tie benefits, if necessary • Process 5.0 – Adjust tie benefits of individual interconnection or group of interconnections to account for capacity imports • Process 6.0 – Calculate the final tie benefits for each individual neighboring control area • Process 7.0 – Calculate the final total tie benefits for New England
5 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Process 1.0 Calculation of Tie Benefits for All Interconnection States Interconnection Interconnection Status Equivalent TB State Discription Maritimes Ph II Highgate NY-AC CSC LOLE (MW) 1 Cut All x x x x x 0.403 0 2 Cut None √ √ √ √ √ 0.100 1990 3 Cut MT x √ √ √ √ 0.138 1515 4 Cut Ph II √ x √ √ √ 0.181 1105 5 Cut Highgate √ √ x √ √ 0.110 1855 6 Cut NY-AC √ √ √ x √ 0.114 1785 7 Cut CSC √ √ √ √ x 0.100 1990 8 Cut MT & Ph II x x √ √ √ 0.249 670 9 Cut MT & Highgate x √ x √ √ 0.149 1400 10 Cut MT & NY-AC x √ √ x √ 0.162 1270 11 Cut MT & CSC x √ √ √ x 0.138 1515 12 Cut Ph II & Highgate √ x x √ √ 0.197 990 13 Cut Ph II & NY-AC √ x √ x √ 0.229 785 14 Cut Ph II & CSC √ x √ √ x 0.181 1105 15 Cut Highgate & NY-AC √ √ x x √ 0.127 1630 16 Cut Highgate & CSC √ √ x √ x 0.110 1855 17 Cut NY-AC & CSC √ √ √ x x 0.114 1785 18 Cut MT, Ph II & Highgate x x x √ √ 0.268 570 19 Cut MT, Ph II & NY-AC x x √ x √ 0.350 195 20 Cut MT, Ph II & CSC x x √ √ x 0.249 670 21 Cut MT, Highgate & NY-AC x √ x x √ 0.178 1135 22 Cut MT, Highgate & CSC x √ x √ x 0.149 1400 23 Cut MT, NY-AC & CSC x √ √ x x 0.162 1270 24 Cut Ph II, Highgate & NY-AC √ x x x √ 0.257 625 25 Cut Ph II, Highgate & CSC √ x x √ x 0.197 990 26 Cut Ph II, NY-AC & CSC √ x √ x x 0.229 785 27 Cut Highgate, NY-AC & CSC √ √ x x x 0.127 1630 28 Cut MT, Ph II, Highgate & NY-AC x x x x √ 0.403 0 29 Cut MT, Ph II, Highgate & CSC x x x √ x 0.268 570 30 Cut MT, Ph II, NY-AC & CSC x x √ x x 0.350 195 31 Cut MT, Highgate, NY-AC & CSC x √ x x x 0.178 1135 32 Cut Ph II, Highgate, NY-AC & CSC √ x x x x 0.257 625 6 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Process 2.0 Calculation of Initial Total Tie Benefits
• Compare state 1 (without any ties) and state 2 (with all the ties)
– TB_total_initial = 1,990 MW
– This value is subjected to the adjustment later to account for imports
7 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Process 3.0 Calculation of Tie Benefits for Neighboring Control Areas
• All interconnections connected to a given neighboring control area are grouped together to represent the state of interconnection between New England and that neighboring control area. The simple average of values for all the interconnection states represents the tie benefits of the target neighboring control area (four states for each area) • Tie Benefits from Maritimes – 1 vs. 32 = 625 2 vs. 3 = 475 12 vs. 18 = 420 17 vs. 23 = 515 – Average = 509 MW • Tie Benefits from Hydro Quebec – 1 vs. 23 = 1,270 2 vs. 12 = 1,000 3 vs. 18 = 945 17 vs. 32 = 1,160 – Average = 1,094 MW • Tie Benefits from New York – 1 vs. 18 = 570 2 vs. 17 = 205 3 vs. 23 = 245 12 vs. 32 = 365 – Average = 346 MW • Tie Benefits after Proration (since 509 + 1094 + 346 = 1,949 < 1,990) – TB_MTCA_initial = 1,990 * 509 / (509 + 1,094 + 346) = 519 MW – TB_HQCA_initial = 1,990 * 1094 / (509 + 1,094 + 346) = 1,117 MW – TB_NYCA_initial = 1,990* 346 / (509 + 1,094 + 346) = 354 MW
8 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Process 4.0 Calculation of Tie Benefits for Individual or Group of Interconnections • Each individual interconnection or group of interconnections subject to individual tie benefits contribution calculation is treated independently. The simple average of values for all the interconnection states represents tie benefits of the target interconnection or group of interconnections • Interconnections with Maritimes – No individual interconnections subject to the calculation • Interconnections with Quebec (Phase II and Highgate are subject to the calculation) – Phase II • 1 vs. 31 = 1,135 2 vs. 4 = 885 3 vs. 8 = 845 5 vs. 12 = 865 • 9 vs. 18 = 830 17 vs. 26 = 1,000 23 vs. 30 = 1,075 27 vs. 32 = 1,005 • Average = 955 MW
– Highgate • 1 vs. 30 = 195 2 vs. 5 = 135 3 vs. 9 = 115 4 vs. 12 = 115 • 8 vs. 18 = 100 17 vs. 27 = 155 23 vs. 31 = 135 26 vs. 32 = 160 • Average = 139 MW
– Tie Benefits after Proration (since 955 + 139 = 1,094 < 1,117) • TB_Ph-II_initial = 1,117 * 955 / ( 955 + 139 ) = 975 MW • TB_HG_initial= 1,117 * 139 / ( 955 + 139 ) = 142 MW
9
NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a
Process 4.0 (cont.)
• Interconnections with New York (NY AC ties and Cross Sound Cable (CSC) are subject to the calculation) – NY AC ties • 1 vs. 29 = 570 2 vs. 6 = 205 3 vs. 10 = 245 7 vs. 17 = 205 • 11 vs. 23 = 245 12 vs. 24 = 365 18 vs. 28 = 570 25 vs. 32 = 365 • Average = 346 MW
– CSC • 1 vs. 28 = 0 2 vs. 7 = 0 3 vs. 11 = 0 6 vs. 17 = 0 • 10 vs. 23 = 0 12 vs. 25 = 0 18 vs. 29 = 0 24 vs. 32 = 0 • Average = 0 MW
– Tie Benefits after Proration (since 346 + 0 = 346 < 354) • TB_NYAC_initial = 354 * 346/( 346 + 0 ) = 354 MW • TB_CSC_initial = 0 MW
10 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Process 5.0 Adjustment to Initial Tie Benefits Values
• Tie benefits determined in Process 4.0 for individual interconnection or group of interconnections are adjusted to account for capacity imports
• Interconnections with Maritimes • No adjustments required as no existing capacity imports
• Interconnections with Quebec – Phase II • No adjustments required as no existing capacity imports
– Highgate • Existing import = 6 MW • Assumed total import capability = 200 MW • Remaining import capability after import = 200 – 6 = 194 MW • Tie benefits value calculated in Process 4.0 = 142 MW • Since 142 MW < 194 MW, no adjustment is required • TB_HG = 142 MW
11 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a
Process 5.0 (cont.)
• Interconnections with New York – NY AC Ties • Existing import = 82.8 MW • Assumed total import capability = 1,400 MW • Remaining import capability after import = 1,400 – 82.8 = 1,317.2 MW • Tie benefits value calculated in Process 4.0 = 354 MW • Since 354 MW <1317.2 MW, no adjustment is required • TB_NY-AC = 354 MW
– CSC • No adjustments required since there are no tie benefits • TB_CSC = 0 MW
12 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Process 6.0 Determination of Tie Benefits for Individual Neighboring Control Area • Final tie benefits for each neighboring control area are the sum of the tie benefits from the individual interconnections or groups of interconnections with that control area, after accounting for the adjustments for capacity imports as determined in Process 5.0
– Maritimes • TB_MTCA= 519 MW
– Quebec • TB_HQCA = 975 + 142 = 1,117 MW
– New York • TB_NYCA = 354 + 0 = 354 MW
13 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Process 7.0 Determination of Total Tie Benefits for New England
• Final total tie benefits from all neighboring control areas are the sum of the control area tie benefits after the adjustments made to account for capacity imports as determined in Process 6.0.
– TB_Total = 519 + 1,117 + 354 = 1,990 MW
14 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a
Summary of Tie Benefits Results
• Total tie benefits – TB_Total = 1,990 MW
• Tie benefits for New Brunswick ties – TB_NB = 519 MW
• Tie benefits for HQ Phase II – TB_PH-II = 975 MW
• Tie benefits for Highgate – TB_HG = 142 MW
• Tie benefits for NY AC ties – TB_NY-AC = 354MW
• Tie benefits for Cross Sound Cable – TB_CSC = 0 MW
15 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a
Comparison of Tie Benefits for FCA10 and FCA9 (MW)
2019/20 (FCA10) 2018/19 (FCA9) Total Tie Benefits 1,990 1,970 New Brunswick 519 523 HQ Phase II 975 953 Highgate 142 148 New York AC 354 346 CSC 0 0
16 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a
APPENDIX: STUDY ASSUMPTIONS AND METHODOLOGY NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a
Scope of Study
• To calculate tie benefits values from neighboring control areas to New England for the 2019/20 FCA through a probabilistic analysis, using the calculation methodology described in III.12.9 of Market Rule 1. The calculations include:
– Total tie benefits from all neighboring control areas
– Tie benefits associated with each neighboring control area
– Tie benefits associated with individual interconnection or group of interconnections of interest
18 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Resource Assumptions - New England
• All existing qualified resources are modeled – Ratings, EFORd, Maintenance Weeks consistent with assumptions for the 2019/20 FCA ICR calculation
• Real-Time Emergency Generations (RTEG) – modeled as resources that are dispatched under OP-4 – Derated to account for unavailability
• Real-Time Demand Resources (RTDR) – RTDR assumed to be dispatched to meet system load and operating reserve requirements – modeled as resources that are dispatched prior to OP-4 – EFORd is used to reflect historical performance
19 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Resource Assumptions - External Areas • Resources assumptions based on – 2014 NPCC Long Range Adequacy Overview – 2015 NPCC Seasonal Assessments – 2015 New York Gold Book
20 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Load Assumptions
• Load Forecast – New England: based on 2015 CELT – Other Areas: based on their latest load models used in NPCC studies
• Load Shape – 2002 shape is used, consistent with current NPCC studies
21 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Transmission System Representation • Areas to be modeled – New England, Maritimes, Quebec, and New York are simulated using bubble transportation model – Equivalent model is used to reflect the impacts of the known capacity import/export between our directly interconnected neighboring areas and PJM and Ontario • Transmission interfaces and transfer capabilities – New England • Thirteen RSP subarea representation • Transfer capabilities consistent with RSP15 values • Interfaces associated with capacity zones are not modeled
– Other Areas • Consistent with their latest model used in NPCC studies
22 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a RSP 15 Internal Transmission Interface Limits
Year Interface(a) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 Orrington South Export 1,325 1,325 1,325 1,325 1,325 1,325 1,325 1,325 1,325 1,325 Surowiec South 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 Maine–New Hampshire 1,900 1,900 1,900 1,900 1,900 1,900 1,900 1,900 1,900 1,900 Northern New England– Scobie + 394 3,100 3,100 3,100 3,100 3,100 3,100 3,100 3,100 3,100 3,100 North–South(b) 2,100 2,100 2,100 2,100 2,675(c) 2,675 2,675 2,675 2,675 2,675 East–West 2,800 3,500(d) 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500 West–East 1,000 2,200(d) 2,200 2,200 2,200 2,200 2,200 2,200 2,200 2,200 Boston Import (N-1) 4,850 4,850 4,850 4,850 5,700(c) 5,700 5,700 5,700 5,700 5,700 Boston Import (N-1-1) 4,175 4,175 4,175 4,175 4,600(c) 4,600 4,600 4,600 4,600 4,600 SEMA/RI Export 3,000 3,400(d) 3,400 3,400 3,400 3,400 3,400 3,400 3,400 3,400 SEMA/RI Import (N-1) - - - 786 1,280(e) 1,280 1,280 1,280 1,280 1,280 SEMA/RI Import (N-1-1) - - - 473 720(e) 720 720 720 720 720 Southeast New England Import (N-1) - - - - 5,700 5,700 5,700 5,700 5,700 5,700 Southeast New England Import (N-1-1) - - - - 4,600 4,600 4,600 4,600 4,600 4,600 Connecticut Import (N-1) 3,050 2,950(d) 2,950 2,950 2,950 2,950 2,950 2,950 2,950 2,950 Connecticut Import (N-1-1) 1,850 1,750(d) 1,750 1,750 1,750 1,750 1,750 1,750 1,750 1,750 SW Connecticut Import (N-1) 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200 SW Connecticut Import (N-1-1) 2,300 2,300 2,300 2,300 2,300 2,300 2,300 2,300 2,300 2,300 Norwalk–Stamford No limit for each year
Please see Table 4-8 in RSP15 at: http://www.iso-ne.com/committees/planning/planning-advisory
23 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a RSP 15 Internal Transmission Interface Limits (cont.) (a) The transmission interface limits are single-value, summer peak (except where noted to be winter), for use in subarea transportation models. The limits may not include possible simultaneous impacts and should not be considered as “firm.” (The bases for these limits will be subject to more detailed review.) For the years within the FCM horizon (2019, FCA #10 and sooner), only accepted certified transmission projects are included when identifying transfer limits. Certified transmission projects were presented to the Reliability Committee at their January 27, 2015, meeting (http://www.iso- ne.com/committees/reliability/reliability-committee). For the years beyond the FCM horizon (2020 and later), proposed plan approved transmission upgrades are included according to their expected in-service dates. (b) The North–South transfer capabilities reflect the retirements of Brayton Point and Vermont Yankee. (c) The ISO has accepted the certification of the Greater Boston upgrades project (see Section 6.4.2.1) to be in service by June 2019. (d) The ISO has accepted the certification of the New England East–West Solution (NEEWS) Interstate Reliability Program (IRP) (see Sections 6.4 and 6.5) to be in service by December 2015. (e) In response to the Brayton Point retirement, the following Rhode Island area facilities are now planned to be upgraded (and are certified to be in service by the start of the tenth capacity commitment period ((i.e., by June 1, 2019): The V148N 115 kV line between Woonsocket and Washington, the West Farnum 345/115 kV autotransformer upgrade (already in service), and the Kent County 345/115 kV autotransformer (already in service).
24 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a RSP 15 External Transmission Interface Limits
Year Interface(a) 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 New Brunswick–New England 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 (energy import capability)(b) New Brunswick–New England 700 700 700 700 700 700 700 700 700 700 (capacity import capability) HQ-NE (Highgate) 217 217 217 217 217 217 217 217 217 217 (energy import capability)(c) HQ-NE (Highgate) 200 200 200 200 200 200 200 200 200 200 (capacity import capability) HQ-NE (Phase II) 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 (energy import capability)(d) HQ-NE (Phase II) 1,400 1,400 1,400 1,400 1,400 1,400 1,400 1,400 1,400 1,400 (capacity import capability) Cross–Sound Cable (CSC) 330 330 330 330 330 330 330 330 330 330 (energy import capability)(e) CSC 0 0 0 0 0 0 0 0 0 0 (capacity import capability)
New York–New England (NY–NE) 1,400 1,400 1,400 1,400 1,400 1,400 1,400 1,400 1,400 1,400 (energy transfer capability)(f)
NY–NE 1,400 1,400 1,400 1,400 1,400 1,400 1,400 1,400 1,400 1,400 (capacity transfer capability)
Please see Table 4-9 in RSP15 at: http://www.iso-ne.com/committees/planning/planning-advisory
25 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a RSP 15 External Transmission Interface Limits (cont.) (a) The transmission interface limits are single-value, summer peak (except where noted to be winter), for use in subarea transportation models. The limits may not include possible simultaneous impacts and should not be considered as “firm.” (The bases for these limits will be subject to more detailed review.) For the years within the FCM horizon (2019, FCA #10 and sooner), only accepted certified transmission projects are included when identifying transfer limits. Certified transmission projects were presented to the Reliability Committee at their January 27, 2015, meeting (http://www.iso- ne.com/committees/reliability/reliability-committee). For the years beyond the FCM horizon (2020 and later), proposed plan approved transmission upgrades are included according to their expected in-service dates. (b) The electrical limit of the New Brunswick–New England (NB–NE) tie is 1,000 MW. When adjusted for the ability to deliver capacity to the ISO New England Balancing Authority Area, the NB–NE transfer capability is 700 MW because of downstream constraints, in particular, Orrington South. (c) The capability for the Highgate facility is listed at the New England AC side of the Highgate terminal. (d) The HQICC interconnection is a DC tie with equipment ratings of 2,000 MW. The PJM and NYISO systems may be constrained by the loss of this line. As a result, ISO New England has assumed that its transfer capability is 1,400 MW for capacity and reliability calculations. This assumption is based on the results of loss-of-source analyses conducted by PJM and NYISO. (e) The import capability on the CSC is dependent on the level of local generation. (f) The New York interface limits are without the CSC and with the Northport–Norwalk Cable at 0 MW flow. Simultaneously importing into New England and SWCT or CT can lower the NY–NE capability (very rough decrease = 200 MW). Conversely, simultaneously exporting to NY and importing to SWCT or CT can lower the NE–NY capability (very rough decrease = 700 MW).
26 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Interconnected System Representation
Quebec Chur. 5,200 JB Maritimes 2,250 MAN PEI 15,000 12,900 222 900 S 124 ND 1,200 S 1,000 W 0 W Que 685 S NB 150 Cent. 720 W 9,999 350 NS
2,138 NM 22,290 550 Mtl 1,000 100
Cedars 700 1 1,500 New 190 1,400 BHE D 200 York 0 A 0 VT G 600 CMA C F 800 800 1,000 200 800 J W- J2 MA 550 2,000 K 330 800 0 CT 1,500 660 428 200 300 0 1,000 660 New 1,000 NOR Equivalent England 500 for PJM- 1,400 1,400 NY Total NY-NE boundary (Excludes CSC)
27 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a New York System Representation
To Cedars 0 To Quebec 1,000 To VT
1,500 2,750 - 800 800 D 0 CE Group 3,250* F To WMA 3,400 4,800 1,600 1,999 UPNY-SENY AG 2,650 800 - 2,875* 1,999 3,475 1,999 1,999 1,999 5,600 1,300 9,999 A B C E 1,600 2,150 600 800 1,300 5,650 G To CT Total East 1,000 1,999 800 200 1,999 6,750 0 5,210 550 1,000 RECO 1,000 H 300 200 1,000 PJM East-G&J 1,999 8,450 1,000 J2 LI Sum 400 – 1,500 2,000 DSY49Y50 1,000 0 I 144 – Equivalent 1,000* 1,525 1,999 344 * for PJM-NY 200 – 815* 1,999 5,160 boundary 815 J3 530
500 400 - 1,000 * 0 4,400 1,290 330 CSC 660 200 – 815 * J K 388 - 428 * 283- 235 510 * 0 To NOR 660 LI West * Rating a function of unit availabilities and/or area loads. (I to K) + (J to K) - 199 99,999 0.13(PJM to K)
28 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a New England System Representation To NB
To East – West 550 3,500/2,200 Quebec To 100 Highgate Quebec NB - NE
200 1,200 S ME - NH VT 0 W Surowiec Orrington South 0 Phase II South 0 700 To D 1,900
SME ME BHE Total NY-NE 1,500 1,325 (Excludes NH CSC) North – South 2,675
1,400 1,400 Southeast Import 5,700 (relaxed in the study) 1,400 Boston Boston Import To F 800 800 5,700 CMA/ WMA NEMA
To G 600
To K 800 330 (CSC) CT RI SEMA 0 Connecticut (Excludes CSC) Norwalk - Stamford 2,950 1,650 In SEMA/RI Export SEMA Export SWCT 3,400/1280 NOR 9,999 388 – 428 * 0 Southwest CT Import To K 3,200 * Rating a function of unit availabilities and/or area loads.
29 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Other Assumptions
• Emergency Operating Procedures – New England • 2,375 MW of system-wide operating reserve assumed – Allowed to deplete to a minimum of 200 MW as OP-4 procedures progress prior to firm load shedding • Local reserve requirements are based on the latest forward reserve market requirements – CT: 714 MW (summer); 363 MW (winter) – SWCT: 138 MW (summer); 87 MW (winter) – BOSTON: 331 MW (summer); 0 MW (winter) • Voltage reductions – Consistent with the ICR calculation, and the amount for subareas calculated as • (90/10 Subarea Coincident Peak Load MW – Subarea DR MW with a system-wide RTEG limited to 600 MW) * 1.5% – Other Areas • Consistent with their latest model in NPCC studies
30 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a
Imports used for Tie Benefits Adjustments
Hydro- Quebec New New York AC Phase I/II HQ Name Highgate Brunswick Ties Excess NYPA - CMR 68.8 NYPA - VT 14 VJO - Highgate 6 VJO - Phase I/II Total 6 0 82.8 0
31 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Study Methodology Calculation Process
• Process 1.0 – Calculate the tie benefits values for all possible interconnection states using isolated New England system as the reference • Process 2.0 – Calculate initial total tie benefits for New England from all neighboring control areas • Process 3.0 – Calculate initial tie benefits for each individual neighboring control area – Pro-rate tie benefits values of individual control areas based on the total tie benefits, if necessary • Process 4.0 – Calculate initial tie benefits for individual interconnection or group of interconnections – Pro-rate tie benefits values of individual interconnection or group of interconnections based on the individual control area tie benefits, if necessary • Process 5.0 – Adjust tie benefits of individual interconnection or group of interconnections to account for capacity imports • Process 6.0 – Calculate the final tie benefits for each individual neighboring control area • Process 7.0 – Calculate the final total tie benefits for New England
32 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Study Methodology Calculation Process 1.0
• Calculation of tie benefits values for all possible interconnection states – Bring all interconnected areas to LOLE of 0.1 days/year simultaneously – Calculate New England’s LOLE for all the possible interconnection states, e.g. • with no interconnections (isolated state) • With any single interconnection only • With any of two interconnections • With any of three interconnections • … – Calculate the equivalent tie benefits values for each interconnection state using the isolated state as reference • As the equivalent MW to bridge the LOLE delta between these two states
33 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Study Methodology Calculation Process 2.0
• Calculation of total tie benefits for New England – Compare the following two interconnection states • New England system with all interconnections to neighboring control areas connected • New England System with all interconnections with neighboring Control Areas disconnected
– Total tie benefits for New England is the equivalent MW value to bridge the LOLE delta between these two states
– This initial total tie benefits value is subject to adjustment to account for capacity imports in the later process.
34 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Study Methodology Calculation Process 3.0
• Calculation of initial tie benefits for each individual neighboring control area – all interconnections connected to a given neighboring control area are grouped together to represent the state of interconnection between New England and that neighboring control area – For each target neighboring control area, identify all the related interconnection states and calculate the equivalent tie benefits values for each of these states • With a total of three neighboring control areas, there are four interconnection states for each neighboring area • Use the simple average of values for all the interconnection states to represent the tie benefits of the target neighboring control area – If the sum of the individual control area tie benefits calculated above is different than the total tie benefits calculated in Process 2.0, each control area’s tie benefits shall be adjusted based on the ratio of the individual control area tie benefits to the total tie benefits – These initial individual control area tie benefits are subject to further adjustment to account for capacity imports in the later process.
35 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Study Methodology Calculation Process 4.0
• Calculation of preliminary tie benefits for individual interconnection or group of interconnections – Each individual interconnection or group of interconnections subject to individual tie benefits contribution calculation is treated independently. – For each target interconnection or group of interconnections, identify all the related interconnection states and calculate the equivalent tie benefits values for each of these states • Use the simple average of values for all the interconnection states to represent the tie benefits of the target interconnection or group of interconnections – If the sum of the individual interconnection’s or group of interconnection’s tie benefits calculated above is different than the relative control area’s tie benefits calculated in Process 3.0, tie benefits of the individual interconnection or group of interconnections shall be adjusted ratio of the tie benefits of the individual interconnection or group of interconnections to the relative control area’s tie benefits – These initial individual interconnection’s or group of interconnection’s tie benefits are subject to further adjustment to account for capacity imports in the later process.
36 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Study Methodology Calculation Process 5.0
• Adjustment to the initial tie benefits for individual interconnection or group of interconnections – Deduct capacity imports from the import capability of each individual interconnection or group of interconnections to determine the remaining available import capability to support tie benefits • Capacity imports are the Qualified Existing Import Capacity for FCA 2014/15
– Compare the tie benefits value of an individual interconnection or group of interconnections as determined in Process 4.0 to its remaining transmission import capability • If the tie benefits value is greater than the remaining transmission import capability, the tie benefit value of the individual interconnection or group of interconnections is capped to the remaining transmission import capability
• Otherwise, no adjustments are made.
37 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Study Methodology Calculation Process 6.0
• Determination of tie benefits for individual neighboring control area
– Final tie benefits for each neighboring control area are the sum of the tie benefits from the individual interconnections or groups of interconnections with that control area, after accounting for any adjustment for capacity imports as determined in Process 5.0
38 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a Study Methodology Calculation Process 7.0
• Determination of total tie benefits for New England
– Final total tie benefits from all neighboring control areas are the sum of the control area tie benefits after accounting for any adjustment for capacity imports as determined in Process 6.0.
39 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a
40 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b RELIABILITY COMMITTEE
SEPTEMBER 15, 2015 | WESTBOROUGH MA
Proposed Installed Capacity Requirement (ICR) Values for the 2019/20 Forward Capacity Auction (FCA10)
Maria Scibelli NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b
Objective of this Presentation • Review the ICR review and FERC filing schedules • Review the proposed ICR Values* including: – Installed Capacity Requirement (ICR)
– For the Southeast New England (SENE) Capacity Zone (combined Load Zones of NEMA/Boston, SEMA and RI) • Transmission Security Analysis (TSA), • Local Resource Adequacy Requirement (LRA), • Local Sourcing Requirement (LSR)
– Capacity requirement values for the System-Wide Capacity Demand Curve (Demand Curve)
*The ICR, LSR and the Demand Curve capacity requirements are collectively the ICR Values.
2 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b
Capacity Zone Locational Requirements
– SENE was determined to be an import-constrained Capacity Zone in the Objective Criteria analysis presented to the PSPC on June 30, 2015
– The Connecticut Load Zone was determined not to be import-constrained and will not be modeled as a Capacity Zone for FCA10
• Presentation for both analyses available at: http://www.iso-ne.com/static- assets/documents/2015/06/fca10_zone_formation.pdf
– The combined Maine, New Hampshire and Vermont Load Zones (Northern New England (NNE)) will not be modeled as a Capacity Zone for FCA10 because NNE did not meet the export-constrained Capacity Zone Objective Criteria. This analysis was presented to the PSPC on August 14, 2015.
• Presentation available at: http://www.iso-ne.com/static- assets/documents/2015/08/pspc_081415_a3.0_fca10_zone_formation2.pdf
3 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b
ICR Review and FERC Filing Schedule
• ICR Values for 2019/20 Forward Capacity Auction (FCA10) – PSPC reviewed Capacity Zone determinations – Jun 30 & Aug 14, 2015 – PSPC reviewed ICR assumptions – May 28, Jun 30 & Jul 23, 2015 – PSPC reviewed ISO recommendation of ICR Values – Aug 27, 2015 – RC review/vote of ISO recommendation of ICR Values – Sep 15, 2015 – PC review/vote of ISO recommendation of ICR Values – Oct 2, 2015 – File with the FERC – by Nov 10, 2015 – FCA10 begins – Feb 8, 2016
4 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b
PROPOSED ICR VALUES FOR THE 2019/20 FCA
5 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b ISO Proposed ICR Values for the 2019/20 FCA (MW)
Southeast New New 2019/20 FCA England England Peak Load (50/50) 29,861 12,282 Existing Capacity Resources* 33,484 11,194 Installed Capacity Requirement 35,126 NET ICR (ICR Minus 975 MW HQICCs) 34,151 1-in-5 LOLE Demand Curve capacity value 33,076 1-in-87 LOLE Demand Curve capacity value 37,053 Local Sourcing Requirement 10,028
• *Existing Capacity Resources are the Existing Qualified capacity resources for FCA10 at the time of the calculation and reflect early June terminations. • In addition to the Existing Capacity Resources shown, 800 MW of proxy units are required for the ICR calculation and 3,600 MW for the 1-in-87 LOLE Demand Curve capacity requirement value calculation.
6 NEPOOL PARTICIPANTS COMMITTEE Comparison of ICR Values (MW) OCT 2, 2015 MEETING, AGENDA ITEM #6.b - 2019/20 (FCA10) Vs 2018/19 (FCA9)
Southeast New New England England 2019/20 2018/19 2019/20 2018/19 FCA FCA FCA FCA
Peak Load (50/50) 29,861 30,005 12,282 -
Existing Capacity Resources* 33,484 32,842 11,194 -
Installed Capacity Requirement 35,126 35,142
NET ICR (ICR Minus HQICCs) 34,151 34,189
1-in-5 LOLE Demand Curve capacity value 33,076 33,132
1-in-87 LOLE Demand Curve capacity value 37,053 37,027
Local Resource Adequacy Requirement 9,584 -
Transmission Security Analysis Requirement 10,028 -
Local Sourcing Requirement 10,028 - • *Existing Capacity Resources are the Existing Qualified capacity resources for FCA10 at the time of the calculation and reflect early June terminations. • In addition to the FCA10 Existing Capacity Resources shown, 800 MW of proxy units are required for the ICR calculation and 3,600 MW for the 1-in-87 LOLE Demand Curve capacity requirement value calculation.
• For details on the FCA9 (2018/19) ICR Values calculation see: http://www.iso-ne.com/static-assets/documents/2014/09/a6_fca9_icr_values.pdf.
7 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b ICR Calculation Details Total Capacity Breakdow n 1-in-5 2019/20 FCA ICR 1-in-87 Generating Resources 30,654 30,654 30,654 Tie Benefits 1,990 1,990 1,990 Imports/Sales (41) (41) (41) Demand Resources 2,871 2,871 2,871 OP4 - Action 6 & 8 (Voltage Reduction) 442 442 442 Minimum Reserve Requirement (200) (200) (200) Proxy Unit Capacity - 800 3,600 Total Capacity 35,716 36,516 39,316
Installed Capacity Requirement Calculation Details 1-in-5 2019/20 FCA ICR 1-in-87 Annual Peak 29,861 29,861 29,861 Total Capacity 35,716 36,516 39,316 Tie Benefits 1,990 1,990 1,990 HQICCs 975 975 975 OP4 - Action 6 & 8 (Voltage Reduction) 442 442 442 Minimum Reserve Requirement (200) (200) (200) ALCC 368 116 25 Installed Capacity Requirements 34,051 35,126 38,028 Ne t ICR 33,076 34,151 37,053
Reserve Margin with HQICCs 14.0% 17.6% 27.3% Reserve Margin without HQICCs 10.8% 14.4% 24.1%
Capacity − Tie Benefits − OP4 Load Relief Installed Capacity Requirement (ICR) = + HQICCs ALCC 1 + APk
• All values in the table are in MW except the Reserve Margin shown in percent. • ALCC is the “Additional Load Carrying Capability” used to bring the system to the target Reliability Criterion.
8 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b Cost of New Entry (CONE) - for the System-Wide Capacity Demand Curve
• CONE for the Cap of the Demand Curve for FCA10 has been calculated as: – Gross CONE = $14.29/kW-month – Net CONE = $10.81/kW-month • Price cap of the Demand Curve is determined as: Max (1.6 x Net CONE, Gross CONE) • Price at the Demand Curve Cap = $17.296/kW-month
9 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b System-Wide Capacity Demand Curve for FCA10
Net ICR $20
$15
$10 month) -
$5 Price ($/kW $0 30,000 31,000 32,000 33,000 34,000 35,000 36,000 37,000 38,000
Capacity Requirement (MW)
Cap [1-in-5 LOLE Demand Curve capacity value = 33,076 MW, $17.296]
Foot [1-in-87 LOLE Demand Curve capacity value = 37,053 MW, $0]
10 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b
Effect of Updated Assumptions on ICR
Effect on Assumption 2019/2020 FCA 2018/2019 FCA ICR (MW) 354 MW New York 346 MW New York 519 MW Maritimes 523 MW Maritimes Tie Benefits 975 MW Quebec (HQICCs) 953 MW Quebec (HQICCs) 8 142 MW Quebec via Highgate 148 MW Quebec via Highgate Total 1,990 MW* 1,970 MW Weighted Forced Weighted Forced MW Outage MW Outage Generation & IPR 30,524 6.7% 29,699 6.5% 136 Demand Resources 2,871 2.5% 3,054 4.0% -42 Imports 89 0.0% 89 0.0% - MW MW Load Forecast - Reference 29,861 30,005 -56 MW % MW % OP 4 5% VR 442 1.50% 441 1.50% - MW MW ICR 35,126 35,142 -16
• Methodology: Using the resources associated with the 2018/19 FCA ICR calculation, change one assumption at a time and note the change in ICR. * The difference in Net ICR (ICR minus HQICCS) due to the change in tie benefits is -14 MW.
11 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b
LRA – SENE
Local Resource Adequacy Requirement - SENE
Southeast New England Capacity Zone 2019/20 FCA 2018/19 FCA
Resourcez [1] 11,194 -
Proxy Units z [2] 0 -
Firm Load Adjustmentz [3] 1,482 -
FORz [4] 0.079 -
LRAz [5]=[1]+[2]-([3]/(1-[4])) 9,584 - Rest of New England Zone Resource [6] 22,290 - Proxy Units [7] 800 - Firm Load Adjustment [8] = -[3] -1,482 - Total System Resource [9]=[1]+[2]-[3]+[6]+[7]-[8] 34,284 -
• All values in the table are in MW except the FORz
12 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b
TSA Requirement - SENE
FCA10 TSA Requirement for SENE
Sub-area 2015 90/10 Load* 13,342 Reserves (Largest unit) 1,413
Sub-area Transmission Security Need 14,755
Existing Resources** 11,194 Assumed Unavailable Capacity -1,086 Sub-area N-1 Import Limit 5,700
Sub-area Available Resources 15,808
TSA Requirement (14755-5700)/(1-1086/11194) = 10,028
*Behind the Meter not Embedded in the Load Forecast (BTMNEL) PV is modeled as a reduction to the load forecast **The 2019-20 Qualified Existing Capacity amount as of 06/04/2015 NOTE: All values have been rounded off to the nearest whole number 13 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b
14 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b
ASSUMPTIONS FOR CALCULATING THE ICR VALUES FOR THE 2019/20 FCA NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b
Modeling the New England Control Area
The GE MARS model is used to calculate the ICR and Related Values – Internal transmission constraints are not modeled in the ICR calculation. All loads and resources are assumed to be connected to a single electric bus.
– Internal transmission constraints are addressed through LSR and MCL
– LSR was calculated for the SENE Capacity Zone
– The Demand Curve capacity values are the capacity requirement values net of Hydro-Quebec Interconnection Capability Credits (HQICCs) at the cap and foot of the System-Wide Capacity Demand Curve and are calculated at 1-in-5 Loss of Load Expectation (LOLE) and 1-in-87 LOLE, respectively.
16 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b Assumptions for the ICR Calculations • Load Forecast – Load Forecast distribution – Net of Behind the Meter not Embedded in the Load Forecast (BTMNEL) Photovoltaic (PV) resource forecast • Resource Data Based on Existing Qualified Capacity Resources for FCA10 (reflects terminations which occurred in June 2015) – Generating Capacity Resources – Intermittent Power Capacity Resources (IPR) – Import Capacity Resources – Demand Resources (DR) • Resource Availability – Generating Resources Availability – Intermittent Power Resources Availability – Demand Resources Availability • Load Relief from OP 4 Actions – Tie Reliability Benefits • Quebec • Maritimes • New York – 5% Voltage Reduction
17 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b
Load Forecast Data • Load forecast assumption from the 2015 CELT Report Load Forecast
• The load forecast weather related uncertainty is represented by specifying a series of multipliers on the peak load and the associated probabilities of each load level occurring – derived from the 52 weekly peak load distributions described by the expected value (mean), the standard deviation and the skewness.
18 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b Modeling of PV in ICR (MW)
Month 2019/2020 Jun 367.1 Jul 369.2 Aug 371.4 Sep 373.8 Oct 0 Nov 0 Dec 0 Jan 0 Feb 0 Mar 0 Apr 0 May 389.3 • Table shows the monthly sum of Seasonal Claimed Capability (SCC) of BTMNEL PV resources modeled in ICR (includes 8% Transmission & Distribution Gross-up) • Developed using 40%* of PV nameplate forecast from the Distributed Generation Forecast Working Group (DGFWG) • Modeled as a load modifier in GE MARS by Regional System Plan (RSP) 13-subarea representation for hours ending 14:00 – 18:00 * 40% value based on 3 years of historical PV resource ratings during reliability hours
19 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b Load Forecast Data – New England System Load Forecast
Monthly Peak Load (MW) – 50/50 Forecast
Year Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May 2019/20 26,508 29,861 29,861 24,276 19,190 20,955 23,430 23,430 22,160 20,370 18,410 21,021
Probability Distribution of Annual Peak Load (MW)
Year 10/90 20/80 30/70 40/60 50/50 60/40 70/30 80/20 90/10 95/5 2019/20 28,686 28,951 28,996 29,406 29,861 30,341 30,831 31,541 32,341 33,051
• Corresponds to the reference forecast labeled “1.2 REFERENCE - With reduction for BTM PV“ from section 1.1 of the 2015 CELT Report.
20 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b Load Forecast Assumption Comparisons (MW) (Uses the Same Capacity Resources in All Model Runs)
Model Run 1 Model Run 2 Correspond- Correspond- Load ing 50/50 Load ing 50/50 Forecast Peak Load Forecast Peak Load Effect on Comparison CELT Year Load Year (MW) CELT Year Load Year (MW) ICR (MW) Different CELT forecasts and different years [to flush out year over year load growth and changes in the different forecasts] 2015 2019/20 30,230 2014 2018/19 30,005 323
Different CELT forecast for the same year [to flush out level changes in the different forecasts] 2015 2018/19 29,825 2014 2018/19 30,005 -132
Different CELT Load Forecast Uncertainty (LFU) only [reflects increased standard deviation in 2015 CELT forecast] 2015 (LFU) 2018/19 30,005 2014 (LFU) 2018/19 30,005 154
Same CELT forecast and for 2019/20 with and without reflecting BTMNEL PV [Net versus Gross load forecast] 2015 2019/20 29,861 2015 2019/20 30,230 -392
• These comparisons attempt to gauge the change in ICR attributed to the load forecast: such as year over year change, level change in the load forecast, load forecast uncertainty and the effect of incorporating the reduction in the load forecast for BTMNEL PV resources. • Methodology: Using the resources associated with the 2018/19 FCA ICR model, change the load forecast assumptions and note the change in ICR. • The 50/50 peak load forecasts shown here are to aid in comparisons; the models see a distribution of weekly peak loads and corresponding load forecast uncertainty for each CELT load forecast. • These results, presented in a similar table, were reviewed with the PSPC at the August 27, 2015 meeting.
21 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b
Resource Data – Generating Capacity Resources (MW)
Non-Intermittent Generation Intermittent Generation Total Load Zone Summer Winter Summer Winter Summer Winter MAINE 2,863.774 3,018.330 292.832 401.878 3,156.606 3,420.208 NEW HAMPSHIRE 4,043.605 4,267.015 157.295 215.912 4,200.900 4,482.927 VERMONT 222.098 262.716 71.780 124.302 293.878 387.018 CONNECTICUT 9,063.732 9,543.325 172.684 188.939 9,236.416 9,732.264 RHODE ISLAND 1,867.339 2,069.400 3.372 5.220 1,870.711 2,074.620 SOUTH EAST MASSACHUSETTS 4,683.952 5,110.589 83.314 78.057 4,767.266 5,188.646 WEST CENTRAL MASSACHUSETTS 3,732.636 3,986.982 66.670 97.066 3,799.306 4,084.048 NORTH EAST MASSACHUSETTS & BOSTON 3,227.714 3,649.635 71.172 72.260 3,298.886 3,721.895 Total New England 29,704.850 31,907.992 919.119 1,183.634 30,623.969 33,091.626
• Existing Qualified generating capacity resources for FCA10 • Intermittent resources have both summer and winter values modeled; non-Intermittent winter values provided for informational purpose • Reflects the terminations of resources in early June and a 30 MW derating to reflect the firm contract value of the Vermont Joint Owners (VJO) contract
22
NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b Resource Data – Import Capacity Resources (MW)
Qualified Summer Import Resource MW External Interface VJO - Highgate 6.000 Hydro-Quebec Highgate NYPA - CMR 68.800 New York AC Ties NYPA - VT 14.000 New York AC Ties Total MW 88.800
• Existing Qualified Import capacity resources for FCA10 • A 30 MW derating is applied to Citizens Block Load (modeled as a generator) to reflect the value of the VJO contract • All are system-backed imports modeled with 100% resource availability
23 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b Resource Data – Export Delist (MW)
Export Summer MW LIPA via CSC 100.000
• Based on Administrative Delist Bid • Modeled as removed capacity from the resource supplying the export
24 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b Resource Data – Demand Resources (MW)
On-Peak Seasonal Peak RT Demand Response RT Emergency Gen Total Load Zone Summer Winter Summer Winter Summer Winter Summer Winter Summer Winter MAINE 164.811 162.115 - - 149.386 167.281 7.482 5.198 321.679 334.594 NEW HAMPSHIRE 101.215 80.645 - - 12.798 12.078 14.022 12.045 128.035 104.768 VERMONT 120.090 111.095 - - 31.900 39.833 4.918 4.357 156.908 155.285 CONNECTICUT 78.815 56.637 371.437 341.026 77.374 75.541 52.941 52.427 580.567 525.631 RHODE ISLAND 197.599 187.599 - - 60.362 56.831 15.720 11.329 273.681 255.759 SOUTH EAST MASSACHUSETTS 292.685 259.806 - - 51.987 50.112 12.722 12.722 357.394 322.640 WEST CENTRAL MASSACHUSETTS 293.340 266.117 49.645 33.939 58.684 53.826 25.098 24.544 426.767 378.426 NORTH EAST MASSACHUSETTS & BOSTON 548.466 506.968 - - 67.329 67.329 10.439 10.211 626.234 584.508 Total New England 1,797.021 1,630.982 421.082 374.965 509.820 522.831 143.342 132.833 2,871.265 2,661.611
• Existing Qualified Demand Resource capacity for FCA10 • Includes the Transmission and Distribution (T&D) Loss Adjustment (Gross-up) of 8% • Reflects terminations of resources in early June
25 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b LSR Internal Transmission Transfer Capability Assumptions (MW) • Transfer Limits – 2015 Regional System Plan (RSP) for 2019/20 – Internal Transmission Transfer Capability • Southeast New England Import – N-1 Limit: 5,700 MW – N-1-1 Limit: 4,600 MW
Includes: • the New England East West Solution (NEEWS) Interstate Reliability Program – the certification of this project to be in service by December 2015 has been accepted by ISO New England • the Greater Boston Upgrades - the certification of this project to be in service by June 2019 has been accepted by ISO New England • upgrades to Rhode Island facilities which are certified for FCA10 in response to the Brayton Point retirement
26 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b Sub-area Resource and 50/50 Peak Load Forecast Assumptions Used in LRA Calculations (MW) Southeast New England Total New Resource Type (SENE) England Generator 9,779.005 29,604.850 Intermittent Generator 157.858 919.119 Import - 88.800 On-Peak DR 1,038.750 1,797.021 Seasonal-Peak DR - 421.082 Real-Time DR 179.678 509.820 Real-Time Emergency Gen DR 38.881 143.342 Total 11,194.172 33,484.034
SENE New England 50/50 Load Forecast Net BTMNEL PV 12,282 29,861
• Generating resource assumptions are based on the RSP sub-areas, used as a proxy for the Load Zones as the transmission transfer capability is determined using the RSP 13 sub-areas. DR values are the Load Zone values. • Generating resources for New England reflects the 100 MW export and 30 MW derating to reflect the value of the firm VJO contract • For the SENE Capacity Zone, the sum of the Load Zone resources equals the corresponding RSP sub-areas. The 50/50 load forecast value shown is the sum of the corresponding RSP sub-areas.
27 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b Availability Assumptions - Generating Resources • Forced Outages Assumption – Each generating unit’s Equivalent Forced Outage Rate on Demand (non- weighted EFORd) modeled – Based on a 5-year average (Jan 2010 – Dec 2014) of generator submitted Generation Availability Data System (GADS) data – NERC GADS Class average data is used for immature units
• Scheduled Outage Assumption – Each generating unit weeks of Maintenance modeled – Based on a 5-year average (Jan 2010 – Dec 2014) of each generator’s actual historical average of planned and maintenance outages scheduled at least 14 days in advance – NERC GADS Class average data is used for immature units
28 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b Availability Assumptions - Generating Resources
Assumed Average Assumed Average Maintenance Weeks EFORd (%) Weighted Weighted by Summer Resource Category Summer MW by Summer Ratings Ratings Combined Cycle 13,279 4.0 5.4 Fossil 6,087 15.9 5.1 Nuclear 4,024 2.5 4.5 Hydro (Includes Pumped Storage) 2,903 4.9 4.4 Combustion Turbine 3,171 9.4 2.5 Diesel 190 7.3 1.0 Miscellaneous 51 16.1 3.8 Total System 29,705 6.9 4.8
• Assumed summer MW weighted EFORd and Maintenance Weeks are shown by resource category for informational purposes. In the LOLE simulations, individual unit values are modeled.
29 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b Availability Assumptions - Intermittent Power Resources
• Intermittent Power Resources are modeled as 100% available since their outages have been incorporated in their 5-year historical output used in their ratings determination.
30 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b Demand Resource Availability
On-Peak Seasonal Peak RT Demand Response RT Emergency Gen Total Summer Perform- Summer Perform- Summer Perform- Summer Perform- Perform- Load Zone (MW) ance (MW) ance (MW) ance (MW) ance Summer ance MAINE 164.811 100% - - 149.386 99% 7.482 92% 321.679 99% NEW HAMPSHIRE 101.215 100% - - 12.798 88% 14.022 97% 128.035 98% VERMONT 120.090 100% - - 31.900 97% 4.918 82% 156.908 99% CONNECTICUT 78.815 100% 371.437 100% 77.374 83% 52.941 87% 580.567 97% RHODE ISLAND 197.599 100% - - 60.362 83% 15.720 91% 273.681 96% SOUTH EAST MASSACHUSETTS 292.685 100% - - 51.987 78% 12.722 83% 357.394 96% WEST CENTRAL MASSACHUSETTS 293.340 100% 49.645 100% 58.684 90% 25.098 89% 426.767 98% NORTH EAST MASSACHUSETTS & BOSTON 548.466 100% - - 67.329 83% 10.439 90% 626.234 98% Total New England 1797.021 100% 421.082 100% 509.820 89% 143.342 89% 2,871.265 97%
• Uses historical DR performance from summer & winter 2010 – 2014. See presentation at: http://www.iso- ne.com/static-assets/documents/2015/05/2015_DR_availability.pdffor more information. • Modeled by zones and type of DR with outage factor calculated as 1- performance/100
31 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b FCA10 TSA Requirements Assumptions – Detailed Assumptions
• Load Forecast Data – 2015 CELT forecast adjusted for PV forecast* • SENE sub-area 90/10 peak load: 13,342 MW • Resource Data – 2019-20 Existing Capacity Qualification data as of June 4, 2015 • Generating capacity: 9,937 MW – Includes 9,237 MW of regular generation resources, 158 MW of intermittent generation resources and 542 MW of peaking generation resources • Passive Demand Resources: 1,039 MW • Non-RTEG Active Demand Resources: 180 MW • Real-Time Emergency Generation: 39 MW
*Behind the Meter not Embedded in the Load Forecast (BTMNEL) PV is modeled as a reduction to the load forecast NOTE: All values have been rounded off to the nearest whole number
32 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b FCA10 TSA Requirements Assumptions – Detailed Assumptions, cont.
• Resource Unavailability Assumptions – Regular Generation Resources - Weighted average EFORd • SENE sub-area: 10% – Peaking Generation Resources - Operational de-rating factor: 20% – Passive Demand Resources: 0% – Non-RTEG Active Demand Resources - De-rating based on performance factors • Boston sub-area: 17% • SEMA sub-area: 23% • RI sub-area: 17% – Real-Time Emergency Generation - De-rating based on performance factors • Boston sub-area: 10% • SEMA sub-area: 17% • RI sub-area: 9% NOTE: All values have been rounded off to the nearest whole number
33 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b Proxy Unit Characteristics
• Proxy unit characteristics based on a study conducted in 2014 using the 2017/18 FCA8 ICR Model • Current proxy unit characteristics: – Proxy unit size equal to 400 MW – EFORd of proxy unit = 5.47% – Maintenance requirement = 4 weeks
• Proxy unit characteristics are determined using the average system availability and a series of LOLE calculations. By replacing all system capacity with the correct sized proxy units, the system LOLE and resulting capacity requirement unchanged.
• The 2014 Proxy Unit Study was reviewed at the May 22, 2014 PSPC Meeting and is available at: http://www.iso-ne.com/static- assets/documents/committees/comm_wkgrps/relblty_comm/pwrsuppln_comm/mtrls/2014/may222014/proxy_unit_2014_s tudy.pdf
34 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b OP 4 Assumptions - Action 6 & 8 - 5% Voltage Reduction (MW)
Action 6 & 8 90-10 Peak 5% Voltage Load Pa ssive DR RTDR RTEG Reduction Jun 2019 - Sep 2019 32,341 2,218 510 143 442 Oct 2019 - May 2020 24,085 2,006 523 133 321
• Uses the 90-10 Peak Load Forecast minus BTMNEL PV and all Passive & Active DR • Multiplied by the 1.5% value used by ISO Operations in estimating relief obtained from OP4 voltage reduction
35 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b OP 4 Assumptions - Tie Benefits (MW)
• Based on the results of the 2019/20 Tie Benefits Study (with NNE not a zone)
Control Area 2019/20 FCA10 Québec via Phase II 975 Québec via Highgate 142 Maritimes 519 New York 354 Total Tie Benefits 1,990
• Modeled in the ICR calculations with the tie line availability assumptions shown below:
Forced Outage Rate Maintenance External Tie (%) (Weeks) HQ Phase II 0.39 2.7 Highgate 0.07 1.3 New Brunswick Ties 0.08 0.4 New York AC Ties 0 0 Cross Sound Cable 0.89 1.5
36 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b OP 4 Assumptions - Minimum Operating Reserve Requirement(MW)
• Minimum Operating Reserve is the 10-Minute minimum Operating Reserve requirement for ISO Operations
• Modeled at 200 MW in the ICR calculation
37 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b Summary of all MW Modeled in the ICR Calculations (MW)
Type of Resource/OP 4 2019/20 FCA Generating Resources 29,734.850 Intermittent Power Resources 919.119 Demand Resources 2,871.265 Import Resources 88.800 Export Delist (100.000) Import Deratings (30.000) OP 4 Voltage Reduction 442.000 Minimum Operating Reserve (200.000) Tie Benefits (with 975 MW of HQICCs) 1,990.000 Proxy Units 800.000 Total MW Modeled in ICR 36,516.034
Notes:
• Intermittent Power Resources have both the summer and winter capacity values modeled
• Import deratings reflect the value of the firm VJO contract
• OP 4 Voltage Reduction includes both Action 6 and Action 8 MW assumptions.
• Minimum Operating Reserve is the 10-Minute minimum Operating Reserve requirement for ISO Operations
38 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.b
39 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a & 6.b
memo
To: Participants Committee
From: Marc Lyons, Secretary – Reliability Committee Date: September 17, 2015
Subject: ACTIONS OF THE RELIABILITY COMMITTEE
This memo is to notify the Participants Committee (“PC”) of the actions taken by the Reliability Committee (“RC”) at its September 15, 2015 meeting.
(Agenda Item 2.0) Meeting Minutes
It was moved and seconded to approve the previously distributed minutes of the following RC meeting:
August 18, 2015
A vote to approve the minutes was taken by show of hands with none opposed and no abstentions.
(Agenda Item 3.1) New Gloucester Substation Project - Proposed Plan Application (PPA) CMP- 15-T03 Resolved, the Reliability Committee recommends that ISO New England Inc. determine that implementation of the New Gloucester Substation Project described in Proposed Plan Application (“PPA”) CMP-15-T03 from Central Maine Power Company (“CMP”) as detailed in Mr. Chris Morin’s September 1, 2015 transmittals to Mr. Donald Gates, Chair, Reliability Committee, will not have a significant adverse effect on the stability, reliability or operating characteristics of the transmission facilities of the applicant, the transmission facilities of another Transmission Owner or the system of a Market Participant.
The motion to recommend a determination of no adverse effects passed with none opposed and no abstentions.
(Agenda Item 3.2) Newington Generator Uprate Project - Proposed Plan Application (PPA) EP- 15-G01 Resolved, the Reliability Committee recommends that ISO New England Inc. determine that implementation of the Newington Generator Uprate Project described in Proposed Plan Application (“PPA”) EP-15-G01 from Essential Power (“EP”), as detailed in Mr. Tom Fallon’s September 3, 2015 transmittal to Mr. Donald Gates, Chair, Reliability Committee, will not have a significant adverse effect on the stability, reliability or operating characteristics of the transmission facilities of the applicant, the transmission facilities of another Transmission Owner or the system of a Market Participant.
ISO New England Inc. One Sullivan Road, Holyoke, MA 01040-2841 www.iso-ne.com T 413 540-4517 F 413 535-4343 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a & 6.b
Participants Committee September 17, 2015 Page 3 of 4
The motion to recommend ISO approval of Pool-Supported PTF costs passed based on a show of hands, with none opposed and no abstentions.
(Agenda Item 5.2) PTF Cost Allocation - TCA Application UI-15-TCA-02 It was moved and seconded to recommend ISO New England Inc. approval of, as PTF investment, the Pool-Supported PTF costs associated with Proposed Plan Application UI-14-T01 and UI-14-T02, for the Housatonic River Crossing 88006A & 89006B Line Rebuild Project as described in the United Illuminating TCA Application UI-15-TCA-02, submitted September 4, 2015, with an Pool-Supported PTF costs of $19.75M (2016 Estimated Costs).
The motion to recommend ISO approval of Pool-Supported PTF costs passed based on a show of hands, with none opposed and no abstentions.
(Agenda Item 5.3) PTF Cost Allocation - TCA Application ES-15-TCA-14 It was moved and seconded to recommend ISO New England Inc. approval of, as PTF investment, the Pool-Supported PTF costs associated with Proposed Plan Application NU-12-T59, NU-12-T60, NU- 12-T61, NU-12-T62, and NU-12-T63, for the construction of a new 115-kV A184 line; a five-breaker 115-kV Pulpit Rock Switching Station; 115-kV circuit breaker additions at Scobie Pond and Three Rivers substations; addition of six 13.3-MVAR, 115-kV capacitor banks and three 115-kV circuit breakers at Shiller and line upgrades on the H141 Line and R193 Line, as described in the Eversource Energy TCA Application ES-15-TCA-14, submitted July 9, 2015, with an Pool-Supported PTF costs of $53.215M (2015 Estimated Costs).
The motion to recommend ISO approval of Pool-Supported PTF costs passed based on a show of hands, with none opposed and no abstentions.
(Agenda Item 7.4) ISO New England Operating Procedures No. 18 It was moved and seconded to recommend Participants Committee support for revision of ISO New England Operating Procedure No. 18 – Metering and Telemetering Criteria, together with such other changes as discussed and agreed to at the meeting] and such other non-material changes as may be approved by the Chair and Vice-Chair of the Reliability Committee following the meeting.
The motion to recommend approval to the Participants Committee passed based on a show of hands with none opposed and no abstentions.
(Agenda Item 9.0) Installed Capacity Requirement and Related Values for 2019/2020 (FCA 10)
HQICC Motion It was moved and seconded to recommend Participants Committee support of the following megawatt values that represent the Hydro-Québec Interconnection Capability Credit (HQICC) for the Forward Capacity Auction for the 2019/2020 Capacity Commitment Period:
ISO New England Inc. One Sullivan Road, Holyoke, MA 01040-2841 www.iso-ne.com T 413 540-4517 F 413 535 -4343 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #6.a & 6.b
Participants Committee September 17, 2015 Page 4 of 4
HQICC Values 2019/2020 Capacity Commitment Period Month (MW) June 975 July 975 August 975 September 975 October 975 November 975 December 975 January 975 February 975 March 975 April 975 May 975
A motion to approve the HQICC Values was moved and seconded. A vote was taken by show of hands with 2 opposed (1 Generation Sector, 1 Supplier Sector) and 4 abstentions (2 Generation Sector, 2 Supplier Sector). Motion passes.
ICR/Demand Curve/LSR Motion It was moved and seconded to recommend Participants Committee support for the following megawatt values that represent the New England Installed Capacity Requirement (ICR), Net ICR, the capacity requirement values for the System-Wide Capacity Demand Curve (Demand Curve) and the Southeast New England Local Sourcing Requirement (LSR) for the Forward Capacity Auction for the 2019/2020 Capacity Commitment Period:
2019/2020 Values (MW) Installed Capacity Requirement 35,126
Net Installed Capacity Requirement (Net ICR) 34,151
1-in-5 LOLE Demand Curve capacity value 33,076
1-in-87 LOLE Demand Curve capacity value 37,053
Southeast New England Local Sourcing Requirement 10,028
It was moved and seconded to recommend Participants Committee support for the following megawatt values that represent the ICR/Demand Curve/LSR Values. A vote was taken by show of hands with 3 opposed (2 Generation Sector, 1 Supplier Sector) and 9 abstentions (5 Alternative Resource Sector, 2 End User Sector, 2 Supplier Sector). Motion passes.
ISO New England Inc. One Sullivan Road, Holyoke, MA 01040-2841 www.iso-ne.com T 413 540-4517 F 413 535 -4343 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
EXECUTIVE SUMMARY Status Report of Current Regulatory and Legal Proceedings as of October 1, 2015
The following activity, as more fully described in the attached litigation report, has occurred since the report dated September 9, 2015 was circulated. New matters/proceedings since the last Report are preceded by an asterisk ‘*’. Page numbers precede the matter description. I. Complaints/Section 206 Proceedings 1 206 Proceeding: 2014/15 RNS Sep 15 1st settlement conference held Recovery of SeaLink Development Sep 16 Settlement Judge Young schedules 2nd settlement conference for Oct Costs (EL15-85) 29, 2015; recommends settlement judge procedures be continued Sep 28 Chief Judge Wagner issues order continuing settlement judge procedures II. Rate, ICR, FCA, Cost Recovery Filings 6 FCA9 Results Correction: Holliston Sep 25-29 NEPOOL, Entergy intervene Resource SEMA Load Zone Location (ER15-2626) III. Market Rule and Information Policy Changes, Interpretations and Waiver Requests * 8 Fast Start Pricing Changes Sep 24 ISO and NEPOOL jointly file changes to improve Real-Time Energy (ER15-2716) Market pricing logic when fast start assets are deployed to supply energy; comment date Oct 13 * 8 Monthly Qualified Capacity Changes Sep 14 ISO and NEPOOL jointly file changes to allow for updates to the (ER15-2650) winter Qualified Capacity of resources that participate in monthly reconfiguration auctions and CSO Bilaterals; comment date Oct 5 Sep 30 NRG intervenes 8 Reactive Capability Auditing Sep 14, 25 NESCOE, Entergy intervene Revisions (ER15-2628) 9 CSO Terminations: Enerwise Global Sep 15 FERC accepts terminations Technologies (ER15-2232) 9 CSO Termination: Hampshire Sep 15 FERC accepts termination Council of Governments (ER15-2229) 9 Jump Ball Filing: Winter Reliability Sep 11 FERC conditionally accepts NEPOOL Proposal; compliance filing Program (ER15-2208) due Oct 26 10 IMM FCM Mitigation Package Sep 29 FERC accepts ISO compliance filing, effective Jun 1, 2015 (ER15-1650) 10 DNE Dispatch Changes Sep 11 NEPOOL submits comments reflecting unanimous support for (ER15-1509) compliance changes Oct 1 FERC accepts compliance changes IV. OATT Amendments / TOAs / Coordination Agreements * 12 Retirement of RTO Mapping Sep 25 ISO-NE and NEPOOL jointly file changes to retire the RTO Mapping Document (Tariff Attachment C) Document; comment date Oct 16 (ER15-2717)
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* 13 CTS Conforming Changes Sep 10 ISO and NEPOOL jointly file changes to conforming changes to the (ER15-2641) Tariff and the ISO-NE/NYISO Coordination Agreement to support the implementation of CTS Sep 14 NESCOE intervenes Sep 24-25 Exelon, Entergy intervene 13 Order 676-H Compliance: Revisions Oct 1 FERC accepts ISO’s additional Order 676-H compliance filing to Schedule 24 (ER15-519) 13 Order 676-H Compliance: PTOs, Oct 1 FERC accepts TOs’/SSPs’/CSC’s additional Order 676-H SSPs, CSC et al. (ER15-517) compliance filing V. Financial Assurance/Billing Policy Amendments No Activity to Report VI. Schedule 20/21/22/23 Changes * 15 Schedule 22: Granite Ridge LGIA Sep 30 ISO, National Grid, Eversource, and Granite Ridge file non- (ER15-2747) conforming LGIA to govern interconnection of Londonderry, NH facility; comment date Oct 21 * 15 Schedule 22: Braintree LGIA Sep 28 ISO and Braintree submit non-conforming LGIA under Schedule 22; (ER15-2734) petitions for Declaratory Order and exemption of associated fee; and notice of cancellation of prior LGIA (LGIA-ISONE/BELD-08-01); comment date Oct 19 VII. NEPOOL Agreement/Participants Agreement Amendments 16 AR Provider Amendments Sep 28 FERC accepts amendments to the NEPOOL Agreement and (ER15-2523) Participants Agreement revising the definition of AR Provider and creating a Large Renewable Generation Group Seat; eff. Oct 1, 2015 VIII. Regional Reports * 17 Reserve Market Compliance (19th) Oct 1 ISO submits 19th semi-annual report Semi-Annual Report (ER06-613) * 18 IMM Quarterly Markets Reports - Oct 1 Internal Market Monitor files report for Q2 2015 2015 Q2 (ZZ15-4) IX. Membership Filings * 18 October 2015 Membership Filing Oct 1 Memberships: Antrim Wind Energy, Astral Energy, Beacon Falls (ER16-1) Energy Park, Champlain VT, Concord Steam, Deepwater Wind Block Island, Invenergy Energy Management, MA Operating Holdings; Terminations: HOP Energy, energy.me, Parkview AMC Energy, Denver Energy, Johnston Clean Power; Name Change: NRG Curtailment Solutions, Inc.; comment date Oct 21 18 September 2015 Membership Filing Sep 28 FERC accepts Green Development (d/b/a Wind Energy (ER15-2584) Development), Johnston Clean Power, UIL Distributed Resources, and Uncia Energy memberships; CSG termination X. Misc. - ERO Rules, Filings; Reliability Standards * 18 FFT Report:August2015 (NP15-36) Sep 30 NERC files report * 18 Revised Reliability Standards: IRO- Sep 16 NERC files revised IRO Standards; comment date Oct 19 006-EAST-2; IRO-009-2 (RD15-7) 19 NOPR: Revised CIP Reliability Sep 11-23 Over 35 parties file comments, including ISO-NE, NextEra, and Standards (RM15-14) APPA/EEI/EPSA/NRECA et al.
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20 NOPR: New Reliability Standard: Sep 10 Parties file comments on appeal decision TPL-007-1 (RM15-11) Sep 23 NERC files reply comments 21 Order 813: Revised Rel. Standard: Sep 17 FERC issues Order 813, effective Nov 23 PRC-005-4 (RM15-9) 21 NOPR: New Reliability Standard: Sep 17 FERC issues NOPR proposing to approve PRC-026-1; PRC-026-1 (RM15-8) comments due Nov 23 21 Order 814: Revised Reliability Sep 17 FERC issues Order 814, effective Nov 24 Standard: PRC-002-2 (RM15-4) 22 NOPR: Revised Reliability Standard: Sep 25 NAESB submits report indicating development of supporting WEQ MOD-001-2 (RM14-7) business practice standards is complete and standards to be filed in Oct 2015 23 E. Morris v. NERC/SERC (EL15-93) Sep 16 Morris partially withdraws complaint XI. Misc. - of Regional Interest 25 Construction Agreement: Sep 10 FERC accepts MEPCO files Construction Agreement with Number MEPCO/Number Nine Wind Farm Nine Wind Farm, effective Aug 13, 2015 (ER15-2451) * 26 FERC Enforcement Action: Non- Oct 1 FERC issues order authorizing OE to conduct a non-public, formal Public, Formal Investigation into investigation regarding violations of FERC’s regulations in MISO Zone 4 Planning Resource connection with, or related to, MISO’s April 2015 Planning Auction Offers (IN15-10) Resource Auction for the 2015/16 power year * 26 FERC Enforcement Action: Staff Sep 11 NoV that Coaltrain, its co-owners, traders, and an analyst violated NoV -- Coaltrain Energy/Co- FERC’s Anti-Manipulation Rule by executing a scheme involving Owners/Traders/Analyst manipulative PJM Up-To Congestion trading between Jun and Sep 2010 XII. Misc. - Administrative & Rulemaking Proceedings * 27 NOPR: Price Formation Fixes - Sep 17 FERC issues NOPR to require each RTO/ISO (i) to settle (a) energy Settlement Intervals/Shortage transactions in its real-time markets at the same time interval it Pricing (RM15-24) dispatches energy and (b) operating reserves transactions in its real- time markets at the same time interval it prices operating reserves; and (ii) to trigger shortage pricing for any dispatch interval during which a shortage of energy or operating reserves occurs; comment date Nov 30 * 27 NOPR: Connected Entity Data Sep 17 FERC issues NOPR; comment date Nov 30 Collection (RM15-23) 28 Order 812: Revisions to Public Utility Sep 15 FERC issues tolling order affording it additional time to consider Filing Requirements (RM15-3) Dominion request for clarification and/or reh’g of Order 812 XIII. Natural Gas Proceedings 31 Order 809: Coordination of the Sep 17 FERC denies reh’g of Order 809; requests natural gas and electric Scheduling Processes of Interstate industries, through NAESB, begin considering development of Natural Gas Pipelines and Public standards related to faster, computerized scheduling and file such Utilities (RM14-2) standards or a report on their development by Oct 17, 2016 32 Enforcement Actions:BP (IN13-15) Sep 14 BP files Brief on Exceptions * 32 Staff Notice of Alleged Violation: Sep 21 OE Staff issues notice alleging that TGPNA and its West Desk traders Total Gas & Power, North America and supervisors devised and executed a scheme to manipulate natural gas prices in the southwest US between Jun 2009 and Jun 2012 XIV. State Proceedings & Federal Legislative Proceedings No Activity to Report Page ES-3 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
XV. Federal Courts 36 2013/14 Winter Reliability Program Sep 15 Oral argument held before Judges Tatel, Pillard and Edwards (14-1104, 14-1105, 14-1103 (consolidated)) 38 CPV Maryland, LLC v. PPL Sep 16 U.S. government files amicus brief EnergyPlus et al. Sep 29 CPV Maryland submit supplemental brief (Supreme Court, 14-623) Sep 30 Case distributed for Court’s Oct 16 Conference 39 CPV Power Development, Inc., et al. Sep 16 U.S. government files amicus brief v. PPL EnergyPlus, LLC, et al. Sep 29 CPV Maryland submit supplemental brief (Supreme Court, 14-634, 14-694) Sep 30 Case distributed for Court’s Oct 16 Conference
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MEMORANDUM
TO: NEPOOL Participants Committee Member and Alternates
FROM: Patrick M. Gerity, NEPOOL Counsel
DATE: October 1, 2015
RE: Status Report on Current Regional Wholesale Power and Transmission Arrangements Pending Before the Regulators, Legislatures, and Courts
We have summarized below the status of key ongoing proceedings relating to NEPOOL matters before the Federal Energy Regulatory Commission (“FERC”), state regulatory commissions, and the Federal Courts and legislatures through September 30, 2015. If you have questions, please contact us.1
I. Complaints/Section 206 Proceedings
• 206 Proceeding: 2014/15 RNS Recovery of SeaLink Development Costs (EL15-85) On August 12, 2015, the FERC issued an order accepting the TOs’ July 31, 2014 informational rate filing but, in response to a protest by “Public Representatives”,2 instituted a Section 206 proceeding in Docket EL15-85 to examine whether the recovery by New Hampshire Transmission (“NHT”) of SeaLink project development costs through the RNS formula rate is just and reasonable.3 The FERC encouraged the parties to make every effort to settle their dispute before hearings are commenced, and will hold the hearings in abeyance pending the outcome of settlement judge procedures.4 Interventions were filed by ISO-NE, NEPOOL, CMP, CT OCC, CT PURA, Eversource, MA AG, MOPA, National Grid, NESCOE, RI PUC, UI, VT DPS, and VT Transco. The FERC-established refund effective date is August 19, 2015.5
Settlement Judge Proceedings. On August 19, Chief Judge Wager appointed Judge H. Peter Young as the Settlement Judge. A first settlement conference was held on September 15; a second settlement conference has been scheduled for October 29, 2015. On September 28, Chief Judge Wagner issued an order continuing settlement judge procedures. If there are questions on these proceedings, please contact Eric Runge (617-345- 4735; [email protected]).
• NEPGA Peak Energy Rent (PER) Complaint (EL15-25) Rehearing remains pending of the FERC’s January 30 order denying NEPGA’s PER Complaint.6 As previously reported, the PER Complaint Order found that NEPGA had failed to meet its burden under Section 206 of the Federal Power Act to demonstrate that the existing ISO Tariff provisions were unjust and
1 Capitalized terms used but not defined in this filing are intended to have the meanings given to such terms in the Second Restated New England Power Pool Agreement (the “Second Restated NEPOOL Agreement”), the Participants Agreement, or the ISO New England Inc. (“ISO” or “ISO-NE”) Transmission, Markets and Services Tariff (the “Tariff”). 2 “Public Representatives” are the MA AG, CT OCC, CT PURA, the RI PUC, the Attorney General of the State of Rhode Island (“RI AG”), the Maine Public Advocate (“MOPA”) and the Vermont Department of Public Service (“VT DPS”). 3 ISO New England Inc. Participating Transmission Owners Administrative Committee and New Hampshire Transmission, LLC, 152 FERC ¶ 61,121 (Aug. 12, 2015). 4 Id. at P 20. 5 The notice of this proceeding was published in the Fed. Reg. on Aug. 19, 2015 (Vol. 80, No. 160) p. 50,271. 6 New England Power Generators Assoc., Inc. v. ISO New England Inc., 150 FERC ¶ 61,053 (Jan. 30, 2015) (“PER Complaint Order”), reh’g requested. Page 1 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7 unreasonable.7 On March 2, NEPGA and Entergy challenged the PER Complaint Order. NEPGA argued the FERC should “reverse its finding … that NEPGA did not satisfy its Section 206 burden in the Complaint with respect to the relief sought for Capacity Commitment Periods 5 through 8” and “clarify that the [FERC], not the complainant, carries the burden under Section 206 of establishing a just and reasonable “replacement” rate”. If rehearing is denied, NEPGA asked the FERC to clarify that it “did not intend to prejudge any future proceeding on the PER Adjustment issue by establishing a required evidentiary standard” in the PER Complaint Order. In its request, Entergy, adopting and incorporating NEPGA’s request, provided additional bases to support its request for rehearing of the PER Complaint Order. Entergy challenged further the FERC’s reliance on (i) the ISO’s assessment of the PER adjustment’s reliability impacts and, with respect to Capacity Commitment Periods 5-8, (ii) the stakeholder process considering changes to the PER rules. On April 1, 2015, the FERC issued a tolling order affording it additional time to consider NEPGA’s and Entergy’s rehearing requests, which remain pending before the FERC. If you have any questions concerning this matter, please contact Joe Fagan (202-218-3901; [email protected]) or Sebastian Lombardi (860- 275-0663; [email protected]).
• New Entry Pricing Rule Complaint (EL15-23) Exelon and Calpine’s request for rehearing of the FERC’s January 30 order denying the New Entry Pricing Rule Complaint8 remains pending. As previously reported, the New Entry Pricing Rule Complaint Order found that Exelon and Calpine had failed to show that the existing pricing rules governing lock-in capacity result in unjust, unreasonable or unduly discriminatory price suppression. In their rehearing request, Exelon and Calpine assert, among other things, that the New Entry Pricing Rule Complaint Order (i) did not provide a reasoned basis for finding that there is no artificial price suppression in post-entry FCAs; (ii) did not address Exelon/Calpine’s arguments regarding artificial price suppression in the entry FCA; and (iii) ignored arguments regarding the undue discrimination that results from the current Market Rules. On April 1, 2015, the FERC issued a tolling order affording it additional time to consider Exelon’s and Calpine’s rehearing request, which remains pending before the FERC. If you have any questions concerning this matter, please contact Dave Doot (860-275-0102; [email protected]) or Sebastian Lombardi (860-275-0663; [email protected]).
• NEPGA DR Capacity Complaint (EL15-21) NEPGA’s November 14, 2014 complaint remains pending before the FERC. As previously reported, the complaint requests that (i) Demand Response (“DR”) Capacity Resources be disqualified from FCA9 and (ii) the Tariff be revised to exclude DR from FCM participation going forward (as a result of EPSA v. FERC). Interventions were filed by AEP, Brookfield, Calpine, ConEd, CSG, Direct, Dominion, EEI, ELCON, Emera, EnergyConnect, EnerNOC, Entergy, Exelon, FirstEnergy, Maryland Public Service Commission (“MD PSC”), NextEra, NRG, PPL, and Wal-Mart stores. NEPOOL filed comments on November 26 asking the FERC to reject the NEPGA Complaint without prejudice to a complaint being resubmitted if and as appropriate following consideration of specifically-proposed changes to the Tariff within the Participant Processes. Eversource and UI jointly protested the complaint on December 3, requesting that the FERC either dismiss or hold the Complaint in abeyance. The ISO answered the Complaint on December 4. Also on December 4, Advanced Energy Management Alliance, NESCOE, Conn/RI,9 Enerwise, Environmental
7 NEPGA’s Dec. 3, 2014 complaint requested that the ISO be directed (i) to increase the daily PER Strike Price by $250/MWh for Capacity Commitment Periods 5 through 8, and (ii) to eliminate the PER Adjustment for FCA9 and beyond, or, alternatively, to continue the $250 per MWh increase in the PER Strike Price for FCA9. The changes proposed in the Complaint were considered but not supported by the Participants Committee at its Oct. 3, 2014 meeting. 8 The FERC stated that much of the complainants’ argument rested on the assertion that ISO-NE’s lock-in resource requirements differ from PJM’s. The FERC acknowledged that ISO-NE’s and PJM’s differing mechanics may yield different prices paid to existing resources, but the FERC was not persuaded that the difference itself renders ISO-NE’s rules unjust and unreasonable. Exelon Corp. and Calpine Corp. v. ISO New England Inc., 150 FERC ¶ 61,067 at P 35 (Jan. 30, 2015) (“New Entry Pricing Rule Complaint Order”), reh’g requested. 9 “Conn/RI” is the Connecticut Public Utilities Regulatory Authority (“CT PURA”), George Jepsen, Att’y Gen. for the State of Conn. (“CT AG”), the Conn. Department of Energy and Environmental Protection (“CT DEEP”), the Conn. Office of Consumer Counsel (“CT OCC”), and the Rhode Island Div. of Public Utilities and Carriers (“RI PUC”). Page 2 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
Advocates,10 NGrid, Public Systems, and the Sustainable FERC Project opposed the Complaint; EPSA and PSEG supported the Complaint; Genbright submitted comments. On December 15, CT PURA moved to lodge the December 15 DC Circuit Court order extending the stay of the mandate in EPSA v. FERC. On December 19, NEPGA answered the ISO response and the other pleadings submitted in response to its Complaint. On January 7, just as they had on December 23 in the FirstEnergy Complaint (see Section XI below), Environmental Advocates moved to lodge the US Solicitor General’s application for an extension of time in which to file a petition for writ of certiorari, the Supreme Court Clerk’s notice to the DC Circuit that the extension had been granted, and the DC Circuit’s order extending the stay of its mandate pending the Supreme Court’s final disposition of the writ of certiorari. As noted, this matter remains pending before the FERC. If you have any questions concerning these matters, please contact Dave Doot (860-275-0102; [email protected]) or Sebastian Lombardi (860-275-0663; [email protected]).
• 206 Proceeding: Importers’ FCA Offers Review/Mitigation (EL14-99; ER15-117) As previously reported, the FERC initiated this proceeding, on September 16, 2014, pursuant to Section 206 of the Federal Power Act (“FPA”). The FERC directed the ISO to either revise its Tariff to provide for the review and potential mitigation of importers’ offers prior to each annual Forward Capacity Auction (“FCA”) or show cause why it should not be required to do so.11 The FERC directed the ISO to submit those Tariff revisions or support for why Tariff revisions should not be required on or before October 16, 2014. September 24, 2014 was the refund effective date.12 On October 16, the ISO submitted Tariff revisions in response to the Show Cause Order and Public Citizen requested that the FERC expand this proceeding (i) to determine whether the rates produced by FCA8 are just and reasonable and if not, to fix the just and reasonable rates to be charged; and (ii) to include in this proceeding “stakeholder reform and transparency”. On December 15, 2014, the FERC conditionally accepted, subject to two additional Compliance filings, the ISO’s October 16 Tariff revisions.13 Each of the additional Compliance filings have been filed and accepted.14 All remaining requests and protests, including those of Public Citizen, were rejected. Public Citizen requested rehearing of the Imports Mitigation Order on January 14, 2015 (ER15- 117-003). On January 26, NEPGA answered Public Citizen’s request. On February 12, 2015, the FERC issued a tolling order affording it additional time to consider Public Citizen’s rehearing request, which remains pending before the FERC. Other than FERC action on the January Public Citizen rehearing request, this matter is concluded. If you have any questions concerning these matters, please contact Dave Doot (860- 275-0102; [email protected]), Pat Gerity (860-275-0533; [email protected]), or Sebastian Lombardi (860-275-0663; [email protected]).
• Base ROE Complaints (2012 and 2014) Consolidated (EL13-33 and EL14-86) As previously reported, the FERC, in response to second (EL13-3315) and third (EL14-8616) complaints regarding the TOs’ 11.14% return on equity (“Base ROE”), issued orders establishing trial-type,
10 “Environmental Advocates” are the Sustainable FERC Project, Sierra Club, Environmental Defense Fund, and Acadia Center. 11 ISO New England Inc., 148 FERC ¶ 61,201 (Sep. 16, 2014) (“September 16 Order”). 12 The Sep. 17 notice of this proceeding was published in the Fed. Reg. on Sep. 24, 2014 (Vol. 79, No. 185) p. 57,075. 13 ISO New England Inc., 149 FERC ¶ 61,227 (2014) (“Imports Mitigation Order”), reh’g requested. 14 The first compliance filing corrected an incorrect cross-reference in Section III.13.1.3.5.7 (Qualification Determination Notification for New Import Capacity Resources). The second compliance filing included tariff revisions “which allow importers to submit up to five price-quantity pairs, together with any necessary mitigation provisions to address the exercise of market power” for implementation in FCA10. 15 The 2012 Base ROE Complaint, filed by Environment Northeast (now known as Acadia Center), Greater Boston Real Estate Board, National Consumer Law Center, and the NEPOOL Industrial Customer Coalition (“NICC”, and together, the “2012 Complainants”), challenged the TOs’ 11.14% return on equity, and seeks a reduction of the Base ROE to 8.7%. 16 The 2014 Base ROE Complaint, filed July 31, 2014 by the Massachusetts Attorney General (“MA AG”), together with a group of State Advocates, Publicly Owned Entities, End Users, and End User Organizations (together, the “2014 ROE Page 3 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7 evidentiary hearings and separate refund periods. The first, in EL13-33, was issued on June 19, 2014 and established a 15-month refund period of December 27, 2012 through March 27, 2014;17 the second, in EL14- 86, was issued on November 24, 2014, established a 15-month refund period beginning July 31, 2014,18 and, because of “common issues of law and fact”, consolidated the two proceedings for purposes of hearing and decision, with the FERC finding it “appropriate for the parties to litigate a separate ROE for each refund period.”19 The TOs requested rehearing of both orders. On May 14, the FERC denied rehearing of both orders.20 On July 13, the TOs appealed those order to the D Circuit Court of Appeals (see Section XIV below).
Hearings. The hearings in this mater began June 25, 2015 and were completed on July 2. Just prior to the commencement of the hearing, pursuant to an unopposed motion of the TOs, Judge Sterner adopted a proposed protective order to permit the exchange and use during hearing of certain confidential materials provided by Thomson Reuters. Joint Transcript Corrections and a Final Index of Exhibits were submitted on July 13, 2015. Judge Sterner adopted the transcript corrections on July 15. On July 23, the TOs filed a motion to lodge portion of testimony filed in the Southwestern Public Service Co. ROE proceeding (EL15-8) to show inconsistent positions of FERC Trial Staff. That motion to lodge was opposed by Complainant- Aligned Parties, EMCOS, and FERC Trial Staff on August 7 and denied by Trial Judge Sterner on August 13. On July 29, 2015, a Joint Procedural History was submitted, as were initial briefs by the Complainant- Aligned Parties, TOs, EMCOS and FERC Staff. On August 26, 2015, Reply Briefs were submitted by the Complainant-Aligned Parties, TOs, EMCOS and FERC Staff , as was a Joint List of Appearances. With all briefing completed, the parties await Judge Sterner’s initial decision, which is to be issued by December 30, 2015. If you have any questions concerning this matter, please contact Joe Fagan (202-218-3901; [email protected]) or Eric Runge (617-345-4735; [email protected]).
• 206 Investigation: FCM Performance Incentives (Compliance Proceedings) (EL14-52; ER14-2419) Rehearing remains pending of the FERC’s May 30, 2014 PI Order21 on the FCM PI Jump Ball Filing and its October 2 Order22 on the first Compliance filing in response to the PI Order. As previously reported, the FERC instituted this proceeding, pursuant to Section 206 of the FPA, in its May 30 PI Order on the FCM Performance Incentives Jump Ball filing. In the PI Order, the FERC concluded that the ISO’s FCM payment design was “unjust and unreasonable, because it fails to provide adequate incentives for resource performance, thereby threatening reliable operation of the system and forcing consumers to pay for capacity without receiving commensurate reliability benefits.”23 The FERC directed the ISO to submit “Tariff revisions reflecting a modified version of its [PFP] proposal and an increase in the Reserve Constraint Penalty
Complainants”), seeks to reduce the current 11.14% Base ROE to 8.84% (but in any case no more than 9.44%) and to cap the Combined ROE for all rate base components at 12.54%. 2014 ROE Complainants state that they submitted this Complaint seeking refund protection against payments based on a pre-incentives Base ROE of 11.14%, and a reduction in the Combined ROE, relief as yet not afforded through the prior ROE proceedings. 17 Environment Northeast, et al. v. Bangor Hydro-Elec. Co., et al., 147 FERC ¶ 61,235 (June 19, 2014) (“2012 Base ROE Initial Order”), reh’g denied, 151 FERC ¶ 61,125 (May 14, 2015). 18 Mass. Att’y Gen. et al. -v- Bangor Hydro et al., 149 FERC ¶ 61,156 (Nov. 24, 2014), reh’g denied, 151 FERC ¶ 61,125 (May 14, 2015). 19 Id. at P 27 (for the refund period covered by EL13-33 (i.e., Dec. 27, 2012 through Mar. 27, 2014), the ROE for that particular 15-month refund period should be based on the last six months of that period; the refund period in EL14-86 and for the prospective period, on the most recent financial data in the record). 20 Environment Northeast, et al. v. Bangor Hydro-Elec. Co., et al. and Mass. Att’y Gen. et al. -v- Bangor Hydro et al., 151 FERC ¶ 61,125 (May 14, 2015). 21 ISO New England Inc. and New England Power Pool, 147 FERC ¶ 61,172 (May 30, 2014) (“PI Order”), clarif. and reh’g requested. 22 ISO New England Inc., 149 FERC ¶ 61,009 (Oct. 2, 2014) (“October 2 Order”), reh’g requested. 23 PI Order at P 23. Page 4 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
Factors, consistent with NEPOOL’s proposal.”24 The FERC-established refund effective date was June 9, 2014.25 Requests for clarification and/or rehearing of the PI Order were filed by: NEPOOL, Connecticut and Rhode Island,26 Dominion, MMWEC, Indicated Generators,27 NEPGA, NextEra, Potomac Economics, and PSEG/NRG. On July 28, the FERC issued a tolling order affording it additional time to consider the rehearing requests, which remain pending before the FERC.
FCM PI Jump Ball Compliance Filing I (ER14-2419-001). On October 2, 2014, the FERC accepted in part, subject to condition, and rejected in part, the ISO’s July 14, 2014 Compliance filing (“Compliance Filing I”) that, as previously reported, had been filed in response to directives in the PI Order. While accepting nearly all of the provisions proposed in Compliance Filing I, the October 2 Order rejected the ISO’s Compliance proposal concerning improper price signals caused by binding intra-zonal transmission constraints.28 The FERC found that an exemption was not necessary for resources on the export side of an intra-zonal transmission constraint during a Capacity Scarcity Condition and directed the ISO to submit a further Compliance filing (since filed and accepted) to revise Market Rule Section 13.7 by removing the language that reflected that aspect of the ISO’s July 14 Compliance proposal and restoring language in Sections III.13.7.2.2(a) and III.13.7.2.2(b) ISO-NE originally proposed by the ISO in its January 17 Filing. The Tariff sections accepted were accepted effective June 9, 2014, December 3, 2014, and June 1, 2018, as requested.29 Connecticut/Rhode Island30 and Public Systems31 requested rehearing of the October 2 Order on November 3, 2014. On December 3, 2014, the FERC issued a tolling order affording it additional time to consider the rehearing requests, which remain pending before the FERC.
If you have any questions related to these proceedings, please contact Dave Doot (860-275-0102; [email protected]), Pat Gerity (860-275-0533; [email protected]), or Sebastian Lombardi (860-275- 0663; [email protected]).
• 206 Investigation: Consistency of ISO-NE (DA) Scheduling Practices with Natural Gas Scheduling Practices to be Adopted in Docket RM14-2 (EL14-23) As previously reported, on March 20, 2014, the FERC initiated this proceeding, pursuant to Section 206 of the FPA, to ensure that the ISO’s scheduling, particularly its Day-Ahead scheduling practices, correlate with any revisions to the natural gas scheduling practices to be ultimately adopted by the FERC in RM14-2 (see Section XIII below).32 Noting its concern about the lack of synchronization between the Day- Ahead scheduling practices of interstate natural gas pipelines and electricity markets, the FERC directed each ISO and RTO, including ISO-NE, within 90 days after publication of a Final Rule in Docket RM14-2 in the Federal Register (or, as discussed in Section XIII below, Thursday, July 23, 2015):
(1) to make a filing that proposes tariff changes to adjust the time at which the results of its day-ahead energy market and reliability unit commitment process (or equivalent) are
24 Id. at P 1. 25 The June 3 notice of this proceeding was published in the Fed. Reg. on June 9, 2014 (Vol. 79, No. 110) pp. 32,937-89. 26 “Connecticut and Rhode Island” are: the CT PURA, CT OCC, CT AG, CT DEEP, the United Illuminating Company (“UI”) and the RI PUC. 27 “Indicated Generators” are: Exelon Corp. (“Exelon”), EquiPower Resources Management, LLC (“EquiPower”), Essential Power, LLC (“Essential Power”), and Dynegy Marketing and Trade, LLC and Casco Bay Energy Company, LLC (together, “Dynegy”). 28 October 2 Order at P 56. 29 October 2 Order at P 1; Ordering Paragraph (A). 30 “Connecticut/Rhode Island” are the CT PURA, CT AG, CT OCC, CT DEEP, and the RI PUC. 31 “Public Systems” are CMEEC, MMWEC, NHEC, and VEC. 32 Cal. Indep. Sys. Op. Corp. et al., 146 FERC ¶ 61,202 (Mar. 20, 2014). The New England 206 proceeding was docketed as EL14-23. Page 5 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
posted to a time that is sufficiently in advance of the Timely and Evening Nomination Cycles, respectively, to allow gas-fired generators to procure natural gas supply and pipeline transportation capacity to serve their obligations, or (2) to show cause why such changes are not necessary. In their responses, each ISO and RTO must explain how its proposed scheduling modifications are sufficient for gas-fired generators to secure natural gas pipeline capacity prior to the Timely and Evening Nomination Cycles.33
ISO Response to Show Cause Order. On July 23, the ISO filed its response. In that filing, the ISO described why changes to the time at which the results of the Day-Ahead Energy Market and RAA process are posted are not necessary in response to the FERC’s rule making. Comments on the ISO’s filing were due on or before August 18, 2015. No party submitted adverse comments on ISO-NE’s filing. In comments submitted in each of the ISO/RTO proceedings, NRG requested that the FERC direct the ISOs/RTOs to set their Day-Ahead offer submission deadlines to a time after fixed-price gas has started trading (i.e., 10:30 a.m. EPT) and reduce their solve times (NRG protested the CAISO, MISO and SPP filings; supported PJM’s and was silent with respect to the NYISO and ISO-NE filings specifically). The National Gas Supply Association (“NGSA”) submitted general comments. And, since the last Report, late interventions were filed by EPSA, Entergy, INGAA, and the NY TOs. The FERC expects to issue a final order in this Section 206 proceeding by October 21, 2015 (or within 90 days of the filings required under the March 20 order). If you have any questions concerning this matter, please contact Dave Doot (860-275-0102; [email protected]), Joe Fagan (202-218-3901; [email protected]), or Sebastian Lombardi (860-275-0663; [email protected]).
II. Rate, ICR, FCA, Cost Recovery Filings
• FCA9 Results Correction: Holliston Resource SEMA Load Zone Location (ER15-2626) On September 8, the ISO filed a correction to the results of the ninth FCA (“FCA9”). In its FCA9 Results Filing (see ER15-1137 below), the ISO reported that the Holliston resource, a new 330 kW solar facility, was located in the NEMA Load Zone and cleared in the NEMA/Boston Capacity Zone. The Holliston resource, however, is electrically located in the SEMA Load Zone and SEMA/RI Capacity Zone. Accordingly, the ISO requested that the FERC accept the correction to the FCA9 results by changing location of the Holliston resource to the SEMA Load Zone and the SEMA/RI Capacity Zone. The ISO stated that the correction would have a de minimis impact on the FCA9 results, with the SEMA/RI Capacity Zone still having inadequate resources and subject to Inadequate Supply administrative pricing rules for FCA9. As a new SEMA/RI Capacity Zone resource, Holliston will receive the FCA9 Starting Price of $17.728/kW-month. Doc-les interventions were filed by NEPOOL and Entergy. Comments on this filing were due on or before September 29; none were filed. This matter is pending before the FERC. If you have any questions concerning this matter, please contact Sebastian Lombardi (860-275-0663; [email protected]) or Pat Gerity (860-275-0533; [email protected]).
• FCA9 Results Filing (ER15-1137) As previously reported, the FERC accepted, on June 18, the results of FCA9, effective June 27, 2015, as requested.34 On July 20, 2015, the Utility Workers Union of America Local 464 and Robert Clark (“UWUA”) requested rehearing of the FCA9 Results Order. On August 19, 2015, the FERC issued a tolling order affording it additional time to consider the UWUA request for clarification, which remains pending before the FERC. If you have any questions concerning this matter, please contact Sebastian Lombardi (860-275-0663; [email protected]) or Pat Gerity (860-275-0533; [email protected]).
33 Id. at P 19. 34 ISO New England Inc., 151 FERC ¶ 61,226 (June 18, 2015) (“FCA9 Results Filing”). Page 6 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
• FCA1 Results Remand Proceeding (ER08-633) As previously reported, the DC Circuit issued on December 23, 2011, a per curiam order35 that PSEG’s May 2010 petition for review be granted, remanding the FERC’s orders in this proceeding36 for further consideration. In particular, the FERC was directed to (i) determine whether PSEG’s position (that it should receive the full (unprorated) floor price for all its resources that it could not prorate) would be an appropriate way to interpret the then-existing Market Rules and, if not, (ii) respond to PSEG’s objections that any contrary result would result in “undue discrimination” and would be “inconsistent with the fundamental policy goals” of FCM.
On June 2, 2015, in a long-awaited order, the FERC reversed its prior determination and found that, given that the ISO had prohibited resources needed for reliability from prorating quantity based on its interpretation of the Proration Rule, it was appropriate to consider resettlements to those resources that were not able to prorate quantity.37 “[W]here resources needed for reliability were prohibited from prorating quantity under the Proration Rule, they should have received the full market clearing price for each megawatt offered.”38 Although the FERC found that the ISO reasonably interpreted the Proration Rule as allowing it to limit certain suppliers’ ability to prorate quantity, in order to maintain reliability, and the FERC disagrees with PSEG’s argument that it would be unduly discriminatory under the FPA to make unavailable to certain resources the option to choose quantity proration instead of price proration, the FERC found that resources prevented from prorating quantity must also receive “a just, reasonable, and not unduly discriminatory or preferential rate,” (i.e. the full clearing price for each megawatt offered).
Accordingly, the FERC established a briefing schedule to permit the parties to address issues relating to the amounts of such resettlements (i.e., the difference between a resource’s actual payment and what the payment would have been had proration of the resource not been rejected for reliability reasons), and the parties to which those payments should be charged and to whom they should be paid (taking into consideration any possible changes in ownership, retirements, or similar new circumstances of the resources in question). In its initial brief filed on July 17, the ISO identified: • the Connecticut resources that were unable to prorate quantity in FCA1, and the number of MWs for which each resource received a CSO; • the resettlements due to each such entity, based on the difference between (1) the prorated price that the resources did receive (4.254/kW-mo.), and (2) the un-prorated capacity clearing price that the resources would have received absent price proration (4.50/kW-mo.), plus interest (total refunds with interest will total approximately $20.4 million); • the parties to whom the resettlements would be charged (those with Regional Network Load within Connecticut during that time) and paid (the resource’s Lead Market Participant during each month of FCA1); and • the mechanism by which the ISO would make such resettlements.
The ISO did not identify any considerations that would render the resettlements inappropriate or difficult. For purposes of its brief, the ISO assumed a December 14, 2015 resettlement date. Initial briefs were also submitted by Bridgeport Energy, Dominion, and Bridgeport Energy. A reply brief was submitted on August 17 by Bridgeport Energy (requesting that payments be paid to the legal entity that owned the
35 PSEG Energy Res. & Trade LLC and PSEG Power Conn. LLC v. FERC, No. 10-1103, 2011 U.S. App. LEXIS 25659, (D.C. Cir. Dec. 23, 2011). 36 ISO New England Inc., 123 FERC ¶ 61,290 (2008); reh’g denied, 130 FERC ¶ 61,235 (2010), remanded, PSEG Energy Res. & Trade LLC and PSEG Power Conn. LLC v. FERC, No. 10-1103, 2011 U.S. App. LEXIS 25659, (D.C. Cir. Dec. 23, 2011). 37 ISO New England Inc., 151 FERC ¶ 61,196 (June 2, 2015) (“FCA1 Remand Order”). 38 Id. at P 14. Page 7 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7 resource at the time of the FCA 1 Commitment Period or, if that legal entity no longer exists, to the successor in interest to ownership of the subject resource). On September 2, the ISO answered Bridgeport Energy’s reply brief, advocating for resettlement payments to the Lead Market Participant during the first Capacity Commitment Period. This matter is pending before the FERC. If you have any questions concerning this matter, please contact Pat Gerity (860-275-0533; [email protected]) or Sebastian Lombardi (860- 275-0663; [email protected]).
III. Market Rule and Information Policy Changes, Interpretations and Waiver Requests
• Fast Start Pricing Changes (ER15-2716) On September 24, the ISO and NEPOOL jointly filed changes to improve Real-Time Energy Market pricing logic when fast start assets are deployed to supply energy (“Fast Start Pricing Changes”). The Fast Start Pricing Changes were supported by the Participants Committee at its June 25, 2015 Summer Meeting (Consent Agenda Item # 1). While an effective date of March 31, 2017 was requested, the ISO asked for a FERC order on or before December 1, 2015. Comments on this filing are due on or before October 13. If you have any questions concerning this matter, please contact Sebastian Lombardi (860-275-0663; [email protected]).
• Monthly Qualified Capacity Changes (ER15-2650) On September 14, the ISO and NEPOOL jointly filed changes to changes to allow for updates to the winter Qualified Capacity of resources that participate in monthly reconfiguration auctions and CSO Bilaterals. These changes were supported by the Participants Committee at its September 11, 2015 meeting. An October 13, 2015 effective date was requested. Comments on this filing are due on or before October 5. Thus far, a doc-less intervention was filed by NRG. If you have any questions concerning this matter, please contact Sebastian Lombardi (860-275-0663; [email protected]).
• Reactive Capability Auditing Revisions (ER15-2628) On September 9, the ISO and NEPOOL jointly filed changes to (1) add a new section III.1.5.3 to Market Rule 1 addressing reactive capability audits (in part in response to the proposed 2016 retirement of NPCC Directory #10); (2) add additional generation resource unit types to the provisions for real power audits; and (3) change the effective date for real power audits (from seven to one business day following notification of audit results). The Reactive Capability Auditing Revisions were supported by the Participants Committee at its August 7, 2015 meeting (Consent Agenda Item # 16). A December 1, 2015 effective date was requested. Comments on this filing were due on or before September 30; none were filed. Interventions were filed by NESCOE and Entergy. If you have any questions concerning this matter, please contact Sebastian Lombardi (860-275-0663; [email protected]).
• FCM ARA Sloped Demand Curve Changes (ER15-2404) As previously reported, the ISO and NEPOOL jointly submitted, on August 10, Tariff revisions to the rules for FCM Annual Reconfiguration Auctions (“ARAs”) to reflect the use of a system-wide demand curve. The ARA Changes also make a number of other conforming and clean-up changes to the existing rules. These changes were supported by the Participants Committee at its August 7, 2015 meeting (Consent Agenda Item # 15). Comments on this filing were due on or before August 31. Interventions were filed by Dominion, Entergy, Eversource, and NRG. NEPGA submitted comments supporting the changes, but reiterating its request that the FERC confirm that it expects the ISO to file sloped zonal demand curves for effect in FCA10 (see NEPGA 206 Request, ER14-1639 below).39 On September 9, the ISO answered NEPGA’s request, restating its position that “it would be neither practical nor wise to engage in an effort at this time to design and implement sloped zonal
39 Motion for Clarification and Request to Direct Compliance of the New England Power Generators Association, Inc., Docket No. ER14-1639-002 (filed June 22, 2015). Page 8 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7 demand curves for FCA 10”. This matter is pending before the FERC. If you have any questions concerning this matter, please contact Sebastian Lombardi (860-275-0663; [email protected]).
• CSO Terminations: Enerwise Global Technologies (ER15-2232) On September 15, the FERC accepted the termination of CSOs for Resource #s 16700 and 37922 held by Project Sponsor Enerwise Global Technologies (“Enerwise”). The ISO will draw down the applicable amount of financial assurance provided by Enerwise with respect to the CSOs. Unless the September 15 order is challenged, this proceeding will be concluded. If you have any questions concerning this matter, please contact Pat Gerity (860-275-0533; [email protected]).
• CSO Termination: Hampshire Council of Governments (ER15-2229) Also on September 15, the FERC accepted the termination of the CSO for Resource # 38110 held by Project Sponsor Hampshire Council of Governments. The ISO will draw down the applicable amount of financial assurance provided by the Hampshire Council of Governments with respect to the CSO being terminated. Unless the September 15 order is challenged, this proceeding will be concluded. If you have any questions concerning this matter, please contact Pat Gerity (860-275-0533; [email protected]).
• Jump Ball Filing: Winter Reliability Program (ER15-2208) On September 11, the FERC conditionally accepted NEPOOL’s Winter Reliability Program Proposal.40 The FERC, “[a]fter evaluating each proposal and with consideration given to the cost of expanding the program,” conditionally accepted the NEPOOL Proposal as “just and reasonable and preferable, to become effective on September 14, 2015, as requested, subject to ISO-NE submitting revised Tariff records in a compliance filing” due on or before October 26, 2015.41 In the compliance filing, the ISO was directed to revise the Tariff to include the formula used to calculate the annual rate, rather than simply post that formula on the ISO website,42 and to make certain corrections to NEPOOL’s proposed Tariff revisions.43
As previously reported, the ISO and NEPOOL submitted, on July 17, two alternative versions of Market Rule changes intended to establish a winter reliability program for winters 2015/16, 2016/17 and 2017/18 -- the “NEPOOL Proposal” and the “ISO-NE Proposal”. Both Proposals were intended to address reliability challenges created by the region’s increased reliance on natural gas-fueled generation and to be stop-gap measures until revised incentives for capacity resources (PFP) become fully effective in 2018. The NEPOOL Proposal was based on the design of the 2014/15 program, with three main components: (1) compensation for certain oil inventory that remains in New England following the end of each winter period; (2) compensation for unused liquefied natural gas (“LNG”) contract volumes; and (3) a supplemental demand response (“DR”) program. The ISO Proposal also included the first two components of the NEPOOL Proposal, but eliminated the DR component, and provided compensation not only for fuel oil and LNG, but also for nuclear, hydro, biomass and coal-fired resources.
In accepting the NEPOOL Proposal, the FERC noted that the NEPOOL Proposal was “widely supported in the region by a substantial majority of stakeholders representing all six NEPOOL stakeholder sectors.”44 The FERC disagreed with those that argued that NEPOOL’s proposal was unduly discriminatory or represented a collateral attack on the FERC’s prior orders, and disagreed with arguments that DR was incompatible with the Winter Program’s objectives. The FERC also found that the 10-day inventory compensation cap is sufficient to incent participation in the program even if the additional resource types are not included. Any challenges to the September 11 order will be due on or before October 13, 2015. If you have any questions concerning this matter,
40 ISO New England Inc. and New England Power Pool Participants Comm., 152 FERC ¶ 61,190 (Sep. 11, 2015). 41 Id. at P 44. 42 Id. at P 51. 43 Id. at P 52. 44 Id. at P 46. Page 9 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7 please contact Dave Doot (860-275-0102; [email protected]), Joe Fagan (202-218-3901; [email protected]), or Sebastian Lombardi (860-275-0663; [email protected]).
• IMM FCM Mitigation Package (ER15-1650) As previously reported, the FERC accepted in part, and rejected in part, revisions to the market power mitigation provisions in the FCM Market Rules (“IMM FCM Mitigation Package”).45 The Package proposed to (i) establish a revised Pivotal Supplier Test (permitting the IMM to take into account both existing internal resources and import resources when assessing the competiveness of supply and to conduct the Pivotal Supplier Test closer to the start of an FCA); (ii) increase, beginning with FCA10, the value below which existing resources that have chosen to be price takers in an FCA can opt to leave the auction (“Dynamic De-List Bid Threshold”), from $3.94/kW-mo. to $5.50/kW-mo. (with the value to be recalculated and reviewed with Participants not less than once every three years); and (iii) remove some of the flexibility in the auctions that is currently afforded to Market Participants submitting Static De-List Bids. In its June 30 Order, the FERC accepted the revised Pivotal Supplier Test, the increased Dynamic De-List Bid Threshold, the New Import Capacity Resource mitigation rules, and the clean-up changes proposed in the IMM FCM Mitigation Package. However, the FERC rejected the proposed changes to the Static De-List Bid rules, finding it “inconsistent with competitive market principles to prevent a capacity supplier without buyer-side market power from lowering its offer in the FCA or from withdrawing its Static De-List Bid during the post-review modification period, both actions that would tend to reduce FCA clearing prices.”46 “Provided that a resource submits a Non-Price Retirement Request before the deadline for such a request,” the [FERC] found “no basis for precluding a supplier from making this decision during the Static De-List Bid finalization process.”47 Accordingly, the ISO was directed to submit Tariff revisions removing the proposed Static De-List Bid rule changes on or before July 30.48 Finally, with respect to the competitive entry exemption from buyer-side mitigation advocated by Champlain VT, the FERC found the issue beyond the scope of the proceeding and directed Champlain VT to pursue its concerns in the stakeholder process.49 The accepted revisions were effective June 1, 2015, as requested. The June 30 Order was not challenged and is final and unappealable.
July 30, 2015 Compliance Filing. On July 30, the ISO submitted Tariff revisions that removed the changes to the Static De-List Bid rules. Those changes were accepted by the FERC on September 29, 2015. Unless the September 29 Order is challenged, this proceeding will be concluded. If you have any questions concerning this matter, please contact Sebastian Lombardi (860-275-0663; [email protected]).
• DNE Dispatch Changes (ER15-1509) As previously reported, the FERC accepted, in part, and rejected, in part, revisions to Market Rule 1, jointly submitted by the ISO and NEPOOL, to provide for the dispatch of certain wind and hydro Intermittent Power Resources using Do Not Exceed (“DNE”) Dispatch Points (“DNE Dispatch Changes”).50 The DNE Dispatch Changes were accepted effective April 10, 2016, as requested. In response to issues raised by RENEW and SunEdison (“Protestors”), the FERC found that the ISO did not sufficiently justify the blanket exclusion of DNE Dispatchable Generators from the regulation and reserves markets.51 Accordingly, the FERC directed the ISO to submit on or before August 24, “a filing to remove the relevant tariff provisions. Furthermore, in recognition of the fact that, as RENEW explains, it is not currently economic for wind resources to participate in
45 ISO New England Inc. and New England Power Pool Participants Comm., 151 FERC ¶ 61,270 (June 30, 2015) (“June 30 Order”). 46 Id. at P 44. 47 Id. at P 31. 48 Id. 49 Id. at P 64. 50 ISO New England Inc. and New England Power Pool Participants Comm., 152 FERC ¶ 61,065 (July 23, 2015) (“DNE Dispatch Order”). 51 Id. at P 25. Page 10 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7 the frequency regulation market, we also encourage ISO-NE to work with its stakeholders to develop rules integrating intermittent resources into its markets.”52 The FERC also encouraged the ISO to work closely with its stakeholders on the issues it found not at issue in this proceeding or settled by the ISO (including implementation and timing issues, including data accuracy, transparency, and constraints to certain hydro resources).53 Finally, the FERC directed the ISO to correct a typographical error identified by the FERC in Market Rule 1 Section 13.6.2.1.1.2.54 The DNE Dispatch Order was not challenged and is final and unappealable.
August 21 Compliance Filing. On August 21, the ISO submitted changes proposed in response to the DNE Dispatch Order. The changes were supported by the Participants Committee at its September 11 meeting (Consent Agenda Item No. 9). On September 11, NEPOOL submitted comments reflecting its unanimous support for the August 21 changes. The FERC accepted the compliance filing changes on October 1. Unless the October 1 order is challenged, this proceeding will be concluded. If you have any questions concerning these matters, please contact Sebastian Lombardi (860-275-0663; [email protected]).
• Demand Curve Changes (ER14-1639) As previously reported, the FERC denied rehearing of the Demand Curve Order,55 but clarified (agreeing with Exelon and Entergy) that a resource that elects to utilize the renewables minimum offer price rule exemption should not also be allowed to utilize the new resource lock-in).56 Accordingly, the FERC directed the ISO to submit, on or before March 2, 2015, a Compliance filing clarifying that a resource may not utilize both the renewable resource exemption and the new resource price lock-in. That Compliance filing was submitted on March 2, accepted on May 1, and became effective on May 2.57 The petition for DC Circuit Court of Appeals review of the FERC’s Demand Curve orders, filed by NextEra, NRG and PSEG, remains pending before that Court (see Section XV below).
Informational Progress Report: On May 18, the ISO submitted a report to update the FERC on New England’s progress toward developing FCM zonal demand curves. Importantly, the ISO reported that improvements to the current FCM demand curve structure cannot be completed before FCA10, noting that from its perspective and despite efforts to date, the changes have “not yet achieved a design that reasonably satisfies reliability, market efficiency and pricing objectives with reasonable market power protections.” The ISO stated that it needs “additional time to address the complexities associated with the demand curve structure … and commits to filing a further progress report no later than October 31, 2015.” In the remainder of the report, the ISO identified the three fundamental reasons that it believes make it imprudent to immediately adopt a new sloped zonal demand curve design without further analysis and stakeholder review, identified the four key factors for Demand Curve design, and noted reliability, price volatility, robustness, and market power concerns. The ISO concluded that “the best approach at this time is to maintain the current demand curve structure for the FCA 10 auction cycle and continue to analyze and discuss with stakeholders the development of robust zonal demand curve improvements that can be put in place in the future.”
NEPGA 206 Request. In response to the Informational Report and the announcement that the ISO does not intend to file sloped zonal demand curves, NEPGA filed on June 23 a request that the FERC “initiate a Section 206 proceeding on the ISO-NE Tariff and order ISO-NE to file the sloped zonal demand curves developed by ISO-NE and NEPOOL stakeholders, and proposed by ISO-NE as recently as April 2015 (“Zonal
52 Id. 53 Id. at P 29; n. 75. 54 Id. at PP 30-31. 55 ISO New England Inc. and New England Power Pool Participants Comm., 147 FERC ¶ 61,173 (May 30, 2014) (“Demand Curve Order”), reh’g denied but clarif. granted, 150 FERC ¶ 61,065 (Jan. 30. 2015). 56 ISO New England Inc. and New England Power Pool Participants Comm., 150 FERC ¶ 61,065, at P 27 (Jan. 30, 2015) (“Demand Curve Clarification Order”). 57 The changes become effective with FCA10, and will not apply to the resources in FCA9, totaling 12.96 MW, that utilize both the renewable resource exemption and the price lock-in election. Page 11 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
Curves”), for effect in FCA 10, amended to eliminate an FCA clearing rule ISO-NE had proposed as part of its Zonal Curves design.” NEPGA asked that the ISO be compelled to make that filing within 30 days of that FERC order. The ISO answered and opposed NEPGA’s request on July 2. Comments supporting the NEPGA request were filed by EPSA on July 7. NEPOOL submitted comments on July 8 (taking no position on whether an order to implement sloped zonal demand curves generally is appropriate or justified, or whether implementation can be achieved in time for FCA10, but if such an order were to be issued, urging that any Market Rule changes be fully discussed, and voted by NEPOOL pursuant to a schedule that allows the NEPOOL stakeholder process to proceed to completion and account for the many interrelated issues associated with such Market Rule changes. NEPOOL urged the FERC to reject the NEPGA request that the FERC order a specific solution that NEPOOL voted and did not support). NEPGA’s motion remains pending before the FERC.
If you have any questions concerning these matters, please contact Sebastian Lombardi (860-275-0663; [email protected]).
• Jump Ball Filing: FCM Performance Incentives (ER14-1050) Rehearing of the FCM PI Order remains pending. As previously reported, the ISO and NEPOOL submitted on January 17, 2014, two alternative versions of Market Rule changes intended to improve the operating performance of capacity resources in New England -- the “ISO-NE Proposal” and the “NEPOOL Proposal”. As explained above, on May 30, 2014, the FERC issued an order in response to the jump ball filing.58 The FERC concluded that the existing Tariff, specifically the current FCM payment design, “is unjust and unreasonable, because it fails to provide adequate incentives for resource performance, thereby threatening reliable operation of the system and forcing consumers to pay for capacity without receiving commensurate reliability benefits” and instituted a proceeding under Section 206 of the FPA (see EL14-52 in Section I above). Concluding that neither the ISO-NE Proposal nor the NEPOOL Proposal, standing alone, had been shown to be just and reasonable, the FERC, drawing features from each Proposal, went on to direct the ISO to submit by July 14, 2014 Tariff revisions reflecting a modified version of the ISO-NE Proposal and an increase in the Reserve Constraint Penalty Factors, consistent with NEPOOL’s Proposal. Specifically, the Compliance filing was to include (1) changes to implement ISO-NE’s proposed two-settlement capacity market design with certain modifications, and (2) changes to increase the RCPF values for Thirty-Minute Operating Reserves to $1,000/MWh and for Ten-Minute Non-Spinning Operating Reserves to $1,500/MWh. The FERC established a June 9, 2014 refund effective date. Requests for clarification and/or rehearing of the PI Order were filed by: NEPOOL, Connecticut and Rhode Island, Dominion, MMWEC, Indicated Generators, NEPGA, NextEra, Potomac Economics, and PSEG/NRG. On July 28, 2014, the FERC issued a tolling order affording it additional time to consider the requests for clarification and/or rehearing, which remain pending before the FERC.
If you have any questions concerning this matter, please contact Dave Doot (860-275-0102; [email protected]), Harold Blinderman (860-275-0357; [email protected]), Eric Runge (617-345-4735; [email protected]) or Sebastian Lombardi (860-275-0663; [email protected]).
IV. OATT Amendments / TOAs / Coordination Agreements
• Retirement of RTO Mapping Document (Tariff Attachment C) (ER15-2717) On September 25, the ISO and NEPOOL jointly filed changes to retire the RTO Mapping Document (Tariff Attachment C). The RTO Mapping Document was created during the 2005 transition to the RTO arrangements as a guide for identifying where pre-RTO documents/provisions could be found under the RTO arrangements. While no longer to be part of the Tariff, the ISO indicated that the Mapping Document will remain available as a research aid on the ISO website (http://www.iso-ne.com/participate/governing- agreements/historicaldocuments). The retirement of the RTO Mapping Document was supported by the Participants Committee at its September 11, 2015 meeting (Consent Agenda Item # 1). A November 25, 2015
58 See PI Order. Page 12 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7 effective date was requested. Comments on this filing are due on or before October 16. If you have any questions concerning this matter, please contact Eric Runge (617-345-4735; [email protected]).
• CTS Conforming Changes (ER15-2641) On September 10, the ISO, NEPOOL, and PTO AC jointly filed conforming changes to the ISO Tariff and the ISO-NE/NYISO Coordination Agreement to support the implementation of Coordinated Transaction Scheduling between New England and New York over the New York Northern AC interface (“CTS”), a project to be completed in December 2015. The CTS Conforming Changes were supported by the Participants Committee at its August 7, 2015 meeting. An effective date on or after December 1, 2015, with two weeks prior notice to be filed identifying the actual effective date, was requested. Comments on this filing were due on or before October 1; none were filed. Doc-less interventions were filed by NESCOE, Exelon and Entergy. This matter is pending before the FERC. If you have any questions concerning this matter, please contact Eric Runge (617-345-4735; [email protected]).
• Order 676-H Compliance: Revisions to Schedule 24 (ER15-519) As previously reported, the FERC conditionally accepted the ISO’s Order 676-H Compliance filing, effective May 15, 2015,59 but denied the ISO’s request for continued waiver of Version 003 NAESB Standards and of the standards relating to Network Integration Transmission Service (“NITS”) or Service Across Multiple Transmission Systems (“SAMTS”).60 The ISO Order 676-H Compliance Order was not challenged and is final and unappealable.
Additional ISO Order 676-H Compliance Filing. On July 20, as corrected on August 12,61 the ISO filed revisions to Schedule 24 of the OATT to comply with the ISO Order 676-H Compliance Order (incorporating by reference all of the Version 003 NAESB standards, and excluding no standard). Those revisions were unanimously supported by the Participants Committee at its August 7 meeting (Consent Agenda Item No. 12). Comments on the July 30 Compliance filing were due on or before August 10, 2015. Comments supporting the revisions were filed by NEPOOL on August 7. Comments on the errata filing were due September 2, 2015; none were filed. On October 1, the FERC accepted the Additional ISO Order 676-H Compliance Filing. Unless the October 1 order is challenged, this proceeding will be concluded. If you have any comments or concerns, please contact Eric Runge (617-345-4735; [email protected]) or Kristin Sullivan (617-345-4657; [email protected]).
• Order 676-H Compliance: PTOs, SSPs, CSC et al. (ER15-517) The FERC also conditionally accepted on May 19, 2015, the TOs’62 Order 676-H Compliance filing.63 As previously reported, the TOs Order 676-H Compliance Order denied requested waivers of certain transmission provider standards, dismissed requested waivers of reliability coordinator and balancing authority standards as unnecessary. In denying the Filing Parties’ requests for waiver of WEQ-000, WEQ-001, WEQ-002, WEQ-003, WEQ-004, WEQ-008, WEQ-011-1.2, WEQ-011-1.3, and WEQ-011-1.6, the FERC stated that the “Filing Parties are transmission providers, so the standards apply to them, and they are required to implement the standards once
59 ISO New England Inc., 151 FERC ¶ 61,155 (May 19, 2015) (“ISO Order 676-H Compliance Order”). 60 If, however, the ISO continues to believe that renewed waiver of specific standards is warranted, it may file a subsequent request for a waiver detailing the circumstances that it believes warrant a waiver. Id. at n. 20. 61 The August 12 errata filing corrected citations to the following five WEQ Standards: WEQ-000, WEQ-001, WEQ-002, WEQ-003, and WEQ-013. 62 For purposes of this proceeding, the “TOs” are the Participating Transmission Owners (“PTOs”), the Schedule 20A Service Providers (“SSPs”), Cross-Sound Cable Company, LLC (“CSC”), New England Power Company (“NGrid”), Northeast Utilities Service Company (“NUSCO”), Unitil Energy Systems, Inc., Fitchburg Gas and Electric Light Company, and the ISO. 63 Participating Transmission Owners Admin. Comm., 151 FERC ¶ 61,154 (May 19, 2015) (“TOs Order 676-H Compliance Order”). Page 13 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7 they perform the relevant business practices (even if they currently do not perform those practices).”64 The May 19 order was not challenged and is final and unappealable.
Additional TOs Order 676-H Compliance Filing. On July 16, the TOs filed Tariff revisions to incorporate the complete set of Version 003 Business Practice Standards into their tariffs without modification and to remove references to waiver requests previously sought of the Version 003 NAESB standards. Changes were filed to OATT Schedules 18, 20A Common, Schedule 20A-NU, 21 Common, 21-FGE, 21-UES, 21-NEP, and 21-NU. Comments on the July 16 Compliance filing are due on or before August 6, 2015. On August 14, CSC filed an errata to correct an error in Schedule 18, Attachment Z, WEQ-004, Version 003 Standard. No comments on the July 16 additional Compliance filing or on CSC’s errata filing were filed. On October 1, the FERC accepted the additional TOs Order 676-H compliance filing. Unless the October 1 order is challenged, this proceeding will be concluded. If you have any comments or concerns, please contact please contact Eric Runge (617-345-4735; [email protected]) or Kristin Sullivan (617-345-4657; [email protected]).
• Order 1000 Interregional Compliance Filings (ER13-1960; ER13-1957) As previously reported, the FERC conditionally accepted, subject to Compliance filings made July 14, revisions to the ISO Tariff to comply with the interregional coordination and cost allocation requirements of Orders 1000 and 1000-A and (ii) an Amended and Restated Northeastern ISO/RTO Planning Coordination Protocol (“Protocol”).65 The Order 1000 Interregional Compliance Changes included (i) revisions to Attachment K to add provisions describing the interregional coordination provisions included in the Amended Protocol, as well as adding other provisions facilitating the consideration of interregional solutions to regional needs; (ii) a new Schedule 15 reflecting the methodology for allocation among ISO-NE and NYISO of the costs of approved interregional transmission projects; (iii) revisions to Schedule 12 describing the regional cost allocation within New England of the costs of approved interregional transmission projects; and (iv) conforming changes to Tariff Section I.
Second Order 1000 Interregional Compliance Changes. On July 13, the ISO filed revisions to the ISO- NE Tariff and to the Protocol in response to the Order 1000 Interregional Compliance Filing Order (“Second Order 1000 Interregional Compliance Changes”). The Second Order 1000 Interregional Compliance Changes were supported by the Participants Committee at the June 25 session of the Summer Meeting. On August 3, NEPOOL filed comments summarizing that support. This matter is pending before the FERC. If you have any comments or concerns, please contact Eric Runge (617-345-4735; [email protected]).
• Order 1000 Compliance Filing (ER13-193; ER13-196) As previously noticed, the FERC issued, on March 19, 2015, its Order on Rehearing and Compliance66 of the region’s Order 1000 Compliance filing.67 A memo summarizing the 200-page order in more detail was circulated by NEPOOL Counsel on March 23 and posted on the NEPOOL website Litigation Report Updates page.
ISO Request for Clarification and/or Rehearing. On April 20, the ISO requested clarification and/or re-hearing of the Order 1000 Compliance Rehearing Order. Specifically, the ISO requested clarification (i) that the FERC’s concerns with the non-discriminatory applicability of the “hold harmless” clause contained in the Non-Incumbent Transmission Developer Operating Agreement (“NTDOA”) could be addressed by the inclusion of a similar clause in the Transmission Operating Agreement (“TOA”); and (ii) that no changes are
64 Id. at P 32. 65 ISO New England Inc., 151 FERC ¶ 61,133 (May 14, 2015) (“Order 1000 Interregional Compliance Filing Order”). 66 ISO New England Inc., 150 FERC ¶ 61,209 (Mar. 19, 2015) (“Order 1000 Compliance Rehearing Order”), clarif. and/or reh’g requested. 67 ISO New England Inc., 143 FERC ¶ 61,150 (May 17, 2013) (“Order 1000 Compliance Order”), order on reh’g 150 FERC ¶ 61,209 (Mar. 19, 2015). Page 14 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7 required to comply with Regional Cost Allocation Principle 4 and that language providing that “the costs of any external impacts of New England regional projects will not be borne by New England customers” need not be removed from Schedule 15 of the OATT. On May 4, the TOs submitted comments supporting the ISO’s request. On May 15, the FERC issued a tolling order affording it additional time to consider the ISO’s request for rehearing, which remains pending before the FERC.
3rd Regional Order 1000 Compliance Filing. On May 18, the ISO and PTO AC jointly submitted revisions to Sections I and II of the ISO Tariff (-005) and to the TOA (-004) to comply with the Mar 19 order on the 2nd Regional Order 1000 Compliance filing. The Compliance materials, which were not ready in time for NEPOOL consideration before the May 18 filing deadline, were considered and unanimously supported at the June 5 Participants Committee meeting. On June 5, the Participants Committee filed comments supporting the filing. On June 8, LS Power filed a protest, requesting that the FERC require the ISO to revise Attachment K Section 4.3(k) and the definition of Backstop Transmission Solution as described in its protest. The ISO answered the LS Power protest on June 18. LS Power answered the ISO answer on June 26. The 3rd regional Order 1000 Compliance filing remains pending before the FERC.
If you have any comments or concerns, please contact Eric Runge (617-345-4735; [email protected]).
V. Financial Assurance/Billing Policy Amendments
No Activity to Report
VI. Schedule 20/21/22/23 Changes
• Schedule 22: Granite Ridge LGIA (ER15-2747) On September 30, the ISO, National Grid, Eversource (on behalf of PSNH) and Granite Ridge filed a non-conforming, 4-party LGIA between the ISO, Granite Ridge as Interconnection Customer, and both National Grid and Eversource as Interconnecting Transmission Owners. The LGIA is non-conforming in that it contains certain deviations from Schedule 22’s pro forma LGIA necessary to accommodate two Interconnecting TOs. The LGIA will govern the interconnection of Granite Ridge’s Londonderry, NH facility, unique in that, while the facility operates in a single combined cycle configuration such that the individual units comprising the facility cannot be separated, the facility’s combustion and steam turbines were interconnected at two different points on the System. The need for a new LGIA was initiated by a proposed increase in the output of the facility. An August 31, 2015 effective date was requested. Comments on this filing are due on or before October 21. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).
• Schedule 22: Braintree LGIA (ER15-2734) On September 28, the ISO and Braintree Electric Light Department (“Braintree”) filed a non-conforming LGIA between the ISO and Braintree as both Interconnection Customer and Interconnecting Transmission Owner. The LGIA is non-conforming in that it contains certain deviations from Schedule 22’s pro forma LGIA necessary to accommodate Braintree’s status as both Interconnection Customer and Interconnecting TO, and contains deviations previously accepted by the FERC in the 2008 Agreement to be concurrently cancelled. The LGIA will govern the interconnection of Granite Ridge’s Londonderry, NH facility, unique in that, while the facility operates in a single combined cycle configuration such that the individual units comprising the facility cannot be separated, the facility’s combustion and steam turbines were interconnected at two different points on the System. The need for a new LGIA was initiated by a proposed increase in the output of the facility. An August 31, 2015 effective date was requested. Comments on this filing are due on or before October 21. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).
Page 15 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
• Schedule 21-NEP: National Grid/Old Wardour SGIA (ER15-2599) On September 2, National Grid filed an amended SGIA between itself and Old Wardour. The amended SGIA, with revisions to reflect changes in circumstances regarding the Milestones schedule, protective equipment to be installed, and estimated cost for equipment, addresses the interconnection of Wardour’s 4.875 MW photovoltaic generating facility located in Spencer, Massachusetts. An August 5, 2015 effective date was requested. Comments on the amended SGIA were due on or before September 23; none were filed. This matter is pending before the FERC. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).
• Schedule 21-NEP: National Grid/Vuelta Solar SGIA (ER15-2598) On September 2, National Grid filed an amended SGIA between itself and Vuelta Solar, LLC. The amended SGIA, with revisions to reflect changes in circumstances regarding the Milestones schedule, protective equipment to be installed, and estimated cost for equipment, addresses the interconnection of Vuelta’s 4.875 MW photovoltaic generating facility located in East Brookfield, Massachusetts. An August 5, 2015 effective date was requested. Comments on the amended SGIA were due on or before September 23; none were filed. This matter is pending before the FERC. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).
• Schedule 20A-EM: Talen Energy Marketing Updates (ER15-2578) On August 31, Emera Maine filed changes to Schedule 20A-EM to reflect the Talen Energy Marketing transaction and name change. An October 30, 2015 effective date was requested. Comments on this filing are due on or before September 21; none were filed. This matter is pending before the FERC. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).
• Opinion 531-A Compliance Filing: CTMEEC (ER15-584) On August 7, the FERC rejected the Connecticut Transmission Municipal Electric Energy Cooperative’s (“CTMEEC”) changes to Attachment B to Schedule-21 CTMEEC to conform Schedule-21 CTMEEC to the holdings in Opinions 531 and 531-A.68 The FERC found that tariff language concerning “aggregate ROE”69 did not comply with FERC directives in Opinion 531-A, or the FERC’s policy on transmission incentive ROE adders as it would have “allowed CTMEEC to average the ROE earned on its facilities under Schedule 21-CTMEEC, which would allow CTMEEC to earn an equity return on certain assets, for which incentive ROE adders have been granted, at a level that exceeds the zone of reasonableness produced by the DCF methodology—i.e., a return above the level that has been shown to be just and reasonable.”70 Accordingly, the FERC directed CTMEEC to submit, on or before September 7, a revised Compliance filing with tariff provisions ensuring that CTMEEC does not recover an ROE of more than 11.74% on any transmission asset and that each incentive ROE adder granted to CTMEEC applies only to the facility or facilities for which it was granted. CTMEEC submitted its revised Compliance filing on September 8. Comments, if any, on the revised Compliance filings are due on or before September 29; none were filed. This matter is pending before the FERC. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).
VII. NEPOOL Agreement/Participants Agreement Amendments
• AR Provider Amendments (ER15-2523) On September 28, the FERC accepted amendments to the NEPOOL Agreement and the Participants Agreement that (i) revise the AR Provider definition to allow the AR Sector and the Participants Committee,
68 ISO New England Inc., 152 FERC ¶ 61,115 (Aug. 7, 2015). 69 “The Localized Incremental Return on Equity will be adjusted accordingly so that the aggregate ROE does not exceed the top of the range for the aggregate allowed ROE set forth by the Commission.” 70 Id. at P 10. Page 16 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7 together, to determine that a Participant has a Substantial Business Interest in Alternative Resources, sufficient to qualify the Participant as an AR Provider, (ii) create group representation in the AR Sector, similar to the group seat arrangement that currently exists in the Generation Sector, in which RGs with five MW or more of Renewable Generation Resources would be eligible and could voluntarily elect to participate; and (iii) implement a number of clean-up changes that update certain defined terms and remove references to arrangements no longer in effect. These amendments were accepted as of October 1, 2015, as requested. Unless the September 28 order is challenged, this proceeding will be concluded. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).
VIII. Regional Reports
• Capital Projects Report - 2015 Q2 (ER15-2443) As previously reported, the ISO filed on August 13 its Capital Projects Report and Unamortized Cost Schedule covering the second quarter (“Q2”) of calendar year 2015 (the “Report”). The ISO is required to file the Report under Section 205 of the FPA pursuant to Section IV.B.6.2 of the Tariff. Highlights include the following new projects: (i) Wind Integration Phase II/ DNE Dispatch ($5.14 million); (ii) FCA10 ($2.715 million); (iii) NERC CIP v5 Compliance ($2.229 million); (iv) Business Continuity Plan Infrastructure Enhancements Phase III – Remote Desktop ($726,800); (v) Zonal Load Forecast ($680,000); (vi) IT Hardware & Software Asset Management ($317,200); (vii) Internet Explorer v11 Upgrade ($302,000); (viii) Web Content Management System (“CMS”) Enhancements 2015 ($179,000); and (ix) Synchrophasor Initiatives ($165,000). Projects reported to have had a significant change are: (i) Generator Dynamics Data Management ($105,000 decrease); and (ii) due to resource constraints and higher priority work, 2015 capital budget resources will not be allocated to the Power System Modeling, VPN System Upgrade, or the Quarterly Release Projects. On August 27, NEPOOL filed comments supporting the filing. A doc-less intervention was filed by Entergy. This matter is pending before the FERC. If you have any questions concerning this matter, please contact Paul Belval (860-275-0381; [email protected]) or Kristin Sullivan (617-345-4657; [email protected]).
• Opinion 531-A Refund Report: FG&E (EL11-66) On June 29, 2015, FG&E filed its refund report for its customers taking local service during the refund period in accordance with Opinion 531-A. Comments, if any, on this filing were due on or before July 20; none were filed and this matter is pending before the FERC. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).
• Reserve Market Compliance (19th) Semi-Annual Report (ER06-613) As directed by the original ASM II Order,71 as modified,72 the ISO submitted its 19th semi-annual reserve market compliance report on October 1, 2015. In the 19th report, the ISO explained, as in its prior compliance reports, that work on the forward TMSR market issues continues to be on hold due to its efforts on other priority projects. Due to the ISO’s efforts on other priority projects, work on the forward TMSR market issues is on hold, and the ISO reports that it does not contemplate revisiting this issue until at least 2018. If there are questions on this matter, please contact Dave Doot (860-275-0102; [email protected]).
71 See NEPOOL and ISO New England Inc., 115 FERC ¶ 61,175 (2006) (“ASM II Order”) (directing the ISO to provide updates on the implementation of a forward TMSR market), reh’g denied 117 FERC ¶ 61,106 (2006). 72 See NEPOOL and ISO New England Inc., 123 FERC ¶ 61,298 (2008) (continuing the semi-annual reporting requirement with respect to the consideration and implementation of a forward market for Ten-Minute Spinning Reserve (“TMSR”)). Page 17 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
• IMM Quarterly Markets Reports - 2015 Q2 (ZZ15-4) On October 1, the Internal Market Monitor (“IMM”) filed with the FERC its report for the second of 2015 of “market data regularly collected by [it] in the course of carrying out its functions under … Appendix A and analysis of such market data,” as required pursuant to Section 12.2.2 of Appendix A to Market Rule 1. Highlights from this report will be reviewed by the IMM at the October 2, 2015 Participants Committee meeting (agenda item # 4A). These filings are not noticed for public comment by the FERC.
IX. Membership Filings
• October 2015 Membership Filing (ER16-1) On October 1, NEPOOL requested that the FERC accept (i) the membership of Antrim Wind Energy (Provisional Group Member), Astral Energy (Supplier Sector), Beacon Falls Energy Park (Related Person to Kleen Energy – Generation Sector), Champlain VT (Provisional Group Member), Concord Steam Corporation, (Provisional Group Member), Deepwater Wind Block Island (AR Sector, Large AR Group Seat), Invenergy Energy Management (Provisional Group Member), and MA Operating Holdings (Related Person to SunEdison– AR Sector, RG Sub-Sector); (ii) termination of the Participant status of HOP Energy (Supplier Sector), energy.me (Supplier Sector), Parkview AMC Energy (MPEU), Denver Energy (Related Person to Peninsula Power - Supplier Sector), and Johnston Clean Power (Provisional Group Member); and (iii) the name change of NRG Curtailment Solutions, Inc. (f/k/a Energy Curtailment Specialists). Comments on this filing are due on or before October 21, 2015.
• September 2015 Membership Filing (ER15-2584) On August 31, NEPOOL requested that the FERC accept the membership of Green Development, LLC d/b/a Wind Energy Development, LLC (AR Sector, Small RG Group Member); Johnston Clean Power (Provisional Member); UIL Distributed Resources [Related Person of UI – Transmission Sector]; and Uncia Energy (Supplier Sector). Comments on this filing are due on or before September 21, 2015.
X. Misc. - ERO Rules, Filings; Reliability Standards
Questions concerning any of the ERO Reliability Standards or related rule-making proceedings or filings can be directed to Pat Gerity (860-275-0533; [email protected]).
• FFT Report: September 2015 (NP15-36) NERC submitted on September 30, 2015 its Find, Fix, Track and Report (“FFT”) informational filing for the month of September 2015. The September FFT resolves 3 possible violations of 2 Reliability Standards that posed a risk minimal risk to bulk power system (“BPS”) reliability, but which has since been remediated.73 FFT filings are for information only and are not be noticed for public comment by the FERC.
• Revised Reliability Standards: IRO-006-EAST-2; IRO-009-2 (RD15-7) On September 16, 2015, NERC filed for approval changes to IRO-006-EAST-2 (Transmission Loading Relief Procedure for the Eastern Interconnection) and IRO-009-2 (Reliability Coordinator Actions to Operate within IROLs). NERC states that IRO-006-EAST-2 removes redundant requirements based on Paragraph 819 criteria, revises existing language to clearly delineate applicable entities and the specific actions required, and relocates information in bullet points and subparts to the Requirements. IRO-009-2 combines two existing requirements, revises existing language to clearly delineate applicable entities and the specific actions required, and removes unnecessary language. NERC adds that both Standards implement language revisions and format
73 Only possible violations that pose a minimal risk to Bulk-Power System reliability are eligible for FFT treatment. See N. Am. Elec. Reliability Corp., 138 FERC ¶ 61,193 (Mar. 15, 2012) at PP 46-56. Page 18 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7 improvements for consistency with recent Board-approved Reliability Standards. Comments on this filing are due on or before October 19, 2015.
• Revised Reliability Standards: PRC-004-5; PRC-010-2 (RD15-5) As previously reported, NERC filed for approval, on June 8, 2015, changes to PRC-004-5 (Protection System Misoperation Identification and Correction) and PRC-010-2 (Under Voltage Load Shedding). The proposed Reliability Standards address misoperation of undervoltage load shedding (“UVLS”) equipment and were developed as Phase 2 of NERC’s pending proposal to consolidate UVLS Program Reliability Standards. Comments on this filing were due on or before July 9, 2015; none were filed. On July 7, NERC proposed revisions to the Violation Risk Factors (“VRF”) for Requirements R1 through R6 of PRC-004-5 (as well as for PRC-004-3 and PRC-004-5). Comments on the July 7 filing were due on or before August 7, and one set was filed by Peak Reliability. This matter remains pending before the FERC.
• NOPR: Revised TOP and IRO Reliability Standards (RM15-16) As previously reported, the FERC issued, on June 18, 2015, a NOPR proposing to approve changes reflected in the following Transmission Operations (“TOP”) and Interconnection Reliability Operations and Coordination (“IRO”) Reliability Standards:74 TOP-001-3 (Transmission Operations); TOP-002-4 (Operations Planning); TOP-003-3 (Operational Reliability Data); IRO-001-4 (Reliability Coordination – Responsibilities); IRO-002-4 (Reliability Coordination –Monitoring and Analysis); IRO-008-2 (Reliability Coordinator Operational Analyses and Real-time Assessments); IRO-010-2 (Reliability Coordinator Data Specification and Collection); IRO-014-3 (Coordination Among Reliability Coordinators); and IRO-017-1 (Outage Coordination). NERC indicated that the TOP/IRO Standards, which supersede the changes submitted in RM13-15, -14, and -12, but concurrently withdrawn, include improvements over the currently effective TOP and IRO Reliability Standards in key areas such as: (1) operating within SOLs and IROLs; (2) outage coordination; (3) situational awareness; (4) improved clarity and content in foundational definitions; and (5) requirements for operational reliability data. NERC requested that the TOP/IRO Changes be approved as of the first day of the first calendar quarter that is 12 months after the date that the Standards are approved, with the exception of TOP-003-3 and proposed IRO-010-2, which were requested to be approved 3 months earlier. On May 12, NERC supplemented its March 18 filing by removing Load Serving Entities (“LSEs”) from the applicability of proposed Reliability Standard TOP-001-3 in light of the FERC’s order on NERC’s Risk-Based Registration (“RBR”) initiative.75 Comments on this NOPR were due on or before August 24, 2015,76 and more than 14 sets of comments were filed, including joint comments by ISO-NE, IESO, MISO, NYISO, PJM and SPP, and individual comments by Dominion, EEI, ERCOT, and NERC. The TOP/IRO NOPR remains pending before the FERC.
• NOPR: Revised Reliability Standards: CIP-003-6, CIP-004-6, CIP-006-6, CIP-007-6, CIP-009-6, CIP- 010-2, CIP-011-2 (RM15-14) On July 16, 2015, the FERC issued a NOPR proposing to approve changes to seven CIP (“Critical Infrastructure Protection”) Reliability Standards to improve the cyber security protections required by the CIP
74 Transmission Operations Reliability Standards and Interconnection Reliability Operations and Coordination Reliability Standards, 151 FERC ¶ 61,236 (May 14, 2015) (“TOP/IRO NOPR”). 75 N. Am. Elec. Reliability Corp., 150 FERC ¶ 61,213 (2015) (“RBR Order”). 76 The TPL/IRO NOPR was published in the Fed. Reg. on June 24, 2015 (Vol. 80, No. 121) pp. 36,280-36,293. Page 19 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
Standards and address four directives from Order 791 (the “Supply Chain Cyber Controls Changes”).77 NERC stated that the Supply Chain Cyber Controls Changes (i) remove the “identify, assess, and correct” language from the 17 requirements in the CIP Version 5 Standards that included such language; (ii) require responsible entities to implement cyber security plans for assets containing low impact BES Cyber Systems; (iii) include specific requirements applicable to transient devices to further mitigate the security risks associated with such devices; and (iv) require entities to implement security controls for non-programmable components of communication networks at Control Centers with high or medium impact BES Cyber Systems. NERC requested that the Supply Chain Cyber Controls be approved, effective on April 1, 2016. Comments on the Revised CIPs NOPR were due on or before September 21, 2015,78 and were filed by over 40 parties, including NERC, ISO-NE, NextEra, and APPA/EEI/EPSA/ELCON/NRECA et al. This matter is pending before the FERC.
• Revised Reliability Standards: Transition to “Remedial Action Scheme”, PRC-010-1, EOP-011-1 (RM15-13, RM15-12; RM15-7) As previously reported, the FERC issued a NOPR,79 on June 18, proposing to approve three related NERC petitions that revise (i) the definition of “Remedial Action Scheme” and nearly 20 Reliability Standard to insert that term in place of the term “Special Protection System”, which are used interchangeably throughout the Reliability Standards (the “RAS Changes”) (RM15-13); (ii) PRC-010-1 (Undervoltage Load Shedding), a definition of “Undervoltage Load Shedding Program (UVLS Program)”, and associated VRFs and VSLs (together, the “UVLS Changes”) (RM15-12); and (iii) EOP-011-1 (Emergency Operations), a revised definition of “Energy Emergency”, and associated VRFs and VSLs (together, the “Emergency Operations Changes”) (RM15-7). Comments on this NOPR were due on or before August 24, 2015,80 and were filed by NERC, EEI, ITC, Peak Reliability, TAPS, and the Idaho Power Company. This matter remains pending before the FERC. • NOPR: New Reliability Standard: TPL-007-1 (RM15-11) On May 14, 2015, FERC issued a NOPR proposing to approve a new Reliability Standard -- TPL-007-1 (Geomagnetic Disturbance Operations) -- and one new definition (Geomagnetic Disturbance Vulnerability Assessment), associated VRFs and VSLs (together, the “GMD Operations Changes”).81 In addition, the FERC proposes to direct NERC (i) to develop modifications to the benchmark GMD event definition set forth in TPL- 007-1 Attachment 1 so that the definition is not based solely on spatially-averaged data and (ii) to submit a work plan, and subsequently one or more informational filings, that address specific GMD-related research areas. As previously reported, NERC stated that the GMD Operations Changes address the FERC’s directive in Order 779 that NERC develop a Reliability Standard that requires owners and operators of the Bulk-Power System to conduct initial and on-going vulnerability assessments of the potential impact of benchmark geomagnetic disturbance events on the Bulk-Power System equipment and the Bulk-Power System as a whole.82 NERC requested the FERC approve a five-year phased implementation plan for Compliance with TPL-007-1. Comments on this NOPR were due on or before July 27, 201583 and were filed by over 20 parties, including ISO- NE/NYIOS/PJM/MISO/IESO, EEI, Exelon, and NERC. On August 17, NERC filed a notice that the appeal panel appointed under NERC’s process for Standards appeals had concluded NERC appeal proceedings by using a final decision finding that the objections of appellant Foundation for Resilient Societies, Inc. were afforded fair and
77 Revised Critical Infrastructure Protection Reliability Standards, 152 FERC ¶ 61,054 (July 16, 2015) (“Revised CIPs NOPR”). 78 The Revised CIPs NOPR was published in the Fed. Reg. on July 22, 2015 (Vol. 80, No. 140) pp. 43,354-43,367. 79 Revisions to Emergency Operations Reliability Standards; Revisions to Undervoltage Load Shedding Reliability Standards; Revisions to the Definition of “Remedial Action Scheme” and Related Reliability Standards, 151 FERC ¶ 61,230 (June 18, 2015). 80 The NOPR was published in the Fed. Reg. on June 24, 2015 (Vol. 80, No. 121) pp. 36,293-36,301. 81 Reliability Standard for Transmission System Planned Performance for Geomagnetic Disturbance Events, 151 FERC ¶ 61,134 (May 14, 2015) (“TPL-007 NOPR”). 82 Reliability Standards for Geomagnetic Disturbances, Order No. 779, 143 FERC ¶ 61,147 (“Order 779”). 83 The TPL-007 NOPR was published in the Fed. Reg. on May 26, 2015 (Vol. 80, No. 100) pp. 29,990-30,001. Page 20 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7 equitable treatment during the TPL-007-1 development process. Comments on that panel’s decision were due and filed by September 10. This matter is pending before the FERC.
• Order 813: Revised Reliability Standard: PRC-005-4 (RM15-9) On September 17, 2015, the FERC issued a final rule (“Order 813”) approving changes to PRC-005-4 (Protection System, Automatic Reclosing, and Sudden Pressure Relaying Maintenance), one new (Sudden Pressure Relaying) and four revised definitions (Protection System Maintenance Program, Component Type, Component, and Countable Event), and the associated VRFs and VSLs (together, the “PRC-005 Changes”).84 As previously reported, NERC stated that the PRC-005 Changes address FERC concerns expressed in the Order 758 proceeding that NERC’s proposed interpretation of PRC-005-1 may not include all components that serve in some protective capacity.85 Order 813 will become effective November 23. 2015.86 Unless Order 813 is challenged, this proceeding will be concluded.
• NOPR: New Reliability Standard: PRC-026-1 (RM15-8) On September 17, 2015, the FERC issued a NOPR proposing to approve PRC-026-1 (Relay Performance During Stable Power Swings) and associated VRFs and VSLs (the “PRC-026 Standard”). As previously reported, the PRC-026 Standard was filed in response to the FERC’s directive to NERC in Order 73387 to develop a Reliability Standard addressing undesirable relay operation due to stable power swings. NERC requested that PRC-026 be approved, effective as follows: R1 on the first day of the first full calendar year that is 12 months after FERC approval; R2-R4 on the first day of the first full calendar year that is 36 months after FERC approval. Comments on this NOPR are due on or before November 23, 2015.88
• Order 814: Revised Reliability Standard: PRC-002-2 (RM15-4) On September 17, 2015, the FERC issued a final rule (“Order 814”) approving changes to PRC-002-2 (Disturbance Monitoring and Reporting Requirements), associated VRFs and VSLs, and the retirement of PRC- 002-1 (Define Regional Disturbance Monitoring and Reporting Requirements) and PRC-018-1 (Disturbance Monitoring Equipment Installation and Data Reporting) (together, the “PRC-002 Changes”).89 As previously reported, NERC stated that the PRC-002 Changes address FERC concerns expressed in Order 69390 with the “fill in the blank” aspects in PRC-002-1 and PRC-018-1.91 Order 814 will become effective on November 24, 2015.92
84 Protection System, Automatic Reclosing, and Sudden Pressure Relaying Maintenance Reliability Standard, 152 FERC ¶ 61,199 (Sep. 17, 2015) (“Order 813”). 85 Interpretation of Protection System Reliability Standard, Notice of Proposed Rulemaking, 133 FERC ¶ 61,223 (2010) at P 11; Interpretation of Protection System Reliability Standard, Order No. 758, 138 FERC ¶ 61,094 (“Order 758”), order on reh’g, 139 FERC ¶ 61,227 (2012). 86 Order 813 was published in the Fed. Reg. on Sep. 24, 2015 (Vol. 80, No. 185) pp. 57,526-57,531. 87 Transmission Relay Loadability Reliability Standard, Order No. 733, 130 FERC ¶ 61,221 (2010); order on reh’g and clarif., Order No. 733-A, 134 FERC ¶ 61,127 (2011); clarified, Order No. 733-B, 136 FERC ¶ 61,185 (2011) (“Order 733”). 88 The PRC-026 NOPR was published in the Fed. Reg. on Sep. 24, 2015 (Vol. 80, No. 185) pp. 57,549-57,553. 89 Disturbance Monitoring and Reporting Requirements Reliability Standard, Order No. 814, 151 FERC ¶ 61,042 (Sep, 17, 2015) (“Order 814”). 90 Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, 72 FR 16416, FERC Stats. & Regs. ¶ 31,242, at PP 1131-1222, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007) (“Order 693”). 91 Interpretation of Protection System Reliability Standard, Notice of Proposed Rulemaking, 133 FERC ¶ 61,223 (2010) at P 11; Interpretation of Protection System Reliability Standard, Order No. 758, 138 FERC ¶ 61,094 (“Order 758”), order on reh’g, 139 FERC ¶ 61,227 (2012). 92 Order 814 was published in the Fed. Reg. on Sep. 25, 2015 (Vol. 80, No. 186) pp. 57,704-57,709. Page 21 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
• NOPR: Revised Reliability Standard: MOD-001-2 (RM14-7) The MOD-001-2 NOPR remains pending before the FERC. On June 19, 2014, the FERC issued a NOPR proposing to approve changes to MOD-001-2 (Modeling, Data, and Analysis - Available Transmission System Capability) (“MOD Changes”) proposed by NERC. The MOD Changes replace, consolidate and improve upon the Existing MOD Standards in addressing the reliability issues associated with determinations of Available Transfer Capability (“ATC”) and Available Flowgate Capability (“AFC”). MOD-001-2 will replace the six Existing MOD Standards93 to exclusively focus on the reliability aspects of ATC and AFC determinations. NERC requested that the revised MOD Standard be approved, and the Existing MOD Standards be retired, effective on the first day of the first calendar quarter that is 18 months after the date that the proposed Reliability Standard is approved by the FERC. NERC explained that the implementation period is intended to provide NAESB sufficient time to include in its WEQ Standards, prior to MOD-001-2’s effective date, those elements from the Existing MOD Standards, if any, that relate to commercial or business practices and are not included in proposed MOD- 001-2. The FERC seeks comment from NAESB and others whether 18 months would provide adequate time for NAESB to develop related business practices associated with ATC calculations or whether additional time may be appropriate to better assure synchronization of the effective dates for the proposed Reliability Standard and related NAESB practices. The FERC also seeks further elaboration on specific actions NERC could take to assure synchronization of the effective dates. Comments on this NOPR were due August 25, 2014,94 and were filed by NERC, Bonneville, Duke, MISO, and NAESB. On December 19, 2014, NAESB supplemented its comments with a report on its efforts to develop WEQ Business Practice Standards that will support and coordinate with the MOD Standards proposed in this proceeding. Since the last Report, NASEB issued a report on September 25, 2015, informing the FERC that the NAESB standards development process has been completed and NAESB will file the new suite of business practice standards as part of Version 003.1 of the NAESB WEQ Business Practice Standards in October 2015. As noted above, the MOD-001-2 NOPR remains pending before the FERC.
• NOPR: BAL-002-1a Interpretation Remand (RM13-6) This May 16, 2013 NOPR, which proposes to remand NERC’s proposed interpretation of BAL-002 (Disturbance Control Performance Reliability Standard) filed February 12, 2013 (which would prevent Registered Entities from shedding load to avoid possible violations of BAL-002), remains pending.95 NERC asserted that the proposed interpretation clarifies that BAL-002-1 is intended to be read as an integrated whole and relies in part on information in the Compliance section of the Reliability Standard. Specifically, the proposed interpretation would clarify that: (1) a Disturbance that exceeds the most severe single Contingency, regardless if it is a simultaneous Contingency or non-simultaneous multiple Contingency, would be a reportable event, but would be excluded from Compliance evaluation; (2) a pre-acknowledged Reserve Sharing Group would be treated in the same manner as an individual Balancing Authority; however, in a dynamically allocated Reserve Sharing Group, exclusions are only provided on a Balancing Authority member by member basis; and (3) an excludable Disturbance was an event with a magnitude greater than the magnitude of the most severe single Contingency. The FERC, however, proposes to remand the proposed interpretation because it believes the interpretation changes the requirements of the Reliability Standard, thereby exceeding the permissible scope for interpretations. Comments on the BAL-002-1a Interpretation Remand NOPR were due on or before July 8, 2013,96 and were filed by NERC, EEI, ISO/RTO Council, MISO, NC Balancing Area, Northwest Power Pool Balancing Authorities, NRECA, and WECC. This NOPR remains pending before the FERC.
93 The 6 existing MOD Standards to be replaced by MOD-001-2 are: MOD-001-1, MOD-004-1, MOD-008-1, MOD-028-2, MOD-029-1a and MOD-030-2. 94 The MOD-001-2 NOPR was published in the Fed. Reg. on June 26, 2014, (Vol. 79, No. 123) pp. 36,269-36,273. 95 Electric Reliability Organization Interpretation of Specific Requirements of the Disturbance Control Performance Standard, 143 FERC ¶ 61,138 (2013) (“BAL-002-1a Interpretation Remand NOPR”). 96 The BAL-002-1a Interpretation Remand NOPR was published in the Fed. Reg. on May 23, 2013 (Vol. 78, No. 99) pp. 30,245-30,810. Page 22 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
• Compliance Filing: BES Exclusions for Local Network Configurations (RM12-6) On July 1, 2015, NERC submitted, pursuant to Order 773, a Compliance filing identifying in detail the types of local network configurations that may be excluded from the bulk electric system (“BES”) following the implementation of the revised definition of the BES under Exclusion E3 of that definition. As of the date of this Report, the FERC has not noticed the Compliance filing or otherwise invited public comment.
• Revised Regional Delegation Agreements (RR15-12) On June 26, NERC requested approval of revised Regional Delegation Agreements (“RDAs”) with each of the eight Regional Entities, including NPCC, to be effective January 1, 2016, replacing the currently effective RDAs whose terms expire December 31, 2015. The revised RDAs will have five-year terms that automatically renew for another five-year term unless either party gives notice to terminate one year in advance of the end of the term. NERC stated that it and the Regional Entities believe the revised RDAs will enhance clarity and consistency in the operations of the ERO, and will also provide for flexibility without diminishing NERC’s oversight authority over the Regional Entities’ performance of their delegated functions. Comments on the RDA revisions were due on or before July 27. Joint comments were submitted by APPA/TAPS, the Large Public Power Council, Public Utility District No. 1 of Snohomish County, WA (“Snohomish”), and Avista, Idaho Power, Portland General Electric, Puget Sound Energy, and the Tri-State Generation Association (with respect to the WECC Delegation Agreement. Answers were filed by NERC, the Western Interconnection Regional Advisory Board, Snohomish, and Avista. This matter is pending before the FERC.
• Removal of LSE Category from NERC Compliance Registry (RR15-4) On July 17, 2015, NERC filed for FERC approval the removal of the Load-Serving Entity (“LSE”) functional registration category from the NERC Compliance Registry (“NCR”), as well as additional limited changes to the NERC Rules of Procedure (“ROP”). Comments on this filing were due on or before August 17, 2015, and were filed jointly by APPA, NRECA, and TAPS, and individually by Dominion. This matter is pending before the FERC.
• E. Morris v. NERC/SERC (EL15-93) On August 21, Eric S. Morris (“Morris”) filed a formal complaint against NERC and SERC Reliability Corporation (“SERC”) (collectively, “Respondents”), alleging that the Respondents violated NERC’s Rules of Procedure Appendix 4B Sanction Guidelines in assessing a penalty on Entergy (see NP15-31, filed July 30, 2015). Morris alleges that the Respondents failed to follow the Sanction Guidelines by failing to clearly identify that an alternative frequency or duration was used in determining the penalty and providing no supporting rationale. Morris asks that the Notice of Penalty be withdrawn or denied, and resubmitted with either the clear identification of the alternative frequency and duration with rationale or with a settlement base amount “re- adjusted into the multi-million dollar range.” Interventions and comments on the protest were due on or before September 10. NERC and SERC answered the Complaint on September 10. No other interventions or comments were filed. Since the last Report, on September 16, Mr. Morris partially withdraw his Complaint so that he could either petition for a Rulemaking under Rule 207(a)(4) or complain under 18 CFR § 39.10(b) for changes to the NERC Rules of Procedure (ROP) Appendix 4B Sanction Guidelines (Sanction Guidelines). This matter is pending before the FERC.
XI. Misc. - of Regional Interest
• 203 Application: Iberdrola/CMP/ Emera (EC15-103) On June 2, the FERC authorized a transaction whereby UIL Holdings Corp (“UI”) will become an indirect, wholly-owned subsidiary of Iberdrola, S.A (and a Related Person of Central Maine Power Company, Iberdrola Renewables, LLC, and New York State Electric & Gas Corporation).97 Iberdrola and UI must notify the FERC within 10 days of the date that the disposition of jurisdictional facilities has been consummated. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).
97 Iberdrola, S.A. et al., 151 FERC ¶ 62,148 (June 2, 2015). Page 23 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
• FirstEnergy PJM DR Complaint (EL14-55) On May 23, 2014, the same day that DC Circuit vacated Order 745 (see Section XV below), FirstEnergy filed a complaint against PJM requesting that the FERC require the “removal of all portions of the PJM Tariff allowing or requiring PJM to include demand response as suppliers to PJM’s capacity markets.” FirstEnergy also requested that the results of the PJM capacity auction due to be released that same day, to the extent it included and cleared demand response resources, be considered void and legally invalid. PJM’s response, and all comments and interventions were initially due on or before June 12, 2014. However, on June 11, the FERC extended that date to 30 days after the submission by FirstEnergy of an amended complaint. FirstEnergy filed its amended complaint on September 22, 2014.
Comments on the FirstEnergy Complaint were due October 22, 2014. More than 40 parties filed comments or responses to the FirstEnergy amended complaint. Many parties filed comments supporting the complaint (including Calpine, PSEG and PPL), while others opposed the complaint in its entirety (including Direct Energy and Enerwise). PJM’s response argued that the complaint failed to justify the market disruption that would result from recalculating past capacity auction results, PJM was instead more focused on minimizing “litigation risk.” A number of parties filed supporting comments in favor of removing demand response resources from the PJM tariff moving forward, but opposed to recalculating the results of past capacity auctions (including Exelon, the PJM IMM and NRG). Comments were also filed by National Grid and NYISO. A number of New England parties intervened, including NEPOOL (stressing that the FERC should not apply any ruling in this docket to the New England Market), Dominion, Duke Energy, Dynegy, Essential Power, Macquarie Energy, NEPGA, NESCOE, and NextEra. On November 14, FirstEnergy filed an answer to the answers, protests and comments submitted in response to its Complaint and Amended Complaint. Environmental Advocates98 filed an answer to FirstEnergy’s answer on November 21. Since the last Report, CPower and Advanced Energy Management Alliance filed answers to the FirstEnergy and other answers and pleadings. On December 23, Environmental Advocates moved to lodge the US Solicitor General’s application for an extension of time in which to file a petition for writ of certiorari, the Supreme Court Clerk’s notice to the DC Circuit that the extension had been granted, and the DC Circuit’s order extending the stay of its mandate pending the Supreme Court’s final disposition of the writ of certiorari. This matter remains pending before the FERC. If you have any questions concerning this matter, please contact Jamie Blackburn ([email protected]; 202-218-3905) or Pat Gerity ([email protected]; 860- 275-0533).
• CPV Towantic LGIA Cancellation (ER15-2605) On September 3, the ISO filed a notice of cancellation of an LGIA among the ISO, Eversource (CL&P) and CPV Towantic. The ISO indicated that the LGIA was superseded by a new three-party pro forma LGIA, which need not be filed, but instead will be reported going forward through the ISO’s EQRs. A November 1, 2014 effective date was requested. Comments on the cancellation were due on or before September 24; none were filed. This matter is pending before the FERC. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).
• E&P Agreement Termination: CMP/Atlantic Wind (ER15-2603) On September 2, CMP filed to terminate an Engineering and Procurement Agreement (“E&P Agreement”) between CMP and Atlantic Wind, LLC (“Atlantic Wind”). CMP reported that the MPUC issued an August 5, 2015 order denying CMP’s request for approval of the E&P Agreement. Based on the lack of required MPUC approval, CMP is not able to perform the contemplated engineering and procurement services. A November 1, 2015 effective date was requested. Comments on the cancellation were due on or before September 23; none were filed. This matter is pending before the FERC. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).
98 “Environmental Advocates” are Sustainable FERC Project, Natural Resources Defense Council (“NRDC”), Sierra Club, Environmental Defense Fund, Environmental Law and Policy Center, and Acadia Center (f/k/a Environment Northeast). Page 24 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
• Construction Agreement: MEPCO/Number Nine Wind Farm (ER15-2451) On September 10, the FERC accepted the Construction Agreement between MEPCO and Number Nine Wind Farm LLC (“Number Nine”) (designated as service agreement MEPCO-CA-1 under MEPCO’s eTariff files) related to the planned 250 MW wind farm in Aroostook County, Maine. As previously reported, the Construction Agreement sets forth the terms and conditions under which MEPCO will commence construction activities for the All Dielectric Self-Supporting (“ADSS”) fiber optic work that may be necessary for the project, but prior to the completion of applicable Interconnection Studies and the execution of a LGIA under Schedule 22 of the OATT. The Construction Agreement was accepted for filing as of August 13, 2015, as requested. Unless the September 10 order is challenged, this proceeding will be concluded. If there are questions on these matters, please contact Pat Gerity (860-275-0533; [email protected]).
• EPC Agreement: Blue Sky West & Emera Maine (ER15-1459) As previously reported, Emera Maine filed on April 7 an executed Engineering, Procurement, and Construction Agreement (“EPC Agreement”) Agreement with Blue Sky West, LLC (“Blue Sky West”) to facilitate the interconnection of the Blue Sky West’s 191 MW wind farm in Bingham, Mayfield Township and Kingsbury Plantation, Maine. While the Blue Sky West facility will be located in CMP’s service territory, upgrades and modifications at Orrington Substation, in part owned by Emera Maine, are required and will be covered under the EPC Agreement. A March 6, 2015 effective date was requested. SunEdison filed a doc-less intervention. No comments on the EPC Agreement filing were submitted before the April 28 comment date. This matter remains pending before the FERC. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).
• Emera MPD OATT Changes (ER15-1429) On April 1, Emera Maine filed changes to the Open Access Transmission Tariff (“OATT”) for Maine Public District (“MPD OATT”), including to the rates, terms, and conditions set forth in MPD OATT Attachment J. Emera Maine, as successor to Maine Public Service Company (“Maine Public”), provides open access to Emera Maine’s transmission facilities in northern Maine (the “MPD Transmission System”) pursuant to the MPD OATT. The changes to the MPD OATT are needed to ensure that, in light of the filing by Emera of consolidated FERC Form 1 data (data comprising both the former Bangor Hydro and Maine Public systems), charges for service under the MPD OATT reflect only the costs of service over the MPD Transmission System. Emera Maine also proposed additional, limited changes to the MPD OATT. A June 1, 2015 effective date was requested. On April 9, the “Maine Customer Group”99 filed a motion to reject (“Motion to Reject”) the April 1 Filing, asserting the April 1 Filing was deficient because, rather than actual rates, it included proxy rates that MPD said would be replaced with 2014 Form 1 numbers when MPD’s 2014 Form 1 was available. On April 22, the Maine PUC and the Maine Customer Group protested the filing. The MPUC challenged three aspects of the filing: (i) the proposed increase of ROE from 9.75% to 10.20% based on anomalous economic conditions; (ii) the change from a measured loss factor calculation to a fixed loss factor; and (iii) the use of end-of-year account balances, rather than average 13-month account balances, for determination of facilities that are included in rate base. In addition to those aspects, the Maine Customer Group further challenged: (iv) inclusion of an out-of-period adjustment to rate base for forecasted transmission; (v) the proposed capital structure, which they assert is artificially distorted to accommodate a requirement resulting from the merger of Emera Maine’s predecessor companies; and (vi) the proposed new cost allocation scheme. On April 24, Emera Maine answered the Maine Customer Group’s Motion to Reject. On April 29, the Maine Customer Group answered Emera Maine’s April 24 answer. On May 1, Emera Maine filed an amendment and errata to its April 1 filing, in part reflecting 2014 FERC Form 1 data rather than estimated data. On May 7, Emera Maine answered the April 22 Maine PUC and MCG protests and the MCG’s April 29 answer. On May 8, MCG moved to compel revision to Emera’s May 1 filing, asserting that it was not filed in accordance with Emera’s OATT, and specifically the Protocols for Implementing and Reviewing Charges Established by the Attachment J Rate Formulas (the “Protocols”). MCG also protested
99 The “Maine Customer Group (“MCG”) is comprised of: the Maine Office of the Public Advocate (“MOPA”), Houlton Water Company (“Houlton”), Van Buren Light and Power District (“Van Buren”), and Eastern Maine Electric Cooperative, Inc. (“EMEC”). Page 25 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7 the May 1 filing on May 22. On May 26, Emera Maine answered MCG’s May 8 Motion to Compel, which MCG answered the next day. This matter remains pending before the FERC.
• MISO Methodology to Involuntarily Allocate Costs to Entities Outside Its Control Area (ER11-1844) On December 18, 2012, Judge Sterner issued his 374-page initial decision which, following hearings described in previous reports, found at its core that “it is unjust, unreasonable, and unduly discriminatory to allocate costs of Phase Angle Regulating Transformers (“PARs”) of the International Transmission Company (“ITC”) to NYISO and PJM”,100 which the Midwest ISO (“MISO”) and ITC proposed unilaterally to do (without the support of either PJM or NYISO) in its October 20, 2010 filing initiating this proceeding. For a summary of specific findings, please refer to any of the January to June 2013 Reports.
On January 17, 2013, ITC and MISO challenged the Initial Decision through their Brief on Exceptions. Briefs opposing exceptions were filed by the FERC Trial Staff, MISO TOs, NYISO, NY TOs, PJM, and the PJM TOs. On February 25, Joint Applicants moved to strike a portion of the PJM Brief Opposing Exceptions. On March 12, PJM answered Joint Applicants February 25 motion. MISO (now called “Midcontinent Independent System Operator, Inc.”) moved to lodge a NYISO “Broader Regional Markets Informational Report” filed March 19, 2014 in ER08-1281 and a related January 16, 2014 “Ontario- Michigan Interface PAR Performance Evaluation Report” (“Evaluation Report”) prepared by MISO, IESO and PJM. Oppositions to that motion to lodge were filed by FERC Staff, NYISO, NY TOs, PJM, and PSEG. This matter remains pending before the FERC. If there are any questions on this matter, please contact Eric Runge (617-345-4735; [email protected]).
• FERC Enforcement Action: Order of Non-Public, Formal Investigation (IN15-10) MISO Zone 4 Planning Resource Auction Offers. On October 1, 2015, the FERC issued an order authorizing Enforcement to conduct a non-public, formal investigation, with subpoena authority, regarding violations of FERC’s regulations, including its prohibition against electric energy market manipulation, that may have occurred in connection with, or related to, MISO’s April 2015 Planning Resource Auction for the 2015/16 power year.
Unlike a staff notice of alleged violation, a FERC order converting an informal, non-public investigation to a formal, non-public investigation does not indicate that the FERC has determined that any entity has engaged in market manipulation or otherwise violated any FERC order, rule, or regulation. It does, however, give OE’s Director, and employees designated by the Director, the authority to administer oaths and affirmations, subpoena witnesses, compel their attendance and testimony, take evidence, compel the filing of special reports and responses to interrogatories, gather information, and require the production of any books, papers, correspondence, memoranda, contracts, agreements, or other records.
• FERC Enforcement Action: Staff Notices of Alleged Violations (IN__-___) Coaltrain Energy/Co-Owners/Traders/Analyst. On September 11, 2015, the FERC issued a notice that Staff has preliminarily determined that Coaltrain Energy L.P. (“Coaltrain”); its co-owners Peter Jones and Shawn Sheehan; traders Robert Jones, Jeff Miller, and Jack Wells; and analyst Adam Hughes violated the FERC’s Anti- Manipulation Rule by executing a scheme involving manipulative PJM Up-To Congestion trading between June and September 2010. Specifically, Staff alleges that the individuals (on behalf of Coaltrain) planned and executed large volumes of PJM Up-To Congestion transactions designed to falsely appear to be spread trades but that were in fact a vehicle to collect “Marginal Loss Surplus Allocation” payments from PJM. Staff further alleges that Jones, Sheehan, and their agents (on behalf of Coaltrain) violated the FERC’s Market Behavior Rules by making false statements and omitting material information in responding to deposition questions and data requests during the investigation.
100 Midwest Indep. Trans. Sys. Op., Inc., 141 FERC ¶ 63,021 (Dec. 18, 2012) (“MISO Initial Decision”) at P 923. Page 26 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
Etracom/M. Rosenberg. On July 27, 2015, the FERC issued a notice that Staff has preliminarily determined that Etracom LLC (“Etracom”) and Michael Rosenberg violated the FERC’s Anti-Manipulation Rule by engaging in manipulative virtual trading at the New Melones Intertie in the CAISO footprint during May 2011. Enforcement has preliminarily determined that Etracom’s trades were intended to artificially lower the day-ahead LMP to benefit Etracom’s congestion revenue rights positions sourced at the same location. During the period in question, Rosenberg was Etracom’s principal trader and majority owner.
Recall that Notices of Alleged Violations (“NoVs”) are issued only after the subject of an enforcement investigation has either responded, or had the opportunity to respond, to a preliminary findings letter detailing Staff’s conclusions regarding the subject’s conduct.101 NoVs are designed to increase the transparency of Staff’s nonpublic investigations conducted under Part 1b of its regulations. A NoV does not confer a right on third parties to intervene in the investigation or any other right with respect to the investigation.
XII. Misc. - Administrative & Rulemaking Proceedings
• NOPR: Price Formation Fixes - Settlement Intervals/Shortage Pricing (RM15-24) On September 17, the FERC issued a NOPR proposing to revise its regulations to require that each RTO/ISO (i) settle (a) energy transactions in its real-time markets at the same time interval it dispatches energy and (b) operating reserves transactions in its real-time markets at the same time interval it prices operating reserves; and (ii) trigger shortage pricing for any dispatch interval during which a shortage of energy or operating reserves occurs.102 The FERC sated that adopting these reforms would align prices with resource dispatch instructions and operating needs, providing appropriate incentives for resource performance. The Settlement Intervals/Shortage Pricing NOPR will be discussed in more detail at the October 7-9 Markets Committee meeting. Comments on this NOPR are due on or before November 30, 2015.103
• NOPR: Connected Entity Data Collection (RM15-23) Also on September 17, the FERC issued a NOPR that would dramatically expand the corporate and relationship structure information that all Market Participants will be required to share with the ISO as a condition to their participation and that the ISO would be required to share with the FERC.104 The FERC proposes to require that all ISO/RTO market participants report all of the their “Connected Entities,” which is a newly defined term that is much broader than, and is intended to replace, “Affiliate” as defined in and administered under the ISO Tariff. The rule would multiply by several factors the amount of information required to be reported, by including reporting of certain employee and contractual relationships, and of debt/profitability arrangements. The NOPR proposes additional registration and compliance requirements for each market participant and RTO/ISO. The FERC explains in the NOPR that this additional data collection will improve the information that it has for detecting market manipulation, which is a FERC enforcement priority. A more detailed summary of the Connected Entity Data Collection NOPR was distributed with the additional materials for the October 2 meeting and will be discussed in more detail at that meeting. Comments on the Connected Entity Data Collection NOPR are also due on or before November 30, 2015.105
101 See Enforcement of Statutes, Regulations, and Orders, 129 FERC ¶ 61,247 (Dec. 17, 2009), order on requests for reh’g and clarification, 134 FERC ¶ 61,054 (Jan. 24, 2011). 102 Settlement Intervals and Shortage Pricing in Markets Operated by Regional Transmission Organizations and Independent System Operators, 152 FERC ¶ 61,218 (Sep. 17, 2015) (“Settlement Intervals/Shortage Pricing NOPR”). 103 The Settlement Intervals/Shortage Pricing NOPR was published in the Fed. Reg. on Sep. 29, 2015 (Vol. 80, No. 188) pp. 58,393-58,405. 104 Collection of Connected Entity Data from Regional Transmission Organizations and Independent System Operators, 152 FERC ¶ 61,219 (Sep. 17, 2015) (“Connected Entity Data Collection NOPR”). 105 The Connected Entity Data Collection NOPR was published in the Fed. Reg. on Sep. 29, 2015 (Vol. 80, No. 188) pp. 58,382-58,393. Page 27 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
• AWEA Petition for LGIA/LGIP Rulemaking (RM15-21) On June 19, the American Wind Energy Association (“AWEA”) petitioned the FERC to conduct a rulemaking to revise provisions of the FERC’s pro forma Large Generator Interconnection Procedures (“LGIP”) and pro forma Large Generator Interconnection Agreement (“LGIA”). AWEA states that various aspects of the LGIP and LGIA are out of date in comparison to current market conditions and do not ensure that the generation interconnection process is just, reasonable, and not unduly discriminatory or preferential. AWEA indicated that the rulemaking would address reforms to improve (i) certainty in the study and restudy process, (ii) transparency in the interconnection process, (iii) certainty of network upgrade costs, and accountability in the interconnection process. Comments in response to this petition were due on or before September 8, 2015. More than 30 sets of comments were filed, including by ISO-NE, NESCOE, ISO/RTO Council (“IRC”), APPA/NRECA/Large Public Power Council, EEI, EPSA, NextEra, NRG, and PSEG. This matter is pending before the FERC.
• Order 812: Revisions to Public Utility Filing Requirements (RM15-3) On July 16, the FERC issued Order 812106 revising its regulation to eliminate the requirement for (i) RTOs/ISOs and EWGs to submit FERC-566 (Annual Report of a Utility’s 20 Largest Customers), (ii) for public utilities that have not made any reportable sales under FERC-566 in any of the three preceding years to submit a FERC-566, and (iii) public utilities, when submitting FERC-566, to identify individual residential customers by name and address. The Order 812 changes will become effective October 6, 2015.107 On August 17, Dominion Resources Services, Inc. (“Dominion”) requested clarification and/or rehearing of Order 812 (seeking clarification that an entity that is both an EWG and QF is not required to file a FERC-566, or rehearing if not so clarified). On September 15, the FERC issued a tolling order affording it additional time to consider the Dominion request for clarification and/or rehearing, which remains pending before the FERC.
• NOPR: Third-Party Provision of Primary Frequency Response Service (RM15-2) On February 19, the FERC issued a NOPR proposing to foster competition in the sale of primary frequency response service108 by permitting its sale at market-based rates by sellers with market-based rate authority for energy and capacity. The FERC stated that this NOPR is an extension of its policy reforms begun with Order 784109 and anticipates the potential interest in purchase of primary frequency response service from third-parties as a result of a new reliability standard (BAL-003-1) that requires a Balancing Authority to maintain a minimum frequency response obligation. Comments on this NOPR were due on or before April 27, 2015110 and were filed by nearly 20 parties. The NOPR is pending before the FERC.
• NOPR: MBR Authorization Refinements (RM14-14) On June 19, the FERC issued a NOPR proposing to revise its current standards, and to streamline certain aspects of its filing requirements, for obtaining market-based rates (“MBR”) for sales of electric energy, capacity, and ancillary services.111 In addition, the FERC clarified certain standards for obtaining and retaining MBR authority. Among other changes, the FERC proposes (i) to permit sellers in RTO/ISO markets with Commission- approved market monitoring and mitigation to include a statement that they are relying on such mitigation to address any potential horizontal market power concerns in lieu of submitting the indicative screens; (ii) to permit
106 Revisions to Public Util. Filing Reqs., Order No. 812, 152 FERC ¶ 61,032 (July 16, 2015) (“Order 812”). 107 Order 812 was published in the Fed. Reg. on July 23, 2015 (Vol. 80, No. 141) pp. 43,619-43,625. 108 Primary frequency response service would be a reserve product that involves dedicating capacity on a generator or other resource for autonomous, automatic, and rapid action to change its output (within seconds) to rapidly dampen large changes in frequency. 109 Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric Storage Technologies, Order No. 784, 78 Fed. Reg. 46,178 (July 30, 2013), FERC Stats. & Regs. ¶ 31,349, at PP 6-7 (2013), order on clarif., Order No. 784-A, 146 FERC ¶ 61,114 (2014) (“Order 784”). 110 The NOPR was published in the Fed. Reg. on Feb. 26, 2015 (Vol. 80, No. 38) pp. 10,426-10,432. 111 Refinements to Policies and Procedures for Market-Based Rates for Wholesale Sales of Elec. Energy, Capacity and Ancillary Srvcs. by Public Utils., 147 FERC ¶ 61,232 (June 19, 2014) (“MBR NOPR”). Page 28 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7 sellers to explain that their qualified capacity is fully committed in lieu of including indicative screens in their filings in order to satisfy the FERC’s horizontal market power tests and to submit a change in status filing when there is a net increase of 100 MW or more; (iii) to relieve sellers of their obligation to file quarterly land acquisition reports and of the obligation to provide information on sites for generation capacity development in market-based rate applications and triennial updated market power analyses; (iv) to require a change in status filing if there is a 100 MW increase in cumulative nameplate capacity added in any relevant geographic market; and (v) require corporate org charts with all MBR applications and notices of change in status. Comments on this NOPR were due September 23, 2014.112 Over 25 parties filed comments and Berkshire Hathaway, Barrick Mines, and EPSA filed reply comments. This NOPR is pending before the FERC.
• Order 807: Open Access and Priority Rights on ICIF (RM14-11) On March 19, the FERC issued Order 807,113 which waives the Open Access Transmission Tariff (“OATT”) requirements of 18 CFR 35.28 (2013), the Open Access Same-Time Information System (“OASIS”) requirements of Part 37 of its regulations, 18 CFR 37 (2013), and the Standards of Conduct requirements of Part 358 of its regulations, 18 CFR 358 (2013), for any public utility that is subject to such requirements solely because it owns, controls, or operates Interconnection Customer’s Interconnection Facilities (“ICIF”),114 in whole or in part, and sells electric energy from its Generating Facility. Order 807 also finds that those seeking interconnection and transmission service over ICIF that are subject to the blanket waiver adopted in Order 807 may follow procedures applicable to requests for interconnection and transmission service under sections 210, 211, and 212 of the FPA, which also allows the contractual flexibility for entities to reach mutually agreeable access solutions. Order 807 establishes a modified rebuttable presumption for a 5-year safe harbor period to reduce risks to ICIF owners eligible for the blanket waiver during the critical early years of their projects. Finally, Order 807 modifies several elements of the NOPR, including the entities eligible for the OATT waiver, the date on which the safe harbor begins, the rebuttable presumption that the ICIF owner should not be required to expand its facilities during the safe harbor, and the facilities covered by Order 807. Order 807 will become effective June 30, 2015.115 Requests for rehearing and/or clarification of Order 807 were filed on April 20 by APPA/TAPS and NRECA. On May 15, the FERC issued a tolling order affording it additional time to consider the requests for rehearing, which remain pending before the FERC.
• WIRES Request for Policy Statement on ROE for Electric Transmission (RM13-18) As previously reported, WIRES116 petitioned the FERC, on June 26, 2013, to institute an expedited generic proceeding and to provide such policy and clarifications as necessary to provide “greater stability and predictability regarding regulated rates of return on equity for existing and future investments in high voltage electric transmission infrastructure.” Specifically, WIRES recommended a new policy that (1) standardizes selection of proxy groups; (2) denies complainants a hearing on rates of return for existing facilities unless it is shown that existing returns are at the extremes of the zone of reasonableness; (3) allows consideration of competing infrastructure investments of other industries; (4) permits use of other rate of return methodologies; and (5) supports use of more forward-looking data and modeling. In addition, WIRES urged the FERC to support consideration of a project’s actual and anticipated benefits when a complaint is filed against the ROE for an existing project. On September 16, the FERC dismissed the WIRES petition.117 In dismissing the petition, the FERC pointed to Opinion 531, which as reported previously addressed the
112 The MBR NOPR was published in the Fed. Reg. on July 25, 2014 (Vol. 79, No. 143) pp. 43,536-43,572. 113 Open Access and Priority Rights on Interconnection Customer’s Interconnection Facilities, Order No. 807, 150 FERC ¶ 61,211 (Mar. 19, 2015) (“Order 807”), reh’g requested. 114 ICIF is the term used by the FERC in the NOPR to refer to “generator tie lines”. 115 Order 807 was published in the Fed. Reg. on Apr. 1, 2015 (Vol. 80, No. 62) pp. 17,654-17,682. 116 WIRES, the Working group for Investment in Reliable and Economic Electric Systems, describes itself as a national non-profit association of investor-, member-, and publicly-owned entities dedicated to promoting investment in a strong, well-planned, and environmentally beneficial high voltage electric transmission grid. Information about its principles and members is available on its website www.wiresgroup.com. 117 Statement of Policy on Electric Transmission Rates of Return on Equity, 152 FERC ¶ 61,206 (Sep. 16, 2015). Page 29 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7 complaint against the New England TOs’ ROE, changed the DCF methodology to be used in determining a public utility’s ROE, and should be used as a guide in other ROE matters.
• Order 771: Availability of e-Tag Information to FERC Staff (RM11-12) Rehearing of portions of Order 771 has been requested and remains pending. As previously reported, Order 771,118 issued December 20, 2012, granted the FERC access, on a non-public and ongoing basis, to the complete electronic tags (“e-Tags”) used to schedule the transmission of electric power interchange transactions in wholesale markets. Order 771 requires e-Tag Authors (through their Agent Service) and Balancing Authorities (through their Authority Service) to take steps to ensure FERC access to the e-Tags covered by this Rule by designating the FERC as an addressee on the e-Tags. The FERC stated that the information made available under this Final Rule will bolster its market surveillance and analysis efforts by helping it detect and prevent market manipulation and anti-competitive behavior. In addition, Order 771 requires e-Tag information be made available to RTO/ISOs and their Market Monitoring Units, upon request to e-Tag Authors and Authority Services, subject to appropriate confidentiality restrictions. Order 771 became effective February 26, 2013.119 In response to requests for clarification and/or rehearing of Order 771 filed by EEI/NRECA, Open Access Technology International, Inc., NRECA (separately), and Southern Companies (collectively, the “Rehearing Requests”), the FERC issued, on March 8, 2013, Order 771-A.120 Order 771-A addressed only those issues that needed to be answered on an expedited basis to allow affected entities to comply with the requirement to ensure FERC access in a timely manner to the e-Tags covered by Order 771.121 The FERC noted that it would issue an additional rehearing order, addressing the remaining issues raised on rehearing and clarification, which therefore remain pending before the FERC.
XIII. Natural Gas Proceedings
For further information on any of the natural gas proceedings, please contact Joe Fagan (202-218-3901; [email protected]), Jennifer Galiette (860-275-0338; [email protected]) or Jamie Blackburn (202-218- 3905; [email protected]).
• Inquiry Into Natural Gas Trading, and Proposal to Establish an Electronic Information and Trading Platform (AD14-19) On September 18, 2014, Commissioner Moeller convened a meeting to discuss issues related to how transactions are conducted on the natural gas system and potential transactional improvements to address the needs of electric generators for natural gas. The meeting included representatives/speakers from various sectors of the natural gas and electric industries (load, suppliers, marketers, exchanges, gas associations, and ISOs) and environmental interests. Representatives from NYISO and PJM were among the speakers on the electric side (ISO-NE was not present). A summary of that meeting is posted on the Litigation Updates & Reports webpage (http://nepool.com/uploads/Lit_Supp_AD14-19_20140918_Mtg_Summary.pdf ). Written comments on issues discussed at the meeting, limited to 5 pages, were due on or before October 1, 2014.
118 Availability of E-Tag Info. to Comm’n Staff, Order No. 771, 141 FERC ¶ 61,235 (Dec. 20, 2012) (“Order 771”), order on reh’g and clarif., 142 FERC ¶ 61,181 (2013). 119 Order 771 was published in the Fed. Reg. on Dec. 28, 2012 (Vol. 77, No. 249) pp. 76,367-76,380. 120 Availability of E-Tag Info. to Comm’n Staff, Order No. 771-A, 142 FERC ¶ 61,181 (Mar. 8, 2013) (“Order 771-A”). 121 Order 771-A clarified that: (1) Balancing Authorities and their Authority Services will have until 60 days after publication of this order to implement the validation requirements of Order 771; (2) validation of e-Tags means that the Sink Balancing Authority, through its Authority Service, must reject any e-Tags that do not correctly include the FERC in the CC field; (3)the requirement for the FERC to be included in the CC field on the e-Tags applies only to e-Tags created on or after March 15, 2013; (4) the FERC will deem all e-Tag information made available to the FERC pursuant to Order 771 as being submitted pursuant to a request for privileged and confidential treatment under 18 CFR 388.112; (5) the FERC is to be afforded access to the Intra-Balancing Authority e-Tags in the same manner as interchange e-Tags; and (6) the requirement on Balancing Authorities to ensure FERC access to e-Tags pertains to the Sink Balancing Authority and no other Balancing Authorities that may be listed on an e-Tag. Page 30 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
Comments were filed by more than 30 parties. There was no published activity in this proceeding since the last Report.
• Order 809: Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and Public Utilities (RM14-2) On April 16, the FERC issued Order 809,122 which changes the nationwide Timely Nomination Cycle nomination deadline for scheduling natural gas transportation from 11:30 a.m. Central Clock Time (CCT) to 1:00 p.m. CCT and revises the intraday nomination timeline, to include adding an additional intraday scheduling opportunity during the gas operating day (Gas Day). Order 809 also modifies the scheduling practices used by interstate pipelines to schedule natural gas transportation service and provides additional contracting flexibility to firm natural gas transportation customers through the use of multi-party transportation contracts. Order 809 DOES NOT change the start time of the nationwide natural Gas Day (which remains 9:00 a.m. CCT), as had been proposed in the underlying NOPR.123 Order 809 established an implementation date of April 1, 2016.124 On July 23, in response to Order 809, ISO-NE described why changes to the time at which the results of the Day-Ahead Energy Market and RAA process are posted are not necessary in response to the FERC’s rule making. Comments on the ISO’s filing were due on or before August 18, 2015 and no party submitted adverse comments on ISO- NE’s filing (the ISO’s response was filed in EL14-23; see Section I above).
Requests for rehearing and/or clarification of Order 809 were filed by Desert Southwest Pipeline Stakeholders and the American Gas Association. On May 19, the Natural Gas Council asked the FERC to defer NAESB consideration of confirmation process improvements until “after the two industries have had sufficient time to implement and operate reliably under both the new gas scheduling timeline and changes to RTO/ISO dispatch schedules to conform with the newly-approved gas scheduling timeline.” On May 28, 2015 the American Gas Association, the American Public Gas Association, and the Interstate Natural Gas Association of America filed a request for the Commission to clarify the manner in which all pipelines should implement the standards on April 1, 2016, and a request for clarification relating to interpretations of recall rights under existing capacity release contracts in light of the transition from two to three intraday nomination cycles.
On July 31, 2015, the FERC issued an Order on Request for Clarification and Notice of Comment Procedures.125 The FERC explained that the new day-ahead nomination timelines will apply as of March 31, 2016 for those nominations that will become effective April 1, 2016. Furthermore, with respect to capacity releases, the new biddable release schedule will start at 9:00 a.m. CCT on March 31, 2016, for all releases with contracts to be effective on March 31, 2016, April 1, 2016, or thereafter. Non-biddable releases effective on March 31, 2016 will follow the existing posting schedule for the Intraday 1 and Intraday 2 Nomination Cycles, and will follow the new day-ahead nomination schedule for the Timely and Evening Nomination Cycles.
On September 17, 2015, the FERC issued an Order on Rehearing denying a request from a group of utilities and state regulators from Southwest states for rehearing of Order No. 809.126 The Commission recognized the time commitments in implementing the revised nomination timeline, and requested that the natural gas and electric industries, through NAESB, begin considering the development of standards related to faster, computerized scheduling and file such standards or a report on the development of such standards with the Commission by October 17, 2016.
122 Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and Public Utilities, Order No. 809, 150 FERC ¶ 61,049 (Apr. 16, 2015) (“Order 809”). 123 Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and Public Utilities, 146 FERC ¶ 61,201 (Mar. 20, 2014). 124 Order 809 was published in the Fed. Reg. on Apr. 24, 2015 (Vol. 80, No. 79) pp. 23,198-23,227. 125 Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and Public Utilities, 152 FERC ¶ 61,095 (July 31, 2015). 126 Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and Public Utilities, 152 FERC ¶ 61,095 (Apr. 24, 2015), order on reh’g, 152 FERC ¶ 61,212 (Sept. 17, 2015). Page 31 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
• Posting of Offers to Purchase Capacity (Section 5 Proceeding) (RP14-442) Similar to the ISO/RTO 206 Order in EL14-22 et al. (see Section I above), the FERC also instituted a proceeding under Section 5 of the Natural Gas Act to examine whether interstate natural gas pipelines are providing notice of offers to purchase released pipeline capacity in accordance with section 284.8(d) of the Commission’s regulations.127 On or before May 19, natural gas pipelines were required to either revise their respective tariffs to provide for the posting of offers to purchase released capacity, or otherwise demonstrate that they are in full Compliance with FERC regulations.128 The FERC also requested that NAESB develop business practice and communication standards specifying: (1) the information required for requests to acquire capacity; (2) the methods by which such information is to be exchanged; and (3) the location of the information on a pipeline’s website. The Show Cause Order required each pipeline to explain in its Compliance filing how it will fully comply with section 284.8(d) until NAESB develops, and the FERC implements, the requested standards, including how the pipeline will provide shippers the ability to post offers to purchase capacity on the Informational Posting section of its Internet website.
In total, the FERC received, and addressed in one omnibus order, 157 Compliance filings.129 Of the 157 filings, 64 pipelines revised their respective tariffs to provide for the posting of offers to purchase released capacity in a manner that complies with section 284.8(d), and 23 pipelines demonstrated that their tariffs already comply with that section. The FERC found that, and identified in its omnibus order on the Compliance filings the, 69 Compliance filings that did not appear to be in full Compliance with that section, and directed further Compliance filings from those companies as described in the omnibus order.
• Natural Gas-Related Enforcement Actions The FERC continues to closely monitor and enforce Compliance with regulations governing open access transportation on interstate natural gas pipelines.
BP (IN13-15). On August 13, Judge Cintron issued her Initial Decision finding that BP America Inc., BP Corporation North America Inc., BP America Production Company, and BP Energy Company (collectively, “BP”) violated Section 1c.1 of the Commission’s regulations and section 4A of the Natural Gas Act.130 Judge Cintron findings related to civil penalty statutory factors included findings that:
There were at least 48 violations on 49 days; BP’s manipulation resulted in financial losses of $1,375,482 to $1,927,728 on the next-day natural gas markets at Houston Ship Channel (HSC) and Katy during the Investigative Period; the violation was less than five years after a prior FERC adjudication and adjudications of similar misconduct by the CFTC and DOJ (warranting a 2 point increase in BP’s culpability score); BP’s conduct contravened the terms of a permanent injunction with the CFTC (warranting a 2 point increase in BP’s culpability score); BP did not have an effective Compliance program; and the BP Texas team’s gross profits from the manipulation were between $233,330 and $316,170 and net profits between $165,749 and $248,589.
127 Posting of Offers to Purchase Capacity, 146 FERC ¶ 61,203 (Mar. 20, 2014). 128 Id. at P 6. 129 See BR Pipeline Co. et al., 149 FERC ¶ 61,031 (Oct. 16, 2014). 130 BP America Inc. et al., 152 FERC ¶ 63,016 (Aug. 13, 2015) (“BP Initial Decision”). Page 32 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
Judge Cintron certified the BP Initial Decision and the record to the Commission also on August 13. Since the last Report, BP filed its Brief on Exceptions. This matter is now pending before the FERC.
Staff Notice of Alleged Violation: Total Gas & Power, North America, Inc. On September 21, 2015, the FERC issued a notice that Staff has preliminarily determined that Total Gas & Power, North America, Inc. (“TGPNA”) and its West Desk traders and supervisors Therese Nguyen and Aaron Hall, violated section 4A of the Natural Gas Act and the Commission’s Anti-Manipulation Rule, by devising and executing a scheme to manipulate the price of natural gas in the southwest United States between June 2009 and June 2012. Specifically, Staff alleges that the scheme involved making largely uneconomic trades for physical natural gas during bidweek designed to move indexed market prices in a way that benefited the company’s related positions. Staff alleges that the West Desk implemented the bidweek scheme on at least 38 occasions during the period of interest and that Therese Nguyen and Aaron Hall each implemented the scheme and supervised and directed other traders in implementing the scheme.
• New England Pipeline Proceedings The following New England pipeline projects are currently before the FERC: • Algonquin Incremental Market Project (AIM Project) (CP14-96) Algonquin Gas Transmission filed for Section 7(b) and 7(c) certificate Feb. 28, 2014 342,000 dekatherms/day of firm capacity to NY, CT, RI and MA. 37.6 miles of take-up, loop and lateral pipeline facilities in NY, CT, and MA and system modifications in NY, CT and RI. The system upgrades would also require the removal of some facilities. 10 firm shippers: Yankee Gas, NSTAR, Connecticut Natural Gas, Southern Connecticut, Narragansett Electric, Colonial Gas, Boston Gas, Bay State, Norwich Public Utilities, and Middleborough Gas and Electric (eight LDCs and two municipal utilities). Final EIS issued on Jan. 23, 2015. Certificate of public convenience and necessity granted Mar. 3, 2015 (must be constructed and in service within two years).131 Construction began in May 2015. In-service: Nov. 2016 (anticipated). • Connecticut Expansion Project (CP14-529) Tennessee Gas Pipeline filed for Section 7(c) certificate July 31, 2014. 72,100 dekatherms/day of firm capacity. 13.26 miles of three looping segments and facility upgrades/modifications in NY, MA and CT. Three firm shippers: Connecticut Natural Gas, Southern Connecticut Gas, and Yankee Gas. Notice of Schedule issued Sept. 1 with FERC EA to be issued Oct. 23 and 90-day Federal Authorization Decision Deadline set at Jan. 21, 2016. Construction expected to begin Winter/Spring 2016. In-service: Nov 2016 (anticipated). • Constitution Pipeline (CP13-499) and Wright Interconnection Project (CP13-502) Constitution Pipeline Company and Iroquois Gas Transmission (Wright Interconnection) concurrently filed for Section 7(c) certificates on June 13, 2013. 650,000 dekatherms/day of firm capacity from Susquehanna County, PA through NY to Iroquois/Tennessee interconnection (Wright Interconnection).
131 Order Issuing Certificate and Approving Abandonment, Algonquin Gas Transmission LLC, 150 FERC ¶ 61,163 (Mar. 3, 2015), reh’g requested. Page 33 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
New 122-mile interstate pipeline. Two firm shippers: Cabot Oil & Gas and Southwestern Energy Services. Final EIS completed on Oct 24, 2014. Certificates granted Dec 2, 2014 (must be constructed and in service within two years); Construction expected to begin Oct. 2015 (after final Federal Authorizations). • Salem Lateral Project (CP14-522) Algonquin Gas Transmission filed application Jul 10, 2013. 115,000 dekatherms/day of firm capacity. 1.2 miles of pipeline to 630 MW Salem Harbor Station and other Salem, MA facilities. Footprint Power sole firm customer. FERC environmental assessment issued Dec 2, 2014. Certificate granted May 14, 2015 (must be constructed and in service within two years).132 Construction began in May 2015. In-Service: fourth quarter 2015 (anticipated).
XIV. State Proceedings & Federal Legislative Proceedings
No Activity to Report.
XV. Federal Courts
The following are matters of interest, including petitions for review of FERC decisions in NEPOOL-related proceedings, that are currently pending before the federal courts (unless otherwise noted, the cases are before the U.S. Court of Appeals for the District of Columbia Circuit). An “**” following the Case No. indicates that NEPOOL has intervened or is a litigant in the appeal. The remaining matters are appeals as to which NEPOOL has no organizational interest but that may be of interest to Participants. For further information on any of these proceedings, please contact Pat Gerity (860-275-0533; [email protected]).
• Base ROE Complaints (2012 and 2014) (15-1212) Underlying FERC Proceedings: EL13-33; EL14-86133 Appellants: New England Transmission Owners On July 13, 2015, the TOs filed a petition for review of the FERC’s orders in the 2012 and 2014 ROE complaint proceedings. On July 16, the Court issued a scheduling order directing, among other things, a statement of issues and procedural motions to be filed by August 17 and dispositive motions to be filed by August 31; briefing was deferred until further order of the court. However, on August 14, 2015, NETOs filed an unopposed motion to hold this case in abeyance pending final FERC action on the 2012 and 2014 ROE Complaints (see Section I above). On August 20, 2015, the Court granted NETOs’ motion to hold case in abeyance.
• Order 1000 Compliance Filings (15-1139, 15-1141**) (consolidated) Underlying FERC Proceedings: ER13-193; ER13-196134 Appellants: New England Transmission Owners (NETOs); NESCOE/CT DEEP/CT PURA, et al.
132 Order Issuing Certificate, Algonquin Gas Transmission LLC, 151 FERC ¶ 61,118 (May 14, 2015). 133 147 FERC ¶ 61,235 (June 19, 2014); 149 FERC ¶ 61,156 (Nov. 24, 2014); 151 FERC ¶ 61,125 (May 14, 2015). 134 150 FERC ¶ 61,209 (Mar. 19, 2015); 143 FERC ¶ 61,150 (May 17, 2013). Page 34 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
On May 15, 2015, NETOs135 and NESCOE, et al., filed a petition for review of the FERC’s orders in the Order 1000 Compliance Filing proceeding. On June 15, the parties filed a joint statement of issues and unopposed motion regarding briefing format. On June 18, a Joint Statement of issues and docketing statement was filed. On July 2, the Court granted all motions to intervene. On August 17, Petitioners filed an unopposed proposed briefing format and schedule.
• Base ROE Complaint (2011) (15-1118, 15-1119, 15-1121**) (consolidated) Underlying FERC Proceedings: EL11-66136 Appellants: NETOs
On April 30, 2015, NETOs filed a petition for review of the FERC’s orders in the 2011 Base ROE Complaint Proceeding. Motions for leave to intervene have been filed by NEPOOL,EMCOS,137 NJ Division of Rate Counsel, NHEC, MMWEC, CT PURA, CT OCC, CT AG, NJ BPU, Delaware PSC, and Coalition of MISO Transmission Customers. The Court granted all motions to intervene on June 23. On August 10, Petitioners filed an unopposed proposed briefing format and schedule.
• FCM Administrative Pricing Rules Complaint (15-1071**) Underlying FERC Proceedings: EL14-7138 Appellants: NEPGA On March 31, 2015, NEPGA filed a petition for review of the FERC’s orders on NEPGA’s FCM Administrative Pricing Rules Complaint. A Docketing Statement Form, Statement of Issues to be Raised, and Petitioners’ Appearances were filed on April 23, 2015. Also on April 23, 2015, NEPGA requested that the case be held in abeyance pending the FERC’s issuance of an order on rehearing of its initial order in Exelon Corporation v. ISO New England Inc. (EL15-23). Motions for leave to intervene have been filed by NEPOOL, CT PURA, CT OCC, NESCOE, NECPUC, NHEC, and PSEG. On May 22, the Court granted all motions to intervene and NEPGA’s motion to hold the case in abeyance pending a decision in EL15-23. Motions to govern future proceedings are due 30 days from the completion of the FERC proceedings in EL15-23. NEPGA was directed to, and did, file an abeyance status report on or before August 20, 2015. In its August 20 report, NEPGA indicated that the FERC had not taken final action in EL15-23 and requested the Court continue to hold the case in abeyance.
• Demand Curve Changes (15-1070**) Underlying FERC Proceedings: ER14-1639139 Appellants: NextEra, NRG and PSEG On March 30, 2015, NextEra, NRG and PSEG filed a petition for review of the FERC’s orders in the Demand Curve Changes proceedings. Motions for leave to intervene have been filed by NEPOOL, the ISO, CT PURA, NHEC, CPV, Entergy, and NESCOE. A Docketing Statement Form, Statement of Issues to be Raised, and Appearances were filed by Petitioners on April 30, 2015. The Petitioners’ Non-Binding Statement of Issues laid out various challenges to the renewables exemption that was approved as part of the FERC’s Demand Curve Orders. On May 28, the Court granted all filed motions to intervene and ordered intervenors to show by June 29 cause why they should not be limited to one joint brief in support of the FERC. On June 26, CT PURA filed a statement requesting permission from the Court to file its own brief in support of the FERC. Also on June 26, NESCOE, CPV and NHEC filed a statement regarding briefing format. On August 5, the Court issued a briefing schedule, which call for brief for Petitioners by October 5; brief for Intervenor Supporting Petitioners by October
135 “NETOs” are Emera Maine; Central Maine Power Co., National Grid; New Hampshire Transmission (“NHT”), Eversource (on behalf of its electric utility company affiliates CL&P, WMECO, PSNH, and NSTAR), UI, and Vermont Transco. 136 150 FERC ¶ 61,165 (Mar. 3, 2015); 149 FERC ¶ 61,032 (Oct. 16, 2014); 147 FERC ¶ 61,234 (June 19, 2014). 137 “EMCOS” are Taunton, Reading, Hingham, ad Braintree. 138 150 FERC ¶ 61,064 (Jan. 30, 2015); 146 FERC ¶ 61,039 (Jan. 24, 2014). 139 150 FERC ¶ 61,065 (Jan. 30, 2015); delegated letter order (Nov. 13, 2014); 147 FERC ¶ 61,173 (May 30, 2014). Page 35 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
20; brief for Respondent by December 4; brief of Intervenor CT PURA Supporting Respondent by December 21; and brief of other Intervenors Supporting Respondent by December 21, 2015.
• FCA8 Results (14-1244, 14-1246 (consolidated)) Underlying FERC Proceedings: ER14-1409140 Appellants: Public Citizen and CT AG On November 14, 2014, Public Citizen and the CT AG filed petitions for review of the FERC’s action on the FCA8 Results Filing, which became effective by operation of law on September 16, 2014. These proceedings have been consolidated. A Docketing Statement Form and Statement of Issues to be Raised were filed by Petitioners by December 22, 2014. On January 2, 2015, the FERC filed a motion to dismiss the petitions for lack of jurisdiction. The FERC argued that the Court lacks jurisdiction because Petitioners did not challenge a FERC “order” within the meaning of section 313 of the FPA, or “agency action” reviewable under the Administrative Procedures Act. On January 15, EPSA and NEPGA jointly filed a motion supporting the FERC’s motion to dismiss. On January 26, Connecticut141 and Public Citizen opposed the FERC’s motion to dismiss. On February 5, the FERC replied to the Public Citizen and CT AG responses. On April 7, the Court ordered that the motion to dismiss be referred to the merits panel and parties were directed to address in their briefs the issues presented in the motion to dismiss rather than incorporate those arguments by reference. On April 9, the FERC filed an unopposed motion for a schedule setting a minimum 60-day briefing interval for the FERC. On April 10, the Court ordered that parties submit proposed formats for the briefing of the consolidated cases by May 11. The parties filed a joint proposed briefing schedule on May 11. On July 1, the Court issued a briefing schedule -- brief for State Petitioners due 9/4/2015; brief for Public Citizen due 9/4/2015; brief for Respondent due 11/3/2015; brief for FERC/Intervenors due 11/18/2015; reply briefs for Petitioners due 12/2/2015; final briefs due 12/23/2015. In accordance with that schedule, briefs of State Petitioners and Public Citizen were filed on September 4.
• 2013/14 Winter Reliability Program (14-1104, 14-1105, 14-1103 (consolidated)) Underlying FERC Proceedings: ER13-1851142 and ER13-2266143 Appellants: TransCanada and RESA On June 6, 2014, TransCanada and the Retail Energy Supply Association filed petitions for review of the FERC’s orders on the 2013/14 Winter Reliability Program (14-1104 and 14-1105, respectively). Also on June 6, 2014, TransCanada filed a petition for review of FERC’s orders on the 2013/14 Winter Reliability Program Bid Results Filings (ER14-1103). On July 3, 2014, these proceedings were consolidated. On July 7, 2014, the FERC requested a minimum of 60 days after Petitioners’ opening briefs to file its brief. On July 23, leave to intervene was granted to ISO-NE, NEPGA, PSEG and Essential Power. On September 29, 2014, TransCanada, RESA, FERC, ISO-NE, Essential Power MA, PSEG and NEPGA filed a proposed joint, unopposed briefing format and schedule. A Joint Brief for Petitioners was filed on November 24 (as corrected on December 1). At the FERC’s request, the Court ordered that a revised briefing schedule be applied in this case (effectively extending the overall briefing schedule by one month. Briefs for Respondent and Respondent-Intervenors were filed February 13 and March 2, respectively. Petitioners’ Joint Reply Brief was filed on March 25; the Deferred Appendix, April 1, 2015. Final Briefs were filed on April 15, 2015. Oral argument was held on September 15, 2015 before Judges Tatel, Pillard and Edwards. This matter is pending before the Court.
140 Notice of Filing Taking Effect by Operation of Law, ISO New England Inc., Docket No. ER14-1409 (Sep. 16, 2014); Notice of Dismissal of Pleadings, ISO New England Inc., Docket No. ER14-1409 (Oct. 24, 2014). 141 For purposes of this proceeding, “Connecticut” means the CT AG, CT PURA and CT OCC. 142 144 FERC ¶ 61,204 (Sep. 16, 2013); 147 FERC ¶ 61,026 (Apr. 8, 2014). 143 145 FERC ¶ 61,023 (Oct. 7, 2013); 147 FERC ¶ 61,027 (Apr. 8, 2014). Page 36 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
• New England’s Order 745 Compliance Filing (12-1306) Underlying FERC Proceedings: ER11-4336144 Appellants: EPSA and NEPGA On July 16, 2012, EPSA and NEPGA filed a petition for review of FERC’s orders on New England’s Order 745 (Demand Response Compensation) filings. On August 16, 2012, EPSA and NEPGA filed a statement of issues as well as an unopposed motion to hold case in abeyance pending the final resolution of Case Nos. 11-1486, et al. (EPSA et al. v. FERC)(see Orders 745 and 745-A below). On August 23, 2012, the Court granted the motion to hold the case in abeyance. Motions to govern future proceedings will be due 30 days following the issuance of the mandate in the Order 745 appeal.
• Orders 745 and 745-A (FERC v. EPSA, Supreme Court, 14-840 and 14-841) Underlying FERC Proceedings: RM10-17-000145 Appellants: FERC and EnerNOC On January 15, the Solicitor General of the United States, on behalf of the FERC, filed with the Supreme Court a petition for a writ of certiorari seeking review of the District Court’s May 23 Decision.146 Respondents brief in opposition to that writ, pursuant to an order of the Court extending the time for responses, was filed on March 19. Petitioner’s reply was filed on April 7. The Supreme Court granted certiorari on May 4, 2015. On May 27, the Supreme Court granted extensions to file petitioners’ briefs to July 9, 2015 and respondents’ brief to August 31, 2015. On July 9, briefs were submitted by EnerNOC, FERC, CA PUC, Joint States, and PJM. A number of amicus curiae briefs were submitted on July 16. Since the last Report, amicus curiae briefs were submitted by Midwest Load-Serving Entities and EPSA on August 31; by CES and Dr. Silkman on September 1; by the NC PUC on September 4; and on September 8 by NEI/America’s Natural Gas Alliance and Robert L. Borlick, et al. Oral argument is scheduled for October 14, 2015.
As previously reported, the DC Circuit vacated Order 745147 in its entirety as impermissibly encroaching on “states’ exclusive jurisdiction to regulate the retail market” in a 2-1 decision (“Decision”) issued on May 23, 2014. The DC Circuit vacated Order 745 on two separate and independent grounds. First, it held that the FERC does not have jurisdiction to regulate demand response. The Court reasoned that: (i) the states retain exclusive authority to regulate the retail market; (ii) absent an express statutory grant of authority, the FERC cannot regulate areas left to the states; (iii) the FPA provides the FERC with authority over wholesale sales of electricity, but demand response is not such a sale; (iv) the authority of the FERC to regulate wholesale power rates under the FPA cannot be read so broadly as to allow direct regulation of demand response; and (v) demand response, while not necessarily a retail sale, is part of the retail market, involving retail customers, their decision whether to purchase at retail, and the levels of retail electricity consumption. Therefore, the Court concluded, the FERC has no authority to directly regulate demand response. “FERC’s authority over demand response resources is limited: its role is to assist and advise state and regional programs.”
As an alternative and secondary basis for its decision against Order 745, the Court concluded that the FERC order was “arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.” The Court found that the FERC failed to reasonably consider and address arguments that Order 745 will result in over-compensation of demand response resources, resulting in unjust and discriminatory rates. The Court further found that the FERC failed to demonstrate how its proposed pricing construct would result in just compensation. The Decision and preliminary implications of the Decision were summarized in more detail in the memo included with the supplemental materials circulated and posted for the June 6 meeting.
144 138 FERC ¶ 61,042 (Jan. 19, 2012); 139 FERC ¶ 61,116 (May 17, 2012). 145 134 FERC ¶ 61,187 (Mar. 15, 2011); 137 FERC ¶ 61,215 (Dec. 15, 2011). 146 EPSA v. FERC, 753 F.3d 216 (May 23, 2014). 147 Order 745 required RTOs and ISOs to include provisions in their tariffs that assured demand response would be paid at LMP for interrupting their loads when such interruption was cost effective. Page 37 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
On July 7, the FERC petitioned the Court for rehearing en banc of the May 23 Decision. On July 18, the Court, on its own motion, directed EPSA, APPA, NRECA, Old Dominion and EEI (“Petitioners”) to file a joint response to the FERC petition for rehearing. That response was filed on August 4, 2014. The petition for rehearing en banc was denied on September 17, 2014. As previously reported, the DC Circuit directed its clerk to withhold the Court’s mandate pending the Supreme Court’s final disposition.
• CPV Maryland, LLC v. PPL EnergyPlus et al. (Supreme Court, 14-623) A petition for a writ of certiorari in this case was filed on November 26, 2014 and placed on the Supreme Court’s docket on November 28, 2014 as No. 14-623. The parties consented to the filing of amicus curiae briefs, and such briefs were filed by NARUC, the State of Connecticut, and APPA. Respondents (PPL EnergyPlus, LLC, et al.) filed a response on February 11. Petitioner CPV Maryland, LLC replied on February 24. On March 23, the Court invited the Solicitor General to file a brief in the case expressing the views of the United States. Since the last Report, the Solicitor General filed, on September 16, an amicus brief of the United States. On September 29, petitioner CPV Maryland filed a supplemental brief. The case was distributed on September 30 for the Court’s October 16, 2015 Conference.
As previously reported, on June 2, 2014, the 4th Circuit Court of Appeals affirmed the September 30, 2013 decision of the United States District Court for the District of Maryland148 which found that a Maryland Public Service Commission (“MD PSC”) order directing three Maryland distribution utilities to enter into a ‘contract for differences’ for capacity and energy in the PJM control area (the “CfD”) with a gas-fired merchant generator selected by the MD PSC (the “MD PSC Order”) violated the Supremacy Clause of the United States Constitution and cannot be enforced.149 In affirming the District Court decision, the 4th Circuit found the MD PSC Order both field150 and conflict pre-empted.151
With respect to field pre-emption, the 4th Circuit stated that a “wealth of case law confirms FERC’s exclusive power to regulate wholesale sales of energy in interstate commerce, including the justness and reasonableness of the rates charged.”152 It found the federal scheme (i.e. the PJM Market) “carefully calibrated to protect a host of competing interests” (representing “a comprehensive program of regulation that is quite sensitive to external tampering”),153 and leaving “no room either for direct state regulation of the prices of interstate wholesales of [energy], or for state regulations which would indirectly achieve the same result.” Accordingly, the 4th Circuit concluded that the MD PSC Order “field preempted because it functionally sets the rate that CPV receives for its sales in the PJM auction.”154 The MD PSC Order “compromises the integrity of the federal
148 PPL EnergyPlus, LLC v. Nazarian, 974 F.Supp. 2d 790 (D. Md. Sep. 30, 2013); 2013 U.S. Dist. LEXIS 140210, 2013 WL 5432346 (“District Court Decision”). The District Court Decision was summarized in past Litigation Reports. 149 PPL EnergyPlus, LLC v. Nazarian, 753 F.3d 467; 2014 U.S. App. LEXIS 10155. 150 “Field preemption” is a doctrine based on the Supremacy Clause of the U.S. Constitution that holds that any federal law, including regulations of a federal agency, takes precedence over any conflicting state law. Preemption can be implied when federal law/regulation “occupies the field” in which the state is attempting to act/regulate. Field preemption occurs when there is "no room" left for state regulation. Accordingly, a state may not pass a law or take any action in a field, like the regulation of wholesale power sales, pervasively regulated by federal law/regulation. 151 “Conflict preemption” occurs where there is a conflict between a state law and a federal law. (“[E]ven if Congress has not occupied the field, state law is naturally preempted to the extent of any conflict with a federal statute.”). Such a conflict occurs when “the challenged state law stands as an obstacle to the accomplishment and execution of the full purposes and objectives of Congress. The court must look to 'the entire scheme of the statute' and determine '[i]f the purpose of the [federal] act cannot otherwise be accomplished--if its operation with its chosen field [would] be frustrated and its provisions be refused their natural effect. Where a state law conflicts with a federal law, the Court does not balance the competing federal and state interests. Any state law, however clearly within a State’s acknowledged power, which interferes with or is contrary to federal law, must yield.” 152 Slip op. at p. 14. 153 Id. at p. 10. 154 Id. at p. 16. Page 38 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7 scheme and intrudes on FERC’s jurisdiction” because the MD PSC Order “effectively supplants the rate generated by the auction with an alternative rate preferred by the state.” The 4th Circuit rejected arguments that the CfD payments “represented a separate supply-side subsidy implemented entirely outside the federal market.”155 And, even if the presumption against preemption were to apply, the Court found that that it was “overcome by the text and structure of the FPA, which unambiguously apportions control over wholesale rates to FERC.”156
With respect to conflict pre-emption, the 4th Circuit found that the MD PSC Order “presents a direct and transparent impediment to the functioning of the PJM markets, and is therefore preempted”.157 Preemption was appropriate because of the “extensive and disruptive” impact of the MD PSC Order on matters within federal control (the PJM markets). It found that the MD PSC Order had “the potential to seriously distort the PJM’s auction’s price signals, thus ‘interfer[ing] with the method by which the federal statute (i.e. the PJM Markets) was designed to reach its goals.”158 “Maryland’s initiative disrupts [the PJM scheme] by substituting the state’s preferred incentive structure for that approved by FERC.”159 “Maryland has sought to achieve through the backdoor of its own regulatory process what it could not achieve through the front door of FERC proceedings. Circumventing and displacing federal rules in this fashion is not permissible.”160
Petitions for rehearing en banc were filed by MD PSC and CPV Maryland on June 16, 2014. On June 17, 2014, the 4th Circuit stayed the mandate pending the en banc ruling on the Petitions. On June 30, 2014, the 4th Circuit denied the petitions for rehearing en banc.
• CPV Power Development, Inc., et al. v. PPL EnergyPlus, LLC, et al. (Supreme Court, 14-634, 14-694) Petitions for a writ of certiorari in this case were filed on November 26, 2014 and December 10, 2014 and placed on the Supreme Court’s docket as Case Nos. 14-634 and 14-694, respectively. The parties consented to the filing of amicus curiae briefs, and such briefs were filed by NARUC, the State of Connecticut, APPA, AWEA, and the NY PSC. Since the last Report, Respondents (PPL EnergyPlus, LLC, et al.) filed a brief opposing the writ of certiorari on February 11. Petitioners (CPV Power Development, Inc., et al.) replied to that brief on February 20. On March 23, the Court invited the Solicitor General to file a brief in the case expressing the views of the United States. Since the last Report, the Solicitor General filed, on September 16, an amicus brief of the United States. On September 29, petitioner CPV Maryland filed a supplemental brief. The case was distributed on September 30 for the Court’s October 16, 2015 Conference.
As previously reported, on September 11, 2014, the 3rd Circuit Court of Appeals affirmed161 the analogous October 11, 2013 decision of the United States District Court for the District of New Jersey declaring unconstitutional (and therefore null and void) New Jersey’s Long Term Capacity Agreement Pilot Program Act (“LCAPP”).162 In affirming the New Jersey District Court’s decision, the 3rd Circuit concluded:
155 Id. at pp. 18-19. 156 Id. at p. 20. The Court noted the limited scope of its holding, which “is addressed to the specific program at issue” and did not “express an opinion on other state efforts to encourage new generation.” Id. at p. 21. 157 Id. at p. 27. 158 Id. at p. 23. 159 Id. at p. 24. (“Two features of the Order render its likely effect on federal markets particularly problematic. First, as noted, the CfDs are structured to actually set the price received at wholesale. They therefore directly conflict with the auction rates approved by FERC. Second, the duration of the subsidy -- twenty years -- is substantial.”) 160 Id. at p. 25. 161 PPL EnergyPlus, LLC v. Hanna, 977 F.Supp.2d 372 (D. NJ. Oct. 11, 2013); 2013 U.S. Dist. LEXIS 147273, (“NJ Order”). 162 PPL EnergyPlus, LLC v. Hanna, 766 F.3d 241; 2014 U.S. App. LEXIS 17557 (Sep. 11, 2014). Page 39 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
LCAPP compels participants in a federally-regulated marketplace to transact capacity at prices other than the price fixed by the marketplace. By legislating capacity prices, New Jersey has intruded into an area reserved exclusively for the federal government. Accordingly, federal statutory and regulatory law preempts and, thereby, invalidates LCAPP and the Standard Offer Capacity Agreements.163
No petition for rehearing or rehearing en banc was filed on or before September 25, 2014. Accordingly, the mandate was issued on October 3, 2014. As noted above, petitions for certiorari to the U.S. Supreme Court were filed and are pending before the Supreme Court.
• Entergy Nuclear Fitzpatrick, LLC et al v. Zibelman et al (NY PSC Commissioners) (N.D.N.Y. 5:15- cv-00230-DNH-TWD) Entergy164 filed, on February 27, in the United States District Court for the Northern District of New York, a Complaint that seeks a declaratory judgment that the NYPSC Commissioners’ order (“Order”) approving an agreement to keep NRG’s 435 MW Dunkirk facility in the NYISO market, “repowered” as a natural gas-fired (rather than coal-fired) plant (the “Term Sheet”)165 is preempted by the FPA and invalid under the dormant Commerce Clause of the U.S. Constitution. Entergy also seeks a permanent injunction requiring the NYPSC Commissioners to withdraw its Order and/or preventing the NYPSC Commissioners from continuing to treat the Order as valid and binding. This case is noteworthy given the relationship of the issues raised to the Maryland and New Jersey CfD cases summarized above.
163 Id. slip op. at 31. 164 Plaintiffs are Entergy Nuclear FitzPatrick, LLC (“FitzPatrick”); Entergy Nuclear Power Marketing, LLC (“ENPM”); and Entergy Nuclear Operations, Inc. (“ENOI”). 165 The Term Sheet provides that, in exchange for Dunkirk’s commitment to participate in the NYISO energy and capacity markets through 2025, Dunkirk will receive out-of-market payments of $20.4 million per year from National Grid and a $15 million one-time subsidy from a New York State agency. Entergy asserts that the contract structure will lead Dunkirk to bid below its actual costs in the capacity auction, causing the auction market to “clear” at a lower price than otherwise would have resulted, and resulting in all generators receiving lower capacity revenues than they otherwise would have received. Page 40 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
INDEX Status Report of Current Regulatory and Legal Proceedings as of October 1, 2015
I. Complaints/Section 206 Proceedings 206 Investigation: Consistency of ISO-NE (DA) Scheduling Practices with Natural Gas Scheduling Practices to be Adopted in Docket RM14-2 ...... (EL14-23) ...... 5 206 Investigation: FCM Performance Incentives (Compliance Proceeding)...... (EL14-52; ER14-2419)...... 4 206 Proceeding: 2014/15 RNS Recovery of SeaLink Development Costs ...... (EL15-85) ...... 1 206 Proceeding: Importers’ FCA Offers Review/Mitigation ...... (EL14-99; ER15-117)...... 3 Base ROE Complaints (2012 and 2014) (Consolidated) ...... (EL13-33 and EL14-86)...... 3 NEPGA DR Capacity Complaint ...... (EL15-21) ...... 2 NEPGA Peak Energy Rent (PER) Complaint ...... (EL15-25) ...... 1 New Entry Pricing Rule Complaint...... (EL15-23) ...... 2
II. Rate, ICR, FCA, Cost Recovery Filings Base ROE Complaints (2012 and 2014) (Consolidated) ...... (EL13-33 and EL14-86)...... 3 FCA1 Results Remand Proceeding...... (ER08-633) ...... 7 FCA9 Results Filing ...... (ER15-1137) ...... 6 FCA9 Results Correction: Holliston Resource SEMA Load Zone Location...... (ER15-2626)...... 6
III. Market Rule and Information Policy Changes, Interpretations and Waiver Requests 206 Investigation: Consistency of ISO-NE (DA) Scheduling Practices with Natural Gas Scheduling Practices to be Adopted in Docket RM14-2 ...... (EL14-23) ...... 5 206 Investigation: FCM Performance Incentives (Compliance Proceeding)...... (EL14-52; ER14-2419)...... 4 206 Proceeding: Importers’ FCA Offers Review/Mitigation ...... (EL14-99; ER15-117)...... 3 CSO Terminations: Enerwise Global Technologies...... (ER15-2232) ...... 9 CSO Termination: Hampshire Council of Governments...... (ER15-2229) ...... 9 CTS Conforming Changes...... (ER15-2641) ...... 13 Demand Curve Changes ...... (ER14-1639) ...... 8 DNE Dispatch Changes ...... (ER15-1509) ...... 10 Fast Start Pricing Changes...... (ER15-2716) ...... 8 FCM ARA Sloped Demand Curve Changes ...... (ER15-2404) ...... 8 FCM PI Jump Ball Compliance Filing I ...... (ER14-2419-001)...... 4 FCM PI Jump Ball Compliance Filing II ...... (ER14-2419-002)...... 4 IMM FCM Mitigation Package ...... (ER15-1650) ...... 10 ISO Response to Show Cause Order ...... (ER15-117) ...... 3 Jump Ball Filing: FCM Performance Incentives ...... (ER14-1050) ...... 12 Jump Ball Filing: Winter Reliability Program...... (ER15-2208) ...... 9 Monthly Qualified Capacity Changes...... (ER15-2650) ...... 8 NEPGA DR Capacity Complaint ...... (EL15-21) ...... 2 NEPGA Peak Energy Rent (PER) Complaint ...... (EL15-25) ...... 1 New Entry Pricing Rule Complaint...... (EL15-23) ...... 2 Reactive Capability Auditing Revisions...... (ER15-2628) ...... 8
IV. OATT Amendments/Coordination Agreements CTS Conforming Changes...... (ER15-2641) ...... 13 Order 676-H Compliance: TOs...... (ER15-517) ...... 13 Order 676-H Compliance: TOs Additional Filing...... (ER15-517) ...... 13 Order 676-H Compliance: Revisions to Schedule 24...... (ER15-519) ...... 13 Order 676-H Compliance: ISO Additional Revisions to Schedule 24 ...... (ER15-519)...... 13 Order 1000 Compliance: Initial Regional Compliance Filing...... (ER13-193; ER13-196)...... 14 Order 1000 Compliance: 2nd (Nov 15 Order) Regional Compliance Filing ...... (ER13-193; ER13-196)...... 14 Order 1000 Compliance: 3rd Regional Compliance Filing...... (ER13-193; ER13-196)...... 14 Order 1000 Interregional Requirements: Initial Compliance Filing...... (ER13-1960; ER13-1957)....14 2nd Order 1000 Interregional Compliance Changes...... (ER13-1960; ER13-1957)....14 Retirement of RTO Mapping Document (Tariff Attachment C) ...... (ER15-2717) ...... 12 Page I-1 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
V. Financial Assurance/Billing Policy Amendments No Activity to Report
VI. Schedule 20/21/22/23 Updates Opinion 531-A Compliance Filing: CTMEEC ...... (ER15-584) ...... 16 Schedule 20A-EM: Talen Energy Marketing Updates ...... (ER15-2578) ...... 16 Schedule 21-NEP: National Grid/Old Wardour SGIA ...... (ER15-2599)...... 16 Schedule 21-NEP: National Grid/Vuelta Solar SGIA ...... (ER15-2598)...... 16 Schedule 22: Braintree LGIA ...... (ER15-2734) ...... 15 Schedule 22: Granite Ridge LGIA...... (ER15-2747) ...... 15
VII. NEPOOL Agreement/Participants Agreement Amendments AR Provider Amendments...... (ER15-2523) ...... 16
VIII. Regional Reports Capital Projects Report - 2015 Q2 ...... (ER15-2443) ...... 17 IMM Quarterly Markets Reports - 2015 Q2...... (ZZ15-4) ...... 18 Opinion 531-A Refund Report: FG&E ...... (EL11-66) ...... 17 Reserve Market Compliance (19th) Semi-Annual Report...... (ER06-613) ...... 17
IX. Membership Filings October 2015 Membership Filing ...... (ER16-1) ...... 18 September 2015 Membership Filing...... (ER15-2584) ...... 18
X. Misc. - ERO Rules, Filings; Reliability Standards Compliance Filing: BES Exclusions for Local Network Configurations ...... (RM12-6)...... 23 E. Morris v. NERC/SERC ...... (EL15-93) ...... 23 FFT Report: August 2015...... (NP15-36) ...... 18 NOPR: BAL-002-1a Interpretation Remand ...... (RM13-6)...... 22 NOPR: New Reliability Standard: PRC-026-1...... (RM15-8)...... 21 NOPR: New Reliability Standard: TPL-007-1 ...... (RM15-11)...... 20 NOPR: Revised Rel. Standards: CIP-003-6, CIP-004-6, CIP-006-6, CIP-007-6, CIP-009-6, CIP-010-2, CIP-011-2 ...... (RM15-14)...... 19 NOPR: Revised Rel. Standard: MOD-001-2...... (RM14-7)...... 22 NOPR: Revised TOP and IRO Reliability Standards...... (RM15-16)...... 19 Order 813: Revised Rel. Standard: PRC-005-4...... (RM15-9)...... 21 Order 814: Revised Rel. Standard: PRC-002-2...... (RM15-4)...... 21 Removal of LSE Category from NERC Compliance Registry...... (RR15-4)...... 23 Revised Regional Delegation Agreements ...... (RR15-12)...... 23 Revised Reliability Standards: IRO-006-EAST-2; IRO-009-2 ...... (RD15-7)...... 18 Revised Reliability Standards: PRC-004-5; PRC-010-2 ...... (RD15-5)...... 19 Revised Reliability Standards: Transition to “Remedial Action Scheme” ...... (RM15-13)...... 20
Page I-2 41536280.155 October 1, 2015 Report NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7
XI. Misc. Regional Interest 203 Application: Iberdrola/UI ...... (EC15-103) ...... 23 Construction Agreement: MEPCO/Number Nine Wind Farm...... (ER15-2451)...... 25 CPV Towantic LGIA Cancellation...... (ER15-2605) ...... 24 Emera MPD OATT Changes...... (ER15-1429) ...... 25 E&P Agreement Termination: CMP/Atlantic Wind...... (ER15-2603) ...... 24 EPC Agreement: Blue Sky West & Emera Maine...... (ER15-1459)...... 25 FERC Enforcement Action: Formal Investigation (MISO Zone 4 Planning Resource Auction Offers) ...... (IN15-10)...... 26 FERC Enforcement Action: Staff NoV (Coaltrain Energy/Co-Owners/Traders/Analyst...... 26 FERC Enforcement Action: Staff NoV (Etracom/M. Rosenberg)...... 26 FirstEnergy PJM DR Complaint...... (EL14-55) ...... 24 MISO Methodology to Involuntarily Allocate Costs to Entities Outside Its Control Area ..(ER11-1844) ...... 26
XII. Misc: Administrative & Rulemaking Proceedings AWEA Petition for LGIA/LGIP Rulemaking ...... (RM15-21)...... 28 NOPR: Connected Entity Data Collection...... (RM15-23)...... 27 NOPR: Price Formation Fixes - Settlement Intervals/Shortage Pricing ...... (RM15-24)...... 27 NOPR: MBR Authorization Refinements ...... (RM14-14)...... 28 NOPR: Price Formation Fixes - Settlement Intervals/Shortage Pricing ...... (RM15-24)...... 27 NOPR: Third-Party Provision of Primary Frequency Response Service...... (RM15-2)...... 28 Order 771: Availability of E-Tag Information to FERC Staff ...... (RM11-12)...... 30 Order 807: Open Access and Priority Rights on ICIF...... (RM14-11)...... 29 Order 812: Revisions to Public Utility Filing Requirements ...... (RM15-3)...... 28 WIRES Request for Policy Statement on ROE for Electric Transmission...... (RM13-18)...... 29
XIII. Natural Gas Proceedings 206 Investigation: Consistency of ISO-NE (DA) Scheduling Practices with Natural Gas Scheduling Practices to be Adopted in Docket RM14-2 ...... (EL14-23) ...... 5 Enforcement Actions: BP Initial Decision...... (IN15-13)...... 32 Enforcement Actions: Staff NoV: Total Gas & Power, North America, Inc...... 32 Inquiry Into Natural Gas Trading, and Proposal to Establish an Electronic Information and Trading Platform...... (AD14-19) ...... 30 New England Pipeline Proceedings...... 33 Order 809: Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and Public Utilities...... (RM14-2)...... 31 Posting of Offers to Purchase Capacity (Section 5 Proceeding)...... (RP14-442) ...... 32
XIV. State Proceedings & Federal Legislative Proceedings No Activity to Report
XV. Federal Courts 2013/14 Winter Reliability Program and Bid Results ...... 14-1104 (DC Cir.)...... 36 Base ROE Complaint (2011)...... 15-1118 (DC Cir.)...... 35 Base ROE Complaints (2012 and 2014)...... 15-1212 (DC Cir.)...... 34 CPV Maryland, LLC v. PPL EnergyPlus et al...... 14-623 (Supreme Court) ...... 38 CPV Power Development, Inc., et al. v. PPL EnergyPlus, LLC, et al...... 14-634/694 (Supreme Ct) ....39 Demand Curve Changes ...... 15-1070 (DC Cir.)) ...... 35 Entergy Nuclear Fitzpatrick, LLC et al. v. Zibelman et al...... 5:15-cv-00230 (N.D.N.Y.)...40 FCM Administrative Pricing Rules Complaint ...... 15-1071 (DC Cir.)...... 34 FCA8 Results ...... 14-1244 (DC Cir.)...... 36 New England’s Order 745 Compliance Filing ...... 12-1306 (DC Cir.)...... 37 Orders 745/745-A ...... 14-840 (Supreme Court) ...... 37 Order 1000 Compliance Filings ...... 15-1139 (DC Cir.)...... 34
Page I-3 41536280.155 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7.a
MEMORANDUM
TO: NEPOOL Participants Committee Members and Alternates
FROM: Pat Gerity, NEPOOL Counsel
DATE: September 30, 2015
RE: September 17, 2105 NOPR: “Connected Entity” Data Collection
We write to make you aware of a September 17 FERC Notice of Proposed Rulemaking (“NOPR”) and the November 30, 2015 deadline for commenting on that NOPR, and to seek specific guidance on whether NEPOOL should be preparing and providing comments on the NOPR by the November 30 deadline. This NOPR, if adopted without change, would dramatically expand the corporate and relationship structure information that all Market Participants will be required to share with the ISO (and all other RTOs and ISOs for the other regions where they participate). The NOPR will also impose a much broader reporting obligation on the ISO, with any impact on business priorities related to that change in obligations yet to be determined. Based on our experiences with the more than 440 members of NEPOOL, we believe that the NOPR substantially underestimates the number of entities that will be included in the proposed reporting obligations. Related to that conclusion, we believe also that the NOPR materially underestimates the cost and time associated with compliance efforts if the final rule is not changed from that proposed. We have summarized the key points of the NOPR below and I will review this information with you in a presentation at Friday’s Participants Committee meeting. Please contact me if you have any questions before the meeting or after the meeting regarding this summary or the NOPR (860.275.0533; [email protected]).
FERC explains in the NOPR that it is seeking to improve the information that it has for detecting market manipulation, which is a FERC enforcement priority. To accomplish this, FERC proposes to require that all market participants in ISOs and RTOs report all of the their “Connected Entities,” which is a newly defined term discussed below and is much broader than “Affiliate” as defined in and administered under the ISO Tariff. At highest level, Connected Entity reporting would include much, but not all of, the affiliate information already required under current ISO/NEPOOL procedures. The rule would multiply by several factors the amount of information required to be reported, by including reporting of certain employee and contractual relationships, and of debt/profitability arrangements. The NOPR proposes additional registration and compliance requirements for each market participant and RTO/ISO. It estimates that there are 6,000 market participants in RTO/ISO markets, with the number of Connected Entities to be an additional 9,000 companies. By way of comparison, we know that ISO’s database of active affiliates alone, which covers only a portion of the data called for under the NOPR, already has more than 35,000 records, and those would not include entities that currently are NOT reported as affiliates. Keeping this web of relationships current and complete will present compliance challenges for the ISO and Market Participants, particularly as the complexity of the corporate structure and number of Connected Entities increases.
I. NEW, BROADER DEFINITION: CONNECTED ENTITTY
The NOPR would replace the Tariff’s definition of Affiliate with a newly-defined “Connected Entity.” As proposed, a Connected Entity (including natural persons) would be any person or entity that stands in one or more of the following relationships to a Market Participant:
92185161.3 NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7.a
• Equity ownership or common control. Similar to the current definition of an Affiliate, a Connected Entity would include any entity that directly/indirectly owns, controls, or holds with power to vote, 10 percent or more of the ownership instruments of the market participant, including but not limited to voting and non-voting stock and general and limited partnership shares; or an entity 10 percent or more of whose ownership instruments are owned, controlled, or held with power to vote, directly or indirectly, by a market participant. In contrast to, and less broadly than the existing definition of an Affiliate, it would limit entities under common control with the market participant to be considered Connected Entities only if engaged in Commission- jurisdictional markets. More broadly, Connected Entity would include all natural persons with the requisite ownership interest; • Employment relationships. A Connected Entity would also include the chief executive officer, chief financial officer, chief compliance officer, and the traders of a market participant (or employees who function in those roles, regardless of their titles). ISOs and RTOs would be required to identify in their tariffs the key employee positions that would be included as Connected Entities. Currently, some of these persons are disclosed as part of the Financial Assurance Policy’s Minimum Eligibility Requirements, but these persons are not identified as Affiliates; • Debt instruments/profitability arrangements. A Connected Entity also would include anyone that has a holds or issues a debt instrument to, or has a contractual right either to share in the market participant’s profitability (above a de minimis amount) or convert its interest such that, in combination with its other ownership interests, it satisfies the equity ownership thresholds described above; and • Certain contractual relationships. Entities that have entered into an agreement with a market participant that relates to the management, operational, or financial control of resources that participate in FERC-jurisdictional markets, such as a tolling agreement, an energy management agreement, an asset management agreement, a fuel management agreement, an operating management agreement, an energy marketing agreement, or the like. This, too, would dramatically expand the Connected Entity information that would need to be reported. To the extent that Connected Entity information is not already public, collection of Connected Entity information is to be treated as non-public.
II. STANDARDIZED IDs: LEGAL ENTITY IDENTIFIERS
The NOPR proposes to standardize the identification of Market Participants and their Connected Entities by requiring Market Participants to register for and maintain a unique, 20-digit alphanumeric identifier – a so-called Legal Entity Identifier (“LEI”). LEIs would be issued by Local Operating Units (“LOUs”) of the Global LEI System. Entities would be able to obtain LEIs by submitting an application to the appropriate LOU. FERC estimates that the cost to acquire an LEI is approximately $250, with annual maintenance fees of $150. Some market participants may already be under an obligation with other regulators to obtain a unique LEI.
III. REGISRTATION AND COMPLIANCE REQUIREMENTS
A. Market Participant • LEI registration. • As a condition to membership and participation, provide to RTO/ISO all Connected Entities, including LEI (if known) and brief nature of the relationship. Connected Entities need not be engaged in activities in the same markets as the market participant for their inclusion to be required.
92185161.3 -2- . NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7.a
• Update Connected Entity data within 15 days of a change in status. • Yearly certification that Connected Entity data is comprehensive and accurate.
B. RTO/ISO • Initial compliance filing setting forth Connected Entity data requirements in respective tariffs. • Include in Tariff authority (although not the obligation) to audit market participants to determine if their submitted Connected Entity data is accurate, complete, and up-to-date. FERC staff may also from time to time conduct audits for this purpose. • Deliver to FERC, on an ongoing basis, Connected Entity data from market participants. The NOPR describes the tables/rows of information to be collected by the RTO/ISOs and reported to the FERC.
IV. NEXT STEPS
Comments on the NOPR are due on Monday, November 30, 2015. We have discussed this matter with the ISO and anticipate that Market Participants will have different comments and concerns than the ISO, although there may be advantages to discussing these matters together. If NEPOOL wishes to submit comments on this NOPR, we will need to define the process for members to identify and approve such comments.
92185161.3 -3- . NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7.a FERC NOPR: Connected Entity Data Collection RM15-23
presentation to NEPOOL Participants Committee October 2, 2015
Presented by: Pat Gerity (860.275.0533; [email protected]) © 2015 Day Pitney LLP NEPOOL PARTICIPANTS COMMITTEE OCT 2, 2015 MEETING, AGENDA ITEM #7.a
Outline • NOPR Overview . Cause (why?) . Connected Entity Defined . Complexity . Comparisons . Compliance . Cost • Next Steps?
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NOPR Overview • FERC’s assessment of the need and benefits . To assist and improve FERC efforts to detect market manipulation ♦ Existing Affiliate disclosure rules vary and are insufficient ♦ 3rd party sources’ data insufficient ♦ Estimate 90% coverage . To assist RTO/ISO market monitors in indiv/joint investigations of possible cross-market manipulation
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Market Connected Entity Relationships Participant 1. Equity ownership / common control . 10 %+ (direct/indirect) ownership upstream (including natural persons) Related Business Organization . 10 %+ (direct/indirect) ownership downstream . entities engaged in FERC-jurisdictional markets Ownr that are under common control with the market participant 2. Employment relationships . employees who function in these roles,
regardless of their titles: CEO CFO CCO ♦ CEO ♦ CFO Trdr ♦ Chief Compliance Officer ♦ Traders
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Connected Entity Relationships (cont.) 3. Debt/Profitability Instruments . Those holding a right to share in the market participant’s profitability (above a de minimis amount) . convertible ownership interests 4. Certain contractual relationships . relating to operational or financial control of resources participating in FERC-jurisdictional markets ♦ tolling agreements ♦ energy management agreements ♦ asset management agreements ♦ fuel management agreements ♦ operating management agreement ♦ energy marketing agreement ♦ or the like*
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Reporting Complexity: Current
Affiliate Minimum Eligibility Disclosure Requirements I.3.5 (Principals) Ultimate Parent FAP – II.A.1
Parent
Market Participant CEO CFO COO CCO
Related Business Subsidiary Organization Related Business Organization
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Reporting Complexity: NOPR
Ultimate Parent
Parent
Market Participant CEO CFO CCO
Related Business Subsidiary Organization
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Comparisons • “Affiliates of Interest” filter no longer applicable • CCOs and Traders must be reported • Contracts and contract information become reportable • Debt instruments, certain profit sharing and convertible ownership arrangements become reportable
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Compliance: RTO • Compliance filing implementing rule in Tariff changes . Audit authority . Existing affiliate disclosure requirements to be eliminated . particularized need exceptions, if justified and FERC-approved • Connected Entity data delivered to FERC on an ongoing basis
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Compliance: Market Participants • LEI registration • Full disclosure a condition to membership and participation . Connected Entities need not be engaged in activities in ISO-NE for inclusion to be required • Updates required within 15 days of a change • Yearly certifications as to comprehensiveness and accuracy
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Cost • LEI registration and maintenance fees . $250 registration fee . $150 annual fee . Applies to all Connected Entities? If so, aggregate fees may be material • Substantial time and effort • Market Behavior Rules apply . FERC civil penalty risk
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Next Steps? • Update those in your organizations to be impacted • Comments due on or before November 30, 2015 • Responses by: . ISO-NE . NEPOOL? . Individual Market Participants
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TO: NEPOOL Participants Committee Members and Alternates FROM: Pat Gerity, NEPOOL Counsel DATE: September 18, 2015 RE: 2016 Participants Committee Officer Elections
In order to ensure that the selection process requirements in the Participants Committee Bylaws for next year’s Participants Committee officers can be timely completed, we need each Sector to indicate, no later than Friday, October 23, 2015, who the Sector has selected to serve as its Sector’s Participants Committee officer. A description of the qualifications, responsibilities, and expectations of the Sector officers selected has been included with this memorandum. We urge each of you to work within your Sectors to select your Sector’s 2016 Participants Committee officer.
By way of reminder, the Bylaws require that one voting member from each Sector be selected by a majority of all the voting members in its Sector (i) to serve as a nominee for Chair of the Participants Committee and (ii) if not elected Chair, to serve as a Committee Vice-Chair. A secret written balloting process will then be conducted to elect the 2016 Chair from among the Participants Committee officers selected by each of the Sectors. To allow time for that balloting process ahead of the December 4 Annual Meeting, as required by the bylaws, we need the officers to be identified by October 23, 2015.
If any Sector needs assistance in conducting the vote for its Sector officer, please let us know (preferably no later than October 16). We would be pleased to help however we can. Also, if you have any questions, please contact me at [email protected] or (860) 275-0533.
92072409.2
Directions:
From The Airport: Follow signs from the airport for Boston/Sumner Tunnel. At the end of the Sumner Tunnel, move into the left lane and merge onto I-93N. Follow I-93N to Exit 26 – Cambridge/Storrow Drive. Follow Storrow Drive to the Copley Square/Back Bay Exit (The 2nd left hand exit). At the traffic light, turn right onto Beacon Street. Follow Beacon Street 4 blocks and turn left onto Exeter Street. Follow Exeter Street until it ends and turn right onto Huntington Avenue. Follow Huntington Avenue through the 1st set of lights. Make a U-turn at the 2nd set of lights (The hotel will be on your left hand side at this set of lights). Once you make the U-turn, the hotel entrance will be immediately on your right hand side. The garage entrance is located just beyond Brasserie Jo.
From The West: From New York and Connecticut (Route I-90E) Follow the Massachusetts Turnpike/Route I-90E to Exit 22 - Copley Square/Prudential. Stay in the left lane and follow signs for “Prudential.” This exit will place you directly onto Huntington Avenue. Proceed through the stop sign and merge into the far left lane. Make a U-turn at 1st the set of lights (The hotel will be on your left hand side at this set of lights). Once you make the U- turn, the hotel entrance will be immediately on your right hand side. The garage entrance is located just beyond Brasserie Jo.
From Worcester and Fitchburg (Route 2E) Follow Route 2E to Exit 52A – Route 95S/Route 128S. Follow Route 95S/Route 128S for 7 miles to Exit 25 – Massachusetts Turnpike/Route I-90E. Follow the same directions as above from Route I- 90E.
From The North: (Maine, New Hampshire, Vermont and the North Shore) Heading southbound on Route 95S, take Exit 37 – I-93S. Follow I-93S to Exit 26 – Storrow Drive. Stay in the left lane and follow signs for “Storrow Drive.” Follow Storrow Drive to the Copley Square/Back Bay Exit (The 2nd left hand exit). At the traffic light, turn right onto Beacon Street. Follow Beacon Street 4 blocks and turn left onto Exeter Street. Follow Exeter Street until it ends and turn right onto Huntington Avenue. Follow Huntington Avenue through the 1st set of lights. Make a U-turn at the 2nd set of lights (The hotel will be on your left hand side at this set of lights). Once you make the U-turn, the hotel entrance will be immediately on your right hand side. The garage entrance is located just beyond Brasserie Jo.
From The South: (Cape Cod and the South Shore) Heading northbound on Route I-93N, take Exit 18 – Massachusetts Avenue. Proceed through the 1st set of lights. At the 2nd set of lights, turn left over the highway and follow signs for Massachusetts Avenue. Turn right onto Massachusetts Avenue and continue through 8 sets of lights to Huntington Avenue. Turn right onto Huntington Avenue and continue through 2 sets of lights. The hotel will be immediately on your right hand side. The garage entrance is located just beyond Brasserie Jo. #
120 HUNTINGTON AVENUE ∙ BOSTON, MA 02116 USA ∙ T 617 424 7000 ∙ F 617 424 1717 ∙ COLONNADEHOTEL.COM