via electronic mail to: members and alternates of …feb 03, 2017 · 96296800.4 david t. doot...

96296800.4

David T. Doot Secretary

January 27, 2017

VIA ELECTRONIC MAIL

TO: MEMBERS AND ALTERNATES OF THE NEPOOL PARTICIPANTS COMMITTEE

RE: Supplemental Notice of February 3, 2017 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 Participants Committee will be held onFriday, February 3, 2017, at 10:00 a.m. at the Seaport Hotel, Boston MA. The Participants Committee meeting will be held for the purposes set forth on the attached agenda and posted with the meeting materials at http://nepool.com/NPC_2017.php. For your information, this meeting is recorded, as are all the NEPOOL Participants Committee meetings.

Directions to the Seaport Hotel are included with this notice. As indicated previously, rooms at the Seaport for the February 3 meeting are available at the rate of $169.00 per night, on a first-come, first-served basis. Please note, the cut-off for making reservations has been extended until Monday, January 30. To take advantage of these arrangements, please contact the hotel directly (1-877-732-7678) and reference the “NEPOOL Participants Committee” block of rooms.

Respectfully yours,

/s/ David T. Doot, Secretary

NEPOOL PARTICIPANTS COMMITTEE FEBRUARY 3, 2017 MEETING

96296800.4

FINAL AGENDA

1. To approve the draft preliminary minutes of the Participants Committee teleconference meeting held on January 6, 2017. The preliminary minutes of the January 6 teleconference meeting, which have not changed from the draft circulated with the initial notice, are included with this supplemental notice and posted with the meeting materials.

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 with the meeting materials.

3. To receive an ISO Chief Executive Officer Report.

4. To receive an ISO Chief Operating Officer Report.

5. To consider and take action, as appropriate, on revisions to the ISO Tariff related to interconnection clustering, as recommended by the Transmission Committee at its January 24, 2017 meeting. Background materials and a draft resolution are with this supplemental notice and posted with the meeting materials.

6. To consider and take action, as appropriate, on balloting an amendment to the NEPOOL and Participants Agreements to implement a proposal to create a Small Standard Offer Provider Group Seat in the Supplier Sector. Background materials and a draft resolution are included with this supplemental notice and posted with the meeting materials.

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. The litigation report will be circulated and posted in advance of the meeting.

8. To receive reports from Committees, Subcommittees and other working groups:

• Markets Committee • Reliability Committee • Transmission Committee • Budget & Finance Subcommittee • GIS Agreement Working Group • Others

9. To receive a report on administrative matters.

10. To transact such other business as may properly come before the meeting.

NEPOOL PARTICIPANTS COMMITTEE FEB 3, 2017 MEETING, AGENDA ITEM #1

Marked to Show Changes from Jan 24, 2017 draft

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PRELIMINARY

A meeting of the NEPOOL Participants Committee was held via teleconference

beginning at 10:00 a.m. on Friday, January 6, 2017, pursuant to notice duly given. 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 who participated in the teleconference meeting.

Mr. Thomas Kaslow, Chair, presided and Mr. Sebastian Lombardi, Acting Secretary,

recorded.

APPROVAL OF DECEMBER 2, 2016 MEETING MINUTES

Mr. Kaslow referred the Committee to the preliminary minutes for the December 2, 2016

meeting as circulated in advance of the meeting. Following motion duly made and seconded, the

preliminary minutes of the December 2 meeting were unanimously approved without change.

CONSENT AGENDA

Mr. Kaslow 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.

ISO CEO REPORT

Mr. Gordon van Welie, ISO Chief Executive Officer (CEO), referred the Committee to

the summaries of the ISO Board and Board Committee meetings that had occurred since the

December 2 meeting, which had been circulated and posted in advance of the meeting. There

were no questions or comments on the summaries.

In follow up to a request at the December meeting, Mr. van Welie reported the ISO

would participate in the proceeding by the Massachusetts Department of Environmental



3744

Protection (MA DEP) on proposed emission regulations. At Mr. van Welie’s request, Ms. Anne

George, ISO Vice President External Affairs and Corporate Communications, explained that the

ISO was still formulating its comments based on its ongoing review of how the imposition of the

limitations proposed by the MA DEP on carbon emissions from Massachusetts generators might

impact dispatch of generation outside of Massachusetts, regional emissions, cost, reliability, and

fuel security. She stated that the ISO would testify at one of the public hearings, although she

was not sure at which one, and planned to follow up its testimony with written comments before

February 24. She explained, in response to a question, that the ISO would likely not have the

chance to review its position with the Reliability Committee or Planning Advisory Committee

(PAC) because of that amount of work needed to be done and how quickly comments were

required.

ISO COO REPORT

Dr. Vamsi Chadalavada, ISO Chief Operating Officer (COO), reviewed highlights from

the January COO report, which was circulated in advance of the meeting and posted on the

NEPOOL and ISO websites. Focusing on report highlights, which he explained reflected data

through December 28, 2016, he reported for December that: (i) Energy Market value was $566

million, up $313 million from November 2016 and up $318 million from December 2015; (ii)

natural gas prices ($6.88/MMBtu) were 168% higher than November 2016 average values; (iii)

average Real-Time Hub LMPs ($55.48/MWh) were 128% higher than November 2016 LMPs;

(iv) average daily (peak hour) Day-Ahead cleared physical Energy, as a percent of forecasted

load, was 97.4% in December, up from 97.1% in November; (v) daily NCPC for November

totaled $6.4 million, down $8.5 million from November 2016 NCPC and up $1.6 million from

December 2015; (vi) first contingency payments, totaling $4.8 million, were $2.1 million higher



3745

than November’s; (vii) second contingency payments totaled $1.5 million, $10.8 million less

than in November’s; (viii) voltage support payments totaled $174,000, up $154,000 from

November 2016; and (ix) NCPC payments were 1.1% of the total Energy Market value.

He explained that December’s Energy Market value was substantially higher than

November’s largely due to higher natural gas prices. He reported that almost all the uplift in

December was for first contingency payments, with the relatively small second contingency

costs divided between NEMA (due to commitments driven by load levels and miscellaneous

outages) and SEMA/RI (due to a transmission outage that happened to coincide with an

unplanned unit outage).

Turning to the Winter Reliability Program, Dr. Chadalavada reported that, on December

1, when official measurement of inventory levels for potential compensation under the 2016/17

Winter Reliability Program were taken, there were 3.05 million barrels of oil eligible for fuel

compensation. The maximum total exposure for oil program compensation was $31.16 million.

There was a reduction in liquefied natural gas (LNG) program enrollment from October, with

two units participating with about 171,000 MMBtu, for a maximum cost exposure of $291,000.

The maximum exposure for the demand response (DR) program was $71,000 for 23 MW of

interruption capability. He stated that the ISO had not yet collected December fuel usage data

but would have that information distributed when available.

Dr. Chadalavada concluded his report reviewing FCM highlights. He reported that final

preparations were being made for the eleventh Forward Capacity Auction (FCA11) scheduled to

begin on February 6, with a mock auction scheduled on January 30 at 10:00 a.m. He encouraged

participation in the mock auction process to ensure preparedness for FCA11. He reported that

the next installment of financial assurance for new capacity resources participating in FCA11

was due on January 23.



3746

In response to a question, Dr. Chadalavada reported that the difference between LMPs

and natural gas prices on December 16 was driven in part by a snowstorm on December 16-17,

an under-forecast of load by more than 1,000 MW, and minor constraints on the Algonquin

pipeline. Those factors all drove up the LMPs.

CONE, NET CONE AND ORTP VALUE UPDATES

Mr. Alex Kuznecow, Markets Committee Chairman, referred the Committee to the

materials posted in advance of the meeting concerning Tariff revisions to update the Cost of New

Entry (CONE), Net CONE and Offer Review Trigger Prices (ORTP) values in FCM. He

explained that the current CONE, Net CONE and ORTP values were specifically enumerated in

the ISO Tariff and were last updated by the ISO, and filed with and approved by the FERC, in

2014. He stated the Market Rules required those values to be recalculated at least once every

three years using updated data and the Tariff revisions reflected the results of the required

recalculation. He reported that the ISO would use updated values, as approved by the FERC,

beginning with FCA12.

Mr. Kuznecow reported that the Markets Committee, at its December 6, 2016 meeting,

considered and recommended Participants Committee support, by a 65.70% Vote in favor, for

the ISO’s proposed values with one change relating to the ORTP for on-shore wind resources

(the Participant Proposal). That change was proposed by RENEW Northeast, and moved by the

Union of Concerned Scientists on behalf of RENEW (together, the sponsors). As changed by

RENEW Northeast’s proposal, the ORTP value for on-shore wind resources would be

$4.496/kW-mo., as compared with the ISO-proposed $11.025/kW-mo. The reason for the lower

ORTP value recommended by the Market Committee was the use of a higher capacity factor

assumption for on-shore wind than assumed by the ISO (35% versus 32%). Mr. Kuznecow



3747

reported that the Markets Committee also considered a proposed amendment to the CONE

values offered by Calpine, but that amendment did not have sufficient Markets Committee

support to be part of the package of changes recommended to the Participants Committee.

Continuing, he explained that the ISO did not support the Markets Committee-recommended

ORTP value for on-shore wind resources and requested a vote on its own proposal with the

higher ORTP value for on-shore wind (ISO Proposal). That proposal received a 36.53% Vote in

favor and was therefore not recommended by the Markets Committee.

Mr. Lombardi reported that, following the December 6 Markets Committee meeting, the

sponsors of the Participant Proposal decided not to pursue that Proposal at the Participants

Committee, as reported to the Committee in a notice circulated December 22, 2016, and as

explained by the sponsors in a memorandum provided by RENEW, which was circulated with

the meeting materials. In addition, Calpine advised NEPOOL Counsel that it would offer for

Participants Committee consideration the same amendment it had previously offered at, and

which was not supported by, the Markets Committee.

Mr. Lombardi then summarized the suggested process for consideration of the proposals,

which had been described more fully in the NEPOOL Counsel memorandum circulated with the

meeting materials. He noted first that Participants Committee consideration would normally

begin with the proposal recommended by the Markets Committee (in this case, the Participant

Proposal). Given the decision of the sponsors to not pursue the Participant Proposal at the

Participants Committee, as explained in the memo to the Committee, NEPOOL Counsel

suggested that beginning with the ISO Proposal as the main motion might be more efficient.

That deviation from the normal process, though, would only be followed if no one objected to

the ISO Proposal being reflected in the main motion. If anyone objected, the Participant

Proposal would be reflected in the main motion and the Committee would then need to vote to



3748

amend the main motion to vote instead on the ISO Proposal. Without any objection to the

suggested procedure, the following main motion was then duly made and seconded, reflecting

the ISO Proposal:

RESOLVED, that the Participants Committee supports revisions to Market Rule 1 and Appendix A to Market Rule 1 to update Cost of New Entry (CONE) and Net CONE values and recalculate the Offer Review Trigger Prices (ORTPs) using updated data for FCA12, as recommended by ISO New England and circulated to this Committee in advance of this meeting, together with such non-substantive changes as the Chair and Vice-Chair of the Markets Committee may approve.

Calpine Amendment

The Calpine representative then reviewed Calpine’s proposed amendment that a combined-

cycle gas turbine be used as the reference technology for the calculation of CONE and Net CONE,

resulting in higher values than those proposed by the ISO. He expressed his view that the ISO

decision since the last CONE determination to change the basis for the calculation of CONE and

Net CONE from a combined-cycle gas turbine to a combustion turbine was unjustified and added

considerable uncertainty to the market. He said that recently cleared greenfield projects in New

England had all been combined-cycle (Towantic, Clear River Energy) and that the combined-cycle

technology was a better fit for the region since it was much more able with a lower carbon footprint than

single-cycle technology to support dispatch requirements and fluctuations in generation output.

The motion to amend the main motion was then duly made and seconded to increase CONE

to $15.62/kW-mo. and to increase Net CONE to $10.00/kW-mo. (Calpine Amendment).

Members then discussed and debated the Calpine Amendment. Speaking in favor of the

Calpine Amendment, members noted the importance of investor certainty and continuity,

explaining that decisions had already been made, money lent, and capital committed based on the

use of a combined-cycle technology, and the adverse impact that a 30% drop in the Net CONE



3749

would have on investor certainty. Supporters pointed to the experiences over the last three FCAs

that demonstrated in their view the correctness of the conclusion that new merchant greenfield

generation would choose combined-cycle technology over the less-expensive combustion turbine

technology. This more flexible generation was, they argued, needed for reliability reasons. They

explained that the ISO-proposed change in Net CONE and its resulting impact on the

establishment of the FCA Starting Price would produce prices that could eliminate fast-start

peaking units from participating in future auctions.

Others spoke in opposition to the Calpine Amendment. They argued that there would

still be opportunities for combined-cycle units to continue to participate and clear in auctions

going forward, and could better manage any related investment risk. They strongly supported

the certainty and benefits associated with the ISO employing then, and in the future, the lowest-

cost, reasonably available resource technology for setting Net CONE (which the Concentric

analysis demonstrated the ISO Proposal would do). The NESCOE representative reported that

the States opposed the amendment because it would produce an unjustified increase of more than

40% over the FCA10 clearing price. He pointed out also that, even if the ISO-proposed values

proved to be wrong, the transitional sloped demand curves would produce prices closer to those

that would result if the Calpine Amendment passed, and the States were confident that the Net

ICR would remain at an acceptable level for resource adequacy purposes.

On behalf of the ISO, Mr. Mark Karl stated that, with respect to the choice of technology,

the ISO believed that the analysis performed supported the use of the combustion turbine

resource in establishing the CONE/Net CONE values. He summarized concerns identified three

years ago that, despite the fact that the single-cycle combustion turbine was the cheaper

technology, there would not be willingness to build that technology in New England. He

explained the ISO’s view that those concerns were no longer justified because, over the past



3750

three years, single-cycle combustion turbines had cleared in the marketplace at prices close to the

recommended number. Accordingly, he concluded that a single-cycle combustion turbine was

the right reference technology and the resulting values were appropriate.

The Committee then voted the Calpine Amendment, which failed with a 44.21% Vote in

favor (Generation Sector – 17.12%; Transmission Sector – 1.72%; Supplier Sector – 17.12%;

AR Sector – 8.25%; Publicly Owned Entity Sector – 0%; and End User Sector – 0%). (See Vote

1 on Attachment 2).

ISO Proposal

The Committee then considered the main motion for NEPOOL to support the ISO

Proposal. Commenting against that proposal, a representative of NEPGA argued that the

proposed calculation of NET CONE employed by the ISO to calculate ancillary service revenue

offsets failed to reflect properly planned market structure changes and could overstate revenues

from those markets. He stated that NEPGA had received from the ISO and its consultant certain

information and details as to the modeling and analysis performed, and continued to evaluate that

additional information and its resulting conclusions. Based on analysis and discussion to date,

NEPGA would be opposing the filing of the updated CONE, Net CONE and ORTP values, and

would be providing additional information explaining the bases for that opposition.

Noting concern that the ISO Proposal could produce inappropriate FCM values for

multiple FCAs, a member asked whether the ISO would be willing to re-evaluate CONE/Net

CONE values earlier than the three-year full recalculation required under the Tariff should there

be dramatic changes in the marketplace. Mr. Karl indicated that if dramatic changes in the

market called into question the appropriateness of CONE/Net CONE values, the ISO would

consider revisiting them in the stakeholder process and with the FERC earlier than required

under the Tariff.



3751

A representative of the AR Sector stated the companies he represented would abstain on

the vote to support the ISO Proposal because of the change in circumstances since the Markets

Committee. The representative of the Maine and New Hampshire consumer advocates explained

that abstentions on the main motion by those Participants would be attributable specifically to the

ISO-proposed ORTP value for on-shore wind resources, and not to the Net CONE or the CONE

values. The SunEdison representative noted Sun Edison would oppose the motion. He

explained that SunEdison supported the process followed by this Committee in not voting on the

Participant Proposal, but was very concerned with the process undertaken and the analysis

performed by the ISO in relation to the ORTP for on-shore wind resources. He expressed his

opinion that the ISO’s calculation of ORTP for on-shore wind was an exercise in false precision

that was not unsupported by the data.

The NESCOE representative stated that NESCOE supported the overall reasonableness

of the ISO Proposal but that support did not mean that the States supported or agreed with every

individual assumption used in the CONE and Net CONE calculations. He thanked the ISO for

its commitment to revisit these values earlier, rather than wait a full three years, if circumstances

support such an early revisitation.

Mr. Jeffrey McDonald, ISO Internal Market Monitor (the IMM), offered his assessment

that the ISO Proposal reflected an accurate set of ORTP values that were consistent with the

relative economics of the different generation technologies and consistent with the intent of the

Minimum Offer Price Rule. He expressed IMM support for the ORTP values, noting that,

although the higher ORTP for on-shore wind might well impose a greater burden on the IMM to

specifically analyze more offers, that value would not deny any resource the opportunity to

participate in the market at a competitive price.



3752

The Committee then voted on the main motion (ISO Proposal), which failed with a

49.66% Vote in favor (Generation Sector – 0%; Transmission Sector – 15.42%; Supplier Sector

– 0%; AR Sector – 0%; Publicly Owned Entity Sector – 17.12%; and End User Sector –

17.12%). (See Vote 2 on Attachment 2). The ISO reported its plan to file the proposal with the

FERC by January 13.

PROPOSAL TO IMPLEMENT A SMALL STANDARD OFFER SUPPLIER SECTOR GROUP SEAT

At the request of Mr. Kaslow, Mr. Patrick Gerity, NEPOOL Counsel, referred the

Committee to the materials circulated in advance of the meeting regarding a proposal to amend

the NEPOOL and Participants Agreements to create a “Small Standard Offer Group Seat” in the

Supplier Sector (the Proposal). He explained that the Proposal would establish a group seat in

the Supplier Sector that was intended to facilitate participation by Market Participants who are

solely serving standard offer load and whose average hourly Real-Time Load Obligation (RTLO)

(looking back over all hours with RTLO during the prior 12 months) was 10 MWh or less. He

said that this matter would be presented for consideration and vote to ballot at the February 3,

2017 Participants Committee meeting. He reported that the Membership Subcommittee was

scheduled to meet on January 18 to review theis Proposal further, and encouraged those

interested to participate in that meeting. In response to a request, Mr. Gerity committed to

circulate notice of the Subcommittee meeting to the members when NEPOOL Counsel circulated

the Notice of Actions of this meeting.

LITIGATION REPORT

Mr. Lombardi referred the Committee to the January 4 Litigation Report that had been

circulated and posted in advance of the meeting. He referenced two recent Notices of Proposed

Rulemaking (NOPRs) which addressed electric storage participation in RTO/ISO markets



3753

(RM16-23) and fast-start pricing (RM17-3). He stated he would provide an overview of the

NOPRs to members at the January 10 Markets Committee meeting, and would solicit feedback

on any proposed comments that NEPOOL may want to submit in those proceedings. Mr. Gerity

added that all the FCA proceedings were concluded through FCA8. He said that briefing before

the D.C. Circuit on FCA9 and FCA10 was ongoing. He reported that oral argument on the

appeal of the FERC’s orders on New England’s Order 1000 compliance filings was scheduled

for January 13.

COMMITTEE REPORTS

Markets Committee. Mr. William Fowler reported that the next Markets Committee

meeting was scheduled for January 10 as a half-day meeting.

Transmission Committee. Mr. José Rotger reported that the Transmission Committee

was scheduled to meet on January 11, with the agenda including further discussions on the ISO’s

proposal for an interconnection process clustering mechanism and related Tariff language and

amendments, for a vote at its January 24 meeting and final consideration at the February 3

Participants Committee meeting. He requested that anyone with amendments to the ISO’s

proposal to submit them soon or at least advise the officers of their intent to submit an

amendment for Transmission Committee consideration when it votes in January.

Reliability Committee. Mr. Robert Stein reported that the Reliability Committee was

scheduled to meet on January 17 and would start to review changes to the Coordination

Agreements between New York, Hydro-Quebec, New Brunswick, and the ISO and would begin

with the New York Coordination Agreement.

Budget & Finance Subcommittee. Mr. Ken Dell Orto reported that the Budget &

Finance Subcommittee was scheduled to meet on January 26, 2017 to review FAP and Billing



3754

Policy changes, as well as to review NEPOOL Generation Information System (GIS) exemption

requests.

GIS Agreement Working Group. Mr. David Cavanaugh reminded the Committee that

NEPOOL is currently operating under a one-year extension of its agreement with APX. He

stated the GIS Agreement Working Group was evaluating proposals from APX and ISO, looking

to recommend to NEPOOL the GIS administrator following expiration of the one-year extension.

He said that the Working Group would submit clarifying questions to APX on its proposal and

would schedule further discussions with the ISO on its interests. Lastly, he reported the Working

Group sent out three letters seeking expressions of interest from others should the Working

Group recommend soliciting by the end of the first quarter of 2017 further proposals for GIS

services (RFP). He reported two of the three parties expressed interest in participating in the

RFP.

OTHER BUSINESS

Mr. Lombardi reminded the Committee of the January 25 IMAPP meeting that was

scheduled to take place at the Doubletree Hotel in Westborough, MA. He reported that the next

Participants Committee meeting was scheduled for February 3, 2017, at the Seaport Hotel in

Boston, MA.

There being no further business, the teleconference meeting adjourned at 11:40 a.m.

Respectfully submitted,

______________________ Sebastian M. Lombardi, Acting Secretary

ATTACHMENT 2 VOTES TAKEN ON

JANUARY 6, 2017 PARTICIPANTS COMMITTEE TELECONFERENCE MEETING

PARTICIPANT NAME SECTOR/ GROUP

MEMBER NAME ALTERNATE NAME PROXY

American PowerNet Management Supplier Mary Smith

Ashburnham Municipal Light Plant Publicly Owned Brian Thomson

AVANGRID (CMP/UI) Transmission Eric Stinneford Christian Bilcheck

Belmont Municipal Light Department Publicly Owned Tim Hebert

Boylston Municipal Light Department Publicly Owned Brian Thomson

BP Energy Company Supplier Nancy Chafetz

Brookfield Energy Marketing Supplier Aleks Mitreski

Bucksport Generation Generation Brett Kruse

Calpine Energy Services, LP Supplier Brett Kruse William Fowler

Chester Municipal Electric Light Department Publicly Owned Tim Hebert

Chicopee Municipal Lighting Plant Publicly Owned Brian Thomson

Citigroup Energy Inc. Supplier Brett Kruse

CLEAResult Consulting, Inc. AR Doug Hurley

Concord Municipal Light Plant Publicly Owned Tim Hebert

Connecticut Municipal Electric Energy Coop. Publicly Owned Brian Forshaw

Connecticut Office of Consumer Counsel End User Joe Rosenthal David Thompson

Conservation Law Foundation End User Jerry Elmer

Consolidated Edison Energy, Inc. Supplier Jeff Dannels

Covanta Haverhill Associates, LP AR Brett Kruse

CPV Towantic, LLC Generation Dan Pierpont

Cross-Sound Cable Supplier Jose Rotger

Danvers Electric Division Publicly Owned Tim Hebert

Direct Energy Business, LLC Supplier Nancy Chafetz

Dominion Energy Marketing, Inc. Generation Jim Davis

DTE Energy Trading, Inc. Supplier Nancy Chafetz

Dynegy Marketing and Trade, LLC Supplier ` William Fowler

Emera Maine Transmission Sandi Hennequin Stacy Dimou

Entergy Nuclear Power Marketing, LLC Generation Ken Dell Orto William Fowler

EnerNOC, Inc. AR Sarah Griffiths

Essential Power, LLC Generation Lisa Krueger William Fowler

Eversource Energy Transmission James Daly Cal Bowie

Exelon Generation Company Supplier Steve Kirk William Fowler

FirstLight Power Resources Management, LLC Generation Tom Kaslow

Galt Power, Inc. Supplier Nancy Chafetz

Generation Group Member Generation Abby Krich Bob Stein

Georgetown Municipal Light Department Publicly Owned Tim Hebert

Groton Electric Light Department Publicly Owned Brian Thomson

Groveland Electric Light Department Publicly Owned Tim Hebert

H.Q. Energy Services (U.S.) Inc. Supplier Louis Guilbault Bob Stein Abby Krich

Harvard Dedicated Energy Limited End User Mary Smith Paul PetersonDoug Hurley

High Liner Foods (USA) Incorporated End User William P. Short III

Hingham Municipal Lighting Plant Publicly Owned Tim Hebert

Holden Municipal Light Department Publicly Owned Brian Thomson

Hull Municipal Lighting Plant Publicly Owned Brian Thomson

Industrial Energy Consumer Group End User Donald Sipe

Invenergy Energy Management LLC Generation Brett Kruse

Ipswich Municipal Light Department Publicly Owned Brian Thomson

Jericho Power, LLC AR Thomas Hoatson

Long Island Lighting Company (LIPA) Supplier Bill Killgoar

Littleton (MA) Electric Light & Water Department Publicly Owned Tim Hebert

Littleton (NH) Water & Light Department Publicly Owned Craig Kieny

ATTACHMENT 1 PARTICIPANTS COMMITTEE MEMBERS AND ALTERNATES

PARTICIPATING IN JANUARY 6, 2017 TELECONFERENCE MEETING

PARTICIPANT NAME SECTOR/ GROUP

MEMBER NAME ALTERNATE NAME PROXY

Maine Power, LLC Supplier Jeff Jones

Maine Public Advocate Office End User Paul Peterson

Maine Skiing, Inc. End User Donald Sipe

Mansfield Municipal Electric Department Publicly Owned Brian Thomson

Marblehead Municipal Light Department Publicly Owned Brian Thomson

Marble River, LLC Supplier John Brodbeck

Massachusetts Attorney General’s Office (MA AG) End User Fred Plett Christina Belew

Mass. Development Finance Agency Publicly Owned Tim Hebert

Mass. Municipal Wholesale Electric Company (MMWEC) Publicly Owned Brian Thomson

Mercuria Energy America, Inc. Supplier Nancy Chafetz

Merrimac Municipal Light Department Publicly Owned Tim Hebert

Middleborough Gas and Electric Department Publicly Owned Brian Thomson

Middleton Municipal Electric Department Publicly Owned Tim Hebert

National Grid Transmission Timothy Brennan Timothy Martin

New Hampshire Electric Cooperative (NHEC) Publicly Owned Brian Forshaw

New Hampshire Office of Consumer Advocate (NH OCA) End User Paul Peterson

NextEra Energy Resources, LLC Generation Michelle Gardner

NRG Power Marketing LLC Generation Dave Cavanaugh

Pascoag Utility District Publicly Owned Tim Hebert

Paxton Municipal Light Department Publicly Owned Brian Thomson

Peabody Municipal Light Plant Publicly Owned Brian Thomson

PowerOptions, Inc. End User Cindy Arcate

Princeton Municipal Light Department Publicly Owned Brian Thomson

PSEG Energy Resources & Trade LLC Supplier Joel Gordon

Repsol Energy North America Company Supplier Nancy Chafetz

Rowley Municipal Lighting Plant Publicly Owned Tim Hebert

Russell Municipal Light Department Publicly Owned Brian Thomson

Shrewsbury Electric & Cable Operations Publicly Owned Brian Thomson

Small Load Response Group Member AR Doug Hurley Brad Swalwell

Small Renewable Generation Group AR Erik Abend

South Hadley Electric Light Department Publicly Owned Brian Thomson

Sterling Municipal Electric Light Department Publicly Owned Brian Thomson

Stowe Electric Department Publicly Owned Tim Hebert

SunEdison companies AR John Keene Bob Stein, Abby Krich

Talen Energy Marketing, LLC Supplier Tom Hyzinski

Taunton Municipal Light Department Publicly Owned Tim Hebert

Templeton Municipal Lighting Plant Publicly Owned Brian Thomson

The Energy Consortium End User Mary Smith

Union of Concerned Scientists End User Francis Pullaro

Vermont Electric Cooperative Publicly Owned Craig Kieny

Vermont Electric Power Company Transmission Frank Ettori

Vermont Energy Investment Corporation AR Doug Hurley

Vermont Public Power Supply Authority Publicly Owned Brian Callnan

Verso Maine Energy LLC Generation Brett Kruse

Vitol Inc. Supplier Joseph Wadsworth

Wakefield Municipal Gas and Light Department Publicly Owned Brian Thomson

Wallingford DPU Electric Division Publicly Owned Tim Hebert

Wellesley Municipal Light Plant Publicly Owned Tim Hebert

West Boylston Municipal Lighting Plant Publicly Owned Brian Thomson

Westfield Gas & Electric Light Department Publicly Owned Tim Hebert

Wheelabrator North Andover Inc. AR William Fowler

ATTACHMENT 2VOTES TAKEN ON

JANUARY 6, 2017 NEPOOL PARTCIPANTS COMMITTEE TELECONFERENCE MEETING

TOTAL

Sector/Group Vote 1 Vote 2

GENERATION 17.12 0.00

TRANSMISSION 1.72 15.42

SUPPLIER 17.12 0.00

ALTERNATIVE RESOURCES 8.25 0.00

PUBLICLY OWNED ENTITY 0.00 17.12

END USER 0.00 17.12

% IN FAVOR 44.21 49.66

GENERATION SECTOR

Participant Name Vote 1 Vote 2

Bucksport Generation F O

CPV Towantic, LLC F O

Dominion Energy Marketing F O

Entergy Nuclear Power Marketing F O

Essential Power, LLC F O

FirstLight Power Resources F A

Generation Group Member A A

Invenergy Energy Management F O

NextEra Energy Resources, LLC F O

NRG Power Marketing, LLC F O

Verso Maine Energy LLC F O

IN FAVOR (F) 10 0

OPPOSED (O) 0 9

TOTAL VOTES 10 9

ABSTENTIONS ( A) 1 2

TRANSMISSION SECTOR


AVANGRID (CMP/UI) O F

Emera Maine S1

S1

Emera Maine O F

Emera Energy Services Subsidiaries F O

Eversource Energy O F

National Grid O F

Vermont Electric Power Co. O F

IN FAVOR (F) 0.5 4.5

OPPOSED 4.5 0.5

TOTAL VOTES 5.0 5.0

ABSTENTIONS (A) 0.0 0.0

1 Pursuant to Section 6.2 of the NEPOOL Agreement, Participants and their Related Persons are for voting purposes together permitted to join only one Sector to which any of them is eligible to join, but are permitted to split the vote in that Sector as they see fit. Emera Maine and the Emera Energy Services Subsidiaries, as Related Persons, are collectively members of the Transmission Sector, but sometimes split their vote evenly between the companies’ transmission (Emera Maine) and generation (Emera Energy) interests.

ALTERNATIVE RESOURCES SECTOR


Renewable Generation Sub-Sector

Covanta Haverhill Associates F O

Jericho Power LLC F O

Small RG Group Member F A

SunEdison (First Wind) A O

Wheelabrator North Andover Inc. F O

Distributed Generation Sub-Sector

CLEAResult Consulting, Inc. O A

Load Response Sub-Sector

EnerNOC, Inc. A A

Small LR Group Member O A

VT Energy Investment Corp. O A

IN FAVOR (F) 4 0

OPPOSED 3 4

TOTAL VOTES 7 4

ABSTENTIONS (A) 2 5

SUPPLIER SECTOR


American PowerNet Management A A

BP Energy Company A A

Brookfield Energy Marketing Inc. F O

Calpine Energy Services F O

Citigroup Energy Inc. F O

Consolidated Edison Energy, Inc. F O

Cross-Sound Cable Company F A

Direct Energy Business, LLC A A

DTE Energy Trading, Inc. A A

Dynegy Marketing and Trade, LLC F O

Exelon Generation Company F O

Galt Power, Inc. A A

H.Q. Energy Services (U.S.) Inc. F A

Long Island Power Authority (LIPA) A A

Maine Power, LLC -- A

Marble River, LLC F A

Mercuria Energy America, Inc. A A

PSEG Energy Resources & Trade F O

Repsol Energy North America F O

Talen Energy Marketing, LLC F O

Vitol Inc. F A

IN FAVOR (F) 13 0

OPPOSED 0 9

TOTAL VOTES 13 9

ABSTENTIONS (A) 7 12

ATTACHMENT 2 VOTES TAKEN ON

JANUARY 6, 2017 NEPOOL PARTCIPANTS COMMITTEE TELECONFERENCE MEETING

.

END USER SECTOR


Conn. Office of Consumer Counsel O F

Conservation Law Foundation A F

Harvard Dedicated Energy Limited O F

High Liner Foods (USA) Inc. A A

Industrial Energy Consumer Group A A

Maine Public Advocate Office O A

Maine Skiing, Inc. A A

Mass. Attorney General's Office O F

NH Office of Consumer Advocate O A

PowerOptions, Inc. O A

The Energy Consortium O F

Union of Concerned Scientists A A

IN FAVOR (F) 0 5

OPPOSED 7 0

TOTAL VOTES 7 5

ABSTENTIONS (A) 5 7

PUBLICLY OWNED ENTITY SECTOR


Ashburnham Municipal Light Plant O F

Belmont Municipal Light Dep’t O F

Boylston Municipal Light Dep’t O F

Chester Municipal Light Dep’t O F

Chicopee Municipal Lighting Plant O F

Concord Municipal Light Plant O F

Conn. Mun. Electric Energy Coop. O F

Danvers Electric Division O F

Georgetown Municipal Light Dep’t O F

Groton Electric Light Department O F

Groveland Electric Light Dep’t O F

Hingham Municipal Lighting Plant O F

Holden Municipal Light Dep’t O F

Hull Municipal Lighting Plant O F

Ipswich Municipal Light Dep’t O F

Littleton (MA) Electric Light Dep’t O F

Littleton (NH) Water & Light Dep’t O F

Mansfield Municipal Electric Dep’t O F

Marblehead Municipal Light Dep’t O F

Mass. Development Finance Agc’y O F

Mass. Mun. Wholesale. Elec. Co. O F

Merrimac Municipal Light Dep’t O F

Middleborough Gas & Elec. Dep’t O F

Middleton Municipal Electric Dep’t O F

New Hampshire Electric Coop. O F

PUBLICLY OWNED ENTITY SECTOR cont’d


Pascoag Utility District O F

Paxton Municipal Light Dep’t O F

Peabody Municipal Light Plant O F

Princeton Municipal Light Dep’t O F

Rowley Municipal Lighting Plant O F

Russell Municipal Light Dep’t O F

Shrewsbury's Elec. & Cable Ops. O F

South Hadley Electric Light Dep’t O F

Sterling Mun. Elec. Light Dep’t O F

Stowe (VT) Electric Department O F

Taunton Municipal Lighting Plant O F

Templeton Mun. Lighting Plant O F

Vermont Electric Cooperative O F

VT Public Power Supply Authority O F

Wakefield Mun. Gas & Light Dep’t O F

Wallingford (CT) Div. Pub. Utils. O F

Wellesley Municipal Light Plant O F

West Boylston Mun. Lighting Plant O F

Westfield Gas & Elec. Light Dep’t O F

IN FAVOR (F) 0 44

OPPOSED 44 0

TOTAL VOTES 44 44

ABSTENTIONS (A) 0 0


CONSENT AGENDA

From the notice of actions of the January 17, 2017 Reliability Committee1 meeting, dated January 17, 2017, which has been previously circulated:

1. PP-3 Revisions (Reliability Standards for New England Area PTF)

Support revisions to ISO Planning Procedure (PP) No. 3 (to be entitled ‘Reliability Standards for the New England Area Pool Transmission Facilities’) (PP-3), including general clean-up and updates to ensure PP-3 design criteria applies to, and provides an appropriate set of requirements for, all Pool Transmission Facilities (PTF), as recommended by the Reliability Committee at its January 17, 2017 meeting, with such further non-material changes as the Chair and Vice-Chair of the Reliability Committee may approve.

The motion to recommend Participants Committee support was approved unanimously with one abstention in the Publicly Owned Entity Sector.

2. Market Rule 1 Section 12 Revisions (Deletion of RTEG Reference No Longer Needed with DR Full

Integration)

Support revisions to Tariff Section III.12 to remove a reference to Real-Time Emergency Generation (RTEG), no longer be needed with the full integration of Demand Response (DR) Resources into wholesale markets and changes in U.S. Environmental Protection Agency (EPA) regulations, as recommended by the Reliability Committee at its January 17, 2017 meeting, with such further non-material changes as the Chair and Vice-Chair of the Reliability Committee may approve.

The motion to recommend Participants Committee support was approved unanimously.

From the notice of actions of the January 10, 2017 Markets Committee2 meeting, dated January 10, 2017, which has been previously circulated:

3. Market Rule 1 and Tariff Revisions (Deletion of Active DR Provisions No Longer Needed with DR

Full Integration)

Support revisions to Market Rule 1 and Tariff Section I.2.2 to remove Real-Time DR and RTEG Resource provisions (Active DR Provisions) that will no longer be needed with the full integration of DR Resources into wholesale markets and changes in EPA regulations, as recommended by the Markets Committee at its January 10, 2017 meeting, with such further non-material changes as the Chair and Vice-Chair of the Markets Committee may approve.


4. Manual M-20 Revisions (ETU, FCM Enhancements Phase I and Resource Retirement Reforms Projects Supporting Changes)

Support revisions to Manual M-20 (Forward Capacity Market) to support recent initiatives including Elective Transmission Upgrade (ETU), FCM Enhancements Phase I and Resource Retirement Reforms projects, and to reflect reformatting and other changes to enhance Manual functionality, as recommended by the Markets Committee at its January 10, 2017 meeting, with such further non-material changes as the Chair and Vice-Chair of the Markets Committee may approve.


1 Reliability Committee Notices of Actions are posted on the ISO website at: http://iso-ne.com/committees/reliability/reliability-committee.

2 Markets Committee Notices of Actions are posted on the ISO website at: https://iso-ne.com/committees/markets/markets-committee.

ISO-NE PUBLIC

Summary of ISO New England Board and Committee Meetings

February 3, 2017 Participants Committee Meeting

Since the last update, the Compensation and Human Resources Committee met by

teleconference on January 10. On January 19, the Compensation and Human Resources

Committee, the System Planning and Reliability Committee, the Markets Committee, and the

Board of Directors each met in Holyoke.

At its January 10 Meeting, the Compensation and Human Resources Committee confirmed the

budgets for employees’ 2017 salary increases using updated compensation survey information.

The Committee then met in executive session to review corporate goals for 2017 and additional

compensation matters.

At its January 19 Meeting, the Compensation and Human Resources Committee met in

executive session to consider a variety of compensation-related matters. During executive

session, the Committee reviewed the achievement of 2016 goals and discussed officer

compensation for 2017.

The System Planning and Reliability Committee discussed the panel session format for the 2017

Regional System Plan public meeting, and reviewed the latest information on solar photovoltaic

impacts on the New England power system. The Committee then held an executive session to

assess achievement of 2016 corporate goals.

The Markets Committee reviewed reports from both the Internal and External Market Monitors

on key market issues during the 2016 fall season. There was a general discussion concerning the

overall performance of the capacity and energy markets over the past several years, as well as

the issues that are likely to arise over the next several years. Next, the Committee discussed

potential means of addressing the market impact of state public policy initiatives favoring the

development of renewable resources. Finally, during executive session, the Committee assessed

achievement of 2016 corporate goals.

The Board of Directors received an update from the Chief Executive Officer, and reports from

the standing committees. During executive session, the Board approved the corporate goals for

2017.

NEPOOL PARTICIPANTS COMMITTEEFEB 3, 2017 MEETING, AGENDA ITEM #3

ISO-NE PUBLIC

F E B R U A R Y 3 , 2 0 1 7 | B O S T O N , M A

Vamsi Chadalavada E X E C U T I V E V I C E P R E S I D E N T A N D C H I E F O P E R A T I N G O F F I C E R

February 2017

NEPOOL Participants Committee Report

NEPOOL PARTICIPANTS COMMITTEE 02/03/2017 MEETING, AGENDA ITEM #4

ISO-NE PUBLIC

Table of Contents • Highlights Page 3 • System Operations Page 12 • Market Operations Page 25 • Back-Up Detail Page 42

– Load Response Page 43 – New Generation Page 45 – Forward Capacity Market Page 52 – Reliability Costs - Net Commitment Period Compensation

(NCPC) Operating Costs Page 59 – Regional System Plan (RSP) Page 90 – Operable Capacity Analysis – Winter 2016/17 Page 117 – Operable Capacity Analysis – Spring 2017 Page 124 – Operable Capacity Analysis – Appendix Page 131

2


ISO-NE PUBLIC 3

Highlights

• Energy market value was $378M, down $236M from December 2016 and down $67M from January 2016 – January natural gas prices over the period were 23% lower than

December 2016 average values – Average RT Hub Locational Marginal Prices ($37.54/MWh) over the

period were 30% lower than December 2016 averages – Average January 2017 natural gas prices and RT Hub LMPs over the

period were up 16% and up 10%, respectively, from January 2016 averages

• Average DA cleared physical energy during the peak hours as percent of forecasted load was 98.5% during January, up from 97.5% during December 2016*

*DA Cleared Physical Energy is the sum of Generation and Net Imports cleared in the DA Energy Market

Underlying natural gas data furnished by:

Data are through January 25, 2017, except where otherwise noted.


http://www.theice.com/

ISO-NE PUBLIC 4

Highlights, cont.

• Daily Net Commitment Period Compensation (NCPC) – January NCPC payments totaled $3.3M over the period, down $3.3M

from December 2016 and down $4.0M from January 2016 • First Contingency payments totaled $3.0M, down $2.0M from December

– $2.9M paid to internal resources, down $2.0M from December » $1.48M charged to DALO, $1.3M to RT Deviations, $176K to RTLO

– $54K paid to resources at external locations, up $22K from December » $54K to RT Deviations

• Second Contingency payments totaled $340K, down $1.1M from December – Commitments for NEMA on two days (January 9 and 10)

• Voltage payments totaled $26K, down $148K from December

– NCPC payments over the period as percent of Energy Market value were 0.9%

* Generator Performance Auditing (GPA) and Posturing are included in the First Contingency amount and totaled $132K and $44K, respectively.


ISO-NE PUBLIC 5

2016/17 Winter Reliability Program As of December 1, 2016 (unchanged since last month) • Oil Program

– As of December 1st, participation from 84 units for a total of 4.394 million barrels of oil

– 3.052 million barrels of the total inventory on December 1 are eligible for compensation per the winter program rules

– Total oil program cost exposure is expected to be $31.16M (@$10.21/barrel)

• LNG Program – As of December 1st, participation from 2 units, representing 171 thousand

MMBTU – Total LNG program cost exposure is expected to be $291K (@$1.70/MMBTU)

• DR Program – As of December 1st, participation from 6 assets providing 23.0 MW of

interruption capability – Total DR program cost exposure is anticipated to be $70.5K


ISO-NE PUBLIC 6

December 2016 Winter Program Usage (January 2017 usage will be available next week)

• Winter Program Oil Inventory Changes: – Dec 2016: 76,967 BBLs

• Winter Program LNG usage: – Dec 2016: none

• Winter Program DR Events: – Dec 2016: none


ISO-NE PUBLIC 7

Highlights, cont.

• Final preparations are being made for the eleventh Forward Capacity Auction (FCA #11), which is scheduled to begin on Monday, February 6

• 2016 Economic Study - NEPOOL Scenario Analysis – Phase I observations and key messages are complete

– Phase II is underway, reviewing certain market and operations impacts

• 2017 long-term load forecast, energy-efficiency forecast, and solar PV forecast are all under development – ISO staff will be working with the relevant working groups and then

presenting results at the March PAC meeting


ISO-NE PUBLIC 8

Forward Capacity Market (FCM) Highlights

CCP – Capacity Commitment Period RTEG – Real-Time Emergency Generation ICR – Installed Capacity Requirement COS – Capacity Supply Obligation

• CCP #8 (2017-2018) – ICR and related values were filed with FERC on December 1 and

approved by FERC on January 9 – Third and final bilateral window closed, results were posted on

January 11, and all transactions were accepted • Approximately 183 MW of RTEG resources shed their CSO, leaving only

6 MW of CSO remaining • First bilateral in which seasonal bilaterals were received

– Third and final reconfiguration auction will be March 1-3


ISO-NE PUBLIC 9

FCM Highlights, cont. • CCP #9 (2018-2019)

– Second bilateral window will be May – Second reconfiguration auction will be August

• CCP #10 (2019-2020) – First bilateral transaction window will be April – First reconfiguration auction will be June

• CCP #11 (2020-2021) – Forward Capacity Auction #11 to commence on February 6

• CCP #12 (2021-2022) – Preparations for qualification have begun and training dates are set – On February 24, the ISO will notify existing resource qualifications of

their values – Retirement de-list bids and permanent de-list bids are due March 24 – Show of Interest window will be April 14-28


ISO-NE PUBLIC 10

FERC Order 1000

• Intraregional Planning – Several parties have submitted information to be considered as

Qualified Transmission Project Sponsors, and 13 companies have been approved

– Public Policy process was initiated on January 11


ISO-NE PUBLIC 11

Highlights, cont. • The lowest 50/50 and 90/10 Winter Operable Capacity Margin

Week is projected for week beginning February 4, 2017.

• The lowest 50/50 and 90/10 Spring Operable Capacity Margin Week is projected for week beginning May 13, 2017.


ISO-NE PUBLIC ISO-NE PUBLIC

SYSTEM OPERATIONS

12


ISO-NE PUBLIC

System Operations

13

Weather Patterns

Boston Temperature: Above Normal (5.0°F) Max: 61°F, Min: 11°F Precipitation: 3.81” – Normal Normal: 3.80” Snow: 6.85”

Hartford Temperature: Above Normal (5.4°F) Max: 56°F, Min: 1°F Precipitation: 3.07” - Below Normal Normal: 3.73” Snow: 4.96”

Peak Load: 19,587 MW Jan 9, 2017 18:00 (ending)

MLCC2: None

OP-4 : None

NPCC Simultaneous Activation of Reserve Events:

Date Area MW

1/12 ISO-NE 1500

1/17 ISO-NE 650

1/25 ISO-NE 750

1/26 NBSO 378


ISO-NE PUBLIC

System Operations

14

Minimum Generation Warnings & Events:

None


ISO-NE PUBLIC

Month J F M A M J J A S O N D AvgMo Avg 1.54 1.54Day Max 4.58 4.58Day Min 0.33 0.33

Summer Goal 2.60 2.60 2.60Rest 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 1.54 1.54Summer Actual

2017 System Operations - Load Forecast Accuracy Dashboard Indicator

Rest of Year Goal < 1.5% Summer Goal < 2.6%

15


ISO-NE PUBLIC

Month J F M A M J J A S O N D AvgMo Avg 1.43 1.43Day Max 4.41 4.41Day Min 0.01 0.01

Summer Goal 2.60 2.60 2.60Rest 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 1.43 1.43Summer Actual

2017 System Operations - Load Forecast Accuracy cont. Dashboard Indicator

Rest of Year Goal < 1.5% Summer Goal < 2.6%

16


ISO-NE PUBLIC

J F M A M J J A S O N D AvgAbove % 53.3 53Below % 46.7 47Avg Above 168.3 168Avg Below -156.1 -156Avg All 21 21

2017 System Operations - Load Forecast Accuracy cont. Target = 50% Plus/Minus = 5%

17


ISO-NE PUBLIC

2017 System Operations - Load Forecast Accuracy cont.

18


ISO-NE PUBLIC

GR:wnnel GR:nel

Ann Tot (TWh): 127.1 125.8 124.0 .

Weather Normalized NEL

2014 2015 2016 2017G

Wh

8,000

9,000

10,000

11,000

12,000

13,000

14,000

JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC

Ann Tot (TWh): 127.2 127.0 124.2 8.7

Net Energy for Load (NEL)

2014 2015 2016 2017

GW

h

7,000

8,000

9,000

10,000

11,000

12,000

13,000

14,000


Monthly Recorded Net Energy for Load (NEL) and Weather Normalized NEL

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.

19

Partial


ISO-NE PUBLIC

GR:PeakEnergy GR:SeasonalPeak

System Peak Load

2014 2015 2016 2017

MW

14,000

16,000

18,000

20,000

22,000

24,000

26,000

28,000


Weather Normalized Seasonal Peaks

Winter beginning in year displayed

Summer Winter

MW

19,000

20,000

21,000

22,000

23,000

24,000

25,000

26,000

27,000

28,000

29,000

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Monthly Peak Loads and Weather Normalized Seasonal Peak History

F – designates forecasted values, which are updated in April/May of the following year; represents “net forecast” (i.e., the gross forecast net of passive demand response and behind-the-meter solar demand)

F

20

F

*Revenue quality metered value


ISO-NE PUBLIC

10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160

Horizon [Hours Ahead]

0

5

10

15

20

25

30

35

40

45

50

Mea

n A

bsol

ute

Err

or [%

]

Rolling 30-day MAE for ISO Wind Power Forecast, as of January 29, 2017

Individual Wind Plants

Fleet

Dashboard Indicator

Wind Power Forecast Error Statistics: Medium and Long Term Forecasts MAE

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/DNV-GL forecast is very good compared to industry standards, and monthly MAE is mostly within the yearly performance targets.

Yearly Fleet Performance targets

21


ISO-NE PUBLIC

10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160

Horizon [Hours Ahead]

-30

-20

-10

0

10

20

30

Bia

s E

rror

[%]

Rolling 30-day Bias for ISO Wind Power Forecast, as of January 29, 2017


Fleet

Wind Power Forecast Error Statistics: Medium and Long Term Forecasts Bias

Dashboard Indicator

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/DNV-GL forecast compares well with industry standards, and monthly Bias is mostly within yearly performance targets.


22


ISO-NE PUBLIC

10 30 50 70 90 110 130 150 170 190 210 230

Horizon [Minutes Ahead]

0

5

10

15

20

25

30

35

40

45

50

Mea

n A

bsol

ute

Err

or [%

]

Rolling 30-day MAE for ISO Wind Power Forecast, as of January 29, 2017


Fleet

Wind Power Forecast Error Statistics: Short Term Forecast MAE

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/DNV-GL forecast is very good compared to industry standards, and monthly MAE is within the yearly performance targets out to two hours ahead.

Dashboard Indicator


23


ISO-NE PUBLIC

10 30 50 70 90 110 130 150 170 190 210 230

Horizon [Minutes Ahead]

-30

-20

-10

0

10

20

30

Bia

s E

rror

[%]

Rolling 30-day Bias for ISO Wind Power Forecast, as of January 29, 2017


Fleet

Wind Power Forecast Error Statistics: Short Term Forecast Bias

Dashboard Indicator

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/DNV-GL forecast compares well with industry standards, and monthly Bias is within yearly performance targets.


24



MARKET OPERATIONS

25


ISO-NE PUBLIC

GR:Hubwgas

Elec

tric

ity P

rices

($/M

Wh)

$0.00

$30.00

$60.00

$90.00

$120.00

$150.0001/0

1/17

01/03/1

7

01/05/1

7

01/07/1

7

01/09/1

7

01/11/1

7

01/13/1

7

01/15/1

7

01/17/1

7

01/19/1

7

01/21/1

7

01/23/1

7

01/25/1

7

Fuel

Pric

e ($

/MM

Btu)

$0.00

$6.00

$12.00

$18.00

$24.00

$30.00

Gas price is average of Massachusetts delivery pointsAverage percentage difference over this period ABS(DA-RT)/RT Average LMP: 16%

Average price difference over this period ABS(DA-RT): $5.98Average price difference over this period (DA-RT): $3.67

RT LMP DA LMP Natural Gas

Daily Average DA and RT ISO-NE Hub Prices and Input Fuel Prices: January 1-25, 2017


26



ISO-NE PUBLIC

GR:DA_Bar

LMP Congestion Marginal Losses

$/M

Wh

$-10

$0

$10

$20

$30

$40

$50

$60

$70

$80

Hub ME NH VT CT RI SEMA WCMA NEMA

( 2.0%) ( 0.7%) ( 1.6%) ( 0.6%) ( 0.4%) ( 0.4%) 0.1% ( 0.2%)

DA LMPs Average by Zone & Hub, January 2017

ME - Maine NH – New Hampshire VT – Vermont CT – Connecticut

RI – Rhode Island SEMA – Southeastern Massachusetts WCMA – Western/Central Massachusetts NEMA – Northeastern Massachusetts

27


ISO-NE PUBLIC

GR:RT_Bar

LMP Congestion Marginal Losses

$/M

Wh

$-10

$0

$10

$20

$30

$40

$50

$60

$70

$80


( 3.1%) ( 0.9%) ( 2.3%) ( 0.6%) ( 0.4%) ( 0.3%) 0.0% 0.3%

RT LMPs Average by Zone & Hub, January 2017

28


ISO-NE PUBLIC

Definitions

Day-Ahead Concept Definition

Day-Ahead Load Obligation (DALO)

The sum of day-ahead cleared load (including asset load, pump load, exports,

and virtual purchases and excluding modeled transmission losses)

Day-Ahead Cleared Physical Energy The sum of day-ahead cleared generation and cleared net imports

29


ISO-NE PUBLIC

GR:Graph36R GR:Graph36L

Fixed Dem PrSens Dem DecsLosses Exports

Avg

Hou

rly

MW

0

2,500

5,000

7,500

10,000

12,500

15,000

17,500

20,000

22,500

NOV2016 DEC2016 JAN2017

Gen ImportsIncs

Avg

Hou

rly

MW

0

2,500

5,000

7,500

10,000

12,500

15,000

17,500

20,000

22,500

NOV2016 DEC2016 JAN2017

Components of Cleared DA Supply and Demand – Last Three Months

DA Fcst Load

Demand

Act Load

Supply

Gen – Generation Incs – Increment Offers DA Fcst Load – Day-Ahead Forecast Load

Fixed Dem – Fixed Demand PrSens Dem – Price Sensitive Demand Decs – Decrement Bids Act Load – Actual Load

30


ISO-NE PUBLIC

GR:Graph37R GR:Graph37L

Load Exports

Avg

Hou

rly

MW

0

2,500

5,000

7,500

10,000

12,500

15,000

17,500

20,000

22,500

NOV2016 DEC2016 JAN2017

Gen Imports

Avg

Hou

rly

MW

0

2,500

5,000

7,500

10,000

12,500

15,000

17,500

20,000

22,500

NOV2016 DEC2016 JAN2017

Components of RT Supply and Demand – Last Three Months

Supply

DA Fcst Load

Demand

31


ISO-NE PUBLIC

DAM Volumes as % of RT Actual Load (Peak Hour)

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.

32

60%

70%

80%

90%

100%

110%

120%

130%

140%

Jan-

16

Feb-

16

Mar

-16

Apr-

16

May

-16

Jun-

16

Jul-1

6

Aug-

16

Sep-

16

Oct

-16

Nov

-16

Dec-

16

Jan-

17

% o

f RT

Act

ual L

oad

DA Bid FixedDA Bid PriceDALO

60%

70%

80%

90%

100%

110%

120%

130%

140%

1-Ja

n2-

Jan

3-Ja

n4-

Jan

5-Ja

n6-

Jan

7-Ja

n8-

Jan

9-Ja

n10

-Jan

11-Ja

n12

-Jan

13-Ja

n14

-Jan

15-Ja

n16

-Jan

17-Ja

n18

-Jan

19-Ja

n20

-Jan

21-Ja

n22

-Jan

23-Ja

n24

-Jan

25-Ja

n

% o

f RT

Actu

al Lo

ad

DA Bid Fixed DA Bid PriceDALO DA Phys Clrd Energy100%


ISO-NE PUBLIC

GR:Graph26 GR:Graph27

DA

% o

f RT

96.6% 96.8%

97.0% 97.2%

97.4% 97.6% 97.8%

98.0% 98.2%

98.4% 98.6% 98.8%

99.0% 99.2%

99.4%

JAN20

16FE

B2016

MAR20

16APR

2016

MAY2

016

JUN20

16JU

L201

6AUG20

16SE

P201

6OCT

2016

NOV2016

DEC20

16JA

N2017

Monthly, Last 13 Months

DA

% o

f RT

94%

95%

96%

97%

98%

99%

100%

101%

102%

103%

104%

105%

106%

1/ 1

1/ 2

1/ 3

1/ 4

1/ 5

1/ 6

1/ 7

1/ 8

1/ 9

1/10

1/11

1/12

1/13

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1/20

1/21

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1/24

1/25

1/26

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1/28

1/29

1/30

1/31

Daily, This Year vs. Last Year

Last_Year This_Year

DA vs. RT Load Obligation: January, This Year vs. Last Year

*Hourly average values

33


ISO-NE PUBLIC

GR:dapce_dalo_pct_fxlo_fpk_dly_small GR:dapce_dalo_pct_fxlo_fpk_mly_small

Perc

enta

ge o

f Pea

k For

ecas

t Loa

d 80.0%

84.0%

88.0%

92.0%

96.0%

100%

104%

108%

112%

01JAN17

02JAN17

03JAN17

04JAN17

05JAN17

06JAN17

07JAN17

08JAN17

09JAN17

10JAN17

11JAN17

12JAN17

13JAN17

14JAN17

15JAN17

16JAN17

17JAN17

18JAN17

19JAN17

20JAN17

21JAN17

22JAN17

23JAN17

24JAN17

25JAN17

Daily: This Month

DA Cleared Physical Energy DALO100% line

Perc

enta

ge o

f Pea

k For

ecas

t Loa

d

93.0%

95.0%

97.0%

99.0%

101%

103%

105%

JAN2016

FEB2016

MAR2016

APR2016

MAY2016

JUN2016

JUL2016

AUG2016

SEP2016

OCT2016

NOV2016

DEC2016

JAN2017


DA Cleared Physical Energy DALO100% line

DA Volumes as % of Forecast (Peak Hour)

*Forecasted peak hour is reflected.

34


ISO-NE PUBLIC

GR:dapce_delta_fpk_dly_bar

MW

h

-3,000

-2,500

-2,000

-1,500

-1,000

-500

0

500

1,000

1,500

01JAN2017

02JAN2017

03JAN2017

04JAN2017

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06JAN2017

07JAN2017

08JAN2017

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10JAN2017

11JAN2017

12JAN2017

13JAN2017

14JAN2017

15JAN2017

16JAN2017

17JAN2017

18JAN2017

19JAN2017

20JAN2017

21JAN2017

22JAN2017

23JAN2017

24JAN2017

25JAN2017

DA Cleared Physical Energy Difference from RT System Load at Peak Hour*

*Negative values indicate DA Cleared Physical Energy value below its RT counterpart. Forecast peak hour reflected.

DA H

ighe

r

DA Lower

35


ISO-NE PUBLIC

GR:Graph32 GR:Graph33

Net

MW

h

0

500

1,000

1,500

2,000

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01JA

N16

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25JA

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N16

Hourly Average by Day, Last Year

Day-Ahead Real-TimeN

et M

Wh

0

500

1,000

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4,000

01JA

N17

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24JA

N17

25JA

N17

Hourly Average by Day, This Year

Day-Ahead Real-Time

DA vs. RT Net Interchange January 2017 vs. January 2016

Net Interchange is the sum of daily imports minus the sum of daily exports Positive values are net imports

36


ISO-NE PUBLIC

GR:Var_Cost_Gas_Mly

$0

$40

$80

$120

$160JA

N2015

FEB2

015

MAR2

015

APR20

15M

AY201

5JU

N2015

JUL2

015

AUG2015

SEP2

015

OCT20

15NOV20

15DEC

2015

JAN20

16FE

B201

6M

AR201

6APR

2016

MAY2

016

JUN20

16JU

L201

6AUG20

16SE

P201

6OCT

2016

NOV2016

DEC20

16JA

N2017

Var Cost Gas

Variable Production Cost of Natural Gas: Monthly

Note: Assumes proxy heat rate of 7,800,000 Btu/MWh for natural gas units.


37

$/M

Wh



ISO-NE PUBLIC

GR:Var_Cost_Gas_Dly

$0

$40

$80

$120

$16001

JAN20

1702

JAN20

1703

JAN20

1704

JAN20

1705

JAN20

1706

JAN20

1707

JAN20

1708

JAN20

1709

JAN20

1710

JAN20

1711

JAN20

1712

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1713

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1714

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1715

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1716

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1717

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1718

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1719

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1720

JAN20

1721

JAN20

1722

JAN20

1723

JAN20

1724

JAN20

1725

JAN20

17

Var Cost Gas

Variable Production Cost of Natural Gas: Daily

Note: Assumes proxy heat rate of 7,800,000 Btu/MWh for natural gas units.


38

$/M

Wh



ISO-NE PUBLIC

GR:DA_Hrly

$/M

Wh

$-100

$-50

$0

$50

$100

$150

$200

$250

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26

Hourly Day-Ahead LMPs

Hub ME NH VT CTRI SEMA NEMA WCMA

Hourly DA LMPs, January 1-25, 2017

39


ISO-NE PUBLIC

GR:RT_Hrly

$/M

Wh

$-100

$-50

$0

$50

$100

$150

$200

$250

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26

Hourly Real-Time LMPs

Hub ME NH VT CTRI SEMA NEMA WCMA

Hourly RT LMPs, January 1-25, 2017

40

* No Minimum Generation Emergencies were declared in December.

Tight capacity with binding reserve constraints during the morning pickup

Binding NEMA reserve constraints over evening peak


ISO-NE PUBLIC 41

System Unit Availability

Data as of 1/27/17

60

65

70

75

80

85

90

95

100

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual

Syst

em W

EAF

Annual/Monthly Weighted Equivalent Availability Factor (WEAF)

2015 2016 2017

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec YTD2017 91 912016 93 94 89 82 78 90 95 96 91 77 85 90 882015 97 89 88 84 80 94 96 96 88 74 79 91 88



BACK-UP DETAIL

42



LOAD RESPONSE

43


ISO-NE PUBLIC

Capacity Supply Obligation (CSO) MW by Demand Resource Type for February 2017

44

* Real Time Demand Response ** Real Time Emergency Generation NOTE: CSO values include T&D loss factor (8%).

Load Zone RTDR* RTEG** On Peak Seasonal

Peak Total ME 65.3 0.0 129.7 0.0 194.9 NH 9.9 0.0 70.7 0.0 80.6 VT 31.1 0.0 106.6 0.0 137.7 CT 70.4 1.1 59.8 355.4 486.7 RI 7.0 0.0 178.0 0.0 185.0

SEMA 11.1 0.0 257.8 0.0 268.9 WCMA 27.6 0.0 230.7 51.4 309.8 NEMA 31.5 0.0 497.4 0.0 528.9

Total 253.9 1.1 1,530.6 406.9 2,192.5



NEW GENERATION

45


ISO-NE PUBLIC

New Generation Update Based on Queue as of 1/30/17

• No new projects have applied for interconnection study since the last update

• Two projects withdrew from the queue and one project went commercial, resulting in a net decrease in new generation projects of 490 MW

• In total, 75 generation projects are currently being tracked by the ISO, totaling approximately 12,900 MW

46


ISO-NE PUBLIC

• 2017 values include the 16 MW of generation that went commercial in 2017 • DR reflects changes from the initial FCM Capacity Supply Obligations in 2010-11

Actual and Projected Annual Capacity Additions By Supply Fuel Type and Demand Resource Type

47

-1,000

0

1,000

2,000

3,000

4,000

5,000

6,000

2017 2018 2019 2020 2021 2022 2023

Meg

awat

ts (M

W)

Demand Response -Passive

Demand Reponse -Active

Wind/OtherRenewables

Oil

Natural Gas/Oil

Natural Gas

2017 2018 2019 2020 2021 2022 2023 Total MW

% of Total1

Demand Response - Passive 330 196 212 0 0 0 0 738 5.7Demand Response - Active -37 -433 -270 0 0 0 0 -739 -5.7Wind & Other Renewables 360 658 2,681 1,216 800 0 800 6,515 50.3Oil 0 0 0 0 0 0 0 0 0.0Natural Gas/Oil2 74 1,519 904 1,757 0 0 0 4,254 32.9Natural Gas 808 189 1,183 0 0 0 0 2,180 16.8Totals 1,535 2,129 4,711 2,973 800 0 800 12,947 100.01 Sum may not equal 100% due to rounding2 The projects in this category are dual fuel, w ith either gas or oil as the primary fuel


ISO-NE PUBLIC

Actual and Projected Annual Generator Capacity Additions By State

• 2017 values reflect the 16 MW of generation that went commercial in 2017

48

0

1,000

2,000

3,000

4,000

5,000

6,000

2017 2018 2019 2020 2021 2022 2023

Meg

awat

ts (M

W)

Vermont

Rhode Island

New Hampshire

Maine

Massachusetts

Connecticut

2017 2018 2019 2020 2021 2022 2023 Total MW

% of Total1

Vermont 42 30 0 0 0 0 0 72 0.6Rhode Island 60 0 1,268 0 0 0 0 1,328 10.3New Hampshire 102 65 28 5 0 0 0 200 1.5Maine 197 566 2,553 1,145 0 0 0 4,461 34.5Massachusetts 741 224 746 128 800 0 800 3,439 26.6Connecticut 100 1,481 173 1,695 0 0 0 3,449 26.6Totals 1,242 2,366 4,768 2,973 800 0 800 12,949 100.01 Sum may not equal 100% due to rounding


ISO-NE PUBLIC

•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

New Generation Projection By Fuel Type

49

Fuel TypeNo. of

ProjectsCapacity

(MW)No. of

ProjectsCapacity

(MW)No. of

ProjectsCapacity

(MW)

Biomass/Wood Waste 2 112 0 0 2 112

Hydro 4 103 0 0 4 103

Landfill Gas 1 2 0 0 1 2

Natural Gas 13 2,243 1 100 12 2,143

Natural Gas/Oil 12 4,254 2 1,009 10 3,245

Oil 0 0 0 0 0 0

Solar 13 745 0 0 13 745

Wind 28 5,397 1 23 27 5,374Battery Storage 2 77 0 0 2 77

Total 75 12,933 4 1,132 71 11,801

Total Green Yellow


ISO-NE PUBLIC

• 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

New Generation Projection By Operating Type

50

Operating TypeNo. of

ProjectsCapacity

(MW)No. of

ProjectsCapacity

(MW)No. of

ProjectsCapacity

(MW)

Baseload 5 182 0 0 5 182

Intermediate 18 5,422 1 801 17 4,621

Peaker 24 1,932 2 308 22 1,624Wind Turbine 28 5,397 1 23 27 5,374

Total 75 12,933 4 1,132 71 11,801

Total Green Yellow


ISO-NE PUBLIC

New Generation Projection By Operating Type and Fuel Type

• Projects in the Natural Gas/Oil category may have either gas or oil as the primary fuel

51

Fuel TypeNo. of

ProjectsCapacity

(MW)No. of

ProjectsCapacity

(MW)No. of

ProjectsCapacity

(MW)No. of

ProjectsCapacity

(MW)No. of

ProjectsCapacity

(MW)

Biomass/Wood Waste 2 112 2 112 0 0 0 0 0 0

Hydro 4 103 1 5 2 32 1 66 0 0

Landfill Gas 1 2 1 2 0 0 0 0 0 0

Natural Gas 13 2,243 1 63 9 1,991 3 189 0 0

Natural Gas/Oil 12 4,254 0 0 7 3,399 5 855 0 0

Oil 0 0 0 0 0 0 0 0 0 0

Solar 13 745 0 0 0 0 13 745 0 0

Wind 28 5,397 0 0 0 0 0 0 28 5,397Battery Storage 2 77 0 0 0 0 2 77 0 0

Total 75 12,933 5 182 18 5,422 24 1,932 28 5,397

Wind TurbineBaseload Intermediate PeakerTotal



FORWARD CAPACITY MARKET

52


ISO-NE PUBLIC 53

Capacity Supply Obligation FCA 6

* 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.

Resource Type

Resource Type

FCA Proration Annual Bilateral for

ARA 1 ARA 1 Annual Bilateral for

ARA 2 ARA 2 Annual Bilateral for ARA 3 ARA 3

*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

Demand

Active Demand

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

Passive Demand

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 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

Generator

Non-Intermittent

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 28,881.019 153.859 28,971.511 90.492

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

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 29,658.943 111.043 29,725.612 66.669

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

***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 33,480.112 -10.208 33,388.5 -91.612

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


ISO-NE PUBLIC 54





Resource Type

Resource Type

FCA Proration Annual Bilateral for

ARA 1 ARA 1 Annual Bilateral

for ARA 2 ARA 2 Annual Bilateral for

ARA 3 ARA 3

*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

Demand

Active Demand 1,116.698 1,043.719 -72.979 944.27 -99.45 932.721 -11.549 781.206 -151.52 671.28 -109.926 575.63 -95.65 556.453 -19.177

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 1,607.705 63.586 1,884.902 277.197

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 2,183.335 -32.064 2,441.355 258.02

Generator

Non-Intermittent

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 28,948.677 157.546 29,152.793 204.116

Intermittent 936.913 893.710 -43.203 903.244 9.53 913.083 9.839 838.626 -74.46 824.833 -13.793 800.286 -24.547 735.174 -65.112

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 29,748.963 132.999 29,887.967 139.004

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 1,440.401 -136 1,162.202 -278.199

***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 33,372.699 -35.065 33,491.524 118.825

Net ICR (NICR) 32,968 32,968 0

33,529

561

33,529

0 33,529 0.00 33,529 0 33,152 -377

33,152

0


ISO-NE PUBLIC 55





Resource Type

Resource Type

FCA Annual Bilateral for



ARA 3 ARA 3

*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

Demand

Active Demand 1,080.079 887.493 -192.59 891.604 4.111 772.352 -119.252 601.852 -170.5 400.487 -201.365

Passive Demand 1,960.517 1,958.874 -1.64 1,956.663 -2.211 2025.383 68.72 2,036.906 11.523 2,112.758 75.852

Demand Total 3,040.596 2,846.367 -194.23 2,848.267 1.9 2,797.735 -50.532 2,638.758 -158.977 2,513.245 -125.513

Generator

Non-Intermittent

28,547.813 28,523.796 -24.02 28,666.87 143.074 28,658.35 -8.52 28,863.752 205.402 28,888.84 25.092

Intermittent 876.925 898.955 22.03 922.173 23.218 918.782 -3.391 920.037 1.255 916.51 -3.527

Generator Total 29,424.738 29,422.751 -1.99 29,589.043 166.292 29,577.132 -11.911 29,783.789 206.657 29,805.35 21.565

Import Total 1,237.034 1,237.034 0.00 1,375.53 138.496 1,375.53 0 1314.43 -61.1 1,394.43 80

***Grand Total 33,702.368 33,506.152 -196.22 33,812.84 306.688 33,750.397 -62.443 33,736.977 -13.417 33,713.03 -23.948

Net ICR (NICR) 33,855 34,061 206.00 34,061 0 34,061 0 34,061 0 33,138 -923


ISO-NE PUBLIC 56





Resource Type

Resource Type

FCA Annual Bilateral for



ARA 3 ARA 3



Demand

Active Demand 647.26 596.701 -50.559 553.857 -42.844

Passive Demand 2,156.151 2153.94 -2.211 2150.196 -3.744

Demand Total 2,803.411 2,750.641 -52.77 2,704.053 -46.588

Generator

Non-Intermittent

29,550.564 29,558.181 7.617 29,783.831 225.65

Intermittent 891.616 864.924 -26.692 872.425 7.501

Generator Total 30,442.18 30,423.105 -19.075 30,656.256 233.151

Import Total 1,449 1449 0 1449 0

***Grand Total 34,694.591 34622.746 -71.845 34,809.309 186.563

Net ICR (NICR) 34,189 33,883 -306

33,883

0


ISO-NE PUBLIC 57





Resource Type

Resource Type

FCA Annual Bilateral

for ARA 1 ARA 1 Annual Bilateral for


ARA 3 ARA 3



Demand

Active Demand 377.525

Passive Demand 2,368.631

Demand Total 2,746.156

Generator

Non-Intermittent

30,520.433

Intermittent 850.143

Generator Total 31,370.576

Import Total 1,449.8

***Grand Total 35,566.532

Net ICR (NICR) 34,151


ISO-NE PUBLIC

Active/Passive Demand Response CSO Totals by Commitment Period

58

Commitment Period Active/ Passive Existing New Grand Total

2010-11 Active 1246.399 603.675 1850.074

Passive 119.211 584.277 703.488 Grand Total 1365.61 1187.952 2553.562

2011-12 Active 1768.392 184.99 1953.382


2012-13 Active 1726.548 98.227 1824.775


2013-14 Active 1794.195 257.341 2051.536


2014-15 Active 2062.196 41.945 2104.141


2015-16 Active 1935.406 66.104 2001.51


2016-17 Active 1116.468 0.23 1116.698


2017-18 Active 1066.593 13.486 1080.079 Passive 1619.147 341.37 1960.517

Grand Total 2685.74 354.856 3040.596

2018-19 Active 565.866 81.394 647.26


2019-20 Active 357.221 20.304 377.525




RELIABILITY COSTS – NET COMMITMENT PERIOD COMPENSATION (NCPC) OPERATING COSTS

59


ISO-NE PUBLIC

What are Daily NCPC Payments?

• Payments made to resources whose 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 during 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

• NCPC payments are intended to make a resource that follows the ISO’s operating instructions “no worse off” financially than the best alternative generation schedule

60


ISO-NE PUBLIC

Definitions

1st Contingency NCPC Payments

Reliability costs paid to eligible resources that are providing first contingency (1stC) protection (including low voltage, system operating reserve, and load serving) either system-wide or locally

2nd Contingency NCPC Payments

Reliability costs paid to resources providing capacity in constrained areas to 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 Payments

Reliability costs paid to units dispatched at the request of local transmission providers for purpose of managing constraints on the low voltage (distribution) system. These requirements are not modeled in the DA Market software

OATT Open Access Transmission Tariff

61


ISO-NE PUBLIC

Charge Allocation Key

Allocation Category

Market / OATT Allocation

System 1st Contingency

Market

DA 1st C (excluding at external nodes) is allocated to system DALO. 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 Contingency

Market

DA 1st C at external nodes (from imports, exports, Incs and Decs) are allocated to activity at the specific external node or interface involved

Zonal 2nd Contingency

Market DA and RT 2nd C NCPC are allocated to load obligation in the Reliability Region (zone) served

System Low Voltage

OATT (Low) Voltage Support NCPC is allocated to system Regional Network Load and Open Access Same-Time Information Service (OASIS) reservations

Zonal High Voltage

OATT

High Voltage Control NCPC is allocated to zonal Regional Network Load

Distribution - PTO OATT

Distribution NCPC is allocated to the specific Participant Transmission Owner (PTO) requesting the service

System – Other Market Includes GPA and Generator/DARD Posturing NCPC (allocated to RTLO) and Min Generation Emergency NCPC (allocated to RTGO).

62


ISO-NE PUBLIC

GR:Graph23 GR:Graph23m NCPC Dollars

2014 20152016 2017

Mill

ions

$0

$10

$20

$30

$40

$50

$60

$70

$80


NCPC Energy*

2014 20152016 2017

GW

h 0

100

200

300

400

500

600

700

800

900

1,000

1,100


Year-Over-Year Total NCPC Dollars and Energy

* 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.

63


ISO-NE PUBLIC

GR:Graph01 GR:Graph02 JAN-17 Total = $3.33 M

Day-Ahead Real-Time

48%

52%

Last 13 Months

Day-Ahead Real-Time

Mill

ions

$0

$10

$20

$30

$40

$50

JAN20

16FE

B2016

MAR20

16APR

2016

MAY2

016

JUN20

16JU

L201

6AUG20

16SE

P201

6OCT

2016

NOV2016

DEC20

16JA

N2017

DA and RT NCPC Charges

64


ISO-NE PUBLIC

GR:Graph04 GR:Graph03 JAN-17 Total = $3.33 M

1st C 2nd CVoltage

89%

10%

1%

NCPC Charges by Type

1st C – First Contingency 2nd C – Second Contingency Distrib – Distribution Voltage – Voltage

65

Last 13 Months

1st C 2nd CVoltage Distrib

Mill

ions

$0

$10

$20

$30

$40

$50

JAN16

FEB16

MAR16

APR16

MAY1

6JU

N16JU

L16

AUG16SE

P16

OCT16

NOV16DEC

16JA

N17


ISO-NE PUBLIC

GR:ncpc_bytype_stack_dly

1st C 2nd C Voltage Distribution

Thou

sand

$0

$100

$200

$300

$400

$500

$600

$70001

JAN20

1702

JAN20

1703

JAN20

1704

JAN20

1705

JAN20

1706

JAN20

1707

JAN20

1708

JAN20

1709

JAN20

1710

JAN20

1711

JAN20

1712

JAN20

1713

JAN20

1714

JAN20

1715

JAN20

1716

JAN20

1717

JAN20

1718

JAN20

1719

JAN20

1720

JAN20

1721

JAN20

1722

JAN20

1723

JAN20

1724

JAN20

1725

JAN20

17

Daily NCPC Charges by Type

66


ISO-NE PUBLIC

GR:xchart_ncpc_chgs_alloc_cat GR:xpie_ncpc_chgs_alloc_cat Last 13 Months

System 1stC Ext DA 1stCZonal 2ndC System Low VZonal High V Dist - PTOSystem Other

Mill

ions

$0.0

$8.0

$16.0

$24.0

$32.0

$40.0

JAN16

FEB16

MAR16

APR16

MAY1

6JU

N16JU

L16

AUG16SE

P16

OCT16

NOV16DEC

16JA

N17

JAN-17 Total = $3.33 M

System 1stC Ext DA 1stCZonal 2ndC System Low VZonal High V Dist - PTOSystem Other

84%

0.0%

10%

0.8%0.0%0.0%

5.3%

NCPC Charges by Allocation

67

Note: ‘System Other’ includes, as applicable: Resource Posturing, GPA, and Min Gen Emergency

0.8%

0.8%

5%

0.8%


ISO-NE PUBLIC

GR:chart_firstc_rt_bydev_13mo GR:pie_firstc_rt_bydev JAN-17 Total = $1.36 M

Gen ImportInc Load

10.8%

7.2%17.3%

64.7%

RT First Contingency Charges by Deviation Type

Gen – Generator deviations Inc – Increment Offer deviations Imp – Import deviations Load – Load obligation deviations

68

Last 13 Months

Gen ImportInc Load

Mill

ions

$0

$1

$2

$3

$4

$5

$6

JAN16

FEB16

MAR16

APR16

MAY1

6JU

N16JU

L16

AUG16SE

P16

OCT16

NOV16DEC

16JA

N17


ISO-NE PUBLIC

GR:lscpr_charges_byzone_13mo

CT ME NEMA NHRI SEMA VT WCMA

Mill

ions

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

$8.0

$9.0

$10.0

$11.0

$12.0

$13.0

JAN16

FEB16

MAR16

APR16

MAY16

JUN16

JUL1

6

AUG16

SEP16

OCT16

NOV16

DEC16

JAN17

LSCPR Charges by Zone

CT – Connecticut Region ME – Maine Region NH – New Hampshire Region RI – Rhode Island Region VT – Vermont Region

SEMA – Southeast Massachusetts Region WCMA – Western/Central Massachusetts Region NEMA – Northeast Massachusetts Region EXT – External Locations

69


ISO-NE PUBLIC

GR:var_charges_stack_13mo

DA HV NCPC DA LV NCPC RT HV NCPC RT LV NCPC

Thou

sand

$0.0

$100.0

$200.0

$300.0

$400.0

JAN16

FEB16

MAR16

APR16

MAY16

JUN16

JUL1

6

AUG16

SEP16

OCT16

NOV16

DEC16

JAN17

NCPC Charges for Voltage Support and High Voltage Control

70


ISO-NE PUBLIC

GR:NCPC_Stack Value of Charges

1st C 2nd C Distr Voltg

Mill

ions

$0

$25

$50

$75

$100

$125

$150

$1752015

2016

2017

JAN2017

FEB2017

MAR2017

APR2017

MAY2017

JUN2017

JUL2

017

AUG2017

SEP2017

OCT2017

NOV2017

DEC2017

$11

8.1

$73

.1

$3.

3

$3.

3

NCPC Charges by Type

71


ISO-NE PUBLIC

GR:NCPC_pct_Stack NCPC By Type as Percent of Energy Market

1st C 2nd C Distr Voltg

Perc

ent

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%2015

2016

2017

JAN2017

FEB2017

MAR2017

APR2017

MAY2017

JUN2017

JUL2

017

AUG2017

SEP2017

OCT2017

NOV2017

DEC2017

2.0

%

1.8

%

0.9

%

0.9

%

NCPC Charges as Percent of Energy Market

72


ISO-NE PUBLIC

GR:Graph19 GR:Graph20 Value of Charges

Mill

ions

$0

$20

$40

$60

$80

$100

$120

$140

2015

2016

2017

JAN2

017

FEB2

017

MAR

2017

APR2

017

MAY

2017

JUN2

017

JUL2

017

AUG2

017

SEP2

017

OCT2

017

NOV2

017

DEC2

017

$70

.0

$40

.4

$3.

0

$3.

0% of Energy Market Value

0.0%

1.0%

2.0%

3.0%

4.0%

2015

2016

2017

JAN2

017

FEB2

017

MAR

2017

APR2

017

MAY

2017

JUN2

017

JUL2

017

AUG2

017

SEP2

017

OCT2

017

NOV2

017

DEC2

017

1.2

%

1.0

%

0.8

%

0.8

%

First Contingency NCPC Charges

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

73


ISO-NE PUBLIC

GR:Graph21 GR:Graph22 Value of Charges

Mill

ions

$0

$10

$20

$30

$40

$50

2015

2016

2017

JAN2

017

FEB2

017

MAR

2017

APR2

017

MAY

2017

JUN2

017

JUL2

017

AUG2

017

SEP2

017

OCT2

017

NOV2

017

DEC2

017

$42

.7

$31

.1

$0.

3

$0.

3% of Energy Market Value

0.0%

1.5%

3.0%

4.5%

6.0%

2015

2016

2017

JAN2

017

FEB2

017

MAR

2017

APR2

017

MAY

2017

JUN2

017

JUL2

017

AUG2

017

SEP2

017

OCT2

017

NOV2

017

DEC2

017

0.7

%

0.8

%

0.1

%

0.1

%

Second Contingency NCPC Charges


74


ISO-NE PUBLIC

GR:Graph18 GR:Graph17 % of Energy Market Value

0.0%

1.0%

2.0%

3.0%

4.0%

2015

2016

2017

JAN2

017

FEB2

017

MAR

2017

APR2

017

MAY

2017

JUN2

017

JUL2

017

AUG2

017

SEP2

017

OCT2

017

NOV2

017

DEC2

017

0.1

%

0.0

%

0.0

%

0.0

%

Value of Charges

Mill

ions

$0

$10

$20

$30

$40

2015

2016

2017

JAN2

017

FEB2

017

MAR

2017

APR2

017

MAY

2017

JUN2

017

JUL2

017

AUG2

017

SEP2

017

OCT2

017

NOV2

017

DEC2

017

$5.

4

$1.

5

$0.

0

$0.

0

Voltage and Distribution NCPC Charges


75


ISO-NE PUBLIC

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

76


ISO-NE PUBLIC

DA vs. RT LMPs ($/MWh)

77

Arithmetic Average Year 2015 NEMA CT ME NH VT RI SEMA WCMA Hub

Day-Ahead $42.56 $41.23 $40.81 $42.11 $41.58 $42.20 $42.23 $41.93 $41.90 Real-Time $41.58 $40.58 $39.23 $40.21 $40.22 $41.03 $41.21 $40.96 $41.00 RT Delta % -2.3% -1.6% -3.9% -4.5% -3.3% -2.8% -2.4% -2.3% -2.2% Year 2016 NEMA CT ME NH VT RI SEMA WCMA Hub

Day-Ahead $30.66 $29.77 $29.07 $29.64 $29.66 $29.66 $29.88 $29.85 $29.78 Real-Time $29.74 $29.00 $27.81 $28.60 $28.49 $28.87 $29.01 $28.98 $28.94 RT Delta % -3.0% -2.6% -4.3% -3.5% -3.9% -2.7% -2.9% -2.9% -2.8%

January-16 NEMA CT ME NH VT RI SEMA WCMA Hub Day-Ahead $38.63 $38.35 $37.21 $38.36 $38.40 $38.54 $38.73 $38.68 $38.60 Real-Time $34.13 $33.93 $32.36 $33.57 $33.53 $34.02 $34.15 $34.04 $33.99 RT Delta % -11.7% -11.5% -13.0% -12.5% -12.7% -11.7% -11.8% -12.0% -11.9% January-17 NEMA CT ME NH VT RI SEMA WCMA Hub Day-Ahead $41.13 $40.95 $40.41 $40.94 $40.55 $41.04 $41.05 $41.26 $41.22 Real-Time $37.65 $37.32 $36.39 $37.21 $36.69 $37.39 $37.42 $37.55 $37.54 RT Delta % -8.5% -8.9% -9.9% -9.1% -9.5% -8.9% -8.8% -9.0% -8.9%

Annual Diff. NEMA CT ME NH VT RI SEMA WCMA Hub Yr over Yr DA 6.5% 6.8% 8.6% 6.7% 5.6% 6.5% 6.0% 6.7% 6.8% Yr over Yr RT 10.3% 10.0% 12.4% 10.8% 9.4% 9.9% 9.6% 10.3% 10.4%


ISO-NE PUBLIC

GR:Graph25

Mar

ch 2

003=

1.00

0

0.000

1.000

2.000

3.000

MAR2003JU

N2003SEP2003DEC2003

MAR2004JU

N2004SEP2004DEC2004

MAR2005JU

N2005SEP2005DEC2005

MAR2006JU

N2006SEP2006DEC2006

MAR2007JU

N2007SEP2007DEC2007

MAR2008JU

N2008SEP2008DEC2008

MAR2009JU

N2009SEP2009DEC2009

MAR2010JU

N2010SEP2010DEC2010

MAR2011JU

N2011SEP2011DEC2011

MAR2012JU

N2012SEP2012DEC2012

MAR2013JU

N2013SEP2013DEC2013

MAR2014JU

N2014SEP2014DEC2014

MAR2015JU

N2015SEP2015DEC2015

MAR2016JU

N2016SEP2016DEC2016

MAR2017

Natural Gas Hub RT LMP

Monthly Average Fuel Price and RT Hub LMP Indexes


78



ISO-NE PUBLIC

GR:hubwgas_mly_smd

$/M

MBt

u (F

uel)

$0.00

$3.00

$6.00

$9.00

$12.00

$15.00

$18.00

$21.00

$24.00

$27.00

$30.00

MAR2003

JUN20

03SE

P200

3DEC

2003

MAR2004

JUN20

04SE

P200

4DEC

2004

MAR2005

JUN20

05SE

P200

5DEC

2005

MAR2006

JUN20

06SE

P200

6DEC

2006

MAR2007

JUN20

07SE

P200

7DEC

2007

MAR2008

JUN20

08SE

P200

8DEC

2008

MAR2009

JUN20

09SE

P200

9DEC

2009

MAR2010

JUN20

10SE

P201

0DEC

2010

MAR2011

JUN20

11SE

P201

1DEC

2011

MAR2012

JUN20

12SE

P201

2DEC

2012

MAR2013

JUN20

13SE

P201

3DEC

2013

MAR2014

JUN20

14SE

P201

4DEC

2014

MAR2015

JUN20

15SE

P201

5DEC

2015

MAR2016

JUN20

16SE

P201

6DEC

2016

MAR2017

$/M

Wh

(Ele

ctric

ity)

$0.00

$40.00

$80.00

$120.00

$160.00

$200.00

Natural Gas Hub RT LMP

Monthly Average Fuel Price and RT Hub LMP


79



ISO-NE PUBLIC

GR:three_pools_prices_dly GR:three_pools_prices_mly

Elec

tric

ity

Pric

es ($

/MW

h)

$10

$20

$30

$40

$50

$60

JAN20

16FE

B2016

MAR20

16APR

2016

MAY2

016

JUN20

16JU

L201

6AUG20

16SE

P201

6OCT

2016

NOV2016

DEC20

16JA

N2017


*Note: Hourly average prices are shown.

ISO-NE NY-ISO PJM

New England, NY, and PJM Hourly Average Real Time Prices by Month

80

Elec

tric

ity

Pric

es ($

/MW

h)

$20

$30

$40

$50

$60

$70

$80

01JA

N1702

JAN17

03JA

N1704

JAN17

05JA

N1706

JAN17

07JA

N1708

JAN17

09JA

N1710

JAN17

11JA

N1712

JAN17

13JA

N1714

JAN17

15JA

N1716

JAN17

17JA

N1718

JAN17

19JA

N1720

JAN17

21JA

N1722

JAN17

23JA

N1724

JAN17

25JA

N17

Daily: This Month

*Note: Hourly average prices are shown.

ISO-NE NY-ISO PJM


ISO-NE PUBLIC

GR:three_pools_prices_fpk_dly GR:three_pools_prices_fpk_mly

Elec

tric

ity

Pric

es ($

/MW

h)

$10 $20 $30 $40 $50 $60 $70 $80 $90

$100 $110 $120 $130 $140

01JA

N1702

JAN17

03JA

N1704

JAN17

05JA

N1706

JAN17

07JA

N1708

JAN17

09JA

N1710

JAN17

11JA

N1712

JAN17

13JA

N1714

JAN17

15JA

N1716

JAN17

17JA

N1718

JAN17

19JA

N1720

JAN17

21JA

N1722

JAN17

23JA

N1724

JAN17

25JA

N17

Daily: This Month

ISO-NE NY-ISO PJM

Elec

tric

ity

Pric

es ($

/MW

h)

$20

$30

$40

$50

$60

$70

$80

$90

$100

$110

JAN20

16FE

B2016

MAR20

16APR

2016

MAY2

016

JUN20

16JU

L201

6AUG20

16SE

P201

6OCT

2016

NOV2016

DEC20

16JA

N2017


ISO-NE NY-ISO PJM

New England, NY, and PJM Average Peak Hour Real Time Prices

*Forecasted New England daily peak hours reflected

81


ISO-NE PUBLIC 82

Reserve Market Results – January 2017 • Maximum potential Forward Reserve Market payments of

$2.3M were reduced by credit reductions of $22K, failure-to-reserve penalties of $36K and no failure-to-activate penalties, resulting in a net payout of $2.2M or 97% of maximum – Rest of System: $1.29M/1.33M (97)% – Southwest Connecticut: $0.22M/0.22M (99)% – Connecticut: $0.72M/0.73M (98)%

• $619K total Real-Time credits were reduced by $23K in Forward Reserve Energy Obligation Charges for a net of $597K in Real-Time Reserve payments – Rest of System: 145 hours, $341K – Southwest Connecticut: 145 hours, $81K – Connecticut: 145 hours, $65K – NEMA: 148 hours, $109K

* “Failure to reserve” results in both credit reductions and penalties in the Locational Forward Reserve Market.


ISO-NE PUBLIC

GR:Graph39 LFRM Charges by Zone, Last 13 Months

CT ME NEMA NHRI SEMA VT WCMA

Mill

ions

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

JAN16

FEB16

MAR16

APR16

MAY16

JUN16

JUL1

6

AUG16

SEP16

OCT16

NOV16

DEC16

JAN17

LFRM Charges to Load by Load Zone ($)

83

Partial


ISO-NE PUBLIC

GR:Graph28 January Monthly Totals by Zone

Cleared Offered

MW

h

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

110,000

120,000

130,000

140,000


2016

2017

2016

2017

2016

2017

2016

2017

2016

2017

2016

2017

2016

2017

2016

2017

2016

2017

Zonal Increment Offers and Cleared Amounts

84


ISO-NE PUBLIC

GR:Graph29 January Monthly Totals by Zone

Cleared Bid

MW

h

0

10,000

20,000

30,000

40,000

50,000

60,000


2016

2017

2016

2017

2016

2017

2016

2017

2016

2017

2016

2017

2016

2017

2016

2017

2016

2017

Zonal Decrement Bids and Cleared Amounts

85


ISO-NE PUBLIC

GR:Graph30 Zonal Level, Last 13 Months

Cleared Bid/Offered

MW

h

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

1,000,000

1,100,000

JAN

2016

FEB2

016

MAR

2016

APR2

016

MAY

2016

JUN

2016

JUL2

016

AUG

2016

SEP2

016

OCT

2016

NO

V201

6

DEC2

016

JAN

2017

INC

DEC

INC

DEC

INC

DEC

INC

DEC

INC

DEC

INC

DEC

INC

DEC

INC

DEC

INC

DEC

INC

DEC

INC

DEC

INC

DEC

INC

DEC

Total Increment Offers and Decrement Bids

Data excludes nodal offers and bids

86


ISO-NE PUBLIC

GR:Graph31 Total Monthly Energy; Dispatchable % Shown

Non-Dispatchable Dispatchable

GWh

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

JAN2016

FEB2016

MAR2016

APR2016

MAY2016

JUN2016

JUL2

016

AUG2016

SEP2016

OCT2016

NOV2016

DEC2016

JAN2017

45.

2%

41.

1%

40.

9%

48.

9% 43.

2%

43.

7%

45.

2%

48.

8%

47.

5%

45.

8%

47.

5% 48.

4%

46.

3%

Dispatchable vs. Non-Dispatchable Generation

* 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).

87


ISO-NE PUBLIC

GR:rolling_avg_per_big

CT ME NEMA ROP

$/KW

-Mon

th

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

monthJAN16 FEB16 MAR16 APR16 MAY16 JUN16 JUL16 AUG16 SEP16 OCT16 NOV16 DEC16 JAN17

Rolling Average Peak Energy Rent (PER)

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.

88


ISO-NE PUBLIC

GR:fcm_per_adj_byzone_big

CT ME NEMA ROP

Mill

ions

($)

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

monthJAN16 FEB16 MAR16 APR16 MAY16 JUN16 JUL16 AUG16 SEP16 OCT16 NOV16 DEC16 JAN17

PER Adjustments

PER Adjustments are reductions to Forward Capacity Market monthly payments resulting from the rolling average PER.

89



REGIONAL SYSTEM PLAN (RSP)

90


ISO-NE PUBLIC 91

Planning Advisory Committee (PAC)

• RSP17 scope of work was discussed with the PAC at the January 18 meeting and work is proceeding

• February 9 PAC Meeting Agenda* – Interregional Planning Update

– Maine Resource Integration Study

– Northern New England-Scobie+394 Interface Update

– Public Policy Stakeholder Presentations

* Agenda items are subject to change. Visit https://www.iso-ne.com/committees/planning/planning-advisory for the latest PAC agendas.


https://www.iso-ne.com/committees/planning/planning-advisory

ISO-NE PUBLIC 92

Load, Energy Efficiency, and Photovoltaic Forecast

• Load Forecast – Development of the ten-year load forecast is ongoing – Next Load Forecast Committee meeting will be in early April to

discuss the final forecast which will be published as part of the 2017 CELT Report on or about May 1

• Energy Efficiency (EE) Forecast – Preliminary EE forecast is being developed and will be discussed with

stakeholders at the next EE working group meeting on February 16

• Photovoltaic (PV) Forecast – Preliminary PV forecast is being developed and will be discussed with

stakeholders at the next Distributed Generation Forecast working group meeting on February 28


ISO-NE PUBLIC 93

Economic Studies and Keene Road Market Efficiency Transmission Upgrade Needs Assessment • 2016 Economic Study - NEPOOL Scenario Analysis results remain

ahead of schedule – Phase I observations and key messages and results for requests for additional

metrics and sensitivities were discussed with the PAC for the six base scenarios – Work is proceeding on the Phase II scopes of work discussed at the December 14

PAC meeting and are scheduled for completion during 2017 • Natural gas pipeline results • Scope of work for FCA auction results • Scope of work for regulation, ramping, and reserves

– Phase I report is on schedule for first quarter 2017

• Keene Road Market Efficiency Transmission Upgrade needs assessment final results were posted on the PAC website – Initial ISO recommendation not to proceed with an RFP due to anticipated

transmission upgrade costs was discussed at the January 18 PAC meeting


ISO-NE PUBLIC 94

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

Project Benefit: Addresses system needs in the Connecticut River Corridor in Vermont

Note: The above listing focuses on major transmission line construction and rebuilding.

UpgradeExpected In-Service

Present Stage

Rebuild 115 kV line K31, Coolidge-Ascutney Oct-17 3Ascutney Substation - Add a +50/-25 MVAR dynamic reactive device May-18 3Hartford Substation - Split 25 MVAR capacitor bank into two 12.5 MVAR banks Dec-16 4

Chelsea Station - Rebuild to a three-breaker ring bus Dec-17 3

Connecticut River Valley Status as of 1/30/17

95


ISO-NE PUBLIC

Project Benefit: Addresses Needs in New Hampshire and Vermont



Present Stage

Eagle Substation Add: 345/115 kV autotransformer Dec-16 4*Littleton Substation Add: Second 230/115 kV autotransformer Oct-14 4New C-203 230 kV line tap to Littleton NH Substation Nov-14 4New 115 kV overhead line, Fitzwilliam-Monadnock Feb-17 3New 115 kV overhead line, Scobie Pond-Huse Road Nov-15 4*New 115 kV overhead/submarine line, Madbury-Portsmouth Dec-18 2New 115 kV overhead line, Scobie Pond-Chester Dec-15 4

New Hampshire/Vermont 10-Year Upgrades Status as of 1/30/17

96

* Placed in-service ahead of schedule


ISO-NE PUBLIC




Present Stage

Saco Valley Substation - Add two 25 MVAR dynamic reactive devices Aug-16 4Rebuild 115 kV line K165, W157 tap Eagle-Power Street May-15 4Rebuild 115 kV line H137, Merrimack-Garvins Jun-13 4Rebuild 115 kV line D118, Deerfield-Pine Hill Nov-14 4Oak Hill Substation - Loop in 115 kV line V182, Garvins-Webster Apr-15 4*Uprate 115 kV line G146, Garvins-Deerfield Mar-15 4Uprate 115 kV line P145, Oak Hill-Merrimack May-14 4


New Hampshire/Vermont 10-Year Upgrades, cont. Status as of 1/30/17

97


ISO-NE PUBLIC




Present Stage

Upgrade 115 kV line H141, Chester-Great Bay Nov-14 4Upgrade 115 kV line R193, Scobie Pond-Kingston Tap Mar-15 4*Upgrade 115 kV line T198, Keene-Monadnock Nov-13 4Upgrade 345 kV line 326, Scobie Pond-NH/MA Border Dec-13 4Upgrade 115 kV line J114-2, Greggs - Rimmon Dec-13 4Upgrade 345 kV line 381, between MA/NH border and NH/VT border Jun-13 4


New Hampshire/Vermont 10-Year Upgrades, cont. Status as of 1/30/17

98


ISO-NE PUBLIC

Greater Hartford and Central Connecticut (GHCC) Projects* Status as of 1/30/17

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

* Replaces the NEEWS Central Connecticut Reliability Project ** Placed in-service ahead of schedule

99

UpgradeExpectedIn-Service

Present 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

Jun-17 3

Terminal equipment upgrades on the 345 kV line between Haddam Neck and Beseck (362) Dec-17 3

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 4**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 3

Increase the size of the existing 115 kV capacitor bank at Branford Substation from 37.8 to 50.4 MVAR Dec-17 3

Separation of 115 kV double circuit towers corresponding to the Middletown – Pratt and Whitney line (1572) and the Middletown to Haddam (1620) line

Dec-16 4


ISO-NE PUBLIC


* Replaces the NEEWS Central Connecticut Reliability Project

Greater Hartford and Central Connecticut Projects, cont.* Status as of 1/30/17

100


Present 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-18 2Loop the 1779 line between South Meadow and Bloomfield into the Rood Avenue substation and reconfigure the Rood Avenue substation

Dec-17 3

Reconfigure the Berlin 115 kV substation including two new 115 kV breakers and the relocation of a capacitor bank Dec-17 2

Reconductor the 115 kV line between Newington and Newington Tap (1783) Dec-18 2


ISO-NE PUBLIC


101


* Replaces the NEEWS Central Connecticut Reliability Project


Present 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 3

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 3

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


ISO-NE PUBLIC


102


* Replaces the NEEWS Central Connecticut Reliability Project ** Placed in-service ahead of schedule


Present Stage

Add a new control house at Southington 115 kV substation Dec-17 2Add a new 115 kV line from Frost Bridge to Campville Jun-18 3Separation 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 3

Upgrade the 115 kV line between Southington and Lake Avenue Junction (1810-1)

Dec-16 4

Add a new 345/115 kV autotransformer at Barbour Hill substation Dec-16 4**Add a 345 kV breaker in series with breaker 24T at the Manchester 345 kV substation Dec-16 4**

Reconductor the 115 kV line between Manchester and Barbour Hill (1763) Dec-16 4**


ISO-NE PUBLIC

Southwest Connecticut (SWCT) Projects Status as of 1/30/17

103


Present Stage

Add a 25.2 MVAR capacitor bank at the Oxford substation Dec-16 4*Add 2 x 25 MVAR capacitor banks at the Ansonia substation Dec-18 2Close the normally open 115 kV 2T circuit breaker at Baldwin substation Dec-17 3Rebuild Bunker Hill to a 9-breaker substation in breaker-and-a-half configuration** Dec-18 1

Reconductor the 115 kV line between Bunker Hill and Baldwin Junction (1575) Dec-16 4Loop the 1990 line in and out the Bunker Hill substation** Dec-18 1Expand Pootatuck (formerly known as Shelton) substation to 4-breaker ring bus configuration and add a 30 MVAR capacitor bank at Pootatuck

Jun-18 2

Loop the 1570 line in and out the Pootatuck substation Jun-18 2Replace two 115 kV circuit breakers at the Freight substation Dec-15 4

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

* Placed in-service ahead of schedule ** Project to be cancelled


ISO-NE PUBLIC

Southwest Connecticut Projects, cont. Status as of 1/30/17

104



Present Stage

Add two 14.4 MVAR capacitor banks at the West Brookfield substation Dec-17 1Add a new 115 kV line from Plumtree to Brookfield Junction Dec-18 1Reconductor the 115 kV line between West Brookfield and Brookfield Junction (1887) Dec-18 2

Reduce the existing 25.2 MVAR capacitor bank at the Rocky River substation to 14.4 MVAR Dec-17 2

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 2Relocate an existing 37.8 MVAR capacitor bank at Stony Hill to the 25.2 MVAR capacitor bank side Dec-18 2


ISO-NE PUBLIC


105


Present 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 3

Add a 115 kV circuit breaker in series with the existing 29T breaker at the Plumtree substation Dec-16 4*

Terminal equipment upgrade at the Newtown substation (1876) Dec-15 4*Rebuild the 115 kV line from Wilton to Norwalk (1682) and upgrade Wilton substation terminal equipment May-17 3

Reconductor the 115 kV line from Wilton to Ridgefield Junction (1470-1) Dec-17 2Reconductor the 115 kV line from Ridgefield Junction to Peaceable (1470-3) Dec-17 2




ISO-NE PUBLIC


106


Present Stage

Add 2 x 20 MVAR capacitor banks at the Hawthorne substation Mar-16 4*Upgrade the 115 kV bus at the Baird substation May-18 3Upgrade the 115 kV bus system and 11 disconnect switches at the Pequonnock substation Dec-14 4

Add a 345 kV breaker in series with the existing 11T breaker at the East Devon substation Dec-15 4

Rebuild the 115 kV lines from Baird to Congress (8809A / 8909B) Apr-19 2Rebuild the 115 kV lines from Housatonic River Crossing (HRX) to Barnum to Baird (88006A / 89006B) Dec-20 1

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



ISO-NE PUBLIC


107


Present Stage

Remove the Sackett phase shifter Mar-17 3Install a 7.5 ohm series reactor on 1610 line at the Mix Avenue substation Dec-16 4Add 2 x 20 MVAR capacitor banks at the Mix Avenue substation Dec-16 4Separate the 3827 (Beseck to East Devon) and 1610 (Southington to June to Mix Avenue) double circuit towers* Dec-18 1

Upgrade the 1630 line relay at North Haven and Wallingford 1630 terminal equipment Jan-17 4

Rebuild the 115 kV lines from Devon Tie to Milvon (88005A / 89005B) Nov-16 4Replace two 115 kV circuit breakers at Mill River Dec-14 4

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

* Project to be cancelled


ISO-NE PUBLIC

Greater Boston Projects Status as of 1/30/17

108


Present Stage

Install new 345 kV line from Scobie to Tewksbury Dec-17 3Reconductor the Y-151 115 kV line from Dracut Junction to Power Street Dec-17 3*Reconductor the M-139 115 kV line from Tewksbury to Pinehurst and associated work at Tewksbury Jun-17 3

Reconductor the N-140 115 kV line from Tewksbury to Pinehurst and associated work at Tewksbury Jun-17 3

Reconductor the F-158N 115 kV line from Wakefield Junction to Maplewood and associated work at Maplewood Dec-15 4

Reconductor the F-158S 115 kV line from Maplewood to Everett Jun-17 2Install new 345 kV cable from Woburn to Wakefield Junction, install two new 160 MVAR variable shunt reactors and associated work at Wakefield Junction and Woburn

May-19 2

Refurbish X-24 69 kV line from Millbury to Northboro Road Dec-15 4Reconductor W-23W 69 kV line from Woodside to Northboro Road Dec-17 2

Plan Benefit: Addresses long-term system needs in the Greater Boston area and improves system reliability

* Eversource portion of the project is complete


ISO-NE PUBLIC

Greater Boston Projects, cont. Status as of 1/30/17

109


Present Stage

Separate X-24 and E-157W DCT Jul-17 2Separate Q-169 and F-158N DCT Dec-15 4Reconductor M-139/211-503 and N-140/211-504 115 kV lines from Pinehurst to North Woburn tap May-17 4*

Install new 115 kV station at Sharon to segment three 115 kV lines from West Walpole to Holbrook Sep-19 2

Install third 115 kV line from West Walpole to Holbrook Sep-19 2Install new 345 kV breaker in series with the 104 breaker at Stoughton May-16 4Install new 230/115 kV autotransformer at Sudbury and loop the 282-602 230 kV line in and out of the new 230 kV switchyard at Sudbury Dec-17 3

Install a new 115 kV line from Sudbury to Hudson Dec-20 1




ISO-NE PUBLIC


110


Present Stage

Replace 345/115 kV autotransformer, 345 kV breakers, and 115 kV switchgear at Woburn May-19 3

Install a 345 kV breaker in series with breaker 104 at Woburn May-17 3Reconfigure Waltham by relocating PARs, 282-507 line, and a breaker Dec-17 3Upgrade 533-508 115 kV line from Lexington to Hartwell and associated work at the stations Aug-16 4

Install a new 115 kV 54 MVAR capacitor bank at Newton Dec-16 4Install a new 115 kV 36.7 MVAR capacitor bank at Sudbury May-17 3Install a second Mystic 345/115 kV autotransformer and reconfigure the bus Jun-18 3Install a 115 kV breaker on the East bus at K Street Jun-16 4Install 115 kV cable from Mystic to Chelsea and upgrade Chelsea 115 kV station to BPS standards Jun-19 2

Split 110-522 and 240-510 DCT from Baker Street to Needham for a portion of the way and install a 115 kV cable for the rest of the way Dec-18 2



ISO-NE PUBLIC


111


Present Stage

Install a second 115 kV cable from Mystic to Woburn to create a bifurcated 211-514 line Dec-18 2

Open lines 329-510/511 and 250-516/517 at Mystic and Chatham, respectively. Operate K Street as a normally closed station.

Jun-18 3

Upgrade Kingston to create a second normally closed 115 kV bus tie and reconfigure the 345 kV switchyard Jun-18 2

Relocate the Chelsea capacitor bank to the 128-518 termination postion Dec-16 4



ISO-NE PUBLIC


112


Present Stage

Upgrade North Cambridge to mitigate 115 kV 5 and 10 stuck breaker contingencies Nov-17 3

Install a 200 MVAR STATCOM at Coopers Mills Sep-18 2Install a 115 kV 36.7 MVAR capacitor bank at Hartwell May-17 3Install a 345 kV 160 MVAR shunt reactor at K Street Dec-18 1Install a 115 kV breaker in series with the 5 breaker at Framingham Jun-17 3Install a 115 kV breaker in series with the 29 breaker at K Street Mar-17 3



ISO-NE PUBLIC

Project Benefit: Addresses system needs in the Pittsfield/Greenfield area in Western Massachusetts


Present Stage

Separate and reconductor the Cabot Taps (A-127 and Y-177 115 kV lines) Mar-17 3

Install a 115 kV tie breaker at the Harriman Station, with associated buswork, reconductor of buswork and new control house Nov-17 3

Modify Northfield Mountain 16R Substation and install a 345/115 kV autotransformer May-17 3

Build a new 115 kV three-breaker switching station (Erving) ring bus Mar-17 3Build a new 115 kV line from Northfield Mountain to the new Erving Switching Station May-17 3

Install 115 kV 14.4 MVAR capacitor banks at Cumberland, Podick and Amherst Substations Dec-15 4

Pittsfield/Greenfield Projects Status as of 1/30/17

113


ISO-NE PUBLIC



Present Stage

Rebuild the Cumberland to Montague 1361 115 kV line and terminal work at Cumberland and Montague. At Montague Substation, reconnect Y177 115 kV line into 3T/4T position and perform other associated substation work

Dec-16 4

Remove the sag limitation on the 1512 115 kV line from Blandford Substation to Granville Junction and remove the limitation on the 1421 115 kV line from Pleasant to Blandford Substation

Dec-14 4

Loop the A127W line between Cabot Tap and French King into the new Erving Substation Mar-17 3

Reconductor A127 between Erving and Cabot Tap and replace switches at Wendell Depot Apr-15 4

Pittsfield/Greenfield Projects, cont. Status as of 1/30/17

114


ISO-NE PUBLIC



Present Stage

Install a 115 kV 20.6 MVAR capacitor at the Doreen substation and operate the 115 kV 13T breaker N.O. Dec-17 1

Install a 75-150 MVAR variable reactor at Northfield substation Dec-17 1Install a 75-150 MVAR variable reactor at Ludlow substation Dec-17 1Construct a 115 kV three-breaker ring bus at or adjacent to Pochassic 37R Substation, loop line 1512-1 into the new three-breaker ring bus, construct a new line connecting the new three-breaker ring bus to the Buck Pond 115 kV Substation on the vacant side of the double-circuit towers that carry line 1302-2, add a new breaker to the Buck Pond 115 kV straight bus and reconnect lines 1302-2, 1657-2 and transformer 2X into new positions

Dec-19 1

Pittsfield/Greenfield Projects, cont. Status as of 1/30/17

115


ISO-NE PUBLIC 116

Status of Tariff Studies

7 8 515 10 8

2 3 2 3 4 4 2

14 1412

108 9

11 11 12 14 13 14 16

0 00

00 0

0 0 00 0 0 0

40 4245

43

4238

40 3831 28 28 27 26

00 0

0

00 1 1

1 1 2 1 1

8 7 67

108 10 12

15 14 14 14 15

22 2222

2423

24 24 2425 25 24 22 21

6 6 6

66

6 7 6 6 7 75 5

0

20

40

60

80

100

120

Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Jan-17

13,323MW

13,994MW

14,134MW

13,795MW

11,740MW

11,447MW

11,583MW

12,325MW

12,156MW

12,553MW

13,331MW

13,403MW

12,949MW

Num

ber o

f Pro

ject

s

Generator Project Status

Distribution

Executed IA

Negotiating IA

Facility Study

Sys. Impact Study

Optional Study

Feasibility Study

Scoping

9699

105

9286

999593 95

92 9297

87

https://irtt.iso-ne.com/external.aspx Note: As of January 2017, there are 9 ETU’s in SIS, 1 in OSIS, 2 in FS, 3 in Scoping, and 2 in Neg. IA

Note: January 2017 based on partial data


https://irtt.iso-ne.com/external.aspx


OPERABLE CAPACITY ANALYSIS

Winter 2016/17

117


ISO-NE PUBLIC

Winter 2017 Operable Capacity Analysis 50/50 Load Forecast (Reference) February - 20172

CSO February - 20172

SCC

Operable Capacity MW 1 30,246 32,829

OP CAP From OP-4 RTDR (+) 254 254

OP CAP From OP-4 RTEG (+) 1 1

Operable Capacity with OP-4 DR and RTEG 30,501 33,084

External Node Available Net Capacity, CSO imports minus firm capacity exports (+) 994 994

Non Commercial Capacity (+) 0 0

Non Gas-fired Planned Outage MW (-) 844 860

Gas Generator Outages MW (-) 489 562

Allowance for Unplanned Outages (-) 5 3,100 3,100

Generation at Risk Due to Gas Supply (-) 4 2,780 3,050

Net Capacity (NET OPCAP SUPPLY MW) 3 24,282 26,506

Peak Load Forecast MW(adjusted for Other Demand Resources) 2 20,834 20,834

Operating Reserve Requirement MW 2,305 2,305

Operable Capacity Required (NET LOAD OBLIGATION MW) 23,139 23,139

Operable Capacity Margin 3 1,143 3,367 1Operable Capacity is based on data as of January 16, 2017and does not include Capacity associated with Settlement Only Generators, Passive and Active Demand Response, and external capacity. The Operable Capacity (CSO ) and SCC values are based on data as of January 16, 2017. 2 Load forecast that is based on the current CELT report and represents the week with the lowest Operable Capacity Margin, week beginning February 4, 2017. 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.

118


ISO-NE PUBLIC

Winter 2017 Operable Capacity Analysis 90/10 Load Forecast (Extreme) February - 20172

CSO February - 20172

SCC





External Node Available Net Capacity, CSO imports minus firm capacity exports (+) 994 994


Non Gas-fired Planned Outage MW (-) 844 860



Generation at Risk Due to Gas Supply (-) 4 3,143 3,451





Operable Capacity Margin 3 107 2,293 1Operable Capacity is based on data as of January 16, 2017 and does not include Capacity associated with Settlement Only Generators, Passive and Active Demand Response, and external capacity. The Operable Capacity (CSO ) and SCC values are based on data as of January 16, 2017. 2 Load forecast that is based on the current CELT report and represents the week with the lowest Operable Capacity Margin, week beginning February 4, 2017. 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.

119


ISO-NE PUBLIC 120

Winter 2017 Operable Capacity Analysis (MW) 50/50 Forecast (Reference)

CSO 50/50

CSO

1/16/17 11:20 KBO_170116_February_COO_AMS_case7707 50/50

with RTDR and RTEGSCC 90/10

AVAILABLE OPCAP MW

EXTERNAL NODE AVAIL

CAPACITY MW

NON COMMERCIAL CAPACITY MW

NON-GAS PLANNED

OUTAGES CSO MW

GAS GENERAT

OR OUTAGES CSO MW

ALLOWANCE FOR

UNPLANNED OUTAGES MW

GAS AT RISK MW

NET OPCAP SUPPLY MW

PEAK LOAD FORECAST

MW

OPER RESERVE REQUIREMENT

MW NET LOAD

OBLIGATION MW

OPCAP MARGIN

MW

OPCAP FROM OP4 ACTIVE

REAL-TIME DR MW

OPCAP MARGIN w/

OP4 actions through OP4 Step 2 MW

OPCAP FROM OP4 REAL-TIME EMER.

GEN MW

OPCAP MARGIN w/ OP4 actions

through OP4 Step 6 MW

[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14] [15] [16]1/28/2017 30,246 994 0 441 489 3,100 2,780 24,430 21,110 2,305 23,415 1,015 254 1,269 1 1,2702/4/2017 30,246 994 0 844 489 3,100 2,780 24,027 20,834 2,305 23,139 888 254 1,142 1 1,1432/11/2017 30,246 994 0 576 489 3,100 2,416 24,659 20,804 2,305 23,109 1,550 254 1,804 1 1,8052/18/2017 30,246 994 0 910 489 3,100 2,174 24,567 20,533 2,305 22,838 1,729 254 1,983 1 1,9842/25/2017 29,982 1,037 21 1,265 903 3,100 1,276 24,496 19,512 2,305 21,817 2,679 362 3,041 177 3,2183/4/2017 29,982 1,037 21 1,946 735 2,200 1,081 25,078 19,151 2,305 21,456 3,622 362 3,984 177 4,161

3/11/2017 29,982 1,037 21 2,574 887 2,200 808 24,571 18,949 2,305 21,254 3,317 362 3,679 177 3,8563/18/2017 29,982 1,037 21 3,371 887 2,200 320 24,262 18,572 2,305 20,877 3,385 362 3,747 177 3,9243/25/2017 29,982 1,037 21 4,037 556 2,200 291 23,956 17,988 2,305 20,293 3,663 362 4,025 177 4,202

(874)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 2016 CELT Report and adjusted for Passive Demand Resources. http:/ / www.iso-ne.com/ system-planning/ system-plans-studies/ celt10. Operating Reserve Requirement based on 120% 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 2017 OPERABLE CAPACITY ANALYSIS

STUDY WEEK (Week Beginning,

Saturday)

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 Mid September.

February 3, 2017 - 50/50 FORECAST using CSO values


ISO-NE PUBLIC 121

Winter 2017 Operable Capacity Analysis (MW) 90/10 Forecast (Extreme)

CSO 50/50

CSO1/16/17 11:53

KBO_170116_February_COO_AM 90/10 with RTDR and RTEGSCC 90/10

AVAILABLE OPCAP MW

EXTERNAL NODE AVAIL

CAPACITY MW


NON-GAS PLANNED

OUTAGES CSO MW

GAS GENERAT

OR OUTAGES CSO MW

ALLOWANCE FOR


GAS AT RISK MW

NET OPCAP SUPPLY MW

PEAK LOAD FORECAST

MWOPER RESERVE

REQUIREMENT MW

NET LOAD OBLIGATION

MW

OPCAP MARGIN

MW


REAL-TIME DR MW

OPCAP MARGIN w/



GEN MW



[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14] [15] [16]1/28/2017 30,246 994 0 441 489 3,100 3,143 24,067 21,791 2,305 24,096 (29) 254 225 1 2262/4/2017 30,246 994 0 844 489 3,100 3,143 23,664 21,507 2,305 23,812 (148) 254 106 1 1072/11/2017 30,246 994 0 576 489 3,100 2,739 24,336 21,476 2,305 23,781 555 254 809 1 8102/18/2017 30,246 994 0 910 489 3,100 2,470 24,271 21,197 2,305 23,502 769 254 1,023 1 1,0242/25/2017 29,982 1,037 21 1,265 903 3,100 1,518 24,254 20,145 2,305 22,450 1,804 362 2,166 177 2,3433/4/2017 29,982 1,037 21 1,946 735 2,200 1,282 24,877 19,774 2,305 22,079 2,798 362 3,160 177 3,3373/11/2017 29,982 1,037 21 2,574 887 2,200 996 24,383 19,565 2,305 21,870 2,513 362 2,875 177 3,0523/18/2017 29,982 1,037 21 3,371 887 2,200 454 24,128 19,177 2,305 21,482 2,646 362 3,008 177 3,1853/25/2017 29,982 1,037 21 4,037 556 2,200 385 23,862 18,575 2,305 20,880 2,982 362 3,344 177 3,521

(3,247)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 2016 CELT Report and adjusted for Passive Demand Resources. http :/ /www.iso -ne .co m/syste m-p la nning /sys te m-p la ns-s tud ie s /ce lt10. Operating Reserve Requirement based on 120% 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).



Saturday)




ISO-NE PUBLIC 122

Winter 2017 Operable Capacity Analysis (MW) 50/50 Forecast (Reference)

(1,000)

0

1,000

2,000

3,000

4,000

5,000

28-J

an

4-Fe

b

11-F

eb

18-F

eb

25-F

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4-M

ar

11-M

ar

18-M

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25-M

ar

Ope

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apac

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argi

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W)

ISO-NE 2017 OPERABLE CAPACITY ANALYSIS - - with RTDR and RTEG- 50/50 FORECAST

January 28, 2017- March 31, 2017, W/B Saturday


ISO-NE PUBLIC 123

Winter 2017 Operable Capacity Analysis (MW) 90/10 Forecast (Extreme)

(1,000)

0

1,000

2,000

3,000

4,000

5,000

28-J

an

4-Fe

b

11-F

eb

18-F

eb

25-F

eb

4-M

ar

11-M

ar

18-M

ar

25-M

ar

Ope

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argi

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W)

January 28, 2017 - March 31, 2017 W/B Saturday

ISO-NE 2017 OPERABLE CAPACITY ANALYSIS with RTDR and RTEG

- 90/10 FORECAST

- -



OPERABLE CAPACITY ANALYSIS

Spring 2017

124


ISO-NE PUBLIC

Spring 2017 Operable Capacity Analysis 50/50 Load Forecast (Reference) May - 20172

CSO May - 20172

SCC





External Node Available Net Capacity, CSO imports minus firm capacity exports (+) 1,037 1,037


Non Gas-fired Planned Outage MW (-) 3,252 3,866



Generation at Risk Due to Gas Supply (-) 4 0 0





Operable Capacity Margin 3 1,001 3,073 1Operable Capacity is based on data as of January 16, 2017 and does not include Capacity associated with Settlement Only Generators, Passive and Active Demand Response, and external capacity. The Operable Capacity (CSO ) and SCC values are based on data as of January 16, 2017 . 2 Load forecast that is based on the current CELT report and represents the week with the lowest Operable Capacity Margin, week beginning May 13, 2017. 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.

125


ISO-NE PUBLIC

Spring 2017 Operable Capacity Analysis 90/10 Load Forecast (Extreme) May - 20172

CSO May - 20172

SCC





External Node Available Net Capacity, CSO imports minus firm capacity exports (+) 1,037 1,037


Non Gas-fired Planned Outage MW (-) 3,252 3,866



Generation at Risk Due to Gas Supply (-) 4 0 0





Operable Capacity Margin 3 -875 1,197 1Operable Capacity is based on data as of January 16, 2017 and does not include Capacity associated with Settlement Only Generators, Passive and Active Demand Response, and external capacity. The Operable Capacity (CSO ) and SCC values are based on data as of January 16, 2017 . 2 Load forecast that is based on the current CELT report and represents the week with the lowest Operable Capacity Margin, week beginning May 13, 2017. 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.

126


ISO-NE PUBLIC 127

Spring 2017 Operable Capacity Analysis (MW) 50/50 Forecast (Reference)

CSO 50/50

CSO

1/16/17 11:20 KBO_170116_February_COO_AMS_case7707 50/50

with RTDR and RTEGSCC 90/10

AVAILABLE OPCAP MW

EXTERNAL NODE AVAIL

CAPACITY MW


NON-GAS PLANNED

OUTAGES CSO MW

GAS GENERAT

OR OUTAGES CSO MW

ALLOWANCE FOR


GAS AT RISK MW

NET OPCAP SUPPLY MW

PEAK LOAD FORECAST

MW

OPER RESERVE REQUIREMENT

MW NET LOAD

OBLIGATION MW

OPCAP MARGIN

MW


REAL-TIME DR MW

OPCAP MARGIN w/



GEN MW



[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14] [15] [16]4/1/2017 29,964 1,037 21 5,291 1,244 2,700 0 21,787 17,290 2,305 19,595 2,192 367 2,559 184 2,7434/8/2017 29,964 1,037 21 4,772 1,240 2,700 0 22,310 17,031 2,305 19,336 2,974 367 3,341 184 3,5254/15/2017 29,964 1,037 21 4,898 1,161 2,700 0 22,263 16,504 2,305 18,809 3,454 367 3,821 184 4,0054/22/2017 29,964 1,037 21 5,174 393 2,700 0 22,755 16,230 2,305 18,535 4,220 367 4,587 184 4,7714/29/2017 29,964 1,037 21 3,687 254 3,400 0 23,681 15,683 2,305 17,988 5,693 367 6,060 184 6,2445/6/2017 29,964 1,037 21 2,425 1,530 3,400 0 23,667 19,782 2,305 22,087 1,580 367 1,947 184 2,1315/13/2017 29,964 1,037 21 3,252 804 3,400 0 23,566 20,811 2,305 23,116 450 367 817 184 1,0015/20/2017 29,964 1,037 21 2,134 848 3,400 0 24,640 21,767 2,305 24,072 568 367 935 184 1,1195/27/2017 29,964 1,037 21 567 261 3,400 0 26,794 22,816 2,305 25,121 1,673 367 2,040 184 2,224

(874)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 2016 CELT Report and adjusted for Passive Demand Resources. http:/ / www.iso-ne.com/ system-planning/ system-plans-studies/ celt10. Operating Reserve Requirement based on 120% 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).



Saturday)




ISO-NE PUBLIC 128

Spring 2017 Operable Capacity Analysis (MW) 90/10 Forecast (Extreme)

CSO 50/50

CSO1/16/17 11:53

KBO_170116_February_COO_AM 90/10 with RTDR and RTEGSCC 90/10

AVAILABLE OPCAP MW

EXTERNAL NODE AVAIL

CAPACITY MW


NON-GAS PLANNED

OUTAGES CSO MW

GAS GENERAT

OR OUTAGES CSO MW

ALLOWANCE FOR


GAS AT RISK MW

NET OPCAP SUPPLY MW

PEAK LOAD FORECAST

MWOPER RESERVE

REQUIREMENT MW

NET LOAD OBLIGATION

MW

OPCAP MARGIN

MW


REAL-TIME DR MW

OPCAP MARGIN w/



GEN MW



[1] [2] [3] [4] [5] [6] [7] [8] [9] [10] [11] [12] [13] [14] [15] [16]4/1/2017 29,964 1,037 21 5,291 1,244 2,700 0 21,787 17,863 2,305 20,168 1,619 367 1,986 184 2,1704/8/2017 29,964 1,037 21 4,772 1,240 2,700 0 22,310 17,595 2,305 19,900 2,410 367 2,777 184 2,9614/15/2017 29,964 1,037 21 4,898 1,161 2,700 0 22,263 17,053 2,305 19,358 2,905 367 3,272 184 3,4564/22/2017 29,964 1,037 21 5,174 393 2,700 0 22,755 16,771 2,305 19,076 3,679 367 4,046 184 4,2304/29/2017 29,964 1,037 21 3,687 254 3,400 0 23,681 16,223 2,305 18,528 5,153 367 5,520 184 5,7045/6/2017 29,964 1,037 21 2,425 1,530 3,400 0 23,667 21,575 2,305 23,880 (213) 367 154 184 3385/13/2017 29,964 1,037 21 3,252 804 3,400 0 23,566 22,687 2,305 24,992 (1,426) 367 (1,059) 184 (875)5/20/2017 29,964 1,037 21 2,134 848 3,400 0 24,640 23,720 2,305 26,025 (1,385) 367 (1,018) 184 (834)5/27/2017 29,964 1,037 21 567 261 3,400 0 26,794 24,854 2,305 27,159 (365) 367 2 184 186

(3,247)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 2016 CELT Report and adjusted for Passive Demand Resources. http :/ /www.iso -ne .co m/syste m-p la nning /sys te m-p la ns-s tud ie s /ce lt10. Operating Reserve Requirement based on 120% 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).



Saturday)




ISO-NE PUBLIC 129

Spring 2017 Operable Capacity Analysis (MW) 50/50 Forecast (Reference)

(2,000)

(1,000)

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

1-A

pr

8-A

pr

15-A

pr

22-A

pr

29-A

pr

6-M

ay

13-M

ay

20-M

ay

27-M

ay

Ope

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W)

ISO-NE 2017 OPERABLE CAPACITY ANALYSIS - - with RTDR and RTEG- 50/50 FORECAST

April 1, 2017 - June 2, 2017, W/B Saturday


ISO-NE PUBLIC 130

Spring 2017 Operable Capacity Analysis (MW) 90/10 Forecast (Extreme)

(2,000)

(1,000)

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

1-A

pr

8-A

pr

15-A

pr

22-A

pr

29-A

pr

6-M

ay

13-M

ay

20-M

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27-M

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Ope

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W)

April 1, 2017 - June 2, 2017 W/B Saturday

ISO-NE 2017 OPERABLE CAPACITY ANALYSIS with RTDR and RTEG

- 90/10 FORECAST

- -



OPERABLE CAPACITY ANALYSIS Appendix

131


ISO-NE PUBLIC

Possible Relief Under OP4: Appendix A OP 4

Action Number

Page 1 of 2 Action Description

Amount Assumed Obtainable Under OP 4

(MW)

1 Implement Power Caution and advise Resources with a CSO to prepare to provide 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.

0 1

600

2 Dispatch real time Demand Resources. February 254 3

March 362 3

April & May 367 3

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-Control Area Emergency

1,000

6 Voltage Reduction requiring > 10 minutes Dispatch real time Emergency Generation

134 4 February 1 3

March 177 3

April & May 184 3 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 January 16, 2017. 4. The MW values are based on a 26,930 MW system load and the most recent voltage reduction test % achieved.

132


ISO-NE PUBLIC

Possible Relief Under OP4: Appendix A

OP 4 Action

Number Page 2 of 2

Action Description Amount Assumed Obtainable

Under OP 4 (MW)

7 Request generating resources not subject to a Capacity Supply Obligation to voluntary provide energy for reliability purposes

0

8 Voltage Reduction requiring 10 minutes or less 267 4

9 Transmission Customer Generation Not Contractually Available to Market Participants during a Capacity Deficiency. Voluntary Load Curtailment by Large Industrial and Commercial Customers.

5

200 2

10 Radio and TV Appeals for Voluntary Load Curtailment Implement Power Warning

200 2

11 Request State Governors to Reinforce Power Warning Appeals.

100 2

Total February 2,801 3 March 3,085 3

April & May 3,097 3 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 January 16, 2017. 4. The MW values are based on a 26,930 MW system load and the most recent voltage reduction test % achieved.

133



96408578.1

M E M O R A N D U M

TO: NEPOOL Participants Committee Members and Alternates

FROM: Eric Runge, NEPOOL Counsel

DATE: January 27, 2017

RE: Interconnection Clustering Revisions

At the February 3, 2017, meeting of the Participants Committee you will be asked to vote on revisions to Sections I and II of the ISO New England Inc. (“ISO-NE” or “the ISO”) Transmission, Markets and Services Tariff (“ISO-NE Tariff”) to reflect an ISO-NE proposal to enable the clustering of interconnection requests for study and cost allocation purposes (collectively, the “Interconnection Clustering Revisions”).1 At its January 24, 2017 meeting the Transmission Committee recommended Participants Committee support for the Interconnection Clustering Revisions with a vote of 73.55% in favor.2 The ISO has expressed its intent to file the revisions in late February/early March.

The Interconnection Clustering Revisions were proposed by ISO-NE and developed further by ISO-NE and NEPOOL during several NEPOOL Transmission Committee meetings from September 2016 through January 2017. The purpose of the Interconnection Clustering Revisions is to provide a clustering mechanism by which projects can be studied and information provided about the needed infrastructure and costs in a transparent way, so that projects can decide whether or not to move forward, and thereby help to reduce or eliminate backlogs in the interconnection queue caused by the lack of transmission infrastructure. The Interconnection Clustering Revisions are intended to carry out this purpose through the following primary features and activities:

(1) a trigger mechanism will identify the need for clustering when two or more interconnection requests cannot be processed without significant transmission upgrades;

1 The Interconnection Clustering Revisions and related explanatory materials from the ISO have been included with this memorandum.

2 All of the votes on this matter require a two-thirds or better vote in support to pass. The vote at the Transmission Committee on the ISO-NE’s proposal passed with a vote of 73.55% in favor. The individual Sector votes were Generation (11.42% in favor, 5.71 % opposed, 3 abstentions); Transmission (8.56% in favor, 8.56% opposed, 1 abstention); Supplier (13.70% in favor, 3.43% opposed, 2 abstentions); Alternative Resources (9.05% in favor, 5.32% opposed, 1 abstention); Publicly Owned Entity (17.13% in favor, 0% opposed); End User (13.70% in favor, 3.43% opposed, 2 abstentions); Provisional (0% in favor, 0% opposed, 1 abstention). NESCOE also stated its support for the ISO proposal.

96408578.1 -2- .

(2) once a need is triggered, a study under the Regional System Planning process, conducted through the Planning Advisory Committee, will identify the “Cluster Enabling Transmission Upgrade” or “CETU”)3 that would allow for the processing of the identified interconnection requests;

(3) a Regional System Planning process that results in a report (the “Cluster Enabling Transmission Upgrade Regional Planning Study” report or “CRPS” report) that identifies the CETU and the interconnection requests that are eligible to join a cluster study, conducted under the interconnection procedures, that would include the CETU

(4) cluster eligibility and cluster participation requirements;

(5) cluster deposit requirements;

(6) provisions for populating the cluster, withdrawal from the cluster and backfilling the cluster;

(7) provisions for the Cluster System Impact Study and Cluster Facilities Study (including cost estimates of required interconnection facilities and related transmission upgrades);

(8) cost allocation provisions that allocate costs to the participants in the cluster on the basis of a distribution factor methodology,4 which multiplies a distribution factor times the megawatt value of each interconnection customer’s project in the cluster to come up with proportionate shares of costs among cluster participants; and

(9) a transition mechanism that would make the Northern/Western Maine queue backlog the first trigger for the clustering provisions and would make the currently ongoing Maine Resource Integration Study the first CRPS, with the plan being that the initiation of a cluster would commence fairly soon after the Effective Date of the Interconnection Clustering Revisions (the Effective Date is expected to be by early May 2017).

The Interconnection Clustering Revisions do not, and are not designed to, ensure the funding of transmission infrastructure, but instead provide a mechanism for clustering of studies and cost allocation. These cost allocations do not impact sources of potential upgrade funding available to the interconnection customer, such as state procurement agreements and/or participant funding. During the course of the Transmission Committee discussions, there were two funding-related motions to amend that were introduced, one from RENEW and one from

3 The CETU is additional network transmission that must be built to enable the interconnection of two or more interconnection requests located electrically in the same part of the transmission system, and does not include interconnection facilities or other network upgrades that would need to be built to meet interconnection standards.

4 The distribution factor is the measure of responsiveness or change in electrical loading on system facilities due to a change in electric power transfer from one part of the electric system to another, expressed in percent of the change in power transfer.

96408578.1 -3- .

AVANGRID. Both proposals were put forward in the form of amendments to the ISO-NE proposal, and both failed, with the RENEW amendment receiving 63.83% support,5 and the AVANGRID proposal receiving 12.84% support.6 The RENEW amendment was intended to provide a mechanism to synchronize state energy procurements with the clustering process, and would have allowed for electric distribution companies (“EDCs”) to contract to pay for the facilities identified through the clustering process, under provisions in Schedule 11 of the ISO-NE OATT. Without the amendment, EDC-funding of the interconnection costs would need to be accomplished outside of the OATT, as they are now (e.g., via contracts between the EDC and the interconnection customer). The AVAGRID proposal proposed to recognize the costs to the interconnecting transmission owner of managing the major transmission upgrades associated with a cluster, and would have provided funding options to the interconnection customer, including: (1) the transmission owner builds the facilities and the interconnection customer makes an upfront payment to the transmission owner to reflect upgrade costs plus an appropriate markup to recognize value added by the transmission owner in managing the process; (2) the transmission owner builds the facilities and funds the upgrades, and the transmission owner receives payments from the interconnection customer over a 20-year period, with the payments including a recovery of costs and a return on investment for such funding; and (3) the interconnection customer builds and pays. Both RENEW and AVANGRID have indicated that they will pursue their amendments at the Participants Committee and their materials have been included with this memo.7

During discussion of the Interconnection Clustering Revisions proposed by the ISO and the proposed amendments to that proposal, some of those who did not support the proposals expressed some of the following concerns. For those who opposed the ISO proposal, some did so on the basis that it did not include either the RENEW or AVANGRID funding-related proposals, or, in their view, because it would not otherwise fund transmission and get transmission built. Others raised concerns that the proposal was inconsistent with Order 1000 competitive processes for transmission development. Others raised questions about the implementation of certain provisions, particularly those related to ETUs, and whether the language needs further consideration and refinement to reflect implementation details. There

5 The vote on the RENEW amendment failed to pass with a vote of 63.83% in favor. The individual Sector votes were: Generation (8.56% in favor, 8.56% opposed, 2 abstentions); Transmission (6.85% in favor, 10.28% opposed); Supplier (12.84% in favor, 4.28% opposed, 3 abstentions); Publicly Owned Entity (8.56% in favor, 8.56% opposed, 23 abstentions); Alternative Resources (9.88% in favor, 4.49% opposed); End User (17.13% in favor, 0% opposed, 2 abstentions); and Provisional Members (0% in favor, 0% opposed, 1 abstention).

6 The AVANGRID amendment failed to pass with a vote of 12.8% in favor. The individual Sector votes were Generation (0% in favor, 17.12% opposed, 3 abstentions); Transmission (12.84% in favor, 4.28% opposed, 1 abstention); Supplier (0% in favor, 17.12% opposed, 7 abstentions); Publicly Owned Entity (0% in favor, 17.12% opposed); Alternative Resources (0% in favor, 14.37% opposed, 1 abstention); End User (0% in favor, 17.12% opposed, 4 abstentions); and Provisional (0% in favor, 0.017% opposed).

7 Note that the AVANGRID marked tariff revisions do not reflect a change of scope they announced at the January 24 Transmission Committee, which is that the proposal applies only to clustered facilities and would not apply to non-clustered upgrades above a certain dollar threshold, as initially proposed. AVANGRID will confirm this change at the Participants Committee meeting.

96408578.1 -4- .

was a widespread view among committee members that the ISO’s proposal was a positive step in the right direction and will help alleviate the backlog in the queue.

For those who opposed the RENEW amendment, some did so on the grounds that it would provide for non-comparable treatment of interconnection customers, introduce potential interconnection process bias, and potential adverse market impact by facilitating funding of some projects and not others in the queue. Some raised concerns that the proposal was an attempt to build transmission to meet public policy requirements without going through the Order 1000 competitive process for public policy transmission. Others thought the proposal was outside the scope of the changes being proposed by the ISO and that the RENEW proposal needed more development time. Others expressed concern that it would lengthen the cluster study process. NESCOE stated that the states generally supported the RENEW amendment, so long as it does not delay the implementation of the ISO’s proposal, and so long as all references to NESCOE are removed from the provisions. The ISO stated its threshold concerns regarding the inclusion of state procurement processes into the federal interconnection process, particularly the introduction of additional delays. The ISO further stated that even if the RENEW proposal goes forward, there needs to be additional design work done on it, especially to make sure its provisions do not slow down the interconnection clustering process. Several Participants supported the amendment on the grounds that this proposal, or something similar, is needed to synchronize the cluster process with state energy procurements and the related agreements, without which transmission might not get funded.

For those who opposed the AVANGRID amendment, some did so on the basis that they thought that at least some of the proposal was contrary to FERC policies and precedent regarding transmission owner recovery of interconnection costs, especially with respect to the markup provision under the upfront payment option. Others expressed the views that the proposal should provide for competition, or that the proposal needed more development time and effort to provide more clarity about its implementation. NESCOE stated that the majority of the states opposed the AVANGRID amendment. The ISO noted that it has observed that there is recent FERC action on these types of issues but wanted to hear input from NEPOOL. Some Participants stated that the proposal was innovative and might help get transmission built.

During the January 24 Transmission Committee meeting, some clarifications in the language of certain documents were discussed. The ISO committed to review the language after the vote and make any non-substantive changes agreed to by the Chair and Vice Chair of the committee. The ISO has made those changes, with the approval of the Chair and Vice-Chair of the Transmission Committee, in Schedules 22, 23 and 25 of the ISO-NE OATT and they are marked in the documents that have been forwarded to the Participants Committee.8

8 For your convenience in finding the additional revisions they are listed here: Schedule 22: 4.2.3.2(2) – Delete extra “provision” term; 4.2.3.2(3) – Replace “CSIS commences” with “Cluster Entry Deadline”; 4.2.3.3.3 – Delete subsection reference; 4.4.1 – Deleted “original” and added “requested of the Cluster Entry Deadline”; Cluster System Impact Study Form – Corrected editorial error. Schedule 23: 1.5.3.3.2.2(2); 1.5.3.3.2.2(3); 1.5.3.3.3.3; 1.5.5 (all revised consistent with Schedule 22). Schedule 25: 4.2.1 – Added clarification regarding inclusion of Internal ETU that may be considered in place of CETU; 4.2.3.2(3) – Revised consistent with Schedule 22; 4.4.1 – Revised consistent with Schedule 22.

96408578.1 -5- .

As noted in footnote 2 of this memo, all votes on this matter are subject to a two-thirds or better threshold to pass. Additionally, none of the provisions of the ISO-NE Tariff that are being revised are Market Rules and, therefore, are not subject to the “jump-ball” provisions of the Participants Agreement.

The following resolution could be used as the main motion for Participants Committee consideration of this matter:

RESOLVED, that the Participants Committee supports the Interconnection Clustering Revisions, as recommended by the Transmission Committee and as reflected in the materials distributed to the Participants Committee for its February 3, 2017 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 Transmission Committee.

Once that resolution has been put before the Committee, the following form of resolution can be used for Committee consideration of proposed amendments to the main motion:

RESOLVED, that the Participants Committee supports the amendment to the Interconnection Clustering Revisions, as proposed by [RENEW] [AVANGRID] as reflected in the materials distributed to the Participants Committee for its February 3, 2017 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 Transmission Committee.

memo

ISO New England Inc.One Sullivan Road, Holyoke, MA 01040-2841

www.iso-ne.com T 413 535 4135 F 413 540-4226

To: Participants Committee

From: Jay Dwyer, Secretary, NEPOOL Transmission Committee

Date: January 24, 2017

Subject: Actions of the Transmission Committee

This memo is notification to the Participants Committee of the following actions taken by theTransmission Committee at its January 24, 2017 meeting. A quorum was present in all Sectors.

Agenda Item No. 1(A):

November 17, 2016 Meeting Minutes

ACTION: APPROVED

Based on a show of hands, the Transmission Committee unanimously approved the minutes of theNovember 17, 2016 and December 15, 2016 Transmission Committee meetings.

Agenda Item No. 2:ACTION: RECOMMEND SUPPORT

The following motion was moved and seconded by the Transmission Committee:

Resolved, that the Transmission Committee recommends Participants Committee support for ISO NewEngland Inc. proposed revisions to Section I.2, and Attachment K and Schedules 11, 22, 23, and 25 ofSection II of the ISO New England Transmission, Markets and Services Tariff, as reflected in thematerials distributed to the Transmission Committee for its January 24, 2017 meeting, together withany changes adopted by ISO New England Inc. at the meeting, and any non-substantive changesapproved by the Chair and Vice-Chair of the Transmission Committee after the meeting.

(Vote 1 – Failed (Union of Concerned Scientists Amendment on behalf of RENEW) Before themain motion could be voted, it was moved and seconded by the Transmission Committee to amendthe main motion as follows:

Resolved, that the Transmission Committee supports an amendment offered by the Union of ConcernedScientists on behalf of RENEW to ISO New England Inc.’s interconnection clustering proposalcovered in the main motion, as reflected in the RENEW amendment revisions to Section II of the ISONew England Inc. Transmission, Markets and Services Tariff contained in the materials for the January24, 2017 Transmission Committee, together with any changes agreed to at the meeting, and any non-substantive changes approved by the Chair and Vice Chair of the Transmission Committee after themeeting.


memo

ISO New England Inc.One Sullivan Road, Holyoke, MA 01040-2841

www.iso-ne.com T 413 540 4518 F 413 535 4343

The motion to amend the main motion was then voted. The motion to amend failed with a vote of63.83% in favor. The individual Sector votes were: Generation (8.56% in favor, 8.56% opposed, 2abstentions); Transmission (6.85% in favor, 10.28% opposed); Supplier (12.84% in favor, 4.28%opposed, 3 abstentions); Publicly Owned Entity (8.56% in favor, 8.56% opposed, 23 abstentions);Alternative Resources (9.88% in favor, 4.49% opposed); End Users (17.13% in favor, 0%opposed, 2 abstentions) Provisional Members (0% in favor, 0% opposed, 1 abstention)

(Vote 2 – Failed (AVANGRID Amendment) Before the main motion could be voted, it was movedand seconded by the Transmission Committee to amend the main motion as follows:

Resolved, that the Transmission Committee supports an amendment offered by AVANGRID to ISONew England Inc.’s interconnection clustering proposal covered in the main motion, as reflected in theAVANGRID amendment revisions to Section II of the ISO New England Inc. Transmission, Marketsand Services Tariff contained in the materials for the January 24, 2017 Transmission Committee,together with any changes agreed to at the meeting, and any non-substantive changes approved by theChair and Vice Chair of the Transmission Committee after the meeting.

The motion to amend the main motion was then voted. The motion to amend failed with a vote of12.84% in favor. The individual Sector votes were Generation (0% in favor, 17.12% opposed, 3abstentions); Transmission (12.84% in favor, 4.28% opposed, 1 abstention); Supplier (0% in favor,17.12% opposed, 7 abstentions); Publicly Owned Entity (0% in favor, 17.12% opposed); AlternativeResources (0% in favor, 14.37% opposed, 1 abstention); End Users (0% in favor, 17.12% opposed, 4abstentions); Provisional (0% in favor, 0.017% opposed).

(Vote 3 – Passed (Main Motion)) The main motion was then voted. The main motion passedwith a vote of 73.55% in favor. The individual Sector votes were Generation (11.42% infavor, 5.71 % opposed, 3 abstentions); Transmission (8.56% in favor, 8.56% opposed, 1abstention); Supplier (13.70% in favor, 3.43% opposed, 2 abstentions); Alternative Resources(9.05% in favor, 5.32% opposed, 1 abstention); Publicly Owned Entity (17.13% in favor, 0%opposed); End User (13.70% in favor, 3.43% opposed, 2 abstentions); Provisional (0% infavor, 0% opposed, 1 abstention).

cc: Transmission Committee


ISO-NE Public

Al McBride S Y S T E M P L A N N I N G

Proposed Interconnection Queue Clustering Tariff Changes

J A N U A R Y 2 4 , 2 0 1 7 | W E S T B O R O U G H , M A

Summary of Final Changes Made to the Tariff Redlines


ISO-NE Public

2

Interconnection Queue Clustering

Proposed Effective Date: Q1/Q2 2017

• ISO New England (ISO-NE) is proposing to incorporate a clustering methodology in the Interconnection Procedures – Methodology will provide information to Interconnection Customers and to the Region

regarding the infrastructure needed to interconnect requested projects – Will provide a mechanism to expedite interconnection processing in circumstances where a

backlog would be likely to persist with the continued application of the serial queue process – Will allow, under such circumstances, for two or more Interconnection Requests (IRs) to be

analyzed in the same System Impact Study (SIS) effort – The IRs participating in a cluster would be able to share cost responsibility for certain shared

interconnection related transmission upgrades

• The ISO and NEPOOL had fruitful discussions over the course of 6 months – Preceded by discussions at the Planning Advisory Committee in March and May 2016 – Design description memo issued to the Transmission Committee (TC) on September 20, 2016 – Design description presentation made to the TC on September 27, 2016 – Suggestions by RENEW Northeast discussed at the TC on October 11, 2016 – Tariff redlines discussed at the November and December 2016 TC meetings

• Final redlines have been posted for the January 24, 2017 TC meeting and this presentation summarizes those changes, which reflect comments and suggestions raised by the members


https://www.iso-ne.com/static-assets/documents/2016/09/2016_09_27_tca06_clustering.pdf

https://www.iso-ne.com/static-assets/documents/2016/09/2016_09_27_tca06_iso_presentation.pdf

https://www.iso-ne.com/committees/transmission/transmission-committee

ISO-NE Public

3

Summary of Final Tariff Redline Changes Made in Response to TC Comments

• Attachment K – Clarified that the cost estimates provided in the CRPS (Cluster Enabling

Transmission Upgrade [CETU] Regional Planning Study) will be calculated in accordance with the proposed Schedule 11 cost allocation methodology

– Clarified that the CRPS will be posted on the ISO website – Clarified that the Maine Resource Integration Study will be the first

CRPS

• Schedule 11 – Clarified that the proposed distribution factor methodology does not

counteract the existing provision related to the treatment of Reliability Transmission Upgrades

– Clarified that Elective Transmission Upgrades (ETUs) taking the place of CETUs are not included in the cost allocation process

– Clarified that the cost allocation for bidirectional ETUs accounts for the directionality of distribution factor impact


ISO-NE Public

4

Summary of Final Tariff Redline Changes Made in Response to TC Comments, continued

• Schedule 22 (and 23 and 25) – Sub-divided Section 4.2.3.2 for readability – Replaced “separately” with “serially” in Section 4.2 – Clarified, in Section 4.2.2, that the ISO will notify Interconnection

Customers if they are being included in a cluster – In part (2) of Section 4.2.3.2.2, changed the termination of any existing

study agreement to coincide with the execution of the cluster system impact study agreement

– Section 4.2.3.3.3 was changed to provide that all eligible backfill resources are notified at the same time

– In Section 4.2.3.4, extended the deadline to the date of Cluster System Impact Study (CSIS) execution for the indication of any contractual agreement between an ETU and another project

– Various minor ISO clean-up changes


ISO-NE Public

Al McBride a m c b r i d e @ i s o - n e . c o m

5


ISO-NE Public ISO-NE PUBLIC

APPENDIX Examples of Methodology for Distribution Factor Cost Allocation and the processing of Non-Clustered Projects

6


ISO-NE Public

• The distribution factor (DFAX) is the measure of responsiveness or change in electrical loading on system facilities due to a change in electric power transfer from part of the electric system to another, expressed in per cent of the change in power transfer

• Example:

7

DFAX Cost Allocation

CETU 1

QP100

QP120

QP121

QP122

QP101 QP102

CETU 2

CETU 3

QP100 DFAX (%)

QP101 DFAX (%)

QP102 DFAX (%)

QP120DFAX (%)

QP121 DFAX (%)

QP122 DFAX (%)

CETU1 100 0 0 100 100 0

CETU2 50 30 30 50 50 30

CETU3 50 70 70 50 50 70


ISO-NE Public

8

DFAX Cost Allocation, continued

• The individual distribution impact will be calculated by multiplying the distribution factor by the MW size of the Interconnection Request

• The total distribution impact for the upgrade will be calculated as the sum of all of the individual distribution impacts

• The upgrade cost responsibility for entity included in the cluster would be the total cost of the upgrade multiplied by the ratio of the entity’s individual distribution impact divided by the total distribution impact for the entire cluster


ISO-NE Public

9

DFAX Cost Allocation Example

QP100 DFAX (%)

QP101 DFAX (%)

QP102 DFAX (%)

QP120DFAX (%)

QP121 DFAX (%)

QP122 DFAX (%)

CETU1 100 0 0 100 100 0

CETU2 50 30 30 50 50 30

CETU3 50 70 70 50 50 70

Cost $M

CETU1 100

CETU2 200

CETU3 100

QP100 QP101 QP102 QP120 QP121 QP122

MW 50 100 200 100 100 200

Distribution Factors, Calculated from the Power Flow Case

MW Size of the Interconnection Request

Upgrade Cost


ISO-NE Public

10

DFAX Cost Allocation Example, continued

QP100 Impact

MW

QP101 Impact

MW

QP102 Impact

MW

QP120Impact

MW

QP121 Impact

MW

QP122 Impact

MW

Total Impact

MW

CETU1 50 0 0 100 100 0 250

CETU2 25 30 60 50 50 60 275

CETU3 25 70 140 50 50 140 475

QP100 Impact Share

QP101 Impact Share

QP102 Impact Share

QP120Impact Share

QP121 Impact Share

QP122 Impact Share

CETU1 0.2 0 0 0.4 0.4 0

CETU2 0.09 0.11 0.22 0.18 0.18 0.22

CETU3 0.05 0.15 0.29 0.11 0.11 0.29

QP100 Cost

Alloc. $M

QP101 Cost

Alloc. $M

QP102 Cost

Alloc. $M

QP120Cost

Alloc. $M

QP121 Cost

Alloc. $M

QP122 Cost

Alloc. $M

CETU1 20 0 0 40 40 0

CETU2 18.18 21.82 43.64 36.36 36.36 43.64

CETU3 5.26 14.74 29.47 10.53 10.53 29.47

Cost $M

CETU1 100

CETU2 200

CETU3 100

Distribution Impact = MW x Distribution Factor

Impact Share = Distribution Impact/Total Impact

Cost Allocation = Cost x Impact Share


ISO-NE Public

• Studies for an IR that does not have an electrical interaction with the cluster (e.g., assume that QP 110 does not electrically interact with the cluster) can move forward independently

• An IR that does have an interaction with the cluster (e.g., QP 111) will assume that the CETUs and the MW from earlier queued eligible IRs in the CSIS are in its base case – The cluster proposal, as well as

moving the cluster forward, will allow projects like QP 111 to also move forward

11

How Are Non-Cluster Queue Positions Processed?

CETUs

AC Bulk Power System

QP100

QP120

QP121

QP122

QP101 QP102

QP111

QP110


ISO-NE Public

Al McBride S Y S T E M P L A N N I N G

Interconnection Queue Proposed Clustering Methodology

O C T O B E R 2 6 , 2 0 1 6 | W E S T B O R O U G H , M A

Transmission Committee


ISO-NE Public

2

Project Title: Interconnection Queue Clustering

Proposed Effective Date: Q1/Q2 2017

• ISO New England (ISO-NE) is proposing to incorporate a clustering methodology in the Interconnection Procedures

• The proposed clustering methodology will allow, under specific circumstances, for two or more Interconnection Requests (IRs) to be analyzed in the same System Impact Study (SIS) effort

• The IRs participating in a cluster would share cost responsibility for certain shared interconnection related transmission upgrades

• Design description memo issued to the Transmission Committee on September 20, 2016

• Design description presentation made to the Transmission Committee on September 27, 2016

• Suggestions by RENEW Northeast discussed at the Transmission Committee on October 11, 2016


https://www.iso-ne.com/static-assets/documents/2016/09/2016_09_27_tca06_clustering.pdf

https://www.iso-ne.com/static-assets/documents/2016/09/2016_09_27_tca06_iso_presentation.pdf

https://www.iso-ne.com/committees/transmission/transmission-committee

ISO-NE Public

3

Purpose of Today’s Presentation

• To discuss the comments received regarding ISO-NE’s proposal


ISO-NE Public

ISO-NE INTERNAL USE

ISO-NE PUBLIC

BACKGROUND Review

4


ISO-NE Public

5

Background

• The ISO-NE Interconnection Queue has experienced a persistent backlog of requests to interconnect in northern & western Maine

• Elsewhere in New England, the Interconnection Queue has proceeded well – On average, system impact studies are completed within a year of the

interconnection request

• All of the other ISOs/RTOs include some form of clustering in the interconnection process – Stakeholders have requested that ISO-NE investigate clustering – In response to an American Wind Energy Association (AWEA) petition,

FERC held a technical conference regarding interconnection issues in May 2016


ISO-NE Public

6

Addressing the Issues

• In 2015, ISO-NE began a two-phase discussion with Stakeholders to address these specific interconnection issues

• The first phase of the ISO-NE interconnection process improvements was approved by FERC in April 2016 (FERC Docket No. ER16-946-000) – Designed to make wind and other inverter-based generator projects

more “study-ready,” similar to conventional generators • Reactive performance requirements for wind generators • New technical data requirements for wind and inverter-based generators

• The second phase of interconnection process improvements focuses on how to address the identified infrastructure issues – This proposed clustering methodology – Maine Resource Integration Study


https://www.iso-ne.com/static-assets/documents/2016/03/a2_maine_resource_integration_study_scope_of_work.pdf

ISO-NE Public

7

A Note on The AWEA Petition*

• The AWEA Petition for Rulemaking argued for a number of interconnection process changes including: – Reforms to improve certainty in the study/restudy process – Requirements for timely and accurate studies and restudies – Limitations on restudies or the provision cost-certainty that would

eliminate the need for restudies – Requirements to provide cost estimate information earlier in the study

process – Requirements to standardize study costs – Reforms to improve transparency in the interconnection process – Reforms to improve certainty of network upgrade costs

• All of the above objectives would be harmed by the application of a poorly designed clustering methodology or by the unnecessary application or over-application of clustering

*FERC Petition of Rule Making: RM15-21-000


ISO-NE Public

8

Interactions with the Forward Capacity Market

• The procedures already include a form of an annual cluster study – A CNR Group Study is conducted as part of qualification for each

Forward Capacity Auction (FCA)

• Resources that enter the interconnection queue before the FCA Show of Interest deadline may apply to the FCA – Resources may have a completed System Impact Study, or, may have

just entered queue


ISO-NE Public

• In the FCM Group Study, requesting resources are studied in queue order and will be qualified for the FCA if needed upgrades can be completed in time – Later queued resources will

learn if their upgrades depend on the outcome for earlier resources

• Resources that obtain a Capacity Supply Obligation receive Capacity Interconnection Service – even if they clear before an earlier queued resource – “First-cleared, first served”

9

Interactions with the Forward Capacity Market, continued


New Resources


ISO-NE Public

10

Interactions with the Forward Capacity Market, continued

• The coordination of the interconnection process with FCM participation, while complicated for both ISO-NE and for participating resources, has been successful in allowing many projects to move forward

• The imposition of a (second) clustering methodology in all circumstances where there are new resources in proximity would over-complicate and impede FCM participation – Resources would have to await the outcome of the additional

clustering process before having sufficient information to participate in FCM

– Such a design would run counter to the competitive dynamic that is created under the current FCM Group Study design


ISO-NE Public

11

Objective of the Proposed Clustering Design

• Provide a mechanism to expedite interconnection processing in circumstances where ISO-NE determines that a backlog would be likely to persist with the continued application of the serial queue process – Do so without harming the overall efficient participation of new

resources in the Forward Capacity Market – Limit the likelihood of re-study – which is key to the success of the

clustering approach


ISO-NE Public

ISO-NE INTERNAL USE

ISO-NE PUBLIC

SUMMARY OF THE ISO-NE PROPOSAL

Review

12


ISO-NE Public

13

ISO-NE Proposal: Two-Phase Process

Phase 1

• Identification of cluster study trigger

• CETU Regional Planning Study

• Conducted in the Regional Planning Process (Attachment K)

• Scope and results presented and discussed with PAC

• 12 months best-efforts to complete

• Study will identify: • CETU Description

• MW Quantity enabled by the CETU

• Approximate cost of CETU and associated supporting upgrades

• Eligible Queue Positions

Phase 2

• Cluster System Impact Study

• Conducted under the ISO-NE Interconnection Procedures

• Cluster is filled in queue position order by eligible queue positions electing to participate

• Cluster Entry Requirements: • 5% Deposit of expected CETU and other

upgrades cost allocation responsibility – forfeited upon withdrawal (unless all withdraw)

• Site Control

• All Data and Models required for a system impact study



FEEDBACK REGARDING CUSTOMER COMMENTS The following slides provide feedback regarding the comments received on the ISO-NE proposal

14


ISO-NE Public

ISO-NE INTERNAL USE

ISO-NE PUBLIC

CLUSTER TRIGGER DESIGN

15


ISO-NE Public

16

Modification to Trigger Threshold

• In response to Stakeholder feedback, ISO-NE has modified the proposed threshold for the cluster formation trigger to include one or more new 115 kV or greater transmission lines

• ISO-NE is not proposing to use a cost threshold to trigger the cluster process – Costs estimates are not known until the end of the System Impact

Study – Some projects chose to pay (even relatively large) upgrade costs that

have been assessed for a given Interconnection Request under the serial queue construct

• ISO-NE is not proposing to introduce clustering in every circumstance where there are resources in proximity – As described earlier, this would run counter to the objectives of the

clustering design *October 11 RENEW Northeast TC Presentation – Slide 6


ISO-NE Public

17

Modification to ISO-NE Proposal: Cluster Trigger

• A cluster approach will be triggered by ISO-NE’s identification of the following circumstances in the ISO New England Interconnection Queue 1. There must be a backlog of two or more requests in the same part of

the ISO-NE transmission system 2. ISO-NE must have identified that none of the applicable

interconnection requests will be able to interconnect, either on an individual basis or as a cluster, without incurring significant transmission upgrades (i.e., one or more new 115 kV or above transmission line(s) or HVDC lines) • The ‘significant transmission upgrades’ shall be known as Cluster

Enabling Transmission Upgrades (CETU)

• ISO-NE will announce and discuss the creation of a given cluster with the PAC through the Regional Planning Process


ISO-NE Public

ISO-NE INTERNAL USE

ISO-NE PUBLIC

CETU REGIONAL PLANNING STUDY Additional Details

18


ISO-NE Public

19

Additional Details Regarding the Scope of the CETU Regional Planning Study

• In response to Stakeholder feedback* ISO-NE is providing additional details regarding the deliverables in the CETU Regional Planning Study (the Phase 1 study) – A study report will be posted to the PAC website providing:

• a planning level description of the CETU and an order-of-magnitude estimate, developed by the applicable Transmission Owner, of the costs for the CETU

• a list of other network upgrades that may be needed in addition to the CETU and an order-of-magnitude estimate, developed by the applicable Transmission Owner, of the costs for those upgrades

– the CRPS will not provide descriptions of expected Interconnection Facilities (e.g., the lead connecting the resource to the CETU) for specific Interconnection Requests in the cases where the Interconnection Facilities cannot be finalized until the actual Interconnection Requests that will be moving forward in the cluster is known

• the approximate megawatt quantity of resources that could be interconnected in a manner that meets the (i) Network interconnection standards and (ii) Capacity interconnection standards

• a list of the Interconnection Requests, by Queue Position that are identified as eligible to participate in the Cluster Interconnection System Impact Study

*October 11 RENEW Northeast TC Presentation – Slide 10


ISO-NE Public

20

Additional Details Regarding the Results of the CETU Regional Planning Study

• In response to Stakeholder feedback* ISO-NE is providing additional details regarding the review of the CETU Regional Planning Study (the Phase 1 study) – A review of the study report will take place at the Planning Advisory

Committee (PAC) – If necessary, discussions will take place at more than one PAC meeting



ISO-NE Public

21

The Updating of Points of Interconnection

• Additional discussion was requested* regarding the updating of Points of Interconnection (POI)

• The updating of POIs is already provided for under today’s procedures – no further change is required – Section 7.2 of the current LGIP

» If the Interconnection System Impact Study uncovers any unexpected result(s) not contemplated during the Scoping Meeting … a substitute Point of Interconnection identified by the System Operator, Interconnection Customer, Interconnecting Transmission Owner, or any Affected Party as deemed appropriate by the System Operator in accordance with applicable codes of conduct and confidentiality requirements, and acceptable to each Party, such acceptance not to be unreasonably withheld, will be substituted for the designated Point of Interconnection specified above without loss of Queue Position …



ISO-NE Public

ISO-NE INTERNAL USE

ISO-NE PUBLIC

CLUSTER PARTICIPATION Feedback on Stakeholder comments regarding “opt-in”, “step-aside” & “off-ramps”

22


ISO-NE Public

23

At the Beginning of Phase 1: Assume All Queue Positions Seek to Proceed

• The proposed Phase 1 process will not seek expressions of interest from a subset of the area queue positions* – It is assumed that all of the Interconnection Requests in the queue

intend to proceed toward interconnection – Unlikely that projects will know they are ready to move forward 12

month before the completion of the Phase 1 CETU Regional Planning Study

– Such expression of interest would not be binding and projects could change their decision

• ISO-NE will develop the scope of the (Phase 1) CETU Regional Planning Study based on the Interconnection Requests that are located in the same part of the ISO-NE transmission system



ISO-NE Public

24

Eligible Projects May Not Refuse to be Clustered

• Once the cluster provisions have been triggered, eligible projects may not refuse to be considered within the cluster study – Including in cases where an IR’s serial System Impact Study is already

underway

• Refusing to be clustered would block the progress of the interconnection process for all other eligible projects

• Conversely, an Interconnection Request with a completed System Impact Study may not elect to join a cluster – The interconnection study phase is complete for such a project



ISO-NE Public

25

Choices at the Beginning of the Phase 2 Study

• In response to Stakeholder feedback* ISO-NE is providing additional details regarding the entry into the Cluster SIS

• All eligible Interconnection Requests that are located in the same part of the ISO-NE transmission system will be identified in the Phase 1 CETU RPS study report

• By the Cluster Entry Deadline, eligible projects will have the following choices: 1. Enter the cluster 2. Move to the bottom of the queue in the same relative queue order as other

eligible projects that make this choice (no new $50,000 Interconnection Request deposit)

3. Withdraw the Interconnection Request, and receive a refund of the unspent portion of the $50,000 IR deposit



ISO-NE Public

ISO-NE INTERNAL USE

ISO-NE PUBLIC

CLUSTER WITHDRAWAL Off Ramps

26


ISO-NE Public

27

CPD Refundable if Cluster Initially Undersubscribed

• In response to Stakeholder feedback* ISO-NE will include a provision whereby the initial Cluster Participation Deposit is refundable, upon withdrawal, following the determination that the cluster is initially undersubscribed as indicated by IR participation immediately following the cluster entry deadline – E.g., If the cluster was developed to enable 1,000 MW and only 500

MW met the cluster entry requirements, then, before the commencement of the Cluster SIS, projects may withdraw and receive refund of the CPD

– Such a process may required multiple iterations before stasis is reached and the CSIS can start



ISO-NE Public

28

CPD Refundable if Cost Estimate Changes Significantly

• In response to Stakeholder feedback* ISO-NE will include a provision whereby the Cluster Participation Deposit is refundable upon withdrawal when the total cost of the CETU and network upgrades for the cluster has increased by a given percentage – Seeking feedback from the Transmission Committee regarding the

appropriate percentage



ISO-NE Public

29

No Additional Deposit at the End of the SIS

• The proposal will not require an additional Cluster Participation Deposit* at the end of the Cluster System Impact Study – Sufficient commitment from the initial CPD at cluster entry and the

additional CPD that follows the Cluster Facilities study



ISO-NE Public

ISO-NE INTERNAL USE

ISO-NE PUBLIC

FORM OF DEPOSITS

30


ISO-NE Public

31

Why is the Cluster Participation Deposit Required?

• The initial CPD is required to demonstrate commitment to proceeding towards interconnection – Because it will include more than one project, the cluster study is

dependent on more than one project moving forward • Projects in the cluster need assurance that the other cluster projects are also

moving forward

• The additional CPD is required before entering the Interconnection Agreement phase so that there is reassurance of commitment to move forward before developing all of the Interconnection Agreement details

• Unless forfeited, the initial and additional CPD (including any additional reallocations) are returned following the payment of the cost responsibility deposit required by the Interconnection Agreement


ISO-NE Public

32

Cluster Participation Deposits

• The proposal will require that Cluster Participation Deposits are in the form of cash, consistent with other deposits provided to ISO-NE in the interconnection process – This is necessary to ensure commitment to completing the cluster



ISO-NE Public

33

Deposits Due with Interconnection Agreement

• In response to Stakeholder feedback* the proposal will call for 20% (instead of the initially proposed 100%) of the total upgrade costs to be provided in the form of cash to the Transmission Owner(s) upon execution of the IA – Once paid, ISO-NE will return the initial and additional CPDs (including

any additional reallocations) to the IRs with executed IAs



ISO-NE Public

ISO-NE INTERNAL USE

ISO-NE PUBLIC

CLUSTER SYSTEM IMPACT STUDY

34


ISO-NE Public

35

Application of the Network Capability Interconnection Standard*

• Detailed examples regarding the application of the Network Capability Interconnection Standard (“minimum interconnection standard”), in the context of clustering, will be provided at the November 16, 2016 PAC meeting as part of the discussion of the Maine Resource Integration Study



ISO-NE Public

• Studies for an IR that does not have an electrical interaction with the cluster (e.g., QP 110 – assume that it does not electrically interact with the cluster) can move forward independently

• An IR that does have an interaction with the cluster (e.g., QP 111) will assume that the CETUs and the MW from earlier queued eligible IRs in the CSIS are in its base case – The cluster proposal, as well as

moving the cluster forward, will allow projects like QP 111 to also move forward

36

How Are Non-Cluster Queue Positions Processed?

CETUs


QP100

QP120

QP121

QP122

QP101 QP102

QP111

QP110


ISO-NE Public

37

CETU is Not Redesigned During SIS

• ISO-NE will develop the Phase 1 CETU Regional Planning Study by studying the ranges of MW in the Interconnection Queue – As such, the CRPS may include CETU solutions that are based upon the

total MWs of eligible projects expected to enter the CSIS – See example of the Maine Resource Integration Study

• Recall that, according to the trigger design, all of the eligible projects in the cluster require new enabling infrastructure

• Therefore, it will not be necessary to redesign the CETU during the SIS if an eligible project withdraws*



ISO-NE Public

ISO-NE INTERNAL USE

ISO-NE PUBLIC

PARTICIPATION OF ELECTIVE TRANSMISSION UPGRADES

38


ISO-NE Public

39

Can Elective Transmission Upgrades Participate in the Cluster?

• Elective Transmission Upgrades (ETUs) can participate in the cluster in Queue Position order – External ETUs can be considered as eligible projects

• Participate in the same way as generators • Requested import and export capability are recognized

– Internal ETUs can be considered as eligible projects and/or potential CETU solutions* • An ETU will only be considered in the place of a CETU for the cluster in the

case where all of the eligible projects in the cluster that need to use the CETU have made a contractual commitment to pay for the ETU



ISO-NE Public

ISO-NE INTERNAL USE

ISO-NE PUBLIC

INTERCONNECTION UPGRADE COST ALLOCATION

40


ISO-NE Public

41

ISO-NE Proposal: Upgrade Cost Allocation

1. Direct allocation of direct-connect costs • e.g., the generator lead that would connect the generator to the CETU

2. CETUs will be allocated to each cluster project by MW ratio share • e.g., if a $500 million CETU enables the interconnection of 500 MW of

resources, then a 100 MW project in the cluster would be allocated a CETU contribution cost of $100 million

3. Network upgrades (other than the CETU(s)) will be allocated to each project in the cluster by MW ratio share • e.g., if the re-conductoring of an existing line costs $50 million and there are

500 MW of resources in the cluster, then a 100 MW project would be allocated a cost of $10 million

4. All upgrade costs paid by Interconnection Customers in the cluster • No regional or local rate-payer support for interconnection upgrades


ISO-NE Public

42

Why Use Upgrade Cost Allocation on a Per-MW Basis?

• The methodology hinges on “enabling” upgrades – None of the projects could interconnect without the enabling

upgrades – The amount of generation that the upgrades can enable will be limited

by MW


ISO-NE Public

• The distribution factor (DFAX) is the measure of responsiveness or change in electrical loading on system facilities due to a change in electric power transfer from part of the electric system to another, expressed in per cent of the change in power transfer

• Example:

43

For Discussion: Alternative Cost Allocation


CETU 1

QP100

QP120

QP121

QP122

QP101 QP102

CETU 2

CETU 3

DFAX (%)

QP100 QP101 QP102 QP120 QP121 QP122

CETU1 100 0 0 100 100 0

CETU2 50 30 30 50 50 30

CETU3 50 70 70 50 50 70


ISO-NE Public

44

For Discussion: Alternative Cost Allocation, Continued

• The individual distribution impact will be calculated by multiplying the distribution factor by the MW size of the Interconnection Request

• The total distribution impact for the upgrade will be calculated as the sum of all of the individual distribution impacts

• The upgrade cost responsibility for an entity included in the cluster would be the total cost of the upgrade multiplied by the ratio of the entity’s individual distribution impact divided by the total distribution impact for the entire cluster


ISO-NE Public

45

For Discussion: Late Comer Provision

• Would apply only to CETUs and their costs – not other upgrades – Because of the expected investment in, utilization of and importance of CETUs

• Late Comer Projects (LCPs)* are IRs being placed into commercial operation within 5 years of the commercial operation of the CETU. The obligation to reimburse a share of the CETU costs would be conditional on the following for the LCP:

1. Connects directly to the CETU; or 2. Connects to a substation where the CETU terminates; or 3. Has an impact on the CETU that is greater than 5% of the CETU normal rating or

has a distribution factor on the CETU that is ≥ 20% using the distribution factor methodology described above

• Late Comer Projects would reimburse, to the other cluster projects and LCPs that have contributed to the payment of the CETU, the corresponding reduction in CETU costs (including depreciation, ARR compensation, LCP payments, other) for those other cluster projects and LCPs that would have occurred if the LCP had participated in the original CETU cost determination – Assessment utilizes the LCP’s individual/cluster SIS model to determine cost

allocation – May need to be modified based on the cost allocation selected (slide 45 vs 47)



ISO-NE Public

46

Conclusion & Next Steps

• ISO-NE has incorporated many of the suggestions made by Stakeholders on the clustering design

• November Transmission Committee – Tariff redlines – Any stakeholder alternative redlines (see memo to the Transmission

Committee dated October 21, 2016)

• December Transmission Committee – Vote on tariff redlines – Any stakeholder amendments (see memo to the Transmission

Committee dated October 21, 2016)

• January 2017 – NEPOOL Participants Committee vote – FERC filing


ISO-NE Public

Al McBride a m c b r i d e @ i s o - n e . c o m

47



APPENDIX Previously presented description of the ISO-NE proposal

48


ISO-NE Public

49

Why Does the Design Have Two Phases?

• The first phase (the CETU Regional Planning Study) provides a significant amount of information to Interconnection Customers regarding the infrastructure needed and costs – Interconnection Customers can decide to move forward or not

• As a comparison: – The California ISO methodology also includes two primary phases –

with increased commitment required to enter the second phase – The Tehachapi Renewable Transmission Project was effectively carried

out in two phases • The first phase was conducted in the regional planning process • The second phase was conducted in the interconnection process


ISO-NE Public

50

ISO-NE Proposal: Withdrawal, Re-study, Backfill & Oversubscription

• An additional 5% Cluster Participation Deposit is required to move from the Facility Study phase to the Interconnection Agreement phase

• Cluster Participation Deposit(s) forfeited upon withdrawal – Divided among remaining cluster participants on a per-MW basis – All deposits returned if everyone withdraws

• Cluster is re-studied if there is a withdrawal – Cost responsibilities updated – Later-queued eligible projects can enter the cluster (backfill) if there is a

withdrawal (which could mitigate the need for a re-study)

• If a cluster is oversubscribed (more eligible projects remain in the queue than can ultimately be accommodated by the CETU), then another CETU Regional Planning Study will be commissioned – First round of eligible projects proceed with the first CETU cluster study – Process is repeated for second round of eligible projects – with a second

CETU cluster study


ISO-NE Public

51

What is the Proposed Transition?

• The current Maine Resource Integration Study will form the basis of the first cluster study – It will provide the:

• CETU(s) Description • MW Quantity enabled by the CETU(s) • Approximate cost of CETU(s) and associated supporting upgrades • Eligible Queue Positions

– Interconnection Requests in the interconnection queue located in the relevant portions of Northern and Western Maine that do not have a completed System Impact Study by the effective date of the clustering methodology will be considered as eligible resources

– The CSIS entry deadline will be 30 Calendar Days after the later of the effective date of the clustering methodology or the issuance of the final Maine Resource Integration Study report


ISO-NE Public

52

What will not change?

• The current “default” serial interconnection process and cost allocation methodology will continue for all queue positions, unless they participate in a cluster

• The addition of the proposed cluster methodology in the Interconnection Procedures will not change the existing service products that result from the interconnection processes – Resources meeting the applicable procedural milestones will continue to be eligible to

request and receive Network Resource Interconnection Service, or Network Import Capability Interconnection Service in the case of eligible external ETUs, and Capacity Network Resource Interconnection Service, or Capacity Network Import Capability Interconnection Service in the case of eligible external ETUs

• Finally, there will be no changes to the existing dispatch, market and OATT structures within the ISO-NE Tariff – No introduction of firm reservations, grandfathering or point-to-point rights over the

any Pool Transmission Facilities, including those that are built/upgraded as a result of the cluster or serial SIS processes

– Internal transmission facilities, regardless of categorization for rate purposes, will be operated/scheduled by ISO-NE without recognition of physical transmission rights

– No change to the FCM milestones or procedures – Requested CTRs and ARRs will be allocated for system upgrades as appropriate in

accordance with existing rules


Francis Pullaro Executive Director

Voice: 646-734-8768 Email: [email protected]

Web: renew-ne.org

Q&A on RENEW Northeast Amendment to ISO New England Cluster Study Process

January 27, 2017

1. The RENEW proposal imposes a mandate on the states.

False. The RENEW proposal gives the states a free option to: a) Receive additional information from ISO on the effectiveness of transmission alternatives

for use in state RFP evaluations b) Coordinate the timing of the ISO cluster study process with the timing of state RFP

decisions c) Require the ISO plan for use of an alternative transmission solution if selected in a state

RFP, and d) Use a pre-approved FERC method for the EDC to fund cluster upgrades if a contract for

such funding has resulted from a state RFP and requires FERC approval. All of these are options available to the states under the RENEW proposal. None are required and none are options under the ISO proposal.

2. The RENEW proposal poses risks to the states. False. Again, the RENEW proposal places no obligations on the states. It still allows the states to manage generation project risks through terms in PPAs as has been the case in past RFPs. Developers are still required to post security deposits to enter the Cluster Study even if EDCs commit to funding interconnection upgrades.

3. The RENEW proposal is “not essential” for giving states certainty of the ability to the fund the cost of network upgrades needed for clean energy generation bidding into state RFP.

False. Under the bid category of a “PPA with the Transmission Project under FERC Tariff” that was available in the tristate RFP, any transmission upgrades needed to deliver the energy was priced separately from the energy and the recovery of associated costs was to be through a FERC filed tariff (in addition to any state statute requiring approval by its utility commission). The RENEW proposal is necessary to provide certainty on the viability at FERC of this funding approach by having the concept placed into FERC pre-approved Tariff covering the cluster study process and payments.

4. The states can avoid FERC approval altogether if they use only the bid category requiring generators to include the cost of the new transmission in its bid for a PPA

True, but the bid category “PPA with the Transmission Project under FERC Tariff” gives the soliciting parties more control and greatly increases the likelihood transmission and generation projects will get built. If bundled within the PPA bid, a generator must assume what its share of cluster-related upgrade costs will be, with no knowledge of which projects will ultimately be selected in the RFP (and subsequently join the cluster). If the RFP selects fewer cluster projects than assumed, the generator’s share of upgrade costs will increase. This could cause the winning bidders to forfeit their PPAs, in turn leaving the states without projects fulfilling RFP needs. By contrast, if the transmission costs were kept separate from the generator bids, this would allow the RFP evaluation team to have control over the total, all-in cost of the generation and transmission as it would be selecting which projects to award contracts with full knowledge of the associated upgrade costs for that set of generation.

5. The RENEW proposal allows NESCOE to approve transmission upgrades and bind

the states to paying for them.

False. In the previous RENEW language developed in collaboration with NESCOE and several states, NESCOE might have communicated certain information to the ISO on behalf of a state. However, as requested by NESCOE at the January 24 Transmission Committee meeting, this been eliminated, leaving only the governor or state executive agencies with the ability to provide informational (and still non-binding) notices to ISO. RENEW has and will continue to defer to the states on how to construct the language involving the parties that can inform the ISO.

Under the RENEW proposal, only a state EDC a) with a contract in place with the interconnection customer obligating it to fund the cluster upgrades and b) that also becomes a party to the Interconnection Agreement at the end of the interconnection process would be bound to fund the upgrades. NESCOE is not involved in the selection or funding of upgrades.

6. Without the RENEW proposal, if future generation or energy import projects

utilize as part of their interconnection plans a competitively-selected transmission upgrade that was originally funded by a state to further its policy goals, that state can recover costs from those later projects (e.g. if they do not serve the state’s policy goals or if they receive a PPA with another state).

False. The RENEW proposal provides that Late Comer Projects using the headroom from a CETU cluster upgrade or ETU that has taken the place of a CETU must pay for their share of the headroom used as they connect. The ISO requires Late Comers to pay their fair share of only the CETU (the ISO-identified, incumbent-built solution), not of the ETU (competitive solution in place of the CETU). The ISO proposal lets Late Comers to state funded competitive transmission projects become free riders at the expense of ratepayers in the EDCs host state.

7. The RENEW proposal unnecessarily delays the interconnection process for small projects not requiring significant upgrades.

False. The RENEW proposal, identically to the ISO proposal, allows existing interconnection requests that are not eligible for the initial Maine cluster, because they do not require major interconnection upgrades, to move to the top of queue when the initial cluster collapses. A cluster will collapse as a result of the cluster-eligible projects not posting cluster participation deposits because they do not yet have PPAs. The RENEW proposal neither changes the likelihood of this occurring this spring nor delays its timing.

8. The RENEW proposal unnecessarily delays the overall cluster interconnection process.

False. Once the ISO begins restudying the cluster following the collapse described in Question (7), one or more states could request that ISO’s new Planning Study include evaluation of one or more competitive transmission solutions if they have an ongoing competitive procurement process in which the competitive transmission solution is participating. After the ISO completes this Planning Study, RENEW has allowed the states to postpone the opening of the window in which generators may elect to enter the Cluster Study process by up to five months if there is an ongoing competitive procurement process considering projects eligible to join the cluster and/or competitive transmission solutions. The up to five-month postponement is necessary to allow consideration by the RFP evaluation team of the results of the final Planning Study against generation and transmission bids in a pending RFP. As it is likely that no Cluster Study will form without state support from PPAs and transmission, this delay during the pending RFP evaluation is not unreasonable.

9. The ISO proposal allows for competition for needed network upgrades.

Nearly False. The states would have the ability to pick a solution and contract to pay for it, but the ISO would still require the generators in the cluster to build and pay for the ISO-identified, incumbent-built solution unless every project entering the cluster was able to show a contractual arrangement in place with the competitive transmission solution prior to submitting the Cluster Study agreement to the ISO. This is a threshold that would be extremely difficult to achieve under the timeline required in the ISO’s proposal. The RENEW proposal injects competition for transmission into the cluster process by allowing more competitive proposals to be considered by the states and requiring the ISO to recognize and utilize a transmission solution in the cluster process if it was selected in a state procurement process.

10. The RENEW proposal helps ratepayers in addition to offering competition.

True. The RENEW proposal gives states the option to have transmission be amortized and depreciated over its long useful life instead of consumers paying for the cost over a shorter time period defined by the term of a generator PPA (e.g., if the state expects the upgrade to provide benefits beyond the PPA duration).

11. The RENEW proposal requires that EDCs funding cluster interconnection upgrades recover their costs over a 40-year period.

False. This would be possible, as described in Question (10), but if a state and EDC preferred to have the transmission costs fully recovered during the lifetime of a generator’s PPA, this would still be an option. The RENEW proposal does not change or attempt to dictate how a state would run its competitive procurement process or how it would structure the resulting contracts. It only seeks to harmonize the ISO cluster study process with the state process to enable various options the states may want to utilize.

12. The RENEW proposal makes an end-run around the MOPR by reducing the apparent interconnection costs

False. The ISO Internal Market Monitor (IMM) has confirmed that under the existing Minimum Offer Price Rule, new resources would have to indicate which project cash flows are supported by a regulated rate (i.e., are "Out of Market"). The IMM considers the cost of interconnection to be a type of project cash flow, and if an EDC were funding interconnection costs as a result of a state RFP as contemplated as a possibility in the RENEW proposal, the IMM in its evaluation would replace this with the "In Market" cash flow which would be the new resource funding its entire share of interconnection upgrades. Thus, there would be no impact on a new resource’s Minimum Offer Price if an EDC were funding its interconnection costs.

Distribution Utility Funding Process for ClusterRelated Interconnection Upgrades

1

January 24, 2017

NEPOOL Transmission Committee

About RENEWAn association of the renewable energy industry and environmental advocates

united to promote renewable energy in New England and New York. The comments expressed herein represent the views of RENEW and not necessarily those of any

particular member of RENEW.

2

Overview of RENEW Proposal

(1) Integrates competitive state solicitation for transmission upgrades and energy into ISO cluster process;

(2) Injects more competition for transmission into cluster process; and

(3) Enables states through their EDCs opportunity to fund one or more generators’ share of the Cluster Enabled Transmission Upgrade (CETU), which is incumbent-built, or an Elective Transmission Upgrade (ETU), which can include a non-incumbent, in place of a CETU, under a cluster process approved by FERC.

3

Cluster & Procurement Processes

ISO Proposal

Start: ISO sends Notice of Initiation of Cluster and CRPS to Planning Advisory Committee (PAC)

End: ISO submits final CRPS report to PAC

Esti

mat

ed 1

2 m

on

ths

RENEW Proposal

1 m

on

th Cluster System Impact Study (CSIS) Entry Window

Start: CSIS

During CRPS: States submit statement to ISO that CETU or ETU supports state need; makes request for CRPS to analyze any CETU alternatives

Esti

mat

ed 1

2 m

on

ths

End: ISO submits final CRPS report to PAC that includes analysis of CETU alternatives

5 m

on

th li

mit

Soliciting parties evaluate clean energy and transmission proposals including CETU and ETU alternatives with CRPS report

ISO submits RFP results to PAC

Cluster System Impact Study (CSIS) Entry Window

1 o

r 2

mo

nth

s

Start: CSIS

State RFP

Esti

mat

ed 1

2 m

on

ths

Cluster Regional Planning Study (CRPS)

RFP issued

Soliciting parties evaluate clean energy and transmission proposals including CETU and ETU alternatives

RFP results submitted to ISO

PPAs and/or transmission agreements signed

2 m

on

ths

Bids due

CETU/ETU Legal Relationships

5

CETU/ETUDeveloper

Generator

ISO/TO EDCs

InterconnectionAgreement

InterconnectionAgreement

Benefits for States1. Tariff mechanism, FERC approved, increases efficiency and provides

information on network upgrade needs and costs by meshing timing of state competitive procurement with cluster process;

2. Injects more competition for transmission into cluster process by allowing more ETU proposals to be considered;

3. Allows the capitalized CETU, or ETU in place of the CETU, to be amortized and depreciated over its long useful life instead of consumers paying for the cost of the CETU, or ETU in place of the CETU, over a shorter time period defined by the term of a generator PPA;

4. Reduces the risk of the winning bidders ultimately forfeiting their PPAs due to altered CETU cost allocation after RFP selections are made; and

5. Developers still required to post security deposit to enter Cluster System Impact Study even if EDCs commit to funding interconnection upgrades.

6

memo

ISO-NE PUBLIC

iso-ne.com isonewswire.com @isonewengland

iso-ne.com/isotogo iso-ne.com/isoexpress

ISO New England Inc. One Sullivan Road Holyoke, MA 01040-2841 413-540-4223 [email protected]

To: New England Power Pool Participants Committee

From: Alan McBride, Director, Transmission Strategy & Services

Date: February 1, 2017

Subject: ISO-NE Response Regarding RENEW Amendment

At the February 3, 2017 meeting, ISO New England Inc. (the “ISO”) will be asking the Participants Committee to provide advisory input on the ISO’s proposed revisions to Sections I and II of the ISO New England Inc. Transmission, Markets and Services Tariff (“ISO Tariff”) to incorporate a locational specific clustering methodology in the Interconnection Procedures (the “Clustering Revisions”). The Clustering Revisions provide the mechanism to expedite interconnection processing in circumstances where a backlog resulting from a lack of significant infrastructure would be likely to persist with the continued application of the serial queue process. At the February 3 meeting, the Participants Committee will also be asked to consider RENEW’s proposed amendments to the ISO’s Clustering Revisions. The ISO provides this memorandum to explain its reasoning for not supporting RENEW’s proposal to insert a sate procurement process into the ISO New England interconnection process.

First, the RENEW proposal is unnecessary as the ISO’s Clustering Revisions already provide a mechanism for the states to provide input to the ISO. Specifically, the Clustering Revisions incorporate into the ISO New England interconnection process a two-phased clustering methodology, the first phase of which provides for the identification of the projects that may be eligible to participate in a cluster study, the infrastructure needed to interconnect the projects and the associated costs in an open and transparent forum – the Regional System Planning Process. The states, and any other interested stakeholder, can take an active role in that phase of the process and inform the ISO of its views on the infrastructure and even identify other solutions for the ISO’s consideration. The outcome of the first phase of the clustering process can be used to inform the state selection process taking place outside of the interconnection process, and those projects that are selected, may elect to move forward, in that case having the certainty of underlying state-sponsored power purchase agreements. Additionally, a state or electric distribution company is already able to commit to pay any or all of an interconnection project’s costs outside of, and without causing a delay to, the interconnection process.

Second, the ISO’s interconnection process is regulated by the Federal Energy Regulatory Commission (“the Commission”) under the principles of open transmission access whereby those public utilities that offer transmission services must offer nondiscriminatory, standardized interconnection service. However, as RENEW explains in the materials provided for the Participants Committee meeting, the RENEW proposal provides for the insertion of state procurement processes into the ISO’s interconnection process. More specifically, the RENEW proposal would require the ISO to delay the cluster study process to allow for the conduct of a portion of a state procurement process, in which the state may be considering, with no obligation to purchase, some of the projects that may be identified as eligible to participate in a cluster. In


Participants Committee February 1, 2017 Page 2 of 2

ISO-NE PUBLIC

iso-ne.com isonewswire.com @isonewengland

iso-ne.com/isotogo iso-ne.com/isoexpress

ISO New England Inc. One Sullivan Road Holyoke, MA 01040-2841 413-540-4223 [email protected]

addition, instead of the ISO identifying the upgrades required to interconnect, the proposal would obligate the ISO to evaluate and use transmission solutions that are selected by one or more states through the state procurement process for the interconnection of the selected projects regardless of whether or not those transmission solutions are available to all area projects that are seeking to interconnect to the system.

As a practical matter, the proposed insertion of a state procurement process into the interconnection process will introduce significant delays, uncertainties and costs into the interconnection process, thereby aggravating the very concerns that have been raised by RENEW in the past. The proposal would be harmful to other projects that are identified as eligible to participate in a cluster, but are not pursuing the same or any state procurement process as a funding source, as well as to those projects outside of the cluster, including lower-queued small projects, that will be delayed because they depend on the certainty of the cluster.

For these reasons, the ISO cannot support the RENEW proposal.


www.avangrid.com 1

Paul Dumais

Transmission Committee Proposal

January 24, 2017

Interconnection

Clustering – Cost

Recovery of

Transmission

Upgrades

https://www.iberdrola.es/

www.avangrid.com 2

Purpose: Discuss changes to the Transmission Owner cost recovery proposal for CETUs, cluster-enabled

Network Upgrades and other significant Interconnection Network Upgrades

Agenda:

1. Proposal - January 11 meeting

2. January 11 Feedback and AVANGRID Response

3. Payment option scenarios

4. Tariff Changes

TIME: 90 Minutes

Table of Contents


www.avangrid.com 3

Principles

1. Typical generator interconnections are limited in scale and scope (generally

lines to connect into transmission network) and current practices is that they

are 100% paid by developer. The NETOs recover ongoing O&M costs monthly

under the IA based upon current transmission formula rate information.

2. The scale and scope of CETUs and Network Upgrades from the Maine Cluster

Study (and future Cluster studies) would be a size and magnitude significantly

beyond that of typical generator interconnections. The CETUs and Network

Upgrades would be additions to the Bulk Electric System that are identified as

part of a regional planning process. These upgrades will require significant

NETO resources to manage, plan, design, site, procure and construct and

could present substantial challenges to the execution of NETO capital

investment plans

3. Therefore, Avangrid considers it critical that an appropriate ratemaking

mechanism is in place for CETUs and cluster related Network Upgrades,

similar to that in place for Reliability Benefit Transmission Upgrades but

charged to the interconnecting customer and not load customers. Avangrid

also proposes to extend this treatment to significant Network Upgrades

resulting from non-cluster interconnections


www.avangrid.com 4

Proposal on January 11

1. Applies to: a. CETUs and Network Upgrades identified under clustering; and

b. Significant Network Upgrades for non-cluster system impact studies

(equal to or greater than $100 M).

2. Interconnecting customers have two options for paying for upgrades

described in Item 1 above: a. Pay net present value of revenue requirement of cost of upgrades in

advance, recognizing value brought by TO; or

b. TO funds upgrades and interconnecting customer pays over time

using revenue requirement construct for Pool Transmission Facility

Reliability Benefit Upgrades (Attachment F).

c. This optionality consistent with current FERC proposal contained in

recent Notice of Proposed Rulemaking on Interconnection Reforms

(RM17-8-000)


www.avangrid.com 5

Feedback from January 11 TC Meeting With AVANGRID Revisions

Feedback AVANGRID January 24 Revisions

Upfront payment should not include NPV of 40 year revenue requirement (about 20% over costs). Desire to keep upfront payment option that exists today.

Costs plus an appropriate markup (to be negotiated) - similar to EPC construct. Markup recognizes value provided by TO for these substantial upgrades. Interconnecting Customer has option to build CETUs in accordance with TO standards, approved contractors and oversight (and turn over facilities for TO ownership and maintenance).

Credit support as proposed for pay over time option is expensive

Credit support during construction same as today. Once interconnecting customer facilities in commercial operation, credit support for rolling five years of payments )

Pay over time period can vary depending on customer specific situation. And NPV construct may not pick up changes due to income taxes or ROE

Investment recovery period of 20 years unless other recovery period mutually acceptable. Calculations point to regional formula rate where returns and income taxes change over time


www.avangrid.com 6

TO Builds - Pay Upfront – Revised Proposal

1. Negotiated markup over costs, recognizing the value brought by the

interconnecting TO:

a. Interconnecting customer pays for O&M same as today;

b. The amount of markup not credited to Attachment F or Schedule 21;

c. Deposits and credit requirements same as today.


www.avangrid.com 7

TO Builds - TO Funds and Interconnecting Customer Pays Over Time - Revised Proposal

1. TO funds upgrades and interconnecting customer pays over 20 year period using

revenue requirement construct in Attachment F with 20 year investment depreciation

a. 20% deposit still required from interconnecting customer and TO will refund

upon commercial operation;

b. TO to recover investment over 20 years using Attachment F, excluding O&M

elements and with depreciation of investment over 20 year. TO and

interconnecting customer can negotiate different recovery period depending on;

i. Term of any contract that interconnecting customer has to sell its service;

ii. Credit worthiness of interconnecting customer; and

iii. Other items as appropriate.

2. Interconnecting customer pays for O&M same as today; and

3. Revenue received by TO to be credited to Schedule 21, where investment and

costs reside.


www.avangrid.com 8

TO Builds - TO Funds and Customer Pays Over Time – Credit Requirements

1. TO will require security during construction – same as today; and

2. Once interconnecting customer facilities in commercial operation,

TO requires security for rolling five years of payments.


www.avangrid.com 9

Summary - Options For Interconnecting Customers

1. TO build upgrades and IC pays upfront;

2. TO builds upgrades and IC pays over 20 years;

3. IC builds upgrades.


www.avangrid.com 10

Provisions for Competition in Clustering

1. Generators in cluster can partner with transmission developer and

have an Elective Transmission Upgrade (ETU) as all or some of

CETUs (ISO-NE proposal);

2. State can opt-in with results of RFP and have ISO-NE study

ETU(s) from RFP process as all or some of CETUs (RENEW

Northeast proposal); or

3. Interconnecting customer has option to build CETUs (AVANGRID

proposal here and being considered in FERC Interconnection

Notice of Proposed Rulemaking).


www.avangrid.com 11

Review Scenarios

1. Refer to separate analysis


www.avangrid.com 12

Tariff Revisions

1. Definitions

2. Schedule 11

3. Schedule 22 and IA




www.avangrid.com 13

Treatment of Cluster-like Transmission Upgrades in other

Regional Transmission Organizations


www.avangrid.com 14

Treatment in Other RTOs

1. CAISO: permits interconnection facilities to be eligible for regional

recovery (like RBTUs in NE) if the network upgrades meet the following

criteria:

a. The Network Upgrades consist of new transmission lines 200 kV

or above, and have capital costs of $100 million or greater;

b. The Network Upgrade is a new 500 kV substation that has capital

costs of $100 million or greater; or

c. The Network Upgrades have a capital cost of $200 million or

more.

CAISO tariff permits regional recovery (like RBTUs in NE) of public policy-

driven transmission solutions designed to facilitate delivery of energy to

meet state RPS.


www.avangrid.com 15

Treatment in Other RTOs

2. SPP: direct assignment facilities for standard interconnections – customer

pays (like NE). For Network Upgrades related to an interconnection,

included in transmission revenue requirements and all or a part is eligible

for regional cost allocation (like RBTUs in NE) and the rest included in local

rates (like Local RBTUs in NE).

a. Direct Assignment Upgrade Costs are:

i. Paid as a lump-sum; or

ii. Paid as periodic charges - payment equal to NPV of the annual

revenue requirements over a 20 year plant life (using the levelized

fixed charge rate, based on full depreciation over a 20 year plant

life and including operating and maintenance expenses and any

applicable tax consequences)

3. MISO: standard interconnections – customer pays (like NE). For

upgrades to deliver energy in support of public policies are called Multi-

Value Projects and are included in regional transmission rates (like RBTUs

in NE)


Large Generation Interconnections

TO Build - Today and Two CETU Options

Comparison Today Today - O&M Option A Aotion A - O&M Option B Option B - O&M

Current Approach with

Interconnections - Pay

for construction as it

occurs

Annual O&M

and Property

Tax payments

Proposed Option

A - Pay for

construction as it

occurs

Annual O&M

and Property

Tax payments

Pay annual

revenue

requirement

over 20 years

Annual O&M

and Property

Tax payments

Capital Expenditure (1)500 500 500

Financing (AFUDC rate) 5.0%

Capitalized Asset 500$ 500$ 536$

Utility Margin Adder 0.0% 10.0% 0.0%

Total Expenditure 500$ 800$ 550$ 800$ 1,110$ 800$

O&M % 4.0% 4.0% 3.7%

Present Value (Yr-4) @ 10.0% 374$ 134$ 411$ 134$ 379$ 134$

Construction cost timing:

Year -3 5% 25$ -$ 28$ -$ -$ -$

Year -2 17% 85$ -$ 94$ -$ -$ -$

Year -1 43% 215$ -$ 237$ -$ -$ -$

Year 0 35% 175$ -$ 193$ -$ -$ -$

Year 1 20$ 20$ 87$ 20$

Year 2 20$ 20$ 84$ 20$

Year 3 20$ 20$ 80$ 20$

Year 4 20$ 20$ 77$ 20$

Year 5 20$ 20$ 73$ 20$

Year 6 20$ 20$ 70$ 20$

Year 7 20$ 20$ 66$ 20$

Year 8 20$ 20$ 63$ 20$

Year 9 20$ 20$ 60$ 20$

Year 10 20$ 20$ 56$ 20$

Year 11 20$ 20$ 53$ 20$

Year 12 20$ 20$ 50$ 20$

Year 13 20$ 20$ 46$ 20$

Year 14 20$ 20$ 43$ 20$

Year 15 20$ 20$ 40$ 20$

Year 16 20$ 20$ 37$ 20$

Year 17 20$ 20$ 35$ 20$

Year 18 20$ 20$ 33$ 20$

Year 19 20$ 20$ 31$ 20$

Year 20 20$ 20$ 29$ 20$

Year 21 20$ 20$ -$ 20$

Year 22 20$ 20$ -$ 20$

Year 23 20$ 20$ -$ 20$

Year 24 20$ 20$ -$ 20$

Year 25 20$ 20$ -$ 20$

Year 26 20$ 20$ -$ 20$

Year 27 20$ 20$ -$ 20$

Year 28 20$ 20$ -$ 20$

Year 29 20$ 20$ -$ 20$

Year 30 20$ 20$ -$ 20$

Year 31 20$ 20$ -$ 20$

Year 32 20$ 20$ -$ 20$

Year 33 20$ 20$ -$ 20$

Year 34 20$ 20$ -$ 20$

Year 35 20$ 20$ -$ 20$

Year 36 20$ 20$ -$ 20$

Year 37 20$ 20$ -$ 20$

Year 38 20$ 20$ -$ 20$

Year 39 20$ 20$ -$ 20$

Year 40 20$ 20$ -$ 20$

(1) Capital Expenditure includes: Engineering, Procurement, Construction, Fees, Spares, Contingency, EPC Project Mgmt, EPC A&G, and Utility A&G


AVANGRID Revisions: Comparison

Net Present Value Revenue Requirement Network Upgrade Revenue Requirements (excluding management fee) Lvl ARR 51$ 55$ 63$ 68$ 74$

536$ Maine For $1,000 Capital 40-yr 30-yr 20-yr 15-yr 10-yr FIT - Book FIT Bonus SIT Capital Weighted Weighted

Investment 536$ Structure Rate Present Value 635 635 635 591 501 MULTIPLIER FACTOR Tax Depr (180) (19) (161) (27) CMP Structure AT AT ETR PT PT

PTROR 12.985% ATROR 7.687% Equity 55% 11.070% Equity 10-yr PMT 93 93 93 87 74 Investment Total Cost PV Book Depr 27$ 27 - 27$ Equity 55% 11.07% 6.09% 40.80% 18.70% 10.29%

Depreciation Rate 5.00% Debt 45% 6.000% Debt 15-yr PMT 73 73 73 68 57 $1= 1.18315 Tax - Book Depr (153) 8 (161) - Debt 45% 3.55% 1.60% 40.80% 6.00% 2.70%

Property Tax 0.00% SIT 8.93% SIT 20-yr PMT 63 63 63 59 50 Discount Rate: 7.687% ~ATROR SIT 14 (1) 14 - ROR 100% 7.69% 12.99%

O&M and A&G 0.00% FIT 35% FIT 30-yr PMT 55 55 55 51 43 (139) 7 (147)

Escalation 1.00% CCBT 40.80% CCBT 40-yr PMT 51 51 51 48 41 0.408045 FIT (49) 3 (51)

* Estimate uses CMP capital structure of 55% equity at 11.07% and debt at 6% for 40-year asset 0.318745

O&M, Property Taxes and Depreciation Expense Rate Base **Estimate includes 30% Bonus Depreciation for assets placed in service 2019 & 2020 30% Composite Composite

O&M Exp - Property Book Initial Accumulated Net EOP for ME EOP for ME Prepay, M&S EOP for ME Return on Revenue PV Present 15-yr Tax Accum Combined EOP for ME Bonus Accum Accum MACRS Same

Year Transmission Taxes Depreciation Total Exp Investment Depreciation Plant Net Plant ADIT Working Capital Rate Base Investment Requirement Factor Value Year MACRS Depreciation Tax Depr SIT&FIT ADIT SIT&FIT ADIT FIT Depr MACRS for Model Answer

1 - - 27$ 27 536 (27)$ 510 510 (49) - 461 60 87 92.86% 80 1 5.000% 27 (27) (49) (49) (180) 27.26% 27.2628% (49) 0.272628203

2 - - 27$ 27 536 (54)$ 483 496 (54) - 443 57 84 86.23% 73 2 9.500% 51 (78) (54) (54) (215) 34.54% 7.2737% (54)

3 - - 27$ 27 536 (80)$ 456 469 (57) - 412 54 80 80.08% 64 3 8.550% 46 (124) (57) (57) (248) 41.08% 6.5463% (57)

4 - - 27$ 27 536 (107)$ 429 443 (59) - 384 50 77 74.36% 57 4 7.695% 41 (165) (59) (59) (276) 46.97% 5.8917% (59)

5 - - 27$ 27 536 (134)$ 402 416 (60) - 356 46 73 69.05% 50 5 6.926% 37 (202) (60) (60) (302) 52.28% 5.3025% (60)

6 - - 27$ 27 536 (161)$ 376 389 (59) - 330 43 70 64.12% 45 6 6.233% 33 (236) (59) (59) (326) 57.05% 4.7723% (59)

7 - - 27$ 27 536 (188)$ 349 362 (58) - 304 39 66 59.55% 39 7 5.905% 32 (267) (58) (58) (348) 61.57% 4.5211% (58)

8 - - 27$ 27 536 (215)$ 322 335 (57) - 278 36 63 55.30% 35 8 5.905% 32 (299) (57) (57) (370) 66.09% 4.5211% (57)

9 - - 27$ 27 536 (241)$ 295 308 (56) - 252 33 60 51.35% 31 9 5.905% 32 (331) (56) (56) (392) 70.61% 4.5211% (56)

10 - - 27$ 27 536 (268)$ 268 282 (55) - 227 29 56 47.68% 27 10 5.905% 32 (362) (55) (55) (415) 75.13% 4.5211% (55)

11 - - 27$ 27 536 (295)$ 241 255 (54) - 201 26 53 44.28% 23 11 5.905% 32 (394) (54) (54) (437) 79.65% 4.5211% (54)

12 - - 27$ 27 536 (322)$ 215 228 (53) - 175 23 50 41.12% 20 12 5.905% 32 (426) (53) (53) (459) 84.18% 4.5211% (53)

13 - - 27$ 27 536 (349)$ 188 201 (52) - 149 19 46 38.18% 18 13 5.905% 32 (457) (52) (52) (481) 88.70% 4.5211% (52)

14 - - 27$ 27 536 (376)$ 161 174 (51) - 124 16 43 35.46% 15 14 5.905% 32 (489) (51) (51) (503) 93.22% 4.5211% (51)

15 - - 27$ 27 536 (402)$ 134 148 (50) - 98 13 40 32.93% 13 15 5.905% 32 (521) (50) (50) (525) 97.74% 4.5211% (50)

16 - - 27$ 27 536 (429)$ 107 121 (44) - 77 10 37 30.58% 11 16 2.952% 16 (536) (44) (44) (536) 100.00% 2.2606% (44)

17 - - 27$ 27 536 (456)$ 80 94 (33) - 61 8 35 28.39% 10 17 - (536) (33) (33) (536) 100.00% 0.0000% (33)

18 - - 27$ 27 536 (483)$ 54 67 (22) - 45 6 33 26.37% 9 18 - (536) (22) (22) (536) 100.00% 0.0000% (22)

19 - - 27$ 27 536 (510)$ 27 40 (11) - 29 4 31 24.49% 7 19 - (536) (11) (11) (536) 100.00% 0.0000% (11)

20 - - 27$ 27 536 (536)$ - 13 (0) - 13 2 29 22.74% 6 20 - (536) (0) (0) (536) 100.00% 0.0000% -

21 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 21.11% (0) 21 - (536) (0) (0) (536) 100.00% 0.0000% -

22 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 19.61% (0) 22 - (536) (0) (0) (536) 100.00% 0.0000% -

23 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 18.21% (0) 23 - (536) (0) (0) (536) 100.00% 0.0000% -

24 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 16.91% (0) 24 - (536) (0) (0) (536) 100.00% 0.0000% -

25 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 15.70% (0) 25 - (536) (0) (0) (536) 100.00% 0.0000% -

26 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 14.58% (0) 26 - (536) (0) (0) (536) 100.00% 0.0000% -

27 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 13.54% (0) 27 - (536) (0) (0) (536) 100.00% 0.0000% -

28 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 12.57% (0) 28 - (536) (0) (0) (536) 100.00% 0.0000% -

29 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 11.68% (0) 29 - (536) (0) (0) (536) 100.00% 0.0000% -

30 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 10.84% (0) 30 - (536) (0) (0) (536) 100.00% 0.0000% -

31 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 10.07% (0) 31 - (536) (0) (0) (536) 100.00% 0.0000% -

32 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 9.35% (0) 32 - (536) (0) (0) (536) 100.00% 0.0000% -

33 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 8.68% (0) 33 - (536) (0) (0) (536) 100.00% 0.0000% -

34 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 8.06% (0) 34 - (536) (0) (0) (536) 100.00% 0.0000% -

35 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 7.49% (0) 35 - (536) (0) (0) (536) 100.00% 0.0000% -

36 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 6.95% (0) 36 - (536) (0) (0) (536) 100.00% 0.0000% -

37 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 6.46% (0) 37 - (536) (0) (0) (536) 100.00% 0.0000% -

38 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 6.00% (0) 38 - (536) (0) (0) (536) 100.00% 0.0000% -

39 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 5.57% (0) 39 - (536) (0) (0) (536) 100.00% 0.0000% -

40 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 5.17% (0) 40 - (536) (0) (0) (536) 100.00% 0.0000% -

41 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 4.80% (0) 41 - (536) (0) (0) (536) 100.00% 0.0000% -

42 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 4.46% (0) 42 - (536) (0) (0) (536) 100.00% 0.0000% -

43 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 4.14% (0) 43 - (536) (0) (0) (536) 100.00% 0.0000% -

44 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 3.84% (0) 44 - (536) (0) (0) (536) 100.00% 0.0000% -

45 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 3.57% (0) 45 - (536) (0) (0) (536) 100.00% 0.0000% -

46 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 3.32% (0) 46 - (536) (0) (0) (536) 100.00% 0.0000% -

47 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 3.08% (0) 47 - (536) (0) (0) (536) 100.00% 0.0000% -

48 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 2.86% (0) 48 - (536) (0) (0) (536) 100.00% 0.0000% -

49 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 2.65% (0) 49 - (536) (0) (0) (536) 100.00% 0.0000% -

50 - - -$ - 536 (536)$ - - (0) - (0) (0) (0) 2.47% (0) 50 - (536) (0) (0) (536) 100.00% 0.0000% -


AVANGRID Revisions: Comparison

Summary of AVANGRID Proposed Tariff Revisions

Section I.2

Adding definition of “Significant Interconnection Upgrades”

Schedule 11

Section 5

Section 7

Section 8

Schedule 22, Appendix 6 (Large Generator Interconnection Agreement)

Article 1 (adding definition of “Significant Interconnection Upgrades”)

Article 5.1.3

Article 5.2

Article 11.3

Article 11.7

Schedule 23 (Standard Small Generator Interconnection Agreement)

Article 4.1.2

Article 5.2

Article 5.5

Attachment 1 (Glossary of Terms) (adding definition of “Significant Interconnection Upgrades”)

Schedule 25, Appendix 6 (Elective Transmission Upgrade Interconnection Agreement)

Article 1 (adding definition of “Significant Interconnection Upgrades”)

Article 5.1.3

Article 5.2

Article 11.3

Article 11.7


AVANGRID Revisions: Summary


96161665.6

M E M O R A N D U M


FROM: Pat Gerity and Jennifer Galiette, NEPOOL Counsel

DATE: January 27, 2017

RE: Proposal to Implement a Small Standard Offer Supplier Sector Group Seat

At the February 3, 2017 meeting, you will be asked to approve for balloting amendments to the NEPOOL and Participants Agreements that would create a “Small Standard Offer Group Seat” in the Supplier Sector (the “Proposal”). As reported at the January 6 teleconference meeting, the Proposal is designed to facilitate participation by Market Participants1 who are solely serving standard offer load and whose average hourly Real-Time Load Obligation (“RTLO”) (looking back over all hours with RTLO during the prior 12 months) is 10 MWh or less through a group seat arrangement in the Supplier Sector. Since the January 6 Participants Committee meeting, the Proposal was further discussed and considered at the January 18 Membership Subcommittee meeting. As more fully described below, those participating in that discussion did not reach a consensus with respect to the Proposal. This memorandum provides additional materials describing the Proposal in more detail and includes a draft One Hundred Thirtieth Agreement that would effect the changes to the NEPOOL and Participants Agreements required to implement the Proposal (the “Amendments”).

As reported previously, discussion leading to the Proposal was initiated by Maine Power LLC, which has since been selected by the Maine Public Utilities Commission to serve large non-residential class standard offer load in Maine’s Emera Maine - Bangor Hydro District. The Proposal was vetted amongst and refined by those participating in the November and December Membership Subcommittee meetings , and subject to further discussion and consideration at the January Subcommittee meeting.

The Subcommittee did not reach a consensus on the Proposal. Those supporting the Proposal expressed the view that it was consistent with NEPOOL’s history of implementing appropriate arrangements to facilitate participation in the New England Markets and stakeholder process. They further asserted that it was designed to ensure that it would only be of very limited impact from Participant Expense and voting share allocation perspectives. Those who did not support the Proposal identified a number of continuing concerns, including (i) concerns that application of the proposed treatment would not necessarily be limited to Entities defined in the Proposal and could be requested by others in similar but not exactly the same circumstances (“slippery slope” concerns); (ii) if not limited, concerns with potential impacts on Participant Expense allocation; (iii) a discomfort with establishing arrangements applicable to too-narrow a class of Entity; and (iv) a preference to maintain consistent requirements/obligations for all competitive suppliers (“level playing field”).

This Proposal is at the stage of requiring a Participants Committee decision as to whether to proceed to ballot Amendments to governing documents that would be required to implement the Proposal. A motion to ballot must be approved by two-thirds Vote and, if approved, the ballots would be circulated

1 Capitalized terms used but not defined in this memorandum are intended to have the same meaning given to such terms in the Second Restated New England Power Pool Agreement (the “2d RNA”), the Participants Agreement, or the ISO New England Inc. (“ISO-NE”) Transmission, Markets and Services Tariff (“ISO-NE Tariff”).


96161665.6 -2- .

for signature. The changes to the governing documents could only be made if the Amendments reflected in the Proposal are then approved in balloting by 66.67% Vote from enough members to satisfy the Minimum Response Requirement.

The following form of resolution could be used to direct the balloting of the proposed Amendments:

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 agreements amending the New England Power Pool Agreement and Participants Agreement, to effect the Small Standard Offer Group Seat Proposal, as presented at this meeting, together with [such changes as were discussed and agreed to by the Committee and] such non-substantive changes as may be agreed to after the meeting by the Chair or any Vice-Chair of the Participants Committee, to each Participant for execution by its voting member or alternate on this Committee or such Participant’s duly authorized officer.

If approved in balloting, the Amendments would be filed with the FERC with a request that they become effective as of March 1, 2017. If there are any questions in advance of the meeting concerning the Amendments, please contact Pat Gerity (860-275-0533; [email protected]).

96226338.2

ONE HUNDRED THIRTIETH AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT

(Small Standard Offer Supplier Proposal)

THIS ONE HUNDRED THIRTIETH AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT, dated as of February 3, 2017 (“130th Agreement”), amends the New England Power Pool Agreement (the “NEPOOL Agreement”).

WHEREAS, effective February 1, 2005 the NEPOOL Agreement was amended by the One Hundred Seventh Agreement Amending New England Power Pool Agreement and restated as the Second Restated NEPOOL Agreement, and has subsequently been amended numerous times; and

WHEREAS, the Participants desire to amend further the Second Restated NEPOOL Agreement to reflect the revision detailed herein.

NOW, THEREFORE, upon approval of this 130th Agreement by the NEPOOL Participants Committee in accordance with the procedures set forth in the Second Restated NEPOOL Agreement, the Participants agree as follows:

SECTION 1 AMENDMENTS

1.1 Addition of Definitions. The following definitions are added to Section 1 of the Second Restated NEPOOL Agreement and inserted in the appropriate alphabetical order:

Small Standard Offer Group Seat is the group in the Supplier Sector comprised of all Small Standard Offer Suppliers.

Small Standard Offer Supplier is a Participant that (a) has been selected by a New England state’s public utilities commission to provide “standard offer” electric generation service to all or a specified portion of consumers in that state receiving standard offer service; (b) serves no load except such standard offer load; and (c) whose average hourly aggregate RTLO (averaged over all hours in which that Participant had an RTLO during the prior twelve (12) calendar months) is ten (10) MWh or less.

1.2 Amendment to Section 1.50(c). Section 1.50(c) (Member Adjusted Voting Share) is amended to read as follows:

(c) for a member of the Provisional Member Group Seat or the Small Standard Offer Supplier Group Seat which casts an affirmative or negative vote on a proposed action or amendment, is the member’s Member Fixed Voting Share.

1.3 Addition of new Section 1.51(b). The following new Section 1.51(b) (Member Fixed Voting Share) is added (with existing Sections 1.51(b) and (c) re-ordered to reflect that addition):


96226338.2

.

(b) for a member of the Small Standard Offer Supplier Group Seat, until there are five or more Small Standard Offer Supplier Group Seat members, the Small Standard Offer Supplier Group Seat Member Fixed Voting Share shall be one-fifth of the Member Fixed Voting Share of a Supplier Sector member that is not a member of the Small Standard Offer Supplier Group Seat times the total number of Small Standard Offer Supplier Group Seat members; and

1.4 Amendment to Section 1.51(c). Reordered Section 1.51(c) is amended to read as follows:

(c)(b) for a voting member of each active Sector (other than the AR Sector), whether or not the member is in attendance, is the quotient obtained by dividing (i) the Sector Voting Share of the Sector to which the Participant or group of Participants which appointed the voting member belongs by (ii) the total number of voting members appointed by members of that Sector, adjusted, if necessary, to take into account (A) the manner in which the voting shares of End User Participants are to be determined while they are members of the Publicly Owned Entity Sector, and (B) any required change in the voting share of the Transmission Group Member, as determined in accordance with Section 6.2(b), and (C) the voting share of the Small Standard Offer Supplier Group Seat; and

1.5 Amendment to Section 3.1(c). Section 3.1(c) (Membership) is amended to read as follows:

(c) The application fee to be paid by each Entity seeking to become a Participant (i) shall be in addition to the annual fee provided by Section 14.1 and (ii) shall be $500 for an applicant which qualifies for membership only as an End User Participant or a Data-Only Participant, $1,000 for an applicant which together with its Related Persons owns or controls less than 5 MW (or its equivalent) of Alternative Resources and qualifies for membership as an AR Provider or an applicant which qualifies for membership as a Provisional Member, $1,500 for an applicant which qualifies for membership as a Small Standard Offer Supplier, and $5,000 for all other applicants, or such other amount as may be fixed by the Participants Committee.

1.6 Amendment to Section 14.1(d). Section 14.1(d) (Annual Fee) is amended to read as follows:

(d) Each Provisional Member and Small Standard Offer Supplier Participantshall pay an annual fee of $1,500.

1.7 Amendment to Section 14.2(e)(1). Section 14.2(e)(1) (Participant Expenses) is amended to read as follows:

(1) in the Supplier Sector, Related Person Suppliers and Small Standard Offer Suppliers shall each pay a portion of the Supplier Sector share in the same proportion as the vote that Participant is entitled to in the Supplier Sector;


96226338.2

.

SECTION 2 MISCELLANEOUS

2.1 This 130th Agreement shall become effective March 1, 2017, or on such other date as the Commission shall provide that the amendment reflected herein shall become effective.

2.2 Capitalized terms used in this 130th Agreement that are not defined herein shall have the meanings ascribed to them in the Second Restated NEPOOL Agreement.


96226338.2

.

AMENDMENT NO. 10 TO PARTICIPANTS AGREEMENT

(Small Standard Offer Supplier Proposal)

THIS AMENDMENT NO. 10 TO PARTICIPANTS AGREEMENT (“Amendment No. 10”) is made and entered into as of this 3rd day of February, 2017 by and between ISO New England Inc. (the “ISO”) and the New England Power Pool, an unincorporated association created pursuant to the New England Power Agreement dated as of September 1, 1971, as amended and restated, acting herein by and through the NEPOOL Participants Committee (“NEPOOL”).

WHEREAS, the Participants Agreement by and among the ISO and NEPOOL became effective as of February 1, 2005 and has subsequently been amended nine times.

WHEREAS, the ISO and NEPOOL desire to amend the Participants Agreement to reflect the revisions detailed herein.

NOW, THEREFORE, upon approval of this Amendment No. 10 by the ISO and by the NEPOOL Participants Committee in accordance with the procedures set forth in the Participants Agreement, the ISO and NEPOOL agree as follows:

1. Amendments to Section 1.1 (Defined Terms).

1.1 Addition of Definitions of Small Standard Offer Group Seat and Small Standard Offer Supplier. The following definitions are added to Section 1.1 of the Participants Agreement:

“Small Standard Offer Group Seat” shall mean the group in the Supplier Sector comprised of all Small Standard Offer Suppliers.

“Small Standard Offer Supplier” shall mean a Participant that (a) has been selected by a New England state’s public utilities commission to provide “standard offer” electric generation service to all or a specified portion of consumers in that state receiving standard offer service; (b) serves no load except such standard offer load; and (c) whose average hourly aggregate RTLO (averaged over all hours in which that Participant had an RTLO during the prior twelve (12) calendar months) is ten (10) MWh or less.

1.2 Amendment to Definition of “Member Adjusted Voting Share”. The following sub-section (c) is added to the definition of Member Adjsuted Voting Share as follows:

(c) for a member of the Provisional Member Group Seat or the Small Standard Offer Supplier Group Seat which casts an affirmative or negative vote on a proposed action or amendment, is the member’s Member Fixed Voting Share.

1.3 Amendment to Definition of “Member Fixed Voting Share”. The definition of Member Fixed Voting Share is amended to read as follows:


96226338.2

.

(a) for a member of the Provisional Member Group Seat, whether or not the member is in attendance, is the quotient obtained by dividing (i) the Provisional Member Group Seat Voting Share by (ii) the total number of Provisional Members in the Provisional Member Group Seat; and

(b) for a member of the Small Standard Offer Supplier Group Seat, until there are five or more Small Standard Offer Supplier Group Seat members, the Small Standard Offer Supplier Group Seat Member Fixed Voting Share shall be one-fifth of the Member Fixed Voting Share of a Supplier Sector member that is not a member of the Small Standard Offer Supplier Group Seat times the total number of Small Standard Offer Supplier Group Seat members; and

(c) for a voting member of each active Sector (other than the AR Sector), whether or not the member is in attendance, is the quotient obtained by dividing (i) the Sector Voting Share of the Sector to which the Participant or group of Participants which appointed the voting member belongs by (ii) the total number of voting members appointed by members of that Sector, adjusted, if necessary, to take into account (A) the manner in which the voting shares of End User Participants are to be determined while they are members of the Publicly Owned Entity Sector, (B) any required change in the voting share of the Transmission Group Member, as determined in accordance with Section 6.2(b), and (C) the voting share of the Small Standard Offer Supplier Group Seat; and.

(d) for a voting member of an AR Sub-Sector whether or not the member is in attendance and until the sum of the Member Fixed Voting Shares of the Sub-Sector voting members equals or exceeds the Fully Activated Sub-Sector Voting Share, is either 1 2/3% if the voting member represents a Participant or Participants which own or control, together with their Related Persons, more than 15 MW (or its equivalent) of Alternative Resources or 1% if the voting member represents less than 15 MW (or its equivalent) of Alternative Resources. When the sum of the Member Fixed Voting Shares of the AR Sub-Sector voting members equals or exceeds the Fully Activated Sub-Sector Voting Share, the Member Fixed Voting Share for the voting member whether or not the voting member is in attendance will be the quotient obtained by dividing (i) the Fully Activated Sub-Sector Voting Share by (ii) the total number of voting members appointed by Participants in that Sub-Sector.

2. Effective Date. This Amendment No. 10 shall become effective on March 1, 2017 or on such other date as the Commission shall provide that the amendments reflected herein shall become effective.

3. Counterparts. Counterparts of this Amendment No. 10 may be signed by the parties, each of which shall be an original but both of which together shall constitute one and the same instrument.

4. Governing Law. This Amendment No. 10 shall be governed by and enforced in accordance with the laws of the State of Delaware.


96226338.2

.

5. Miscellaneous. Terms used in this Amendment No. 10 that are not defined herein shall have the meanings ascribed to them in the Participants Agreement, the Second Restated NEPOOL Agreement, or the ISO’s Transmission, Markets and Services Tariff.

[The next page is the signature page.]


96226338.2

.

IN WITNESS WHEREOF, the ISO and NEPOOL have caused this Amendment No. 10 to be executed by their duly authorized representatives as of the date first written above.

ISO NEW ENGLAND INC. NEW ENGLAND POWER POOL acting through the NEPOOL Participants Committee

By:____________________________ By:______________________________ Name: Gordon van Welie Name: Thomas W. Kaslow Title: President and Chief Executive Officer Title: Chair, NEPOOL Participants

Committee


Revised Draft for Discussion Dec 27, 2016

Small Standard Offer Supplier Sector Group Seat Proposal

Eligibility:

• Must have been selected by a New England state’s public utilities commission as a

standard offer provider to provide all or a specified portion of electric generation service

to consumers in that state receiving standard offer service.

• Only serves standard offer load.

• Average hourly load (aggregate customer hourly RTLO) over the last 12 months of 10

MWh or less.

Principal Committee Participation and Voting Share:

• Small Standard Offer Suppliers to participate as members of a Small Standard Offer

Group Seat in the Supplier Sector.

• Group Seat would have the same Member Fixed Voting Share and Member Adjusted

Voting Share as other members of the Supplier Sector once the Group Seat achieves five

members.

• Until the total number of Group Seat members is five, the Group Seat Voting Share shall

be the Member Fixed Voting Share and Member Adjusted Voting Share of the other

members of the Supplier Sector times the quotient obtained by dividing the total

number of Group Seat members by 5.

Annual Fee (§ 14.1):

• $1,500 each.

Participant Expenses (§14.2):

• Each Group Seat member would pay monthly participant expenses equal to one-twelfth

(1/12) of the following amount: the amount of Participant Expenses paid by an

individual voting Participant in the Supplier Sector (other than a Related Person

Supplier) pursuant to Section 14.1(f) of the 2dRNA during the previous calendar year,

multiplied by the Group Seat Member’s fractional Voting Share of the Group Seat Voting

Share.

Revised Draft for Discussion Dec 27, 2016

Proposed Definition of Small Standard Offer Supplier (§1):

A Small Standard Offer Supplier is a Participant that (a) has been selected by a New England

state’s public utilities commission to provide “standard offer” electric generation service to all

or a specified portion of consumers in that state receiving standard offer service; (b) serves no

load except such standard offer load; and (c) its average agregate hourly RTLO (averaged over

all hours with RTLO during the prior twelve (12) calendar months) is ten (10) MWh or less.


96425355.5

M E M O R A N D U M


FROM: NEPOOL Counsel

DATE: February 1, 2017

RE: Implications of the Resignation of Norman Bay and the Lack of a FERC Quorum

Responding to numerous questions asked of us recently, as of Friday, February 3, the number of sitting FERC Commissioners will shrink to two, which means that Commission will lack a quorum and will be unable to vote on orders, regulations or policy initiatives. This memorandum summarizes what we can expect to happen until the President appoints, and the Senate confirms, additional Commissioners for the FERC. Attached is a table that identifies pending matters being tracked in the NEPOOL litigation report and our thoughts concerning the impact on those matters.

The FERC developments follow a series of events since President Trump took office. First, on January 20, 2017, the White House issued a broad directive to all executive agencies, referred to as the Regulatory Freeze memorandum, that directed all federal departments and agencies to publish no new regulations or to temporarily postpone regulations that have not yet taken effect.1 Second, on Monday, January 23, 2017, President Trump elevated Cheryl LaFleur to Acting Chairman of the Commission. Three days later, on January 26, former Chairman, now Commissioner, Norman Bay announced that he would resign from the Commission on Friday, February 3, 2017. The following day, Acting Chairman LaFleur issued a statement explaining that the Regulatory Freeze no longer applied to the FERC because, as provided in that memo, there was a “triggering event” that permitted continued FERC regulatory actions.2

While the Commission cannot, without a quorum, issue substantive orders, regulations, or policy initiatives,3 the Commission continues to have statutory obligations that need to be met. The Commission satisfies many of its routine obligations through delegated authority and generally has broad statutory authority to perform acts and to make rules that are necessary or appropriate to carry out its statutory functions.4 The matters now delegated to staff generally are uncontested matters “which in many cases represent nothing more than a ministerial judgment by

1 White House Management and Budget Office, Regulatory Freeze Pending Review, 82 Fed. Reg. 8346 (Jan. 20, 2017). The Regulatory Freeze memorandum the White House issued on January 20, 2017 does not apply to the FERC at this time.

2 FERC Statement on Regulatory Freeze Memorandum, available at https://ferc.gov/media/news-releases/2017/2017-1/01-27-17.asp.

3 42 U.S.C. § 7171(e) (2012). 4 See Regulations Delegating Authority, Order No. 492, FERC Stats. & Regs. ¶ 30,814, at 31,117

& n.2 (1988) (citing 16 U.S.C. 825h (Federal Power Act), 15 U.S.C. 717o (Natural Gas Act), and 15 U.S.C. 3411 (Natural Gas Policy Act of 1978)).


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the office director concerning procedural matters.”5 The scope of this existing delegated authority is set forth in Part 375, Subpart C, of the FERC’s regulations, and expressly prescribes the tasks that can be performed by the various office directors.6

Recognizing its pending inability to act on certain matters, the Commission has indicated that it will issue a supplemental delegation order that will grant expanded authority to certain FERC office directors.7 Significantly, none of the existing delegations, or the additional authority that may be delegated, allows the Commission, without a quorum, to rule on contested cases, to grant certificates of public convenience and necessity, to adopt new rules,8 or to rule on initial decisions that are issued by one of the FERC’s Administrative Law Judges.

It is unclear when the Commission will have a third confirmed member. Recently, Senator Lisa Murkowski (R-AK), Chairman of the Senate Energy and Natural Resources Committee, issued a statement concerning the Commission’s lack of a quorum, stating that she would make it “a top priority to work with President Trump and my colleagues to move nominees rapidly and to re-establish a working quorum on the Commission.”9 While predictions about the timing of the Presidential nomination and confirmation process are often imperfect, given the numerous issues surrounding the new administration’s nominations and confirmations across the executive branch, it is not unreasonable to assume that the Commission will be without a third voting member, and therefore a quorum, for at least the next two to three months.10

Given these circumstances, we expect during the interim the following impacts on New England matters (and have grouped them accordingly in the attached table):

• Pending Filings. Filings on which the Commission must act or those filings will otherwise be “deemed accepted”11 are likely to be acted on by delegated authority, either (i) subject to a deficiency letter if there are matters staff concludes require further information or explanation; (ii) being approved by letter order if acceptable

5 See J.R. Ferguson and Assoc., 20 FERC ¶ 61,132 at p. 61,291 (1982). 6 18 C.F.R. §§ 375.301 – 315 et seq. (2016). 7 The Commission issued an order delegating authority in 1993 when it similarly anticipated that

it would lack a quorum. See Order Delegating Authority to the Secretary and Certain Office Directors, 63 FERC ¶ 61,073 (1993).

8 On Monday, January 30, 2017, an Executive Order requiring “that for every one new regulation issued, at least two prior regulations be identified for elimination.” At this time, it is not clear how this Executive Order will be applied to the FERC’s existing or future rulemakings. Seehttps://www.whitehouse.gov/the-press-office/2017/01/30/presidential-executive-order-reducing-regulation-and-controlling.

9 Available at http://www.energy.senate.gov/public/index.cfm/2017/1/sen-murkowski-statement-on-ferc-quorum.

10 For example, Commissioner Honorable was nominated by President Obama in August 2014 and was not confirmed by the U.S. Senate until December 2014. Commissioner Honorable’s term expires in June 2017.

11 16 U.S.C. § 824d(d) (2016).


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and unchallenged by a party; or (iii) if challenged or unacceptable in part, conditionally approved subject to refund and/or further action by the Commission.

• Compliance Filings. Compliance filings will generally remain pending without Commission action (since there is no statutory time by which the Commission must act on such filings), though some may be accepted by letter order if uncontested.

• Contested Cases. We expect that contested cases that have already been set for hearing or settlement will proceed without interruption in accordance with their procedural schedules. Pending Offers of Settlement or Initial Decisions will remain pending without Commission action.

• Requests for Rehearing. Matters subject to requests for rehearing will remain pending with Staff likely issuing orders, referred to as “tolling orders,” that prevent rehearing from being denied by operation of law because of Commission inaction.12

• Notices of Proposed Rulemakings (“NOPRs”). No Commission action will be taken on NOPRs or in response to Administrative (“AD” Docket) Proceedings until after a quorum is re-established and the Commission has been able to consider fully the comments provided. NOPRs with comment deadlines that have not passed will proceed according to the published schedules.

12 18 C.F.R. § 385.713(f) (2016).


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Current New England Matters (summarized in the Feb. 1, 2017 Litigation Report)

Pending Filings (delegated action expected):

• ER17-680 (Sub-Hourly Settlement NCPC Changes) (uncontested) • ER17-576 (Effective Date Update: Fast Start Pricing & DARD Pump Parameter Changes) (uncontested) • ER17-857 (Attachment K Revisions - Public Policy Transmission Studies Timeline

Modifications and Clean-Up/Admin Changes to Section 6.3 and Appendices 2 & 3) (uncontested)• ER17-899 (February 2017 Membership Filing) (uncontested)• ER17-795 (CONE & ORTP Updates) (expected to be contested)• EC17-62 (203 Application: NSTAR/WMECO Merger) (Jan 1, 2018 effective date requested;

order not expected before July 2017)

Compliance Filings (will remain pending unless uncontested):

• ER17-774 - Order 825 Compliance: 5-Min. Settlement of Regulation Capacity & Service Credit (uncontested)

• ER16-2695 (New England’s Orders 827/828 Compliance Filing) (uncontested) • ER13-2266 (2013/14 Winter Reliability Program Remand Proceeding) • EL11-66 (Opinion 531-A/531-B Regional & Local Refund Reports) • EC16-93 (203 Application: GDF Suez Energy Resources/Atlas Power (Dynegy/ECP))

Contested Cases Set for Settlement Judge Proceedings/Hearings (to proceed uninterrupted; no final action will be taken):

• EL16-120 (NEPGA PER Complaint) • EL16-64 (Base ROE Complaint IV (2016)) • EL16-19 (RNS/LNS Rates and Rate Protocols) • ER15-1434 et al. (Schedule 21-EM: Recovery of BHE/MPS Merger-Related Costs) • ER15-1429 et al. (Emera MPD OATT Changes) • EL13-33/EL14-86 (Base ROE Complaints II & III (2012 & 2014) – initial decision pending)

Rehearing Requests (will remain pending):

• EL16-120 (NEPGA PER Complaint) (Expected) • ER17-337 (Natural Gas Index Changes) (Possible)• EL16-64 (Base ROE Complaint IV (2016)) (tolled)• ER16-2451 (FCM Enhancements) (tolled)• ER16-551 (FCM Resource Retirement Reforms) (tolled)• ER14-1639 (Demand Curve Changes Remand Proceedings) (tolled)• RM16-15 (Order 833: Critical Energy/Electric Infrastructure Information (CEII) Procedures) (tolled)• RM16-5 (Order 831: Price Caps in RTO/ISO Markets) (tolled)• RP16-618 (Algonquin EDC Capacity Release Bidding Requirements Exemption Request)


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NOPRs/Admin Proceedings (comment deadline in parentheses if not passed) (no action will be taken):

• PL17-1 (NOI: FERC's Policy for Recovery of Income Tax Costs & ROE Policies) (Mar 8)• RM17-8 (LGIA/LGIP Reforms) (Feb 16)• RM17-3 (Fast Start Pricing in RTO/ISO Markets) (Feb 8)• RM16-22 (New NERC Reliability Standards: PRC-027-1 and PER-006-1) (pending)• AD16-25 (Electric Storage Resource Utilization in RTO/ISO Markets) (pending)• AD16-18 (Competitive Transmission Development Rates) (pending)• AD16-17 (Reactive Supply Compensation in RTO/ISO Markets) (pending)• AD16-16 (PURPA Implementation) (pending)• AD14-14 (Price Formation in RTO/ISO Energy & Ancillary Services Markets) (pending)• RM16-17 Data Collection for Analytics & Surveillance/MBR Purposes) (pending)• RM16-6 (Primary Frequency Response - Essential Reliability Services and the Evolving Bulk-

Power System) (pending)• RM16-13 (Revised Reliability Standards: BAL-005-1 & FAC-001-3) (pending)• RM14-7 (ATC NOPR - Revised Reliability Standard MOD-001-2) (pending)• RM13-6 (BAL-002-1a Interpretation Remand NOPR) (pending)

February 1, 2017 Report NEPOOL PARTICIPANTS COMMITTEE FEB 3, 2017 MEETING, AGENDA ITEM #7

Page ES-1

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EXECUTIVE SUMMARY Status Report of Current Regulatory and Legal Proceedings

as of February 1, 2016

The following activity, as more fully described in the attached litigation report, has occurred since the report dated January 4, 2017 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 NEPGA PER Complaint (EL16-120)

Jan 19

Jan 25 Jan 26 Feb 1

FERC (i) grants in part NEPGA’s complaint and (ii) sets in part for hearing and settlement judge procedures the question of the appropriate method of calculating the PER Strike Price; refund effective date of Sep 30, 2016 established Chief Judge Cintron designates H. Peter Young as settlement judge NHEC moves to intervene out-of-time Judge Young schedules 1st settlement conference for Feb 16

2 Base ROE Complaint IV (2016) (EL16-64)

Jan 13 Jan 17 Jan 23

FERC Trial Staff on behalf of active parties submits discovery plan Trial Judge Glazer issues order adopting discovery plan Trial Judge Glazer establishes procedural schedule, which includes hearings Aug 2-8 and an initial decision by Nov 15

II. Rate, ICR, FCA, Cost Recovery Filings

5 ICR-Related Values and HQICCs – Annual Reconfiguration Auctions (ER17-472)

Jan 9 FERC accepts ICR-Related Values, eff. Jan 30

III. Market Rule and Information Policy Changes, Interpretations and Waiver Requests

* 5 CONE & ORTP Updates (ER17-795)

Jan 13

Jan 17-Feb 1

ISO-NE files updates to CONE, Net CONE, ORTP values; comment date Feb 3 Calpine, ConEd, Exelon, National Grid, NESCOE intervene

* 5 Order 825 Compliance: 5-Min. Settlement of Regulation Capacity & Service Credit (ER17-774)

Jan 11

Jan 17-25

ISO-NE and NEPOOL jointly file changes to settle Regulation Capacity Credit and Regulation Service Credit on a 5-minute (rather than on an hourly) basis EPSA, National Grid, NRG intervene

5 Sub-Hourly Settlement NCPC Changes (ER17-680)

Jan 5-17 National Grid, Eversource, Exelon intervene

6 Effective Date Update: Fast Start Pricing and DARD Pump Parameter Changes (ER17-576)

Jan 5-6 Eversource, National Grid intervene

6 Natural Gas Index Changes (ER17-337)

Jan 9 FERC accepts changes, eff. Jan 10

7 Waiver Request: RTEG Resource Type/De-List (ER16-1904)

Jan 19 FERC denies CPower request for rehearing of the ISO RTEG Waiver Request Order

9 2013/14 Winter Reliability Program Remand Proceeding (ER13-2266)

Jan 23 ISO-NE submits compliance filing recommending that “there is insufficient demonstration of market power to warrant modification of program”; comment date Feb 13


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IV. OATT Amendments / TOAs / Coordination Agreements

* 10 Attachment K Revisions (ER17-857)

Jan 26

Jan 30

ISO-NE and NEPOOL file revisions to modify the Public Policy Transmission Study Process timeline and to update Section 6.3(Interregional Coordination) and Appendices 2 and 3; comment date Feb 16 NESCOE intervenes

V. Financial Assurance/Billing Policy Amendments

No Activity to Report

VI. Schedule 20/21/22/23 Changes

10 Schedule 23: FPL Energy Wyman SGIA (ER17-581)

Jan 19 FERC accepts non-conforming SGIA governing interconnection of Wyman’s 16 MW battery energy storage facility; eff. Nov 30, 2016

11 Schedule 21-ES: Eversource Recovery of NU/NSTAR Merger-Related Costs (ER16-1023)

Jan 31 FERC approves settlement agreement

11 Schedule 21-EM: Recovery of BHE/MPS Merger-Related Costs (ER15-1434 et al.)

Jan 11 Settlement Judge Dring issues status report indicating that the parties have reached a settlement in principal and are memorializing their agreement, and recommending settlement procedures be continued

VII. NEPOOL Agreement/Participants Agreement Amendments


VIII. Regional Reports

* 12 IMM Quarterly Markets Reports - 2016 Fall (ZZ16-4)

Jan 27 IMM files 2016 Fall Report

* 12 LFTR Implementation: 32nd Quarterly Status Report (ER07-476)

Oct 14 ISO files its 32nd quarterly report

IX. Membership Filings

* 13 February 2017 Membership Filing (ER17-899)

Jan 31 NEPOOL requests the FERC accept (i) the membership of NRDC; (ii) the termination of Artis Energy Holdings, EMI Power Systems, Jeffrey A. Jones, and Powerex; and (iii) the name change of NextEra Energy Marketing, LLC; comment date Feb 21

13 January 2017 Membership Filing (ER17-682)

Jan 25 FERC accepts (i) the memberships of Emera Energy Services Subsidiaries 11-15; and (ii) the termination of the Participant status of Summit Hydropower and StatArb Investments and (iii) the name change of Calpine (f/k/a/ Noble Americas) Energy Solutions

X. Misc. - ERO Rules, Filings; Reliability Standards

13 Reliability Standard Retirement: BAL-004-0 (RD17-1)

Jan 18 FERC approves retirement of BAL-004-0

14 Order 835: Revised Reliability Standard: BAL-002-2 (RM16-7)

Jan 19 FERC approves BAL-002 Changes, eff. [60 days after publication in the Federal Register]

14 Order 830-A: New Reliability Standard: TPL-007-1 (RM15-11)

Jan 19 FERC denies rehearing of Order 830


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XI. Misc. - of Regional Interest

* 16 203 Application: NSTAR/WMECO merger (EC17-62)

Jan 13

Jan 27

Eversource files for approval of merger of WMECO with and into NSTAR; comment date Feb 3 MA AG intervenes

16 203 Application: GDF Suez Energy Resources/Atlas Power (Dynegy/ECP) (EC16-93)

Jan 10 Jan 13 Jan 19

UWUA Local 464 and R. Clark protest Dec 27 compliance filing Applicants answer UWUA Local 464 protest UWUA Local 464 answers Applicants Jan 13 answer; Applicants answer UWUA Local 464 Jan 19 answer

* 17 LGIA: CMP/ReEnergy Livermore Falls (ER17-909)

Jan 31 CMP LGIA with ReEnergy Livermore Falls; comment date Feb 21

* 17 MOPR-Related Proceedings (PJM, NYISO) (EL16-49; ER13-62)

Jan 24, 30 NEPOOL files limited comments requesting that any Commission action or decision be limited narrowly to the facts and circumstances as presented in the applicable market/proceedings, not New England

17 Emera MPD OATT Changes (ER15-1429; EL16-13, ER12-1650)

Jan 24 Settlement Judge Dring issues status report indicating the parties have reached a settlement in principal (which is to be filed in Mar) and recommending settlement judge procedures be continued

* 18 FERC Enforcement Action: Covanta Haverhill Associates (IN17-3)

Jan 23 Feb 1

Staff issues NoV concerning Covanta’s New England activities FERC approves Agreement resolving OE’s investigation of Covanta; Covanta required to pay a civil penalty of $36,000 and implement procedures to improve compliance, subject to semi-annual report monitoring

* 19 FERC Enforcement Action: GDF SUEZ Energy Marketing NA (IN17-2)

Feb 1 FERC approves Stipulation and Consent Agreement with GDF SUEZ Energy Marketing NA, requiring GSEMNA to pay a $41 million civil penalty and to disgorge $40.8 million to resolve the FERC’s investigation into violations of its Anti-Manipulation Rules

XII. Misc. - Administrative & Rulemaking Proceedings

23 NOPR: Electric Storage Participation in RTO/ISO Markets (RM16-23; AD16-20)

Jan 19-31 6 parties file comments; comment date Feb 13

* 21 NOI: FERC's Policy for Recovery of Income Tax Costs (PL17-1)

Jan 4 FERC extends comment date to Mar 8, 2017; reply comment date, Apr 7

* 21 Order 834: Civil Monetary Penalty Inflation Adjustments (RM17-9)

Jan 9 FERC issues final rule increasing maximum civil monetary penalties it may assess; market manipulation penalties increased to $1,213,503 per violation, per day; eff. Jan 24, 2017

22 NOPR: LGIA/LGIP Reforms (RM17-8)

Jan 17 Schulte Associates submits comments

24 Order 833: Critical Energy/Electric Infrastructure Information (CEII) Procedures (RM16-15)

Jan 17 FERC issues tolling order affording it additional time to consider EEI’srequest for rehearing of Order 833

24 NOPR: Primary Frequency Response -Essential Rel. Services & the Evolving BPS (RM16-6)

Jan 24-25 Over 30 parties submit comments

25 Order 831: Price Caps in RTO/ISO Markets (RM16-5)

Jan 4 Jan 13 Jan 17

PJM Market Monitor opposes Exelon’s request for clarification MISO submits comments supporting NYISO request for rehearing FERC issues tolling order affording it additional time to consider requests for rehearing of Order 831


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XIII. Natural Gas Proceedings

28 New England Pipeline Proceedings Atlantic Bridge Project (CP16-9)

Jan 25 FERC grants certificate of public convenience and necessity for Atlantic Bridge Project

XIV. State Proceedings & Federal Legislative Proceedings

No Activity Reported

XV. Federal Courts

29 FCA10 Results and FCA9 Results (16-1408 and 16-1068 consol.)

Jan 17 Jan 31

FERC moves for consolidation of two proceedings Court consolidates cases

30 Order 1000 Compliance Filings (15-1139, 15-1141**) (consolidated)

Jan 13 Oral argument held before Judges Brown, Wilkins and Edwards


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41536280.171

M E M O R A N D U M

TO: NEPOOL Participants Committee Member and Alternates

FROM: Patrick M. Gerity, NEPOOL Counsel

DATE: February 1, 2017

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 February 1, 2017. If you have questions, please contact us.1


• NEPGA PER Complaint (EL16-120) On January 19, the FERC (i) granted in part NEPGA’s complaint2 and (ii) set in part for hearing and

settlement judge procedures the question of the appropriate method of calculating the PER Strike Price under Market Rule 1 section III.13.7.2.7.1.1.1.3 In granting NEPGA’s complaint in part, the FERC found that “for the period at issue in NEPGA’s complaint (September 30, 2016 – May 31, 2018), the PER mechanism has become unjust and unreasonable as a result of the interaction between the PER mechanism and the higher Reserve Constraint Penalty Factors.”4 Accordingly, the FERC required the ISO to revise the method by which it calculates the PER Strike Price as set forth in Tariff section III.13.7.2.7.1.1.1. But, finding NEPGA’s request that the PER Strike Price be increased by $250 per MWh “raises issues of material fact that cannot be resolved based upon the record before us and that are more appropriately addressed in the hearing and settlement judge procedures”, the FERC set the question of the appropriate method of calculating the PER Strike Price for hearing and settlement judge procedures under section 206 of the FPA.5 The FERC established a refund effective date of September 30, 2016 (the date of the complaint). In establishing a September 30, 2016 effective date, the FERC clarified that “any changes to the calculation of the PER Strike Price under ISO-NE Tariff section III.13.7.2.7.1.1.1 would be prospective only from September 30, 2016, as required by FPA section 206, and would not impact the application of any PER Adjustment occurring before September 30, 2016.”6 Challenges, if any, to the PER Complaint Order will be due on or before February 21.

Settlement Judge Procedures. On January 25, Chief Cintron designated Judge H. Peter Young as the Settlement Judge in these proceedings.

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 NEPGA’s complaint asked the FERC (i) to find the ISO Tariff's Peak Energy Rent (“PER”) Adjustment provisions unjust & unreasonable; (ii) to direct the ISO to file revisions to the PER Adjustment sections of the Tariff that return the PER Adjustment to a just & reasonable level; (iii) to establish a refund effective date of September 30, 2016; and (iv) to issue an order granting the complaint by November 29, 2016.

3 New England Power Generators Assoc., Inc. v. ISO New England Inc., 158 FERC ¶ 61,034 (Jan. 19, 2017). 4 Id. at P 48. 5 Id. at P 57. 6 Id. at P 61.


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If you have any questions concerning this matter, please contact Joe Fagan (202-218-3901; [email protected]), Jamie Blackburn (202-218-3905; [email protected]), or Sebastian Lombardi (860-275-0663; [email protected]).

• Base ROE Complaint IV (2016) (EL16-64) On September 20, 2016, the FERC established hearing and settlement judge procedures (and set a

refund effective date of April 29, 2016) for the 4th ROE Complaint.7 As previously reported, EMCOS8 filed the 4th ROE complaint on April 29, 2016. The Complaint asked the FERC to reduce the TOs’ current 10.57% return on equity (“Base ROE”) to 8.93% and to determine that the upper end of the zone of reasonableness (which sets the incentives cap) is no higher than 11.24%. EMCOS identified three main considerations requiring submission of this Complaint: (1) the continuing decline of the market cost of equity capital, which makes NETOS’ currently authorized ROE “excessive, unjust and unreasonable, and therefore ripe for adjustment under FPA Section 206”; (2) “divergent rulings concerning the persistence of the “anomalous” capital market conditions”; and (3) “the extent to which the Commission’s anomalous conditions rationale in Opinion No. 531 is intended to reflect changes in its long-standing reliance on the DCF methodology, and particularly the DCF midpoint, for determining ROE remains unclear.”

In setting the complaint for hearing and settlement judge procedures, the FERC found that the Complaint “raises issues of material fact that cannot be resolved based upon the record before us and that are more appropriately addressed in the hearing and settlement judge procedures we order.”9 The FERC also found “unpersuasive the assertions of New England TOs and EEI that the Commission should dismiss the Complaint because the New England TOs’ base ROE continues to fall within the zone of reasonableness. The Commission has repeatedly rejected the assertion that every ROE within the zone of reasonableness must be treated as an equally just and reasonable ROE.”10 Further, the FERC rejected arguments as to the propriety of allowing a fourth complaint against the TOs’ ROE after three previous complaints have been filed since 2011. As it did when it allowed Complaints II and III to go forward, the FERC found that Complaint IV was properly set for hearing as it is based on newer, more current data than prior Complaints subsequent hearings.11 The FERC is “initiating an entirely new proceeding, based on an entirely separate factual record, that may or may not reach the same conclusions as those reached in the earlier ROE proceeding.”12 The FERC estimated that, if this case does not settle and goes to hearing, the Commission’s ultimate decision would be issued on or before June 30, 2018.13 Both the TOs and EEI requested rehearing of the Base ROE Complaint IV Order. The FERC issued a tolling order on November 21, affording it additional time to consider the requests for rehearing, which remain pending.

Settlement Judge Procedures. On October 4, Chief Judge Cintron designated Judge Jennifer Long, the FERC’s newest ALJ, as the Settlement Judge. Settlement conferences have thus far been held on November 8 and December 20, 2016; a third settlement conference is tentatively scheduled for March 22,

7 Belmont Mun. Light Dept. et al. v. Central Me. Power Co. et al., 156 FERC ¶ 61,198 (Sep. 20, 2016) (“Base ROE Complaint IV Order”).

8 “EMCOS” are: Belmont Mun. Light Dept., Braintree Elec. Light Dept., Concord Mun. Light Plant, Georgetown Mun. Light Dept., Groveland Elec. Light Dept., Hingham Mun. Lighting Plant, Littleton Elec. Light & Water Dept., Middleborough Gas & Elec. Dept., Middleton Elec. Light Dept., Reading Mun. Light Dept. (“Reading”), Rowley Mun. Lighting Plant, Taunton Mun. Lighting Plant, and Wellesley Mun. Light Plant.

9 Base ROE Complaint IV Order at P 37. 10 Id. at P 38. 11 Complaint IV was filed 21 months after the July 31, 2014 filing of Complaint III, nearly nine months after

the July 2, 2015 close of the Complaint III evidentiary hearing record, and six months after the end of the Complaint III refund period.

12 Base ROE Complaint IV Order at P 40. 13 Id. at P 44.


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2017 (subject to change depending on disposition of Emera Maine v. FERC (DC Cir. case No. 15-1118). On January 3, Settlement Judge Long issued a status report indicating that the parties remain open to settlement and recommending that settlement judge procedures be continued concurrently with the hearings described below.

Concurrent Hearing Procedures. On December 21, 2016, in response to a request of the parties and supported by Settlement Judge Long, Chief Judge Cintron designated Steven A. Glazer as presiding judge for hearings in this matter, so that hearing procedures can proceed concurrently with settlement judge procedures still underway before Judge Long. Absent a settlement, these hearing procedures will be conducted under the FERC’s “Track II” procedural time standards, which requires that an initial decision be issued within 47 weeks, or by November 15, 2017. Judge Glazer scheduled a preliminary conference for January 17, 2017, noting that hearing has been set for August 2, 2017 (with September 27, 2017 as the deadline for reply briefs). At the January 17 conference, Participants proposed the remaining procedural schedule, which was adopted by Judge Glazer in an order issued January 23. In addition, Judge Glazer has issued orders adopting rules for the conduct of the hearing (December 21, 2016) and the discovery plan (January 17). Complainants’ and Parties Supporting Complainants’ Direct Testimony and Exhibits (with summaries) were due and filed on February 1. Respondents’ and Parties Supporting Respondents’ Answering Testimony and Exhibits (with summaries) are due March 23. Hearings are scheduled for August 2-8, with an initial decision to be issued November 15, 2017.

If you have any questions concerning this matter, please contact Eric Runge (617-345-4735; [email protected]) or Jamie Blackburn (202-218-3905; [email protected]).

• 206 Proceeding: RNS/LNS Rates and Rate Protocols (EL16-19) Settlement discussions in this proceeding are on-going. As previously reported, the FERC instituted this

Section 206 proceeding on December 28, 2015, finding that the ISO Tariff is unjust, unreasonable, and unduly discriminatory or preferential because the Tariff “lacks adequate transparency and challenge procedures with regard to the formula rates” for Regional Network Service (“RNS”) and Local Network Service (“LNS”).14 The FERC also found that the RNS and LNS rates themselves “appear to be unjust, unreasonable, unduly discriminatory or preferential, or otherwise unlawful” because (i) “the formula rates appear to lack sufficient detail in order to determine how certain costs are derived and recovered in the formula rates” and “could result in an over-recovery of costs” due to the “the timing and synchronization of the RNS and LNS rates”.15 Accordingly, the FERC established hearing and settlement judge procedures to develop just and reasonable formula rate protocols to be included in the ISO-NE Tariff and to examine the justness and reasonableness of the RNS and LNS rates. The FERC encouraged the parties to make every effort to settle this matter before hearing procedures are commenced.16 Hearings are being held in abeyance pending the outcome of settlement judge procedures underway.17 The FERC-established refund date is January 4, 2016.18

Settlement Judge Procedures. As previously reported, John P. Dring was designated the Settlement Judge in these proceedings. Five settlement conferences have thus far been held: January 19, March 24, April 28, August 30, and November 18 (telephonically). Judge Dring issued his latest status report on December 8 indicating that the parties are making progress toward settlement and recommending that the settlement procedures be continued. The Transmission Committee is being kept apprised of settlement efforts. If you have any questions concerning this matter, please contact Eric Runge (617-345-4735; [email protected]).

14 ISO New England Inc. Participating Transmission Owners Admin. Comm. et al., 153 FERC ¶ 61,343 (Dec. 28, 2015), reh’g denied, 154 FERC ¶ 61,230 (Mar. 22, 2016).

15 Id. at P 8. 16 Id. at P 11. 17 Id.18 The notice of this proceeding was published in the Fed. Reg. on Jan. 4, 2016 (Vol. 81, No. 1) p. 89.


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• Base ROE Complaints II & III (2012 & 2014) (EL13-33 and EL14-86) (consolidated) Judge Sterner’s findings and Initial Decision, and pleadings in response thereto, remain pending

before the FERC. As previously reported, the FERC, in response to second (EL13-33)19 and third (EL14-86)20 complaints regarding the TOs’ 11.14% Base ROE, issued orders establishing trial-type, 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;21 the second, in EL14-86, was issued on November 24, 2014, established a 15-month refund period beginning July 31, 2014,22 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.”23 The TOs requested rehearing of both orders. On May 14, 2015, the FERC denied rehearing of both orders.24 On July 13, 2015, the TOs appealed those orders to the DC Circuit Court of Appeals (see Section XIV below), and that appeal remains pending.

Hearings and Trial Judge Initial Decision. Initial hearings on these matters were completed on July 2, 2015. In mid-December 2015, Judge Sterner reopened the record for the limited purpose of having the discounted cash flow (“DCF”) calculations re-run in accordance with the FERC’s preferred approach and re-submitted. A limited hearing on that supplemental information was held on February 1, 2016. On March 22, 2016, Judge Sterner issued his 939-paragraph, 371-page Initial Decision, which lowered the base ROEs for the EL13-33 and EL14-86 refund periods from 11.14% to 9.59% and 10.90%, respectively.25 The Decision also lowered the ROE ceilings. Judge Sterner’s decision, if upheld by the FERC, would result in refunds totaling as much as $100 million, largely concentrated in the EL13-33 refund period. Briefs on exceptions were filed by the TOs, Complainant-Aligned Parties (“CAPs”), EMCOS, and FERC Trial Staff on April 21, 2016; briefs opposing exceptions, on May 20, 2016. Judge Sterner’s findings and Initial Decision, and pleadings in response thereto, remain pending, and will be subject to challenge, before the FERC. The 2012/14 ROE Initial Decision and its findings can be approved or rejected, in whole or in part.

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]).

19 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%.

20 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 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.

21 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).

22 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).

23 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).

24 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).

25 Environment Northeast, et al. v. Bangor Hydro-Elec. Co., et al. and Mass. Att’y Gen. et al. -v- Bangor Hydro et al., 154 FERC ¶ 63,024 (Mar. 22, 2016) (“2012/14 ROE Initial Decision”).


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• ICR-Related Values and HQICCs – Annual Reconfiguration Auctions (ER17-472) On January 9, the FERC accepted materials that identify the Installed Capacity Requirement (“ICR”),

Local Sourcing Requirements (“LSR”), Maximum Capacity Limits (“MCL”), Hydro Quebec Interconnection Capability Credits (“HQICCs”), and capacity requirement values for the System-Wide Demand Curve (collectively, the “ICR-Related Values”) for the third annual reconfiguration auction (“ARA”) for the 2017/18 Capability Year to be held March 1, 2017, the second ARA for the 2018/19 Capability Year to be held August 1, 2017, and the first ARA for the 2019/20 Capability Year to be held June 5, 2017. The ICR-Related Values were accepted effective as of January 30, 2017, as requested. Unless the January 9 order is challenged, this proceeding will be concluded. If you have any questions concerning these matters, please contact Eric Runge (617-345-4735; [email protected]).


• CONE & ORTP Updates (ER17-795)

On January 13, the ISO filed updated FCM Cost of New Entry (“CONE”), Net CONE and Offer Review Trigger Price (“ORTP”) values. With respect to CONE and Net CONE, the ISO will use a gas-fired simple cycle combustion-turbine (“CT”) as the reference technology for the updated values, $11.35 and $8.04, respectively. The ISO will use a Capacity factor of 32%, resulting in a $11.02 ORTP for on-shore wind resources. The ISO requested a March 15, 2017 effective date for the new values to coincide with the beginning of the administrative cycle for FCA12. The CONE & ORTP Updates were not supported by the Participants Committee when considered at the January 6 meeting. Comments on this filing are due on or before February 3. Doc-less interventions have thus far been filed by Calpine, ConEd, Exelon, National Grid, and NESCOE. If you have any questions concerning this proceeding, please contact Sebastian Lombardi (860-275-0663; [email protected]).

• Order 825 Compliance: 5-Min. Settlement of Regulation Capacity & Service Credit (ER17-774) On January 11, the ISO and NEPOOL jointly filed changes that, in accordance with Order 825,26

change the settlement interval for the Regulation Capacity Credit and Regulation Service Credit to five minutes (rather than hourly). A December 1, 2017 effective date was requested. The Regulation Capacity & Service Credit changes were supported by the Participants Committee by way of the January 6, 2017 Consent Agenda (Item #5). Comments on this filing were due on or before February 1; none were filed. Doc-less interventions were filed by EPSA, National Grid, and NRG. This matter is pending before the FERC. If you have any questions concerning this proceeding, please contact Sebastian Lombardi (860-275-0663; [email protected]).

• Sub-Hourly Settlement NCPC Changes (ER17-680)

On December 27, 2016, the ISO and NEPOOL jointly filed changes to the Net Commitment Period Compensation (“NCPC”) credit rules (the “NCPC Revisions”) related (i) to the implementation of sub-hourly Real-Time settlement (including adding “Real-Time Dispatch Lost Opportunity Cost NCPC Credit” as an NCPC credit type) and (ii) to Dispatchable Asset Related Demand (“DARD”). A March 1, 2017 effective date (coincident with the Real-Time sub-hourly settlement effective date) was requested. The NCPC Revisions were supported by the Participants Committee by way of the December 2, 2016 Consent Agenda (Item #3). Comments on this filing were due on or before January 17, 2017; none were filed. Doc-less interventions were filed by Eversource, Exelon and National Grid. This matter is pending before the FERC. If you have any questions concerning this proceeding, please contact Sebastian Lombardi (860-275-0663; [email protected]).

26 Settlement Intervals and Shortage Pricing in Markets Operated by Regional Transmission Organizations and Indep. Sys. Operators, Order No. 825, 155 FERC ¶ 61,276 (June 16, 2016) (“Order 825”).


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• Effective Date Update: Fast Start Pricing and DARD Pump Parameter Changes (ER17-576) On December 19, 2016, the ISO filed changes to make March 1, 2017 (rather than March 31, 2017)

the effective date for the following two sets of previously-approved Tariff Changes: (i) the Fast Start Changes (improvements to Real-Time price formation when fast start resources are deployed);27 and (ii) the DARD Pump Parameter Changes (improvements to pump storage hydro-generating resource modeling and dispatch).28 The accelerated effective date was requested to make the two sets of changes effective coincident with the March 1, 2017 implementation of sub-hourly settlement. Comments on this filing were due on or before January 9, 2017; none were filed. Doc-less interventions were filed by NEPOOL, Eversource and National Grid. This matter is pending before the FERC. If you have any questions concerning this proceeding, please contact Sebastian Lombardi (860-275-0663; [email protected]).

• Natural Gas Index Changes (ER17-337) On January 9, the FERC accepted changes to the Tariff that replace the Algonquin Citygates location

with the AGT-CG (Non-G) hub (a newer hub established by ICE) as the source for natural gas prices to be used in the calculation of the Peak Energy Rent Strike Price, the Import Capacity Resource offer threshold price, and the Forward Reserve threshold price (“Natural Gas Index Changes”).29 The Natural Gas Index Changes were accepted effective as of January 10, 2017, as requested. In accepting the Natural Gas Index Changes, the FERC rejected Dominion’s alternative proposal, finding that Dominion had not provided any evidence that the continued use of the AGT-CG index would meet the FERC’s minimum index conditions.30

Challenges, if any, to the Natural Gas Index Changes Order are due on or before February 8. If you have any questions concerning this proceeding, please contact Sebastian Lombardi (860-275-0663; [email protected]).

• FCM Enhancements (ER16-2451) The FERC’s FCM Enhancements Order31 remains subject to a request for rehearing by Indicated

NYTOs.32 As previously reported, the FERC accepted changes to the Tariff to increase liquidity in the FCM by increasing Market Participant opportunities to enter into reconfiguration auctions and bilateral contracts for the exchange of CSOs (“FCM Enhancements”). Specifically, the FCM Enhancements (i) modify certain FCM qualification rules to facilitate the ability of New Capacity Resources to supply capacity beginning four months after participating in their first FCA; (ii) provide Import Capacity Resources backed by one or more External Resources the opportunity (currently available to generators and demand response) to provide capacity beginning one or two years after participating in their first FCA; and (iii) establish a new form of bilateral contracting in which Market Participants can, as the Capacity Commitment Period approaches, trade CSOs for a seasonal strip of CSOs. The FCM Enhancements included several smaller improvements as well, including the elimination of a requirement that the ISO make a FERC filing in order to terminate the CSO of a resource that has voluntary withdrawn from the FCM resource development process. The FCM Enhancements were accepted, effective as of October 19, 2016, as requested.

27 See ISO New England Inc. and New England Power Pool, Revisions to Fast-Start Pricing and Dispatch, Docket No. ER15-2716 (filed Sep. 24, 2015; accepted Oct. 19, 2015).

28 See ISO New England Inc. and New England Power Pool Participants Comm., DARD Pump Parameter Changes, Docket No. ER16-954 (filed Feb. 17, 2016; accepted Mar. 22, 2016).

29 ISO New England Inc., 158 FERC ¶ 61,016 (Jan. 9, 2017) (“Natural Gas Index Changes Order”). 30 Id. at PP 20-21. The FERC’s conditions for minimum levels of activity at a particular trading location are:

(1) average daily volume traded of a least 25,000 MMBtus/day for gas or 2,000 MWh/day for power; (2) average daily number of transactions of five, eight, 10, or more (depending on whether it is a daily, weekly, or monthly index); and (3) average daily number of counterparties of five, eight, 10, or more (depending on whether it is a daily, weekly, or monthly index). See Price Discovery in Natural Gas and Electric Markets, 109 FERC ¶ 61,184 at P 66.

31 ISO New England Inc. and New England Power Pool Participants Comm. and NY Indep. Sys. Op., Inc., 157 FERC ¶ 61,025 (Oct. 18, 2016) (“FCM Enhancements Order”), reh’g requested.

32 “Indicated NYTOs” are Central Hudson Gas & Electric, Consolidated Edison Co. of New York, New York Power Authority, New York State Electric & Gas, Orange and Rockland Utilities, Inc., and Rochester Gas and Electric.


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In accepting the FCM Enhancements, the FERC noted that “protestors do not challenge the justness and reasonableness of the specific tariff revisions … the concerns raised by NYISO are not the result of ISO-NE’s proposed tariff revisions, but result from NYISO’s treatment of generators that export capacity from within a constrained locality under its current market rules.”33 Accordingly, the FERC was “not persuaded that the potential behavior of New York suppliers provides a sufficient basis to reject ISO-NE’s filing in this case, and deferring the effective date of an otherwise just and reasonable proposal would be inconsistent with the notice provision in section 205 of the FPA.”34 The FERC did acknowledge NYISO’s concerns about a potential flaw in its market rules, and encouraged NYISO stakeholders to timely complete discussions underway to address that flaw.

As noted above, on November 17, Indicated TOs’ requested rehearing of the FCM Enhancements Order. On December 19, the FERC issued a tolling order affording it additional time to consider Indicated TOs’ rehearing request, which remains pending before the FERC.

NYISO Tariff Revisions in Response to FCM Enhancements (ER17-446). On January 27, the FERC conditionally accepted in part, and rejected, in part, NYISO tariff revisions proposed in response to the acceptance of the FCM Enhancements, to correct a pricing inefficiency in NYISO’s Installed Capacity (“ICAP”) market design related to capacity exports from certain zones in the New York Control Area.35

Specifically, the FERC accepted NYISO’s proposed locality exchange factor methodology to be implemented immediately but rejected NYISO’s proposed one-year transitional mechanism.36 In accepting the immediate implementation of NYISO’s Locality Exchange Factor methodology, the FERC found the proposed methodology “just and reasonable because it corrects a pricing inefficiency in NYISO’s ICAP market design. NYISO’s proposed methodology will now recognize that an exporting generator continues to operate within its Locality, which would be reflected in the ICAP Spot Market Auction clearing prices by accounting for the portion of exported capacity that can be replaced by capacity located in Rest of State. Therefore, NYISO’s proposal will ensure that prices within the Localities reflect actual market conditions and prices.”37 In rejecting the transition mechanism, the FERC found that “that the mechanism lacks analytical basis and will delay efficient market signals … because it could overstate the extent to which the capacity export will unencumber NYISO’s transmission capability into Southeast New York.”38 NYISO was directed submit a compliance filing on or before February 27, 2017 removing the one-year transition mechanism provisions.39

If you have any questions concerning these proceedings, please contact Sebastian Lombardi (860-275-0663; [email protected]).

• Waiver Request: RTEG Resource Type/De-List (ISO-NE) (ER16-1904) On January 19, the FERC denied CPower’s request for rehearing of the ISO RTEG Waiver Request

Order.40 As previously reported, the FERC granted the limited waiver requested by the ISO of Tariff Sections III.13.1.4.2.5.2, III.13.1.4.3.1.2 & III.13.1.2.3.1.1.41 The waiver allows Real-Time Emergency

33 Id. at P 31. 34 Id.35 NY Indep. Sys. Op., Inc., 158 FERC ¶ 61,064 (Jan. 27, 2017). 36 Id. at P 20. 37 Id. at P 35. 38 Id. at P 55. 39 Id. at P 61. 40 ISO New England Inc., 158 FERC ¶ 61,033 (Jan. 19, 2017) (“ISO RTEG Waiver Request Rehearing

Order”). 41 ISO New England Inc., 156 FERC ¶ 61,096 (Aug. 8, 2016) (“ISO RTEG Waiver Request Order”), reh’g

denied, 158 FERC ¶ 61,033 (Jan. 19, 2017).


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Generation Resources (“RTEGs”) either to change their resource type to Real-Time Demand Response Resources or to de-list (“Waiver Request”), particularly in connection with FCA11, but also, to the extent applicable, for FCA8, FCA9, and FCA10, in light of (i) a May 4, 2016 order of the United States Court of Appeals for the District of Columbia Circuit (“DC Circuit”) reversing and remanding United States Environmental Protection Agency (“EPA”) rules that provided for a 100-hour exemption for operation of emergency engines for purposes of emergency demand response under National Emissions Standards; and (ii) an April 15, 2016 EPA Guidance Memorandum, which in anticipation of the DC Circuit order, indicated that the EPA will not develop an alternative to the rules reversed by the DC Circuit. In granting the waiver, the FERC rejected CPower’s request for limited modifications thereto, finding CPower’s proposed modification “beyond the scope of ISO-NE’s instant proposal,” and that it “would decrease incentives for RTEG market participants to exhaust existing remedies”. The FERC also found “speculative CPower’s characterization that applying the FCA Starting Price to the Third Annual Reconfiguration Auction, rather than the FCA Payment Rate, would essentially cause a ‘penalty’.”42 On September 7, CPower requested rehearing of the ISO RTEG Waiver Request Order, which, as noted above, the FERC denied on January 19. In dismissing rehearing, the FERC clarified that it dismissed CPower’s proposal without prejudice.43

If you have any questions concerning this proceeding, please contact Sebastian Lombardi (860-275-0663; [email protected]) or Pat Gerity (860-275-0533; [email protected]).

• FCM Resource Retirement Reforms (ER16-551) A request for rehearing by NEGPA, NextEra and Exelon of the FERC’s Resource Retirement Reforms

Order44 remains pending. As previously reported, the FERC conditionally accepted, effective March 1, 2016, changes to the FCM rules for resource retirements proposed by the ISO and its Internal Market Monitor (“IMM”) (the “ISO/IMM Proposal”). The FERC conditioned its acceptance of the ISO/IMM Proposal on the filing of Tariff revisions “establishing a materiality threshold for determining whether or not a particular proxy de-list bid will replace a Retirement Bid in an FCA,”45 which were filed with and accepted by the FERC.46 NEPGA, Exelon and NextEra jointly requested rehearing of the Resource Retirement Reforms Order. On June 13, the FERC issued a tolling order affording it additional time to consider the joint rehearing request, which remains pending before the FERC. If you have any questions concerning this matter, please contact Sebastian Lombardi (860-275-0663; [email protected]).

• Demand Curve Changes Remand Proceedings (ER14-1639) Rehearing remains pending of the FERC’s April 8, 2016 Demand Curve Remand Order.47 As previously

reported, the FERC conditionally accepted, on May 30, 2014, revisions to the FCM rules that establish a system-wide sloped demand curve (“Demand Curve Changes”).48 The Demand Curve Changes defined the shape of the

42 Id. at P 19. 43 ISO RTEG Waiver Request Rehearing Order at P 21. 44 ISO New England Inc., 155 FERC ¶ 61,029 (Apr. 12, 2016), reh’g requested (“Resource Retirement

Reforms Order”). As previously reported, the ISO/IMM Proposal requires (i) that capacity suppliers with existing resources to submit a price for the retirement of a resource (to replace the existing Non-Price Retirement Request process), (ii) the use of a Proxy De-List Bid, and (iii) notice of the potential retirement and proposed retirement price to be submitted prior to the commencement of an FCA’s qualification process for new resources. The ISO/IMM Proposal was considered but not supported by the Participants Committee at its Dec. 4, 2015 meeting.

45 Id. at P 62. 46 ISO New England Inc., 15 FERC ¶ 61,067 (July 27, 2016) (“Resource Retirement Reforms Compliance

Order”). 47 ISO New England Inc. and New England Power Pool Participants Comm., 155 FERC ¶ 61,023 (Apr. 8,

2016), reh’g requested (“Demand Curve Remand Order”) (affirming its earlier finding that the renewables exemption from the minimum offer price rule is just and reasonable, and not unduly discriminatory or preferential).

48 ISO New England Inc. and New England Power Pool Participants Comm., 147 FERC ¶ 61,173 (May 30, 2014) (“Demand Curve Order”).


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system-wide sloped demand curve (with key points defined by CONE and the 0.1 days/year LOLE target), extended the period during which a Market Participant may “lock-in” the capacity price for a new resource from five to seven years, establish a limited renewables resource exemption, and eliminated, at the system-wide level, the administrative pricing rules that were necessary in certain market conditions under the vertical demand curve construct. In response to challenges, the FERC denied rehearing of the Demand Curve Order,49 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).50 A compliance filing clarifying that a resource may not utilize both the renewable resource exemption and the new resource price lock-in was submitted, accepted, and became effective on May 2, 2015.51 NextEra, NRG and PSEG petitioned the DC Circuit Court of Appeals for review of the FERC’s Demand Curve orders (March 30, 2015). Following submission of Petitioner and Intervenor for Petitioner briefs (October 5 and 20, 2015, respectively), the FERC, on November 20, 2015, requested that the Court remand the case back to the FERC for further proceedings (stating that “review of the opening briefs indicates that further consideration by the Commission is appropriate”). On December 1, 2015, the Court granted FERC’s unopposed motion, and remanded the case back to the FERC for further proceedings, which, as noted above, resulted in the Demand Curve Remand Order. NextEra, NRG and PSEG jointly requested rehearing of the Demand Curve Remand Order on May 9, 2016. On June 3, NESCOE answered the NextEra/PSEG/NRG rehearing request. On June 8, 2016, the FERC issued a tolling order affording it additional time to consider the NextEra/PSEG/NRG request for rehearing, which remains pending before the FERC. If you have any questions concerning these matters, please contact Sebastian Lombardi (860-275-0663; [email protected]).

• 2013/14 Winter Reliability Program Remand Proceeding (ER13-2266) On August 8, 2016, the FERC issued its long-awaited remand order.52 As previously reported, the

DC Circuit remanded the FERC’s decision in ER13-2266, agreeing with TransCanada that the record upon which the FERC relied is devoid of any evidence regarding how much of the 2013/14 Winter Reliability Program cost was attributable to profit and risk mark-up (without which the FERC could not properly assess whether the Program’s rates were just and reasonable), and directing the FERC to either offer a reasoned justification for the order in ER13-2266 or revise its disposition to ensure that the Program rates are just and reasonable.53 In the 2013/14 Winter Reliability Program Remand Order, the FERC directed the ISO to request from Program participants the basis for their bids, including the process used to formulate the bids, and to file with the FERC, by December 6, 2016, a compilation of that information, an IMM analysis of that information, and the ISO’s recommendation as to the reasonableness of the bids, so that the FERC can further consider the question of whether the Bid Results were just and reasonable.54 On November 7, the ISO requested, and on November 15 the FERC granted, a 45-day extension of time to submit the directed filing. The ISO submitted its compliance filing on January 23. In that filing, the ISO reported the IMM’s conclusion that “the auction was not structurally competitive and a ‘small proportion’ of the total cost of the program may be the result of the exercise of market power” but that the “vast majority of supply was offered at prices that appear reasonable and that, for a number of reasons, it is difficult to assess the impact of market power on cost.” Based on the IMM and additional analysis, the ISO recommended that “there is insufficient demonstration of market power to warrant modification of program.” Comments on the ISO’s report are due

49 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).

50 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”).

51 The changes become effective with FCA-10, 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.

52 ISO New England Inc., 156 FERC ¶ 61,097 (Aug. 8, 2016) (“2013/14 Winter Reliability Program Remand Order”).

53 TransCanada Power Mktg. Ltd. v. FERC, 2015 U.S. App. LEXIS 22304 (D.C. Cir. 2015). 54 2013/14 Winter Reliability Program Remand Order at P 17.


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on or before February 13. If you have any questions concerning these matters, please contact Sebastian Lombardi (860-275-0663; [email protected]).

IV. OATT Amendments / TOAs / Coordination Agreements

• Orders 827/828 Compliance Filing: New England (ER16-2695) The revisions to Schedules 22 and 23 of the ISO OATT filed jointly by the ISO, NEPOOL and PTO

AC on September 29, 2016 to comply with the FERC Order Nos. 82755 and 82856 are pending before the FERC. As previously reported, Schedules 22 and 23 were revised to incorporate the pro forma revisions set forth in Orders 827 and 828 with variations necessary to recognize New England reactive power requirements and overall structure previously accepted under the “independent entity variation” standard and to make certain enhancements “consistent with or superior to” the pro forma revisions. An October 5, 2016 effective date was requested. The compliance filing changes were supported by the Participants Committee at its September 9 meeting. Comments on this filing were due on or before October 20, 2016; none were filed. Doc-less interventions were filed by National Grid and NRG. This matter is pending before the FERC. If you have any questions concerning these matters, please contact Eric Runge (617-345-4735; [email protected]).

• Attachment K Revisions (Public Policy Transmission Studies Timeline Modifications and Clean-Up/Admin Changes to Section 6.3 and Appendices 2 & 3) (ER17-857) On January 26, the ISO and NEPOOL filed revisions to Attachment K of the OATT to modify the

timeline associated with the Public Policy Transmission Study Process and to reflect clean-up changes to Section 6.3(Interregional Coordination) and to Appendices 2 (List of Entities Enrolled in the Transmission Planning Region) and 3 (List of Qualified Transmission Project Sponsors). A March 22, 2017 effective date was requested. The Attachment K Revisions were supported by the Participants Committee at its January 6 meeting (Consent Agenda Item #s 1 and 2). Comments on this filing are due on or before February 16. A doc-less intervention has thus far been filed by NESCOE. If you have any questions concerning this proceeding, please contact Eric Runge (617-345-4735; [email protected]).



VI. Schedule 20/21/22/23 Changes

• Schedule 23: FPL Energy Wyman SGIA (ER17-581) On January 19, the FERC accepted a non-conforming, 3-party SGIA between the ISO, Central Maine

Power (“CMP”), and FPL Energy Wyman (“Wyman”). As previously reported, the SGIA governs the interconnection of Wyman’s approximately 16 MW battery energy storage facility through existing facilities that are currently owned, operated and maintained by Wyman and FPL Energy Wyman IV (“Wyman IV”) for Wyman Station and Wyman Station IV. The SGIA is non-conforming in that it reflects the fact that the Interconnection Facilities include facilities that are not for the sole use of Wyman’s battery storage facility. The SGIA was accepted effective as of November 30, 2016, as requested. Unless the January 19 order is challenged, this proceeding will be concluded. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).

55 Reactive Power Requirements for Non-Synchronous Generation, Order No. 827, 155 FERC ¶ 61,277 (June 16, 2016) (“Order 827”), order on clarification and reh’g, 157 FERC 61,003 (Oct. 3, 2016).

56 Requirements for Frequency and Voltage Ride Through Capability of Small Generating Facilities, Order No. 828, 156 FERC ¶ 61,062 (July 21, 2016) (“Order 828”).


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• Schedule 21-ES: Eversource Recovery of NU/NSTAR Merger-Related Costs (ER16-1023) On January 31, the FERC accepted Eversource’s November 22 offer of settlement57 to resolve the

issues in this proceeding (as described in previous reports, principally whether the $38.9 million in FERC-jurisdictional, merger-related transmission costs incurred as the result of the April 10, 2012 NU/NSTAR merger that Eversource sought to recover through changes to Schedule ES-21 were just and reasonable58). Eversource was directed to file revised tariff records in eTariff format, on or before March 2, 2017, to reflect the FERC’s approval of the settlement. Unless the January 31 order is challenged, this proceeding will be concluded. If you have any questions concerning these proceedings, please contact Pat Gerity ([email protected]; 860-275-0533).

• Schedule 21-EM: Recovery of Bangor Hydro/Maine Public Service Merger-Related Costs (ER15-1434 et al.) On June 2, 2016, the FERC accepted, but established hearing and settlement judge procedures for,59

March 31 filings by Emera Maine in which Emera Maine sought authorization to recover certain merger-related costs viewed by the FERC’s Office of Enforcement’s Division of Audits and Accounting (“DAA”) to be subject to the conditions of the orders authorizing Emera Maine’s acquisition of, and ultimate merger with, Maine Public Service (“Merger Conditions”). As previously reported, the Merger Conditions imposed a hold harmless requirement, and required a compliance filing demonstrating fulfillment of that requirement, should Emera Maine seek to recover transaction-related costs through any transmission rate. Following its recent audit of Emera Maine, DAA found that Emera Maine “inappropriately included the costs of four merger-related capital initiatives in its formula rate recovery mechanisms” and “did not properly record certain merger-related expenses incurred to consummate the merger transaction to appropriate non-operating expense accounts as required by [FERC] regulations [and] inappropriately included costs of merger-related activities through its formula rate recovery mechanisms” without first making a compliance filing as required by the merger orders.

In the June 2 Order, the FERC found that the Compliance Filings raise issues of material fact that could not be resolved based on the record, and are more appropriately addressed in the hearing and settlement judge procedures.60 The FERC reiterated several points with respect to transaction-related cost recovery explained in prior FERC orders and provided guidance on other transaction-related cost recovery points.61

The FERC encouraged the parties to make every effort to settle their disputes before hearing procedures are commenced, and will hold the hearing in abeyance pending the outcome of settlement judge procedures.62

The separate compliance filing dockets were consolidated for the purposes of settlement, hearing and decision.63

Settlement Judge Procedures. ALJ John Dring is the settlement judge for these proceedings. A first settlement conference was held on June 29; a second settlement conference, October 25. A third settlement conference, scheduled for November 22, 2016, was cancelled and subsequently held on December 1. Since the last Report, Judge Dring issued a status report indicating that the parties have reached a settlement in principal and are memorializing their agreement, and recommending settlement procedures be continued. If you have any questions concerning these matters, please contact Pat Gerity ([email protected]; 860-275-0533).

57 ISO New England Inc. et al., 158 FERC ¶ 61,096 (Jan. 31, 2017). 58 See ISO New England Inc. et al., 155 FERC ¶ 61,136 (May 3, 2016). 59 Emera Maine and BHE Holdings, 155 FERC ¶ 61,230 (June 2, 2016) (“June 2 Order”). 60 Id. at P 24. 61 Id. at PP 25-26. 62 Id. at P 27. 63 Id. at P 21; Ordering Paragraph (B).


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VII. NEPOOL Agreement/Participants Agreement Amendments



• IMM Quarterly Markets Reports - 2016 Fall (ZZ16-4)

On January 27, the Internal Market Monitor (“IMM”) filed with the FERC its report for the Fall quarter of 2016 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. These filings are not noticed for public comment by the FERC.

• LFTR Implementation: 33rd Quarterly Status Report (ER07-476; RM06-08) The ISO filed the thirty-third of its quarterly status reports regarding LFTR implementation on

January 13, 2017. The ISO again reported its plan to focus on implementation of the monthly reconfiguration auctions (accepted in ER12-2122). The ISO reported that it will file in early 2017 a Participants Committee-supported financial assurance design and for monthly reconfiguration auctions and will subsequently renew efforts to address LFTR financial assurance issues leveraging that design. As in previous reports, the ISO described the 18-month implementation process that will follow once the LFTR financial assurance issues are resolved. These status reports are not noticed for public comment and no comments have been filed.

• Opinion 531-A Local 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 2015; 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]).

• Opinions 531-A/531-B Regional Refund Reports (EL11-66) On November 2, 2015, the TOs submitted a refund report documenting resettlements of regional

transmission charges by the ISO in compliance with Opinions No. 531-A64 and 531-B.65 As previously reported, refunds resulting from Opinion No. 531-B were completed by August 31, 2015. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• Opinions 531-A/531-B Local Refund Reports (EL11-66) In accordance with Opinions 531-A and 531-B, the following TOs filed their refund reports for their

customers taking local service during the refund period (comment date on refund report noted in parentheses):

♦ Central Maine Power (Jan 21, 2016) ♦ Emera Maine (Jan 29, 2016) ♦ Eversource (CL&P, PSNH, WMECO) (Jan 21, 2016) ♦ National Grid (Jan 13, 2016) ♦ NHT (Jan 21, 2016) ♦ NSTAR (Jan 21, 2016) ♦ United Illuminating (Jan 21, 2016); supplement (Feb 1, 2016) ♦ VT Transco (Feb 3, 2016)

All comments dates have passed. No comments were filed in response to any of the reports and each is pending before the FERC. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).

64 Martha Coakley, Mass. Att’y Gen. et al., 149 FERC ¶ 61,032 (Oct. 16, 2014) (“Opinion 531-A”). 65 Martha Coakley, Mass. Att’y Gen. et al., Opinion No. 531-B, 150 FERC ¶ 61,165 (Mar. 3, 2015) (“Opinion

531-B”).


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• 2015 ISO-NE SIL Limits (AD10-2-009) On December 20, 2016, the ISO submitted an information filing with the 2015 simultaneous import

limits (“SIL”) for the New England market and the Connecticut Import Interface (“CT Import Interface”) and the Southwest Connecticut Import Interface (“SWCT Import Interface”) geographic submarkets. The SILs may be used by New England sellers in updated market power indicative screens and Delivered Price Test (“DPT”) analyses submitted under Order 697. [Note: in the GDF Suez Energy Resources/Atlas Power (Dynegy/ECP) order in EC16-93/94 discussed in Section XI below, the FERC found that “Connecticut and Southwest Connecticut are no longer submarkets in the ISO-NE energy market.”66] If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).


• February 2017 Membership Filing (ER17-899) On January 31, NEPOOL requested that the FERC accept (i) the Governance Only End User membership

of Natural Resources Defense Council (“NRDC”), effective April 1, 2017; (ii) the termination of the Participant status, each effective January 1, 2017, of Provisional Members Artis Energy Holdings, LLC (formerly Nxegen, LLC and EMI Power Systems, Inc., Jeffrey A. Jones, P.E. (Related Person of Maine Energy LLC), and Powerex Corp. (Supplier Sector); and (iii) the name change of NextEra Energy Marketing, LLC (f/k/a/ NextEra Energy Power Marketing, LLC). Comments on this filing are due on or before February 21.

• January 2017 Membership Filing (ER17-682) On January 25, the FERC accepted (i) the memberships of Emera Energy Services Subsidiary Nos. 11,

12, 13, 14, and 15 [each Related Persons of Emera Maine, Transmission Sector]; (ii) the termination of the Participant status of Summit Hydropower (AR Sector Small RG Group Member) and StatArb Investments (Supplier Sector); and (iii) the name change of Calpine Energy Solutions (f/k/a/ Noble Americas Energy Solutions).


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]).

• Reliability Standard Retirement: BAL-004-0 (RD17-1) On January 18, 2017, the FERC approved NERC’s retirement of Reliability Standard BAL-004-0 (Time

Error Correction) which, due to improvements to other Standards (e.g. BAL-003-1.1 and BAL-001-2) had become redundant. BAL-004-0 will be retired effective on the later of: (i) April 1, 2017 or (ii) the effective date of the retirement/reservation of North American Energy Standard Board (“NAESB”) WEQ006 Manual Time Error Correction Business Practice Standard (“NAESB WEQ-006”). Unless the January 18 order is challenged, this proceeding will be concluded.

• New Reliability Standards: PRC-027-1 and PER-006-1 (RM16-22) On September 2, 2016, NERC filed for approval (i) two new Reliability Standards -- PRC-027-1

(Coordination of Protection Systems for Performance During Faults) and PER-006-1 (Specific Training for Personnel), (ii) associated Glossary definitions, (iii) an implementation plan, (iv) VRFs and VSLs, and (v) the retirement of PRC-001-1.1(ii) (together, the “Protection System Changes”). NERC stated that the purpose of the Protection System Changes is to: (1) maintain the coordination of Protection Systems installed to detect and isolate Faults on Bulk Electric System (“BES”) Elements, such that those Protection Systems operate in the intended sequence during Faults; and (2) require registered entities to provide training to their relevant personnel on Protection Systems and Remedial Action Schemes (“RAS”) to help ensure that the BES is reliably operated. NERC requested that the new Standards and definitions become effective on the first day of the first calendar quarter that is 24 months following the effective date of the FERC’s order approving the Standards. As of the

66 Atlas Power Finance, LLC et al., 157 FERC ¶ 61,237 (Dec. 22, 2016)) at P 48.


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date of this Report, the FERC still has not noticed a proposed rulemaking proceeding or otherwise invited public comment.

• NOPR: Revised Reliability Standards: BAL-005-1 & FAC-001-3 (RM16-13) On September 22, the FERC issued a NOPR proposing to approve Reliability Standards BAL-005-1

(Balancing Authority Control) and FAC-001-3 (Facility Interconnection Requirements), and associated Glossary definitions, implementation plan, VRFs and VSLs (together, the “Frequency Control Changes”).67 As previously reported, NERC stated that the Frequency Control Changes clarify and refine Requirements for accurate, consistent, and complete reporting of Area Control Error (“ACE”) calculations. NERC indicated that the Frequency Control Changes will improve reliability by supporting efforts to maintain Interconnection frequency at 60 Hz in a manner consistent with FERC directives, technological developments, and NERC’s current framework of integrated Reliability Standards. NERC requested that the Frequency Control Changes become effective on the first day of the first calendar quarter that is 12 months after the effective date of an order approving the Standard, pursuant to the Implementation Plans included with the Changes. Comments on the Frequency Control Changes NOPR were due on or before November 28, 2016,68 and were filed by NERC, EEI, Bonneville, Idaho Power and J. Appelbaum. The Frequency Control Changes NOPR is now pending before the FERC.

• Order 835: Revised Reliability Standard: BAL-002-2 (RM16-7) On January 19, the FERC approved revised Reliability Standard -- BAL-002-2 (Disturbance Control

Performance - Contingency Reserve for Recovery from a Balancing Contingency Event), and eight associated Glossary definitions, implementation plan, VRFs and VSLs (together, the “BAL Changes”).69 Order 835 also directs NERC: (1) to collect and report on data regarding additional MW losses following Reportable Balancing Contingency Events during the Contingency Reserve Restoration Period; and (2) to study and report on the reliability risks associated with MW losses above the most severe single contingency (“MSSC”) that do not cause energy emergencies. As previously reported, BAL-002-2 is intended to ensure that balancing authorities and reserve sharing groups are able to recover from system contingencies by deploying adequate reserves to return their Area Control Error (“ACE”) to defined values and by replacing the capacity and energy lost due to generation or transmission equipment outages. Order 835 will be effective [60 days after publication in the Federal Register].70

• Order 830-A: New Reliability Standard: TPL-007-1 (RM15-11) As previously reported, the FERC issued, on September 22, 2016, a final rule approving a new Reliability

Standard -- TPL-007-1 (Geomagnetic Disturbance (“GMD”) Operations) -- and one new definition (Geomagnetic Disturbance Vulnerability Assessment), associated VRFs and VSLs (“Order 830”).71 In addition, the FERC directed 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, (ii) to require the collection of necessary geomagnetically-induced current monitoring and magnetometer data and to make such data publicly available; and (iii) to include a one-year deadline for the development of corrective action plans and two and four-year deadlines to complete mitigation actions involving non-hardware and hardware mitigation, respectively. The FERC also directed NERC to submit a work plan and, subsequently, one or more informational filings that

67 Balancing Authority Control, Inadvertent Interchange, and Facility Interconnection Rel. Standards, 156 FERC ¶ 61,210 (Sep. 22, 2016) (“Frequency Control Changes NOPR”).

68 The Frequency Control Changes NOPR was published in the Fed. Reg. on Sep. 28, 2016 (Vol. 81, No. 188) pp. 66,555-66,562.

69 Disturbance Control Standard - Contingency Reserve for Recovery from a Balancing Contingency Event Reliability Standard, Order No. 835, 158 FERC ¶ 61,030 (Jan. 19, 2017) (“Order 835”).

70 Order 835 was published in the Fed. Reg. on [Feb __, 2017 (Vol. 82, No. ___) pp. _____.] 71 Rel. Standard for Transmission System Planned Performance for Geomagnetic Disturbance Events, Order

No. 830, 156 FERC ¶ 61,2115 (, 2016) (“Order 830”), rehearing denied, 158 FERC ¶ 61,041, Order No. 830-A (Jan. 19, 2017) (“Order 830-A”).


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address specific GMD-related research areas. Order 830 became effective November 29, 2016.72 Rehearing of Order 830 was requested by EEI, the Foundation for Resilient Societies (“FRS”), and the Jewish Institute for National Security Affairs (“JINSA”), but denied on January 19.73 Unless Orders 830 and 830-A are challenged in Federal Court, this proceeding will be concluded.

• NOPR: Revised Reliability Standard: MOD-001-2 (RM14-7) The ATC NOPR remains pending before the FERC. As previously reported, the FERC’s June 19, 2014,

NOPR74 proposed to approve changes to MOD-001-2 (Modeling, Data, and Analysis - Available Transmission System Capability) to 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 Standards75 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 sought 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 sought further elaboration on specific actions NERC could take to assure synchronization of the effective dates. Comments on this NOPR were due August 25, 2014,76 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. 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 ATC NOPR remains pending before the FERC.

• NOPR: BAL-002-1a Interpretation Remand (RM13-6) The BAL-002-1a Interpretation Remand NOPR 77 remains pending. As previously explained, this NOPR

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). 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

72 Order 830 was published in the Fed. Reg. on Sep. 30, 2016 (Vol. 81, No. 190) pp. 67,120-67,140. 73 Rel. Standard for Transmission System Planned Performance for Geomagnetic Disturbance Events, Order

No. 830-A, 158 FERC ¶ 61,041 (Jan. 19, 2017) (“Order 830-A”). 74 Modeling, Data, and Analysis Rel. Standards, 147 FERC ¶ 61,208 (June 19, 2014) (“ATC NOPR”). 75 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. 76 The MOD-001-2 NOPR was published in the Fed. Reg. on June 26, 2014, (Vol. 79, No. 123) pp. 36,269-

36,273. 77 Elec. Rel. Org. Interpretation of Specific Requirements of the Disturbance Control Performance Standard,

143 FERC ¶ 61,138 (2013) (“BAL-002-1a Interpretation Remand NOPR”).


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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, 2013,78 and were filed by NERC, EEI, ISO/RTO Council, MISO, NC Balancing Area, Northwest Power Pool Balancing Authorities, NRECA, and WECC. As noted, the BAL-002-1a Interpretation Remand NOPR remains pending before the FERC.

XI. Misc. - of Regional Interest

• 203 Application: NSTAR/WMECO Merger (EC17-62) On January 13, Eversource filed an application requesting FERC authorization for an internal

reorganization under which Western Massachusetts Electric Company (“WMECO”) will merge with and into NSTAR Electric Company (“NSTAR”), with NSTAR as the surviving entity. Eversource indicated its expectation that the Merger would be consummated on January 1, 2018, following the receipt of all necessary regulatory approvals, waivers, and orders. Comments on the application are due on or before February 3, 2017. This far, a doc-less intervention was filed by the MA AG.

• 203 Application: GDF Suez Energy Resources/Atlas Power (Dynegy/ECP) (EC16-93) On December 22, the FERC conditionally authorized, subject to mitigation, the acquisition of GDF Suez

Energy Resources by Atlas Power Finance, a subsidiary of Atlas Power (a recently-formed joint venture between Dynegy Inc. and Energy Capital Partners III, LLC) (“Acquisition”) and the purchase of approximately 10 percent of Dynegy’s outstanding shares by a subsidiary of ECP III, Terawatt Holdings, LP (“Stock Purchase”).79 In authorizing the transaction, the FERC found that the applicants had not shown that either the Acquisition or the Stock Purchase would not adversely affect competition within the SENE capacity zone.80 Specifically, the FERC disagreed with applicants that, because GSENA was pivotal prior to the Transactions and Atlas would be pivotal after the Transactions, albeit with an additional 224 MW, there would be no adverse impact on competition. Rather, the FERC identified concerns that, because there would be an increase in the degree to which Atlas would be pivotal, Atlas would have an increased ability to exercise market power in an FCA when its resources enter or exit the market. Accordingly, as a condition to its authorization, the FERC suggested that Atlas propose in a 30-day compliance filing tailored mitigation mechanisms to address that concern, including divestiture of generation units or a commitment to keep resources in the FCM for a specified period of time.81

Compliance Filing. In its compliance filing, applicants propose to divest within six months an amount of generation equal to or greater than the amount by which they would become more pivotal post-transaction (i.e. the 224 MW currently controlled by Dynegy and ECP in SENE), so that the amount of generation controlled in SENE is equal to or less than the amount of generation currently controlled by GDF Suez. Until that divestiture is accomplished, applicants will rely on pre-existing market mitigation provisions for annual FCA purposes and, for monthly and reconfiguration auctions, a commitment to limit capacity bids to a level no greater than the FCA clearing price for the applicable planning period. Comments on the compliance filing were due on or before January 10. A protest was filed by Utility Workers of America Local 464 (“UWUA Local 464”) and Robert Clark, who contended that the compliance filing was inadequate because it failed to provide for the divestiture of Brayton Point or address anti-competitive concerns that the failure to divest that unit raises. Atlas Power, Dynegy and ECP answered the UWUA Local 464 protest on January 13. On January 19, UWUA Local 464 answered

78 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.

79 Atlas Power Finance, LLC, 157 FERC ¶ 61,237 (Dec. 22, 2016) (“Atlas 203 Order”). 80 Atlas 203 Order at P 45. The FERC also found that the Applicants had not shown that the Acquisition

would not adversely affect PJM’s COMED Local Deliverability Area, and that the protest filed by Public Citizen was beyond the scope of the proceeding.

81 Id. at P 56.


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Applicants’’ January 13 answer and Applicants answered that answer later that day. The compliance filing is pending before the FERC. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• MOPR-Related Proceedings (PJM, NYISO) (EL16-49; ER13-62) In two proceedings which, unless narrowly limited solely to the unique facts of the directly applicable

markets (PJM in EL16-49; NYISO in ER13-62), could impact the New England market through FERC jurisdictional or other determinations, NEPOOL filed limited comments requesting that any Commission action or decision be limited narrowly to the facts and circumstances as presented in the applicable market. NEPOOL urged that any changes that may be ordered by the Commission in the proceedings not circumscribe the results of NEPOOL’s stakeholder process or predetermine the outcome of that process through dicta or a ruling concerning different markets with different history and different rules. NEPOOL’s comments were filed on January 24 in the NYISO proceeding; January 30 in the PJM proceeding, and are pending before the FERC. If you have any questions concerning these proceedings, please contact Dave Doot (860-275-0102; [email protected]) or Sebastian Lombardi (860-275-0663; [email protected]).

• LGIA: CMP/ReEnergy Livermore Falls (ER17-909) On January 31, 2017, CMP filed a non-conforming Large Generation Interconnection Agreement

(“LGIA”) with ReEnergy Livermore Falls to govern the interconnection of ReEnergy’s 39 MW biomass-fueled generating facility located in Livermore Falls, Maine. Since the LGIA continues the existing interconnection arrangements between CMP and Livermore Falls, without modification to the facility’s capability or operating characteristics, a new three-party Interconnection Agreement (that would include the ISO) was not required. A January 1, 2017 effective was requested. Comments on this filing are due on or before February 21, 2017. If you have any questions concerning this matter, please contact Pat Gerity ([email protected]; 860-275-0533).

• Emera MPD OATT Changes (ER15-1429; EL16-13, ER12-1650) As previously reported, the FERC conditionally accepted, on December 7, 2015, changes to the

Maine Public District (“MPD”) Open Access Transmission Tariff (“MPD OATT”), including to the rates, terms, and conditions set forth in MPD OATT Attachment J.82 However, the FERC found, ultimately, that the changes to the MPD OATT had not been shown to be just and reasonable, may be unjust and unreasonable, instituted a Section 206 proceeding (in EL16-13) to examine the provisions, and set the matter for a trial-type evidentiary hearing, to be held in abeyance pending the outcome of settlement judge procedures (see below).

Background (ER15-1429). 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. Emera Maine stated that the changes to the MPD OATT were 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. The “Maine Customer Group”83 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

82 Emera Maine, 153 FERC ¶ 61,283 (Dec. 7, 2015). 83 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”).


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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 “Motion to Compel”). MCG also protested 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.

On June 2, 2016, the FERC granted Maine Customer Group’s Motion to Compel, and set the remaining issues with respect to Emera Maine’s 2014 and 2015 Annual Updates for hearing and settlement judge procedures.84 The FERC also consolidated ER12-1650 with this proceeding. In addition, the FERC directed that Emera Maine to make a compliance filing, on or before July 5, that (1) revises its 2014-2015 formula rate charges to correct the errors the Maine Customer Group raised with respect to amortization of long-term debt costs and post-retirement benefits other than pensions, and (2) imputes the retired debt balance for the tax-free Maine Public bonds ($22.6 million) into the capital structure calculation for the 2014-2015 Rate Year. Emera Maine requested rehearing of the June 2 order on July 5. On January 6, 2017, the FERC denied rehearing and Emera Maine’s alternative request for consolidation with the ongoing proceedings in Docket Nos. EC10-67-002, et al.85

Compliance Filing (ER12-1650). The January 6 Order also conditionally accepted Emera Maine’s July 5, 2016, pending compliance filing. submitted in response to the June 2 Order described above. The compliance filing was contested by the Maine Customer Group, which asserted that Emera’s compliance filing was incorrect as to two of the three refund issues, and Emera should be ordered to pay immediate refunds in accordance with the corrected revised formula rate it proposed. While the FERC sided with Emera Maine on the refund issues, it agreed with the Maine Customer Group that immediate refunds were in order. Accordingly, the FERC directed Emera Maine to make adjustments during the 2014-2015 Rate Year and refund the nearly $400,000 of excess revenue requirement as shown in its compliance filing, demonstrating in a refund report due on or before February 6 how the excess charges will be refunded.86

Hearing and Settlement Judge Procedures. The FERC encouraged the parties to make every effort to settle their disputes before hearing procedures are commenced, and is holding the hearing in abeyance pending the outcome of settlement judge procedures. As previously reported, Chief Judge Cintron substituted ALJ Dring in place of ALJ Johnson in mid-September as the settlement judge for these proceedings. Settlement conferences before Judge Johnson were held on January 5, March 3, and April 26, 2016 and on October 25 before Judge Dring. A fifth settlement conference, scheduled for November 22, was held on December 1. Since the last Report, Judge Dring issued a status report on January 24 (i) indicating that the parties have reached a settlement in principal and are memorializing their agreement (which is to be filed in March), and (ii) recommending that settlement judge procedures be continued. If you have any questions concerning these matters, please contact Pat Gerity ([email protected]; 860-275-0533).

• FERC Enforcement Action: Covanta Haverhill Associates (IN17-3)

On February 1, 2017, the FERC approved on a Stipulation and Consent Agreement between OE and Covanta Haverhill Associates LP (“Covanta”) that, among other things, levied a $36,000 civil penalty and

84 Emera Maine, 155 FERC ¶ 61,233 (June 2, 2016), reh’g denied, 158 FERC ¶ 61,012 (Jan. 6, 2017). 85 Emera Maine, 158 FERC ¶ 61,012 (Jan. 6, 2017) (“January 6 Order”). 86 Id. at PP 39-40.


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required Covanta to implement procedures to improve compliance, subject to monitoring via submission of semi-annual reports for at least two years.87 OE determined, following a referral from the ISO, that Covanta failed to provide instantaneous metered data from an RTU to the ISO, as required by the Tariff, relying instead on its Local Control Center (LCC) to provide such output data through its settlement system. Covanta did not complete installation of the necessary equipment to provide such data until June 29, 2016. OE determined that Covanta violated sections 1.3.2, II.22.1, II.22.2 of the Tariff, and thereby violated the FERC’s Unit Operation Market Behavior Rule. The February 1 order was preceded on January 23, 2016 by a staff notice of alleged violations.

• FERC Enforcement Action: GDF SUEZ Energy Marketing NA (IN17-2)

Also on February 1, the FERC approved a Stipulation and Consent Agreement88 that resolves the Office of Enforcement’s (“OE”) investigation into whether GDF SUEZ Energy Marketing NA (“GSEMNA”) violated the FERC’s Anti-Manipulation by improperly targeting and increasing its receipt of lost opportunity cost credits (“LOCs”) in the PJM market. In summary, GSEMNA offered units into the PJM Da-Ahead market at discounted prices, resulting in Day-Ahead commitments and LOCs at times when the units would have been out of the money had they not been offered at discounted prices.89 OE determined that GSEMNA’s offers did not reflect the price at which it wanted to generate power, but rather the price at which it could obtain a Day-Ahead award and then receive LOCs during periods when the discounted units likely could not have been operated profitably. OE further determined that, in order to increase LOCs, GSEMNA discounted the cost-based offers for the units when it discounted their price-based offers. Accordingly, OE concluded that GSEMNA’s strategy of targeting and inflating LOCs was contrary to supply and demand fundamentals and impaired the functioning of the LOC provisions of the PJM market and PJM’s unit commitment process.90 Under the Settlement, in which GSEMNA neither admits nor denies the alleged violations, GSEMNA agreed to disgorge $40.8 million to PJM and pay a $40 million civil penalty to the United States Treasury. If you have any questions concerning this matter, please contact Pat Gerity (860-275-0533; [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

87 Covanta Haverhill Assoc. LP, 158 FERC ¶ 61,105 (Feb. 1, 2017). 88 GDF SUEZ Energy Marketing NA, Inc., 158 FERC ¶ 61,102 (Feb. 1, 2017). 89 OE explained that GSEMNA implemented its strategy of offering the units into the DA market with

discounted price-based and cost-based offers, seeking to obtain a Day-Ahead award and to profit from LOCs at times when its units would have operated at a loss if dispatched. GSEMNA would discount a given unit’s Day-Ahead offer based on an assessment of the likelihood that the unit would not be dispatched in the Real-Time market, weighing the risk of running the unit at a loss if dispatched against the potential reward of LOCs if the unit was not dispatched. When GSEMNA expected that a CT unit would be dispatched in the Real-Time market, it typically offered the unit at or above cost and did not discount its Day-Ahead energy offer. GSEMNA typically offered uncommitted units (which were not eligible for LOCs) in the Real-Time market without discounting.

90 Id. at PP 12-13.


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special reports and responses to interrogatories, gather information, and require the production of any books, papers, correspondence, memoranda, contracts, agreements, or other records.

• FERC Audit of ISO-NE (PA16-6) The FERC’s audit of ISO-NE docketed in this proceeding is on-going. As previously reported, the

FERC informed ISO-NE on November 24, 2015 that it would evaluate ISO-NE’s compliance with: (1) the transmission provider obligations described in the Tariff, (2) Order 1000 as it relates to transmission planning and expansion, and interregional coordination, (3) accounting requirements of the Uniform System of Accounts under 18 C.F.R. Part 101, (4) financial reporting requirements under 18 C.F.R. Part 141; and (5) record retention requirements under 18 CFR Part 125. The FERC indicated that the audit will cover the July 10, 2013 period through the present.

XII. Misc. - Administrative & Rulemaking Proceedings

• Electric Storage Resource Utilization in RTO/ISO Markets (AD16-25) On November 9, the FERC held a technical conference to discuss the utilization of electric storage

resources as transmission assets compensated through RTO/ISO transmission rates, for grid support services that are compensated in other ways, and for multiple services. On November 14, the FERC invited all those interested to file, on or before December 14, 2016, post-technical conference comments on the topics discussed in the November 1 Supplemental Notice of Technical Conference. Comments were filed by over 45 parties, including Avangrid, Brookfield, EEI, Energy Storage Association, Exelon, FirstLight, NEPGA, NextEra, PSEG, Solar City/Tesla, and UCS. This matter is pending before the FERC.

• Competitive Transmission Development Rates (AD16-18) The FERC held a technical conference on a June 27-28, 2016 to discuss competitive transmission

development process-related issues, including use of cost containment provisions, the relationship of competitive transmission development to transmission incentives, and other ratemaking issues. In addition, participants had the opportunity to discuss issues relating to interregional transmission coordination, regional transmission planning and other transmission development issues. Pre-technical conference comments were filed by over 20 parties, including by NESCOE, BHE US Transmission, LSPower, and NextEra Energy Transmission. Technical conference materials are available on the FERC’s e-Library. On August 3, the FERC issued a notice inviting post-technical conference comments on questions listed in the attachment to the notice. Following requests by Utility Trade Associations91 and the New Jersey BPU, the deadline for comments was extended to October 3, 2016. Comments were filed by over 60 parties, including: ISO-NE, Avangrid, AWEA, BHE US Transmission, EDF Renewables, EEI, ELCON, Eversource, Exelon, LSP Transmission Holdings, MMWEC, National Grid, NESCOE, NextEra, and PSEG. Since the last Report, NEPOOL filed its Status Report, which was approved at the November 4 meeting. This matter is pending before the FERC.

• Reactive Supply Compensation in RTO/ISO Markets (AD16-17) A workshop to discuss compensation for Reactive Supply and Voltage Control (Reactive Supply) in

RTO/ISO markets was held on June 30, 2016. The workshop explored the types of costs incurred by generators for providing Reactive Supply capability and service; whether those costs are being recovered solely as compensation for Reactive Supply or whether recovery is also through compensation for other services; and different methods by which generators receive compensation for Reactive Supply (e.g., FERC-approved revenue requirements, market-wide rates, etc.). The workshop also explored potential adjustments in compensation based on changes in Reactive Supply capability and potential mechanisms to prevent overcompensation for Reactive Supply. Technical conference materials are available on the FERC’s e-Library. Written comments were due on or before July 28, 2016, and were filed by, among others, NYISO, PJM, the PJM IMM, AWEA, EEI, EPSA, EDF Renewables, Talen, Essential Power, and Exelon. EDF

91 The “Utility Trade Associations” are APPA, EEI, Large Public Power Council, National Rural Electric Cooperative Association (“NRECA”), and Transmission Access Policy Study Group (“TAPS”).


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Renewables filed reply comments on August 19. Since the last Report, the PJM IMM filed comments answering and objecting to AWAE’s July 28 comments suggesting that wind units should receive cost of service compensation for reactive capability apart from how the rules apply to other types of generators. This matter remains pending before the FERC.

• PURPA Implementation (AD16-16) A workshop to discuss issues associated with the FERC’s implementation of PURPA was held on

June 29, 2016. The conference focused on two issues: the mandatory purchase obligation under PURPA and the determination of avoided costs for those purchases. Panelists’ advanced written comments and materials from the technical conference are available on the FERC’s e-Library. On September 6, the FERC issued a notice inviting post-technical conference comments to be filed. Such comments may address (1) the use of the “one-mile rule” to determine the size of an entity seeking certification as a small power production qualifying facility (“QF”); and (2) minimum standards for PURPA-purchase contracts. Comments were due on or before November 7, 2016 and were filed by over 40 parties, including AWEA, Covanta, CT PURA/MA AG, Duke, EDP, EEI, ELCON, NARUC, and NRECA.

• Price Formation in RTO/ISO Energy and Ancillary Services Markets (AD14-14) As previously reported, the FERC directed each RTO/ISO to publicly provide information related to five

price formation issues:92 (1) pricing of fast-start resources; (2) commitments to manage multiple contingencies; (3) look-ahead modeling; (4) uplift allocation; and (5) transparency. The FERC directed each RTO/ISO to file a report that provides an update on its current practices in the identified topic areas, that provides the status of its efforts (if any) to address each of the five issues, and that fully responds to the questions. The FERC indicated it would use the reports and comments to determine what further action is appropriate. The RTO/ISO reports were filed February 17 by PJM, March 4 by ISO-NE, CAISO, MISO, and NYISO (corrected on March 23), and March 7 by SPP. Comments on the reports were due on or before April 693 and were filed by over 25 parties, including Exelon, EEI, and EPSA. This matter is pending before the FERC.

• NOI: FERC's Policy for Recovery of Income Tax Costs & ROE Policies (PL17-1) On December 15, 2016, the FERC issued a notice of inquiry (“NOI”) seeking comments regarding how to

address any double recovery resulting from the FERC’s current income tax allowance and ROE policies.94 The NOI follows the D.C. Circuit’s United Airlines95 holding that the FERC failed to demonstrate that there is no double recovery of taxes for a partnership pipeline as a result of the income tax allowance and ROE determined pursuant to the DCF methodology, and remanding the decisions to the FERC to develop a mechanism “for which the Commission can demonstrate that there is no double recovery” of partnership income tax costs”.96 In response to requests for an extension of the comment and reply comment deadlines, and objections to those requests, the FERC extended the comment and reply comment deadlines to March 8 and April 7, 2017, respectively.

• Order 834: Civil Monetary Penalty Inflation Adjustments (RM17-9)

On January 9, the FERC issued Order 83497 to amend its regulations governing the maximum civil monetary penalties assessable for violations of statutes, rules, and orders within FERC’s jurisdiction. The FERC

92 Price Formation in Energy and Ancillary Services Markets Operated by Regional Transmission Organizations and Independent System Operators, 153 FERC ¶ 61,221 (Nov. 20, 2015).

93 In the order directing the reports, the FERC provided that public comment in response to the RTOs/ISOs’ reports may be submitted within 30 days of the filing of the reports. Apr. 6 was 30 days after the filing of the last of the reports, the SPP report, on Mar. 7.

94 Inquiry Regarding the FERC’s Policy for Recovery of Income Tax Costs, 157 FERC ¶ 61,210 (Dec. 15, 2017).

95 United Airlines Inc., et al. v. FERC, 827 F.3d 122, 134, 136 (D.C. Cir. 2016) (“United Airlines”). 96 Id. at 137. 97 Civil Monetary Penalty Inflation Adjustments, Order No. 834, 158 FERC ¶ 61, 170 (Jan. 9, 2017) (“Order

834”).


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is required to update each such civil monetary penalty on an annual basis every January 15.98 Of particular interest is the increase in potential civil penalties for market manipulation, which were increased from $1,193,970 to $1,213,503 per violation, per day. Order 834 became effective January 24, 2017.99

• NOPR: LGIA/LGIP Reforms (RM17-8) On December 15, the FERC issued a NOPR100 proposing reforms designed to improve certainty,101

promote more informed interconnection,102 and enhance interconnection processes.103 Based, in part, on input received in response to AWEA’s petition for changes to the pro forma LGIP/LGIA, and the FERC’s May 13, 2016 technical conference to explore generator interconnection issues (as reported previously under Docket Nos. RM16-12; RM15-21), the FERC has identified proposed reforms which it states could remedy potential shortcomings in the existing interconnection processes. The FERC also seeks comment on whether any of its proposed reforms should be applied to the pro forma SGIP/SGIA.104 Comments on the LGIP/LGIA Reforms NOPR are due March 14, 2017.105 Thus far, comments have been submitted by Schulte Associates.

98 See Federal Civil Penalties Inflation Adjustment Act Improvements Act of 2015, Sec. 701, Pub. L. 114-74, 129 Stat. 584, 599. The FERC made its first adjustment under the Act in July 2016. See Civil Monetary Penalty Inflation Adjustments, Order No. 826, 81 FR 43937 (July 6, 2016), FERC Stats. & Regs. ¶ 31,386 (2016).

99 Order 834 was published in the Fed. Reg. on Jan. 24, 2017 (Vol. 82, No. 14) pp. 8,137-8,139. 100 Reform of Generator Interconnection Procedures and Agreements, 157 FERC ¶ 61,212 (Dec. 15, 2016)

(“LGIP/LGIA Reforms NOPR”). 101 To accomplish this goal, the FERC proposes to: (1) revise the pro forma LGIP to require transmission

providers that conduct cluster studies to move toward a scheduled, periodic restudy process; (2) remove from the pro forma LGIA the limitation that interconnection customers may only exercise the option to build transmission provider’s interconnection facilities and standalone network upgrades if the transmission owner cannot meet the dates proposed by the interconnection customer; (3) modify the pro forma LGIA to require mutual agreement between the transmission owner and interconnection customer for the transmission owner to opt to initially self-fund the costs of the construction of network upgrades; and (4) require that the RTO/ISO establish dispute resolution procedures for interconnection disputes. The Commission also seeks comment on the extent to which a cap on the network upgrade costs for which interconnection customers are responsible can mitigate the potential for serial restudies without inappropriately shifting cost responsibility. Id. at P 6.

102 The FERC proposes to: (1) require transmission providers to outline and make public a method for determining contingent facilities in their LGIPs and LGIAs based upon guiding principles in the Proposed Rule; (2) require transmission providers to list in their LGIPs and on their OASIS sites the specific study processes and assumptions for forming the networking models used for interconnection studies; (3) require congestion and curtailment information to be posted in one location on each transmission provider’s OASIS site; (4) revise the definition of “Generating Facility” in the pro forma LGIP and LGIA to explicitly include electric storage resources; and (5) create a system of reporting requirements for aggregate interconnection study performance. The FERC also seeks comment on proposals or additional steps that the Commission could take to improve the resolution of issues that arise when affected systems are impacted by a proposed interconnection. Id. at P 7.

103 The FERC proposes to: (1) allow interconnection customers to limit their requested level of interconnection service below their generating facility capacity; (2) require transmission providers to allow for provisional agreements so that interconnection customers can operate on a limited basis prior to completion of the full interconnection process; (3) require transmission providers to create a process for interconnection customers to utilize surplus interconnection service at existing interconnection points; (4) require transmission providers to set forth a separate procedure to allow transmission providers to assess and, if necessary, study an interconnection customer’s technology changes (e.g., incorporation of a newer turbine model) without a change to the interconnection customer’s queue position; and (5) require transmission providers to evaluate their methods for modeling electric storage resources for interconnection studies and report to the Commission why and how their existing practices are or are not sufficient. Id. at P 8.

104 Id. at P 11. 105 The LGIP/LGIA Reforms NOPR was published in the Fed. Reg. on Jan. 13, 2017 (Vol. 82, No. 9 pp. 4,464-

4,501.


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• NOPR: Fast Start Pricing in RTO/ISO Markets (RM17-3) On December 15, the FERC issued a NOPR proposing to require each RTO and ISO to incorporate

market rules that meet certain requirements when pricing fast-start resources.106 The FERC stated that these reforms should lead to prices that more transparently reflect the marginal cost of serving load, which will reduce uplift costs and thereby improve price signals to support efficient investments. Specifically, the FERC proposes to require that each RTO/ISO incorporate the following five requirements for its fast-start pricing:

1. an RTO/ISO must apply fast-start pricing to any resource committed by the RTO/ISO that is able to start up within 10 minutes or less, has a minimum run time of one hour or less, and that submits economic energy offers to the market;

2. when an RTO/ISO makes a decision to commit a fast-start resource, it should incorporate commitment costs, i.e., start-up and no-load costs, of fast-start resources in energy and operating reserve prices, but must do so only during the fast-start resource’s minimum run time;

3. an RTO/ISO must modify its fast-start pricing to relax the economic minimum operating limit of fast-start resources and treat them as dispatchable from zero to the economic maximum operating limit for the purpose of calculating prices;

4. if an RTO/ISO allows offline fast-start resources to set prices for addressing certain system needs, the resource must be feasible and economic; and

5. an RTO/ISO must incorporate fast-start pricing in both the Day-Ahead and Real-Time markets.

Comments on the Fast-Start Pricing NOPR are due on or before February 28, 2017.107

• NOPR: Electric Storage Participation in RTO/ISO Markets (RM16-23; AD16-20) On November 23, the FERC issued a NOPR proposing to require each RTO and ISO to revise its

tariff “to (1) establish a participation model consisting of market rules that, recognizing the physical and operational characteristics of electric storage resources, accommodates their participation in the organized wholesale electric markets and (2) define distributed energy resource aggregators as a type of market participant that can participate in the organized wholesale electric markets under the participation model that best accommodates the physical and operational characteristics of its distributed energy resource aggregation.”108 Comments on the Storage NOPR were initially due on or before January 30, 2017,109 but following requests for an extension of time, are now due February 13, 2017.

The Storage NOPR follows FERC Staff’s data request directing the RTO/ISOs to submit information on rules that affect the participation of electric storage resources in their markets, including, but not limited to, the eligibility of electric storage resources to participate in the markets, the qualification and performance requirements for market participants, required bid parameters, and the treatment of electric storage resources when they are receiving electricity for later injection to the grid. (Information from each of the ISO/RTOs, including ISO-NE’s information, was submitted on May 16).

• NOPR: Data Collection for Analytics & Surveillance and MBR Purposes (RM16-17) As previously reported, the FERC issued a July 21, 2016 NOPR, which supersedes both its

Connected Entity NOPR (RM15-23) and Ownership NOPR (RM16-3), proposing to collect certain data for analytics and surveillance purposes from market-based rate (“MBR”) sellers and entities trading virtual

106 Fast-Start Pricing in Markets Operated by Regional Transmission Organizations and Independent System Operators, 157 FERC ¶ 61,213 (Dec. 15, 2016) (“Fast-Start Pricing NOPR”).

107 The Fast-Start Pricing NOPR was published in the Fed. Reg. on Dec. 30, 2016 (Vol. 81, No. 251 pp. 96,391-96,404.

108 Electric Storage Participation in Markets Operated by Regional Transmission Orgs. and Indep. Sys. Operators, 157 FERC ¶ 61,121 (Nov. 17, 2016) (“Storage NOPR”).

109 The Storage NOPR was published in the Fed. Reg. on Nov. 30, 2016 (Vol. 81, No. 230 pp. 86,522-86,550.


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products or holding FTRs and to change certain aspects of the substance and format of information submitted for MBR purposes.110 The Data Collection NOPR presents substantial revisions from what the FERC proposed in the Connected Entity NOPR, and responds to the comments and concerns submitted by NEPOOL in that proceeding. Among other things, the changes proposed in the Data NOPR include: (i) a different set of filers; (ii) a reworked and substantially narrowed definition of Connected Entity; and (iii) a different submission process. With respect to the MBR program, the proposals include: (i) adopting certain changes to reduce and clarify the scope of ownership information that MBR sellers must provide; (ii) reducing the information required in asset appendices; and (iii) collecting currently-required MBR information and certain new information in a consolidated and streamlined manner. The FERC also proposes to eliminate MBR sellers’ corporate organizational chart submission requirement adopted in Order 816. Comments on the Data Collection NOPR were due on or before September 19, 2016111 and were filed by over 30 parties, including: American Public Power Association (“APPA”), Avangrid, Brookfield, EPSA, Macquarie/DC Energy/Emera Energy Services, NextEra, and NRG.

Technical Workshops. The FERC held two technical workshops. The first technical workshop was held on August 11 and focused on the Data Collection NOPR’s draft data dictionary. The second technical workshop was held on December 7, 2016 and focused on the submittal process, with case studies serving as a platform for discussion of (i) the steps to submit data; (ii) data review and validation processes; and (iii) the notifications to be provided through the data validation and receipt process. Staff also provided a high-level update on proposed technical refinements to the data dictionary based on input received during the first workshop and additional outreach.

• Order 833: Critical Energy/Electric Infrastructure Information (CEII) Procedures (RM16-15) On June 16, the FERC issued Order 833 amending its regulations to implement provisions of the Fixing

America’s Surface Transportation (“FAST”) Act that pertain to the designation, protection and sharing of Critical Electric Infrastructure Information (“CEII”) and to amend its regulations that pertain to CEII.112 The amended procedures will be referred to as the Critical Energy/Electric Infrastructure Information (CEII) procedures. Order 833 will become effective February 21, 2017.113 On December 19, 2016, EEI requested rehearing of Order 833. The FERC issued a tolling order on January 17, affording it additional time to consider the EEI request for rehearing, which remains pending.

• NOPR: Primary Frequency Response - Essential Reliability Services and the Evolving Bulk-Power System (RM16-6) On November 17, 2016, the FERC issued a NOPR proposing to require all newly interconnecting

large and small generating facilities, both synchronous and non-synchronous, to install and enable primary frequency response capability as a condition of interconnection.114 To implement these requirements, the Commission proposes to revise the pro forma Large Generator Interconnection Agreement (“LGIA”) and the pro forma Small Generator Interconnection Agreement (“SGIA”). The Primary Frequency Response NOPR follows the FERC’s Frequency Response NOI115 from early 2016. Comments on the Primary Frequency

110 Data Collection for Analytics and Surveillance and Market-Based Rate Purposes, 156 FERC ¶ 61,045 (July 21, 2016) (“Data Collection NOPR”).

111 The Data Collection NOPR was published in the Fed. Reg. on Aug. 4, 2016 (Vol. 81, No. 150 pp. 51,726-51,772.

112 Regulations Implementing FAST Act Section 61003 – Critical Electric Infrastructure Security and Amending Critical Energy Infrastructure Information; Availability of Certain North American Electric Reliability Corporation Databases to the Commission, Order No. 833, 157 FERC ¶ 61,123 (Nov. 17, 2016) (“Order 833”).

113 Order 833 was published in the Fed. Reg. on Dec. 21, 2016 (Vol. 81, No. 245) pp. 93,732-93,753.114 Essential Reliability Services and the Evolving Bulk-Power System—Primary Frequency Response, 157

FERC ¶ 61,122 (Nov. 17, 2016) (“Primary Frequency Response NOPR”). 115 Essential Reliability Services and the Evolving Bulk-Power System—Primary Frequency Response, 154

FERC ¶ 61,117 (Feb. 18, 2016 ) (“Frequency Response NOI”).


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Response NOPR were due on or before January 24, 2017116 and were filed by over 30 parties, including AWEA, EEI, ELCON, EPSA, ESA, the IRC, NRECA, and UCS.

• Order 831: Price Caps in RTO/ISO Markets (RM16-5) On November 17, 2016, the FERC issued Order 831117 requiring each RTO/ISO: (i) to cap each

resource’s incremental energy offer at the higher of $1,000/MWh or that resource’s verified cost-based incremental energy offer; and (ii) cap verified cost-based incremental energy offers at $2,000/MWh when calculating locational marginal prices (“LMP”). In addition, the FERC clarified that the verification process for cost-based incremental offers above $1,000/MWh should ensure that a resource’s cost-based incremental energy offer reasonably reflects that resource’s actual or expected costs. Order 831 modified the FERC’s Offer Cap NOPR by including a $2,000/MWh hard cap for the purposes of calculating LMPs. Order 831 will become effective, and Market Rule changes implementing Order 831 will be required to be filed, February 21, 2017.118 On December 19, 2017, American Municipal Power Inc. (“AMP”) and American Public Power Association (“APPA”), Exelon, NYISO, and the Transmission Access Policy Study Group (“TAPS”) requested rehearing and/or clarification of Order 831. The FERC issued a tolling order on January 17, affording it additional time to consider the requests for rehearing, which remain pending. On January 4, the PJM Market Monitor opposed Exelon’s motion for clarification and/or rehearing. On January 13, MISO submitted comments supporting NYISO request for rehearing.

• Order 825: Settlement Intervals/Shortage Pricing (RM15-24) As previously reported, Order 825119 revises FERC 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; (b) operating reserves transactions in its real-time markets at the same time interval it prices operating reserves; and (c) intertie transactions in the same time interval it schedules intertie transactions; and (ii) trigger shortage pricing for any dispatch interval during which a shortage of energy or operating reserves occurs. The FERC stated that adopting these reforms will align prices with resource dispatch instructions and operating needs, providing appropriate incentives for resource performance. Order 825 will become effective September 13, 2016.120

Compliance. Each RTO/ISO was required to submit a compliance filing with the tariff changes needed to implement this Final Rule within 120 days of the Final Rule’s September 13, 2016 effective date (on or before January 11, 2017). As noted in Section III above, New England’s Order 825 compliance filing was submitted on January 11. The FERC will allow a further 12 months from the compliance filing date for the tariff changes implementing reforms to settlement intervals to be effective, and 120 days from that same compliance filing date for the tariff changes implementing shortage pricing reforms to be effective. As previously noted, the ISO’s and NEPOOL’s jointly filed Sub-Hourly Settlement Changes, which changed to five minutes the settlement interval in the Real-Time Energy and Reserves Markets, was filed and accepted by the FERC.

116 The Primary Frequency Response NOPR was published in the Fed. Reg. on Nov. 25, 2016 (Vol. 81, No. 227) pp. 85,176-85,190.

117 Offer Caps in Markets Operated by Regional Transmission Organizations and Independent System Operators, Order No. 831, 157 FERC ¶ 61,115 (Nov. 17, 2016 ) (“Order 831”), reh’g requested.

118 Order 831 was published in the Fed. Reg. on Dec. 5, 2016 (Vol. 81, No. 233) pp. 87,770-87,800.119 Settlement Intervals and Shortage Pricing in Markets Operated by Regional Transmission Organizations

and Independent System Operators, Order No. 825, 155 FERC ¶ 61,276 (June 16, 2016) (“Order 825”). 120 Order 825 was published in the Fed. Reg. on June 30, 2016 (Vol. 81, No. 126) pp. 42,882-42,910.


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For further information on any of the natural gas proceedings, please contact Joe Fagan (202-218-3901; [email protected]) or Jamie Blackburn (202-218-3905; [email protected]).

• Algonquin EDC Capacity Release Bidding Requirements Exemption Request (RP16-618) On March 31, 2016, the FERC conditionally accepted Algonquin tariff modifications and request for

waiver that provided an exemption from capacity release bidding requirements for certain types of firm transportation capacity releases by Electric Distribution Companies (“EDCs”) that are participating in state-regulated electric reliability programs.121 As previously reported, Algonquin stated that the modifications were consistent with the FERC’s current policy of exempting releases pursuant to state-regulated retail access programs of natural gas local distribution companies (“LDCs”) from bidding requirements. Algonquin added that its proposal (i) supports the efforts of EDCs to increase the reliability of supply for natural gas-fired electric generation facilities in New England and to address high electricity prices during peak periods in New England and therefore is in the public interest; and (ii) furthers the FERC’s initiatives related to gas-electric coordination. On May 9, 2016, the FERC held a technical conference to examine “concerns raised regarding the basis and need for the waiver.” Initial comments were due May 31. Almost two dozen sets of initial comments were filed, raising numerous issues both in support and in opposition to the Algonquin proposal. Reply comments were due June 10, 2016 and were filed by Algonquin Gas Transmission, Sequent Energy Management, L.P. and Tenaska Marketing Ventures, Indicated Shippers, National Grid, Eversource, Repsol, Calpine, Exelon/NextEra, New England LDCs, CT PURA and the MA AG.

On August 31, 2016, the FERC issued an order in which it rejected Algonquin’s request for a waiver that would have exempted gas-fired generators from capacity release bidding requirements but accepted Algonquin’s proposal to exempt from bidding an EDC’s capacity release to an asset manager who is required to use the released capacity to carry out the EDC’s obligations under the state-regulated electric reliability program.122 The FERC explained that its capacity release regulations seek to balance the interests of the releasing shipper in releasing capacity to a replacement shipper of its choosing while still ensuring that allocative efficiency is enhanced by ensuring the capacity is used for its highest valued use.123 Algonquin’s proposal, whereby any gas-fired generator to whom EDCs release capacity would be a pre-arranged replacement shipper, failed to meet the standard of “improving the competitive structure of the natural gas industry” as formulated by the FERC in granting bidding exemptions for state-regulated retail access programs.124 Furthermore, the FERC found that exemption proponents had not shown why such a broad exemption was necessary in order for EDCs to have a sufficient ability to direct their capacity releases to natural gas-fired generators in order to accomplish the goal of increasing electric reliability.125 On September 30, 2016, ConEd and Orange & Rockland Utilities, Inc. (“O&R”) requested clarification of the Algonquin Order Following Technical Conference, asking the FERC to clarify certain aspects of its approval exempting from bidding an EDC’s capacity release to an asset manager. Algonquin Gas Transmission, National Grid Electric Distribution Companies, and Sequent Energy Management and Tenaska Marketing Ventures filed answers to the requests for clarification on October 17. Those requests are pending before the FERC.

On September 23, Algonquin submitted a compliance filing in response to the requirements of the Algonquin Order Following Technical Conference. Comments on that compliance were due on or before October 5; none were filed. The compliance filing is pending before the FERC.

121 Algonquin Gas Transmission, LLC, 154 FERC ¶ 61,269 (Mar. 31, 2016). 122 Algonquin Gas Transmission, LLC, 156 FERC ¶ 61,151 (Aug. 31, 2016) (“Algonquin Order Following

Technical Conference”) 123 Id. at P 27. 124 Id. at P 34. 125 Id. at P 35


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• 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 July 11, 2016, the FERC issued Opinion 549126 affirming Judge Cintron’s August 13, 2015 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 (“Anti-Manipulation Rule”) and section 4A of the Natural Gas Act (“NGA”).127 Specifically, after extensive discovery and hearing procedures, Judge Cintron found that BP’s Texas team engaged in market manipulation by changing their trading patterns, between September 18, 2008 through the end of November 2008, in order to suppress next-day natural gas prices at the Houston Ship Channel (“HSC”) trading point in order to benefit correspondingly long position at the Henry Hub trading point. The FERC agreed, finding that the “record shows that BP’s trading practices during the Investigative Period were fraudulent or deceptive, undertaken with the requisite scienter, and carried out in connection with Commission-jurisdictional transactions.”128 Accordingly, the FERC assessed a $20.16 million civil penalty and required BP to disgorge $207,169 in “unjust profits it received as a result of its manipulation of the Houston Ship Channel Gas Daily index.” The $20.16 million civil penalty was at the top of the FERC’s Penalty Guidelines range, reflecting increases for having had a prior adjudication within 5 years of the violation, and for BP’s violation of a FERC order within 5 years of the scheme. BP’s penalty was mitigated because it cooperated during the investigation, but BP received no deduction for its compliance program, or for self-reporting. The BP Penalties Order also denied BP’s request for rehearing of the order establishing a hearing in this proceeding.129 BP was directed to pay the civil penalty and disgorgement amount within 60 days of the BP Penalties Order. On August 10, BP requested rehearing of the BP Penalties Order. On September 8, the FERC issued a tolling order, affording it additional time to consider BP’s request for rehearing of the BP Penalties Order, which remains pending.

On September 7, BP submitted a motion for modification of the BP Penalties Order’s disgorgement directive because it cannot comply with the disgorgement directive as ordered. BP explained that the entity to which disgorgement was to be directed, the Texas Low Income Home Energy Assistance Program (“LIHEAP”), is not set up to receive or disburse amounts received from any person other than the Texas Legislature. In response, on September 12, the FERC stayed the disgorgement directive (until an order on BP’s pending request for rehearing is issued), but indicated that interest will continue to accrue on unpaid monies during the pendency of the stay.130

Total Gas & Power North America, Inc. et al. (IN12-17). On April 28, 2016, the FERC issued a show cause order131 in which it directed Total Gas & Power North America, Inc. (“TGPNA”) and its West Desk traders and supervisors, Therese Tran f/k/a Nguyen (“Tran”) and Aaron Hall (collectively, “Respondents”) to show cause why Respondents should not be found to have violated NGA Section 4A and the FERC’s Anti-Manipulation Rule through a scheme to manipulate the price of natural gas at four locations in the southwest United States between June 2009 and June 2012.132

126 BP America Inc., et al., Opinion No. 549, 156 FERC ¶ 61,031 (July 11, 2016) (“BP Penalties Order”). 127 BP America Inc., et al., 152 FERC ¶ 63,016 (Aug. 13, 2015) (“BP Initial Decision”). 128 BP Penalties Order at P 3. 129 BP America Inc. et al., 147 FERC ¶ 61,130 (May 15, 2014) (“BP Hearing Order”), reh’g denied, 156

FERC ¶ 61,031 (July 11, 2016). 130 BP America Inc. et al., 156 FERC ¶ 61,174 (Sep. 12, 2016) (“Order Staying BP Disgorgement”)

131 Total Gas & Power North America, Inc., et al., 155 FERC ¶ 61,105 (Apr. 28, 2016) (“TGPNA Show Cause Order”).

132 The allegations giving rise to the Total Show Cause Order were laid out in a September 21, 2015 FERC Staff Notice of Alleged Violations which summarized OE’s case against the Respondents. Staff determined that the Respondents violated section 4A of the Natural Gas Act and the Commission’s Anti-Manipulation Rule by devising


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The FERC also directed TGPNA to show cause why it should not be required to disgorge unjust profits of $9.18 million, plus interest; TGPNA, Tran and Hall to show cause why they should not be assessed civil penalties (TGPNA - $213.6 million; Hall - $1 million (jointly and severally with TGPNA); and Tran - $2 million (jointly and severally with TGPNA)). In addition, the FERC directed TGPNA’s parent company, Total, S.A. (“Total”), and TGPNA’s affiliate, Total Gas & Power, Ltd. (“TGPL”), to show cause why they should not be held liable for TGPNA’s, Hall’s, and Tran’s conduct, and be held jointly and severally liable for their disgorgement and civil penalties based on Total’s and TGPL’s significant control and authority over TGPNA’s daily operations. Respondents field their answer on July 12, 2016. OE Staff replied to Respondents’ answer on September 23, 2016.

• New England Pipeline Proceedings The following New England pipeline projects are currently under construction or before the FERC:

• Atlantic Bridge Project (CP16-9)

Algonquin Gas Transmission filed for Section 7(b) and 7(c) certificate on Oct. 22, 2015.

132,700 Dth/d of firm transportation to new and existing delivery points on the Algonquin system and 106,276 Dth/d of firm transportation service from Beverly, MA to various existing delivery points on the Maritimes & Northeast system.

6.3 miles of replacement pipeline along Algonquin in NY and CT; new 7,700-horsepower compressor station in Weymouth, MA; more horsepower at existing compressor stations in CT and NY.

Seven firm shippers: Heritage Gas Limited, Maine Natural Gas Company, NSTAR Gas Company d/b/a Eversource Energy, Exelon Generation Company, LLC (as assignee and asset manager of Summit Natural Gas of Maine), Irving Oil Terminal Operations, Inc., New England NG Supply Limited, and Norwich Public Utilities.

Certificate of public convenience and necessity granted Jan. 25, 2017.133

• Connecticut Expansion Project (CP14-529)

Tennessee Gas Pipeline filed for Section 7(c) certificate July 31, 2014.

72,100 Dth/d of firm capacity.

13.26 miles of three looping segments & facility upgrades/modifications in NY, MA & CT.

Three firm shippers: Conn. Natural Gas, Southern Conn. 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.

Environmental Assessment (EA) issued on Oct. 23, 2015.

Certificate of public convenience and necessity granted Mar. 11, 2016.134

Construction expected to begin 4th Quarter 2016.

In-service: Nov. 2017 (anticipated).

and executing a scheme to manipulate the price of natural gas in the southwest United States between June 2009 and June 2012. Specifically, Staff alleged that the scheme involved making largely uneconomic trades for physical natural gas during bid-week designed to move indexed market prices in a way that benefited the company’s related positions. Staff alleged that the West Desk implemented the bid-week scheme on at least 38 occasions during the period of interest, and that Tran and Hall each implemented the scheme and supervised and directed other traders in implementing the scheme.

133 Order Issuing Certificate and Authorizing Abandonment, Algonquin Gas Transmission LLC and Maritimes & Northeast Pipeline, LLC, 158 FERC ¶ 61,061 (Jan. 25, 2017).

134 Tennessee Gas Pipeline Co., LLC, 154 FERC ¶ 61,191 (Mar. 11, 2016) (order issuing certificate); reh’g requested. See also 154 FERC ¶ 61,263 (Mar. 30, 2016) (order denying stay); 155 FERC ¶ 61,087 (Apr. 22, 2016) (order denying stay).


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• 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 Dth/d of firm capacity from Susquehanna County, PA (Marcellus Shale) through NY to Iroquois/Tennessee interconnection (Wright Interconnection).

New 122-mile interstate pipeline.

Two firm shippers: Cabot Oil & Gas and Southwestern Energy Services.

Final EIS completed on Oct 24, 2014.

Certificates of public convenience and necessity granted Dec 2, 2014.

On April 22, 2016, New York State Department of Environmental Conservation denied Constitution’s application for a Section 401 permit under the Clean Water Act. The decision effectively guarantees that the Constitution Pipeline project will, at best, be delayed by several years.

On May 16, 2016, the New York Attorney General filed a complaint against Constitution at the FERC (CP13-499) seeking a stay of the December 2014 order granting the original certificates, as well as alleging violations of the order, the Natural Gas Act, and the Commission’s own regulations due to acts and omissions associated with clear-cutting and other construction-related activities on the pipeline right of way in New York.

Construction was expected to begin Spring 2016 (after final Federal Authorizations), but has been plagued by delays. On October 13, 2016, the FERC approved Constitution’s request to proceed to

remove the felled trees in Pennsylvania.


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]).

• FCA10 Results (16-1408) and FCA9 Results (16-1068) Underlying FERC Proceedings: ER16-1041135 ER15-1137136

Petitioners: UWUA Local 464 and Robert Clark UWUA Local 464 and Robert Clark (“Petitioners”) filed petitions for review of the FERC’s orders on

the FCA10 and FCA9 Results Filings. On January 17, the FERC moved to have the FCA10 Results and FCA9 Results appeals consolidated. On January 31, the Court consolidated the two cases, and directed the Clerk to issue an appropriate briefing order.

135 155 FERC ¶ 61,273 (June 16, 2016); 157 FERC ¶ 61,060 (Oct. 27, 2016). 136 153 FERC ¶ 61,378 (Dec. 30, 2015); 151 FERC ¶ 61,226 (June 18, 2015).


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• NEPGA PER Complaint and FCM Jump Ball and Compliance Proceedings (16-1023/1024) Underlying FERC Proceeding: ER14-1050;137 EL14-52;138 EL15-25139

Petitioner: NEPGA As previously reported, NEPGA filed, on January 19, 2016, a petition for review of the FERC’s

orders on NEPGA’s first PER Complaint. On February 24, 2016, the Court granted NEPGA’s motion to consolidate this proceeding with 16-1024. Briefing was completed on November 28, 2016 and this matter remains pending before the DC Circuit.

• Base ROE Complaints II & III (2012 & 2014) (15-1212) Underlying FERC Proceedings: EL13-33; EL14-86140

Appellants: New England Transmission Owners As previously reported, the TOs filed a petition for review of the FERC’s orders in the 2012 and 2014

ROE complaint proceedings on July 13, 2015. On August 14, 2015, the TOs 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 the TOs’ motion to hold the case in abeyance, subject to submission of status reports every 90 days. The most recent status report, the fifth such report filed, was filed on November 14, 2016. In that report, the parties again indicated, ultimately, that the proceedings upon which the TOs based their request for abeyance of this appeal remain ongoing. This case continues to be held in abeyance.

• Order 1000 Compliance Filings (15-1139, 15-1141**) (consolidated) Underlying FERC Proceedings: ER13-193; ER13-196141

Appellants: New England Transmission Owners (NETOs); NESCOE/CT DEEP/CT PURA, et al. As previously reported, NETOs142 and NESCOE, et al., filed a petition for review of the FERC’s orders in

the Order 1000 Compliance Filing proceeding on May 15, 2015. Briefing has been completed and oral argument was held on January 13, 2017 before a panel comprised of Judges Brown, Wilkins and Edwards. This matter is now pending before the DC Circuit.

• Base ROE Complaint I (2011) (15-1118, 15-1119, 15-1121**) (consolidated) Underlying FERC Proceeding: EL11-66143

Appellants: NETOs On April 30, 2015, NETOs filed a petition for review of the FERC’s orders in the 2011 Base ROE

Complaint Proceeding. All briefing was completed and oral argument was held on December 6 before Judges Millett, Sentelle and Randolph. This matter is now pending before the DC Circuit.

137 153 FERC ¶ 61,224 (Nov. 19, 2015); 153 FERC ¶ 61,223 (Nov. 19, 2015); 147 FERC ¶ 61,172 (May 30, 2014). 138 153 FERC ¶ 61,222 (Nov. 19, 2015); 150 FERC ¶ 61,053 (Jan. 30, 2015). 139 153 FERC ¶ 61,222 (Nov. 19, 2015); 150 FERC ¶ 61,053 (Jan. 30, 2015). 140 147 FERC ¶ 61,235 (June 19, 2014); 149 FERC ¶ 61,156 (Nov. 24, 2014); 151 FERC ¶ 61,125 (May 14,

2015). 141 150 FERC ¶ 61,209 (Mar. 19, 2015); 143 FERC ¶ 61,150 (May 17, 2013). 142 “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.

143 150 FERC ¶ 61,165 (Mar. 3, 2015); 149 FERC ¶ 61,032 (Oct. 16, 2014); 147 FERC ¶ 61,234 (June 19, 2014).


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• FCM Pricing Rules Complaints (15-1071**, 16-1042) (consol.) Underlying FERC Proceeding: EL14-7,144 EL15-23145

Petitioners: NEPGA, Exelon On March 31, 2015, NEPGA filed a petition for review of the FERC’s orders on NEPGA’s FCM

Administrative Pricing Rules Complaint. On May 22, the Court granted NEPGA’s motion to hold the case in abeyance pending a decision in EL15-23 and, following the FERC’s decision in EL15-23 and Exelon’s appeal of that case (16-1042), Exelon’s motion to consolidate this proceeding with 16-1042. All briefing in the consolidated proceeding has now been completed and this matter is now before the Court.

• Allco Finance Limited v. Klee et al. (Commissioners, CT DEEP and CT PURA) (2d Cir. 16-2946) In this proceeding, an appeal from an unsuccessful challenge of Connecticut’s actions under the 2015

multi-state clean energy RFP (“Clean Energy RFP”) in Connecticut District Court, Allco continues its challenges to Connecticut’s actions under the Clean Energy RFP. Allco asserts that Connecticut’s actions are inconsistent with PURPA and constitutional principles recently addressed by the Supreme Court in Hughes v Talen Energy Marketing and summarized in prior Reports. As reported at the November Participants Committee meeting, the Second Circuit Court of Appeals on November 2 granted Allco’s motion for an emergency injunction. The emergency injunction enjoined Connecticut (but not Massachusetts or Rhode Island) from “awarding, entering into, executing, or approving any wholesale electricity contracts in connection with the [Clean Energy RFP] during the pendency of this appeal.” The injunction did “not apply retroactively to any wholesale electricity contract that has been entered into, executed, and approved” as of November 2, 2016. Briefs and Amicus Briefs were filed. Oral argument was held on December 9, 2016 and on December 12, 2016 the Court vacated the November 2 injunction, indicating that an opinion would follow in due course. That opinion has not yet been issued.

144 150 FERC ¶ 61,064 (Jan. 30, 2015); 146 FERC ¶ 61,039 (Jan. 24, 2014). 145 154 FERC ¶ 61,005 (Jan. 7, 2016); 150 FERC ¶ 61,067 (Jan. 30, 2015).


Page I-1

41536280.171

INDEX Status Report of Current Regulatory and Legal Proceedings

as of February 1, 2017


206 Proceeding: RNS/LNS Rates and Rate Protocols .......................................................... (EL16-19) .............................. 3 Base ROE Complaints II & III (2012 & 2014) (Consolidated) ............................................ (EL13-33 and EL14-86)......... 4 Base ROE Complaint IV (2016) ........................................................................................... (EL16-64) .............................. 2 NEPGA PER Adjustment Complaint ................................................................................... (EL16-120) ............................ 1


206 Proceeding: RNS/LNS Rates and Rate Protocols .......................................................... (EL16-19) .............................. 3 Base ROE Complaints II & III (2012 and 2014) (Consolidated) .......................................... (EL13-33 and EL14-86)......... 4 Base ROE Complaint IV (2016) ........................................................................................... (EL16-64) .............................. 2 ICR-Related Values and HQICCs – Annual Reconfiguration Auctions............................... (ER17-472) ............................ 5 NEPGA PER Adjustment Complaint ................................................................................... (EL16-120) ............................ 1


2013/14 Winter Reliability Program Remand Proceeding ................................................... (ER13-2266) .......................... 9 CONE & ORTP Updates ...................................................................................................... (ER17-795) ............................ 5 Demand Curve Changes Remand Proceedings..................................................................... (ER14-1639) .......................... 8 Effective Date Update: Fast Start Pricing and DARD pump Parameter Changes ................ (ER17-576) ............................ 6 FCM Enhancements ............................................................................................................. (ER16-2451) .......................... 6 FCM Resource Retirement Reforms ..................................................................................... (ER16-551) ............................ 8 Natural Gas Index Changes .................................................................................................. (ER17-337) ............................ 6 Order 825 Compliance: 5-Min. Settlement of Regulation Capacity & Service Credit ........ (ER17-774) ............................ 5 Sub-Hourly Settlement NCPC Changes ............................................................................... (ER17-680) ............................ 5 Waiver Request: RTEG Resource Type/De-List (ISO-NE) ................................................. (ER16-1904) .......................... 7

IV. OATT Amendments/Coordination Agreements

Attachment K Revisions ....................................................................................................... (ER17-857) .......................... 10 Orders 827/828 Compliance Filing ...................................................................................... (ER16-2695) ........................ 10



VI. Schedule 20/21/22/23 Updates

Schedule 21-EM: Bangor Hydro/Maine Public Service Merger-Related Costs Recovery ... (ER15-1434 et al.) ............... 11 Schedule 21-ES: Eversource Recovery of NU/NSTAR Merger-Related Costs ................... (ER16-1023) ........................ 11 Schedule 23: FPL Energy Wyman SGIA ............................................................................. (ER17-581) .......................... 10

VII. NEPOOL Agreement/ Participants Agreement Amendments



Page I-241536280.171


2015 ISO-NE SIL Limits ...................................................................................................... (AD10-2-009) ...................... 13 LFTR Implementation: 33rd Quarterly Status Report .......................................................... (ER07-476; RM06-08) ......... 12 IMM Quarterly Markets Reports - 2016 Fall ........................................................................ (ZZ16-4) .............................. 12 Opinion 531-A Local Refund Report: FG&E ....................................................................... (EL11-66) ............................ 12 Opinions 531-A/531-B Local Refund Reports ...................................................................... (EL11-66) ............................ 12 Opinions 531-A/531-B Regional Refund Reports ................................................................. (EL11-66) ............................ 12


February 2017 Membership Filing ....................................................................................... (ER17-899) .......................... 13 January 2017 Membership Filing ......................................................................................... (ER17-682) .......................... 13


New Rel. Standards: PRC-027-1 and PER-006-1 ................................................................. (RM16-22) ........................... 13 NOPR: BAL-002-1a Interpretation Remand ........................................................................ (RM13-6) ............................. 15 NOPR: Revised Rel. Standards: BAL-005-1 & FAC-001-3 ................................................ (RM16-13) ........................... 14 NOPR: Revised Rel. Standard: MOD-001-2 ........................................................................ (RM14-7) ............................. 15 Order 830: New Rel. Standard: TPL-007-1 ......................................................................... (RM15-11) ........................... 14 Order 835: Revised Rel. Standard: BAL-002-2 ................................................................... (RM16-7) ............................. 14 Rel. Standards Retirement: BAL-004-0 ................................................................................ (RD17-1) .............................. 13

XI. Misc. Regional Interest

203 Application: GDF Suez Energy Resources/Atlas Power ............................................... (EC16-93) ............................ 16 203 Application: NSTAR/WMECO Merger ........................................................................ (EC17-62) ............................ 16 Emera MPD OATT Changes ................................................................................................ (ER15-1429; EL16-13) ........ 17 FERC Audit of ISO-NE ........................................................................................................ (PA16-6) .............................. 20 FERC Enforcement Action: Covanta Haverhill Associates ................................................. (IN17-3) ............................... 18 FERC Enforcement Action: Formal Investigation

(MISO Zone 4 Planning Resource Auction Offers) ............................................... (IN15-10) ............................. 19 FERC Enforcement Action: GDF SUEZ Energy Marketing NA ......................................... (IN17-2) ............................... 19 LGIA: CMP/ReEnergy Livermore Falls ............................................................................... (ER17-909) .......................... 17 MOPR-Related Proceedings (NYISO, PJM) ........................................................................ (ER13-62; ER16-49 ............. 17

XII. Misc: Administrative & Rulemaking Proceedings

Competitive Transmission Development Rates .................................................................... (AD16-18) ........................... 20 NOPR: Data Collection for Analytics & Surveillance and MBR Purposes .......................... (RM16-17) ........................... 23 NOPR: Electric Storage Participation in RTO/ISO Markets ................................................ (RM16-23; AD16-20) .......... 23 NOPR: LGIA/LGIP Reforms ............................................................................................... (RM17-8) ............................. 22 NOPR: Primary Frequency Response -

Essential Reliability Services and the Evolving Bulk-Power System .................... (RM16-6) ............................. 24 Order 825: Settlement Intervals/Shortage Pricing ................................................................ (RM15-24) ........................... 25 Order 831: Price Caps in RTO/ISO Markets ........................................................................ (RM16-5) ............................. 25 Order 833: Critical Energy/Electric Infrastructure Information (CEII) Procedures ............. (RM16-15) ........................... 24 Order 834: Civil Monetary Penalty Inflation Adjustments .................................................. (RM17-9) ............................. 21 Price Formation in RTO/ISO Energy and Ancillary Services Markets ................................ (AD14-14) ........................... 21 PURPA Implementation ....................................................................................................... (AD16-16) ........................... 21 Reactive Supply Compensation in RTO/ISO Markets ......................................................... (AD16-17) ........................... 20 Electric Storage Resource Utilization in RTO/ISO Markets ................................................ (AD16-25) ........................... 20


Page I-341536280.171


Algonquin EDC Capacity Release Bidding Requirements Exemption Request ................... (RP16-618) .......................... 26 Enforcement Action: BP Initial Decision ............................................................................. (IN13-15) ............................. 27 Enforcement Action: Total Gas & Power North America, Inc. ............................................ (IN12-17) ............................. 27 New England Pipeline Proceedings ...................................................................................... ............................................. 28



XV. Federal Courts

Allco Finance Limited v. Klee et al. .................................................................................... 16-2946 ((2d Cir.) ................ 31 Base ROE Complaint I (2011) .............................................................................................. 15-1118 et al. (DC Cir.) ....... 30 Base ROE Complaints II & III (2012 & 2014) ..................................................................... 15-1212 (DC Cir.) ................ 30 FCM Pricing Rules Complaints ............................................................................................ 15-1071/16-1042 (DC Cir.) . 31 FCA10 Results and FCA9 Results........................................................................................ 16-1068/16-1408 (DC Cir.) . 29 NEPGA PER Complaint and FCM Jump Ball and Compliance Proceedings ...................... 16-1023/1024 (DC Cir.) ....... 30 Order 1000 Compliance Filings ........................................................................................... 15-1139 (DC Cir.) ................ 30

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