David T. Doot Secretary April 3, 2015 - nepool T. Doot Secretary April 3, 2015 VIA ELECTRONIC MAIL TO: MEMBERS AND ALTERNATES OF THE NEPOOL PARTICIPANTS COMMITTEE RE: Supplemental

David T. DootSecretary

April 3, 2015

VIA ELECTRONIC MAIL

TO: MEMBERS AND ALTERNATES OF THE NEPOOL PARTICIPANTS COMMITTEE

RE: Supplemental Notice of April 10, 2015 NEPOOL Participants Committee Meeting

Pursuant to Section 6.6 of the Second Restated New England Power Pool Agreement,supplemental notice is hereby given that a meeting of the NEPOOL Participants Committee willbe held on Friday, April 10, 2015, at 10:00 a.m. at The Seaport Boston Hotel, 1 SeaportLane, Boston, MA. The Participants Committee meeting will be held in Seaport Ballroom (inthe Seaport Hotel) for the purposes set forth on the attached agenda and posted with the meetingmaterials at http://nepool.com/NPC_2015.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. We hope you have all madeovernight reservations as needed, since rooms are scarce and at a premium. If you still need areservation, please contact the Seaport directly (617-385-4000) to see if they have any roomsavailable outside of the NEPOOL block. Cindy Jacobs, NEPOOL Administrator,([email protected]/860-275-0246) will also try to assist if you are not successful withSeaport.

Looking ahead, please mark your calendars for the 14th Annual NEPOOL ParticipantsCommittee Summer Meeting, which will be held at The Stoweflake Resort & ConferenceCenter, Stowe, VT, on June 23-25, 2015 (http://www.stoweflake.com/). As in the past, there willbe a welcome reception with the ISO Board and New England Regulators on Monday, June 22for those who are able to arrive early. Detailed information regarding the ParticipantsCommittee Summer Meeting will be provided in future notices, including information regarding the reservations block, once the block is open.

Respectfully yours,

/s/David T. Doot, Secretary

NEPOOL PARTICIPANTS COMMITTEEAPR 10, 2015 MEETING

FINAL AGENDA

1. To approve the preliminary minutes of the Participants Committee meeting held onMarch 6, 2015. The draft minutes of the March 6 meeting marked to show changes fromthe draft circulated with the initial notice are included with this supplemental notice andposted with the meeting materials.

2. To adopt and approve all actions recommended by the Technical Committees set forth onthe Consent Agenda included with this supplemental notice.

3. To receive an ISO Chief Executive Officer Report.

4. To receive an ISO Chief Operating Officer Report. Please note that the COO report thismonth will also include discussion of the 2014/15 Winter Program experiences.

5. To consider, and take action, as appropriate, on revisions to the ISO Financial AssurancePolicy related to Foreign Entities’ ability to use BlackRock accounts as a collateral andconforming revisions to the ISO Billing Policy, as recommended by the Budget &Finance Subcommittee. Background materials and a draft resolution are included withthis supplemental notice and posted with the meeting materials.

6. To consider, and take action as appropriate, on revisions to Market Rule 1 to allowoverhead/centralized costs to be included, up to a specified default rate, in Static De-ListBids submitted in the FCM, as proposed by Exelon Generation Company, LLC.Background materials and a draft resolution are included with this supplemental noticeand posted with the meeting materials.

7. To consider, and take action as appropriate, on revisions to Market Rule 1 to allow thefull inclusion of capital costs in FCM de-list bids, as proposed by Exelon GenerationCompany, LLC. Background materials and a draft resolution are included with thissupplemental notice and posted with the meeting materials.

8. To consider and take action, as appropriate, on proposed amendments to the NEPOOLAgreement to create a GIS-Only Participant status, as recommended by the MembershipSubcommittee. Background materials and a draft resolution to approve the amendmentsfor balloting are included with this supplemental notice and posted with the meetingmaterials.

9. To receive a report on current matters relating to regional wholesale power andtransmission arrangements that are pending before the regulators and the courts. Thelitigation report will be circulated in advance of the meeting.

10. To receive reports from committees and subcommittees.

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

NEPOOL PARTICIPANTS COMMITTEEAPR 10, 2015 MEETING, AGENDA ITEM #1

Marked to Show Changes from Draft Circulated 3/27/2015

3415

PRELIMINARY

A meeting of the NEPOOL Participants Committee was held beginning at 10:00 a.m. on

Friday, March 6, 2015 at The Colonnade Hotel, Boston, Massachusetts, 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 attending the meeting.

Mr. Joel Gordon, Chairman, presided and Mr. David Doot, Secretary, recorded. Mr.

Gordon welcomed the members, alternates and guests who were present.

ACKNOWLEDGMENT IN MEMORIAM -- ALLISON SMITH

Mr. Gordon began the meeting acknowledging Ms. Allison Smith, most recently of

NESCOE, who was recently killed in a car accident. He quoted the following passage from

Maya Angelou: “I've learned that people will forget what you said, people will forget what you

did, but people will never forget how you made them feel.” He recalled Allison’s magical ability,

in every interaction, on any issue, to leave her colleagues with a smile and a warm feeling. Mr.

Gordon requested that, in Allison’s memory, the minutes reflect Allison’s presence at the March

6 Participants Committee meeting.

Mr. Doot then read the following resolution of appreciation honoring Allison’s

contributions:



3416

APPRECIATION IN MEMORIAMOF ALLISON SMITH

WHEREAS, we pause to express our gratitude for the pleasure and opportunityto work with Ms. Allison Smith, who shared with us her passion for life, for friends,for the industry and for the environment;

WHEREAS, Allison always contributed to NEPOOL discussions withhumility, grace, great thought, self-confidence, a sincere effort to understand the diverseinterests of the region, and ever-increasing demonstration of her growth in thatunderstanding, a genuine respect for those around the table, and a refreshing sense ofhumor; and

WHEREAS, Allison leaves with us her legacy of caring, for which she will alwaysbe remembered and we will always be grateful.

NOW, THEREFORE, the Participants Committee of the New England PowerPool, on behalf of the NEPOOL Participants, hereby expresses sincere gratitude toAllison for her years of participation in NEPOOL and for her warm, enthusiastic andvisible efforts to make our region a more welcoming, happier and better place. She willbe missed.

The motion of appreciation was duly made, seconded and by acclimation unanimously

approved by the Committee. Mr. Doot stated that originals of the resolution would be sent to

Allison’s parents and her spouse following the meeting.

APPROVAL OF MINUTES OF FEBRUARY 6, 2015

Mr. Gordon referred the Committee to the preliminary minutes of the February 6, 2015

meeting that were circulated and posted in advance of the meeting. Following motion duly made

and seconded, the preliminary minutes of the February 6, 2015 meeting were unanimously

approved without change.



3417

CONSENT AGENDA

Mr. Gordon referred the Committee to the Consent Agenda circulated in advance of the

meeting. A motion was duly made and seconded to approve the Consent Agenda, with Item No.

3 (support for revisions to Market Rule 1 to eliminate the Peak Energy Rent (PER) mechanism

for the June 1, 2019 – May 31, 2020 Capacity Commitment Period (CCP-10) and beyond)

removed for discussion later in the meeting. That motion was unanimously approved without

comment.

REPORT OF THE ISO CHIEF EXECUTIVE OFFICER

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

summary of the February 5 and February 19, 2015 ISO Board and Board Committee meetings,

which had been circulated and posted in advance of the meeting. There were no questions or

comments on that report.

Mr. van Welie then reported that the ISO planned to release in April a document

exploring options for addressing demand response (DR) depending on the outcome of the

Supreme Court action on the Order 745 appeals. He stressed that the document would not be a

contingency plan but, rather, a document to identify the different possibilities for discussions

with the ISO Board and NEPOOL Markets Committee. Following those discussions, the ISO

was seeking to have contingency plans in place prior to final Supreme Court action. In response

to a question, Mr. van Welie confirmed that the ISO was exploring the implications to both the

energy and capacity markets given the possibility for either a narrow or broader interpretation by

the Courts and the FERC on the DR issues.



3418

REPORT OF THE ISO CHIEF OPERATING OFFICER

Dr. Vamsi Chadalavada, ISO Chief Operating Officer, reviewed highlights from the

March COO report, which had been circulated and posted in advance of the meeting. Focusing

on report highlights, which he noted reflected experiences through February 25 (except Real-

Time Net Commitment Period Compensation (NCPC), which was only through February 23), he

stated that in February: (i) Energy Market value was $1.2 billion, up $339,000 from the prior

month, but down $492,000 from February 2014; (ii) natural gas prices were 74% higher than

January 2015 average values; (iii) Real-Time Hub locational marginal prices (LMPs) on average

were 89% higher than January 2015 LMPs; (iv) average daily (peak hour) Day-Ahead cleared

physical Energy, as a percentage of forecasted load, was 99.2% in February 2015, down from

99.8% in January 2015; (v) daily NCPC through February 23 totaled $8.9 million, up $946,000

from January; (vi) first contingency payments totaled $7 million, up $300,000 from January’s;

(vii) second contingency payments totaled $865,000, up from $559,000 in January; (viii) voltage

support payments totaled $928,000, up $241,000 from January; and (ix) distribution payments

totaled $21,000; and (x) NCPC payments were 0.7% of the total Energy Market value.

Dr. Chadalavada reviewed the amount of Day-Ahead cleared physical energy, which had

recently been between 99.5 - 99.8%, was fairly remarkable, and had resulted in an almost

complete elimination of supplemental commitments. He reported for 2014/15 Winter about $32

million of uplift, down sharply from the almost $110 million for Winter 2013/14, which he

attributed to a more balanced optimization of grid operations, price formation improvements, and

improved Control Room judgments. He added that similar evaluations would be prepared for the

spring, summer and fall periods, with some variations expected in the spring and fall due to

maintenance outages. He noted that, in general, System performance during the peaks was good.



3419

Turning to NCPC, Dr. Chadalavada said that the calculation of, and compensation for,

NCPC had been substantially changed with the implementation of hourly offers. The ISO still

needed to analyze the impact of the NCPC design and its contribution to commitment costs. By

way of example, he stated the NCPC design changes explained a portion of the $7 million first

contingency payments in the prior month. He noted that the ISO would report on the

observations, causes and contributions towards the uplift amount at the May or June Participants

or Markets Committee meetings. He stated that almost all second contingency uplift costs were

for NEMA in early February; uplift for voltage were largely in Western Massachusetts; and

NCPC was 0.7% of total Energy Market value.

Dr. Chadalavada reported that the Show-of-Interest (SOI) window for new resource

participation in the tenth Forward Capacity Auction (FCA-10) had closed on March 3, with a

total of 17,000 MW of new resources being proposed, including new generation, new DR and

imports. He compared this interest to the approximately 12,000 MW of new resources that

expressed interest in FCA9. He referred stakeholders to the interconnection queue, which at

least from the generation standpoint, provided additional information.

In response to clarifying questions, Dr. Chadalavada explained the favorably low

Supplemental Commitments by explaining how first contingency uplift was created and other

features of the recently implemented Market Rules. Dr. Chadalavada confirmed that, were there

a sub-hourly settlement (a project included in the 2015 Work Plan), some of the remaining uplift

would also go awayhave been eliminated. Overall, Dr. Chadalavada noted that the region had

experienced a dramatic reduction in uplift costs, with aggregate annual levels dropping over the

past five to ten years from $250-$350 million to $100 million.



3420

With respect to resources in the FCAs, Dr. Chadalavada confirmed that 16.25 MW of

renewable technology resources (RTR) had cleared in FCA9 (against the 200 MW aggregate

exemption). He also noted the breakdown in the report of DR resources that cleared from FCA1

to FCA9.

Turning next to the 2014/15 Winter Reliability Program, Dr. Chadalavada updated the

Committee on the Dual-Fuel Commissioning Program, reporting that, as of February 3, three of

four units had successfully commissioned their Dual-Fuel capability during Winter 2014/15.

NCPC totaling $1 million had been incurred from November 1 through February 23, leaving

$1.2 million remaining under the 2014/15 Commissioning Cap. He reported the total Program

fuel burn for December 2014 through February 2015 was 2.72 million barrels, roughly the same

amount burned during the same period in 2013/14, but which would have been much higher but

for the unavailability of two large oil generating units that were out-of-service during key

portions of February. Dr. Chadalavada indicated that, except for a few commitments in the

beginning of February for second contingency in NEMA, none of the 2.72 million barrels of oil

were burned out-of-merit. Final information regarding oil replenishments was not yet available

but would be provided in April and sooner if possible.

Operationally, he reported that, notwithstanding the cold temperatures, February was

uneventful, in part because gas units had access to LNG, there was high availability of nuclear,

coal, and oil-fired base load units, imports from Quebec, few contingencies, few forced outages,

and very nominal load forecast variations. He reported that LNG injections were substantially

lower in February, and three of the four dual-fuel units were running low on oil, but two were

switched to gas as gas prices moderated. He expected the switch from oil to gas to continue

through March.



3421

Dr. Chadalavada concluded that the timing of the Winter 2014/15’s colder temperatures,

and the incentives to increase oil inventory, had worked in the region’s favor. He showed with

charts that the coldest temperatures during Winter 2014/15 were in February. Had the cold

period occurred in January rather than in February, there would have been higher loads (1,000 to

1,5000 MW higher), roughly 1 million additional barrels of oil would have been burned, and it

would have been more challenging to maintain System reliability. Mr. van Welie cautioned that

reliability concerns for future Winter periods continue through Winter 2017, particularly given

the impending loss of significant amounts of non-gas-fired generation such as Brayton Point.

Dr. Chadalavada committed to provide more detailed information at future meetings

regarding total oil burned. He confirmed that the lower oil price during Winter 2014/15 had also

benefitted New England. He explained that, with the world LNG market indexed to the price of

crude oil, lower oil prices had reduced LNG shipments world-wide, but not to New England

which, for the second winter in a row, had the most expensive LNG prices. Dr. Chadalavada

explained that the ISO saw increased LNG during Winter 2014/15, although the reason still

needed to be ascertained. It was clear, however, that the dip in oil prices and the amount of LNG

available to the New England System had disciplined Energy Market clearing prices.

A NESCOE representative asked why none of the LNG was burned in the program. Dr.

Chadalavada postulated that higher strike prices had likely inhibited broader use of LNG inLNG

call option contracts under the Winter 2014/15 Program. With respect to LNG replenishment

data, the ISO committed to do its best to make that data available as soon as possible likely had

strike prices above the prevailing LNG market prices during this period and therefore went

unstruck.



3422

Dr. Chadalavada indicated that a comprehensive summary of Winter 2014/15 operations,

including several additional exhibits, would be presented to NEPOOL as soon as possible

following the conclusion of the winter.

2015 WORK PLAN

Mr. Gordon referred the Committee to the revised 2015 Work Plan that was circulated

and posted in advance of the meeting, reminding members that it had been introduced at the

February teleconference meeting. He said the presentation at this meeting was forto support a

more in-depth discussion of the Plan.

Dr. Chadalavada then reviewed the Work Plan noting that it had been revised to update

the timelines for the Third Party FTR clearing project, to be implemented in 2016 for the 2017

annual FTR auction, and the “Do Not Exceed” (DNE) wind dispatch project, targeted for

implementation in April 2016. He explained in that reviewed that the cyber security-related

projects required substantial operational efforts and a capital investment. He expected the work

load associated with this project to increase faster than any other project, with plans in 2015 to

implement a 24x7 security operations center to address cyber threats. He reported that this

project would result in an incremental headcount addition in 2015, which had not been reflected

in the 2015 budget, but would be trued up in the 2016 budget.

In the area of market design, Dr. Chadalavada stated the focus would be on energy price

formation and continued FCM reforms, including fast start pricing, ramp constraint pricing, and

full co-optimization of energy and reserves in the Day-Ahead Energy Market. Turning to the full

integration of Demand Resources, as touched on earlier in the meeting by Mr. van Welie, he

noted the ISO’s plan to discuss development of contingency plans to address potential impacts of

Supreme Court action on the EPSA v. FERC matter. He pointed out that the full integration of



3423

price responsive demand (PRD), previously scheduled for June 1, 2017, would be delayed at

least one year, to June 1, 2018, to minimize capital investment to implement PRD before

knowing how it might be impacted by EPSA v. FERC.

Dr. Chadalavada also noted uncertainty surrounding the level of efforts to be required on

Order 1000 compliance. He noted the potential for incremental costs, both in 2015 and 2016,.

He said that scheduling around probabilistic planning would be discussed at the April Planning

Advisory Committee (PAC) meeting.

Dr. Chadalavada agreed with members’ requests to time the development and release of

the Work Plan to coincide more closely with budget development and review. Although he

indicated that many activities were in a “steady state,” the following three areas in the 2015

Work Plan could potentially lead to spikes in needed personnel resources or expenditures: (1)

cyber security; (2) NERC/NPCC compliance and standards; and (3) Order 1000 compliance and

implementation. Similarly, Mr. van Welie reported that the IMM had requested a slightly higher

headcount, which would be funded as a contingency in 2015 from the management and Board

contingency funds. The additional resources, once hired, would be included in 2016’s baseline

headcount.

Addressing the implementation schedule for third party clearing of FTRs, Dr.

Chadalavada explained that the projected delay resulted from personnel constraints related

primarily to implementation of Coordinated Transaction Scheduling and Generation Control

Application in the 4th quarter. He acknowledged Participants’ sensitivity to the additional delay,

but indicated that the ISO would continue to work on this project in 2015 (albeit at a slower pace

than previously projected) and that the project would be a high priority project in 2016.



3424

In planning for combined discussions of the Work Plan and budgets, Mr. Gordon

reminded the Committee of the timing of the 2016 budget process, with the first ISO

presentations to be made in June at the NECPUC Symposium and Participants Committee

Summer Meeting, in August at the Budget & Finance Subcommittee, and then again at the

Participants Committee in September and/or October for final consideration, prior to its filing

with the FERC.

ISO INTERNAL MARKET MONITOR (IMM) QUARTERLY MARKETS REPORT

Mr. Jeffrey McDonald, the ISO IMM, referred the Committee to the IMM 2014 Fourth

Quarter (Q4 2014) Quarterly Markets report circulated in advance of the meeting. He

highlighted that Energy Market prices in Q4 2014 were consistent with those expected of a

competitive market and were generally concentrated and structurally competitive.

Summarizing with more details, he reported that:

• Lower natural gas prices in Q4 2014 led to lower Day-Ahead and Real-Time EnergyMarket prices when compared to Q4 2013.

• NCPC payments totaled $27.8 million in Q4 2014, a 6% drop compared to the sameperiod in 2013.

• Real-Time Reserve payments totaled $8 million in Q4 2014, which was a 60% decreasefrom Q4 2013.

• Regulation payments totaled $5.8 million in Q4 2014, a 10% decrease from Q4 2013.

Mr. McDonald then reviewed a chart reflecting NCPC payments, highlighting which

payments were higher and lower from prior periods. He summarized that NCPC payments

increased 143% in Q4 2014 compared to Q3 2014, attributing that increase to, among other

things, the implementation of hourly offers and negative LMPs, and subject to further study,

hourly settlement for NCPC.



3425

For the next quarterly report, Mr. McDonald committed to provide a more holistic look at

what was driving NCPC as well as pricing by addressing gas availability during Winter 2014/15,

the effectiveness of hourly offers, and the settlement change that permits negative pricing. He

reported a substantial increase in Second Contingency Payments from $2.84 million in Q4 2013

to $8.7 million in Q4 2014. He explained that Second Contingency Payments for Q4 2014 were

primarily driven by NEMA/Boston, with commitment decisions needed to meet reserve

requirements impacted by the loss of Salem Harbor for Q4 and most of Q3.

Mr. McDonald reviewed a slide illustrating the marginal units by fuel type for Q4 and

provided a breakdown of the percentages including: natural gas - 74.9%; oil - 0.6%, diesel -

0.9%, pumped storage - 11.6%, other hydro, wood, refuse - 4.9%; and coal - 7.4%. In response

to a question, Mr. McDonald committed to report back at a subsequent meeting as to whether the

pump storage percentage included only generation pump storage or if it also included the

pumping side when setting the price.

Mr. McDonald then updated the Committee on the Energy Market Offer Flexibility

(EMOF) changes that were implemented on December 3, 2014. He reviewed that the changes

allow Market Participants to vary Energy Market Offers by hour and to change Offers in Real-

Time during the Operating Day. He stated the offers that are more reflective of actual fuel prices

improve Energy Market price signals and permit a better match between those prices and the cost

of procuring fuel in Real-Time. He reported the IMM would continue to monitor how the EMOF

changes were working and would include an update in the Q1 2015 Quarterly Markets Report.

In response to a request that the next quarterly report include an analysis of negative bids, Mr.

McDonald indicated that he was not certain that there would be sufficient time to include that

detailed analysis in the Q1 2015 report, but would ensure its inclusion in the Q2 report.



3426

Mr. Gordon asked whether the ISO had considered whether there would be benefits to

changing the timing of these periodic reports, such that they might be more aligned with physical

market operations (winter, summer, shoulder periods), rather than by calendar quarters. Mr.

McDonald noted the FERC requirement that the ISO produce quarterly markets reports, but

agreed to consider whether a modified schedule for Committee presentations might be beneficial

and/or more efficient.

Mr. McDonald concluded his presentation by reporting on an OP4 event that occurred on

December 4, 2014 and referred the Committee to charts reflecting an operational summary of

that event. He reported a loss of nearly 2,000 MW from Hydro-Quebec as two large

transmission lines went out, which caused the ISO to implement Action 1 of OP4 to allow for

depletion of Thirty-Minute Operating Reserves. He reviewed that no demand responseDR was

dispatched during the event, and sufficient reserves were available after the evening peak

occurred, at which point OP4 was cancelled.

A member asked for an update with respect to a pending request for an evaluation of the

Forward Reserve Market clearing during summer 2014. Mr. McDonald responded that the

analysis had not been completed and released for two reasons. First, the ISO’s lead analyst had

left for another job opportunity before the analysis was finalized. Second, the IMM believed that

the benefits of a public report had been overtaken by ISO efforts to evaluate revamping the

procurement of ancillary services/reserves, in response to a recommendation by the External

Market Monitor move towards a Day-Ahead and Real-Time, rather than forward, procurement.

The member urged the IMM to reconsider releasing the analysis, particularly given the length of

time that would be required to fully consider such changes.



3427

ELIMINATION OF PER MECHANISM FOR CCP-10

Ms. Allison DiGrande, Markets Committee Chair, referred the Committee to the

materials circulated and posted in advance of the meeting regarding revisions to Market Rule 1

to eliminate the FCM PER mechanism beginning with the Capacity Commitment Period

associated with the tenth Forward Capacity Auction that is scheduled to commence on June 1,

2019 (CCP-10). She reported that the Markets Committee recommended Participants Committee

support for these changes at its February 10-11, 2015 meeting.

The following motion was duly made, seconded:

RESOLVED, that the Participants Committee supports revisions toMarket Rule 1 to eliminate the Peak Energy Rent mechanism forthe June 1, 2019 – May 31, 2020 Capacity Commitment Period(CCP-10) and beyond, as circulated to this Committee anddiscussed at this meeting, with such further non-substantivechanges as the Chair and Vice-Chair of the Markets Committeemay approve.

Mr. Gordon reported that this matter was initially included as Item #3 on the March 6

Consent Agenda, but was removed for discussion at the request of the Maine Office of the Public

Advocate (MOPA) and the New Hampshire Office of Consumer Advocate (NHOCA). The

MOPA and NHOCA representative explained that the item had been removed from the Consent

Agenda so that there would be an opportunity to hear and discuss the IMM’s plans to continue

monitoring of Real-Time offers, both during the three-year period in which PER will remain in

effect as well as once the PER mechanism is no longer in effect.

In response, Mr. McDonald explained that there were a number of market power

mitigation measures to address economic or physical withholding that PER was specifically

designed to address that would be unaffected by whether PER is, or is not, in place. He

explained that the existing PER provisions still required careful monitoring of bidding activities



3428

in any event to protect against physical withholding. Looking ahead, he indicated that the

penalties or take backs from capacity market revenues to be implemented with the

implementation of the pay-for-performance rules would provide a reasonable, if not an exact,

substitute for the PER mechanism. In addition, Mr. McDonald opined that the ISO was already

in a better position to use availability/outage and portfolio profitability data to conduct the

necessary daily and weekly monitoring, and noted efforts underway to further bolster the IMM’s

monitoring capabilities, including improving the speed and automation of data access.

The National Grid representative stated his company would oppose the elimination of the

PER mechanism, explaining that, with the strike price set intentionally at a level well above what

could be considered a competitive energy price, it was unnecessary to allow resources to be paid

and retain revenues at that extreme price, would otherwise be an overpayment in the combined

Energy and Capacity Markets, and would not impact the true cost of new entry. For the same

reasons expressed by the National Grid representative, the MMWEC representative stated he

would oppose the changes. Providing the opposite view, a member of the Generation Sector

indicated his support for the changes, which he viewed as eliminating a penalty for those selling

into the Day-Ahead Energy Market during a PER hour.

The Committee then considered and approved the motion with oppositions noted by: CT

OCC, Harvard, National Grid, and each of members of the Publicly Owned Entity Sector with

representatives in attendance.

INTERMITTENT RESOURCE REAL-TIME DNE DISPATCH RULES

Ms. DiGrande referred the Committee to the materials circulated and posted in advance

of the meeting regarding revisions to Market Rule 1, Appendix F to Market Rule 1 and Tariff

Section I.2.2 to implement Real-Time Do Not Exceed (DNE) dispatch rules for intermittent



3429

resources (DNE Dispatch Rules). She reported that the Markets Committee recommended the

changes with a 74.54% Vote in favor at its February 10-11, 2015 meeting. She noted that the

DNE Dispatch Rules were not on the Consent Agenda in light of discussion that continued

following the Markets Committee recommendation that suggested a high probability that either

the ISO would propose substantive changes to the Markets Committee-recommended DNE

Dispatch Rules or one or more Participant motions to amend those recommended changes would

be forthcoming.

The following motion was duly made and seconded:

RESOLVED, that the Participants Committee supports revisions toMarket Rule 1, Appendix F to Market Rule 1 and Tariff Section I.2.2 toimplement Real-Time Do Not Exceed dispatch rules for intermittentresources, as circulated to this Committee and discussed at thismeeting, with such non-substantive changes as may be approved bythe Chair and Vice-Chair of the Markets Committee.

Members commented on the revisions. The Brookfield representative expressed

appreciation to the ISO for meeting with his company to discuss some of the operational

challenges that hydro facilities would face under the rules. He stated that the ISO had agreed to

consider the development of new parameters that might support better representation of the

physical characteristics of hydro facilities. He stated Brookfield would abstain on the motion

because the parameters and the full design were not yet fully identified or captured in the Market

Rules. He also urged the ISO to consider implementing, as soon as practicable, dispatch

characteristics for other resources that could elect to be non-dispatchable.

Others noted their concerns and echoed appreciation for the ISO’s efforts on the changes.

A Generation Sector representative, noting a general preference for inclusion of details in the

Tariff itself, was satisfied that, in this case, the details would be developed in a new appendix to



3430

Operating Procedure No. 14 (OP-14), and was pleased that details of the requirements would be

known and clarified in advance of implementation. Explaining their abstentions, the Eversource

representative noted a desire to see the OP-14 changes developed and to have a more complete

understanding of the associated costs and obligations prior to taking a final position, while a

representative of the Publicly Owned Entity Sector noted that the Sector’s members had not yet

gotten comfortable with the implications for hydro resources (though acknowledging the

advantages to wind resources) or with the implications for other categories of resources,

particularly those that may not be participating directly in the markets (e.g. demand responseDR

resources).

After further discussion, the Committee then considered and unanimously approved the

motion with abstentions noted by: Brookfield, CSC, Dominion, Eversource, LIPA, National

Grid, UI, and the Publicly Owned Entity Sector.

SRECTRADE, INC. MEMBERSHIPAPPLICATION

Mr. Patrick Gerity, NEPOOL Counsel, referred the Committee to the materials circulated

and posted in advance of the meeting regarding the application for membership in NEPOOL by

SRECTrade, Inc. (SRECTrade). He explained that SRECTrade, an Entity in the business of

brokering and trading in solar renewable energy credits (SRECs) and active participant in the

NEPOOL Generation Information System (GIS), did not qualify for membership in any Sector of

NEPOOL without changes being made to the NEPOOL arrangements. He summarized ongoing

efforts by the Membership Subcommittee to identify changes to the membership provisions to

address that issue, including the elements of a proposal to establish a “GIS-Only Participant”

status. Mr. Gerity reported that the details of that proposal were scheduled to be finalized at the

March 16 meeting of the Membership Subcommittee, encouraged all those interested to



3431

participate, and indicated that, if finalized at the March Subcommittee meeting, the proposal

would be presented for Participants Committee consideration at its April 10 meeting.

Members then asked clarifying questions and provided input on the elements of the GIS-

Only Participant proposal. In response to a members’ questions, Mr. Gerity clarified that a GIS-

Only Participant would be a treated like any other Participant for all purposes, other than with

respect to making a motion and voting, where they would be a voting member for, and could

make motions only with respect to, GIS matters. When voting on GIS matters, GIS-Only

Participants would vote as members of the Provisional Member Group Seat.

Addressing a request by SRECTrade to participate in the Pool while the arrangements

governing its membership were finalized, Mr. Gerity reported that SRECTrade had requested,

and the Subcommittee had not opposed, that SRECTrade be admitted as a Provisional Member

for a limited, interim period of time. Mr. Gerity clarified that, in order to address concerns that

the interim period of time be both long enough to ensure time for the long-term arrangements to

be finalized and become effective, but not be of unlimited duration (thereby incenting

completion of the arrangements), an additional sunset condition to SRECTrade’s membership

had been recommended that would have SRECTrade’s membership as a Provisional Member

expire upon the earlier to occur of (i) the effectiveness of changes to the NEPOOL Agreement to

address SRECTrade’s participation in the Pool or (ii) January 1, 2016 (at most, nine months).

The following motion was then duly made, seconded, and unanimously approved:

RESOLVED, that the Participants Committee approves the membership ofSRECTrade, Inc. (SRECTrade) in the New England Power Pool, subjectto the following conditions: (1) that NEPOOL Counsel and the ISO findthe application by SRECTrade complete; and (2) that SRECTrade accept(a) the Standard Membership Conditions, Waivers and Reminders and (b)the following additional condition: SRECTrade’s status as a ProvisionalMember will expire upon the earlier to occur of (x) the effectiveness of



3432

changes to the NEPOOL Agreement to address SRECTrade’s Sectoreligibility or alternative participation in the Pool or (y) January 1, 2016.

LITIGATION REPORT

Mr. Gerity then referred the Committee to the March 4 Litigation Report that had been

circulated and posted in advance of the meeting. He highlighted recent activity in the complaint

proceedings, including a number of requests for rehearing of orders issued on January 30 and an

order denying rehearing of FERC Opinions 531 and 531-A.

COMMITTEE REPORTS

The Vice-Chairs of each of the Technical Committees reported on the schedule for

Committee meetings in March (see NEPOOL calendar). Mr. Dell Orto reported that the next

Budget & Finance Subcommittee meeting was scheduled for March 26 and would include, in

addition to routine matters, a discussion of GIS cost allocation practices. He encouraged those

with an interest in those practices to participate in that meeting. Ms. Abigail Krich, Vice-Chair

of the Variable Resources Working Group (VRWG), reported that the VRWG was scheduled to

meet on March 30 at the Publick House in Sturbridge, with discussion to include potential OP-14

changes to support DNE dispatch rules for intermittent hydro resources (as noted earlier in the

meeting) and Day-Ahead Energy Market Offers from, and NCPC calculations for, variable

resources. Mr. Jose Rotger reported that, following some re-scheduling, the Planning Advisory

Committee was scheduled to meet on March 24.

OTHER BUSINESS

Mr. Doot reported that the next Participants Committee meeting was scheduled for April

10, 2015, at the Seaport Hotel, with the discounted room block open for reservations already full



3433

and asked that anyone still needing a reservation to contact Ms. Cynthia Jacobs, NEPOOL

Administrator, for her assistance. Looking ahead, he encouraged people to mark their calendars

for the Summer Meeting, scheduled to be held at the Stoweflake Resort & Conference Center in

Stowe, Vermont, on June 23-25 with a welcome reception on June 22. He indicated that the

room block for the summer meeting had not yet opened as of yet and to stay tuned for that

information in future notices of upcoming meetings.

Highlighting additional meetings on the March calendar, Mr. Doot noted that the

Consumer Liaison Group was scheduled to meet at Stoweflake on March 13 and that the FERC

had scheduled a March 11 Eastern region technical conference on the implications of compliance

approaches to the Environmental Protection Agency’s proposed Clean Power Plan at the same

time as the second day of the previously announced March Markets Committee meeting. He

encouraged those impacted to focus on arranging coverage for both.

There being no further business, the meeting adjourned at 12:05 p.m.

Respectfully submitted,

______________________David T. Doot, Secretary

NEPOOL PARTICIPANTS COMMITTEE MEETINGAPR 10, 2015 MEETING, AGENDA ITEM #1

Marked to Show Changes from Draft Circulated 3/27/2015ATTACHMENT 1

MEMBERS AND ALTERNATES PARTICIPATING INMARCH 6, 2015 PARTICIPANTS COMMITTEE MEETING

PARTICIPANT NAME SECTOR/GROUP MEMBER NAMEALTERNATE

NAMEPROXY

American PowerNet Management Supplier Mary H. Smith

Ashburnham Municipal Light Plant Publicly Owned Gary Will

Boylston Municipal Light Department Publicly Owned Gary Will

BP Energy Company Supplier Nancy Chafetz

Brookfield Energy Marketing/Cross-Sound Cable (CSC) Supplier Aleksandar Mitreski

Calpine Energy Services, LP Supplier John Flumerfelt

Central Maine Power Company Transmission Eric Stinneford (tel)

Chicopee Municipal Lighting Plant Publicly Owned Gary Will

Connecticut Office of Consumer Counsel (CT OCC) End User Joseph Rosenthal

Conn. Municipal Electric Energy Cooperative Publicly Owned Brian Forshaw

Conservation Law Foundation End User Jerry Elmer

Conservation Services Group AR Doug Hurley

Consolidated Edison Energy, Inc. Supplier Jeff Dannels

Cross Sound Cable Supplier Jose Rotger

Dominion Energy Marketing, Inc. Generation Jim Davis

DTE Energy Trading, Inc. Supplier Nancy Chafetz

Dynegy Marketing and Trade Supplier William Fowler

Emera Maine Transmission Stacy Dimou

Energy America, LLC Supplier Nancy Chafetz

EnerNOC, Inc. AR Herb Healy (tel)

Enerwise Global Technologies Inc. d/b/a CPower AR John Driscoll

Entergy Nuclear Power Marketing LLC Generation Ken Dell Orto

EquiPower Resources Management, LLC Generation James Ginnetti (tel)

Essential Power, LLC Generation M.Q. Riding (tel)

Eversource Energy Transmission James Daly Joe Staszowski

Exelon Generation Company Supplier Steve Kirk (tel)

Galt Power, Inc. Supplier Nancy Chafetz

GDF SUEZ Energy Marketing NA, Inc. Generation Thomas Kaslow

Generation Group Member Generation Abby Krich

Granite Ridge Energy, LLC Supplier

Groton Electric Light Department Publicly Owned Gary Will

H.Q. Energy Services (U.S.) Inc. Supplier Robert Stein

Harvard Dedicated Energy Ltd End User Mary H. Smith

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

Holden Municipal Light Department Publicly Owned Gary Will

Holyoke Gas & Electric Department Publicly Owned Gary Will

Hull Municipal Lighting Plant Publicly Owned Gary Will

Industrial Energy Consumer Group End User Donald J. Sipe

Ipswich Municipal Light Department Publicly Owned Gary Will

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

Long Island Lighting Company (LIPA) Supplier William Killgoar

Maine Public Advocate Officer End User Paul Peterson

Maine Skiing, Inc. End User Donald J. Sipe

Mansfield Municipal Electric Department Publicly Owned Gary Will

Marblehead Municipal Light Department Publicly Owned Gary Will

Marble River, LLC Supplier Steve Garwood (tel)

Massachusetts Attorney General's Office End User Fred Plett Christina Belew

NEPOOL PARTICIPANTS COMMITTEE MEETINGAPR 10, 2015 MEETING, AGENDA ITEM #1

Marked to Show Changes from Draft Circulated 3/27/2015ATTACHMENT 1

MEMBERS AND ALTERNATES PARTICIPATING INMARCH 6, 2015 PARTICIPANTS COMMITTEE MEETING

PARTICIPANT NAME SECTOR/GROUP MEMBER NAMEALTERNATE

NAMEPROXY

Mass. Municipal Wholesale Electric Company Publicly Owned Gary Will

Middleborough Gas and Electric Department Publicly Owned Gary Will

National Grid Transmission Tim Brennan Tim Martin

New Hampshire Electric Cooperative, Inc. Publicly Owned Brian Forshaw

New Hampshire Office of Consumer Advocate End User Paul Peterson Sarah Jackson

NextEra Energy Resources, LLC Generation Michelle Gardner

Noble Americas Gas & Power Corp. Supplier Becky Merola (tel)

NRG Power Marketing, Inc. Generation Dave Cavanaugh

Paxton Municipal Light Department Publicly Owned Gary Will

Peabody Municipal Light Plant Publicly Owned Gary Will

PowerOptions, Inc. End User Cindy Arcate (tel)

Princeton Municipal Light Department Publicly Owned Gary Will

PSEG Energy Resources & Trade LLC Supplier Joel Gordon

Repsol Energy North America Supplier Sam Moreton (tel) Nancy Chafetz

Russell Municipal Light Dept Publicly Owned Gary Will

Shrewsbury Electric & Cable Operations Publicly Owned Gary Will

Small LR Group Member AR Doug Hurley

Small RG Group Member AR Erik Abend (tel)

South Hadley Electric Light Department Publicly Owned Gary Will

Sterling Municipal Electric Light Department Publicly Owned Gary Will

SunEdison (First Wind Energy Marketing) AR John Keene Robert Stein

Tangent Energy Solutions, Inc. Provisional Group Brad Swalwell (tel)

Templeton Municipal Lighting Plant Publicly Owned Gary Will

The Energy Consortium End User Mary Smith

TransCanada Power Marketing Ltd. Generation Mike Hachey (tel)

United Illuminating Company (UI) Transmission Alan Trotta

Utility Services Inc. End User Paul Peterson

Vermont Electric Cooperative Publicly Owned Craig Kieny (tel)

Vermont Electric Power Company, Inc. Transmission Frank Ettori Marc Sciarotta

Vermont Energy Investment Corporation AR Doug Hurley

Vermont Public Power Supply Authority Publicly Owned David Mullett

Vitol Inc. SupplierJoseph Wadsworth(tel)

Wakefield Municipal Gas and Light Department Publicly Owned Gary Will

West Boylston Municipal Lighting Plant Publicly Owned Gary Will

Westfield Gas & Electric Department Publicly Owned Gary Will


CONSENT AGENDA

From the notice of actions of the March 17, 2015 Reliability Committee1 meeting, dated March 17, 2015,which has been previously circulated:

1. Revisions to OP-23 Appendix G (Testing Date, Unit Listing, and REMVEC/NGRID Table Titlechanges)

Support revisions to Operating Procedure No. 23 Appendix G (Generators Required toPerform Reactive Capability Testing), which modify testing dates, add and removeunits at the request of the Voltage Task Force, and change the title of Table 5 (toREMVEC/NGRID), as recommended by the Reliability Committee at its March 17, 2015meeting, with such further non-substantive changes as the Chair and Vice-Chair of theReliability Committee may approve.

The motion to recommend Participants Committee support was approved unanimously.

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

Summary of ISO New England Board and Committee Meetings

April 10, 2015 Participants Committee Meeting

Since the last Participants Committee meeting, the Audit and Finance Committee, the Compensation and

Human Resources Committee, the Nominating and Governance Committee, the Markets Committee, and the

Board of Directors each met in Holyoke on March 19.

The Audit and Finance Committee was presented with the 2015 audit plan. The Committee discussed

the major areas of coverage, including cyber security, hourly offers, reliability standards, and local control

center reviews. Next, the Committee received an update on current Internal Audit Department activities

and the risks and outcomes pertaining to Internal Audit’s work. The Committee discussed audit ratings,

their meanings and the best way to convey audit results. The Committee also discussed the performance

and cost effectiveness of the Company’s external auditors. Following this discussion, the Committee

approved the 2015 audit plan. The Committee also approved the appointment of KPMG as auditor of the

Company’s financial statements and to conduct the Service Organization Controls engagement, and

approved Meyers Brothers Kalicka as auditor of the Company’s benefit plans. Next, the Committee met

with representatives from KPMG and reviewed the objectives for the 2015 Service Organization Controls

report. The Committee discussed the scope of the report, including objectives, audit team and

methodology. KPMG and management reviewed the 2014 audited financial statements with the

Committee and discussed disclosure controls. The Committee then held an executive session with KPMG.

Following the executive session, the Committee voted to recommend the adoption of the audited financial

statements by the Board of Directors. Next, the Committee reviewed the Company’s cyber security plan,

including the timeline, funding, and design of the plan. The Committee discussed the significant elements

of the plan and how management intends to prioritize and address the various elements. The Committee

received a status update on financial performance against the 2015 budget, and also conducted its biennial

review of the committee charter to confirm compliance. The Committee agreed that the charter was

accurate and that the Committee is in compliance with its terms. Finally, the Committee discussed the

Company’s rules prohibiting directors and employees from investing in securities of market participants,

and the changes recently made to similar rules by other independent system operators and regional

transmission organizations. The Committee agreed not to pursue changes to the Company’s rules at this

time, and to reconsider the issue in the future.

The Compensation and Human Resources Committee discussed a report benchmarking certain of the

Company’s benefits against other independent system operators and regional transmission organizations as

well as non-profit and for-profit companies.


Add'l Materials Circulated 4/8/15

2

The Nominating and Governance Committee considered the 2015 evaluation process for the Board and

Committees and the use of facilitated evaluations. The Committee also discussed director succession

planning and board succession trends. The Committee reviewed the important factors to consider in

succession planning, including committee membership composition, retirements and timing of vacancies,

and requisite areas of board expertise.

The Markets Committee received reports on market monitoring, mitigation and reliability costs,

including the External Market Monitor’s quarterly report on market performance. The Committee

discussed the amount of load cleared in the day-ahead market, reviewed changes in the payment of Net

Commitment Period Compensation that took place during the month, and also discussed the premium that

New England is paying for gas-fired electricity compared to other areas. The Committee reviewed the

Company’s draft contingency plan options for demand response in light of the Court of Appeals decision

vacating Order 745 and finding that the Federal Energy Regulatory Commission lacked jurisdiction over

demand response in certain circumstances. The Committee noted that the various options will be

discussed with stakeholders in the NEPOOL stakeholder process. Finally, the Committee received an

overview of the Company’s plans to address price formation issues, and discussed stakeholders’ interests

and varying incentives along with the Federal Energy Regulatory Commission’s process for considering

the issues.

The Board of Directors received reports from the standing committees and the Chief Executive Officer.

During the committee reports, the Board approved the 2014 audited financial statements and discussed the

evaluation process for board and committee evaluations. The Board then reviewed various issues

concerning capacity zone formation, show of interest, and zonal pricing related to Forward Capacity

Auction #10.



A P R I L 1 0 , 2 0 1 5 | 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

April 2015

NEPOOL Participants Committee Report

NEPOOL PARTICIPANTS COMMITTEE MEETING 04/10/15 MEETING, AGENDA ITEM #4

2

Table of Contents • Highlights Page 3

• System Operations Page 9

• Market Operations Page 20

• Back-Up Detail Page 37

– Load Response Page 38 – New Generation Page 40 – Forward Capacity Market Page 47 – Reliability Costs - Net Commitment Period

Compensation (NCPC) Operating Costs Page 54 – Regional System Plan (RSP) & Interregional Planning Page 85 – Operable Capacity Analysis – Spring 2015 Page 115 – Operable Capacity Analysis – Preliminary

Summer 2015 Page 122 – Operable Capacity Analysis – Appendix Page 129

Highlights

• Day-Ahead (DA), Real-Time (RT) Prices and Transactions

– Energy Market Value was $734M over the period, down $660M from February 2015 and down $584M from March 2014

– March natural gas prices over the period were 53% lower than February 2015 average values

– Average RT Hub Locational Marginal Prices (LMPs) over the period were 54% lower than February 2015 averages

– Average March 2015 natural gas prices and RT Hub LMPs over the period were down 48% and 50%, respectively, from March 2014 averages

• Average DA cleared physical energy in the peak hours as percent of forecasted load was 99.9% during March, up from 99.4% during February

3

Underlying natural gas data furnished by:

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

http://www.theice.com/

Highlights, cont.

• Daily Net Commitment Period Compensation (NCPC)*

– March NCPC payments totaled $14.8M, up $3.5M from February and down $3.3M from March 2014

– First Contingency payments totaled $9.5M, up $271K from February

• $8.9M paid to internal resources, up $207K from February

– $993K charged to DALO, $7.9M to RT Deviations

• $522K paid to resources at external locations, up $65K from February

– $483K charged to DALO at external locations, $39K to RT Deviations

– Second Contingency payments totaled $4.9M, up $4.1M from the February total of $865K

– Voltage payments were $448K, down $833K from February

– NCPC payments over the period as percent of Energy Market value were 2.0%

4

Highlights, cont.

5

• ISO received three economic study requests that will be discussed with the PAC on April 22

• ISO will be discussing the final PV forecast with the DGFWG on April 14

• FERC issued its final order on ISO’s Order 1000 compliance filing on March 19. The new intraregional planning process will become effective on May 18, 2015, which is the same date for an additional compliance filing.

Forward Capacity Market (FCM) Highlights

6

CCP – Capacity Commitment Period

• CCP #4 (2013-2014) – Less than 10 MW of resources are non-commercial at this time.

Discussions with the affected project sponsors have begun and will likely result in self-withdrawal.

• CCP #5 (2014-2015) – Approximately 60 MW of resources are non-commercial at this

time but progress continues

• CCP #6 (2015-2016) – Entering the CCP, the Transmission Security Analysis margin for

NEMA/Boston will be about 211 MW short

• CCP #7 (2016-2017) – Next bilateral transaction window is May 1-7 – Second reconfiguration auction will be held August 3-5

FCM Highlights, cont.

7

• CCP #8 (2017-2018) – First bilateral transaction window is April 1-8 – First reconfiguration auction will be held June 1-3

• CCP #9 (2018-2019) – First bilateral transaction window is April 2016

• CCP #10 (2019-2020) – Potential new capacity zones filed with FERC on April 6 – Upcoming Deadlines

• De-list bids are due by the Existing Resource Qualification Deadline of June 1

• Non-Price Retirement window opens on June 1 • New resource qualification packages are due June 16

Highlights, cont.

• The lowest 50/50 Spring Operable Capacity Margin is projected for week beginning May 9, 2015.

• The lowest 90/10 Spring Operable Capacity Margin is projected for week beginning May 23, 2015.

• The lowest 50/50 and 90/10 Summer Operable Capacity Margin is projected for week beginning May 30, 2015.

8

SYSTEM OPERATIONS

System Operations Weather Patterns

Boston Temperature – Below normal (-6.6) Max: 57, Min: 9 Precipitation 3.03” - Below Normal Normal - 3.85” Total Snowfall – 19.57”

Hartford Temperature – Below normal ( -6.5) Max: 57 , Min: 2

Precipitation 2.61” - Below Normal Normal – 3.88”

Total Snowfall – 14.02”

10

Peak Load: 18,863 MW March 05, 2015 19:00

MLCC2: None

OP-4 : None

NPCC Simultaneous Activation of Reserve Events:

3/10/15 IESO 525 MW

System Operations, cont.

11

Minimum Generation Warnings & Events:

Minimum Generation Warning 03/05/15 Start – 01:00, Expired – 19:00 Interchange Cuts Only

Minimum Generation Warning 03/10/15 Start – 23:00, Expired – 23:59 Interchange Cuts Only

12

0.0

2.0

4.0

6.0

8.0

10.0

J F M A M J J A S O N D Cum. Avg

% E

rro

r

All Hours Monthly Average, Daily Maximum and Minimum,

Based on forecast published by 1000 on day before Operating Day

Mo. Avg Day Max Day Min Summer Goal Rest of Year Goal

2015 System Operations – Load Forecast Accuracy Dashboard

Indicator

J F M A M J J A S O N D Avg

Mo Avg 1.70 1.31 1.37 1.47

Day Max 5.66 3.47 3.35 4.18

Day Min 0.65 0.57 0.44 0.55

Summer Goal 2.6 2.6 2.6

Rest of Year Goal 1.50 1.50 1.50 1.50 1.50 1.50 1.50 1.50 1.50

Rest of year Actual 1.70 1.31 1.37 1.47

Summer Actual

Rest of Year Goal < 1.5%

Summer Goal < 2.6%

Sponsor - John Norden Contact – William Callan

Summer Goal - 2.6%, Rest of Year Goal - 1.5%

Summer consists of June, July & August

13

0.0

2.0

4.0

6.0

8.0

10.0

12.0

J F M A M J J A S O N D Cum. Avg

% E

rro

r

Peak Hours Monthly Average, Daily Maximum and Minimum

Based on forecast published by 1000 on day before Operating Day

Mo. Avg Day Max Day Min Summer Goal Rest of Year Goal

2015 System Operations - Load Forecast Accuracy cont. Dashboard

Indicator

Rest of Year Goal < 1.5%

Summer Goal < 2.6%

Summer Goal - 2.6%, Rest of Year Goal - 1.5%

Summer consists of June, July & August

J F M A M J J A S O N D Avg

Mo Avg 1.75 1.28 1.36 1.47

Day Max 6.13 3.41 4.31 4.66

Day Min 0.00 0.08 0.00 0.02

Summer Goal 2.6 2.6 2.6

Rest of Year Goal 1.50 1.50 1.50 1.50 1.50 1.50 1.50 1.50 1.50

Rest of year Actual 1.75 1.28 1.36 1.47

Summer Actual

14

20

30

40

50

60

70

J F M A M J J A S O N D Cum.

Avg

% E

rro

r

Percent of Hours Actual Load Above vs. Below Forecast

Based on LF published by 1000, day before Operating Day

Above Below

2015 System Operations - Load Forecast Accuracy

Target = 50%

Plus/Minus 5%

Percent of hours that the actual load was above versus below the forecast Sponsor –John Norden Contact –William Callan

15

2015 System Operations - Load Forecast Accuracy

Sponsor –John Norden Contact – William Callan

GR:wnnel GR:nel

Ann Tot (TWh): 128.2 127.8 127.1 21.8

Weather Normalized NEL

2012 2013 2014 2015G

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): 128.1 129.4 127.1 33.6

Net Energy for Load (NEL)

2012 2013 2014 2015

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

16

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.

GR:SeasonalPeak GR:PeakEnergy

Weather Normalized Seasonal Peaks

Winter beginning in year displayed

Summer WinterM

W

20,000

21,000

22,000

23,000

24,000

25,000

26,000

27,000

28,000

29,000

30,000

20032004 2005 20062007 2008 2009 20102011 2012 20132014 2015

System Peak Load

2012 2013 2014 2015

MW

15,000

16,000

17,000

18,000

19,000

20,000

21,000

22,000

23,000

24,000

25,000

26,000

27,000

28,000


Monthly Peak Loads and Weather Normalized Seasonal Peak History

17

F – designates forecasted values, which are updated in April/May of the following year; represents “gross forecast”

F

10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 1601680

5

10

15

20

25

30

35

40

45

50

Horizon [Hours Ahead]

Mean A

bsolu

te E

rror

[%]

Rolling 30-day MAE for ISO Wind Power Forecast, as of April 1, 2015

Individual Wind Plants

Fleet

Wind Power Forecast Error Statistics: 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/GH forecast is very good compared to industry standards, and MAE continues to be well within the yearly performance targets specified in the forecast RFP.

Dashboard Indicator

Yearly Fleet Performance targets

18

10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160168-30

-20

-10

0

10

20

30

Horizon [Hours Ahead]

Bia

s E

rror

[%]

Rolling 30-day Bias for ISO Wind Power Forecast, as of April 1, 2015

Individual Wind Plants

Fleet

Wind Power Forecast Error Statistics: 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/GH forecast is very good compared to industry standards, and monthly values for March are near yearly performance targets specified in the forecast RFP. Some bias corrections applied in mid-March are not visible.

Yearly Fleet Performance targets

19

MARKET OPERATIONS

GR:Hubwgas

Ele

ctri

city

Pri

ces

($/M

Wh

)

$0.00

$50.00

$100.00

$150.00

$200.00

$250.0003/

01/1

503/

03/1

503/

05/1

503/

07/1

503/

09/1

503/

11/1

503/

13/1

503/

15/1

503/

17/1

503/

19/1

503/

21/1

503/

23/1

503/

25/1

503/

27/1

503/

29/1

503/

31/1

5

Fue

l Pri

ce (

$/M

MB

tu)

$0.00

$7.00

$14.00

$21.00

$28.00

$35.00

Gas price is average of Massachusetts delivery pointsAverage percentage difference over this period ABS(DA-RT)/RT Average LMP: 21%

Average price difference over this period ABS(DA-RT): $12.16Average price difference over this period (DA-RT): $6.31

RT LMP DA LMP Natural Gas

Daily DA and RT ISO-NE Hub Prices and Input Fuel Prices: March 1-31, 2015

21



GR:DA_Bar

LMP Congestion Marginal Losses

$/M

Wh

$-20

$0

$20

$40

$60

$80

$100

$120

$140

Hub ME NH VT CT RI SEMA WCMA NEMA

( 2.8%) 0.5% ( 4.7%) ( 5.5%) 1.8% 3.3% ( 0.6%) 3.2%

DA LMPs Average by Zone & Hub, March 2015

22

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

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

GR:RT_Bar

LMP Congestion Marginal Losses

$/M

Wh

$-20

$0

$20

$40

$60

$80

$100

$120

$140


( 4.6%) ( 2.1%) ( 3.2%) ( 3.4%) ( 0.3%) 0.2% ( 0.8%) 0.7%

RT LMPs Average by Zone & Hub, March 2015

23

Definitions

24

Day-Ahead Concept Definition

Day-Ahead Load Obligation (DALO) The sum of day-ahead cleared load

(including pump load), exports, and virtual purchases (excluding bulk losses)

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

and cleared net imports

GR:Graph36R GR:Graph36L

Fixed Dem PrSens Dem Decs

Losses Exports

Avg

Ho

url

y M

W 0

2,500

5,000

7,500

10,000

12,500

15,000

17,500

20,000

22,500

JAN2015 FEB2015 MAR2015

Gen Imports

Incs

Avg

Ho

url

y M

W

0

2,500

5,000

7,500

10,000

12,500

15,000

17,500

20,000

22,500

JAN2015 FEB2015 MAR2015

Components of Cleared DA Supply and Demand – Last Three Months

25

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

GR:Graph37R GR:Graph37L

Load Exports

Avg

Ho

url

y M

W 0

2,500

5,000

7,500

10,000

12,500

15,000

17,500

20,000

22,500

JAN2015 FEB2015 MAR2015

Gen Imports

Avg

Ho

url

y M

W

0

2,500

5,000

7,500

10,000

12,500

15,000

17,500

20,000

22,500

JAN2015 FEB2015 MAR2015

Components of RT Supply and Demand – Last Three Months

26

Supply

DA Fcst Load

Demand

DAM Volumes vs. RT Actual Load (at Peak Hour): Monthly and Daily

27

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.

60%

70%

80%

90%

100%

110%

120%

130%

140%

Ma

r-1

4

Ap

r-1

4

Ma

y-1

4

Jun

-14

Jul-

14

Au

g-1

4

Se

p-1

4

Oc

t-1

4

No

v-1

4

De

c-1

4

Jan

-15

Fe

b-1

5

Ma

r-1

5

% o

f R

T A

ctu

al L

oa

d

DA Bid Fixed DA Bid Price

DALO DA Phys Clrd Energy

100%

60%

70%

80%

90%

100%

110%

120%

130%

140%

1-M

ar

2-M

ar

3-M

ar

4-M

ar

5-M

ar

6-M

ar

7-M

ar

8-M

ar

9-M

ar

10

-Ma

r1

1-M

ar

12

-Ma

r1

3-M

ar

14

-Ma

r1

5-M

ar

16

-Ma

r1

7-M

ar

18

-Ma

r1

9-M

ar

20

-Ma

r2

1-M

ar

22

-Ma

r2

3-M

ar

24

-Ma

r2

5-M

ar

26

-Ma

r2

7-M

ar

28

-Ma

r2

9-M

ar

30

-Ma

r3

1-M

ar

% o

f A

ctu

al R

T L

oa

d

DA Bid Fixed DA Bid PriceDALO DA Phys Clrd Energy100%

GR:Graph26 GR:Graph27

DA

% o

f R

T

96.0% 96.2%

96.4% 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%

MAR20

14APR2

014M

AY201

4JU

N20

14JU

L201

4AU

G20

14SE

P201

4O

CT201

4N

OV20

14D

EC20

14JA

N20

15FE

B2015

MAR20

15

Monthly, Last 13 Months

DA

% o

f R

T

92%

93%

94%

95%

96%

97%

98%

99%

100%

101%

102%

3/ 1

3/ 2

3/ 3

3/ 4

3/ 5

3/ 6

3/ 7

3/ 8

3/ 9

3/10

3/11

3/12

3/13

3/14

3/15

3/16

3/17

3/18

3/19

3/20

3/21

3/22

3/23

3/24

3/25

3/26

3/27

3/28

3/29

3/30

3/31

Daily, This Year vs. Last Year

Last_Year This_Year

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

28

*Hourly average values

GR:dapce_dalo_pct_fxlo_fpk_dly_small GR:dapce_dalo_pct_fxlo_fpk_mly_small

Perc

enta

ge o

f Pea

k Fo

reca

st L

oad

80.0%

84.0%

88.0%

92.0%

96.0%

100%

104%

108%

112%

01MAR15

02MAR15

03MAR15

04MAR15

05MAR15

06MAR15

07MAR15

08MAR15

09MAR15

10MAR15

11MAR15

12MAR15

13MAR15

14MAR15

15MAR15

16MAR15

17MAR15

18MAR15

19MAR15

20MAR15

21MAR15

22MAR15

23MAR15

24MAR15

25MAR15

26MAR15

27MAR15

28MAR15

29MAR15

30MAR15

31MAR15

Daily: This Month

DA Cleared Physical Energy DALO100% line

Perc

enta

ge o

f Pea

k Fo

reca

st L

oad

92.0%

94.0%

96.0%

98.0%

100%

102%

104%

MAR2014

APR2014

MAY2014

JUN2014

JUL2

014

AUG2014

SEP2014

OCT2014

NOV2014

DEC2014

JAN2015

FEB2015

MAR2015


DA Cleared Physical Energy DALO100% line

DA Volumes as % of Forecast (Peak Hour)

29

*Forecasted peak hour is reflected.

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

01MAR20

1502M

AR2015

03MAR20

1504M

AR2015

05MAR20

1506M

AR2015

07MAR20

1508M

AR2015

09MAR20

1510M

AR2015

11MAR20

1512M

AR2015

13MAR20

1514M

AR2015

15MAR20

1516M

AR2015

17MAR20

1518M

AR2015

19MAR20

1520M

AR2015

21MAR20

1522M

AR2015

23MAR20

1524M

AR2015

25MAR20

1526M

AR2015

27MAR20

1528M

AR2015

29MAR20

1530M

AR2015

31MAR20

15

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

30

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

DA

Hig

he

r

DA

Low

er

GR:Graph32 GR:Graph33

Ne

t M

Wh

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

01

MA

R1

40

2M

AR

14

03

MA

R1

40

4M

AR

14

05

MA

R1

40

6M

AR

14

07

MA

R1

40

8M

AR

14

09

MA

R1

41

0M

AR

14

11

MA

R1

41

2M

AR

14

13

MA

R1

41

4M

AR

14

15

MA

R1

41

6M

AR

14

17

MA

R1

41

8M

AR

14

19

MA

R1

42

0M

AR

14

21

MA

R1

42

2M

AR

14

23

MA

R1

42

4M

AR

14

25

MA

R1

42

6M

AR

14

27

MA

R1

42

8M

AR

14

29

MA

R1

43

0M

AR

14

31

MA

R1

4

Hourly Average by Day, Last Year

Day-Ahead Real-Time

Ne

t M

Wh

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

01

MA

R1

50

2M

AR

15

03

MA

R1

50

4M

AR

15

05

MA

R1

50

6M

AR

15

07

MA

R1

50

8M

AR

15

09

MA

R1

51

0M

AR

15

11

MA

R1

51

2M

AR

15

13

MA

R1

51

4M

AR

15

15

MA

R1

51

6M

AR

15

17

MA

R1

51

8M

AR

15

19

MA

R1

52

0M

AR

15

21

MA

R1

52

2M

AR

15

23

MA

R1

52

4M

AR

15

25

MA

R1

52

6M

AR

15

27

MA

R1

52

8M

AR

15

29

MA

R1

53

0M

AR

15

31

MA

R1

5

Hourly Average by Day, This Year

Day-Ahead Real-Time

DA vs. RT Net Interchange March 2015 vs. March 2014

31

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

GR:Var_Cost_Gas_Mly

$0

$40

$80

$120

$160

$200

MAR20

13APR

2013

MAY2

013

JUN

2013

JUL2

013

AUG20

13SE

P201

3O

CT20

13N

OV20

13DEC

2013

JAN

2014

FEB20

14M

AR2014

APR20

14M

AY201

4JU

N20

14JU

L201

4AU

G2014

SEP2

014

OCT

2014

NO

V2014

DEC20

14JA

N20

15FE

B2015

MAR20

15

Var Cost Gas

Variable Production Cost of Natural Gas: Monthly

32

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

GR:Var_Cost_Gas_Dly

$0

$40

$80

$120

$160

$200

$240

01M

AR2015

02M

AR2015

03M

AR2015

04M

AR2015

05M

AR2015

06M

AR2015

07M

AR2015

08M

AR2015

09M

AR2015

10M

AR2015

11M

AR2015

12M

AR2015

13M

AR2015

14M

AR2015

15M

AR2015

16M

AR2015

17M

AR2015

18M

AR2015

19M

AR2015

20M

AR2015

21M

AR2015

22M

AR2015

23M

AR2015

24M

AR2015

25M

AR2015

26M

AR2015

27M

AR2015

28M

AR2015

29M

AR2015

30M

AR2015

31M

AR2015

Var Cost Gas

Variable Production Cost of Natural Gas: Daily

33

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

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 27 28 29 30 31 **

Hourly Day-Ahead LMPs

Hub ME NH VT CTRI SEMA NEMA WCMA

Hourly DA LMPs, March 1-31, 2015

34

Binding constraints on the Lower Southeastern Massachusetts/Eastern Rhode Island Import Interface due to a planned outage

Binding constraint on the New England West-East Interface due to the planned outages of the 301 (Ludlow-Carpenter Hill) and 302 (Millbury-Carpenter Hill) lines

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 27 28 29 30 31 **

Hourly Real-Time LMPs

Hub ME NH VT CTRI SEMA NEMA WCMA

Hourly RT LMPs, March 1-31, 2015

35

Negative system pricing on March 10, 12, 24, and 29; not Min Gen Emergencies

Binding constraint on the Seabrook-South Interface due to the planned outage of the 326-2 (Lawrence-Sandy Pond) line

Multiple binding constraints resulting from the aforementioned 301 and 302 line outages

System Unit Availability

36

Data as of 4/6/15

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

2015 97 89 88 91

2014 87 92 84 76 77 95 96 95 93 81 82 95 88

2013 89 87 85 76 81 90 90 92 88 80 81 92 86

2012 93 92 88 75 83 93 95 95 91 76 80 89 88

60

65

70

75

80

85

90

95

100

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

Syste

m W

EA

FAnnual/Monthly Weighted Equivalent Availability Factor (WEAF)

2013 2014 2015

BACK-UP DETAIL

LOAD RESPONSE

Capacity Supply Obligation (CSO) MW by Demand Resource Type for April 2015

39

* Real Time Demand Response

** Real Time Emergency Generation

NOTE: CSO values include T&D loss factor (8%) and, as applicable, a reserve margin gross-up of

either 14.3% or 16.1%, respectively, for portions of resources that selected a multi-year obligation

in the FCA 1 or FCA 2. Otherwise, reserve margin gross-ups were discontinued with FCA 3.

Load Zone RTDR* RTEG** On Peak

Seasonal

Peak Total

ME 113.6 3.8 103.1 0.0 220.5

NH 8.2 14.3 69.9 0.0 92.4

VT 27.4 3.0 94.2 0.0 124.6

CT 84.6 73.1 77.5 312.3 547.4

RI 13.5 13.8 83.5 0.0 110.8

SEMA 11.1 9.5 157.7 0.0 178.3

WCMA 26.2 19.9 140.4 34.9 221.3

NEMA 34.2 3.5 307.5 0.0 345.1

Total 318.8 140.9 1,033.6 347.2 1,840.4

NEW GENERATION

New Generation Update Based on 3/1/15 Queue Update

• Five new projects, with a total rating of 376 MW, have applied for interconnection study since the last update

• The new projects consist of two new combustion turbines, one new wind facility, one upgrade to an existing hydro station, and one upgrade to an existing combined cycle plant. The expected in-service dates range from 2015 to 2019.

• One project went commercial and two projects withdrew from the Queue, resulting in a net increase in new generation projects of 83 MW

• In total, 79 generation projects are currently being tracked by the ISO, totaling approximately 11,300 MW

41

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

• 2015 values include the 27 MW of generation that has gone commercial in 2015 •DR reflects changes from the initial FCM Capacity Supply Obligations in 2010-11

42

-1,000

-500

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

2015 2016 2017 2018 2019 2020

Me

ga

wa

tts

(M

W)

Demand Response -Passive

Demand Reponse -Active

Wind/Other Renewables

Oil

Natural Gas/Oil

Natural Gas

2015 2016 2017 2018 2019 2020Total

MW

% of

Total1

Demand Response - Passive 157 -12 330 196 0 0 670 6.3

Demand Response - Active 3 -868 -37 -433 0 0 -1,335 -12.5

Wind & Other Renewables 77 620 1,309 458 1,029 698 4,191 39.3

Oil 0 0 0 0 0 0 0 0.0

Natural Gas/Oil2 0 10 567 2,208 1,469 0 4,254 39.9

Natural Gas 180 135 745 728 1,093 0 2,881 27.0

Totals 417 -115 2,914 3,157 3,591 698 10,661 100.01 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

Actual and Projected Annual Generator Capacity Additions By State

43

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

2015 2016 2017 2018 2019 2020

Me

ga

wa

tts

(M

W)

Vermont

Rhode Island

New Hampshire

Maine

Massachusetts

Connecticut

2015 2016 2017 2018 2019 2020Total

MW

% of

Total1

Vermont 3 58 0 0 30 97 188 1.7

Rhode Island 27 51 0 0 1,661 0 1,739 15.4

New Hampshire 81 0 79 0 0 0 160 1.4

Maine 52 490 726 488 999 601 3,356 29.6

Massachusetts 10 65 1,816 1,267 838 0 3,996 35.3

Connecticut 84 101 0 1,639 63 0 1,887 16.7

Totals 257 765 2,621 3,394 3,591 698 11,326 100.01 Sum may not equal 100% due to rounding

• 2015 values include the 27 MW of generation that has gone commercial in 2015

New Generation Projection By Fuel Type

•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

44

Fuel Type

No. of

Projects

Capacity

(MW)

No. of

Projects

Capacity

(MW)

No. of

Projects

Capacity

(MW)

Biomass/Wood Waste 2 70 0 0 2 70

Hydro 6 38 0 0 6 38

Landfill Gas 0 0 0 0 0 0

Natural Gas 17 2,854 0 0 17 2,854

Natural Gas/Oil 17 4,254 0 0 17 4,254

Oil 0 0 0 0 0 0

Solar 1 10 1 10 0 0

Wind 36 4,073 6 294 30 3,779

Total 79 11,299 7 304 72 10,995

Total Green Yellow

New Generation Projection By Operating Type

• 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

45

Operating Type

No. of

Projects

Capacity

(MW)

No. of

Projects

Capacity

(MW)

No. of

Projects

Capacity

(MW)

Baseload 3 133 0 0 3 133

Intermediate 26 5,465 0 0 26 5,465

Peaker 14 1,628 1 10 13 1,618

Wind Turbine 36 4,073 6 294 30 3,779

Total 79 11,299 7 304 72 10,995

Total Green Yellow

New Generation Projection By Operating Type and Fuel Type

46

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

Fuel Type

No. of

Projects

Capacity

(MW)

No. of

Projects

Capacity

(MW)

No. of

Projects

Capacity

(MW)

No. of

Projects

Capacity

(MW)

No. of

Projects

Capacity

(MW)

Biomass/Wood Waste 2 70 2 70 0 0 0 0 0 0

Hydro 6 38 0 0 5 13 1 25 0 0

Landfill Gas 0 0 0 0 0 0 0 0 0 0

Natural Gas 17 2,854 1 63 13 2,700 3 91 0 0

Natural Gas/Oil 17 4,254 0 0 8 2,752 9 1,502 0 0

Oil 0 0 0 0 0 0 0 0 0 0

Solar 1 10 0 0 0 0 1 10 0 0

Wind 36 4,073 0 0 0 0 0 0 36 4,073

Total 79 11,299 3 133 26 5,465 14 1,628 36 4,073

Wind TurbineBaseload Intermediate PeakerTotal

FORWARD CAPACITY MARKET

Capacity Supply Obligation FCA 5

48

* 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 2 ARA 2 Annual Bilateral for ARA 3 ARA 3

*CSO CSO **Change ARA 2 Change CSO Change CSO Change CSO Change

MW MW MW MW MW MW MW MW MW MW MW

Demand

Active Demand 2,104.14 2,001.13 -103.02 1,385.67 -615.46 1,074.46 -311.21 899.13 -175.34 699.93 -199.20

Passive

Demand 1,485.71 1,397.59 -88.13 1,345.28 -52.30 1,348.59 3.31 1,365.95 17.35 1,399.56 33.62

Demand Total 3,589.85 3,398.71 -191.14 2,730.95 -667.76 2,423.05 -307.90 2,265.07 -157.98 2,099.49 -165.58

Generator

Non-

Intermittent 30,558.22 28,337.48 -2,220.74 27,917.69 -419.79 28,364.59 446.90 28,517.10 152.51 28,557.86 40.76

Intermittent 880.737 827.804 -52.933 778.165 -49.639 795.545 17.38 795.767 0.222 718.908 -76.859

Generator Total 31,438.96 29,165.29 -2,273.67 28,695.86 -469.43 29,160.13 464.28 29,312.86 152.73 29,276.76 -36.10

Import Total 2,011.00 1,831.37 -179.63 1,831.37 0.00 1,635.84 -195.54 1,635.84 0.00 1,382.55 -253.28

***Grand Total 37,039.81 34,395.37 -2,644.44 33,258.18 -1,137.19 33,219.02 -39.16 33,213.77 -5.25 32,758.81 -454.96

Net ICR (NICR) 33,200 33,200 0 33,200 0 32,209 -991 32,209 0 32,588 379


49

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 Chan

ge 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





50

Resource

Type Resource Type

FCA Proration Annual Bilateral for

ARA 1 ARA 1



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

Passive Demand 1,631.335 1,519.740 -111.595 1,519.311 -0.43 1,543.793 24.482

Demand Total 2,748.033 2,563.459 -184.574 2,463.581 -99.88 2,476.514 12.933

Generator

Non-

Intermittent 30,704.578 28,146.837 -2,557.741 28,127.044 -19.79 28,523.002 395.958

Intermittent 936.913 893.710 -43.203 903.244 9.53 913.083 9.839

Generator Total 31,641.491 29,040.547 -2,600.944 29,030.288 -10.26 29,436.085 405.797

Import Total 1,830.000 1,606.862 -223.138 1,606.862 0.00 1,616.401 9.539

***Grand Total 36,219.524 33,210.868 -3,008.656 33,100.731 -110.14 33,529.000 428.269

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

33,529

561

33,529

0





51

Resource

Type Resource Type

FCA Annual Bilateral

for ARA 1 ARA 1



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

Passive Demand 1,960.517

Demand Total 3,040.596

Generator

Non-

Intermittent 28,547.813

Intermittent 876.925

Generator Total 29,424.738

Import Total 1,237.034

***Grand Total 33,702.368

Net ICR (NICR) 33,855





52

Resource

Type Resource Type

FCA Annual Bilateral

for ARA 1 ARA 1



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 647.26

Passive Demand 2,156.151

Demand Total 2,803.411

Generator

Non-

Intermittent 29,550.564

Intermittent 891.616

Generator Total 30,442.18

Import Total 1,449

***Grand Total 34,694.591

Net ICR (NICR) 34,189




Active/Passive Demand Response CSO Totals by Commitment Period

53

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

Passive 719.98 263.25 983.23

Grand Total 2488.372 448.24 2936.612

2012-13

Active 1726.548 98.227 1824.775

Passive 861.602 211.261 1072.863

Grand Total 2588.15 309.488 2897.638

2013-14

Active 1794.195 257.341 2051.536

Passive 1040.113 257.793 1297.906

Grand Total 2834.308 515.134 3349.442

2014-15

Active 2062.196 41.945 2104.141

Passive 1264.641 221.072 1485.713

Grand Total 3326.837 263.017 3589.854

2015-16

Active 1935.406 66.104 2001.51

Passive 1395.885 247.449 1643.334

Grand Total 3331.291 313.553 3644.844

2016-17

Active 1116.468 0.23 1116.698

Passive 1386.56 244.775 1631.335

Grand Total 2503.028 245.005 2748.033

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

Passive 1870.549 285.602 2156.151

Grand Total 2436.415 366.996 2803.411

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

What are Daily NCPC Payments?

• “Make-whole” payments made to resources whose hourly commitment and dispatch by ISO-NE resulted in a shortfall between the resource’s offered value in the Energy and Regulation Markets and the revenue earned from output over the course of the day

• Typically, this is the result of some out-of-merit operation of resources occurring in order to protect the overall resource adequacy and transmission security of specific locations or of the entire control area

55

Definitions

56

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

Delisted Units Resources within the control area that have requested to be classified as a non-installed capacity (ICAP) resource, and as such, are not required to offer their capacity into the DA Energy Market

OATT Open Access Transmission Tariff

Charge Allocation Key

57

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, Min Generation Emergency, and Generator and DARD NCPC

GR:Graph23 GR:Graph23m NCPC Dollars

2012 2013

2014 2015

Mill

ion

s

$0

$10

$20

$30

$40

$50

$60

$70

$80


NCPC Energy*

2012 2013

2014 2015

GW

h

0

100

200

300

400

500

600

700

800

900


Year-Over-Year Total NCPC Dollars and Energy

58

* 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.

GR:Graph01 GR:Graph02 MAR-15 Total = $14.82 M

Day-Ahead Real-Time

24%

76%

Last 13 Months

Day-Ahead Real-Time

Mill

ion

s $0

$15

$30

$45

$60

$75

MAR20

14APR2

014M

AY201

4JU

N20

14JU

L201

4AU

G20

14SE

P201

4O

CT201

4N

OV20

14D

EC20

14JA

N20

15FE

B2015

MAR20

15

DA and RT NCPC Charges

59

GR:Graph04 GR:Graph03 MAR-15 Total = $14.82 M

1st C 2nd CVoltage

64%

33%

3%

NCPC Charges by Type

60

1st C – First Contingency

2nd C – Second Contingency

Distrib – Distribution

Voltage – Voltage

Last 13 Months

1st C 2nd CVoltage Distrib

Mill

ion

s $0

$15

$30

$45

$60

$75

MAR14

APR14

MAY1

4JU

N14

JUL1

4AU

G14

SEP1

4O

CT14

NO

V14D

EC14

JAN

15

FEB15

MAR15

GR:ncpc_bytype_stack_dly

1st C 2nd C Voltage

Mil

lio

ns

$0.0

$0.1

$0.2

$0.3

$0.4

$0.5

$0.6

$0.7

$0.8

$0.9

$1.0

$1.1

$1.2

$1.3

$1.4

$1.5

$1.6

$1.701M

AR2015

02MAR201

5

03MAR201

5

04MAR201

5

05MAR201

5

06MAR201

5

07MAR201

5

08MAR201

5

09MAR201

5

10MAR201

5

11MAR201

5

12MAR201

5

13MAR201

5

14MAR201

5

15MAR201

5

16MAR201

5

17MAR201

5

18MAR201

5

19MAR201

5

20MAR201

5

21MAR201

5

22MAR201

5

23MAR201

5

24MAR201

5

25MAR201

5

26MAR201

5

27MAR201

5

28MAR201

5

29MAR201

5

30MAR201

5

31MAR201

5

Daily NCPC Charges by Type

61

GR:xchart_ncpc_chgs_alloc_cat GR:xpie_ncpc_chgs_alloc_cat MAR-15 Total = $14.82 M

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

60%

3.3%33%

3.0%0.0%0.0%0.8%

NCPC Charges by Allocation

62

0.8%

0.8%

Last 13 Months

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

Mill

ion

s

$0.0

$8.0

$16.0

$24.0

$32.0

$40.0

MAR14

APR14

MAY1

4JU

N14

JUL1

4AU

G14

SEP1

4O

CT14

NO

V14D

EC14

JAN

15FE

B15M

AR15

GR:chart_firstc_rt_bydev_13mo GR:pie_firstc_rt_bydev MAR-15 Total = $7.99 M

Gen ImportInc Load

13.4%

10.7%10.9%

65.0%

RT First Contingency Charges by Deviation Type

63

Gen – Generator deviations

Inc – Increment Offer deviations

Imp – Import deviations

Load – Load obligation deviations

Last 13 Months

Gen ImportInc Load

Mill

ion

s $0

$1

$2

$3

$4

$5

$6

$7

$8

$9

$10

MAR14

APR14

MAY1

4JU

N14

JUL1

4AU

G14

SEP1

4O

CT14

NO

V14D

EC14

JAN

15FE

B15M

AR15

GR:lscpr_charges_byzone_13mo

CT ME NEMA NHRI SEMA VT WCMA

Mil

lio

ns

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

MAR14

APR14

MAY14

JUN

14

JUL1

4

AUG14

SEP14

OCT14

NO

V14

DEC14

JAN

15

FEB15

MAR15

LSCPR Charges by Zone

64

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

GR:var_charges_stack_13mo

DA LV NCPC RT LV NCPC DA HV NCPC

Mil

lio

ns

$0.0

$0.1

$0.2

$0.3

$0.4

$0.5

$0.6

$0.7

$0.8

$0.9

$1.0

$1.1

$1.2

$1.3

$1.4

$1.5

$1.6

MAR14

APR14

MAY14

JUN

14

JUL1

4

AUG14

SEP14

OCT14

NO

V14

DEC14

JAN

15

FEB15

MAR15

NCPC Charges for Voltage Support and High Voltage Control

65

GR:NCPC_Stack Value of Charges

1st C 2nd C Distr Voltg

Mill

ions

$0

$25

$50

$75

$100

$125

$150

$175

2013

2014

2015

JAN

2015

FEB20

15

MAR20

15

APR2015

MAY201

5

JUN2015

JUL2

015

AUG20

15

SEP2015

OCT2

015

NOV201

5

DEC2015

$158.7 $

174.7

$35.7

$9.8

$11.4

$14.5

NCPC Charges by Type

66

GR:NCPC_pct_Stack NCPC By Type as Percent of Energy Market

1st C 2nd C Distr Voltg

Perc

ent

0.0%

1.0%

2.0%

3.0%

4.0%

2013

2014

2015

JAN

2015

FEB20

15

MAR20

15

APR2015

MAY201

5

JUN2015

JUL2

015

AUG20

15

SEP2015

OCT2

015

NOV201

5

DEC2015

2.0

%

1.9

%

1.2

%

1.1

%

0.8

%

2.0

%

NCPC Charges as Percent of Energy Market

67

GR:Graph19 GR:Graph20 Value of Charges

Mill

ion

s

$0

$20

$40

$60

$80

$100

$120

$140

2013

2014

2015

JAN

2015

FEB

2015

MA

R20

15A

PR2

015

MA

Y201

5JU

N20

15JU

L201

5A

UG

2015

SEP2

015

OC

T201

5N

OV

2015

DEC

2015

$98.9

$135.2

$27.2

$8.6

$9.2

$9.5

% of Energy Market Value

0.0%

1.0%

2.0%

3.0%

4.0%

2013

2014

2015

JAN

2015

FEB

2015

MA

R20

15A

PR2

015

MA

Y201

5JU

N20

15JU

L201

5A

UG

2015

SEP2

015

OC

T201

5N

OV

2015

DEC

2015

1.2

% 1.5

%

0.9

%

1.0

%

0.7

%

1.3

%

First Contingency NCPC Charges

68

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

GR:Graph22 GR:Graph21 % of Energy Market Value

0.0%

0.4%

0.8%

1.2%

1.6%

2.0%

2013

2014

2015

JAN

2015

FEB

2015

MA

R20

15A

PR2

015

MA

Y201

5JU

N20

15JU

L201

5A

UG

2015

SEP2

015

OC

T201

5N

OV

2015

DEC

2015

0.5

%

0.4

%

0.2

%

0.1

%

0.1

%

0.7

%

Value of Charges

Mill

ion

s

$0

$10

$20

$30

$40

2013

2014

2015

JAN

2015

FEB

2015

MA

R20

15A

PR2

015

MA

Y201

5JU

N20

15JU

L201

5A

UG

2015

SEP2

015

OC

T201

5N

OV

2015

DEC

2015

$38.0

$32.4

$6.3

$0.6

$0.9

$4.9

Second Contingency NCPC Charges

69


GR:Graph18 GR:Graph17 % of Energy Market Value

0.0%

1.0%

2.0%

3.0%

4.0%

2013

2014

2015

JAN

2015

FEB

2015

MA

R20

15A

PR2

015

MA

Y201

5JU

N20

15JU

L201

5A

UG

2015

SEP2

015

OC

T201

5N

OV

2015

DEC

2015

0.3

%

0.1

%

0.1

%

0.1

%

0.1

%

0.1

%

Value of Charges

Mill

ion

s

$0

$10

$20

$30

$40

2013

2014

2015

JAN

2015

FEB

2015

MA

R20

15A

PR2

015

MA

Y201

5JU

N20

15JU

L201

5A

UG

2015

SEP2

015

OC

T201

5N

OV

2015

DEC

2015

$21.8

$7.0

$2.4

$0.7

$1.3

$0.4

Voltage and Distribution NCPC Charges

70


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

71

DA vs. RT LMPs ($/MWh)

72

Arithmetic Average Year 2013 NEMA CT ME NH VT RI SEMA WCMA Hub

Day-Ahead $56.90 $55.43 $54.48 $55.98 $55.36 $57.80 $57.02 $56.38 $56.43 Real-Time $56.32 $55.90 $53.23 $55.15 $55.08 $56.10 $56.43 $56.12 $56.06 RT Delta % -1.0% 0.8% -2.3% -1.5% -0.5% -2.9% -1.0% -0.5% -0.7% Year 2014 NEMA CT ME NH VT RI SEMA WCMA Hub

Day-Ahead $64.98 $64.10 $61.95 $64.12 $63.82 $64.98 $64.71 $64.66 $64.57 Real-Time $64.03 $63.11 $59.04 $61.48 $61.60 $63.34 $63.45 $63.29 $63.32 RT Delta % -1.5% -1.5% -4.7% -4.1% -3.5% -2.5% -2.0% -2.1% -1.9%

March-14 NEMA CT ME NH VT RI SEMA WCMA Hub Day-Ahead $111.77 $109.23 $107.34 $109.75 $109.34 $112.49 $112.27 $111.12 $111.16 Real-Time $116.87 $114.46 $110.06 $113.20 $112.47 $116.65 $117.15 $116.10 $116.12 RT Delta % 4.6% 4.8% 2.5% 3.1% 2.9% 3.7% 4.4% 4.5% 4.5% March-15 NEMA CT ME NH VT RI SEMA WCMA Hub

Day-Ahead $66.28 $60.69 $62.47 $64.56 $61.24 $65.38 $66.36 $63.87 $64.25 Real-Time $58.34 $55.98 $55.24 $56.71 $56.08 $57.73 $58.02 $57.48 $57.93 RT Delta % -12.0% -7.8% -11.6% -12.2% -8.4% -11.7% -12.6% -10.0% -9.8%

Annual Diff. NEMA CT ME NH VT RI SEMA WCMA Hub Yr over Yr DA -40.7% -44.4% -41.8% -41.2% -44.0% -41.9% -40.9% -42.5% -42.2% Yr over Yr RT -50.1% -51.1% -49.8% -49.9% -50.1% -50.5% -50.5% -50.5% -50.1%

GR:Graph25

Ma

rch

20

03

=1

.00

0

0.000

1.000

2.000

3.000

MAR20

03JU

N20

03SE

P200

3D

EC20

03M

AR2004

JUN

2004

SEP2

004

DEC

2004

MAR20

05JU

N20

05SE

P200

5D

EC20

05M

AR2006

JUN

2006

SEP2

006

DEC

2006

MAR20

07JU

N20

07SE

P200

7D

EC20

07M

AR2008

JUN

2008

SEP2

008

DEC

2008

MAR20

09JU

N20

09SE

P200

9D

EC20

09M

AR2010

JUN

2010

SEP2

010

DEC

2010

MAR20

11JU

N20

11SE

P201

1D

EC20

11M

AR2012

JUN

2012

SEP2

012

DEC

2012

MAR20

13JU

N20

13SE

P201

3D

EC20

13M

AR2014

JUN

2014

SEP2

014

DEC

2014

MAR20

15JU

N20

15SE

P201

5

Natural Gas Hub RT LMP

Monthly Average Fuel Price and RT Hub LMP Indexes

73



GR:hubwgas_mly_smd $

/M

MB

tu (

Fu

el)

$0.00

$3.00

$6.00

$9.00

$12.00

$15.00

$18.00

$21.00

$24.00

$27.00

$30.00

MAR20

03JU

N20

03SE

P200

3D

EC20

03M

AR2004

JUN

2004

SEP2

004

DEC

2004

MAR20

05JU

N20

05SE

P200

5D

EC20

05M

AR2006

JUN

2006

SEP2

006

DEC

2006

MAR20

07JU

N20

07SE

P200

7D

EC20

07M

AR2008

JUN

2008

SEP2

008

DEC

2008

MAR20

09JU

N20

09SE

P200

9D

EC20

09M

AR2010

JUN

2010

SEP2

010

DEC

2010

MAR20

11JU

N20

11SE

P201

1D

EC20

11M

AR2012

JUN

2012

SEP2

012

DEC

2012

MAR20

13JU

N20

13SE

P201

3D

EC20

13M

AR2014

JUN

2014

SEP2

014

DEC

2014

MAR20

15JU

N20

15SE

P201

5

$/

MW

h (

Ele

ctri

city

)

$0.00

$40.00

$80.00

$120.00

$160.00

$200.00


Monthly Average Fuel Price and RT Hub LMP

74



GR:three_pools_prices_dly GR:three_pools_prices_mly

Ele

ctri

city

Pri

ces

($/M

Wh

)

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

01M

AR15

02M

AR15

03M

AR1504

MAR15

05M

AR15

06M

AR15

07M

AR15

08M

AR15

09M

AR15

10M

AR15

11M

AR15

12M

AR15

13M

AR1514

MAR15

15M

AR15

16M

AR15

17M

AR15

18M

AR15

19M

AR15

20M

AR15

21M

AR15

22M

AR15

23M

AR1524

MAR15

25M

AR15

26M

AR15

27M

AR15

28M

AR15

29M

AR15

30M

AR15

31M

AR15

Daily: This Month

*Note: Hourly average prices are shown.

ISO-NE NY-ISO PJM

Ele

ctri

city

Pri

ces

($/M

Wh

)

$20

$30

$40

$50

$60

$70

$80

$90

$100

$110

$120

$130

MAR20

14APR2

014M

AY201

4JU

N20

14JU

L201

4AU

G20

14SE

P201

4O

CT201

4N

OV20

14D

EC20

14JA

N20

15FE

B2015

MAR20

15


*Note: Hourly average prices are shown.

ISO-NE NY-ISO PJM

New England, NY, and PJM Real Time Prices

75

GR:three_pools_prices_fpk_dly GR:three_pools_prices_fpk_mly

Ele

ctri

city

Pri

ces

($/M

Wh

)

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

$200

$220

01M

AR15

02M

AR15

03M

AR1504

MAR15

05M

AR15

06M

AR15

07M

AR15

08M

AR15

09M

AR15

10M

AR15

11M

AR15

12M

AR15

13M

AR1514

MAR15

15M

AR15

16M

AR15

17M

AR15

18M

AR15

19M

AR15

20M

AR15

21M

AR15

22M

AR15

23M

AR1524

MAR15

25M

AR15

26M

AR15

27M

AR15

28M

AR15

29M

AR15

30M

AR15

31M

AR15

Daily: This Month

ISO-NE NY-ISO PJM

Ele

ctri

city

Pri

ces

($/M

Wh

)

$40 $50 $60 $70 $80

$90 $100 $110 $120 $130 $140 $150 $160 $170

MAR20

14APR2

014M

AY201

4JU

N20

14JU

L201

4AU

G20

14SE

P201

4O

CT201

4N

OV20

14D

EC20

14JA

N20

15FE

B2015

MAR20

15


ISO-NE NY-ISO PJM

New England, NY, and PJM Real Time Prices (Peak Hour)

76

*Forecasted peak hour is reflected.

Reserve Market Results – March 2015 • Maximum potential Forward Reserve Market payments of

$13.8M were reduced by credit reductions of $390K, failure-to-reserve penalties of $584K and failure-to-activate penalties of $0, resulting in a net payout of $12.9M or 93% of maximum – Rest of System: $7.34M/$7.60M (97%)

– Southwest Connecticut: $0.92M/$1.11M (83%)

– Connecticut: $4.60M/$5.12M (90%)

• $394K total Real-Time credits were reduced by $0 in Forward Reserve Energy Obligation Charges for a net of $394K in Real-Time Reserve payments – Rest of System: 124 hours, $382K

– Southwest Connecticut: 124 hours, $8K

– Connecticut: 124 hours, $1K

– NEMA: 124 hours, $3K

77

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

GR:Graph39 LFRM Charges by Zone, Last 13 Months

CT ME NEMA NH

RI SEMA VT WCMA

Mill

ion

s

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0M

AR14

APR14

MAY14

JUN14

JUL1

4

AUG14

SEP14

OCT1

4

NOV14

DEC14

JAN

15

FEB15

MAR15

LFRM Charges to Load by Load Zone ($)

78

GR:Graph28 March 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


20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

Zonal Increment Offers and Cleared Amounts

79

GR:Graph29 March Monthly Totals by Zone

Cleared Bid

MW

h

0

10,000

20,000

30,000

40,000

50,000

60,000


20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

20

14

20

15

Zonal Decrement Bids and Cleared Amounts

80

GR:Graph30

Total Increment Offers and Decrement Bids

81

Data excludes nodal offers and bids

Zonal Level, Last 13 Months

Cleared Bid/Offered

MW

h

0

200,000

400,000

600,000

800,000

MA

R2

01

4

AP

R2

01

4

MA

Y2

01

4

JUN

20

14

JUL2

01

4

AU

G2

01

4

SEP

20

14

OC

T20

14

NO

V2

01

4

DEC

20

14

JAN

20

15

FEB

20

15

MA

R2

01

5

INC

DEC IN

C

DEC IN

C

DEC IN

C

DEC IN

C

DEC IN

C

DEC IN

C

DEC IN

C

DEC IN

C

DEC IN

C

DEC IN

C

DEC IN

C

DEC IN

C

DEC

GR:Graph31 Total Monthly Energy; Dispatchable % Shown

Non-Dispatchable Dispatchable

GW

h

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000M

AR2014

APR2014

MAY201

4

JUN2014

JUL2

014

AUG20

14

SEP2014

OCT2

014

NOV201

4

DEC2014

JAN

2015

FEB20

15

MAR20

15

21.7

%

24.8

%

19.2

% 24.6

%

30.7

%

26.3

%

22.8

%

19.9

%

17.1

% 34.1

%

41.2

%

49.7

%

42.0

%

Dispatchable vs. Non-Dispatchable Generation

82

* 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).

GR:rolling_avg_per_big

Maine Rest-of-Pool

$/K

W-M

on

th

$0.00

$0.04

$0.08

$0.12

$0.16

$0.20

monthMAR14 APR14 MAY14 JUN14 JUL14 AUG14 SEP14 OCT14 NOV14 DEC14 JAN15 FEB15 MAR15

Rolling Average Peak Energy Rent (PER)

83

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.

NEW SLIDE

GR:fcm_per_adj_byzone_big

Maine Rest-of-Pool

Mil

lio

ns

($)

$0.0

$1.0

$2.0

$3.0

monthMAR14 APR14 MAY14 JUN14 JUL14 AUG14 SEP14 OCT14 NOV14 DEC14 JAN15 FEB15 MAR15

PER Adjustments

84

NEW SLIDE

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

REGIONAL SYSTEM PLAN (RSP) AND INTERREGIONAL PLANNING

Planning Advisory Committee (PAC)

86

• The next PAC meeting is scheduled for April 22. Major agenda topics will include:

– Post Winter 2014/15 Review

– New England Gas Association Update

– 2015 Economic Study Stakeholder Presentations

• Additional PAC meeting is slated for April 28. Major agenda topics will include:

– ISO Discussion on Transmission Planning Methods and Assumptions

– RSP15 Resource Adequacy Related Studies Scope of Work

– RSP15 Load and Capacity Resource Overview

Economic Study Requests

• Three economic study requests were submitted to the ISO and will be discussed with the PAC on April 22

• The ISO draft scope of work for economic studies is scheduled for discussion at the May PAC meeting

87

Distributed Generation Forecast Working Group (DGFWG)

88

• DGFWG meeting is scheduled for April 14

– Discussions will include stakeholder comments on the draft PV forecast, the final PV forecast, and the classification of the PV forecast into four types

• By the release of CELT 2015, the ISO plans on producing the final 2015 PV forecasts

– Forecasts will show PV nameplate, estimated seasonal claimed capability, and energy production

– Forecasts will be developed for the overall system, states, and RSP bubbles

DGFWG, cont.

89

• ISO has classified PV resources by market participation type – FCM resources with capacity supply obligations – Settlement-only resources (energy market only) – Behind-the-meter resources that are already accounted for as part of the ISO load forecast – Remaining behind-the-meter resources

• ISO urges DG resources to participate in the FCM

• A portion of the behind-the-meter PV forecast has been identified as a part of the demand forecast that needs to be captured for purposes of Installed Capacity Requirement calculations

– ISO will continue working with the PSPC and the RC to receive stakeholder input in preparation for FCA #10

• PV forecast will be used in new economic studies and new transmission planning studies

• ISO is working with the transmission owners, distribution owners, the states, and IEEE to resolve interconnection issues

• ISO will continue participation in DOE projects that support operational and planning forecasts of PV

90

Environmental Matters

• FERC held technical conferences to consider the reliability implications of various compliance approaches to EPA’s proposed June 2014 Clean Power Plan, regulating CO2 emissions from existing generators – February 19, 2015 - National Overview (Washington, DC) – March 11, 2015 - Eastern Region (Washington, DC)

• Steve Rourke and Bob Ethier participated indicating the following:

– With RGGI, NEPOOL GIS tracking system and market rules to help with compliance, New England is already moving along on a clean energy path

– Pay-for-Performance will ensure that existing generation retires from the market when it is no longer able to meet reliability needs and that new resources are actually able to meet those needs

– ISO expects to work with the states to address reliability concerns

– The IRC’s proposed “reliability safety valve” is an important mechanism

– Additional infrastructure will be necessary for natural gas generation and wind/hydro that will likely replace aging oil and coal resources

RSP Project Stage Descriptions

91

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

NEEWS: Interstate Reliability Project Status as of 4/6/15

Plan Benefit: Improves New England reliability by increasing transfer limits of three critical interfaces

92

Upgrade

Expected

In-service

Present

Stage

Build New 345 kV Line 3271 Card - Lake Road Dec-15 3

Card 345 kV Substation Expansion Dec-15 3

Lake Road 345 kV Substation Expansion Dec-15 3

Build New 345 kV Line 341 Lake Road to CT/RI Border Dec-15 3

Build New 345 kV Line 341 CT/RI Border to West Farnum Dec-15 3

West Farnum 345 kV Substation Additions (New Line Terminations) Dec-15 3

New Sherman Road 345 kV Substation Dec-15 3

West Farnum 115 kV Substation Upgrades Sep-14 4

Reconductor 345 kV Line 328 West Farnum to Sherman Road Dec-15 3

Riverside Substation Relay Upgrades Sep-14 4

Woonsocket Substation Relay Upgrades Sep-14 4

Hartford Avenue Substation Relay Upgrades Sep-14 4

Build New 345 kV Line 366 West Farnum to MA/RI Border Dec-15 3

Build New 345 kV Line 366 MA/RI Border to Millbury 3 Dec-15 3

Millbury 3 Substation Expansion Dec-15 3

Carpenter Hill Substation Relay Upgrades Dec-15 3

Maine Power Reliability Program (MPRP) Status as of 4/6/15

Project Benefit: Addresses long-term system needs of Emera Maine and Central Maine Power, thermal and voltage issues in western Maine and supports load growth in southern Maine

93

New 345 kV Lines

Expected

In-Service

Present

Stage

Construct New Section 3023 Orrington to Albion Road May-13 4

Construct New Section 3024 Albion Road to Coopers Mills Mar-15 4

Construct New Section 3025 Coopers Mills to Larrabee Road Apr-15* 3

Construct New Section 3026 Larrabee Road to Surowiec Dec-12 4

Construct New Section 3020 Surowiec to Raven Farm Nov-13 4

Construct New Section 3021 South Gorham to Maguire Road Apr-14 4

Construct New Section 3022 Maguire Road to Eliot Aug-14 4

* Scheduled to be in service April 13, 2015 Note: The above listing focuses on major transmission line construction and rebuilding.

Maine Power Reliability Program, cont. Status as of 4/6/15


94

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

New 115 kV Lines

Expected

In-Service

Present

Stage

Construct New Section 254 Orrington to Coopers Mills Mar-15 4

Construct New Section 243A Livermore Falls to Junction Section 243 May-14 4

Construct New Section 251 Livermore Falls to Larrabee Road May-14 4

Construct New Section 255 Larrabee Road to Middle Street Mar-17 3

Construct New Section 86A Tap to Belfast Jul-14 4

Construct New Section 256 Middle Street to Lewiston Lower Mar-17 1


95


115 kV Lines Rebuilds

Expected

In-Service

Present

Stage

Rebuild Section 60 Coopers Mills to Bowman Street Feb-15 4

Rebuild Section 88 Coopers Mills to Augusta East Side Feb-15 4

Rebuild Section 89 Livermore Falls to Riley May-14 4

Rebuild Section 229 Riley to Rumford IP May-13 4

Rebuild Section 212 Monmouth to Larrabee Road Feb-13 4

Rebuild Section 269 Bowman Street to Monmouth May-12 4

Rebuild Section 238 Louden to Maguire Road Feb-12 4

Rebuild Section 250 Maguire Road to Three Rivers Dec-13 4



96



345/115 kV Autotransformers

Expected

In-Service

Present

Stage

Install One 345/115 kV Autotransformer at Albion Road Apr-13 4

Install One 345/115 kV Autotransformer at Coopers Mills Mar-15 4

Install One 345/115 kV Autotransformer at Larrabee Road Dec-12 4

Install One 345/115 kV Autotransformer at Maguire Road Apr-14 4

Install One 345/115 kV Autotransformer at South Gorham Nov-09 4

New Hampshire/Vermont 10-Year Upgrades Status as of 4/6/15

Project Benefit: Addresses Needs in New Hampshire and Vermont

97


Upgrade

Expected

In-Service

Present

Stage

Eagle Substation Add: 345/115 kV autotransformer Dec-16 2

Littleton Substation Add: Second 230/115 kV autotransformer Oct-14 4

New C-203 230 kV line tap to Littleton NH Substation Nov-14 4

New 115 kV overhead line, Fitzwilliam-Monadnock Dec-15 3

New 115 kV overhead line, Scobie Pond-Huse Road Dec-15 3

New 115 kV overhead/submarine line, Madbury-Portsmouth Dec-17 2

New 115 kV overhead line, Scobie Pond-Chester Dec-15 3

New 115 kV overhead line, Coolidge-Ascutney Dec-16 1

New Hampshire/Vermont 10-Year Upgrades, cont. Status as of 4/6/15


98


Upgrade

Expected

In-Service

Present

Stage

Saco Valley Substation - Add two 25 MVAR dynamic reactive devices Dec-16 3

Rebuild 115 kV line K165, W157 tap Eagle-Power Street May-15 3

Rebuild 115 kV line H137, Merrimack-Garvins Jun-13 4

Rebuild 115 kV line D118, Deerfield-Pine Hill Nov-14 4

Oak Hill Substation - Loop in 115 kV line V182, Garvins-Webster Apr-15 4*

Uprate 115 kV line G146, Garvins-Deerfield Mar-15 4

Uprate 115 kV line P145, Oak Hill-Merrimack May-14 4

* Placed in-service ahead of schedule

New Hampshire/Vermont 10-Year Upgrades, cont. Status as of 4/6/15


99


Upgrade

Expected

In-Service

Present

Stage

Upgrade 115 kV line H141, Chester-Great Bay Nov-14 4

Upgrade 115 kV line R193, Scobie Pond-Kingston Tap Mar-15 4*

Upgrade 115 kV line T198, Keene-Monadnock Nov-13 4

Upgrade 345 kV line 326, Scobie Pond-NH/MA Border Dec-13 4

Upgrade 115 kV line J114-2, Greggs - Rimmon Dec-13 4

Upgrade 345 kV line 381, between MA/NH border and NH/VT border Jun-13 4

* Placed in-service ahead of schedule

Greater Hartford and Central Connecticut (GHCC) Projects* Status as of 4/6/15

100

Upgrade

Expected

In-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 Dec-18 1

Terminal equipment upgrades on the 345 kV line between Haddam Neck and

Beseck (362) Dec-17 1

Redesign the Green Hill 115 kV substation from a straight bus to a ring bus and

add a 115 kV 37.8 MVAR capacitor bank Dec-17 1

Add a 37.8 MVAR capacitor bank at the Hopewell 115 kV substation Dec-16 1

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 1

Separation of 115 kV double circuit towers corresponding to the Middletown –

Pratt and Whitney line (1572) and the Middletown to Haddam (1620) line Dec-17 1

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

Greater Hartford and Central Connecticut Projects, cont.* Status as of 4/6/15

101

Upgrade

Expected

In-service

Present

Stage

Terminal equipment upgrades on the 115 kV line from Middletown to Dooley

(1050) Dec-17 1

Terminal equipment upgrades on the 115 kV line from Middletown to Portland

(1443) Dec-17 1

Add a new 115 kV underground cable from Newington to Southwest Hartford

and associated terminal equipment including a 2% series reactor Dec-18 1

Add a 115 kV 25.2 MVAR capacitor at Westside 115 kV substation Dec-16 1

Loop the 1779 line between South Meadow and Bloomfield into the Rood

Avenue substation and reconfigure the Rood Avenue substation Dec-17 1

Reconfigure the Berlin 115 kV substation including two new 115 kV breakers

and the relocation of a capacitor bank Dec-18 1

Reconductor the 115 kV line between Newington and Newington Tap (1783) Dec-18 1




102

Upgrade

Expected

In-service

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 1

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 1

Install a 115 kV 3% reactor on the 115 kV line between South Meadow and

Southwest Hartford (1704) Dec-18 1

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 1

Replace the normally open 19T breaker at Southington 115 kV with a normally

closed 3% series reactor Dec-17 1

Add a 345 kV breaker in series with breaker 5T at Southington Dec-17 1




103

Upgrade

Expected

In-service

Present

Stage

Add a new control house at Southington 115 kV substation Dec-17 1

Add a new 115 kV line from Frost Bridge to Campville Dec-18 1

Separation of 115 kV DCT corresponding to the Frost Bridge to Campville

(1191) line and the Thomaston to Campville (1921) line and add a breaker at

Campville 115 kV substation Dec-18 1

Upgrade the 115 kV line between Southington and Lake Avenue Junction

(1810-1) Dec-17 1

Add a new 345/115 kV autotransformer at Barbour Hill substation Dec-16 2

Add a 345 kV breaker in series with breaker 24T at the Manchester 345 kV

substation Dec-16 2

Reconductor the 115 kV line between Manchester and Barbour Hill (1763) Dec-16 2



Southwest Connecticut (SWCT) Projects Status as of 4/6/15

104

Upgrade

Expected

In-service

Present

Stage

Add a 25.2 MVAR capacitor bank at the Oxford substation Dec-17 1

Add 2 x 25 MVAR capacitor banks at the Ansonia substation Dec-17 1

Close the normally open 115 kV 2T circuit breaker at Baldwin substation Dec-17 1

Rebuild Bunker Hill to a 9-breaker substation in breaker-and-a-half

configuration Dec-17 1

Reconductor the 115 kV line between Bunker Hill and Baldwin Junction (1575) Dec-17 1

Loop the 1990 line in and out the Bunker Hill substation Dec-17 1

Expand Pootatuck (formerly known as Shelton) substation to 4-breaker ring

bus configuration and add a 30 MVAR capacitor bank at Pootatuck Dec-17 1

Loop the 1570 line in and out the Pootatuck substation Dec-17 1

Replace two 115 kV circuit breakers at the Freight substation Dec-17 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

Southwest Connecticut Projects, cont. Status as of 4/6/15

105


Upgrade

Expected

In-service

Present

Stage

Add two 14.4 MVAR capacitor banks at the West Brookfield substation Dec-17 1

Add a new 115 kV line from Plumtree to Brookfield Junction Dec-17 1

Reconductor the 115 kV line between West Brookfield and Brookfield

Junction (1887) Dec-17 1

Reduce the existing 25.2 MVAR capacitor bank at the Rocky River

substation to 14.4 MVAR Dec-17 1

Reconfigure the 1887 line into a three-terminal line (Plumtree - W.

Brookfield - Shepaug) Dec-17 1

Reconfigure the 1770 line into 2 two-terminal lines (Plumtree - Stony Hill and

Stony Hill - Bates Rock) Dec-17 1

Install a synchronous condenser (+25/-12.5 MVAR) at Stony Hill Dec-17 1

Relocate an existing 37.8 MVAR capacitor bank at Stony Hill to the 25.2

MVAR capacitor bank side Dec-17 1


106

Upgrade

Expected

In-service

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 1

Add a 115 kV circuit breaker in series with the existing 29T breaker at the

Plumtree substation Dec-17 1

Terminal equipment upgrade at the Newtown substation (1876) Dec-17 1

Rebuild the 115 kV line from Wilton to Norwalk (1682) and upgrade

Wilton substation terminal equipment Dec-17 1

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

Reconductor the 115 kV line from Ridgefield Junction to Peaceable

(1470-3) Dec-17 1



107

Upgrade

Expected

In-service

Present

Stage

Add 2 x 20 MVAR capacitor banks at the Hawthorne substation Apr-16 2

Upgrade the 115 kV bus at the Baird substation Dec-17 1

Upgrade the 115 kV bus system and 11 disconnect switches at the

Pequonnock substationDec-14 4

Add a 345 kV breaker in series with the existing 11T breaker at the East

Devon substationDec-16 2

Rebuild the 115 kV lines from Baird to Congress (8809A / 8909B) May-18 1

Rebuild the 115 kV lines from Housatonic River Crossing (HRX) to Barnum

to Baird (88006A / 89006B)Apr-19 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


108

Upgrade

Expected

In-service

Present

Stage

Remove the Sackett phase shifter Dec-17 1

Install a 7.5 ohm series reactor on 1610 line at the Mix Avenue substation Dec-17 1

Add 2 x 20 MVAR capacitor banks at the Mix Avenue substation Dec-17 1

Separate the 3827 (Beseck to East Devon) and 1610 (Southington to June

to Mix Avenue) double circuit towersDec-17 1

Upgrade the 1630 line relay at North Haven and Wallingford 1630 terminal

equipmentDec-16 1

Rebuild the 115 kV lines from Devon Tie to Milvon (88005A / 89005B) Dec-16 2

Replace 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

Greater Boston Projects Status as of 4/6/15

109

Upgrade

Expected

In-service

Present

Stage

Install new 345 kV line from Scobie to Tewksbury Dec-17 1

Reconductor the Y-151 115 kV line from Dracut Junction to Power Street Dec-17 1

Reconductor the M-139 115 kV line from Tewksbury to Pinehurst and

associated work at Tewksbury Dec-16 1

Reconductor the N-140 115 kV line from Tewksbury to Pinehurst and

associated work at TewksburyDec-16 1

Reconductor the F-158N 115 kV line from Wakefield Junction to

Maplewood and associated work at MaplewoodJun-16 1

Reconductor the F-158S 115 kV line from Maplewood to Everett Jun-16 1

Install 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

Dec-18 1

Refurbish X-24 69 kV line from Millbury to Northboro Road Dec-15 1

Reconductor W-23W 69 kV line from Woodside to Northboro Road Jun-16 1

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

Greater Boston Projects, cont. Status as of 4/6/15

110

Upgrade

Expected

In-service

Present

Stage

Separate X-24 and E-157W DCT Dec-15 1

Separate Q-169 and F-158N DCT Dec-15 1

Reconductor M-139/211-503 and N-140/211-504 115 kV lines from

Pinehurst to North Woburn tapMay-17 1

Install new 115 kV station at Sharon to segment three 115 kV lines from

West Walpole to HolbrookMay-17 1

Install third 115 kV line from West Walpole to Holbrook Dec-16 1

Install new 345 kV breaker in series with the 104 breaker at Stoughton Dec-16 1

Install new 230/115 kV autotransformer at Sudbury and loop the 282-602

230 kV line in and out of the new 230 kV switchyard at Sudbury Dec-15 1

Install a new 115 kV line from Sudbury to Hudson Dec-18 1



111

Upgrade

Expected

In-service

Present

Stage

Replace 345/115 kV autotransformer, 345 kV breakers, and 115 kV

switchgear at WoburnDec-17 1

Install a 345 kV breaker in series with breaker 104 at Woburn Dec-16 1

Reconfigure Waltham by relocating PARs, 282-507 line, and a breaker May-16 1

Upgrade 533-508 115 kV line from Lexington to Hartwell and associated

work at the stationsDec-15 1

Install a new 115 kV 54 MVAR capacitor bank at Newton Dec-16 1

Install a new 115 kV 36.7 MVAR capacitor bank at Sudbury Dec-16 1

Install a second Mystic 345/115 kV autotransformer and reconfigure the bus Dec-16 1

Install a 115 kV breaker on the West bus at K Street Dec-15 1

Install 115 kV cable from Mystic to Chelsea Dec-17 1

Split 110-522 and 240-510 DCT from Baker Street to Needham for a

portion of the way and install a 115 kV cable for the rest of the wayDec-17 1



112

Upgrade

Expected

In-service

Present

Stage

Install a second 115 kV cable from Mystic to Woburn to create a bifurcated

211-514 lineDec-17 1

Open lines 329-510/511 and 250-516/517 at Mystic and Chatham,

respectively. Operate K Street as a normally closed stationDec-16 1

Upgrade Kingston to create a second normally closed 115 kV bus tie and

reconfigure the 345 kV switchyardDec-17 1

Relocate the Chelsea capacitor bank to the 128-518 termination postion Dec-17 1



113

Upgrade

Expected

In-service

Present

Stage

Upgrade North Cambridge to mitigate 115 kV 5 and 10 stuck breaker

contingenciesJun-16 1

Upgrade Edgar 115 kV station to BPS standards Dec-20 1

Upgrade Dover 115 kV station to BPS standards Dec-20 1

Upgrade East Cambridge 115 kV station to BPS standards Dec-19 1

Upgrade West Methuen 115 kV station to BPS standards Jun-18 1

Upgrade Medway 115 kV station to BPS standards Dec-19 1

Install a 200 MVAR STATCOM at Coopers Mills TBD 1

Install a 115 kV 36.7 MVAR capacitor bank at Hartwell May-17 1

Install a 345 kV 160 MVAR shunt reactor at K Street May-18 1

Install a 115 kV breaker in series with the 5 breaker at Framingham Jun-17 1

Install a 115 kV breaker in series with the 29 breaker at K Street Dec-15 1


Status of Tariff Studies

114

14 17

8 11 12 105 5 6 8 10

24 244

4

77 7

7

7 6 5 44

7 9

00

00 0

0

0 0 0 00

00

1516

1818 15

1521 21 19

2121

22 17

0

11

11

1 1 00

00

00

7

68

76 7 7

77

88

10 13

20

2120 18 21

19 18 21 2222

22

22 24

33

3 3 33 3 4 4

4 4

46

0

10

20

30

40

50

60

70

80

90

100

Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15

6,908

MW

7,341

MW

6,907

MW

8,345

MW

8,293

MW

8,268

MW

8,268

MW

8,311

MW

8,355

MW

9,579

MW

10,597

MW

11,208

MW

11,367

MW

Nu

mb

er

of

Pro

jects

Project Status

Distribution

Executed IA

Negotiating IA

Facility Study

Sys. Impact Study

Optional Study

Feasibility Study

Scoping

89

67

6265

63

69

63

686565

6264

93

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




OPERABLE CAPACITY ANALYSIS

Spring 2015

116

50/50 Load Forecast (Reference) May - 20152

CSO

May- 20152

SCC

Generator Operable Capacity MW 1 29,887 32,828

OP CAP From OP-4 RTDR (+) 468 468

OP CAP From OP-4 RTEG (+) 195 195

Operable Capacity Generator with OP-4 DR and RTEG 30,550 33,491

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

528 528

Non Commercial Capacity (+) 0 87

Non Gas-fired Planned Outage MW (-) 2,737 3,047

Gas Generator Outages MW (-) 823 988

Allowance for Unplanned Outages (-) 3,400 3,400

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

Net Capacity (NET OPCAP SUPPLY MW) 3 24,118 26,671

Peak Load Forecast MW(adjusted for Other Demand Resources) 2 19,945 19,945

Operating Reserve Requirement MW 2,375 2,375

Operable Capacity Required (NET LOAD OBLIGATION MW) 22,320 22,320

Operable Capacity Margin 3 1,798 4,351

1 Generator Operable Capacity is based on data as of March 25, 2015 and does not include Capacity associated with Settlement Only Generators, Passive and Active Demand Response, and external capacity. 2 Load based on preliminary 2015 CELT report and week with lowest Operable Capacity Margin, week beginning May 9, 2015. 3 Includes OP4 actions associated with RTEG and RTDR 4 Total of (Gas at Risk MW) – (Gas Gen Outages MW)

Spring 2015 Operable Capacity Analysis

117

Spring 2015 Operable Capacity Analysis 90/10 Load Forecast (Extreme) May - 20152

CSO

May - 20152

SCC






622 622


Non Gas-fired Planned Outage MW (-) 916 1,030








Operable Capacity Margin 3 (99) 2,731


Spring 2015 Operable Capacity Analysis(MW) 50/50 Forecast (Reference)

118

(1,000)

0

1,000

2,000

3,000

4,000

5,000

6,000

4-A

pr

11-A

pr

18-A

pr

25-A

pr

2-M

ay

9-M

ay

16-M

ay

23-M

ay

Op

era

ble

Cap

acit

y M

arg

in (M

W)

ISO-NE 2015 OPERABLE CAPACITY ANALYSIS - - with RTDR and RTEG

- 50/50 FORECAST

April 4, 2015 - May 29, 2015, W/B Saturday

Spring 2015 Operable Capacity Analysis(MW) 90/10 Forecast (Extreme)

119

(1,000)

0

1,000

2,000

3,000

4,000

5,000

6,000

4-A

pr

11-A

pr

18-A

pr

25-A

pr

2-M

ay

9-M

ay

16-M

ay

23-M

ay

Op

era

ble

Cap

acit

y M

arg

in (M

W)

April 4, 2015 - May 29, 2015 W/B Saturday

ISO-NE 2015 OPERABLE CAPACITY ANALYSIS with RTDR and RTEG

- 90/10 FORECAST

- -

Spring 2015 Operable Capacity Analysis(MW) 50/50 Forecast (Reference)

120

CSO 50/50

CSO3/25/15 21:36

RWT_APRIL2015

_COO_AMS_040 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]

4/4/2015 30,057 660 0 3,045 1,691 2,700 0 23,281 17,313 2,375 19,688 3,593 319 3,912 141 4,053

4/11/2015 30,057 660 0 3,463 2,377 2,700 0 22,177 17,057 2,375 19,432 2,745 319 3,064 141 3,205

4/18/2015 30,057 266 0 3,893 1,243 2,700 0 22,487 16,539 2,375 18,914 3,573 319 3,892 141 4,033

4/25/2015 30,057 660 0 3,478 705 3,400 0 23,134 16,270 2,375 18,645 4,489 319 4,808 141 4,949

5/2/2015 29,887 622 0 4,879 1,034 3,400 0 21,196 16,243 2,375 18,618 2,578 468 3,046 195 3,241

5/9/2015 29,887 528 0 2,737 823 3,400 0 23,455 19,945 2,375 22,320 1,135 468 1,603 195 1,798

5/16/2015 29,887 622 0 1,399 1,118 3,400 0 24,592 20,942 2,375 23,317 1,275 468 1,743 195 1,938

5/23/2015 29,887 622 0 916 778 3,400 0 25,415 21,868 2,375 24,243 1,172 468 1,640 195 1,835(1,793)

1. Available OPCAP MW based on resource Capacity Supply Obligations, CSO. Does not include Settlement Only Generators.

2. External Node Available Capacity MW based on the sum of external Capacity Supply Obligations (CSO) imports and exports.

3. New resources and generator improvements that have acquired a CSO but have not become commercial.

4.Non-Gas Planned Outages is the total of Non Gas-fired Generator/DARD Outages for the period. This value would also include any known long-term Non Gas-fired Forced Outages.

5. All Planned Gas-fired generation outage for the period. This value would also include any known long-term Gas-fired Forced Outages.

6. Allowance for Unplanned Outages includes forced outages and maintenance outages scheduled less than 14 days in advance per ISO New England Operating Procedure No. 5 Appendix A.

7. Generation at Risk due to Gas Supply pertains to gas fired capacity expected to be at risk during cold weather conditions or gas pipeline maintenance outages.

8. Net OpCap Supply MW Available (1 + 2 + 3 - 4 - 5 - 6 - 7 = 8)

9. Peak Load Forecast as provided in the 2015 CELT Report and adjusted for Passive Demand Resources. http:/ /www.iso-ne .com/system-planning/system-plans-studies/ce lt

10. Operating Reserve Requirement based on 125% of first largest contingency plus 50% of the second largest contingency.

11. Total Net Load Obligation per the formula(9 + 10 = 11)

12. Net OPCAP Margin MW = Net Op Cap Supply MW minus Net Load Obligation (8 - 11 = 12)

13. OP 4 Action 2 Real-time Demand Response based on OP4 Appendix A. Reserve Margins and Distribution Loss Factor Gross Ups are Included.

14. OPCAP Margin taking into account Real Time Demand Response through OP4 Step 2 (12 + 13 = 14)

15. OP 4 Action 6 Emergency Generation Response without the Voltage Reduction requiring > 10 Minutes based on OP4 Appendix A. Real Time Emergency Generation is capped at 600MW.

Reserve Margins and Distribution Loss Factor Gross Ups are Included.

16. OPCAP Margin taking into account Real Time Demand Response and Real Time Emergency Generation through OP4 Step 6 (14 + 15 = 16) This does not include Emergency Energy Transactions (EETs).

ISO-NE 2015 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 M id September.

April 10, 2015 - 50/50 FORECAST using CSO values

Spring 2015 Operable Capacity Analysis(MW) 90/10 Forecast (Extreme)

121

CSO 50/50

CSO3/25/15 22:36

RWT_APRIL2015


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]

4/4/2015 30,057 660 0 3,045 1,691 2,700 0 23,281 17,862 2,375 20,237 3,044 319 3,363 141 3,504

4/11/2015 30,057 660 0 3,463 2,377 2,700 0 22,177 17,599 2,375 19,974 2,203 319 2,522 141 2,663

4/18/2015 30,057 266 0 3,893 1,243 2,700 0 22,487 17,066 2,375 19,441 3,046 319 3,365 141 3,506

4/25/2015 30,057 660 0 3,478 705 3,400 0 23,134 16,789 2,375 19,164 3,970 319 4,289 141 4,430

5/2/2015 29,887 622 0 4,879 1,034 3,400 0 21,196 16,761 2,375 19,136 2,060 468 2,528 195 2,723

5/9/2015 29,887 528 0 2,737 823 3,400 0 23,455 21,721 2,375 24,096 (641) 468 (173) 195 22

5/16/2015 29,887 622 0 1,399 1,118 3,400 0 24,592 22,800 2,375 25,175 (583) 468 (115) 195 80

5/23/2015 29,887 622 0 916 778 3,400 0 25,415 23,802 2,375 26,177 (762) 468 (294) 195 (99)(4,402)



















STUDY WEEK

(Week Beginning,

Saturday)



OPERABLE CAPACITY ANALYSIS

Preliminary Summer 2015

123

50/50 Load Forecast (Reference) June - 20152

CSO

June - 20152

SCC






1,237 1,237


Non Gas-fired Planned Outage MW (-) 0 0








Operable Capacity Margin 3 (434) 316


Preliminary Summer 2015 Operable Capacity Analysis

124

Preliminary Summer 2015 Operable Capacity Analysis 90/10 Load Forecast (Extreme) June - 20152

CSO

June - 20152

SCC






1,237 1,237


Non Gas-fired Planned Outage MW (-) 0 0








Operable Capacity Margin 3 (2,784) (2,034)


Preliminary Summer 2015 Operable Capacity Analysis (MW) 50/50 Forecast (Reference)

125

(4,500)

(3,500)

(2,500)

(1,500)

(500)

500

1,500

2,500

30-M

ay

6-J

un

13-J

un

20-J

un

27-J

un

4-J

ul

11-J

ul

18-J

ul

25-J

ul

1-A

ug

8-A

ug

15-A

ug

22-A

ug

29-A

ug

5-S

ep

12-S

ep

Op

era

ble

Cap

acit

y M

arg

in (M

W)

ISO-NE 2015 OPERABLE CAPACITY ANALYSIS - - with RTDR and RTEG

- 50/50 FORECAST

May 30, 2015 - September 18, 2015, W/B Saturday

Preliminary Summer 2015 Operable Capacity Analysis(MW) 90/10 Forecast (Extreme)

126

(4,500)

(3,500)

(2,500)

(1,500)

(500)

500

1,500

2,500

30-M

ay

6-J

un

13-J

un

20-J

un

27-J

un

4-J

ul

11-J

ul

18-J

ul

25-J

ul

1-A

ug

8-A

ug

15-A

ug

22-A

ug

29-A

ug

5-S

ep

12-S

ep

Op

era

ble

Cap

acit

y M

arg

in (M

W)

May 30, 2015 - September 18, 2015 W/B Saturday

ISO-NE 2015 OPERABLE CAPACITY ANALYSIS with RTDR and RTEG

- 90/10 FORECAST

- -

Preliminary Summer 2015 Operable Capacity Analysis(MW) 50/50 Forecast (Reference)

127

CSO 50/50

CSO3/25/15 21:36

RWT_APRIL2015


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]

5/30/2015 29,576 1,237 0 0 0 2,800 0 28,013 26,710 2,375 29,085 (1,072) 446 (626) 192 (434)

6/6/2015 29,576 1,237 0 0 0 2,800 0 28,013 26,710 2,375 29,085 (1,072) 446 (626) 192 (434)

6/13/2015 29,576 1,237 0 0 0 2,800 0 28,013 26,710 2,375 29,085 (1,072) 446 (626) 192 (434)

6/20/2015 29,576 1,237 0 0 0 2,800 0 28,013 26,710 2,375 29,085 (1,072) 446 (626) 192 (434)

6/27/2015 29,576 1,237 0 0 0 2,800 0 28,013 26,710 2,375 29,085 (1,072) 446 (626) 192 (434)

7/4/2015 29,576 1,237 0 0 0 2,100 0 28,713 26,710 2,375 29,085 (372) 446 74 192 266

7/11/2015 29,576 1,237 0 0 0 2,100 0 28,713 26,710 2,375 29,085 (372) 446 74 192 266

7/18/2015 29,576 1,237 0 0 0 2,100 0 28,713 26,710 2,375 29,085 (372) 446 74 192 266

7/25/2015 29,576 1,237 0 0 0 2,100 0 28,713 26,710 2,375 29,085 (372) 446 74 192 266

8/1/2015 29,576 1,237 0 0 0 2,100 0 28,713 26,710 2,375 29,085 (372) 446 74 192 266

8/8/2015 29,576 1,237 0 0 0 2,100 0 28,713 26,710 2,375 29,085 (372) 446 74 192 266

8/15/2015 29,576 1,237 0 0 0 2,100 0 28,713 26,710 2,375 29,085 (372) 446 74 192 266

8/22/2015 29,576 1,237 0 0 0 2,100 0 28,713 26,710 2,375 29,085 (372) 446 74 192 266

8/29/2015 29,576 1,237 6 0 0 2,100 0 28,719 26,710 2,375 29,085 (366) 446 80 192 272

9/5/2015 29,576 1,237 6 12 493 2,100 0 28,214 26,710 2,375 29,085 (871) 446 (425) 192 (233)

9/12/2015 29,576 1,237 6 1,361 802 2,100 0 26,556 23,016 2,375 25,391 1,165 446 1,611 192 1,803(1,793)



















STUDY WEEK

(Week Beginning,

Saturday)



Preliminary Summer 2015 Operable Capacity Analysis(MW) 90/10 Forecast (Extreme)

128

CSO 50/50

CSO3/25/15 22:36

RWT_APRIL2015


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]

5/30/2015 29,576 1,237 0 0 0 2,800 0 28,013 29,060 2,375 31,435 (3,422) 446 (2,976) 192 (2,784)

6/6/2015 29,576 1,237 0 0 0 2,800 0 28,013 29,060 2,375 31,435 (3,422) 446 (2,976) 192 (2,784)

6/13/2015 29,576 1,237 0 0 0 2,800 0 28,013 29,060 2,375 31,435 (3,422) 446 (2,976) 192 (2,784)

6/20/2015 29,576 1,237 0 0 0 2,800 0 28,013 29,060 2,375 31,435 (3,422) 446 (2,976) 192 (2,784)

6/27/2015 29,576 1,237 0 0 0 2,800 0 28,013 29,060 2,375 31,435 (3,422) 446 (2,976) 192 (2,784)

7/4/2015 29,576 1,237 0 0 0 2,100 0 28,713 29,060 2,375 31,435 (2,722) 446 (2,276) 192 (2,084)

7/11/2015 29,576 1,237 0 0 0 2,100 0 28,713 29,060 2,375 31,435 (2,722) 446 (2,276) 192 (2,084)

7/18/2015 29,576 1,237 0 0 0 2,100 0 28,713 29,060 2,375 31,435 (2,722) 446 (2,276) 192 (2,084)

7/25/2015 29,576 1,237 0 0 0 2,100 0 28,713 29,060 2,375 31,435 (2,722) 446 (2,276) 192 (2,084)

8/1/2015 29,576 1,237 0 0 0 2,100 0 28,713 29,060 2,375 31,435 (2,722) 446 (2,276) 192 (2,084)

8/8/2015 29,576 1,237 0 0 0 2,100 0 28,713 29,060 2,375 31,435 (2,722) 446 (2,276) 192 (2,084)

8/15/2015 29,576 1,237 0 0 0 2,100 0 28,713 29,060 2,375 31,435 (2,722) 446 (2,276) 192 (2,084)

8/22/2015 29,576 1,237 0 0 0 2,100 0 28,713 29,060 2,375 31,435 (2,722) 446 (2,276) 192 (2,084)

8/29/2015 29,576 1,237 6 0 0 2,100 0 28,719 29,060 2,375 31,435 (2,716) 446 (2,270) 192 (2,078)

9/5/2015 29,576 1,237 6 12 493 2,100 0 28,214 29,060 2,375 31,435 (3,221) 446 (2,775) 192 (2,583)

9/12/2015 29,576 1,237 6 1,361 802 2,100 0 26,556 25,060 2,375 27,435 (879) 446 (433) 192 (241)(4,402)



















STUDY WEEK

(Week Beginning,

Saturday)



OPERABLE CAPACITY ANALYSIS Appendix

Possible Relief Under OP4 based on OP4 Appendix A

130

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. April 319 3

May 468 3

June – September 446 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

133 4

April 141 3

May 195 3

June – September 192 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 March 25, 2015. 4. The MW values are based on a 26,658 MW system load and the most recent voltage reduction test % achieved.

Possible Relief Under OP4 based on OP4 Appendix A

131

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 April 3,005 MW

May 3,208 MW

June – September 3,183 MW NOTES: 1. Based on Summer Ratings. Assumes 25% of total MW Settlement Only units <5 MW will be available and respond. 2. The actual load relief obtained is highly dependent on circumstances surrounding the appeals, including timing and the amount of advanced

notice that can be given. 3. The RTDR and RTEG MW values are based on FCM results as of March 25, 2015. 4. The MW values are based on a 26,658 MW system load and the most recent voltage reduction test % achieved.

A P R I L 1 0 , 2 0 1 5 | B O S T O N , M A

Vamsi ChadalavadaE 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

Winter 2014/15 Review

NEPOOL ParticipantsCommittee Report



2

Table of Contents

• 2014/15 Winter Reliability Program Page 3

• 2014/15 Winter Weather Page 9

• Winter Readiness Page 14

• 2014/15 Winter Operations Page 17

• Prices During 2014/15 Winter Page 37



2014/15 WINTER RELIABILITY PROGRAM



2014/15 Winter Reliability Program

– Oil Program• As of Dec 1, 2014:

– 3.8 million barrels of the initial inventory requirement hadbeen met for a maximum cost exposure of $68.7M

– 16 program units exceeded initial requirements, representingan additional 0.68 million barrels

– LNG Program• As of Dec 1, 2014:

– Current participation of 6 units, representing 500,000MMBTU, for a maximum cost exposure of $1.5M

– DR Program• As of Dec 1, 2014:

– 3 assets participated to provide 14 MW for a total cost of$75,600 (@$1,800/MW-Month)

4



2014/15 Winter Reliability Program

• Dual Fuel Commissioning (DFC) Program– Participation:

• 6 Units submitted intent to commission Dual Fuel Capability– 4 Units for 2014/15 (1,039 MW)– 2 Units for 2015/16 (735 MW)

• Total winter seasonal claimed capability commissioned is 1,774MW

– DFC Activity and related NCPC:• Units commissioned: 3 successful (722.5 MW), 1 outstanding

(316.9 MW), 2 pending (2015/16; 734.8 MW)• Total NCPC Commissioning Cap: $5.7M

– 2014/15: $3.56M– 2015/16: $2.19M

• NCPC incurred: $1.0M

5



Winter Reliability Program Results:Demand Response

• 1 of 30 possible dispatches used over a 5 hour period on12/4/2014

• Average performance exceeded the winter obligation– Audit conducted in January 2015 demonstrated that the winter

obligation was met incrementally to FCM obligations

6



2014/15 Winter Fuel Burn

• Winter Reliability Program Oil Burn– Total program fuel burn during December 2014 through February 2015

is 2,717,500 bbl– Total program oil burn last winter was 2,700,500 bbl

• Winter Reliability Program LNG Burns– None of the LNG that was contracted for this winter was utilized

7



2014/15 Winter Reliability Program Final Costsfor Oil, LNG and DR Components

• Winter Reliability Program Oil Costs– Total Oil Eligible for Program Payment as of March 15: 2,559,847 Barrels– Oil Program Cost (Pre-Penalties): $46.1M– Total Penalties: $2.2M– Total Oil Program Cost: $43.9M

• Winter Reliability Program LNG Costs– LNG Cost (Pre-Penalties): $1.5M– Total Penalties: $100K– Total LNG Program Cost: $1.4M

• Winter Reliability Program DR Costs– Total DR Program Capacity Cost: $75.6K

8



2014/15 WINTER WEATHER



Winter 2014/15 Compared to Winter 2013/14

• December 2014: Milder than previous year– Lower demand– Less restriction on Natural Gas system– Less need for oil

• January 2015: Colder average temperature but previous year hadpockets of extreme cold temperatures– Slightly lower energy demand– Less oil burned than last January

• February 2015: Coldest month in recent history when comparingaverage temperature and cumulative HDDs (data starts 1960)– Higher demand– High pipeline capacity utilization– Significantly more oil burned

10



Average Temperature Comparison

• Daily Average Temperature 2013/14 vs 2014/15

11



Average Temperature Comparison

• Sorted by Low to High Temperature, Monthly– Clearly milder December– Clearly colder February

12

Milder

ColderSimilar



Heating Degree Days by Month• Heating Degree Days (HDDs) apply a single value to describe

how cold a day is. More HDDs mean colder temperatures.

• HDDs show milder December and colder February

• January looks comparable, but 13/14 had higher highs andlower lows and resulted in a similar average

13



WINTER READINESS



Winter Preparations

• Prior to the start of the winter of 2014/15:– Prior year, still in effect:

• Advanced the Day Ahead Market Timeline to allow more time toprocure gas

• Replacement Reserve Pricing• Tighter criteria for FCM Reserve Shortage Events• Increased Coordination and Communication• Winter Preparedness Seminar with Designated Entities• Winter Reliability Program

– For Winter 14/15:• Energy Market Offer Flexibility Enhancements (December 3, 2014)• Expanded the Winter Reliability Program to include LNG and Dual

Fuel Conversions

15



Other Preparations for Winter – Coordinationand CommunicationISO-NE stepped up communications through:

• Regular conference calls with NPCC Reliability Coordinators– Beginning in December and continuing through the cold weather

• Regular communications with gas pipelines– Routine review of gas purchases via pipeline Electronic Bulletin Boards for

generators known to be committed on natural gas– Information Policy changes were made to improve gas-electric

coordination per FERC Order 787• Exchange of more detailed information on both the gas and electric side

proved helpful

• Winter preparedness seminars– ISO-NE offered both online and live training

• Fuel surveys– Initially monthly; became more frequent at different points in the winter

16



2014/15 WINTER OPERATIONS



Winter Operations Summary

• The New England Power Grid operated well throughout the winter

• Close coordination with generators and gas pipeline operatorshelped operate the grid reliably during really cold days

• Increased LNG injections were very helpful in maintaining gridreliability

• The Winter Reliability Program, was instrumental in augmenting thefuel security of the region, primarily by boosting oil inventory in theregion

• Cold weather in February depleted fuel supplies after mildDecember kept oil tanks fuller than last season

• Some problems late in the season with fuel barges getting throughthe ice and weather to dock and unload cargoes

18



Monthly Oil Inventory

• More oil as we entered into February 2015 than in 2014

• Significantly more oil depleted during February 2015

19



March Oil Inventory Surveys

• End of 2015 winter oil inventories – Less than 3 days at MostFacilities

20



On-Site Oil and Electricity Output DepletionBased on Fuel Survey Responses

Upper Left

• MaximumInventory

Lower Right

• Inventorydepletion

21



Pipelines Continue to be Primarily For Non-Power Use

• The natural gas pipeline infrastructure was built to primarilysupply firm customers

• Peak overall natural gas demand requires large volumes fromthe east (including LNG) to supplement constrained supplyfrom the West

• Majority of the pipeline capacity is for Local Gas DistributionCompanies

22



Pipelines Primarily For Non-Power Use

23



Pipelines Primarily For Non-Power Use; LNGEssential for Power Use

24



Natural Gas Demand On The Rise

• Multiple days of record breaking single-day natural gasdemand this year

• Continuing trend of rising average natural gas demand acrossall users

25



Pipeline Utilization:Highest Natural Gas Supply Days

All values shown as MMBTU scheduled

Pipeline Location Oper Capacity 2/5/2015 2/2/2015 2/3/2015 1/7/2015 2/6/2015 1/28/2015

Algonquin Stony Point 1,583,000 1,522,000 1,494,000 1,517,000 1,343,000 1,486,000 1,518,000

Tennessee Station 245 1,083,300 1,055,954 1,031,956 1,052,473 1,057,514 1,024,318 1,054,023

Iroquois Waddington** 1,150,000 1,159,707 1,057,020 1,149,931 1,004,092 1,239,817 1,164,471

M&NBaileyville(includes Canaport) 850,000 736,059 845,683 713,731 798,047 515,402 660,090

PNGTS E. Hereford 168,000 259,335 238,141 259,334 217,377 259,206 259,322

Total 4,834,300 4,733,055 4,666,800 4,692,469 4,420,030 4,524,743 4,655,906

AGT/TGP Distrigas 457,180 252,676 94,239 132,333 306,422 163,907 196,791

Algonquin Northeast Gateway 400,000 141,187 322,871 149,320 199,819 166,343 0

Total 5,691,480 5,126,918 5,083,910 4,974,122 4,926,271 4,854,993 4,852,697

** Not all gas is consumed in ISO-NE'sfootprint, especially Capacity at Iroquois

26



Rising Natural Gas Demand in New England

27



Oil More Economic Than Natural Gas, EspeciallyDuring February 2015

28



Colder Temps – Oil and Coal In RateDaily Energy Contribution From All Fuel Categories

29



Colder Temps – Oil and Coal In RateEnergy Contribution from Gas, Oil, and Coal

30



Significant Increase in LNG This Year

31



32

Observations from Winter OperationsLNG into New England Pipelines (shown in MMBTU scheduled)

Source: Genscape

December 2013 - February 2014

DECEMBER JANUARY FEBRUARY TOTAL FACILITY

Distrigas 1,013,199 815,439 932,475 2,761,113

Canaport 3,237,722 6,609,209 3,419,294 13,266,225

Northeast Gateway - - - -

TOTAL/MONTH 4,250,921 7,424,648 4,351,769 16,027,338

-

5,000,000

10,000,000

15,000,000

20,000,000

25,000,000

30,000,000

35,000,000

2013/2014

2014/2015

Scheduled Capacity

December 2014 - February 2015

DECEMBER JANUARY FEBRUARY TOTAL FACILITY

Distrigas 707,137 5,634,040 4,450,831 10,792,008

Canaport 2,681,902 6,177,325 9,270,340 18,129,567

Northeast Gateway - 1,070,443 1,605,378 2,675,821

TOTAL/MONTH 3,389,039 12,881,808 15,326,549 31,597,396



Global LNG Prices

33



Oil Prices Fell Dramatically this WinterEnd of day Commodity Futures Price Quotes for CrudeOil WTI (NYMEX)

34

Source: Nasdaq



Marginal Fuel This Winter

• Natural gas is thepredominant marginalfuel

• Oil was on the margin15.7% of the time

• All hours for Winter2014/15

35



Fleet Performance Overall Better Than LastWinter

36



PRICES DURING 2014/15 WINTER



Energy Pricing

• Fuel prices lower in 2014/15 than in 2013/14– Gas Prices down 46%– Oil Prices down 50%

• LMPs down 44%– DA and RT LMPs were closer, on average, than during previous two

winters– Energy Market down 45% due to lower LMPs

38



Energy Pricing

• NCPC totaled $34.9M– Down 68% from previous winter ($109.7M) and down 54% from

winter of 2012/13 ($76.1M)

39



Winter Gas Prices

$19.33

$10.70

$0

$5

$10

$15

$20

$25

$/M

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40

* Algonquin Citygate price, December – February average



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$0.00

$3.00

$6.00

$9.00

$12.00

$15.00

$18.00

$21.00

$24.00

$27.00

$30.00

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JUN

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JUL2

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JUN

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013

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$0.00

$40.00

$80.00

$120.00

$160.00

$200.00


Monthly Average Fuel Price and RT Hub LMP

41




Comparison of 2013/14 and 2014/15 WinterPrices: DA vs. RT LMPs ($/MWh)

42

Arithmetic Average

Dec’13-Feb’14 Hub NEMA CT ME NH VT RI SEMA WCMA

Day-Ahead $138.71 $139.98 $135.52 $133.33 $138.18 $136.40 $140.03 $140.07 $138.72

Real-Time $137.59 $138.52 $135.99 $125.43 $132.13 $133.65 $137.87 $138.21 $137.36

RT Delta % -0.8% -1.0% 0.3% -5.9% -4.4% -2.0% -1.5% -1.3% -1.0%

Dec’14-Feb’15 Hub NEMA CT ME NH VT RI SEMA WCMA

Day-Ahead $77.51 $77.88 $76.33 $73.80 $76.33 $76.61 $77.78 $77.89 $77.54

Real-Time $76.64 $77.52 $75.34 $71.76 $74.31 $74.89 $76.86 $77.22 $76.47

RT Delta % -1.1% -0.5% -1.3% -2.8% -2.6% -2.2% -1.2% -0.9% -1.4%

Annual Diff. Hub NEMA CT ME NH VT RI SEMA WCMA

Yr over Yr DA -44.1% -44.4% -43.7% -44.6% -44.8% -43.8% -44.5% -44.4% -44.1%

Yr over Yr RT -44.3% -44.0% -44.6% -42.8% -43.8% -44.0% -44.3% -44.1% -44.3%



Winter Wholesale Prices

• 30% of average daily real-timeprices were above $100/MWh, downfrom 64% last winter

• Average daily real-timeprices did not exceed $250this winter

• Energy market costs were$2.77B this winter, downfrom $5.05B last winter

43

2003-042004-05

2005-062006-07

2007-082008-09

2009-102010-11

2011-122012-13

2013-142014-15

05

101520253035404550

2003-04

2004-05

2005-06

2006-07

2007-08

2008-09

2009-10

2010-11

2011-12

2012-13

2013-14

2014-15

Nu

mb

ero

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ays

Daily Average Locational Marginal Prices



Uplift Payments to Participants Decreased

44

NCPC Dollars

2012 2013

2014 2015

Mill

ion

s

$0

$10

$20

$30

$40

$50

$60

$70

$80




Winter 2013-14 Winter 2014-15

Uplift Payments to Participants Decreased

45



Colder Cold

Net Change in Import Supply Between DA and RTat Peak Hour on Coldest Days, Winter 2014-15

• Increased coordination between neighboring areas inpreparation for winter led to fewer curtailments between DayAhead imports and Real Time imports

46

Mo

reIm

po

rts

inR

TLe

ssIm

po

rts

inR

T



Winter Operations Report Conclusion

• While operations this winter was relatively uneventful,challenges remain for future winters with fuel security andadditional retirements

• Increased usage of oil and coal units, with additionalretirements or colder weather, could limit generator outputdue to environmental limits

• The ISO will continue to work with stakeholders on addressingthe transition winters between now and 2017/18, when thePay-For-Performance design takes effect

47



New England power system performed well throughwinter 2014/2015Tuesday, April 7, 2015 at 10:30AMISO New England in Industry News & Developments, Inside ISO New England, energy efficiency, new englandstates, peak demand, system operations, wholesale prices

Now that the winter of 2014/2015 is one for the history books, this much we knowis certain: no two New England winters are alike. A confluence of regional and global factors,advance planning and preparations, and delayed cold weather during winter 2014/2015 helpedalleviate the operational issues and record-high prices seen during the previous winter.

The primary factors that helped ensure power system reliability in New England and keep pricevolatility in check, include:

• The 2014/2015 Winter Reliability Program provided incentives to generators to have oilinventory stored on site, or to have a contract for LNG deliveries to supplement pipelinegas supplies before the start of winter.

• December was mild, and the coldest winter weather didn’t arrive until February, when dayswere longer and electricity consumption was lower.

• More liquefied natural gas (LNG) supplies were drawn to New England from world LNGmarkets, because of the region’s high natural gas prices during the previous winter and highforward prices for delivery during winter 2014/2015.

• Global oil prices dropped dramatically during 2014, making oil-fired generation often moreeconomic to run than natural-gas-fired generation and dampening both gas and electricityprice volatility.

• Energy-efficiency measures helped reduce total power consumption and peak demand.

As a result, New England’s generating resources and high-voltage power grid performed wellthroughout December, January, and February. Nevertheless, natural gas pipeline constraintscontinue to affect grid operations, wholesale energy costs, and the resource mix used to meetdemand during the winter months.

2014/2015 winter weather

Weather is one of the biggest drivers of peak demand and overall power usage: mildertemperatures translate into lower demand, and extreme temperatures push up demand. While theregion experienced fairly moderate weather during December 2014, temperatures dropped inJanuary and became downright arctic in February. With an average monthly temperature of 16.9°F in New England, February 2015 was the coldest month on record, based on ISO New England

Page 1 of 9ISO Newswire - Updates

4/8/2015http://isonewswire.com/updates/2015/4/7/new-england-power-system-performed-well-throu...

historical statistics, which date back to 1960.

February 2015 set another record as the cold temperatures pushed up total energy usage higherthan any other February. Yet, when considering the weather and temperatures were mild inDecember and average for January, peak demand and total winter electricity consumption wereboth lower than in winter 2013/2014:

• Demand for power reached its highest level on January 8, 2015, at 20,556 MW; theprevious winter’s peak occurred on December 17, 2013, at 21,453 MW.

• New Englanders consumed 33,654 gigawatt-hours (GWh) of electricity from December2014 through February 2015, slightly less than the 33,991 GWh consumed during the sameperiod of the previous winter.

Although February was the coldest month, demand for electricity peaked in January for thiswinter period. As temperatures plummeted in February, consumer demand was lower because theholiday season had largely passed, which reduced the amount of electricity needed for decorativelighting. And in general, as the days grow longer, heating, lighting, and cooking activities don’tfall into such a narrow time frame when people arrive home.

Other reasons for lower peak demand and consumption include the frequent snow storms that ledto schools, businesses, and in some cases government offices closing, as well as the effects ofincreased energy-efficiency in New England. Compared to the previous winter, regional energy-

efficiency measures reduced peak demand by an additional 265 MW.

For detailed statistics, see the “Winter by the Numbers” tables below.

Winter power system operations

The New England power grid and the power plant fleet operated very well throughout thewinter’s varying temperatures, so that sufficient resources were available to meet peak demandand provide reserves at all times.



"Given the difficulties we experienced the last few winters, we expectedsimilarly challenging conditions this winter," said Peter Brandien, vice president of systemoperations at ISO New England. "But from a system operations standpoint, the season was fairlyuneventful overall, due mainly to preparations made well before the winter season began.

"First, close coordination with natural-gas-fired generators and natural gas pipeline operatorshelped ensure grid reliability even when temperatures plummeted and demand for gas and powerclimbed," continued Brandien. "Along with this, heavy injections of LNG into the eastern portionof New England’s system were helpful because this increased the amount of gas coming into theregion, while circumventing the pipelines bringing in gas from the west, which were alreadyrunning at full capacity throughout the winter. And once again, the Winter Reliability Programproved invaluable, significantly boosting oil inventory in the region before the start of winter. InFebruary, generation from oil-fired power plants was especially critical in meeting demand forpower when the weather turned bitterly cold, and also when LNG deliveries became intermittentwhen one LNG import terminal ran out of fuel and another terminal was unable to dock andunload cargoes because of poor weather conditions."

Significant market improvements that took effect in December 2014 also contributed toimproved generator performance. The energy market offer flexibility changes, for example, now allowgenerators to update their offers to sell energy during the operating day, so if the cost of fuel(e.g., natural gas) changes, they can reflect the updated price in their offers. Higher reserve priceshave also been placed into effect for times when the system has limited power reserves and is atheightened reliability risk. Both of these market changes increase the financial incentives forgeneration owners to improve their fuel supply arrangements and generating plant performance.

System operators implemented Operating Procedure 4, Actions during a Capacity Deficiency once during the

winter because of an event originating outside New England. On December 4, 2014, HydroQuébec experienced outages on two of its major transmission lines and had to significantly cutelectricity exports to New England and other neighboring areas. The ISO brought additionalgeneration online to maintain grid reliability in New England and also to provide support to ournorthern neighbors as they worked to restore their system to normal operations. OP-4 wasimplemented at 4:15 p.m. and was cancelled at 8:45 p.m. For the rest of the winter, powerimports from Québec were regular and steady, and helped meet regional demand for electricity.

Winter Reliability Program boosted oil inventory, helped ensure reliability through recordcold



Given the resource performance challenges and reliability risks to the grid during theprevious two winter seasons, ISO New England implemented a second Winter ReliabilityProgram for 2014/2015 to address potential fuel-availability issues. Several elements of thiswinter’s program were consistent with the first, but there were also some fundamentaldifferences, including the compensation structure. Under the 2014/2015 winter program,generators receive an end-of-season payment to help offset some—but not all—of the carryingcosts associated with leftover oil inventory or unused LNG contracts. This design change wasmade to encourage generators that burn oil to rely on upfront inventory, rather thanreplenishments, and to incentivize natural-gas-fired generators to contract for LNG as a peakingfuel to augment the use of pipeline gas. Read more about the structure of the program.

The program helped achieve the desired effect—by the start of the winter, the region was wellpositioned with fuel inventory: by December 1, 2014, 79 units (both oil-fired and dual-fuel) hadmore than 4 million barrels of oil in their fuel tanks. Like the previous winter, that oil inventorywas instrumental in allowing the region to withstand the severe cold weather conditions.

From December through February, the region burned 2,717,500 barrels of program oil. Datashowing the total amount of program oil used through March 15 (the end date of the oil aspect ofthe program) is being compiled.

While six natural-gas-fired generators participated in the winter program and arranged contractsfor LNG, none of the contracts were utilized, likely because the contracted prices were higherthan the cost of buying LNG or natural gas on the spot market this winter.

The 14 megawatts of demand-response resources participating in the program were activatedonce for a five-hour period during the OP-4 event in December.

Three resources with a total combined capacity of about 720 MW successfully commissioneddual-fuel capability this winter, under provisions of the Winter Reliability Program designed topromote these reliability-enhancing investments by power plant owners. Three other gas-firedfacilities have committed to becoming dual-fuel capable by next winter.

Further analysis of the program is underway and will be shared with stakeholders in the comingweeks, but preliminary figures show that the total program cost will come in under $50 million,which is below the $66 million cost of the first winter program.

Greater fuel availability, lower fuel prices helped reduce wholesale electricity prices

Wholesale electric energy prices during winter 2014/2015 were well below the previous winter’sprices: the average cost of wholesale electric energy from December 2014 through February2015 was $76.64/megawatt-hour (MWh), while last winter’s average price was $137.60/MWh.

The total cost of wholesale energy from December 2014 through February 2015 was $2.77billion, 45 percent less than the $5.05 billion for the same three-month period the previouswinter. The overall lower wholesale energy costs can be credited to increased supplies of LNG to



the region and lower oil and natural gas prices. For more information on wholesale prices, see the“Winter by the Numbers” tables below.

Source: Winter 2014-15 Energy MarketAssessment, FERC, October 16, 2014More LNG attracted to New EnglandLNG is a globally-priced commodity and its availability in New England is dependent onworldwide demand. New England’s record-high natural gas and wholesale energy prices duringwinter 2013/2014, along with high forward prices late last year, provided strong economicsignals to LNG suppliers to bring tankers to the region this winter. An October 2014 FERC analysis

noted that winter futures prices in New England for both natural gas and power were the highestin the US.

In addition, the estimated landing prices for LNG revealed that the New England region waspredicted to have the highest prices in the world—and nearly twice as high as prices in Europe,Asia, and South America.

Source: National Natural Gas Market Overview, FERC, December 2014 (slide 13). (Source data fromWaterborne Energy, Inc.)

According to the Northeast Gas Association (NGA), both the Distrigas LNG terminal in Everett,MA, and the Canaport LNG terminal in New Brunswick, Canada, recorded steady throughputthis winter, and the Northeast Gateway facility, located offshore from Gloucester, MA, received



its first LNG shipment in four years, in January 2015 (Source: Regional Market Update, Northeast GasAssociation, March 20, 2015, slide 9).

From December through February, New England saw the injection of about 31 Bcf of gas fromLNG imports into the region—nearly twice as much as the 16 Bcf of gas from LNG imports theprevious winter.

"LNG was in substantially greater supply this winter than last, and thisadditional LNG heightened competition in the wholesale fuels markets which, in turn, helpedmoderate the cost of both pipeline gas and LNG this past winter," explained Matthew White,Chief Economist at ISO New England. "Compared to winter 2013/2014, the increased fuelsupplies resulted in much lower price levels this winter."

However, while increased competition in the gas market helped to dampen prices over the courseof the winter, the amount of Marcellus shale gas that could be delivered to the region from thewest remained limited by New England’s constrained pipeline system. During many cold days inFebruary, daily spot-market natural gas prices hovered in a range of $20 to $30 per millionBritish thermal units (MMBtu), which is high by historical standards. These higher gas pricesincreased winter wholesale electricity prices: February’s average wholesale energy price was$126.70/MWh, which makes it the third-highest average monthly wholesale energy price in NewEngland. The highest and second-highest prices were logged the previous winter, during Januaryand February 2014, respectively.

Lower oil prices and diverse fuel mix also helped moderate energy prices, meet demandWorldwide oil prices fell to approximately half what they were the previous winter, whichdramatically reduced the cost of operating oil-fired power plants. While nuclear and natural gaswere the dominant fuels used to produce power this winter, oil and coal resources werecompetitively priced and, at times, were a large part of the fuel mix—especially during thecoldest month of February 2015. On some days, oil and coal together fueled more than 40% ofthe region’s power needs, as shown in the pie chart.



"The New England wholesale electricity market experienced the effects of the drop in oil prices,just as automobile drivers have seen relief at the gas pump over the past several months," Whiteexplained. "The plunge from $100/barrel oil in winter 2013/2014 to less than $50/barrel oil thiswinter made oil-fired power plants price-competitive with coal-fired and even high-efficiencygas-fired plants. Coupled with the increased competition in the natural gas markets that helpedkeep a lid on the price of natural gas for much of the winter, low oil prices put downwardpressure on the cost of wholesale energy, helping to curb wholesale power prices well belowthose of the previous winter of 2013/14."

Implications for future winters

Many of the factors that contributed to smooth power grid operations and lower wholesaleenergy prices this winter are difficult to predict, and resulted in part from changing conditions inglobal fuel markets. Importantly, it remains to be seen whether they will recur similarly in futurewinters.

Natural gas pipeline constraints

The interstate natural gas pipelines serving New England continue to beutilized at full or near-full capacity during the winter months, which contributes to higher priceshere compared to other US regions. Further, most of the natural gas flowing through pipelinesduring the winter serves customers using it to heat their homes and businesses. As more andmore residences and businesses convert to natural gas for heating purposes, the pipeline systemserving the region will become progressively more constrained, further limiting the gas supplyavailable to power generators in the winter. While utilities, private investors, and the states arediscussing various proposals for expanding pipeline capacity, any significant relief is at leastseveral years away.



LNG import variabilityLNG tankers follow the money around the world each winter. Consequently, the LNG importsthat helped increase gas supplies in the region this winter—and helped moderate prices—werehere because of last winter’s (2013/2014) high prices. If another part of the world experienceshigh LNG demand as the global economy recovers, global LNG suppliers may no longer findNew England their preferred destination in future winters. Lower LNG supplies in future winterswould exacerbate New England’s gas pipeline constraints and infrastructure challenges, andheighten the potential for a return to the high wholesale energy prices experienced in winter2013/2014.

Uncertainty of future oil pricesLow oil prices resulted in greater dispatch of oil-fired power plants this winter, which helped todampen the price of wholesale electricity. However, global oil markets—and therefore oilprices—are notoriously fickle. Should oil prices go back up, the cost of operating oil-fired powerplants will rise as well.

Generator environmental limitsIncreased operation of oil- and coal-fired plants comes with environmental costs for the region:greater air emissions. For example, New England’s generator air emissions figures increased in 2013,

as higher-emitting units were needed more often to serve peak demand and to make up fordecreased natural gas-fired generation during the winter months. Additionally, the runtimes ofgenerators that burn oil are limited by state and federal emissions restrictions and the potentialfor these limitations will continue to be a factor during future winter operations.

Resource retirementsThe continued retirements of aging oil and other non-gas generators from the region’s fleet ofpower plants will further increase New England’s reliance on natural gas for power productionand exacerbate natural gas infrastructure constraints. In 2014, two large power plants wentoffline permanently: the remaining coal and oil units at Salem Harbor station (585 MW) and theVermont Yankee Nuclear station (615 MW). Brayton Point Station—a 1,535 MW coal- and oil-powered plant that the region relied on heavily throughout the 2014/2015 winter—will be retiredby June 1, 2017, and as many as 6,000 MW of other non-gas resources are at risk for retirementin coming years. In total, the retirements from 2014 through 2018 represent more than 10% ofthe region’s generating capacity.

Ensuring reliability during the winter monthsISO New England has made longer-term changes to the Forward Capacity Market design, mostsignificantly Pay-for-Performance, which will create strong incentives for generators to firm up their

fuel supply and improve their overall performance. These changes will take effect in 2018. In theinterim, the ISO has used targeted reliability programs that have improved regional fuel adequacyand maintained grid reliability for the past two winters. Earlier this year, the Federal EnergyRegulatory Commission (FERC) required ISO New England to implement a market-basedsolution for the winters between now and 2018. Citing the difficulty in creating a market-based



solution on top of the existing patchwork of generator obligations, ISO New England has asked FERC topermit the continuation of the winter reliability programs—with an expanded scope to includemore resource types—until new performance and investment incentives take effect. If thisrequest isn’t accepted by FERC, the ISO will propose a seasonal increase in energy marketreserve pricing during times of system stress—the only market-based solution that can beimplemented before next winter. However, the ISO has concerns that changes to the energymarket may not provide the same assurances of “fuel in the tank” as the recent winter reliabilityprograms.

More information

For background on how natural gas infrastructure constraints, resource retirements, and otherchallenges are affecting the grid, see the 2015 Regional Electricity Outlook.

Article originally appeared on ISO Newswire (http://isonewswire.com/).See website for complete article licensing information.




91062543.1

M E M O R A N D U M

TO: NEPOOL Participants Committee Members and Alternates

FROM: Paul N. Belval, NEPOOL Counsel

DATE: April 3, 2015

RE: ISO New England Financial Assurance Policy and Billing PolicyChanges Related to Deposit Accounts

The Participants Committee will be asked at its April 10 meeting to support changes tothe ISO Financial Assurance Policy (the “FAP”) and the ISO Billing Policy (the “BillingPolicy”) related to deposit accounts maintained under the FAP and the ability of certain MarketParticipants not organized under U.S. law to use those deposit accounts as collateral. Thismemorandum summarizes the proposed changes (which have been included and posted with thismemorandum).

Pursuant to Section X of the FAP, a Market Participant that is required to post collateralmay provide a letter of credit or cash collateral. If a Market Participant chooses the cashcollateral option, that Market Participant must (1) open an investment account with BlackRock,Inc. or its affiliates (collectively, “BlackRock”), (2) complete and execute a Security Agreementand (3) complete and execute a Control Agreement (which, together with the SecurityAgreement, gives the ISO status as a “perfected,” or first priority, secured creditor with respectto the shares held in that Market Participant’s BlackRock account).

The cash provided is invested in one of six BlackRock investment options (the “LiquidityFunds”) listed on ISO New England’s (the “ISO”) website.1 BlackRock recently informed theISO that it was changing its internal compliance procedures to exclude foreign entities from theLiquidity Funds, due to concerns about compliance with U.S. securities laws. The ISO and wesubsequently engaged in several conversations with BlackRock to determine if BlackRock couldoffer alternatives to the Liquidity Funds in which foreign Market Participants could invest, whilestill providing the ISO with perfected secured creditor status. BlackRock ultimately concludedthat the only BlackRock funds available to foreign Market Participants would be offshore funds(e.g., organized in the Cayman Islands) that issue non-U.S. securities. Permitting the use of non-U.S. securities to act as collateral for a foreign Market Participant’s obligations presents a risk,however, that the ISO’s security interest in those securities would cease to have the first prioritystatus required under the FAP.

As a result of BlackRock’s new rules restricting foreign entities from investing in theLiquidity Funds, the ISO is proposing modifications to the FAP that would prohibit a foreignentity from using the BlackRock funds to satisfy their collateral requirements under the FAPunless that entity qualifies for an exemption from those BlackRock rules. The ISO is currently

1 The six options are BlackRock Fed Fund, BlackRock Muni-Cash, BlackRock MuniFund,BlackRock T-Fund, BlackRock Temp Cash, and BlackRock Temp Fund. If a Market Participant does notselect one of the investment options, the default investment is BlackRock Temp Fund.


-2-91062543.1

exploring a limited exemption with BlackRock that would allow Canadian Market Participantsthat meet the definition of “permitted client” under Canadian securities laws to invest in theLiquidity Funds. For these purposes, that exemption would require the applicable CanadianMarket Participant to have net assets of at least $25 million (as shown on its most recentlyprepared financial statements). BlackRock is seeking internal approvals of this exemption. TheISO will keep affected Market Participants updated on this process.

Foreign Market Participants that are currently invested in the BlackRock Liquidity Fundswill not be affected by the proposed FAP changes, and they will be allowed to maintain theirinvestments in the BlackRock Liquidity Funds. However, any foreign Market Participant that iscurrently invested in an offshore fund (e.g., BlackRock International Dollar Reserve Fund) andthat does not meet any applicable BlackRock exemptions will be required to obtain a letter ofcredit to satisfy its obligations under the FAP. Two Market Participants, both of which areCanadian companies, are currently invested in an offshore BlackRock fund as a result of anadministrative oversight. These Market Participants will be required to provide a letter of creditto the ISO unless BlackRock provides the limited exemption described above and thosecompanies qualify for that exemption. The ISO has notified both of these Market Participantsregarding this situation.

In addition to the above described changes, the ISO has proposed clean-up changes to theFAP and the Billing Policy to reflect the fact that the balances in deposit accounts under the FAPare maintained in securities, not in cash. Analogous changes will also be made to the forms ofstanding instructions for the ISO to use amounts on deposit in those accounts to pay ISOinvoices, although the changes to those standing instructions do not require ParticipantsCommittee action.

The NEPOOL Budget & Finance Subcommittee (the “Subcommittee”) discussed theproposed changes to the FAP and Billing Policy on its March 26 teleconference. None of theSubcommittee members on that teleconference objected to the proposed changes, althoughseveral noted that this change to BlackRock’s internal procedures follows a change last year thatrequired all Market Participants providing cash deposits to re-execute the Security Agreementand Control Agreement described above. The ISO will discuss those customer service concernswith BlackRock.

The following form of resolution could be used for Participants Committee action:

RESOLVED, that the Participants Committee supports the changes to the ISONew England Financial Assurance Policy and the ISO New England BillingPolicy related to deposit accounts provided by Market Participants, ascirculated to the Committee and discussed at this meeting, together with [anychanges agreed to at this meeting and ]such further non-substantive changesas the Chief Financial Officer of ISO New England and the Chairman of theBudget & Finance Subcommittee may approve.

Page 58

Best & Co. or “A” or better by S&P. The cost of the Credit Coverage obtained for each calendar year

shall be allocated to all Credit Qualifying Market Participants pro rata based, for each Credit Qualifying

Market Participant, on the average amount of the Invoices issued to that Credit Qualifying Market

Participant under the ISO New England Billing Policy in the preceding calendar year. Each Credit

Qualifying Market Participant shall provide the ISO with such information as may be reasonably

necessary for the ISO to obtain the Credit Coverage at the lowest possible cost.

X. ACCEPTABLE FORMS OF FINANCIAL ASSURANCE

Provided that the requirements set forth herein are satisfied, acceptable forms of financial assurance

include shares of registered or private mutual funds held in a shareholder account a cash deposit or a letter

of credit, each in accordance with the provisions of this Section X. All costs associated with obtaining

financial security and meeting the provisions of the ISO New England Financial Assurance Policy are the

responsibility of the Market Participant or Non-Market Participant Transmission Customer providing that

security (each a “Posting Entity”). Any Posting Entity requesting a change to one of the model forms

attached to the ISO New England Financial Assurance Policy which would be specific to such Posting

Entity (as opposed to a generic improvement to such form) shall, at the time of making that request, pay a

$1,000 change fee, which fee shall be deposited into the Late Payment Account maintained under the ISO

New England Billing Policy.

A. Shares of Registered or Private Mutual Funds in a Shareholder Account

Cash Deposit

Shares of registered or private mutual funds in a shareholder account are A cash deposit

submitted to the ISO provides an acceptable form of financial assurance to the ISO

provided that the Posting Entity providing the cash depositsuch collateral (i) completes

all required documentation to open an account with the financial institution selected by

the ISO, after consultation with the NEPOOL Budget and Finance Subcommittee, to hold

such cash deposit, (ii) completes and executes a security agreement (“Security

Agreement”) in the form of Attachment 1 to the ISO New England Financial Assurance

Policy and is in compliance with the Security Agreement, and (iii) completes and

executes a Control Agreement in the form posted on the ISO website and is in

compliance with the Control Agreement. Any material variation from the form of

Security Agreement included in Attachment 1 to the ISO New England Financial

Assurance Policy or the form of Control Agreement posted on the ISO website must be

approved by the ISO after consultation with the NEPOOL Budget and Finance

Formatted: Indent: Left: 1"


Page 59

Subcommittee and, in the case of the Security Agreement, filed with the Commission.

To the extent any amount of shares contained in the shareholder account portion of a cash

deposit is no longer required hereunder, the ISO shall return such portion collateral to the

Posting Entity providing it within four (4) Business Days of a request to do so.

If the amount of cash depositedcollateral maintained in the shareholder account is below

the required level (including by reason of losses on investments of that cash deposit), the

Posting Entity shall immediately replenish or increase the deposit amount to the required

level. The cash depositcollateral will be held in an account maintained in the name of the

Posting Entity providing the cash deposit and invested in the investment selected by that

Posting Entity from a menu of investment options listed at the time on the ISO’s website,

which menu will be approved by the NEPOOL Budget and Finance Subcommittee, with

discounts applied to the cash investedinvestments in certain of such options if and as

determined by the NEPOOL Budget and Finance Subcommittee. If a Posting Entity

providing a cash deposit does not select an investment for that depositits collateral, that

cash depositcollateral will be invested in the “default” investment option selected by the

ISO and approved by the NEPOOL Budget and Finance Subcommittee from time to time.

Interest earnedAny dividends and distribution on such investment will accrue to the

benefit of the Posting Entity. The ISO may sell or otherwise liquidate such investments

at its discretion to meet the Posting Entity’s obligations to the ISO. In no event will the

ISO or NEPOOL or any NEPOOL Participant have any liability with respect to the

investment of a cash depositcollateral under this Section X.A.

Notwithstanding the foregoing, an investment in shares of a registered fund in a

shareholder account shall not be an acceptable form of financial assurance for a Posting

Entity that is not a U.S. Person, as defined in Regulation S under the Securities Act of

1933, as amended, unless the financial institution selected by the ISO allows such Posting

Entity to invest in the investment options listed at the time on the ISO’s website or the

Posting Entity is invested in the investment options listed on the ISO’s website as of

March 19, 2015.

B. Letter of Credit

An irrevocable standby letter of credit provides an acceptable form of financial assurance

to the ISO. For purposes of the ISO New England Financial Assurance Policy, the letter


Page 9

c) Adjustments Reflecting Compliance with an Order of the Commission or other

Regulatory or Judicial Authority With Jurisdiction. Adjustments required to

effect compliance with an order of the Commission (or any other regulatory or

judicial authority with jurisdiction to interpret and/or enforce the provisions of

the Governing Documents) shall be completed by the ISO in compliance with

such order. The costs of any such re-billing to the ISO shall be allocated among

the Covered Entities in accordance with the provisions of the Transmission,

Markets and Services Tariff.

d) Nothing in this Section 2.6 shall affect resettlements of the New England

Markets under Market Rule 1.

SECTION 3 -PAYMENT PROCEDURES.

All Payments (including prepayments as described in Section 3.1(e) below) made by the ISO will in all

instances be made by EFT or in immediately available funds payable to the account designated to the ISO

by the Covered Entity to which such Payment is due. Payments made by Covered Entities shall be made

by EFT to the account designated by the ISO.

Section 3.1 -Invoice Payments.

a) Payment Date. Except in the case of special billings, all Charges due shall be

paid to and received by the ISO not later than the second (2nd) Business Day

after the Invoice on which they appeared was issued (the “Invoice Date”) so long

as the ISO sends such Invoice to the Covered Entities by 11:00 a.m. Eastern

Time on the Invoice Date. If the ISO sends an Invoice after 11:00 a.m. Eastern

Time on the Invoice Date, the charges on such Invoice will be paid not later than

the third (3rd) Business Day after such Invoice Date. Notwithstanding the

foregoing, a Non-Market Participant Transmission Customer will in no event be

required to make a payment on an Invoice any sooner than provided in Section II

of the Transmission, Markets and Services Tariff.

b) Right to Alter Payment Date. The ISO may establish the dates on which

payments are due in the case of a special billing; provided, however, that, (i)


Page 10

payment on any special billing invoice shall not be due prior to the second (2nd)

Business Day after the Invoice is issued, and (ii) a Non-Market Participant

Transmission Customer shall not be required to make a payment on an Invoice

any sooner than provided in Section II of the Transmission, Markets and Services

Tariff.

c) Payments Received by the ISO. Each Covered Entity owing monies to the ISO,

either in the ISO’s individual capacity, or as agent for NEPOOL, shall remit the

amount shown on its Invoice no later than the date such payment is due.

Disputed Amounts shall be paid in accordance with clause (d) below. All

Invoices shall be paid by EFT, except that (i) Covered Entities (other than

Unqualified New Market Participants and Returning Market Participants under

the ISO New England Financial Assurance Policy that are not Provisional

Members) may, and any Provisional Member must, pay any Invoice for ISO

Charges (but not for Transmission Charges) by instructing the ISO (either on a

case-by-case basis or pursuant to a standing instruction) in writing to draw on a

cash depositcollateral maintained in a shareholder account created pursuant to the

ISO New England Financial Assurance Policy provided by such Covered Entity

under the ISO New England Financial Assurance Policy for such Invoice,

provided that the failure of a Provisional Member to provide such an instruction

to the ISO shall not, in and of itself, be deemed to be a default under the ISO

New England Billing Policy and (ii) any Covered Entity may instruct the ISO to

auto-debit an account identified by that Covered Entity to pay all Invoices issued

by the ISO and in such case the Covered Entity will direct the bank or other

institution holding that account to permit the ISO to auto-debit that account to

pay all such Invoices on the date they are due. Any instruction to pay any

Invoice by drawing on collateral maintained in a shareholder account a cash

deposit or to auto-debit an account must be received by no later than the first

Business Day following the date of such Invoice. The amount of a Covered

Entity’s collateral maintained in a shareholder account cash deposit will

immediately be reduced by the amount drawn to pay an Invoice for ISO Charges

pursuant to a standing instruction. Nothing set forth in this section will reduce

the financial assurance obligation otherwise applicable to any Covered Entity that

instructs the ISO to draw on collateral maintained in a shareholder account a cash


Page 11

deposit or to auto-debit an account to pay an Invoice, and the ISO is not liable for

any default resulting from a draw on collateral maintained in a shareholder

account a cash deposit to pay an Invoice or for any overdraft charges resulting

from any auto-debit.

d) Payments Pending Resolution of a Dispute. Any Covered Entity that disputes the

amount due, including an amount due for Participant Expenses, on any Invoice

for service other than transmission service under Section II of the Transmission,

Markets and Services Tariff shall pay to the ISO all amounts due on such

Invoice, including any such Disputed Amounts. Such payment shall in no way

prejudice the right of such Covered Entity to seek reimbursement of such

Disputed Amounts, including accrued interest on such amounts at the

Commission’s standard rate, set forth in 18 C.F.R. Section 35.19, pursuant to the

Billing Dispute Resolution Procedures provided in Section 6 below.

Any Covered Entity that disputes the amount due on any Invoice for transmission

service under the Transmission, Markets and Services Tariff shall pay to the ISO

all amounts not in dispute in accordance with the ISO New England Billing

Policy and shall pay (or, in the case of an auto-debit payment or a payment for

ISO Charges pursuant to a standing instruction, as described above, direct the

ISO to pay) such Disputed Amounts into an independent escrow account

designated by the ISO, which account shall be established at a banking institution

acceptable to the ISO and the Covered Entity challenging the amount due and

shall accrue interest at a prevailing market rate. Such amount in dispute shall be

held in escrow pending the resolution of such dispute in accordance with the

applicable Governing Document(s). The shortfall of funds available to pay

Remittance Advices resulting from the amount in dispute being held in an escrow

account shall be allocated among the Covered Entities according to the two-step

allocation process described in Section 3.3 (for ISO Charges) and in Section 3.4

(for Transmission Charges) for the applicable type of Covered Entity disputing

the Charges, subject to payment to all Covered Entities being allocated a portion

of the shortfall, with applicable interest (if any), once the dispute is resolved with

the funds in such escrow account or with other amounts provided by the Covered

Entity losing such dispute.


Page 12

e) Prepayments. A Covered Entity may prepay any Invoice, in whole or in part,

according to the following procedures:

(i) only two such prepayment shall be made by any Covered Entity in any calendar

week, and no prepayments shall be made on a Friday;

(ii) each prepayment will be applied only to the next subsequent Invoice issued;

(iii) prepayments and payments for issued Invoices must be made in separate wire

transfers;

(iv) for purposes of calculating a Covered Entity’s financial assurance obligations

under the ISO New England Financial Assurance Policy, prepayments will be

applied first to Hourly Charges, then any remaining prepayment will offset the

Covered Entity’s financial assurance obligations on a dollar-for-dollar basis;

(v) if ISO Charges and Transmission Charges are billed on separate Invoices, then

separate prepayments must be made for those ISO Charges and Transmission

Charges (the ISO will account for each prepayment separately and will only

apply each prepayment to the designated Charges);

(vi) if a prepayment exceeds the amount due on the next subsequent Invoice issued,

then the prepayment will be applied to that Invoice first, and then to the extent

any amount is left after paying that Invoice, the Covered Entity making that

prepayment may direct at the time of the prepayment that the excess be deposited

with its collateral maintained in a shareholder account created cash deposit

maintained under pursuant to the ISO New England Financial Assurance Policy,

and if the Covered Entity does not direct the ISO to make that deposit, the excess

will be returned to the Covered Entity. Under either circumstance, the deposit in

the to the shareholder account cash deposit or the return of excess funds will

occur on the next date when the ISO pays Remittances; and

(vii) all prepayments will be held in the ISO’s settlement account until the Invoice

payments are due, and no interest will be paid to any Covered Entity on any

prepayments provided by it.

Section 3.2 -ISO Payment of Remittance Advice Amounts. The Payment Date for a Remittance

Advice shall be the fourth (4th) Business Day following the date on which the Remittance Advice

was issued (the “Remittance Advice Date”) so long as the ISO sends such Remittance Advice by


41670279.4

Form of Standing Instruction

[______], 200201[_]

Billing Department

ISO New England Inc.

One Sullivan Road

Holyoke, MA 01040

RE: Standing Instruction to pay Invoices per Section 3.1(c) of the ISO New England Billing

Policy (the “Billing Policy”)

Please accept this letter as a standing instruction (this “Instruction”) for [Complete Company

Name and ISO Company Customer ID] (the “Customer”) to pay all Invoices issued by ISO New

England Inc. (the “ISO”), to the extent of available cashcollateral, from the cash deposit amount

on hand with the ISOshareholder account maintained with BlackRock Liquidity Funds (or its

affiliates, “BlackRock”), as that amount may be replenished from time to time (the “Deposit”).

In connection with this Instruction, the Customer acknowledges and agrees to the following:

(a) The ISO may draw on the Deposit at any time to pay an Invoice issued to the

Customer. If there are insufficient funds available after the liquidation of all

investments in the Deposit, the ISO will draw down the full amount of the

Deposit and may notify the Customer that there are insufficient funds available in

the Deposit to pay the Invoice, but shall not be obligated to notify the Customer.

(b) The Deposit will be held in the Customer’s account established with BlackRock

Institutional Management Corporation (“BlackRock”) pursuant to the Control

Agreement among the Customer, the ISO and BlackRock (the “Control

Agreement”) or, if the Customer does not have such an account with BlackRock,

in the ISO’s account with BlackRock. If the Deposit is held in the Customer’s

account with BlackRock, the Deposit will be invested in the investment option

selected by the Customer pursuant to the Control Agreement. If the Customer has

not selected such an investment option or if the Deposit is held in the ISO’s

account with BlackRock, the Deposit shall be invested in the “Default

Investment” option identified from time to time by the ISO and approved by the

New England Power Pool (“NEPOOL”) Budget and Finance Subcommittee,

pursuant to the ISO New England Financial Assurance Policy for [Market

Participants] (the “Financial Assurance Policy”). All income generated by the

Deposit will be added to the amount of the Deposit and will be reinvested in the

applicable investment described above. All losses to the Deposit as a result of it

being so invested or any liquidation of such Default Investment in connection

with a draw on the Deposit will be deducted from the Deposit.


41670279.4 -2-

(c) If the Deposit is held in the ISO’s account with BlackRock, the Deposit shall at all

times remain the property of the ISO, provided that the ISO shall only use the

Deposit as set forth herein.

(d) The Customer shall be responsible for all fees, costs and expenses due to or

incurred by the ISO in connection with the maintenance of the Deposit and the

other transactions contemplated by this Instruction, including if applicable and

without limitation a pro rata share of BlackRock’s regular fees for establishing

and maintaining the account in which the Deposit is held. The Customer shall

pay, or reimburse the ISO for, such fees, costs and expenses promptly upon

receiving a request therefor which may be included either on the Customer’s

settlement Invoice or on a separate non-settlement Invoice issued to the Customer.

(e) The Customer agrees that (a) the ISO, NEPOOL and BlackRock is each released

from any and all liabilities arising from the terms of this Instruction and its

compliance with the terms hereof, except to the extent that such liabilities arise

from its own gross negligence or willful misconduct and (b) the Customer shall at

all times indemnify and save harmless the ISO, NEPOOL and BlackRock and

their officers, directors, members, trustees, employees, agents and representatives

(each, an “Indemnified Party”) from and against any and all claims, actions and

suits of others arising out of the terms of this Instruction or the compliance with

the terms hereof, except to the extent that such arises from such Indemnified

Party’s gross negligence or willful misconduct, and from and against any and all

liabilities, losses, damages, costs, charges, counsel fees and other expenses of

every nature and character arising by reason of the same.

(f) The Deposit shall not constitute an acceptable form of financial assurance under

the Financial Assurance Policy unless the Customer takes all steps required under

the Financial Assurance Policy with respect thereto, including without limitation

executing and delivering a Security Agreement (as defined in the Financial

Assurance Policy) and a related Control Agreement.

This Instruction will remain in effect until such time as the ISO receives written notice from the

Customer revoking this Instruction; provided that any revocation notice must be received by the

ISO at least five business days prior to the effective date of that revocation notice. All amounts

held in the Deposit will be returned to the Customer within five (5) business days after the ISO’s

receipt of a request that the Deposit be returned. In the event that the Customer revokes this

Instruction but does not at the same time request a return of all amounts held in the Deposit, then

during the time between the revocation of this Instruction and the requested return of the

amounts in the Deposit, (i) the ISO will continue to hold such amounts in accordance with

paragraphs (b), (c), (d), (e) and (f) above, (ii) the ISO may, but shall not be required to, draw on

the Deposit to pay any Invoice issued to the Customer that is not paid in full within the time

provided by the Billing Policy, and (iii) any draw by the ISO on the Deposit pursuant to this

sentence will not excuse a Payment Default under the Billing Policy or a Financial Assurance

Default under the Financial Assurance Policy.


41670279.4 -3-

Nothing set forth in this Instruction modifies the rights and obligations of the ISO or the

Customer under the Billing Policy, the Financial Assurance Policy, all other relevant documents

and applicable law.

If this Instruction is acceptable to you, please sign a copy of this Instruction in the space

indicated below and return it to the Customer.

Sincerely,

_____________________________

Authorized Signer

Complete Company Name

Address

Phone Number

E-Mail Address

ACCEPTED AND AGREED:

ISO NEW ENGLAND INC.

By:___________________________

Name:

Title:


41672012.2

Form of One-Time Instruction

[______], 200201[_]

Billing Department


One Sullivan Road

Holyoke, MA 01040

RE: Instruction to pay Invoice per Section 3.1(c) of the ISO New England Billing Policy (the

“Billing Policy”)

Please accept this letter as an instruction (this “Instruction”) for [Complete Company Name and

ISO Company Customer ID] (the “Customer”) to pay the Customer’s Invoice to be issued by ISO

New England Inc. (the “ISO”) on [Date] (the “Invoice”), to the extent of available cashcollateral,

from the cash deposit amount on hand with the ISOshareholder account maintained with

BlackRock Liquidity Funds (or its affiliates, “BlackRock”), as that amount may be replenished

from time to time (the “Deposit”). In connection with this Instruction, the Customer

acknowledges and agrees to the following:

(a) The ISO may draw on the Deposit at any time to pay the Invoice. If there are

insufficient funds available after the liquidation of all investments in the Deposit,

the ISO will draw down the full amount of the Deposit and may notify the

Customer that there are insufficient funds available in the Deposit to pay the

Invoice, but shall not be obligated to notify the Customer.

(b) The Deposit will be held in the Customer’s account established with BlackRock

Institutional Management Corporation (“BlackRock”) pursuant to the Control

Agreement among the Customer, the ISO and BlackRock (the “Control

Agreement”) or, if the Customer does not have such an account with BlackRock,

in the ISO’s account with BlackRock. If the Deposit is held in the Customer’s

account with BlackRock, the Deposit will be invested in the investment option

selected by the Customer pursuant to the Control Agreement. If the Customer has

not selected such an investment option or if the Deposit is held in the ISO’s

account with BlackRock, the Deposit will be invested in the “Default Investment”

option identified from time to time by the ISO and approved by the New England

Power Pool (“NEPOOL”) Budget and Finance Subcommittee, pursuant to the ISO

New England Financial Assurance Policy for [Market Participants] (the

“Financial Assurance Policy”). All income generated by the Deposit will be

added to the amount of the Deposit and will be reinvested in the applicable

investment described above. All losses to the Deposit as a result of it being so


41672012.2 -2-

invested or any liquidation of such Default Investment in connection with a draw

on the Deposit will be deducted from the Deposit.

(c) If the Deposit is held in the ISO’s account with BlackRock, the Deposit shall at all

times remain the property of the ISO, provided that the ISO shall only use the

Deposit as set forth herein.

(d) The Customer shall be responsible for all fees, costs and expenses due to or

incurred by the ISO in connection with the maintenance of the Deposit and the

other transactions contemplated by this Instruction, including if applicable and

without limitation a pro rata share of BlackRock’s regular fees for establishing

and maintaining the account in which the Deposit is held. The Customer shall

pay, or reimburse the ISO for, such fees, costs and expenses promptly upon

receiving a request therefor which may be included either on the Customer’s

settlement invoice or on a separate non-settlement invoice issued to the Customer.

(e) The Customer agrees that (a) the ISO, NEPOOL and BlackRock is each released

from any and all liabilities arising from the terms of this Instruction and its

compliance with the terms hereof, except to the extent that such liabilities arise

from its own gross negligence or willful misconduct and (b) the Customer shall at

all times indemnify and save harmless the ISO, NEPOOL and BlackRock and

their officers, directors, members, trustees, employees, agents and representatives

(each, an “Indemnified Party”) from and against any and all claims, actions and

suits of others arising out of the terms of this Instruction or the compliance with

the terms hereof, except to the extent that such arises from such Indemnified

Party’s gross negligence or willful misconduct, and from and against any and all

liabilities, losses, damages, costs, charges, counsel fees and other expenses of

every nature and character arising by reason of the same.

(f) The Deposit shall not constitute an acceptable form of financial assurance under

the Financial Assurance Policy unless the Customer takes all steps required under

the Financial Assurance Policy with respect thereto, including without limitation

executing and delivering a Security Agreement (as defined in the Financial

Assurance Policy) and a related Control Agreement.

This Instruction will remain in effect until such time as the ISO receives written notice from the

Customer revoking this Instruction; provided that any revocation notice must be received by the

ISO at least five business days prior to the effective date of that revocation notice. All amounts

held in the Deposit will be returned to the Customer within five (5) business days after the ISO’s

receipt of a request that the Deposit be returned. In the event that the Customer revokes this

Instruction but does not at the same time request a return of all amounts held in the Deposit, then

during the time between the revocation of this Instruction and the requested return of the

amounts in the Deposit, (i) the ISO will continue to hold such amounts in accordance with

paragraphs (b), (c), (d), (e) and (f) above, (ii) the ISO may, but shall not be required to, draw on

the Deposit to pay any invoice issued by it to the Customer that is not paid in full within the time

provided by the Billing Policy, and (iii) any draw by the ISO on the Deposit pursuant to this


41672012.2 -3-

sentence will not excuse a Payment Default under the Billing Policy or a Financial Assurance

Default under the Financial Assurance Policy.

Nothing set forth in this Instruction modifies the rights and obligations of the ISO or the

Customer under the Billing Policy, the Financial Assurance Policy, all other relevant documents

and applicable law.

If this Instruction is acceptable to you, please sign a copy of this Instruction in the space

indicated below and return it to the Customer.

Sincerely,

_____________________________

Authorized Signer

Complete Company Name

Address

Phone Number

E-Mail Address

ACCEPTED AND AGREED:

ISO NEW ENGLAND INC.

By:___________________________

Name:

Title:



91068074.2

At the April 10, 2015 Participants Committee meeting, you will be asked to consider andvote on revisions to Market Rule 1, which have been proposed by Exelon Generation Company,LLC (Exelon), to allow certain Existing Capacity Resources to include overhead/centralizedcosts in their Static De-List Bids (up to a specified default rate). A copy of these proposedrevisions are included with this memorandum (see Attachment A). As discussed below, theserevisions were presented to, but not recommended by, the Markets Committee.

Under the current FCM rules, Existing Capacity Resources must submit a Static De-ListBid if they wish to withdraw supply from the capacity market for a single Capacity CommitmentPeriod. The Internal Market Monitor (IMM) evaluates each Static De-List Bid to determine, inpart, whether the de-list bid is consistent with a resource’s net Going Forward Costs.1 Thecurrent rules allow a Resource to include in its Static De-List Bid net Going Forward Costs thatthe IMM determines are otherwise avoidable if the Resource is permitted to withdraw from thecapacity market for one year.

Exelon is seeking modifications to these rules, arguing that the current rules do notpermit the inclusion of sufficient overhead/centralized costs in Static De-List Bids. Under itsproposed Market Rule 1 revisions, any Existing Capacity Resource that is fueled by oil, coal ornatural gas and that is 40 years or older would be permitted to include up to $0.65/kW-month inoverhead costs in its Static De-List Bid. Further details on this proposal are provided in apresentation prepared by Exelon that was previously circulated to the Markets Committee (seeAttachment B).

At its March 10-11, 2015 meeting, the Markets Committee considered and failed to passa resolution to recommend Participants Committee support for these Exelon-proposed changes,with a 39.36% Vote in favor.2 The IMM had reviewed the Exelon proposal and indicated to theMarkets Committee ahead of its vote that the IMM did not support the proposed changes. TheIMM’s explanation for its position was detailed in a memorandum (dated March 3, 2015) that

1 See Section III.13.1.2.3.2.1.3 (Net Going Forward Costs) to Market Rule 1.2 The individual Sector votes were Generation (17.17% in favor, 0% opposed, 1 abstention),

Transmission (2.86% in favor, 14.31% opposed), Supplier (15.03% in favor, 2.14% opposed, 8abstentions), Alternative Resources (4.29% in favor, 9.84% opposed, 3 abstentions), Publicly OwnedEntity (0% in favor, 17.17% opposed, 17 abstentions), and End User (0% in favor, 17.17% opposed, 3abstentions). The Provisional Member Group Seat vote results were 0.01% in favor and 0% opposed.

M E M O R A N D U M


FROM: Sebastian M. Lombardi, NEPOOL Counsel

DATE: April 3, 2015

RE: Exelon’s FCM Proposal re Overhead Costs in Static De-List Bids


-2-

91068074.2

was shared with the Markets Committee and is included in the materials circulated with this item(see Attachment C).

The following form of resolution may be used for Participants Committee action:

RESOLVED, that the Participants Committee supports revisions to MarketRule 1 to allow overhead/centralized costs to be included, up to a specifieddefault rate, in Static De-List Bids, as proposed by Exelon GenerationCompany, LLC, and as circulated to this Committee in advance of thismeeting, together with [any changes agreed to by the Participants Committeeat this meeting and] such non-substantive changes as may be approved by theChair and Vice-Chair of the Markets Committee.

EXELON PROPOSAL(Overhead Expenses: Mitigation of Static De-List Bids)

III.13.1.2.3.2. Review by Internal Market Monitor of Bids from Existing Generating

Capacity Resources.

For purposes of this Section III.13.1.2.3.2, a Static De-List Bid, Permanent De-List Bid, or Export Bid

shall be associated with a pivotal supplier if, using the best available estimates of FCA Qualified Capacity

available at that time: (1) at the Forward Capacity Auction Starting Price, the total amount of FCA

Qualified Capacity of all Existing Capacity Resources in the New England Control Area minus the

Installed Capacity Requirement (net of HQICCs) is less than or equal to the greater of:

(a) the amount of FCA Qualified Capacity from all of the Existing Capacity Resources controlled by

the Lead Market Participant for the resource submitting the bid multiplied by 1.1; and

(b) the amount of FCA Qualified Capacity from all of the Existing Capacity Resources controlled by

the Lead Market Participant for the resource submitting the bid plus 200 MW;

or (2) where the bid is associated with a resource in an import-constrained Capacity Zone, if at the

Forward Capacity Auction Starting Price, the total amount of FCA Qualified Capacity of all Existing

Capacity Resources in the import-constrained Capacity Zone minus the Local Sourcing Requirement for

the import-constrained Capacity Zone is less than or equal to the greater of:

(a) the amount of FCA Qualified Capacity from all Existing Capacity Resources in the import-

constrained Capacity Zone controlled by the Lead Market Participant for the resource submitting

the bid multiplied by 1.1; and

(b) the amount of FCA Qualified Capacity from all of the Existing Capacity Resources controlled by

the Lead Market Participant for the resource submitting the bid plus 100 MW.

In making this determination, the total amount of FCA Qualified Capacity of all Existing Capacity

Resources will be reduced by an amount equal to the total of all pending Non-Price Retirement Requests

and Permanent De-List Bids other than those submitted by the Lead Market Participant for the resource

being evaluated, and the amount of capacity from all of the Existing Capacity Resources controlled by the

Lead Market Participant for the resource will include any capacity subject to a pending Non-Price

Retirement Request or Permanent De-List Bid. The determination whether a Lead Market Participant is

pivotal will be included in the qualification determination notification described in Section III.13.1.2.4. If

the applicable Installed Capacity Requirement (net of HQICCs) and Local Sourcing Requirement are not

finalized at the time that the Internal Market Monitor must make this determination, then the Internal

Market Monitor shall use the best available estimates of those values available at that time, and shall

publish those estimated values to the ISO website no later than the date that the qualification

determination notifications are issued.


Attachment A


III.13.1.2.3.2.1. Static De-List Bids, Export Bids Above the Dynamic De-List Bid Threshold,

and Permanent De-List Bids Above the Dynamic De-List Bid Threshold.

The Internal Market Monitor shall review each Static De-List Bid, each Export Bid the Dynamic De-List

Bid Threshold, and each Permanent De-List Bid above the Dynamic De-List Bid Threshold to determine

whether the bid is consistent with: (1) the Existing Generating Capacity Resource’s net going forward

costs (as determined pursuant to Section III.13.1.2.3.2.1.2); (2) reasonable expectations about the

resource’s Capacity Performance Payments (as determined pursuant to Section III.13.1.2.3.2.1.3); (3)

reasonable risk premium assumptions (as determined pursuant to Section III.13.1.2.3.2.1.4); and (4) the

resource’s reasonable opportunity costs (as determined pursuant to Section III.13.1.2.3.2.1.5). Sufficient

documentation and information about each of these bid components must be included in the Existing

Capacity Qualification Package to allow the Internal Market Monitor to make such determinations. The

entire de-list submittal shall be accompanied by an affidavit executed by a corporate officer attesting to

the accuracy of the reported costs, the reasonableness of the estimates and adjustments of costs that

would otherwise be avoided if the resource were not required to meet the obligations of a listed resource,

and the reasonableness of the expectations and assumptions regarding Capacity Performance Payments

and risk premiums, and shall be subject to audit upon request by the ISO.

III.13.1.2.3.2.1.1. Internal Market Monitor Review of De-List Bids.

The Internal Market Monitor may seek additional information from the Lead Market Participant

(including information about the other existing or potential new resources controlled by the Lead Market

Participant) after the qualification deadline to address any questions or concerns regarding the data

submitted, as appropriate. The Internal Market Monitor shall review all relevant information (including

data, studies, and assumptions) to determine whether the bid is consistent with the resource’s net going

forward costs, reasonable expectations about the resource’s Capacity Performance Payments, reasonable

risk premium assumptions, and reasonable opportunity costs. In making this determination, the Internal

Market Monitor shall consider, among other things, industry standards, market conditions (including

published indices and projections), resource-specific characteristics and conditions, portfolio size, and

consistency of assumptions across that portfolio.

III.13.1.2.3.2.1.1.1. Review of Permanent De-List Bids and Export Bids.

(a) In the case of a Permanent De-List Bid or an Export Bid from a resource associated with a Lead

Market Participant that is found to be not pivotal by the Internal Market Monitor pursuant to the


Attachment A


determination described in Section III.13.1.2.3.2, then the bid shall be entered into the Forward Capacity

Auction as described in Section III.13.2.3.2(b).

(b) In the case of a Permanent De-List Bid or an Export Bid from a resource associated with a Lead

Market Participant that is found to be pivotal by the Internal Market Monitor pursuant to the

determination described in Section III.13.1.2.3.2 , if the Internal Market Monitor determines that the bid

is consistent with the Existing Generating Capacity Resource’s net going forward costs, reasonable

expectations about the resource’s Capacity Performance Payments, reasonable risk premium assumptions,

and reasonable opportunity costs, then the bid shall be entered into the Forward Capacity Auction as

described in Section III.13.2.3.2(b).

(c) In the case of a Permanent De-List Bid or an Export Bid from a resource associated with a Lead

Market Participant that is found to be pivotal by the Internal Market Monitor pursuant to the

determination described in Section III.13.1.2.3.2, if the Internal Market Monitor determines, after due

consideration and consultation with the Lead Market Participant, as appropriate, that the bid is not

consistent with the resource’s net going forward costs, reasonable expectations about the resource’s

Capacity Performance Payments, reasonable risk premium assumptions, and reasonable opportunity costs,

then the bid will be rejected. Where a de-list bid is rejected pursuant to this Section III.13.1.2.3.2.1.1.1(c),

both the qualification determination notification described in Section III.13.1.2.4 and the informational

filing made to the Commission as described in Section III.13.8.1(a) shall include an explanation of the

reasons that the de-list bid was rejected based on the Internal Market Monitor review and the resource’s

net going forward costs, reasonable expectations about the resource’s Capacity Performance Payments,

reasonable risk premium assumptions, and reasonable opportunity costs as determined by the Internal

Market Monitor. The Lead Market Participant for such a resource may elect to have the ISO-determined

bid entered into the Forward Capacity Auction as described in Section III.13.2.3.2(b) by so indicating in a

filing with the Commission in response to the informational filing described in Section III.13.8.1(a).

Such a filing, and notification to the ISO of any such election, shall be made in accordance with the terms

of Section III.13.8.1(b) and shall not limit the other rights provided under that section. A Lead Market

Participant making such an election shall be prohibited from challenging pursuant to Section III.13.8.1(b)

the Internal Market Monitor’s determinations regarding the resource’s net going forward costs, reasonable

expectations about the resource’s Capacity Performance Payments, reasonable risk premium assumptions,

and reasonable opportunity costs. If no such election is made, the Existing Generating Capacity Resource

will be entered into the Forward Capacity Auction as described in Section III.13.2.3.2(c) or as otherwise

directed by the Commission. In no case shall rejection of a de-list bid by the Internal Market Monitor


Attachment A


restrict the ability of the resource to dynamically de-list at prices below the Dynamic De-List Bid

Threshold.

III.13.1.2.3.2.1.1.2. Review of Static De-List Bids.

(a) In the case of a Static De-List Bid from a resource associated with a Lead Market Participant that

is found to be not pivotal by the Internal Market Monitor pursuant to the determination described

in Section III.13.1.2.3.2, then the bid shall be entered into the Forward Capacity Auction as

described in Section III.13.2.3.2(b); provided however, that no later than 7 days after the issuance

by the ISO of the qualification determination notification described in Section III.13.1.2.4, the

Lead Market Participant may elect to: (i) withdraw the Static De-List Bid entirely, in which case

the Existing Generating Capacity Resource will be entered into the Forward Capacity Auction as

described in Section III.13.2.3.2(c); or (ii) submit revised prices for the Static De-List Bid for the

resource at prices equal to or less than the highest price indicated in the initial Static De-List Bid

as approved by the Internal Market Monitor and greater than the Dynamic De-List Bid Threshold.

Where revised prices are submitted, the Static De-List Bid must nonetheless comply with the

requirements of Section III.13.1.2.3.1.1. In no case shall withdrawal of a Static De-List Bid

pursuant to this subsection restrict the ability of the resource to dynamically de-list at prices

below the Dynamic De-List Bid Threshold.

(b) In the case of a Static De-List Bid from a resource associated with a Lead Market Participant that

is found to be pivotal by the Internal Market Monitor pursuant to the determination described in

Section III.13.1.2.3.2, if the Internal Market Monitor determines that the bid is consistent with the

Existing Generating Capacity Resource’s net going forward costs, reasonable expectations about

the resource’s Capacity Performance Payments, reasonable risk premium assumptions, and

reasonable opportunity costs , then the bid shall be entered into the Forward Capacity Auction as

described in Section III.13.2.3.2(b); provided however, that no later than 7 days after the issuance

by the ISO of the qualification determination notification described in Section III.13.1.2.4, the

Lead Market Participant may elect to: (i) withdraw the Static De-List Bid entirely, in which case

the Existing Generating Capacity Resource will be entered into the Forward Capacity Auction as

described in Section III.13.2.3.2(c); or (ii) submit revised prices for the Static De-List Bid for the

resource at prices equal to or less than the highest price indicated in the initial Static De-List Bid

as approved by the Internal Market Monitor and greater than the Dynamic De-List Bid Threshold.

Where revised prices are submitted, the Static De-List Bid must nonetheless comply with the

requirements of Section III.13.1.2.3.1.1. In no case shall withdrawal of a Static De-List Bid


Attachment A


pursuant to this subsection restrict the ability of the resource to dynamically de-list at prices

below the Dynamic De-List Bid Threshold.

(c) In the case of a Static De-List Bid from a resource associated with a Lead Market Participant that

is found to be pivotal by the Internal Market Monitor pursuant to the determination described in

Section III.13.1.2.3.2, if the Internal Market Monitor determines, after due consideration and

consultation with the Lead Market Participant, as appropriate, that the bid is not consistent with

the resource’s net going forward costs, reasonable expectations about the resource’s Capacity

Performance Payments, reasonable risk premium assumptions, and reasonable opportunity costs,

then the bid will be rejected. Where a de-list bid is rejected pursuant to this Section

III.13.1.2.3.2.1.1.2(b), both the qualification determination notification described in Section

III.13.1.2.4 and the informational filing made to the Commission as described in Section

III.13.8.1(a) shall include an explanation of the reasons that the de-list bid was rejected based on

the Internal Market Monitor review and the resource’s net going forward costs, reasonable

expectations about the resource’s Capacity Performance Payments, reasonable risk premium

assumptions, and reasonable opportunity costs as determined by the Internal Market Monitor. In

such a case, no later than 7 days after the issuance by the ISO of the qualification determination

notification described in Section III.13.1.2.4, the Lead Market Participant may elect to submit

revised prices for the Static De-List Bid for the resource at prices equal to or less than the

resource’s net going forward costs, reasonable expectations about the resource’s Capacity

Performance Payments, reasonable risk premium assumptions, and reasonable opportunity costs

as determined by the Internal Market Monitor and greater than the Dynamic De-List Bid

Threshold. Where revised prices are submitted, the Static De-List Bid must nonetheless comply

with the requirements of Section III.13.1.2.3.1.1. A Lead Market Participant making such an

election shall be prohibited from challenging pursuant to Section III.13.8.1(b) the Internal Market

Monitor’s determinations regarding the resource’s net going forward costs, reasonable

expectations about the resource’s Capacity Performance Payments, reasonable risk premium

assumptions, and reasonable opportunity costs. If no such election is made, the Existing

Generating Capacity Resource will be entered into the Forward Capacity Auction as described in

Section III.13.2.3.2(c) or as otherwise directed by the Commission. If no such election is made,

and the Existing Generating Capacity Resource is entered into the Forward Capacity Auction as

described in Section III.13.2.3.2(c), then nothing in this subsection shall restrict the ability of the

resource to dynamically de-list at prices below the Dynamic De-List Bid Threshold.


Attachment A


III.13.1.2.3.2.1.2. Net Going Forward Costs.

The Lead Market Participant for an Existing Generating Capacity Resource that submits a Static De-List

Bid, Export Bid above the Dynamic De-List Bid Threshold, or Permanent De-List Bid above the

Dynamic De-List Bid Threshold that is to be reviewed by the Internal Market Monitor shall report net

going forward costs using ISO spreadsheets and forms provided, and may supplement this information

with other evidence as deemed necessary. A Static De-List Bid, Export Bid above the Dynamic De-List

Bid Threshold, or Permanent De-List Bid above the Dynamic De-List Bid Threshold shall be considered

consistent with the Existing Generating Capacity Resource’s net going forward costs based on a review of

the data submitted in the following formula. To the extent possible, all costs and operational data used in

this calculation shall be the cumulative actual data for the Existing Generating Capacity Resource from

the most recent full Capacity Commitment Period available.

[GFC – (IMR – PER)] x InfIndex

(CQSummer, kw) x (12,months)

Where:

GFC = annual going forward costs, in dollars. These are costs that might otherwise be avoided or not

incurred if the resource were not subject to the obligations of a listed capacity resource during the

Capacity Commitment Period (i.e., maintaining a constant condition of being ready to respond to

commitment and dispatch orders). Costs that are not avoidable in a single Capacity Commitment Period

and costs associated with the production of energy are not to be included. Service of debt is not a going

forward cost. Staffing, maintenance, capital expenses, and other normal expenses that would be avoided

only in the absence of a Capacity Supply Obligation may be included. Staffing, maintenance, capital

expenses, and other normal expenses that would be avoided only if the resource were not participating in

the energy and ancillary services markets may not be included, except in the case of a resource that has

indicated in the submission of a Static De-List Bid or Permanent De-List Bid that the resource will not be

participating in the energy and ancillary services markets during the Capacity Commitment Period (and

thereafter, in the case of a Permanent De-List Bid). For any Existing Generating Capacity Resource that is

fueled by oil, coal or natural gas and that is 40 years or older, overhead costs may be included either: (i) at

a default rate up to $0.65/kW-month; or (ii) pursuant to the methodology prescribed in this Section

III.13.1.2.3.2.1.2. These costs shall be reported to the ISO using the spreadsheet provided on the ISO

website by any Existing Generating Capacity Resource submitting a Static De-List, Permanent De-List

Bid, or Export Bid, shall be accompanied by a signed affidavit, and shall be subject to audit upon request


Attachment A


by the ISO. To the extent that the Capacity Commitment Period data used to calculate these data do not

reflect known and measurable costs that would or are likely to be incurred in the relevant Capacity

Commitment Period, the Internal Market Monitor shall also consider adjustments submitted, provided the

costs are based on known and measurable conditions and supported by appropriate documentation to

reflect those costs.

CQSummerkW = capacity seeking to de-list in kW. In no case shall this value exceed the resource’s

summer Qualified Capacity.

IMR = annual infra-marginal rents, in dollars. In the case of a resource that has indicated in the

submission of a Static De-List Bid or Permanent De-List Bid that the resource will not be participating in

the energy and ancillary services markets during the Capacity Commitment Period (and thereafter, in the

case of a Permanent De-List Bid),this value shall be calculated by subtracting all submitted cost data

representing the cumulative actual cost of production (total expenses related to the production of energy,

e.g. fuel, actual consumables such as chemicals and water, and, if quantified, incremental labor and

maintenance) from the Existing Generating Capacity Resource’s total ISO market revenues. In the case of

a resource that has not indicated in the submission of a Static De-List Bid or Permanent De-List Bid that

the resource will not be participating in the energy and ancillary services markets during the Capacity

Commitment Period, this value shall be $0.00. As soon as practicable, the resource’s total ISO market

revenues used in this calculation shall be calculated by the ISO and available to the Lead Market

Participant upon request.

PER = resource-specific annual peak energy rents, in dollars. As soon as practicable, this value shall be

calculated by the ISO and available to the Lead Market Participant upon request.

At the option of the Lead Market Participant, the cumulative production costs for each of the most recent

three Capacity Commitment Periods may be submitted and the annual infra-marginal rents calculated for

each year. The Lead Market Participant may then specify two of the three years to be averaged and

subsequently used as the IMR value. Upon exercising such option, the PER value used shall be an

average of the PER values for the two years selected

InfIndex = inflation index. infIndex = (1 + i)4


Attachment A


Where: “i” is the most recent reported 4-Year expected inflation number published by the Federal

Reserve Bank of Cleveland at the beginning of the qualification period. The specific value to be used

shall be specified by the ISO and available to the Lead Market Participant.

III.13.1.2.3.2.1.3. Expected Capacity Performance Payments.



Dynamic De-List Bid Threshold that is to be reviewed by the Internal Market Monitor shall also provide

documentation separately detailing the expected Capacity Performance Payments for the resource. This

documentation must include expectations regarding the applicable Capacity Balancing Ratio, the number

of hours of reserve deficiency, and the resource’s performance during reserve deficiencies.

III.13.1.2.3.2.1.4. Risk Premium.



Dynamic De-List Bid Threshold that is to be reviewed by the Internal Market Monitor shall also provide

documentation separately detailing any risk premium included in the bid. This documentation should

address all components of physical and financial risk reflected in the bid, including, for example,

catastrophic events, a higher than expected amount of reserve deficiencies, and performing scheduled

maintenance during reserve deficiencies. Any risk that can be quantified and analytically supported and

that is not already reflected in the formula for net going forward costs described in Section

III.13.1.2.3.2.1.2 may be included in this risk premium component. In support of the resource’s risk

premium, the Lead Market Participant may also submit an affidavit from a corporate officer attesting that

the risk premium submitted is the minimum necessary to ensure that the overall level of risk associated

with the resource’s participation in the Forward Capacity Market is consistent with the participant’s

corporate risk management practices.

III.13.1.2.3.2.1.5. Opportunity Costs.

To the extent that an Existing Generating Capacity Resource submitting a Static De-List Bid, Export Bid

above the Dynamic De-List Bid Threshold, or Permanent De-List Bid above the Dynamic De-List Bid

Threshold has additional opportunity costs that are not reflected in the net going forward costs, expected

Capacity Performance Payments, or risk premium components of the bid, the Lead Market Participant

must include in the Existing Capacity Qualification Package evidence supporting such costs. Opportunity

costs associated with major repairs necessary to restore decreases in capacity as described in Section


Attachment A


III.13.1.2.2.4, capital projects required to operate the plant as a capacity resource or other uses of the

resource shall be considered, provided such costs are substantiated by evidence of a repair plan,

documented business plan and fundamental market analysis, or other independent and transparent trading

index or indices as applicable. Substantiation of opportunity costs relying on sales in reconfiguration

auctions or risk aversion premiums shall not be considered sufficient justification.

III.13.1.2.3.2.2. [Reserved.]

III.13.1.2.3.2.3. Administrative Export De-List Bids.

The Internal Market Monitor shall review each Administrative Export De-List Bid associated with a

multi-year contract entered into prior to April 30, 2007 in the first Forward Capacity Auction in which it

clears. An Administrative Export De-List Bid shall be rejected if the Internal Market Monitor determines

that the bid may be an attempt to manipulate the Forward Capacity Auction, and the matter will be

referred to the Commission in accordance with the protocols set forth in Appendix A to the Commission’s

Market Monitoring Policy Statement (111 FERC ¶ 61,267 (2005)).

III.13.1.2.3.2.4. Static De-List Bids for Reductions in Ratings Due to Ambient Air

Conditions.

A Lead Market Participant may submit a Static De-List Bid for up to the megawatt amount that the Lead

Market Participant expects will not be physically available due to the difference between the summer

Qualified Capacity at 90 degrees and the expected rating of the resource at 100 degrees. The ISO shall

verify during the qualification process that the rating is accurate. Such Static De-List Bids may be entered

into the Forward Capacity Market at prices up to and including the Forward Capacity Auction Starting

Price, subject to validation of the physical limit. Static De-List Bids for reductions in ratings due to

ambient air conditions shall not be subject to the review described in Section III.13.1.2.3.2 and need not

include documentation for that purpose.


Attachment A

Capital and Overhead ExpenseMitigation in Static DeList BidsMarch 10, 2015


Attachment B

Overview

The FCM must allow facilities to reflect their reasonableexpectations of cost and risk in delist offers• Particularly for older units with limited lifetimes, we cannot “hope” for higher, future

clearing prices to cover costs that are not reflected in delist bids.

• We have had significant difficulty getting our estimates of actual costs in delist bids.Our presentation is focused on two areas: Corporate Overheads, and CapitalExpenditures.

• Exelon’s proposal is tariff guidelines that will allow for specific offer caps:• These are not necessarily prices at which the market will clear. The market

could clear higher or lower for many other reasons. The ultimate offerrepresents the price at which the unit owner is truly willing to make the unitavailable for the Commitment Period.

• As caps, the resource owner may wish to offer at lower levels depending on thespecific circumstances.

• Addressing these problems is critical to a well-functioning market. Failure to correctthem may force more units to make uneconomic retirement decisions. This is aproblem for consumers, affected generators, and in some cases, system reliability.

2


Attachment B

Overhead CostsProblem Statement: The IMM does not allow the inclusion of any overhead/centralizedcosts in Static DeList bids.

For owners of multiple generation sites, certain services are centralized in order to minimizecosts, such as:― Engineering & Project Management

― Safety, Training, Outage Management

― Supply

― Traditional Corporate functions like Finance, Accounting, Legal, Human Resources, Communications, and Information Technology

The IMM seems to allow inclusion of only the direct costs of people dedicated to operating theplant, as they are captured in the plant-specific O&M. Yet in companies managing a portfolio,there is a large amount of shared costs that appear ineligible to go into delist offers.― The current tariff language incents market participants to decentralize costs – that is make them plant-specific. While

this is inefficient and increases cost, it seems to be the only way that costs can be recovered in delists.

― These are real, incremental costs of operating a power plant. Failing to allow recovery means that the facility is losing money, and therefore is a candidate for retirement. That retirement could be inefficiently early if costs are not allowed inoffers.

― Uneconomic retirements raise cost to consumers, and are a problem for resource owners.

Exelon has reviewed many of its previous delist bids, reliability contracts and recent sales ofassets and the range of overhead costs allocated to the various transactions ranged fromapproximately $0.50/kW-month and $1.60/kW-month. Therefore Exelon is proposing an up to$0.65 default rate for those resources which are 40 years and older and choose not to gothrough the tariffed avoided cost process.

3


Attachment B

Capital Expenditures (1/3)Problem Statement: An older fossil unit which makes a decision to retire on a year by year basiscannot reflect this year to year decision in their capital cost allocations in their delist bid.

ISO-NE guidelines allow for “incremental capital expenditures” to be recovered at a rateprescribed in the tariff:

The “remaining life” in these schedules may be very different from what the owner actuallyexpects.

Particularly for older resources, there may be little expectation of future capacity revenuesbeyond the Commitment Period for which the offer applies.

Under today’s rules, to be included in delists, CapEx (to which the above recovery rates apply)must typically be linked to making the unit available in a specific Commitment Period. This canbe exceedingly difficult. Capital expenditures are an ongoing process, budgeted in each andevery operating year. While all of the costs are necessary to make the unit reliable andavailable for dispatch, associating every dollar and project with a specific delivery year can bedifficult and subjective.

4

ISO-NE Capital Cost Recovery Factors


Attachment B

Capital Expenditures (2/3)Problem Statement: Current FCM rules do not allow for a reasonable amount of capital to beincluded in the delist offer; tariff changes must be made to ensure reasonable capital recoverygiven current market risks, particularly for older units which make their decision to remain in themarket on a year-by-year basis.

• A 40-year old fossil unit which decides to remain in the market can only recover a fraction of its expectedcapital expenditures under the existing tariff. The issue lies in both the forced (5+ year) amortizationschedule, and the difficulty in attributing individual CapEx dollars to a specific Commitment Period – asdescribed on the prior slide. This structure fails to recognize that:

1. If the unit fails to clear in the prompt year’s auction, it will likely decide to reduce or eliminate allscheduled capital improvements from that day forward – including those moneys scheduled in previousyears but as of yet unspent. The owner may then simply maintain the unit at a minimum level necessaryto meet its residual capacity supply obligations.

2. It is likely that the unit will either retire if they don’t clear or may wait to see the auction results in thefollowing year before retiring.

Proposed Rule Change: For fossil units 40 years and older, all capital expenditures that have notbeen spent but are planned for any dates included in the period beginning with the subsequentcalendar year following the delist bid submission through the end of the first calendar yearduring the delivery period, will be multiplied by the appropriate Capital Recovery Factor and maybe included in the Net Going Forward Cost calculation. We are proposing a 4-year recoveryperiod, because that would allow ¼ of each of 4 years’ capital to be included in consecutiveyears’ delists. In this way we need not attribute a specific CapEx dollar to a specificCommitment Period, but each CapEx dollar is only recovered once. See example on thefollowing page.

Presentation Title5


Attachment B

Capital Expenditures (3 of 3)

6

FCA 9 Delist Bid 2015 2016 2017 2018 Total

CapEx $15.0 M $20.6 M $2.1 M $5.3 M $43.0 M

CapEx $2.08/kW-mo $2.86/kW-mo $0.29/kW-mo $0.74/kW-mo $5.97/kW-mo

Allowed Recovery Rate 31.5% 31.5% 31.5% 31.5% 31.5%

Allowed CapEx in DeList Bid $0.66/kW-mo $0.90/kW-mo $0.09/kW-mo $0.13/kW-mo $1.78/kW-mo

Current ISO-NE Capital Cost Recovery Factors Proposed ISO-NE Capital Cost Recovery Factors


Attachment B

memo


One Sullivan Road, Holyoke, MA 01040-2841

www.iso-ne.com T 413 535 4000

To: Markets Committee Members

From: ISO-NE Internal Market Monitor

Date: March 3, 2015

Subject: Going Forward Costs in De-List Bids

This memo is in response to Exelon’s February 11, 2015 proposal to the NEPOOL Markets Committee

to make Tariff changes related to how the Internal Market Monitor (“IMM”) evaluates overhead and

capital expenditures in Static Delist Bids. Exelon proposal would allow participants to add $0.65/kW-

month to their Static Delist Bid as a default avoidable overhead cost and allow accelerated cost

recovery of capital expenditures for fossil units 40 years and older.

The IMM does not support Exelon’s proposal. The IMM believes that the existing Tariff provides

sufficient flexibility to allow the inclusion of avoidable Going Forward Costs (“GFC”) – including

documented avoidable overhead costs - in Static Delist Bids, as well as accelerated cost recovery of

capital expenditures for units nearing the end of their economic life. Additionally, the IMM does not

believe that establishing a default amount of corporate overhead is the proper market solution to

Exelon’s concern.

Avoidable Overhead Costs:

As discussed in the attached memo the IMM presented to the NEPOOL Markets Committee on

January 14, 2015, GFCs may include costs which are centralized to gain efficiencies across a portfolio.

The inclusion of avoidable GFCs in a resource’s de-list bid is currently allowed in the existing Tariff

language. Typically, these costs are included in the Administrative and General section of the de-list

workbook. The IMM believes it is reasonable to assume that, in the absence of a Capacity Supply


Attachment C

March 3, 2015

Page 2 of 13




Obligation (“CSO”) for a single year, a resource may avoid a portion of certain corporate expenses.

Given the variety of approaches corporations use to account for and allocate overhead and

administrative costs, the IMM believes it appropriate that the participant submitting a Static Delist Bid

present a methodology by which they identify and account for costs which are truly avoidable for a

single year. The IMM reviewed past Static Delist Bid submissions, and identified several instances

where participants demonstrated to the IMM’s satisfaction that certain overhead costs were avoidable.

The IMM defines “avoidable expenses” as those expenses which will not be incurred in the event that a

de-list bid clears the auction and does not receive a CSO. The IMM is willing to discuss with

participants (in advance of the submission deadline if requested) their proposed methodology to help

focus their data collection and analysis.

While GFCs require documentation and further discussion, capital costs are a more straight-forward

concept.

Capital Cost Recovery:

The IMM believes the current Tariff provides sufficient flexibility for participants to reflect their multi-

year capital investment plans, investment risks and annualized cost recovery. Using the example in

Table 1 below from Exelon’s February 11, 2015 presentation to the NEPOOL Markets Committee, the

IMM constructed a capital cost analysis, based on the current Tariff provisions, that achieves the same

outcome.


CapEx $15.0 M $20.6 M $2.1 M $5.3 M $43.0 M


Allowed Recovery

Rate 31.50% 31.50% 31.50% 31.50% 31.50%

Allowed CapEx in

DeList Bid $0.66/kW-mo $0.90/kW-mo $0.09/kW-mo $0.13/kW-mo $1.78/kW-mo

Table 1


Attachment C

March 3, 2015

Page 3 of 13




The current Tariff allows participants to request the IMM evaluate their Static Delist Bid using a

different pre-tax weighted average cost of capital than the 10% default value used to determine the

annual rates of capital cost recovery in the table in Section III.12.1.2.3.2.5 of the Tariff.1

To achieve a recovery rate of 31.5% in Exelon’s example, a participant may request the IMM evaluate

their Static Delist Bid using a pre-tax weighted average cost of capital of approximately 17.3%. The

participant would be required to support such a cost of capital, but if a resource is approaching the end

of its useful economic life (e.g., fossil units 40 years and older), it is reasonable to assume a pretax cost

of capital for the asset greater than the default 10% rate.

In the case of capital investments made prior to the start of the Capacity Commitment Period, if there is

economic benefit received by the resource during the years leading up to the commitment period, the

IMM believes it is appropriate to deduct all or a portion of the annual benefit from the original

investment to properly reflect the costs and benefits of making the investment. For this example, we

assumed a small economic benefit received ahead of the commitment period to illustrate the point.

That reduction is shown below on the second line, and the net expenditure is then converted to a kW-

month basis.


CapEx $15.0 M $20.6 M $2.1 M $5.3 M $43.0 M

Benefit Received $2.14 M $1.73 M $0.00 M $0.00 M $3.87 M

CapEx, net of

benefits received $12.86 M $18.87 M $2.1 M $5.3 M $39.13 M


Allowed Recovery

Rate 31.50% 31.50% 31.50% 31.50% 31.50%

Allowed CapEx in

DeList Bid $0.56/kW-mo $0.83/kW-mo $0.09/kW-mo $0.13/kW-mo $1.61/kW-mo

Conclusion

For the reasons stated above, the IMM cannot support the Exelon proposal. The IMM is committed to

working with participants to accurately reflect their expected business conditions and requirements in

1 The formula and table from the Tariff are included in the IMM’s January 14, 2015 memo.


Attachment C

March 3, 2015

Page 4 of 13




their Static Delist Bids. The IMM does not believe adding a default rate of $0.65/kW-month for

overhead costs accurately reflects the avoidable overhead costs of existing generation. Lastly, the IMM

believes the existing Tariff adequately allows for the inclusion of documented avoidable overhead costs

and the accelerated recovery of capital investments.


Attachment C

March 3, 2015

Page 5 of 13




Appendix

The following was presented to the NEPOOL Markets Committee in a memo dated January 14, 2015

Introduction

At the NEPOOL Markets Committee meeting on December 10, 2014, Exelon presented information on

how overhead costs and capital expenditures may or may not be included in Static De-list Bids

submitted in the Forward Capacity Market (“FCM”).

This memo does not directly address Exelon’s presentation. Rather, the purpose of this memo is to (1)

summarize the current Tariff provisions that govern the inclusion of overhead and capital costs in Static

De-list Bids, (2) summarize two recent Commission orders related to the inclusion of overhead and

capital costs in Static De-list Bids and (3) illustrate for the Markets Committee, through numerical

examples, the Internal Market Monitor’s (“IMM”) approach to determine avoidable overhead and

capital costs.

In advance of the Forward Capacity Auction (“FCA”), Existing Capacity Resources must submit de-list

bids if they wish to withdraw supply from the capacity market at prices above the dynamic de-list bid

threshold.2 The capacity may be withdrawn for a single Capacity Commitment Period via a Static De-

list Bid, exported to another control area via an Export De-list Bid, or removed permanently from the

capacity market via a Permanent De-list Bid. A bid that is entered into the auction will clear (that is,

the capacity will not receive a Capacity Supply Obligation, or “CSO”) the FCA if the clearing price is

equal to or less than the de-list bid price.

The IMM must review Static, Export, and Permanent De-list Bids submitted by participants.

Specifically, the IMM must determine if the de-list bid is consistent with the four cost components

comprising a de-list bid; (1) the participant’s net Going Forward Costs (“GFC”) for the resource, (2) the

participant’s reasonable expectations of the resource’s Capacity Performance Payments, (3) a

reasonable estimate of the resource’s risk premium, and (4) incremental capital expenditures associated

2 Resources may remove capacity below the dynamic de-list bid threshold within the FCA. There is no

requirement to submit information to ISO-NE in advance of the auction in order to submit a dynamic de-list

bid.


Attachment C

March 3, 2015

Page 6 of 13




with maintaining a CSO, which are included as a component of net GFC. Beginning with the Tariff

provisions, we will set the groundwork for describing the IMM’s process.

Tariff Provisions:

Sections III.13.1.2.3.2.1.2 and III.13.1.2.3.2.5 of the tariff define the criteria for including overhead and

capital costs in Static De-list Bids.

Net Going Forward Costs

III.13.1.2.3.2.1.2. Net Going Forward Costs

The Lead Market Participant for an Existing Generating Capacity Resource that

submits a Static De-List Bid, Export Bid above the Dynamic De-List Bid Threshold,

or Permanent De-List Bid above the Dynamic De-List Bid Threshold that is to be

reviewed by the Internal Market Monitor shall report net going forward costs using

ISO spreadsheets and forms provided, and may supplement this information with

other evidence as deemed necessary. A Static De-List Bid, Export Bid above the

Dynamic De-List Bid Threshold, or Permanent De-List Bid above the Dynamic De-

List Bid Threshold shall be considered consistent with the Existing Generating

Capacity Resource’s net going forward costs based on a review of the data submitted

in the following formula. To the extent possible, all costs and operational data used in

this calculation shall be the cumulative actual data for the Existing Generating

Capacity Resource from the most recent full Capacity Commitment Period available.

Where:

GFC = annual going forward costs, in dollars. These are costs that might otherwise be

avoided or not incurred if the resource were not subject to the obligations of a listed

capacity resource during the Capacity Commitment Period (i.e., maintaining a

constant condition of being ready to respond to commitment and dispatch orders).

Costs that are not avoidable in a single Capacity Commitment Period and costs

associated with the production of energy are not to be included. Service of debt is not

a going forward cost. Staffing, maintenance, capital expenses, and other normal

expenses that would be avoided only in the absence of a Capacity Supply Obligation

may be included. Staffing, maintenance, capital expenses, and other normal expenses

that would be avoided only if the resource were not participating in the energy and

ancillary services markets may not be included, except in the case of a resource that

has indicated in the submission of a Static De-List Bid or Permanent De-List Bid that

the resource will not be participating in the energy and ancillary services markets


Attachment C

March 3, 2015

Page 7 of 13




during the Capacity Commitment Period (and thereafter, in the case of a Permanent

De-List Bid). These costs shall be reported to the ISO using the spreadsheet provided

on the ISO website by any Existing Generating Capacity Resource submitting a Static

De-List, Permanent De-List Bid, or Export Bid, shall be accompanied by a signed

affidavit, and shall be subject to audit upon request by the ISO. To the extent that the

Capacity Commitment Period data used to calculate these data do not reflect known

and measurable costs that would or are likely to be incurred in the relevant Capacity

Commitment Period, the Internal Market Monitor shall also consider adjustments

submitted, provided the costs are based on known and measurable conditions and

supported by appropriate documentation to reflect those costs.

In summary, GFC are incremental costs that would only be incurred if the resource were to have a

CSO. For example, if total resource-related overhead costs are $2.00 million with a CSO and $1.75

million without a CSO, then $0.25 million would be considered incremental to having a CSO and may

be avoidable. The Market Participant must clearly demonstrate these costs can be eliminated all

together at both the resource and parent company level in order to be considered an annual GFC. If

these overhead costs can merely be reallocated using accounting methods (i.e., moved from one cost

center to another) but not eliminated entirely, the costs would not be considered an annual GFC.

When determining what costs could be avoided, a participant must develop an expectation of how the

resource will be operated during the Capacity Commitment Period (“CCP”). For example, if the

resource intends to participate in the energy and ancillary services market during the CCP, then many

costs will not be avoided and would not be deemed appropriate for inclusion within the calculation of

the GFC. However, if the plant plans to shut down (e.g. mothball) for a full or partial year, then certain

costs may be avoided.

When evaluating the avoidable operating costs of a resource, the IMM considers the following:

Whether the bid is a Static or a Permanent De-list Bid. In general, a participant will have

greater avoidable costs if a resource permanently exits the capacity market versus becoming

inactive for a single CCP;

Consistency of avoidable costs with the participant’s election to either (a) remain in the energy

and ancillary services market without a CSO, or (b) shut down the resource for the CCP. The

expectation is that the avoidable costs will be lower if the resource continues operation in the

energy and ancillary services markets when compared to shutting down the plant;


Attachment C

March 3, 2015

Page 8 of 13




Whether adequate documentation and a sound methodology was provided demonstrating the

avoidance of major expenditures such as centralized corporate overhead costs allocated to

individual market regions or resources;

Consistency in the use of historical cost and revenue data; such as using the most recent year’s

data or an average of two of the past three year’s data;

Reasonableness of adjustments made to historical operating cost, production cost, and ISO-NE

revenue data; including adjustments to account for expected inframarginal rents (“IMR”) and

Peak Energy Rents (“PER”);

Expectations relative to comparable resources.

Incremental Capital Expenditures

Included in the net GFC calculation are projected incremental capital expenditures that would be made

to support a CSO. For example, if the participant is required to make a capital investment in order to

comply with known environmental regulations, and that capital investment would be avoided as a

result of the resource not obtaining a CSO, then a portion of the capital cost may be included in the

GFC. The total cost included in the de-list bid is based on the annual rate of capital cost recovery as

determined by the resource age and remaining life (see the table included in Tariff reference below).

III.13.1.2.3.2.5. Incremental Capital Expenditure Recovery Schedule

Except as described below, the Internal Market Monitor shall review all de-list bids

using the following cost recovery schedule for incremental capital expenditures,

which assumes an annual pre-tax weighted average cost of capital of 10 percent.


Attachment C

March 3, 2015

Page 9 of 13




A Market Participant may request that a different pre-tax weighted average cost of

capital be used to determine the resource’s annual rate of capital cost recovery by

submitting the request, along with supporting documentation, in the Existing Capacity

Qualification Package. The Internal Market Monitor shall review the request and

supporting documentation and may, at its sole discretion, replace the annual rate of

capital cost recovery from the table above with a resource-specific value based on an

adjusted pre-tax weighted average cost of capital. If the Internal Market Monitor uses

an adjusted pre-tax weighted average cost of capital for the resource, then the

resource’s annual rate of capital cost recovery will be determined according to the

following formula:

Where:

Cost Of Capital = the adjusted pre-tax weighted average cost of capital.

Remaining Life = the remaining life of the existing resource, based on the age of the

resource, as indicated in the table above.

When evaluating the avoidable incremental capital costs of a resource, the IMM considers the

following:

Whether documentation was provided to support the inclusion of major capital expenditures,

such as engineering reports, benchmark cost data, or feasibility studies;

Whether the calculation of annualized costs was done in accordance with the cost recovery

schedule prescribed in Section III.13.1.2.3.2.5;

Whether costs are avoidable in the absence of a CSO for the CCP, and whether such costs

were already included in a previous year’s de-list bid that did not clear in a prior auction (i.e.,

retained a CSO).

The foregoing outlines the Tariff requirements and the IMM’s implementation of the review

process. This process is further informed by recent FERC orders.

Commission Orders:


Attachment C

March 3, 2015

Page 10 of 13




The IMM’s approach to evaluating overhead and capital costs is consistent with two recent

Commission orders.

The Commission addressed the criteria for including avoidable overhead costs in Static De-list

Bids in ISO New England’s Informational Filing for FCA8 (Docket No. ER14-329-000).

The Commission noted that “the Tariff does allow for such [overhead] costs to be include in a

resource’s net risk-adjusted going forward costs, provided that the costs “would be avoided in the

absence of a Capacity Supply Obligation.” It is reasonable to anticipate that some overhead costs

might be avoided in the absence of a capacity supply obligation; however, other costs may not be

avoided during the one-year Capacity Commitment period, and a resource needs to demonstrate

which costs are, in fact, avoidable.” (emphasis added).

The Commission addressed the criteria for including avoidable capital costs in Static De-list Bids

in ISO New England’s Informational Filing for FCA4 (Docket No. ER10-1185-000). The

Commission rejected Dominion’s protest that the IMM had incorrectly denied the inclusion of

capital costs in the Static De-list Bids for its Salem Harbor units that were made before the 2012-

2013 Capacity Commitment period. The Commission determined “the capital costs related to

those investments were already included in Dominion’s static de-list bids for the third FCA and

thus are sunk”.

The Commission went on to state that “ISO-NE was correct in determining that the capital

investment costs from the third Forward Capacity Auction static de-list bids are no-longer

avoidable and not recoverable as part of Dominion’s static de-list bids in the fourth Forward

Capacity Auction” (emphasis added)

Further, the Commission addressed the issue of guaranteed cost recovery as it relates to Static De-

list Bids which affords a Market Participant the option of participating in future Forward Capacity

Auctions where prices could exceed those of the Static De-list Bid. The Commission wrote: “As

we have stated previously, and we reiterate here, resources are provided only an opportunity to

recover their costs, not a guarantee that they will recover those costs.” Using the Tariff, IMM

implementation process, and FERC orders, we can move on to an example.


Attachment C

March 3, 2015

Page 11 of 13




Example:

To help illustrate the IMM process for arriving at a reasonable de-list bid offer, consider the following

example.

A 600 MW resource that is 25 years old intends to submit a Static De-list Bid for FCA 9. The resource

expects to remain in the energy and ancillary services markets even if the de-list bid clears the FCA

(does not receive a CSO).

The resource has the following expense structure:

Table 1 – Historical Annual Expenses

Also, consider that the resource has the following estimated capital expenditures for future Capacity

Commitment Periods:

Table 2 – Projected Capital Expenditures

Expense Category: Historic

Real estate taxes 2,000,000$

Fuel 25,000,000

Off-peak staffing 4,000,000

Corporate overhead 750,000

Base-level staffing 3,000,000

Insurance 5,000,000

Total 39,750,000$


Attachment C

March 3, 2015

Page 12 of 13




Consistent with the assumption that the resource would participate in the energy and ancillary services

markets without a CSO, the de-list bid would be constructed in the following manner:

Table 3 – Avoidable Going Forward Costs

As shown in Table 3, of the $39.75 million historical expenses only $4.5 million may be considered

avoidable and, therefore, will qualify to be included in the de-list bid. While similar in nature, other

components are not deemed avoidable based on the assumption that the resource will participate in the

energy and ancillary services markets under limited circumstances.3 Based on the foregoing, the

expense portion of the GFC would be $0.63 per kW-month.

3 The example shows that some staffing may be avoided even though the resource has elected to continue to

participate in the energy and ancillary services markets as the resource may only plan on participating for a

portion of the CCP.

Capital Expenditure ($ in Millions) 2016-17 2017-18 2018-19 2019-20 2020-21 2021-2022 2022-2023

Fuel dock repair 7.0$

Computer system upgrade 1.2$ 2.8$

Major storage tank overhaul 5.5$

Selective Catalytic Reduction (SCR) 7.2$

Access road repair and misc. 3.0$

Turbine blade replacement 10.0$

Running Total 7.0$ 8.2$ 13.7$ 20.9$ 23.7$ 26.7$ 36.7$ Total

Eligible for inclusion in CCP De-List Bid 1.8$ 0.3$ 1.5$ 1.9$ 0.7$ 0.8$ 2.6$ 9.7$

Eligible for inclusion in FCA 9 CCP De-List Bid 1.5$ 26.4%

De-List Capacity Commitment Period

Historic Variable GFC Unavoidable

Expense Category: (A) (B) (C) (= A-B-C)

Real estate taxes 2,000,000$ 2,000,000$

Fuel 25,000,000 25,000,000 -

Off-peak staffing 4,000,000 4,000,000 -

Corporate overhead 750,000 750,000

Base-level staffing 3,000,000 3,000,000

Insurance 5,000,000 500,000 4,500,000

Total 39,750,000$ 25,000,000$ 4,500,000$ 10,250,000$


Attachment C

March 3, 2015

Page 13 of 13




As shown on the projected capital expenditures shown in Table 2, the resource has plans to perform a

major storage tank overhaul. Provided this investment is necessary to keep back-up fuel on-site, the

cost is to be incurred during the CCP, and is incremental to having a CSO (i.e. if the resource did not

have a CSO, the investment would not be needed), the resource will be able to recover part of the $5.5

million investment in its de-list bid. The portion of the investment that may be captured in the de-list

bid is based on the resource’s age, and is shown in the Incremental Capital Expenditure Recovery

Schedule provided in Section III.13.1.2.3.2.5. In this example, the resource would be able to include

approximately $1.5 million, or 26.4% of the investment in the de-list bid calculation. This value

translates into an additional $0.20 per kW-month adder to the GFC.

Projected capital expenditures to be made before the 2018-19 CCP are not included in the de-list bid for

the 2018-19 period as they are no longer avoidable and are considered to be sunk costs as of the period

during which the participant is evaluating the resource for participation in the FCA. Those

expenditures expected to be made after the 2018-19 CCP are not included in the de-list bid for the

2018-19 period as the capital expenditures are not needed to support a CSO in that the 2018-19 CCP.

Based on the foregoing, the GFC component of the de-list bid price for the 2018-19 CCP would be

equal to $0.83/kW-month.


Attachment C

EXELON PROPOSAL(Capital Costs: Mitigation of Static De-List Bids)

III.13.1.2.3.2.5. Incremental Capital Expenditure Recovery Schedule.

Except as described below, the Internal Market Monitor shall review all de-list bids using the following

cost recovery schedule for incremental capital expenditures, which assumes an annual pre-tax weighted

average cost of capital of 10 percent. For any Existing Generating Capacity Resource that is fueled by

oil, coal or natural gas and that is 40 years or older, all capital expenditures that have not been spent but

are planned to be spent during the period beginning with the subsequent calendar year following the de-

list bid submission through the end of the first calendar year for the relevant Capacity Commitment

Period shall be calculated using the following cost recovery schedule and may be included in an Existing

Generating Capacity Resource’s net going forward costs.

Age of Existing

Resource (years)

Remaining Life

(years)

Annual Rate of

Capital Cost

Recovery

1 to 5 30 0.106

6 to 10 25 0.110

11 to 15 20 0.117

16 to 20 15 0.131

21 to 25 10 0.163

265 to 40plus 5 0.264

40 or more (only

resources fueled by

oil, coal or natural

gas)

4 0.315

A Market Participant may request that a different pre-tax weighted average cost of capital be used to

determine the resource’s annual rate of capital cost recovery by submitting the request, along with

supporting documentation, in the Existing Capacity Qualification Package. The Internal Market Monitor

shall review the request and supporting documentation and may, at its sole discretion, replace the annual

rate of capital cost recovery from the table above with a resource-specific value based on an adjusted pre-

tax weighted average cost of capital. If the Internal Market Monitor uses an adjusted pre-tax weighted

average cost of capital for the resource, then the resource’s annual rate of capital cost recovery will be

determined according to the following formula:


-2-.

Cost Of Capital(1- (1+CostOfCapital)-RemainingLife)

Where:

Cost Of Capital = the adjusted pre-tax weighted average cost of capital.

Remaining Life = the remaining life of the existing resource, based on the age of the resource, as

indicated in the table above.



91071590.2

At the April 10, 2015 Participants Committee meeting, you will be asked to consider andvote on revisions to Market Rule 1 to allow certain Existing Capacity Resources to include intheir de-list bids costs that reflect accelerated recovery of capital expenditures, as proposed byExelon Generation Company, LLC (Exelon). A copy of the proposed revisions, as well asmaterials from Exelon describing the changes that were circulated to the Markets Committee,have been included with this memorandum.

The current FCM rules permit an Existing Capacity Resource to include in its Static De-List Bid incremental capital costs associated with maintaining a Capacity Supply Obligation.The Internal Market Monitor (IMM) is required to review all de-list bids using a pre-specifiedcost recovery schedule for incremental capital expenditures.1

Exelon proposes to modify the cost recovery schedule to permit Existing CapacityResources that are fueled by oil, coal or natural gas, and are 40 years or older to include in theirStatic De-List Bids capital expenditure costs that provide full recovery of those costs over fouryears. Exelon argues that the current incremental capital expenditure recovery schedule does notallow for a reasonable amount of capital costs to be included in de-list bids, particularly for thoseolder fossil units that are deciding whether to remain in the market or retire.

At its March 10-11, 2015 meeting, the Markets Committee considered, but failed tosupport, a resolution to recommend Participants Committee support for these Exelon-proposedchanges.2 The IMM does not support this Exelon proposal and has provided an explanation in amemorandum (dated March 3, 2015) included as Attachment C to the materials for Agenda Item6 posted for this meeting.

The following form of resolution may be used for Participants Committee action:

RESOLVED, that the Participants Committee supports revisions to MarketRule 1 to allow accelerated cost recovery of capital expenditures for certaincapacity resources, as proposed by Exelon Generation Company, LLC, andas circulated to this Committee in advance of this meeting, together with [anychanges agreed to by the Participants Committee at this meeting and] suchnon-substantive changes as may be approved by the Chair and Vice-Chair ofthe Markets Committee.

1 See table in Section III.13.1.2.3.2.5 of Market Rule 1.

2 During the Markets Committee vote, the MC Chair asked members if anyone wanted to registera vote that was different from a previous MC vote on Exelon’s overhead/centralized cost proposal (seeAgenda Item #6). No votes were changed. Thus, the motion failed with a 39.36% Vote in favor.

M E M O R A N D U M


FROM: Sebastian M. Lombardi, NEPOOL Counsel

DATE: April 3, 2015

RE: Exelon’s FCM Proposal re Capital Cost Recovery in De-List Bids

Capital and Overhead ExpenseMitigation in Static DeList BidsMarch 10, 2015


Overview

The FCM must allow facilities to reflect their reasonableexpectations of cost and risk in delist offers• Particularly for older units with limited lifetimes, we cannot “hope” for higher, future

clearing prices to cover costs that are not reflected in delist bids.

• We have had significant difficulty getting our estimates of actual costs in delist bids.Our presentation is focused on two areas: Corporate Overheads, and CapitalExpenditures.

• Exelon’s proposal is tariff guidelines that will allow for specific offer caps:• These are not necessarily prices at which the market will clear. The market

could clear higher or lower for many other reasons. The ultimate offerrepresents the price at which the unit owner is truly willing to make the unitavailable for the Commitment Period.

• As caps, the resource owner may wish to offer at lower levels depending on thespecific circumstances.

• Addressing these problems is critical to a well-functioning market. Failure to correctthem may force more units to make uneconomic retirement decisions. This is aproblem for consumers, affected generators, and in some cases, system reliability.

2


Overhead CostsProblem Statement: The IMM does not allow the inclusion of any overhead/centralizedcosts in Static DeList bids.

For owners of multiple generation sites, certain services are centralized in order to minimizecosts, such as:― Engineering & Project Management

― Safety, Training, Outage Management

― Supply

― Traditional Corporate functions like Finance, Accounting, Legal, Human Resources, Communications, and Information Technology

The IMM seems to allow inclusion of only the direct costs of people dedicated to operating theplant, as they are captured in the plant-specific O&M. Yet in companies managing a portfolio,there is a large amount of shared costs that appear ineligible to go into delist offers.― The current tariff language incents market participants to decentralize costs – that is make them plant-specific. While

this is inefficient and increases cost, it seems to be the only way that costs can be recovered in delists.

― These are real, incremental costs of operating a power plant. Failing to allow recovery means that the facility is losing money, and therefore is a candidate for retirement. That retirement could be inefficiently early if costs are not allowed inoffers.

― Uneconomic retirements raise cost to consumers, and are a problem for resource owners.

Exelon has reviewed many of its previous delist bids, reliability contracts and recent sales ofassets and the range of overhead costs allocated to the various transactions ranged fromapproximately $0.50/kW-month and $1.60/kW-month. Therefore Exelon is proposing an up to$0.65 default rate for those resources which are 40 years and older and choose not to gothrough the tariffed avoided cost process.

3


Capital Expenditures (1/3)Problem Statement: An older fossil unit which makes a decision to retire on a year by year basiscannot reflect this year to year decision in their capital cost allocations in their delist bid.

ISO-NE guidelines allow for “incremental capital expenditures” to be recovered at a rateprescribed in the tariff:

The “remaining life” in these schedules may be very different from what the owner actuallyexpects.

Particularly for older resources, there may be little expectation of future capacity revenuesbeyond the Commitment Period for which the offer applies.

Under today’s rules, to be included in delists, CapEx (to which the above recovery rates apply)must typically be linked to making the unit available in a specific Commitment Period. This canbe exceedingly difficult. Capital expenditures are an ongoing process, budgeted in each andevery operating year. While all of the costs are necessary to make the unit reliable andavailable for dispatch, associating every dollar and project with a specific delivery year can bedifficult and subjective.

4

ISO-NE Capital Cost Recovery Factors


Capital Expenditures (2/3)Problem Statement: Current FCM rules do not allow for a reasonable amount of capital to beincluded in the delist offer; tariff changes must be made to ensure reasonable capital recoverygiven current market risks, particularly for older units which make their decision to remain in themarket on a year-by-year basis.

• A 40-year old fossil unit which decides to remain in the market can only recover a fraction of its expectedcapital expenditures under the existing tariff. The issue lies in both the forced (5+ year) amortizationschedule, and the difficulty in attributing individual CapEx dollars to a specific Commitment Period – asdescribed on the prior slide. This structure fails to recognize that:

1. If the unit fails to clear in the prompt year’s auction, it will likely decide to reduce or eliminate allscheduled capital improvements from that day forward – including those moneys scheduled in previousyears but as of yet unspent. The owner may then simply maintain the unit at a minimum level necessaryto meet its residual capacity supply obligations.

2. It is likely that the unit will either retire if they don’t clear or may wait to see the auction results in thefollowing year before retiring.

Proposed Rule Change: For fossil units 40 years and older, all capital expenditures that have notbeen spent but are planned for any dates included in the period beginning with the subsequentcalendar year following the delist bid submission through the end of the first calendar yearduring the delivery period, will be multiplied by the appropriate Capital Recovery Factor and maybe included in the Net Going Forward Cost calculation. We are proposing a 4-year recoveryperiod, because that would allow ¼ of each of 4 years’ capital to be included in consecutiveyears’ delists. In this way we need not attribute a specific CapEx dollar to a specificCommitment Period, but each CapEx dollar is only recovered once. See example on thefollowing page.

Presentation Title5


Capital Expenditures (3 of 3)

6


CapEx $15.0 M $20.6 M $2.1 M $5.3 M $43.0 M


Allowed Recovery Rate 31.5% 31.5% 31.5% 31.5% 31.5%

Allowed CapEx in DeList Bid $0.66/kW-mo $0.90/kW-mo $0.09/kW-mo $0.13/kW-mo $1.78/kW-mo

Current ISO-NE Capital Cost Recovery Factors Proposed ISO-NE Capital Cost Recovery Factors



91096466.3

M E M O R A N D U M


FROM: Pat Gerity, NEPOOL Counsel

DATE: April 3, 2015

RE: GIS-Only Participant Proposal

You will be asked at the April 10 meeting to approve for balloting amendments to the NEPOOLAgreement (“Amendments”) that will create a “GIS-Only Participant” classification in NEPOOL.Materials explaining this proposal were circulated and explained at the March 6 Participants Committeemeeting. With the exception of one aspect of the proposal, as explained more fully below, theMembership Subcommittee (“Subcommittee”) unanimously recommended at its March 16, 2015 meetingthat the Participants Committee authorize and direct the Balloting Agent to circulate ballots foramendments to the NEPOOL Agreement to achieve that result. This memorandum briefly summarizesthe background and substance of the Subcommittee’s recommendation. A draft of the proposedAmendment is also included with this memorandum.

Background

As explained previously, the genesis of the GIS-Only Participant proposal was a request bySRECTrade, Inc. (“SRECTrade”), which is in the business of brokering and trading in solar renewableenergy credits (“SRECs”) and an active participant in the NEPOOL Generation Information System(“GIS”), to join NEPOOL as a Participant. The NEPOOL arrangements had not contemplatedmembership by such entities, which did not exist when the arrangements were agreed upon. If brokeringor trading in RECs is the sole business activity of such entities in New England, such entities do notcurrently qualify for membership in any Sector of NEPOOL without changes being made to the NEPOOLarrangements. In considering SRECTrade’s application, the members participating in the Subcommitteeefforts concluded that it was desirable to accommodate the participation in the Pool by any Entity withdemonstrated and significant interests in the GIS that do not otherwise qualify for membership in anycurrent NEPOOL Sector. With the help and involvement of SRECTrade representatives, theSubcommittee has identified changes to the NEPOOL arrangements to permit all such Entities toparticipate in NEPOOL.1

The GIS-Only Participant Proposal

• A GIS-Only Participant would be treated like any other Participant for all purposes, otherthan with respect to making a motion and voting.

• Voting Limitation. A GIS-Only Participant would be a voting member only on, andcould make motions only with respect to, GIS matters.

• No Sector Affiliation. When voting on GIS matters, the vote(s) of GIS-Only Participantswould be grouped with those Participants in the Provisional Member Group Seat, sincesuch members are not eligible for any current Sector.

1 Of the 1,476 account holders registered in the GIS, there are at least 2 categories of participant, trader andindependent verifier, encompassing over 300 entities, that could potentially qualify for eligibility as a GIS-OnlyParticipant. The number of Entities that might avail themselves of the GIS-Only Participant status is not limited inany way. Although what the actual interest or participation might be cannot be determined with any reasonablecertainty, the generally held view of the Subcommittee participants was that the number of GIS-Only Participantswould ultimately be relatively small.


91096466.3 -2-

• $5,000 Application and Annual Fee. Similar to most Participants, GIS-Only Participantswould be required to pay an application and annual fee of $5,000 each.

• No Additional Participant Expenses.** GIS-Only Participants would not be required tomake any additional contributions to Participant Expenses (similar to the arrangementsfor Provisional Members, Gas Industry, Data-Only, and Governance Only End UserParticipants). [contested. See next Section].

• No MPSA. No Financial Assurance Requirements. Participating effectively forgovernance purposes only, GIS-Only Participants would not become Market Participantsand would not be subject to any additional financial assurance requirements (unless thisCommittee decides to modify the proposal to allocate additional Participant Expenses).

• GIS-Only Participants would receive notice of, materials for, and be permitted to attendand speak (without limitation) as Participants at, any Principal Committee meeting.

**Alternative Contested Element: Require an Additional Contribution to Participant Expensesfrom GIS-Only Participants

There is one aspect of the Proposal that did not garner unanimous support. As noted above, underthe Proposal, participation by a GIS-Only Participant will be limited only with respect to the matters onwhich a GIS-Only Participant can make a motion and vote. However, GIS-Only Participants will bepermitted to speak, without specific limitation, on any matter before a Principal Committee. OneSubcommittee member expressed the view that, absent a parallel limitation restricting the ability of a GIS-Only Participant to speak only on matters related to the administration of the GIS, GIS-Only Participantsshould be required to pay an additional portion of Participant Expenses. The suggested amount was thatamount equal to roughly one-half the lowest amount of Participant Expenses paid by an individual votingParticipant in the Generation or Supplier Sectors, or $2,700. A number of members objected to such alimitation (and corresponding additional fee), because (i) such a limitation might prove to be challenging toadminister; (ii) even if administratively feasible, all input, particularly helpful input, should be encouraged;(iii) the amount defraying annual Participant Expenses was generally consistent with the amounts paid byother members whose participation is limited; and (iv) if collected monthly, would require additionaladministrative and financial efforts associated with establishing and maintaining the requisite level ofadditional financial assurance.

Proposed Form of Resolution

The following form of resolution could be used to authorize the balloting of the proposedAmendments:

RESOLVED that the Participants Committee authorizes and directs the BallotingAgent (as defined in the Second Restated NEPOOL Agreement) to circulateballots for the approval of changes to the Second Restated NEPOOL Agreement(that define and address the arrangements for GIS-Only Participants), togetherwith [any changes agreed to by the Participants Committee at this meeting and]such non-material changes therein as the Chair of the Membership Subcommitteemay approve, to each Participant for execution by its voting member or alternateon this Committee or such Participant’s duly authorized officer.

Should there be any further questions in advance of the April 10 meeting, please contact Pat Gerity(860-275-0533; [email protected]).


91071983.1

ONE HUNDRED TWENTY-EIGHTH AGREEMENT AMENDINGNEW ENGLAND POWER POOL AGREEMENT

(GIS-Only Participant Revisions)

THIS ONE HUNDRED TWENTY-EIGHTH AGREEMENT AMENDING NEWENGLAND POWER POOL AGREEMENT, dated as of April 10, 2015 (“One Hundred Twenty-Eighth

Agreement”), amends the New England Power Pool Agreement (the “NEPOOLAgreement”).

WHEREAS, effective February 1, 2005 the NEPOOL Agreement was amended by theOne Hundred Eighth Agreement Amending New England Power Pool Agreement and restated asthe Second Restated NEPOOL Agreement, and has subsequently been amended numerous times;and

WHEREAS, the Participants desire to amend further the Second Restated NEPOOLAgreement to reflect the revision detailed herein.

NOW, THEREFORE, upon approval of this One Hundred Twenty-Eighth Agreement bythe NEPOOL Participants Committee in accordance with the procedures set forth in the SecondRestated NEPOOL Agreement, the Participants agree as follows:

SECTION 1AMENDMENTS

1.1 Addition of Definitions. The following definitions are added to Section 1 of the SecondRestated NEPOOL Agreement and inserted in the appropriate alphabetical order:

GIS is the NEPOOL Generation Information System.

GIS-Only Participant is a Participant that meets all four of the following criteria:(a) the Participant owns or controls one or more certificates in the GIS (“GISAccount Holder”) or acts from time to time for GIS Account Holders in arrangingfor the creation, assignment, or transfer of GIS certificates; and (b) the Participantdoes not participate directly in the New England Markets; and (c) the Participantis not eligible to join or designate a voting member of a Sector (other than the EndUser Sector); and (d) the Participant elects to be a treated as a GIS-OnlyParticipant before its membership application is approved by NEPOOL.Notwithstanding any other provision of this Agreement, a GIS-Only Participantshall not have the right to join, or be or vote as a member of, a Sector; providedhowever, that solely for purposes of voting on matters related to theadministration of the GIS, a GIS-Only Participant shall have the right to vote as amember of the Provisional Member Group Seat, and to appoint a voting member,and an alternate to that member, for those purposes. Such a voting member andalternate shall have all of the rights of any other member of a Principal Committeeexcept the right to vote on matters unrelated to the administration of the GIS or toserve as an officer of a Principal Committee.


-2-

91071983.1

1.2 Amendment to Section 1.68B. Section 1.68B of the Second Restated NEPOOL Agreementis amended so that it reads as follows:

Provisional Member Group Seat is the group comprised of all ProvisionalMembers that are not Related Persons to Participants that are eligible to designatea voting member of a Sector (other than the End User Sector) and, solely forpurposes of voting on matters related to the administration of the GIS, GIS-OnlyParticipants.

1.3 Amendment to Section 6.2. The first sentence of the last paragraph of Section 6.2 of theSecond Restated NEPOOL Agreement is amended so that it reads as follows:

All Participants (other than Data-Only Participants, Gas Industry Participants,GIS-Only Participants, and Provisional Members) have the right to join and be amember of a Sector.

SECTION 2MISCELLANEOUS

2.1 This One Hundred Twenty-Eighth Agreement shall become effective June 1, 2015, or onsuch other date as the Commission shall provide that the amendment reflected hereinshall become effective.

2.2 Capitalized terms used in this One Hundred Twenty-Eighth Agreement that are notdefined herein shall have the meanings ascribed to them in the Second RestatedNEPOOL Agreement.

April 9, 2015 Report NEPOOL PARTICIPANTS COMMITTEEAPR 10, 2015 MEETING, AGENDA ITEM #9

Page ES-141536280.149

EXECUTIVE SUMMARYStatus Report of Current Regulatory and Legal Proceedings

as of April 9, 2015

The following activity, as more fully described in the attached litigation report, has occurred since the reportdated March 4, 2015 was circulated. New matters/proceedings since the last Report are preceded by an asterisk ‘*’.Page numbers precede the matter description.

I. Complaints

* 1 NRG Canal 2 2015/16 ARA3Complaint/Waiver Req. (EL15-57)

Apr 6 GenOn files complaint regarding the 3rd ARA for the 2015/16Capacity Commitment Period; comment date May 6, 2015

1 NEPGA Peak Energy Rent (PER)Complaint (EL15-25)

Apr 1 FERC issues tolling order affording it additional time to considerNEPGA’s and Entergy’s requests for rehearing of the Jan 30 PERComplaint Order

2 New Entry Pricing Rule Complaint(EL15-23)

Apr 1 FERC issues tolling order affording it additional time to consider theExelon/Calpine request for rehearing of the Jan 30 order denying theComplaint

3 206 Proceeding: Importers’ FCAOffers Review/Mitigation(EL14-99; ER15-117)

Apr 1 ISO and NEPOOL file Market Rule changes to allow New ImportCapacity Resources to submit up to five price-quantity pairs as part oftheir FCA offer information; comment date Apr 22

4 Base ROE Complaints (2012 &2014) Consolidated(EL14-86 & EL13-33)

Mar 4

Mar 6Mar 10Mar 11Mar 13

Mar 16

Mar 17

Mar 23-26

TOs request substitution of joint Avera/MacKenzie answeringtestimony with testimony sponsored solely by Dr. AveraTOs request Judge Sterner re-schedule oral argument to Mar 24FERC Trial Staff requests extension of procedural datesChief Judge Wagner extends initial decision date to Dec 30, 2015TOs move to waive period for answers to Mar 4 replacementtestimonyJudge Sterner issues order revising procedural schedule andmodifying data update cutoff dateJudge Sterner accepts replacement testimony; finds order to showcase moot and cancels Mar 24 oral argumentFERC Staff submitted its direct and answering testimony

7 Base ROE Complaint (2011)(EL11-66)

Mar 31 In response to Order 531-B, TOs request second extension of time forthe completion of regional and local refunds

II. Rate, ICR, FCA, Cost Recovery Filings

* 9 FCA-10 Capacity Zone Boundaries(ER15-1462)

Apr 6 ISO files a notice identifying two potential new Capacity Zones forFCA-10: Southeastern New England and Northern New EnglandZones; comment date Apr 27

8 Opinion 531-A Compliance Filing:TOs (ER15-414)

Mar 31 TOs request that FERC defer action on pending filing until afterOpinion 531-B-related amendments have been filed and thecorresponding comment period has passed

9 FCA9 Results Filing (ER15-1137) Mar 6-Apr 9

NEPOOL, Calpine, Emera, Essential Power Entergy, EPSA,EquiPower, Exelon, HQ US, NESCOE, NRG, PSEG, TransCanadaintervene

III. Market Rule and Information Policy Changes, Interpretations and Waiver Requests

* 10 eTariff Corrections(ER15-1455)

Apr 6 ISO files corrections to eTariff; comment date Apr 27


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* 10 LMP Calculator Replacement(ER15-1238)

Mar 13

Mar 17

ISO and NEPOOL jointly file changes to replace the part of thesystem dispatch software that calculates prices in the Real-TimeEnergy MarketEntergy intervenes

* 10 CSO Termination: DFC-ERG CT(ER15-1201)

Mar 9

Mar 16Apr 9

ISO files to terminate a CSO for Resource 16729 held by DFC-ERGCT; comment date Mar 30NEPOOL, Entergy interveneFERC accepts termination

* 10 PER Mechanism Elimination (FCA-10) (ER15-1184)

Mar 6Mar 11-30Mar 27

ISO and NEPOOL jointly file changes to eliminate PER mechanismCalpine, CT AG, Dominion, Emera, Exelon, NESCOE, NRG interveneEntergy, NEPGA, GDF Suez submit supporting comments

10 Forward Reserve Obligation ChargeChanges (ER15-1009)

Mar 30 FERC accepts revised Tariff Section III.10.4 to change calculation ofForward Reserve Obligation Charge

11 Winter 2014/15 Reliability Program(ER14-2407)

Mar 23 FERC issues tolling order affording it additional time to consider theISO’s request for rehearing of the Jan 20 Winter Reliability ProgramClarification Order

11 Demand Curve Changes(ER14-1639)

Mar 23Mar 30

NEPOOL submits commentsNextEra, NRG, PSEG petition DC Circuit Court of Appeals for reviewof Demand Curve orders (see Section XV)

IV. OATT Amendments / TOAs / Coordination Agreements

13 ETU Rule Changes(ER15-1050, -1051)

Mar 6

Mar 20Mar 23

Mar 31Apr 3

Eversource, Northern Pass intervene; Champlain VT files commentsgenerally supporting the changes, but protesting its Revised QueuePositionSunEdison answers Champlain VT’s Mar 6 limited protestISO/NEPOL/PTO AC, Anbaric Transmission, Eversource, NorthernPass answer Champlain VT’s Mar 6 limited protestChamplain VT responds to Mar 20/23 answersAnbaric responds to Mar Champlain VT answer

15 Order 1000 Compliance Filing(ER13-193; ER13-196)

Mar 19

V. Financial Assurance/Billing Policy Amendments

No Activity to Report

VI. Schedule 20/21/22/23 Changes

* 17 Schedule 21-NEP: TSAs(BIPCO and Narragansett)(ER15-1466)

Apr 7 NGrid files amended TSAs to reflect BIPS charge;comment date Apr 28

* 17 Schedule 20A-EM and 21-EM(ER15-1434)

Apr 1 Emera Maine and the ISO file changes; comment date Apr 22

17 LGIA – NU/CPV Towantic(ER15-200)

Apr 1Apr 6

3rd settlement conference re-scheduled to Apr 10Settlement Judge Coffman issues report recommending settlementprocedures by continued

VII. NEPOOL Agreement/Participants Agreement Amendments



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VIII. Regional Reports

18 Capital Projects Report - 2014 Q4(ER15-1036)

Mar 6Apr 6

Eversource intervenesFERC accepts Report

18 Future Winter Reliability ProgramProgress Reports (ER14-2407)

Apr 8 ISO files 2nd 60-day progress report

* 18 Reserve Market Compliance (18th)Semi-Annual Report (ER06-613)

Apr 1 ISO submits 18th semi-annual report

* 18 Quarterly Reports Regarding Non-Generating Resource RegulationMarket Participation (ER08-54)

Mar 19Mar 31

ISO files its 26th quarterly reportnew regulation market implemented

* 19 ISO-NE FERC Form 715 Mar 31 ISO submits annual report of total MWh of transmission service

IX. Membership Filings

* 19 April 2015 Membership Filing(ER15-1417)

Mar 31 New Members: Evergreen Wind, Jericho Power; Termination: LincolnPaper and Tissue; Name Change: Constellation Energy Services

19 March 2015 Membership Filing(ER15-1131)

Apr 6 FERC accepts filing

* 19 Suspension Notice (not docketed) Mar 6Mar 9

NECCO suspended from New England MarketsISO files notice of suspension

X. Misc. - ERO Rules, Filings; Reliability Standards

20 FFT Report: Mar 2015 (NP15-23) Mar 31 NERC files report

20 Revised Reliability Standards: PRC-001-1.1(ii), PRC-004-2.1(i)a, PRC-004-4; PRC-005-2(i), PRC-005-3(i), PRC-019-2 and PRC-024-2,VAR-002-4 (RD15-3)

Mar 9Mar 13

Dominion files commentsNERC files supplemental revised Standards

24 NOPR: Revised Reliability Standard:COM-001-2 and COM-002-4(RM14-13)

Mar 6 NERC submits supplemental comments

26 NOPR: Revised TOP and IROReliability Standards (RM13-15,RM13-14, RM13-12)

Mar 18 NERC submits notice of withdrawal of the revised Standards filed inthese proceedings

XI. Misc. - of Regional Interest

* 26 203 Application: Iberdrola/UI(EC15-103)

Mar 25 Iberdrola and UI request authorization of transaction that will makeUI an indirect wholly-owned subsidiary of Iberdrola, S.A.; commentdate Apr 15

27 203 Application: EquiPower /Dynegy (EC14-140)

Mar 27Apr 1Apr 7

FERC authorizes transactionTransaction consummatedParties notify FERC that the transaction was consummated on Apr 1

* 28 EPC Agreement: Blue Sky West &Emera Maine (ER15-1459)

Apr 7 Emera files EPC Agreement with Blue Sky West;comment date Apr 28

* 28 Emera MPD OATT Changes(ER15-1429)

Apr 1 Emera Maine files changes to the OATT for Maine Public District;comment date Apr 22

* 28 Emera Maine Order 676-HCompliance Filing (ER15-1419)

Mar 31 Emera Maine submits Order 676-H compliance filing and requestswaiver of certain standards not applicable to Maine Public District orthe MPD OATT; comment date Apr 21


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* 28 NSTAR/HQ US CMEEC Use RightsTransfer Agreement (ER15-1383)

Mar 26 NSTAR files agreement; comment date Apr 16

* 28 SGIA Termination: CMP/GallopPower Greenville (ER15-1189)

Mar 6Apr 2

CMP files notice of termination of Gallop Power Greenville SGIAFERC accepts termination of SGIA

28 LCC Services Agreement –NSTAR/Braintree (ER15-1040)

Apr 8 FERC accepts Braintree’s NSTAR LCC Agreement; directs NGrid tofile termination of REMVEC LCC Agreement by Apr 29

29 LSA Termination: Emera/ Black BearHVGW (ER15-962)

Mar 10 FERC accepts LAS termination, effective Jan 6

29 IA – CL&P/Energy Stream(ER15-947)

Mar 19 FERC accepts IA, effective Mar 31

29 HG&E Demarcation Agreement(ER15-939)

Mar 17Mar 18

Eversource files complete copy of revised agreementEversource supplements Mar 17 filing

31 FERC Enforcement Action: MaximPower and K. Mitton (IN15-4)

Mar 23Apr 6

OE replies to Maxim Respondents’ Mar 4 answersMaxim Respondents reply to OE’s Mar 23 replies

30 FERC Enforcement Action: CityPower Marketing and Tsingas(IN15-5)

Mar 6

Mar 13Apr 1Apr 7

FERC issues show cause order and notice of proposed penalties (intotal, $1,278,358 disgorgement; $15 million civil penalties)OE Staff submits investigative materialsPJM seeks guidance related to funds to be disgorgedCity Power Respondents invoke their statutory rights to penaltyassessment and de novo review of that penalty in federal district court

31 FERC Enforcement Action:Powhatan Energy, HEEP Fund, CUFund, and Chen (IN15-3)

Mar 18Apr 1

Chen replies to OE’s Mar 3 materialsPJM seeks guidance related to funds to be disgorged

XII. Misc. - Administrative & Rulemaking Proceedings

32 Technical Conferences onImplications of EnvironmentalRegulations (AD15-4)

Mar 11 Eastern Region conference held; speaker materials and post-conferencecomments posted in eLibrary

33 Price Formation in RTO/ISO Energy& Ancillary Services Markets(AD14-14)

Mar 6-18 Nearly 40 parties submit comments

34 RTO/ISO Winter 2013/14 Operationsand Market Performance (AD14-8)

Mar 19-20 Over 15 parties submit comments

35 Order 807: Open Access and PriorityRights on ICIF (RM14-11)

Mar 19 FERC issues final rule; effective June 30, 2015

XIII. Natural Gas Proceedings

40 Algonquin Incremental Market Project(AIM Project) (CP14-96)

Apr 1-3 Rehearing requested of Mar 3 order granting certificate of publicconvenience and necessity

XIV. State Proceedings & Federal Legislative Proceedings



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XV. Federal Courts

* 42 FCM Administrative Pricing RulesComplaint (15-1071)

Mar 31 NEPGA petitions DC Circuit for review of FERC’s orders denying theComplaint

* 42 Demand Curve Changes(15-1070)

Mar 30 NextEra/NRG/PSEG petition DC Circuit for review of FERC’s ordersin the Demand Curve proceedings

42 FCA8 Results(ER14-1244 (consol.))

Apr 7 Court orders that motion to dismiss be referred to the merits panel;parties directed to address in their briefs the issues presented in themotion to dismiss rather than incorporate those arguments by reference

42 2013/14 Winter Reliability Program(14-1104, 14-1105, 14-1103(consol.))

Mar 25Apr 1

Petitioners file Joint Reply BriefDeferred Appendix filed

43 FERC v. EPSA (Orders 745, 745-A)(Supreme Court, 14-840)

Mar 19 Respondents (EPSA et al.) file brief opposing FERC’s petition for awrit of certiorari

44 CPV Maryland, LLC v. PPLEnergyPlus et al.(Supreme Court, 14-623)

Mar 23 Court invites Solicitor General to file a brief in the case expressing theviews of the United States

45 CPV Power Development, Inc., et al.v. PPL EnergyPlus, LLC, et al.(Supreme Court, 14-634, 14-694)

Mar 23 Court invites Solicitor General to file a brief in the case expressing theviews of the United States


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M E M O R A N D U M

TO: NEPOOL Participants Committee Member and Alternates

FROM: Patrick M. Gerity, NEPOOL Counsel

DATE: April 9, 2015

RE: Status Report on Current Regional Wholesale Power and Transmission Arrangements PendingBefore the Regulators, Legislatures, and Courts

We have summarized below the status of key ongoing proceedings relating to NEPOOL mattersbefore the Federal Energy Regulatory Commission (“FERC”), state regulatory commissions, and the FederalCourts and legislatures through April 9, 2015. If you have questions, please contact us.1

I. Complaints

• NRG Canal 2 2015/16 ARA3 Complaint/Waiver Request (EL15-57)

On April 6, 2015, GenOn Energy Management filed an emergency complaint and, alternatively, awaiver request, related to the third annual reconfiguration auction (“ARA”) for the 2015/16 CapacityCommitment Period (“2015/16 ARA3”). Specifically, GenOn requested in its emergency complaint that theFERC find that the ISO violated the Tariff in conducting the 2015/16 ARA by submitting a demand bid intothe March 2015 ARA as if Unit 2 at the Canal Generating Plant (“NRG Canal 2”) was still de-rated (303MW), rather than treating Canal 2 at its full capability (577 MW). Alternatively, should the FERC find thatthe ISO acted in accordance with the Tariff, GenOn requested waiver of all necessary Tariff provisions topermit the ISO to recalculate the results of the 2015/16 ARA3 to reflect NRG Canal 2’s full capability.GenOn requested that the FERC act on this filing on or before May 25, 2015. Comments on, and anyresponses to, this Complaint are due on or before May 6, 2015. If you have any questions concerning thismatter, please contact Dave Doot (860-275-0102; [email protected]) or Sebastian Lombardi (860-275-0663; [email protected]).

• NEPGA Peak Energy Rent (PER) Complaint (EL15-25)

Rehearing has been requested of the FERC’s January 30 order denying NEPGA’s PER Complaint.2

As previously reported, the PER Complaint Order found that NEPGA had failed to meet its burden undersection 206 of the Federal Power Act to demonstrate that the existing ISO Tariff provisions were unjust andunreasonable.3 On March 2, NEPGA and Entergy challenged the PER Complaint Order. NEPGA argued theFERC should “reverse its finding … that NEPGA did not satisfy its Section 206 burden in the Complaint withrespect to the relief sought for Capacity Commitment Periods 5 through 8” and “clarify that the [FERC], notthe complainant, carries the burden under Section 206 of establishing a just and reasonable “replacement”rate”. If rehearing is denied, NEPGA asked the FERC to clarify that it “did not intend to prejudge any futureproceeding on the PER Adjustment issue by establishing a required evidentiary standard” in the PER

1 Capitalized terms used but not defined in this filing are intended to have the meanings given to such terms in theSecond Restated New England Power Pool Agreement (the “Second Restated NEPOOL Agreement”), the ParticipantsAgreement, or the ISO New England Inc. (“ISO” or “ISO-NE”) Transmission, Markets and Services Tariff (the “Tariff”).

2 New England Power Generators Assoc., Inc. v. ISO New England Inc., 150 FERC ¶ 61,053 (Jan. 30, 2015) (“PERComplaint Order”), reh’g requested.

3 NEPGA’s Dec. 3, 2014 complaint requested that the ISO be directed (i) to increase the daily PER Strike Price by$250/MWh for Capacity Commitment Periods 5 through 8, and (ii) to eliminate the PER Adjustment for FCA9 and beyond,or, alternatively, to continue the $250 per MWh increase in the PER Strike Price for FCA9. The changes proposed in theComplaint were considered but not supported by the Participants Committee at its October 3, 2014 meeting.


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Complaint Order. In its request, Entergy, adopting and incorporating NEPGA’s request, provided additionalbases to support its request for rehearing of the PER Complaint Order. Entergy challenged further theFERC’s reliance on (i) the ISO’s assessment of the PER adjustment’s reliability impacts and, with respect toCapacity Commitment Periods 5-8, (ii) the stakeholder process considering changes to the PER rules. OnApril 1, 2015, the FERC issued a tolling order affording it additional time to consider NEPGA’s and Energy’srehearing requests, which remain pending before the FERC. If you have any questions concerning thismatter, please contact Joe Fagan (202-218-3901; [email protected]) or Sebastian Lombardi (860-275-0663; [email protected]).

• New Entry Pricing Rule Complaint (EL15-23)

Exelon and Calpine have requested rehearing of the FERC’s January 30 order denying the New EntryPricing Rule Complaint.4 As previously reported, the New Entry Pricing Rule Complaint Order found thatExelon and Calpine had failed to show that the existing pricing rules governing lock-in capacity result inunjust, unreasonable or unduly discriminatory price suppression. In their rehearing request, Exelon andCalpine assert, among other things, that the New Entry Pricing Rule Complaint Order (i) did not provide areasoned basis for finding that there is no artificial price suppression in post-entry FCAs; (ii) did not addressExelon/Calpine’s arguments regarding artificial price suppression in the entry FCA; and (iii) ignoredarguments regarding the undue discrimination that results from the current Market Rules. On April 1, 2015,the FERC issued a tolling order affording it additional time to consider Exelon’s and Calpine’s rehearingrequest, which remains pending before the FERC. If you have any questions concerning this matter, pleasecontact Dave Doot (860-275-0102; [email protected]) or Sebastian Lombardi (860-275-0663;[email protected]).

• NEPGA DR Capacity Complaint (EL15-21)

NEPGA’s November 14, 2014 complaint remains pending before the FERC. As previously reported,the complaint requests that (i) Demand Response (“DR”) Capacity Resources be disqualified from FCA9 and(ii) the Tariff be revised to exclude DR from FCM participation going forward (as a result of EPSA v. FERC).Interventions were filed by AEP, Brookfield, Calpine, ConEd, CSG, Direct, Dominion, EEI, ELCON, Emera,EnergyConnect, EnerNOC, Entergy, Exelon, FirstEnergy, Maryland Public Service Commission (“MDPSC”), NextEra, NRG, PPL, and Wal-Mart stores. NEPOOL filed comments on November 26 asking theFERC to reject the NEPGA Complaint without prejudice to a complaint being resubmitted if and asappropriate following consideration of specifically-proposed changes to the Tariff within the ParticipantProcesses. NU and UI jointly protested the complaint on December 3, requesting that the FERC eitherdismiss or hold the Complaint in abeyance. The ISO answered the Complaint on December 4. Also onDecember 4, Advanced Energy Management Alliance, NESCOE, Conn/RI,5 Enerwise, EnvironmentalAdvocates,6 NGrid, Public Systems; and the Sustainable FERC Project opposed the Complaint; EPSA andPSEG supported the Complaint; Genbright submitted comments. On December 15, CT PURA moved tolodge the December 15 DC Circuit Court order extending the stay of the mandate in EPSA v. FERC. OnDecember 19, NEPGA answered the ISO response and the other pleadings submitted in response to itsComplaint. On January 7, just as they had on December 23 in the FirstEnergy Complaint (see Section XIbelow), Environmental Advocates moved to lodge the US Solicitor General’s application for an extension oftime in which to file a petition for writ of certiorari, the Supreme Court Clerk’s notice to the DC Circuit that

4 The FERC stated that much of the complainants’ argument rested on the assertion that ISO-NE’s lock-in resourcerequirements differ from PJM’s. The FERC acknowledged that ISO-NE’s and PJM’s differing mechanics may yield differentprices paid to existing resources, but the FERC was not persuaded that the difference itself renders ISO-NE’s rules unjust andunreasonable. Exelon Corp. and Calpine Corp. v. ISO New England Inc., 150 FERC ¶ 61,067 at P 35 (Jan. 30, 2015) (“NewEntry Pricing Rule Complaint Order”), reh’g requested.

5 “Conn/RI” is CT PURA, CT AG, CT DEEP, CT OCC, and the Rhode Island Division of Public Utilities andCarriers (“RI PUC”).

6 Environmental Advocates are the Sustainable FERC Project, Sierra Club, Environmental Defense Fund, andAcadia Center.


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the extension had been granted, and the DC Circuit’s order extending the stay of its mandate pending theSupreme Court’s final disposition of the writ of certiorari. As noted, this matter remains pending before theFERC. If you have any questions concerning these matters, please contact Dave Doot (860-275-0102;[email protected]) or Sebastian Lombardi (860-275-0663; [email protected]).

• 206 Proceeding: Importers’ FCA Offers Review/Mitigation (EL14-99; ER15-117)

As previously reported, the FERC initiated this proceeding, on September 16, 2014, pursuant toSection 206 of the Federal Power Act (“FPA”). The FERC directed the ISO to either revise its Tariff toprovide for the review and potential mitigation of importers’ offers prior to each annual Forward CapacityAuction (“FCA”) or show cause why it should not be required to do so.7 The FERC directed the ISO tosubmit those Tariff revisions or support for why Tariff revisions should not be required on or before October16, 2014. September 24, 2014 is the refund effective date.8 On October 16, Public Citizen requested that theFERC expand this proceeding (i) to determine whether the rates produced by FCA8 are just and reasonableand if not, to fix the just and reasonable rates to be charged; and (ii) to include in this proceeding “stakeholderreform and transparency”.

ISO Response to Show Cause Order (ER15-117): On December 15, 2014, the FERC conditionallyaccepted, subject to two additional compliance filings, the ISO’s October 16 Tariff revisions in response tothe Show Cause Order that provided for the review and potential mitigation of importers’ supply offers priorto each annual FCA, which the FERC found “a significant step toward decreasing the opportunity forimporters to exercise market power.”9 The first compliance filing was due on or before January 14, 2015 andneeded to correct an incorrect cross-reference in Section III.13.1.3.5.7 (Qualification DeterminationNotification for New Import Capacity Resources).10 In the second compliance filing, due on or before April1, 2015, ISO-NE must submit tariff revisions in time for implementation for FCA-10 “which allow importersto submit up to five price-quantity pairs, together with any necessary mitigation provisions to address theexercise of market power” (finding implementation for FCA9 not feasible).11 All remaining requests andprotests, including those of Public Citizen, were rejected. Public Citizen requested rehearing of the ImportsMitigation Order on January 14, 2015 (ER15-117-003). On January 26, NEPGA answered Public Citizen’srequest. On February 12, 2015, the FERC issued a tolling order affording it additional time to consider PublicCitizen’s rehearing request, which remains pending before the FERC.

Compliance Filing I (ER15-117-001): On January 14, the ISO submitted the first compliance filingwhich, as directed, corrected the cross-reference in Section III.13.1.3.5.7 (Qualification DeterminationNotification for New Import Capacity Resources). Comments on that filing were due on or before February4; none were filed. Compliance Filing I is pending before the FERC.

Compliance Filing II (ER15-117-004): On April 1, the ISO and NEPOOL submitted Market Rulechanges, in response to the FERC’s directive in the Imports Mitigation Order, to allow New Import CapacityResources to submit up to five price-quantity pairs as part of their FCA offer information. The changes wereunanimously supported by the Participants Committee at its March 6 meeting (Consent Agenda item no. 2).Comments, if any, on Compliance Filing II are due on or before April 22.

7 ISO New England Inc., 148 FERC ¶ 61,201 (Sep. 16, 2014) (“September 16 Order”).

8 The Sep. 17 notice of this proceeding was published in the Fed. Reg. on Sep. 24, 2014 (Vol. 79, No. 185) p.57,075.

9 ISO New England Inc., 149 FERC ¶ 61,227 (Dec. 15, 2014) (“Imports Mitigation Order”), reh’g requested.

10 Id. at P 53.

11 Id. at PP 41-45, 64.


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If you have any questions concerning these matters, please contact Dave Doot (860-275-0102;[email protected]), Pat Gerity (860-275-0533; [email protected]), or Sebastian Lombardi (860-275-0663; [email protected]).

• Base ROE Complaints (2012 and 2014) Consolidated (EL13-33 and EL14-86)

As previously reported, the FERC issued an order on November 24, 2014, establishing a trial-type,evidentiary hearing, consolidating EL14-8612 with EL13-33,13 and setting a refund effective date for EL14-86of July 31, 2014.14 The FERC found that the Complaint in EL14-86 “raises issues of material fact that cannotbe resolved based upon the record before us and that are more appropriately addressed in the hearing ordered… [b]ecause of the existence of common issues of law and fact, we will consolidate this proceeding with theproceeding in Docket No. EL13-33-000 for purposes of hearing and decision.” In addition, the FERCindicated that “it is appropriate for the parties to litigate a separate ROE for each refund period.”15 The TOsrequested rehearing of the November 24 order on December 24. On January 23, 2015, the FERC issued atolling order affording it additional time to consider the TOs’ rehearing request, which remains pendingbefore the FERC.

Base ROE Complaint (2012) (EL13-33). In response to a December 2012 Complaint byEnvironment Northeast (“ENE”), Greater Boston Real Estate Board, National Consumer Law Center, and theNEPOOL Industrial Customer Coalition (“NICC”, and together, the “2012 Complainants”), the FERC, onJune 19, 2014, established hearing and settlement judge procedures.16 The 2012 Base ROE Complaintchallenged the TOs’ 11.14% return on equity (“Base ROE”), and sought a reduction of the Base ROE to8.7%. In the 2012 Base ROE Initial Order, the FERC found that the Complaint “raises issues of material factthat cannot be resolved based upon the record before us and that are more appropriately addressed in thehearing and settlement judge procedures ordered.”17 The FERC directed the parties to present evidence andany discounted cash flow (“DCF”) analyses in accordance with the guidance provided in the 2012 Base ROEInitial Order.18 Settlement judge procedures in this proceeding were unsuccessful and were terminatedOctober 24, 2014. The TOs July 21 request for rehearing of the 2012 Base ROE Initial Order, remainspending before the FERC pursuant to an August 20, 2014 tolling order issued by the FERC.

Hearings. Trial Judge Sterner’s most recent, revised procedural was issued on March 16 and nowleads to hearings beginning June 25, 2015 and an initial decision by December 30, 2015. As previouslyreported, the active Participants filed a preliminary joint statement of issues on December 9 and a discovery

12 As previously reported, the Massachusetts Attorney General (“MA AG”), together with a group of StateAdvocates, Publicly Owned Entities, End Users, and End User Organizations (together, the “2014 ROE Complainants”),filed a complaint on July 31, 2014 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 submittedthis Complaint seeking refund protection against payments based on a pre-incentives Base ROE of 11.14%, and a reductionin the Combined ROE, relief as yet not afforded through the prior ROE proceedings.

13 The 2012 Base ROE Complaint challenged the TOs’ 11.14% return on equity, and seeks a reduction of the BaseROE to 8.7%.

14 Mass. Att’y Gen. et al. -v- Bangor Hydro et al., 149 FERC ¶ 61,156 (Nov. 24, 2014), reh’g requested.

15 Id. at P 27 (for the refund period covered by EL13-33 (i.e., Dec. 27, 2012 through Mar. 27, 2014), the ROE forthat particular 15-month refund period should be based on the last six months of that period; the refund period in EL14-86and for the prospective period, on the most recent financial data in the record).

16 Environment Northeast, et al. v. Bangor Hydro-Elec. Co., et al., 147 FERC ¶ 61,235 (June 19, 2014) (“2012 BaseROE Initial Order”), reh’g requested.

17 Id. at P 26.

18 Id.


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plan on December 18. On December 19, the Complaint-Aligned Parties,19 EMCOS, TOs, and FERC TrialStaff submitted briefs regarding the appropriate cut-off date for data to be used in filing updates to studies inprior testimony in this proceeding. On December 30, Complaint-Aligned Parties and EMCOS submitted theirdirect testimony, including work sheets and work papers. The TOs filed their Answering Testimony andExhibits (with summaries) on February 2. And, with respect to the data cut-off date, Judge Sterner issued anorder on February 5 setting the updated data cutoff date at May 26, 2015 (the day the Update of Studies inPrior Testimony is due).

On February 26, Judge Sterner issued an order to show cause and notice of a March 17 oral argument(later re-scheduled to March 24) to determine why the joint testimony of witnesses William E. Avera andAdrien M. McKenzie should not be stricken, in whole or in part, or why other remedial measures should notbe taken (explaining that the joint answering testimony of two people testifying simultaneously in the pluralpreliminarily calls into question the identity of the actual witness who is testifying and presents potentialprocedural infirmities). In response, the TOs requested the substitution of the joint answering testimony withtestimony sponsored solely by Dr. Avera, a request which was unopposed by any of the active parties. OnMarch 17, Judge Sterner accepted the replacement testimony and, accordingly, found the February 26 showcause order moot and cancelled pending oral argument. Also since the last Report, in response to anunopposed March 11 motion by FERC Trial Staff, chief Judge Wagner extended the date for the issuance ofthe initial decision in these proceedings to December 30, 2015, leaving to Judge Sterner the authority to ruleon the remaining procedural dates proposed by Staff. On March 16, Judge Sterner issued an order revisingthe procedural schedule, including moving the data update cut-off date. As noted above, the data cutoff datewas moved to May 29, 2015, and hearings are now set to begin June 25, 2015. Finally, on March 23, ascorrected on March 26, FERC Staff submitted its direct and answering testimony.

If you have any questions concerning this matter, please contact Joe Fagan (202-218-3901;[email protected]) or Eric Runge (617-345-4735; [email protected]).

• 206 Investigation: FCM Performance Incentives (Compliance Proceedings) (EL14-52; ER14-2419)

Rehearing remains pending of the FERC’s May 30, 2014 PI Order20 on the FCM PI Jump Ball Filingand its October 20 Order21 on the first compliance filing in response to the PI Order. As previously reported,the FERC instituted this proceeding, pursuant to section 206 of the FPA, in its May 30 PI Order on the FCMPerformance Incentives Jump Ball filing. In the PI Order, the FERC concluded that the ISO’s FCM paymentdesign was “unjust and unreasonable, because it fails to provide adequate incentives for resourceperformance, thereby threatening reliable operation of the system and forcing consumers to pay for capacitywithout receiving commensurate reliability benefits.”22 The FERC directed the ISO to submit “Tariffrevisions reflecting a modified version of its [PFP] proposal and an increase in the Reserve Constraint PenaltyFactors, consistent with NEPOOL’s proposal.”23 The FERC-established refund effective date was June 9,2014.24 Requests for clarification and/or rehearing of the PI Order were filed by: NEPOOL, Connecticut and

19 “Complaint-Aligned Parties” are the CT AG, CT OCC, CT PURA, ME OPA, MA DPU, MMWEC, NHEC, NHOCA, NH PUC, RI PUC, VT DPS, Acadia Center (formerly Environment Northeast), The Energy Consortium, AssociatedIndustries of Massachusetts (“AIM”), and the Industrial Energy Consumer Group (“IECG”).

20 ISO New England Inc. and New England Power Pool, 147 FERC ¶ 61,172 (May 30, 2014) (“PI Order”), clarif.and reh’g requested.

21 ISO New England Inc., 149 FERC ¶ 61,009 (Oct. 2, 2014) (“October 2 Order””), reh’g requested.

22 PI Order at P 23.

23 Id. at P 1.

24 The June 3 notice of this proceeding was published in the Fed. Reg. on June 9, 2014 (Vol. 79, No. 110) pp.32,937-89.


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Rhode Island,25 Dominion, MMWEC, Indicated Generators,26 NEPGA, NextEra, Potomac Economics, andPSEG/NRG. On July 28, the FERC issued a tolling order affording it additional time to consider therehearing requests, which remain pending before the FERC.

FCM PI Jump Ball Compliance Filing I (ER14-2419-001). On October 2, 2014, the FERC accepted inpart, subject to condition, and rejected in part, the ISO’s July 14, 2014 compliance filing (“Compliance Filing I”)that, as previously reported, had been filed in response to directives in the PI Order.27 While accepting nearly allof the provisions proposed in Compliance Filing I, the October 2 Order rejected the ISO’s compliance proposalconcerning improper price signals caused by binding intra-zonal transmission constraints. The FERC found thatan exemption was not necessary for resources on the export side of an intra-zonal transmission constraint during aCapacity Scarcity Condition and directed the ISO to submit a further compliance filing (since filed and accepted)to revise Market Rule Section 13.7 by removing the language that reflected that aspect of the ISO’s July 14compliance proposal and restoring language in Sections III.13.7.2.2(a) and III.13.7.2.2(b) ISO-NE originallyproposed by the ISO in its January 17 Filing. The Tariff sections accepted were accepted effective June 9, 2014,December 3, 2014, and June 1, 2018, as requested. Connecticut/Rhode Island28 and Public Systems29 requestedrehearing of the October 2 Order on November 3, 2014. On December 3, the FERC issued a tolling orderaffording it additional time to consider the rehearing requests, which remain pending before the FERC.

If you have any questions related to these proceedings, please contact Dave Doot (860-275-0102;[email protected]), Pat Gerity (860-275-0533; [email protected]), or Sebastian Lombardi (860-275-0663; [email protected]).

• 206 Investigation: Consistency of ISO-NE (DA) Scheduling Practices with Natural Gas SchedulingPractices to be Adopted in Docket RM14-2 (EL14-23)

As previously reported, on March 20, 2014, the FERC initiated this proceeding, pursuant to Section206 of the FPA, to ensure that the ISO’s scheduling, particularly its Day-Ahead scheduling practices,correlate with any revisions to the natural gas scheduling practices to be ultimately adopted by the FERC inRM14-2 (see Section XIII below).30 Noting its concern about the lack of synchronization between the Day-Ahead scheduling practices of interstate natural gas pipelines and electricity markets, the FERC directed eachISO and RTO, including ISO-NE, within 90 days after publication of a Final Rule in Docket RM14-2 in theFederal Register:

(1) to make a filing that proposes tariff changes to adjust the time at which the results ofits day-ahead energy market and reliability unit commitment process (or equivalent) areposted to a time that is sufficiently in advance of the Timely and Evening NominationCycles, respectively, to allow gas-fired generators to procure natural gas supply andpipeline transportation capacity to serve their obligations, or (2) to show cause why suchchanges are not necessary. In their responses, each ISO and RTO must explain how its

25 “Connecticut and Rhode Island” are: the Connecticut Public Utilities Regulatory Authority (“CT PURA”), theConn. Office of Consumer Counsel (“CT OCC”), George Jepsen, Att’y Gen. for the State of Conn. (“CT AG”), the Conn.Department of Energy and Environmental Protection (“CT DEEP”), the United Illuminating Company (“UI”) and the RhodeIsland Div. of Pub. Utils. and Carriers (“RI PUC”).

26 “Indicated Generators” are: Exelon Corp. (“Exelon”), EquiPower Resources Management, LLC (“EquiPower”),Essential Power, LLC (“Essential Power”), and Dynegy Marketing and Trade, LLC and Casco Bay Energy Company, LLC(together, “Dynegy”).

27 ISO New England Inc., 149 FERC ¶ 61,009 (Oct. 2, 2014) (“October 2 Order”), reh’g requested.

28 “Connecticut/Rhode Island” are the CT PURA, CT AG, CT OCC, CT DEEP, and the RI PUC.

29 “Public Systems” are CMEEC, MMWEC, NHEC, and VEC.

30 Cal. Indep. Sys. Op. Corp. et al., 146 FERC ¶ 61,202 (Mar. 20, 2014). The New England 206 proceeding wasdocketed as EL14-23.


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proposed scheduling modifications are sufficient for gas-fired generators to secure naturalgas pipeline capacity prior to the Timely and Evening Nomination Cycles.31

The Commission expects to issue a final order in this section 206 proceeding within 90 days of thefilings required under the March 20 order. Interventions by over 40 parties, including one by NEPOOL, werefiled in the New England-specific docket. This matter is pending action in RM14-2. If you have anyquestions concerning this matter, please contact Dave Doot (860-275-0102; [email protected]), JoeFagan (202-218-3901; [email protected]), or Sebastian Lombardi (860-275-0663;[email protected]).

• NESCOE FCM Renewables Exemption Complaint (EL13-34)

Rehearing of the FERC’s February 12, 2013 order denying NESCOE’s FCM Renewable ExemptionComplaint32 remains pending before the FERC. As previously reported, NESCOE instituted this December28, 2012 complaint in response to the ISO’s December 3, 2012 FCM compliance filing that implementedbuyer-side mitigation without an exemption for state-sponsored public policy resources. NESCOE assertedthat the ISO’s proposed Minimum Offer Price Rule (“MOPR”) would likely exclude from the FCM newrenewable resources developed pursuant to state statutes and regulations, and thereby result in customersbeing forced to purchase more capacity than is necessary for resource adequacy and proposed an alternativerenewables exemption (the “Renewables Exemption Proposal”). In denying the Complaint, the FERC foundthat “NESCOE has failed to meet its burden under section 206 to demonstrate that ISO-NE’s MOPR is unjust,unreasonable or unduly discriminatory” as applied to the New England Capacity Market.33 The FERCdeclined to set the case for hearing, and therefore denied the motion to consolidate this proceeding with theFCA8 Revisions Compliance Filing proceeding (ER12-953),34 on which it concurrently issued an orderconditionally accepting in part and dismissing in part the ISO’s proposed compliance filing. Rehearing wasrequested by NESCOE, the CT PURA, and the MA DPU on March 14, 2013. On March 29, 2013, NEPGAfiled an answer challenging NESCOE’s request for rehearing. On April 15, 2013, the FERC issued a tollingorder affording it additional time to consider the rehearing requests, which remain pending before the FERC.If you have any questions concerning this matter, please contact Sebastian Lombardi (860-275-0663;[email protected]), Harold Blinderman (860-275-0357; [email protected]) or Dave Doot(860-275-0102; [email protected]).

• Base ROE Complaint (2011) (EL11-66)

On March 3, the FERC issued Opinion 531-B,35 denying rehearing of Opinion 53136 and Opinion531-A.37 Other than the filing of regional and local refund reports, and absent a successful challenge in thefederal courts of appeals or Supreme Court, these proceedings have now been concluded. Challenges, if any,to Opinions 531, 531-A and/or 531-B must be filed in a federal court of appeals on or before May 4, 2015.Any such further developments will be reported on in the federal court section of future Reports.

31 Id. at P 19.

32 New England States Comm. on Elec. v. ISO New England Inc., 142 FERC ¶ 61,108 (Feb. 12, 2013), reh’grequested.

33 Id. at P 32.

34 Id. at P 30.

35 Martha Coakley, Mass. Att’y Gen. et al., Opinion No. 531-B, 150 FERC ¶ 61,165 (Mar. 3, 2015) (“Opinion 531-B”).

36 Martha Coakley, Mass. Att’y Gen. et al., 147 FERC ¶ 61,234 (June 19, 2014) (“Opinion 531”), order on paperhearing, 149 FERC ¶ 61,032 (2014), reh’g denied, 150 FERC ¶ 61,165 (Mar. 3, 2015).

37 Martha Coakley, Mass. Att’y Gen. et al., 149 FERC ¶ 61,032 (Oct. 16, 2014) (“Opinion 531-A”).


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As previously reported, Opinion 531, affirmed in part, and reversed in part, Judge Cianci’s InitialDecision.38 In Opinion 531, the FERC announced a new approach that it will use for determining publicutilities’ base ROE and a change in its’ practice on post-hearing ROE adjustments. With respect to the NewEngland TOs’, the FERC applied its new that approach to the facts of this proceeding to determine theNETOs’ base ROE (10.57%), and established a paper hearing, addressed in Opinion 531-A, to allow theparticipants a limited opportunity to address application of the new ROE approach in those circumstances.39

Several parties requested rehearing and/or clarification of Opinion 531, including the TOs, EMCOS,American Municipal Power (“AMP”), and NRECA/APPA.40

Opinion 531-A set the Transmission Owners’ base ROE at 10.57%, with a maximum ROE includingincentives not to exceed 11.74%. Opinion 531-A affirmed that the 4.39 % projected long-term growth inGDP was the appropriate long-term growth projection to be used in the two-step DCF methodology fordetermining the TOs’ ROE. The FERC directed the TOs to (i) submit a compliance filing with revised ratesreflecting a 10.57% base ROE and a total ROE (inclusive of transmission incentive ROE adders) notexceeding 11.74%, effective October 16, 2014, and (ii) to provide refunds, with interest, for the 15-monthrefund period in this proceeding (October 1, 2011 through December 31, 2012). On November 6, the TOsrequested an extension of time to issue and file the required regional and local refunds and refund reports.The FERC granted that request on November 26, 2014, setting the following deadlines: April 30, 2015, forregional refunds; June 30, 2015, for the regional refund report; July 31, 2015, for local refunds; andSeptember 30, 2015, for the local refund report. On March 31, the TOs requested a second extension of time.In light of the changes in the refund calculation resulting from Opinion No. 531-B and additional timerequired by the ISO, the TOs requested that the following deadlines be permitted: August 31, 2015, forregional refunds; October 31, 2015, for the regional refund report; October 31, 2015, for local refunds; andDecember 31, 2015, for the final local refund report.



• Opinion 531-A Compliance Filing: TOs (ER15-414)

On November 17, 2014, the New England TOs submitted tariff changes (to both the regional andlocal rates in the ISO OATT) in response to Opinion 531-A. Specifically, Section II.A.2.(a)(iii) of theAttachment F Implementation Rule was revised to reflect an ROE of 11.07% – the 10.57% base ROE directedby the Commission in Opinion 531-A plus the 50 basis point adder for ISO-NE participation. The TOs alsorevised Section II.A.2.(a)(iii) of the Attachment F Implementation Rule to require the PTOs to calculate theirtotal ROE each year under both regional and local rates and to reduce any ROE incentives included inregional rates to the extent necessary to ensure that the PTOs’ total ROE does not exceed 11.74% (the TOs’maximum ROE as identified by the FERC). The TOs also revised a number of provisions of the Attachment FImplementation Rule to include cross-references to Section II.A.2.(a)(iii). An effective date of October 16,2014, consistent with Opinion 531-A, was requested. Interventions were filed by the IECG, Complainant-Aligned Parties, and EMCOS. Protests were filed by EMCOS and the Complainant-Aligned Parties. On

38 Martha Coakley, Mass. Att’y Gen. et al., 144 FERC ¶ 61,012 (July 5, 013) (“Initial Decision”) (finding unjustand unreasonable the TO’s 11.14% ROE and that the ROE should be 10.6% for the Oct. 2011 through Dec. 2012 “lockedin/refund period” and 9.7% from Jan. 2013 forward, subject to further updating or modification by the FERC).

39 Opinion 531 at P 1.

40 In Opinion 531-B, the FERC denied the requests for rehearing of AMP and NRECA/APPA on the basis that theywere not parties to the proceeding (having failed in the first instance to meet their burden of justifying their lateinterventions). Opinion 531-B at P 15.


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December 23, the TOs answered the protests of EMCOS and Complainant-Aligned Parties. Complainant-Aligned Parties answered the TOs’ December 23 answer on January 13.

In light of Opinion 531-B, the TOs indicated in a March 31 motion that further amendments would berequired. The TOs indicated that that the amendments would likely resolve the contested issues raised byEMCOS and Complainant-Aligned Parties in response to the November 17 filing. Accordingly, the TOsrequested that the FERC defer action on the pending November 17 filing until after the amendments havebeen filed and the corresponding period for comments has passed.


• FCA-10 Capacity Zone Boundaries (ER15-1462)

On April 6, the ISO filed a notice identifying two potential new boundaries for Capacity Zones for thetenth Forward Capacity Auction (“FCA-10”): (1) a ‘Southeastern New England (“SENE”) Capacity Zone’ (animport-constrained zone that is a combination of the existing NEMA/Boston and SEMA/RI Capacity Zones) and(2) a ‘Northern New England (“NNE”) Capacity Zone’ (an export-constrained zone that is a combination of theexisting Maine, New Hampshire and Vermont Load Zones). No changes are proposed to the West/Central MA orConnecticut zones. If the FERC approves the identified boundaries, then a determination as to whether thepotential zones will actually be modeled as separate Capacity Zones in FCA-10 will be conducted in accordancewith Section III.12.4(b) of Market Rule 1 and addressed in the FCA-10 information filing to be submitted in earlyNovember 2015. An order accepting this filing on or before May 29, 2015 was requested. The annual assessmentof transmission transfer capability that formed the basis for the identification of the new boundaries was presentedto the PAC on March 24. Additional input on the assessment was solicited at an April 2 Reliability Committeemeeting. At the April 2 meeting, the RC voted 34.25% in favor of recommending to the ISO that theidentification of the zonal boundaries was performed in accordance with Section II, Attachment K and SectionIII.12.5 of the ISO Tariff. This matter will not be separately considered by the Participants Committee.Comments on this filing are due on or before April 27, 2015. If you have any questions concerning this matter,please contact Eric Runge (617-345-4735; [email protected]).

• FCA9 Results Filing (ER15-1137)

As previously reported, the ISO filed the results of the ninth FCA (“FCA9”) held February 2, 2015 onFebruary 27, identifying the following highlights:

• FCA9 Capacity Zones were Connecticut (“CT”), Northeastern Massachusetts/Boston(“NEMA/Boston”), Southeastern Massachusetts/Rhode Island (“SEMA/RI”) and Rest-of-Pool(Western/Central Massachusetts, New Hampshire, Vermont and Maine);

• FCA9 commenced with a starting price of $17.728/kW-mo.•Resources will be paid as follows:

♦ In CT, NEMA/Boston, and Rest-of-Pool - $9.551/kW-month♦ New York AC Ties imports - $7.967/kW-month♦ New Brunswick imports - $3.94/kW-month♦ SEMA/RI new resources - $17.728/kW-month♦ SEMA/RI existing resources - $11.08/kW-month

•No de-list bids were rejected for reliability reasons

The ISO asked the FERC to accept the FCA9 rates and results, effective June 27, 2015. Commentson this filing are due on or before April 13, 2015. Interventions have thus far been filed by NEPOOL,Calpine, Emera, Essential Power Entergy, EPSA, EquiPower, Exelon, HQ US, NESCOE, NRG, PSEG, andTransCanada. If you have any questions concerning this matter, please contact Sebastian Lombardi (860-275-0663; [email protected]) or Pat Gerity (860-275-0533; [email protected]).


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• eTariff Corrections (ER15-1455)

On April 6, the ISO submitted corrections to the following sections of the ISO’s eTariff: I.2.2(Definitions); III.2 and III.2 (LMPs, Real-Time Reserve Clearing Prices Calculation; Accounting/Billing);III.13.2(Annual FCA); III.13.7 (Performance, Payments & Charges in the FCM); and MR1 Appendix E2 (LoadResponse Program). The corrections are needed due to the overlapping timing of the filing and acceptance ofvarious Tariff filings. Comments on this filing are due on or before April 27. If you have any questionsconcerning this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• LMP Calculator Replacement (ER15-1238)

On March 13, the ISO and NEPOOL jointly submitted revisions to Market Rule 1 to replace the part ofthe system dispatch software that calculates prices in the Real-Time Energy Market (the “LMP Calculator”).Real-Time price calculations will now be based on the same software and inputs used to produce the DispatchRates, ensuring that Real-Time Prices and Dispatch Rates are more closely aligned. A May 27, 2015 effectivedate was requested. These changes were supported by the Participants Committee at its March 6, 2015 (ConsentAgenda Item #1). A doc-less intervention was filed by Entergy. Comments on this filing are due on or beforeApril 3; none were filed and this matter is pending before the FERC. If you have any questions concerning thismatter, please contact Sebastian Lombardi (860-275-0663; [email protected]).

• CSO Termination: DFC-ERG CT (ER15-1201)

Pursuant to Market Rule 1 § 13.3.4(c), the ISO filed on March 9 to terminate a CSO for Resource No.16729 held by Project Sponsor DFC-ERG CT, LLC (“DFC-ERG CT”). The ISO indicated that, upon FERCacceptance of the filing, the ISO will draw down the amount of financial assurance provided by DFC-ERG CTwith respect to the CSO. Interventions were filed by NEPOOL and Entergy. Comments on this filing were dueon or before March 30; none were filed. On April 9, the FERC accepted the termination. Unless the April 9 orderis challenged, this proceeding will be concluded. If you have any questions concerning this matter, please contactPat Gerity (860-275-0533; [email protected]).

• PER Mechanism Elimination (FCA-10) (ER15-1184)

On March 6, the ISO and NEPOOL jointly submitted revisions to Market Rule 1 to eliminate the FCMPeak Energy Rent (“PER”) mechanism beginning June 1, 2019, with the commencement of the CapacityCommitment Period associated with the tenth Forward Capacity Auction (“FCA-10”). A May 6, 2015 effectivedate was requested. These changes were supported by the Participants Committee at its March 6, 2015 (AgendaItem #6A). Comments on this filing were due on or before March 27. Interventions were filed by Calpine, CTAG, Dominion, Emera, Exelon, NESCOE, and NRG. Comments supporting the filing were filed by Entergy,GDF Suez and NEPGA. Entergy asked the FERC to accept the proposed changes without change or condition.NEPGA and GDF Suez asked the FERC to accept the proposed changes, but also asked the FERC to “directNEPOOL and ISO-NE to commence a stakeholder consideration of Tariff changes for the period preceding theFCA 10 Capacity Commitment Period necessary to address subjecting resources to a reduction in capacitypayments due to a real-time price the resources did not receive.” This matter is pending before the FERC. If youhave any questions concerning this matter, please contact Sebastian Lombardi (860-275-0663;[email protected]).

• Forward Reserve Obligation Charge Changes (ER15-1009)

On March 30, the FERC accepted a revised Market Rule Section III.10.4 to change the calculation of theForward Reserve Obligation Charge that is assessed against Market Participants with resources that participate inthe Forward Reserve Market and provide Operating Reserve (the “FROC Changes”). As previously reported, theFROC Changes expand the scope of the Forward Reserve Obligation Charge so that it applies in twocircumstances not picked up under the current Market Rule -- when a “higher quality” form of reserves (i.e.,TMNSR) is used to satisfy a Forward Reserve Obligation for a “lower quality” form of reserves (i.e., TMOR),


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and when a Forward Reserve Resource in one Reserve Zone is assigned to satisfy a Forward Reserve Obligationin another Reserve Zone. The FROC Changes are designed to ensure that the Forward Reserve ObligationCharge does not take away the incremental compensation that a Market Participant receives for providing a morevaluable, higher quality reserve service in Real-Time than obligated in the Forward Reserve Market. The changeswere accepted effective as of June 1, 2015, as requested. Unless the March 30 order is challenged, thisproceeding will be concluded. If you have any questions concerning this matter, please contact SebastianLombardi (860-275-0663; [email protected]).

• Winter 2014/15 Reliability Program (ER14-2407)

The ISO’s request for rehearing of the January 20, 2015 clarification41 of the Winter 2014/15 ReliabilityProgram Order42 remains pending. In the Winter Reliability Program Clarification Order, the FERC clarified, asrequested by NEPGA, that its directive in the Winter 2014/15 Reliability Program Order “intended that ISO-NEwould determine whether a winter reliability solution is necessary for the 2015-2016 winter and future winters,and, if so, develop an appropriate market-based solution through the stakeholder process that can be implementedbeginning with the 2015-2016 winter. While the two-settlement capacity market design could help address winterreliability concerns in the future, that design will not be fully implemented until the 2018-2019 CapacityCommitment Period.” The ISO requested rehearing of the Clarification Order on February 19, asking the FERC“to reverse this decision and permit the continuation of the winter reliability program construct, possibly with anexpanded scope to encompass other resource types. The reversal is warranted given that … the options fordeveloping a market-based solution in the context of existing obligations are, at best, potentially less effectivethan the winter reliability programs, and, at worst, less effective, inefficient, controversial and expensive toimplement.” On March 4, NESCOE filed an answer to the ISO’s rehearing request. In its answer, NESCOEasked that, should the FERC direct implementation of a new market-based program, it clarify that such a programmust be “measured by the benefits provided to consumers” and “compared against the costs of the 2013/14 and2014/15 winter programs.” NESCOE also asked that the FERC not direct, in this proceeding, dramatic changes tothe winter program, particularly not increases or changes to the RCPFs. On March 23, 2015, the FERC issued atolling order affording it additional time to consider the ISO’s rehearing request, which remains pending beforethe FERC. If you have any questions concerning this proceeding, please contact Sebastian Lombardi (860-275-0663; [email protected]).

• Demand Curve Changes (ER14-1639)

As previously reported, the FERC denied rehearing of the Demand Curve Order,43 but clarified (agreeingwith Exelon and Entergy) that a resource that elects to utilize the renewables minimum offer price rule exemptionshould not also be allowed to utilize the new resource lock-in).44 Accordingly, the FERC directed the ISO tosubmit, on or before March 2, 2015, a compliance filing clarifying that a resource may not utilize both therenewable resource exemption and the new resource price lock-in. On March 30, as reported more fully inSection XVI below, NextEra, NRG and PSEG petitioned the DC Circuit Court of Appeals for review of theFERC’s Demand Curve orders. Developments in that proceeding will be reported in Section XVI below.

41 ISO New England Inc. and New England Power Pool Participants Comm., 150 FERC ¶ 61,029 (Jan. 20, 2015)(“Winter Reliability Program Clarification Order”), reh’g requested.

42 ISO New England Inc. and New England Power Pool Participants Comm., 148 FERC ¶ 61,179 (Sep. 9, 2014)(“Winter 2014/15 Reliability Program Order”), clarif. granted, 150 FERC ¶ 61,029 (Jan. 20, 2015). The Winter 2014/15Reliability Program Order conditionally accepted the Tariff revisions jointly filed by the ISO and NEPOOL intended tomaintain reliability through fuel adequacy by creating incentives for dual-fuel resource capability and participation, offsettingthe carrying costs of unused firm fuel purchased by generators and providing compensation for demand response services(“Winter 2014/15 Reliability Program”).

43 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).

44 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”).


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Compliance Filing (ER14-1639-004). On March 2, the ISO submitted changes, in response to theDemand Curve Clarification Order, clarifying that a resource, including generation resources and eligible demandresources, cannot utilize both the price lock-in election and the renewable resource exemption. The ISO requesteda March 2 effective date for the changes (beginning with FCA-10), noting that the changes would not apply to thealready-completed qualification process for FCA9. The ISO reported that, in FCA9, resources totaling 12.96 MWutilized both the renewable resource exemption and the price lock-in election. Comments on the ISO’scompliance filing were due on or before March 23. In its comments, NEPOOL reported that the ParticipantsCommittee unanimously supported the compliance changes at its March 6 meeting. The Compliance Filing ispending before the FERC. If you have any questions concerning these matters, please contact SebastianLombardi (860-275-0663; [email protected]).

• FCM Performance Incentives Jump Ball Filing (ER14-1050)

Rehearing of the FCM PI Order remains pending. As previously reported, the ISO and NEPOOLsubmitted on January 17, 2014, two alternative versions of Market Rule changes intended to improve theoperating performance of capacity resources in New England -- the “ISO-NE Proposal” and the “NEPOOLProposal”. As explained above, on May 30, 2014, the FERC issued an order in response to the jump ball filing.45

The FERC concluded that the existing Tariff, specifically the current FCM payment design, “is unjust andunreasonable, because it fails to provide adequate incentives for resource performance, thereby threateningreliable operation of the system and forcing consumers to pay for capacity without receiving commensuratereliability benefits” and instituted a proceeding under Section 206 of the FPA (see EL14-52 in Section I above).Concluding that neither the ISO-NE Proposal nor the NEPOOL Proposal, standing alone, had been shown to bejust and reasonable, the FERC, drawing features from each Proposal, went on to direct the ISO to submit by July14, 2014 Tariff revisions reflecting a modified version of the ISO-NE Proposal and an increase in the ReserveConstraint Penalty Factors, consistent with NEPOOL’s Proposal. Specifically, the compliance filing was toinclude (1) changes to implement ISO-NE’s proposed two-settlement capacity market design with certainmodifications, and (2) changes to increase the RCPF values for Thirty-Minute Operating Reserves to$1,000/MWh and for Ten-Minute Non-Spinning Operating Reserves to $1,500/MWh. The FERC established aJune 9, 2014 refund effective date. Requests for clarification and/or rehearing of the PI Order were filed by:NEPOOL, Connecticut and Rhode Island, Dominion, MMWEC, Indicated Generators, NEPGA, NextEra,Potomac Economics, and PSEG/NRG. On July 28, 2014, the FERC issued a tolling order affording it additionaltime to consider the requests for clarification and/or rehearing, which remain pending before the FERC.

If you have any questions concerning this matter, please contact Dave Doot (860-275-0102;[email protected]), Harold Blinderman (860-275-0357; [email protected]), Eric Runge(617-345-4735; [email protected]) or Sebastian Lombardi (860-275-0663;[email protected]).

• FCM Redesign Compliance Filing: FCA8 Revisions (ER12-953 et al.)

Requests for rehearing of the FCA8 Revisions Order remain pending. As previously reported, the FERC,on February 12, 2013, conditionally accepted in part, and rejected in part, revisions to the FCM and FCM-relatedrules in the Tariff (“FCA8 Revisions”) filed by the ISO and the PTO AC.46 The FCA8 Revisions Order acceptedthe following aspects of the FCA8 Revisions as compliant with its prior FCM Orders: the ISO’s offer reviewtrigger prices;47 unit specific offer review;48 the ISO’s proposal to subject a resource to offer floor mitigation untilthat resource clears in one FCA; imports’ treatment under MOPR;49 no exemptions to MOPR for new Self-

45 See PI Order.

46 ISO New England Inc., 142 FERC ¶ 61,107 (Feb. 12, 2013) (“FCA8 Revisions Order”).

47 FCA8 Revisions Order at PP 37-38.

48 Id. at P 53.

49 Id. at P 70.


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Supplied Resources;50 the application of mitigation to all new resources offering into the FCM, includingrenewables that are procured pursuant to state policy initiatives;51 $1.00/kW-month Threshold to trigger IMMreview of Dynamic De-List Bids;52 and a number of other additional revisions.53 The FCA8 Revisions Orderrejected: the ISO’s proposed methodology for reducing the offer floor of an uncleared resource that has alreadyachieved commercial operation at the time of an FCA (directing the ISO to submit a revised proposal that subjectsa resource to an offer floor until it has demonstrated that it is needed by the market);54 and the ISO’s request tomodel only 4 capacity zones for FCA8 (the ISO’s Capacity Zones Changes were accepted in ISO New EnglandInc., 147 FERC ¶ 61,071 (2014)). Two requests for rehearing of the FCA8 Revisions Order were filed on March15, 2013, one by MMWEC, NHEC, APPA, NEPPA, and NRECA; the other, by EMCOS and Danvers. On April11, NEPGA filed an answer to the MMWEC et al. request. On April 15, 2013, the FERC issued a tolling orderaffording it additional time to consider the rehearing requests, which remain pending before the FERC. If youhave any questions concerning these matters, please contact Sebastian Lombardi (860-275-0663;[email protected]), Eric Runge (617-345-4735; [email protected]) or Dave Doot (860-275-0102;[email protected]).

IV. OATT Amendments / TOAs / Coordination Agreements

• ETU Rule Changes (ER15-1050, -1051)

On February 13, the ISO, NEPOOL and PTO AC jointly submitted changes to the Tariff and TOA toimprove the Elective Transmission Upgrade (“ETU”) process (“ETU Rule Changes”). The ETU Rule Changesincorporate into the ISO OATT new Schedule 25 that will govern the interconnection of all forms of ETUs to theNew England System, defining “Interconnection Service” for ETUs, and introducing two new forms of capacityand energy interconnection service – Capacity Network Import Interconnection Service (“CNIIS”) and NetworkImport Interconnection Service (“NIIS”) – for the interconnection of all new controllable External ETUs that areclassified as Merchant Transmission Facilities (“MTF”) or Other Transmission Facilities (“OT”) to theAdministered Transmission System in a manner similar to internal Generating Facilities. The ETU Rule Changesalso provide for the allocation of capacity interconnection service to controllable MTF/OTF External ETUs forthe import of capacity into New England through the FCM, and provide that Internal ETUs may become directlyassociated with a specific Generating Facility seeking CNRIS so that they can be studied together and therebyincrease the Generating Facility’s ability to qualify for the FCM. Other changes necessary to support the revisedtreatment of EUs include: changes to the Tie Benefits calculation to exclude external ETUs eligible for CNIIS andNIIS, inclusion of ETUs in the FCM Network Model Assumptions, transition rules for ETU applications, andconforming and other ministerial Tariff revisions. A February 16, 2015 effective date was requested. Thesechanges were unanimously supported by the Participants Committee at the February 6, 2015 meeting by way ofConsent Agenda Item #s 2-4. Doc-less interventions were filed by ConEd, Entergy, Eversource, HQUS,NESCOE, NHT, Northern Pass, and NRG. Champlain VT filed comments generally supporting the changes, butprotesting its Revised Queue Position (requesting that the ISO be directed to reconfigure the Revised Queue suchthat queue positions for ETUs reflect any material modifications made to interconnection requests prior to theEffective Date). Answers to the Champlain VT comments were filed jointly by the ISO, NEPOOL ad PTO AC,and by Anbaric Transmission, Eversource and Northern Pass, and SunEdison. On March 31, Champlain VTresponded to the answers to its limited protest. On April 3, Anbaric responded to Champlain VT’s March 31answer. This matter is pending before the FERC. If you have any questions concerning this matter, pleasecontact Eric Runge (617-345-4735; [email protected]).

50 Id. at P 80.

51 Id. at P 97.

52 Id. at P 126.

53 Id. at P 127.

54 Id. at PP 63-64.


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• Order 676-H Compliance: Revisions to Schedule 24 (ER15-519)

On December 1, 2014, the ISO submitted a compliance filing requesting (i) renewal of waivers previouslygranted in response to Order 676, 676-C, 676-E, and 890, (ii) waiver of certain new Order 676-H-approvedstandards, and (iii) acceptance of Schedule 24 Revisions incorporating by reference the North American EnergyStandards Board (“NAESB”) Wholesale Electric Quadrant (“WEQ”) v.003 Standards for which waiver was notrequested. A February 2, 2015 effective date was requested. The Schedule 24 revisions were unanimouslysupported by the Participants Committee at its December 5 annual meeting. Interventions were filed by Exelonand NU. In its comments, NEPOOL reported on that support and requested that the FERC accept the ISO-NEOATT revisions and grant the requested waivers. This matter remains pending before the FERC. If you have anycomments or concerns, please contact Eric Runge (617-345-4735; [email protected]) or Kristin Sullivan(617-345-4657; [email protected]).

• Order 676-H Compliance: PTOs, SSPs, CSC et al. (ER15-517)

Also on December 1, 2014, the PTO Administrative Committee (“PTO AC”), on behalf of theParticipating Transmission Owners (“PTOs”), the Schedule 20A Service Providers (“SSPs”), Cross-Sound CableCompany, LLC (“CSC”), New England Power Company (“NGrid”), Northeast Utilities Service Company(“NUSCO”), Unitil Energy Systems, Inc., Fitchburg Gas and Electric Light Company, and the ISO (collectively,the “Filing Parties”), jointly submitted a filing to request (continued and new) waiver of, and to adopt, certainVersion 003 WEQ Standards adopted NAESB incorporated by reference into FERC regulations pursuant to Order676-H. Waiver requests included those previously granted for Orders 676-C and 676-E, waiver of WEQ-4(limited in the case of CSC),WEQ-8, WEQ-11, WEQ-15, WEQ-21, the OASIS-related Standards, and variousadditional waivers under the individual Schedule 21 service schedules. Interventions were filed by NEPOOL andNU. Comments on this filing were due on or before December 22; none were filed and this matter also remainspending before the FERC. If you have any comments or concerns, please contact please contact Eric Runge (617-345-4735; [email protected]) or Kristin Sullivan (617-345-4657; [email protected]).

• Order 1000 Interregional Compliance Filing (ER13-1960; ER13-1957)

On July 10, 2013, the ISO, NEPOOL and the PTO AC jointly filed revisions to Sections I and II of theTariff to comply with the interregional coordination and cost allocation requirements of Orders 1000 and 1000-A(the “Order 1000 Interregional Compliance Changes”) (ER13-1960). In addition, the ISO, on behalf of itself,NYISO and PJM, filed an Amended and Restated Northeastern ISO/RTO Planning Coordination Protocol(“Amended Protocol”) as part of its compliance changes (ER13-1957). The Order 1000 InterregionalCompliance Changes include (i) revisions to Attachment K to add provisions describing the interregionalcoordination provisions included in the Amended Protocol, as well as adding other provisions facilitating theconsideration of interregional solutions to regional needs; (ii) a new Schedule 15 reflecting the methodology forallocation among ISO-NE and NYISO of the costs of approved interregional transmission projects; (iii) revisionsto Schedule 12 describing the regional cost allocation within New England of the costs of approved interregionaltransmission projects; and (iv) conforming changes to Tariff Section I. The Order 1000 Interregional ComplianceChanges and the Amended Protocol were supported by the Participants Committee at its June 27 SummerMeeting. On August 7, the FERC extended the comment deadline on these filings to and including September 9,2013. Doc-less motions to intervene were filed by a number of New England parties in both proceedings,including Dominion, Exelon, PPL, PSEG, and NEPOOL (in the Protocol proceeding (in which it was not a filingparty)). On August 26, 2013, NEPOOL filed comments supporting the Protocol. NEPOOL added that “From astakeholder perspective, stakeholder input into revisions to the Protocol as it evolves over time would be easierand more likely to be taken into account if it were made part of the individual regional tariffs of each of theNortheast ISOs rather than existing solely as a stand-alone three-party agreement”. On September 9, NESCOEsubmitted comments generally supporting the filings, but reserving the right to further comment on these filingsshould the substance of the changes be modified as a result of further FERC (see ER13-193 and ER13-196 below)or federal court proceedings. Public Interest Organizations55 raised concerns that the Protocol and related

55 “Public Interest Organizations” are Conservation Law Foundation, Acadia Center, Natural Resources DefenseCouncil, Pace Energy and Climate Center, and the Sustainable FERC Project.


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amendments “do not meet certain of the transparency and cost allocation aspects of [Order 1000]’s minimumrequirements.” On September 24, 2013, the ISO answered Public Interest Organizations’ and NEPOOL’scomments. These matters remain pending before the FERC. If you have any comments or concerns, pleasecontact Eric Runge (617-345-4735; [email protected]).

• Order 1000 Compliance Filing (ER13-193; ER13-196)

As previously noticed, the FERC issued, on March 19, 2015, its long-awaited Order on Rehearingand Compliance56 of the region’s Order 1000 compliance filing.57 A memo summarizing the 200-page orderin more detail was circulated by NEPOOL Counsel on March 23 and posted on the NEPOOL websiteLitigation Report Updates page. As previously noted, the March 19 Order:

• Affirmed an effective date 60 days from the date of the issuance of the March 19 Order andrequired additional compliance filings within that same time period (i.e. on or before May 18,2015).

• Grandfathered projects that are listed as “Proposed” or “Planned” as of the effective date asexempt from the new transmission development regime, unless the ISO is re-evaluating, orsubsequently determines it necessary to reevaluate, the solution design for such transmissionprojects as of the effective date.

• Required the ISO to make a further compliance filing to provide a list of transmission providersand the enrollment process that defines how transmission providers enroll in the transmissionplanning region.

• Affirmed the finding that the existing framework of the Needs Assessment Study Group isinconsistent with the transparency principle of Order 1000 and accepted use of the PAC in itsplace.

• Affirmed FERC’s prior determination that the ISO and not the States must be the one that selectssolutions that meet transmission needs driven by Public Policy Requirements.

• Affirmed the elimination of the incumbent transmission owners’ right of first refusal (“ROFR”) tobuild and own transmission projects called for by the Regional System Plan.

• Affirmed the exception to the ROFR for reliability projects needed within three years (rather thanfive years).

• Granted rehearing to allow for provisions that recognize the incumbent transmission owners' rightsto build upgrades to their transmission facilities and to retain use and control of their rights-of-way.

• Affirmed the ISO’s proposed mechanism for evaluating the qualifications of transmissiondevelopers to operate and maintain projects.

• Required certain additional compliance changes to the Non-incumbent Agreement for transmissiondevelopment.

• Affirmed elimination of the requirement for prospective transmission developers to providefeasibility studies to demonstrate how their proposed transmission solutions will address theidentified needs.

• Required a further compliance filing providing additional details on the treatment of studydeposits.

• Required a further compliance filing clarifying when project sponsors must submit proposals.• Clarified that in cases where a project is abandoned or not being diligently pursued by the sponsor,

the backstop obligation of the Participating Transmission Owners is to build a solution, not tobuild the selected project.

56 ISO New England Inc., 150 FERC ¶ 61,209 (Mar. 19, 2015) (“Order 1000 Compliance Rehearing Order”).

57 ISO New England Inc., 143 FERC ¶ 61,150 (May 17, 2013) (“Order 1000 Compliance Order”), order onreh’g 150 FERC ¶ 61,209 (Mar. 19, 2015).


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• Required a further compliance filing providing more clarity on backstop transmission solutions,and limiting the obligation on Participating Transmission Owners.

• Required a further compliance filing for cost allocation of reliability and market efficiencyupgrades to ensure that costs for such upgrades are not imposed involuntarily on parties outsideNew England.

• Affirmed the prior rejection of the State “opt-in” approach to cost allocation for public policyprojects.

• Accepted the proposal for cost allocation for public policy projects that would allocate 70% of thecosts of Public Policy Transmission Upgrades throughout the region based on load ratio shares andthe remaining 30% of the costs would be allocated on a load ratio basis among those states with apublic policy planning need that a particular project is intended to meet.

• Rejected consumer-owned systems’ request for an opt-out from public policy project costallocation.

Among the requirements to be addressed in the 60-day compliance filing are (i) to set forth in theOATT the enrollment process that defines how transmission providers enroll in the transmission planningregion; (ii) to include a list of enrolled transmission providers in the OATT; (iii) to describe a just andreasonable and not unduly discriminatory process through which each Participating Transmission Owner willidentify, out of the larger set of potential transmission needs driven by federal public policy requirements thatmay be proposed, those transmission needs for which transmission solutions will be evaluated in the localtransmission planning process; (iv) to restore from the First Compliance Filing the proposed revisions tosection 4.3(a) of the OATT and Schedule 3.09, section 1.1(f) of the TOA dealing with existing rights of way;(v) to revise the definition of non-incumbent transmission developer in the OATT to require that aParticipating Transmission Owner that proposes to develop a transmission facility not located within orconnected to its existing electric system enter into a Non-incumbent Agreement; (vi) to exempt from the holdharmless provision a Participating Transmission Owner’s own ordinary negligence and to remove thereference to FERC penalties; (vii) to modify the study deposit provisions to: (a) provide to each QualifiedSponsor a description of the costs to which the deposit will be applied, how those costs will be calculated, andan accounting of the actual costs, and (b) provide a provision that any disputes arising from this process beaddressed under the ISO’s dispute resolution process; (viii) to clarify when a Qualified Sponsor whose PhaseOne or Stage One Proposal will be considered in Phase Two or Stage Two must submit the requiredinformation regarding its Phase Two or Stage Two Solution; (ix) to create a defined term for a backstoptransmission solution and to use that term consistently in the OATT and TOA; and (x) to remove the newlanguage in section 4.3(k) of Attachment K that would require a Participating Transmission Owner tocontinue developing a backstop transmission solution beyond what was originally proposed and that theCommission accepted in the First Compliance Order.

Challenges, if any, to the Order 1000 Compliance Rehearing Order must be filed on or before April20, 2015. The first Transmission Committee meeting to address these requirements is scheduled for April 13.The current plan is for the Participants Committee to consider the further compliance changes at its May 1,2015 meeting (subject to completion of the stakeholder process). If you have any comments or concerns,please contact Eric Runge (617-345-4735; [email protected]).


No Activity to Report.


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VI. Schedule 20/21/22/23 Changes

• Schedule 21-NEP: BIPCO and Narragansett TSAs (ER15-1466)

On April 7, New England Power Company d/b/a National Grid filed amendments to two local serviceagreements (“LSA”) under Schedule 21-NEP. The LSAs, one among the ISO, NEP and Block Island PowerCompany (“BIPCO”), and the other with The Narragansett Electric Company (“Narragansett”), were eachamended in order to address a concern raised by the Rhode Island Division of Public Utilities and Carriers (“RIPUC”) that the Block Island Transmission System (“BITS”) Surcharge calculated under the LSAs did not fullyconform with Rhode Island General Law Section 39-26.7(f). Accordingly, NGrid modified the BITS Surchargeby adding a collar to the calculation of the BIPCO Share Percentage such that the impact on the typical residentialcustomer in the Town of New Shoreham cannot be lower than 120% of the impact on the typical residentialcustomer of Narragansett. A June 7, 2015 effective date was requested. Comments on this filing are due on orbefore April 28. If there are questions on this matter, please contact Pat Gerity (860-275-0533;[email protected]).

• Schedule 20A-EM and 21-EM Changes (ER15-1434)

On April 1, Emera Maine and the ISO filed changes to Schedule 21-EM (to ensure charges under theschedule reflect only costs of service over Emera Maine's Non-PTF System that is subject to that schedule) and20A-EM (corrections). A June 1, 2015 effective date was requested. Comments on this filing are due on orbefore April 22. If there are questions on this matter, please contact Pat Gerity (860-275-0533;[email protected]).

• Opinion 531-A Compliance Filing: CTMEEC (ER15-584)

On December 5, 2014, the ISO submitted on behalf of the Connecticut Transmission MunicipalElectric Energy Cooperative (“CTMEEC”) changes to Attachment B to Schedule-21 CTMEEC to conformSchedule-21 CTMEEC to the holdings in Opinions 531 and 531-A. Comments, if any, on this filing were dueon or before December 26; none were filed and this matter is pending before the FERC. If there are questionson this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• Opinion 531-A Compliance Filing: GMP (ER15-412)

On November 17, 2014, the ISO submitted on behalf of Green Mountain Power (“GMP”) changes toSchedule-21 GMP, in response to Opinion 531-A, to reflect a 10.57% ROE effective as of October 16, 2014.GMP explained that, although it was not a respondent to the complaint in Docket No. EL11-66, GMP agreedin the recently-accepted Settlement Agreement58 to accept the ROE approved by the FERC in Docket No.EL11-66 and to provide refunds for the period of October 1, 2012 through December 31, 2012 (which it hasalso done). Comments, if any, on this filing were due on or before December 8; none were filed and thismatter is pending before the FERC. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• LGIA – NU/CPV Towantic (ER15-200)

The FERC conditionally accepted, on December 24, 2014, and set for hearing and settlement judgeprocedures on the issue of the proposed operation, maintenance, and capital cost reimbursement charges, theunexecuted LGIA (LGIA-ISONE/NU-14-02) between CPV Towantic, CL&P and the ISO, governing theinterconnection of CPV Towantic’s 795 MW natural gas-fired plant located in Oxford, Connecticut.59 ChiefJudge Wagner appointed Judge David H. Coffman as the Settlement Judge. A first settlement conference washeld on January 8, 2015; a second settlement conference was held on February 5. A third settlementconference is scheduled for April 10. On April 6, Judge Coffman issued a report recommending that the

58 ISO New England Inc., et al., 148 FERC ¶ 61,097 (Aug. 4, 2014).

59 ISO New England Inc. and Northeast Utilities Service Co., 149 FERC ¶ 61,274 (Dec. 24, 2014).


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settlement proceeding continue. If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).




• Capital Projects Report - 2014 Q4 (ER15-1036)

On April 6, the FERC accepted the ISO’s Capital Projects Report and Unamortized Cost Schedulecovering the fourth quarter (“Q4”) of calendar year 2014 (the “Report”). As previously reported, highlightsincluded the following new projects: (i) 2015 Issue Resolution Project Phase I ($950,000); (ii) LMPCalculator Replacement ($735,700); and (iii) Human Resources and Payroll System - Phase II ($65,900).One project reported to have had a significant change was the Simultaneous Feasibility Test Lite ProductionVersion Project (which experienced a $967,000 decrease due to primary project vendor resource constraints,which will delay further work on this project until Q4 2015. The bulk of remaining budget was returned toEmerging Work fund). Unless he April 6 order is challenged, this proceeding will be concluded. If you haveany questions concerning this matter, please contact Paul Belval (860-275-0381; [email protected]) orKristin Sullivan (617-345-4657; [email protected]).

• Future Winter Reliability Program Progress Reports (ER14-2407)

As directed in the Winter 2014/15 Reliability Program Order, the ISO submitted on April 8, 2014, its2nd 60-day progress report on efforts to address reliability concerns for the 2015-2016 winter and futurewinters, as necessary. In its 2nd report, the ISO reiterated “its preference … to file a version of the winterprogram, which cost-effectively targets and compensates the needed short-term behavior,” noting that, in itsFebruary 19 rehearing request, the ISO asked that it be allowed to file a version of the 2014-2015 winterprogram for the next three winters, or it would file a proposed increase to the Reserve Constraint PenaltyFactors (“RCPFs”). This report will not be noticed for public comment. If you have any questionsconcerning this matter, please contact Sebastian Lombardi (860-275-0663; [email protected]).

• Quarterly Reports Regarding Non-Generating Resource Regulation Market Participation(ER08-54); Order 755 Regulation Market Progress Report (ER12-1643)

The ISO filed its twenty-sixth report regarding non-generating resource regulation marketparticipation on March 19, 2015. As previously reported, the ISO committed in the August 5, 2008Regulation Filing to provide the FERC with quarterly reports on its progress in implementing and carryingout market rule revisions to allow non-generating resources to provide Regulation, including the AlternativeTechnologies Pilot Program.60 In the 26th report, the ISO reported that it expects to implement the newregulation market design that fully complies with Order 755 on March 31, 2015. These reports are notnoticed for public comment.

• Reserve Market Compliance (18th) Semi-Annual Report (ER06-613)

As directed by the original ASM II Order,61 as modified,62 the ISO submitted its 18th semi-annualreserve market compliance report on April 1, 2015. In the 18th report, the ISO explained, as in its prior

60 See Market Rule 1 revisions regarding the provision of Regulation by non-generating resources, ISO NewEngland Inc. and New England Power Pool, Docket Nos. ER08-54-000 and -001 (filed Aug. 5, 2008) (the “RegulationFiling”).

61 See NEPOOL and ISO New England Inc., 115 FERC ¶ 61,175 (2006) (“ASM II Order”) (directing the ISO toprovide updates on the implementation of a forward TMSR market), reh’g denied 117 FERC ¶ 61,106 (2006).


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compliance reports, that work on the forward TMSR market issues continues to be on hold due to its effortson other priority projects (e.g. design and implementation of FCM-related changes (specifically, developmentof zonal sloped demand curve and elective transmission upgrade proposals and revisions to the retirementrules), development of a “do not exceed” dispatch mechanism for intermittent resources, proposedmodifications to the pricing fast start resources in Real-Time, and a proposed design for sub-hourly settlementof the Real-Time Energy Markets. In addition, the ISO expects to focus on Energy and Reserve Market priceformation issues during the next year, as well as complete an ongoing review of NCPC cost allocation rules.The ISO reports that it does not expect to have the available resources needed to revisit this issue until at least2016. This report will not be noticed for public comment. If there are questions on this matter, please contactDave Doot (860-275-0102; [email protected]).

• IMM Quarterly Markets Reports - 2014 Q4 (ZZ14-4)

On February 18, the Internal Market Monitor (“IMM”) filed with the FERC its report for the fourthquarter of 2014 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 toMarket Rule 1. Highlights from this report were reviewed by the IMM at the March 6, 2015 ParticipantsCommittee meeting (agenda item # 6). These filings are not noticed for public comment by the FERC.

• ISO-NE FERC Form 715 (not docketed)

On March 31, the ISO submitted its 2015 Annual Transmission Planning and Evaluation Report.These filings are not noticed for filing.


• April 2015 Membership Filing (ER15-1417)

On March 31, NEPOOL requested that the FERC accept (i) the memberships of Evergreen Wind Power II(SunEdison Related Person -- AR Sector, RG Sub-Sector) and Jericho Power (AR Sector, RG Sub-Sector); (ii) thetermination of the Participant status of Lincoln Paper and Tissue (End User Sector); and (iii) the name change ofConstellation Energy Services (f/k/a Integrys Energy Services). Comments on this filing are due on or beforeApril 21.

• March 2015 Membership Filing (ER15-1131)

On April 6 the FERC accepted the membership of Epico USA, Inc. (AR Sector, Small RG GroupMember) and the termination of J. P. Morgan Ventures Energy Corp. (Supplier Sector).

• Suspension Notices (not docketed)

Since the last Report, the ISO filed, pursuant to Section 2.3 of the Information Policy, a notice with theFERC noting that the following Participant was suspended from the New England Markets on the date indicated(at 8:30 a.m.) due to a Payment Default:

62 See NEPOOL and ISO New England Inc., 123 FERC ¶ 61,298 (2008) (continuing the semi-annual reportingrequirement with respect to the consideration and implementation of a forward market for Ten-Minute Spinning Reserve(“TMSR”)).


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Date of Suspension/FERC Notice

Participant Name Date Reinstated

Mar 6 New England Confectionery Company Remains suspended

Suspension notices are for the FERC’s information only and are not docketed or noticed for publiccomment.


Questions concerning any of the ERO Reliability Standards or related rule-making proceedings or filingscan be directed to Pat Gerity (860-275-0533; [email protected]).

• FFT Report: March 2015 (NP15-23)

NERC submitted on March 31, 2015 its Find, Fix, Track and Report (“FFT”) informational filing for themonth of March 2015. The March FFT resolves 23 possible violations of 12 Reliability Standards that posed arisk minimal risk to bulk power system (“BPS”) reliability, but which have since been remediated.63 FFT filingsare for information only and are not be noticed for public comment by the FERC.

• Revised Reliability Standards: PRC-001-1.1(ii), PRC-004-2.1(i)a, PRC-004-4; PRC-005-2(i), PRC-005-3(i), PRC-019-2 and PRC-024-2, VAR-002-4 (RD15-3)

On February 6, 2015, NERC filed for approval changes to VAR-002-4 (Generator Operation forMaintaining Network Voltage Schedules), and multiple versions of PRC-004 (Protection System MisoperationIdentification and Correction) and PRC-005 (Protection System and Automatic Reclosing Maintenance), and theassociated VRFs and VSLs (the “Dispersed Generation Resource Changes”).64 NERC stated that the DispersedGeneration Resource Changes tailor the Standards to account for the reliable operations of variable resources.NERC requested that the Dispersed Generation Resource Changes be approved for effectiveness in accordancewith the corresponding Implementation Plans (or immediately upon approval for those Standards in effect, orupon effectiveness of the pending but approved Standards). Comments on the Dispersed Generation ResourceChanges were due on or before March 9, 2015 and were filed by Dominion. On March 13, NERC supplementedits Dispersed Generation Resource Changes with changes to PRC-001-1.1(ii), PRC-019-2 and PRC-024-2.Comments on the supplemental changes, which NERC requested be accepted together with the DispersedGeneration Resource Changes, were due on or before April 9, 2015; none were filed. This matter is pendingbefore the FERC.

• Revised Reliability Standard: PRC-006-2 (RD15-2)

As previously reported, NERC filed, on December 15, 2014, changes to PRC-006-2 (AutomaticUnderfrequency Load Shedding), and its associated VRFs and VSLs, and requested the retirement of the previousversion of the Standard, all in accordance with the Implementation Plan (“PRC-006 Changes”). NERC stated thatthe PRC-006 Changes address outstanding FERC concerns expressed in Order 76365 that applicable entities arerequired to implement corrective actions identified by the Planning Coordinator in accordance with a scheduleestablished by the same Planning Coordinator. NERC requested that the PRC-006 Changes be approved, and theexisting PRC-006-1 be retired, effective on the first day of the first calendar quarter that is six months after the

63 Only possible violations that pose a minimal risk to Bulk-Power System reliability are eligible for FFT treatment.See N. Am. Elec. Reliability Corp., 138 FERC ¶ 61,193 (Mar. 15, 2012) at PP 46-56.

64 “Dispersed Generation Resources”, as used in NERC’s petition, are variable generation that depends on a primaryfuel source which varies over time and cannot be stored.

65 Automatic Underfrequency Load Shedding and Load Shedding Plans Reliability Standards, Order No. 763, 139FERC ¶ 61,098 (2012), order on clarif., 140 FERC ¶ 61,164 (2012).


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date of FERC approval. Comments on the PRC-006 Changes were due on or before January 16, 2015; none werefiled. This matter is pending before the FERC.

• Revised Reliability Standard: PRC-004-3 (RD14-14)

The PRC-004 Changes remain pending before the FERC. As previously reported, NERC filed, onSeptember 15, 2014, changes to PRC-004-3 (Protection System Misoperation Identification and Correction) aswell as a revised definition of “Misoperation” and a new definition of “Composite Protection System” forinclusion in the NERC Glossary of Terms, and the retirement of Reliability Standards PRC-004-2.1a (Analysisand Mitigation of Transmission and Generation Protection System Misoperations) and PRC-003-1 (RegionalProcedure for Analysis of Misoperations of Transmission and Generation Protection System) as listed in theImplementation Plan (“PRC-004 Changes”). NERC stated that the PRC-004 Changes address outstanding FERCconcerns and directives related to PRC-004 and PRC-003 and create a single Reliability Standard requiringTransmission Owners, Generator Owners, and Distribution Providers to identify and correct causes ofMisoperations of certain Protection Systems for Bulk Electric System Elements. NERC requested that the PRC-004 Changes be approved, and the existing PRC-004-2.1a and PRC-003-1 be retired, effective on the first day ofthe first calendar quarter that is one year after the date of FERC approval. Comments on the PRC-004 Changeswere due on or before October 20, 2014; none were filed. The PRC-004 Changes are pending before the FERC.

• Revised TOP and IRO Reliability Standards (RM15-16)

On March 18, NERC filed for approval changes reflected in the following Transmission Operations(“TOP”) and Interconnection Reliability Operations and Coordination (“IRO”) Reliability Standards:

TOP-002-4 (Operations Planning);

TOP-003-3 (Operational Reliability Data);

IRO-001-4 (Reliability Coordination – Responsibilities);

IRO-002-4 (Reliability Coordination –Monitoring and Analysis);

IRO-008-2 (Reliability Coordinator Operational Analyses and Real-time Assessments);

IRO-010-2 (Reliability Coordinator Data Specification and Collection);

IRO-014-3 (Coordination Among Reliability Coordinators); and

IRO-017-1 (Outage Coordination).

NERC indicated that the OP/IRO Standards, which supersede the changes submitted in RM13-15, -14,and -12, but concurrently withdrawn, include improvements over the currently effective TOP and IRO ReliabilityStandards in key areas such as: (1) operating within SOLs and IROLs; (2) outage coordination; (3) situationalawareness; (4) improved clarity and content in foundational definitions; and (5) requirements for operationalreliability data. NERC requested that the TOP/IRO Changes be approved as of the first day of the first calendarquarter that is 12 months after the date that the Standards are approved, with the exception of TOP-003-3 andproposed IRO-010-2, which were requested to be approved 3 months earlier.. As of the date of this Report, theFERC has not noticed a proposed rulemaking proceeding or otherwise invited public comment.

• Revised Reliability Standards: CIP-003-6, CIP-004-6, CIP-006-6, CIP-007-6, CIP-009-6, CIP-010-2,CIP-011-2 (RM15-14)

On February 13, NERC filed for approval changes to seven CIP (“Critical Infrastructure Protection”)Reliability Standards to improve the cyber security protections required by the CIP Standards and collectivelyaddress the FERC’s four directives from Order 791 (the “CIP Changes”). NERC stated that the CIP Changes (i)remove the “identify, assess, and correct” language from the 17 requirements in the CIP Version 5 Standards thatincluded such language; (ii) require responsible entities to implement cyber security plans for assets containinglow impact BES Cyber Systems; (iii) include specific requirements applicable to transient devices to furthermitigate the security risks associated with such devices; and (iv) require entities to implement security controls fornon-programmable components of communication networks at Control Centers with high or medium impact BES


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Cyber Systems. NERC requested that the CIP Changes be approved, effective on April 1, 2016. As of the dateof this Report, the FERC has not noticed a proposed rulemaking proceeding or otherwise invited public comment.

• Revised Reliability Standards: Transition to “Remedial Action Scheme” RM15-13)

On February 3, NERC filed for approval proposed revisions to the definition of “Remedial ActionScheme” and changes to nearly 20 Reliability Standard to insert that term in place of the term “Special ProtectionSystem”, which are used interchangeably throughout the Reliability Standards (the “RAS Changes”). NERCrequested that the RAS Changes be approved, effective the first day of the first calendar quarter that is one yearafter the date of FERC approval. As of the date of this Report, the FERC has not noticed a proposed rulemakingproceeding or otherwise invited public comment.

• Revised Reliability Standard: PRC-010-1 (RM15-12)

On February 6, NERC filed for approval PRC-010-1 (Undervoltage Load Shedding), a definition of“Undervoltage Load Shedding Program (UVLS Program)”, and associated VRFs and VSLs (together, the “UVLSChanges”). NERC stated that the purpose of the UVLS Changes is to “establish an integrated and coordinatedapproach to the design, evaluation, and reliable operation of UVLS Programs”. The UVLS Changes consolidaterequirements from four existing Reliability Standards66 into a single Reliability Standard. NERC requested thatthe UVLS Changes be approved, effective the first day of the first calendar quarter that is one year after the dateof FERC approval. As of the date of this Report, the FERC has not noticed a proposed rulemaking proceeding orotherwise invited public comment.

• New Reliability Standard: TPL-007-1 (RM15-11)

On January 21, 2015, NERC filed for approval a new Reliability Standard -- TPL-007-1 (GeomagneticDisturbance Operations) -- and one new definition (Geomagnetic Disturbance Vulnerability Assessment),associated VRFs and VSLs (together, the “GMD Operations Changes”). NERC stated that the GMD OperationsChanges address the FERC’s directive in Order 779 that NERC develop a Reliability Standard that requiresowners and operators of the Bulk-Power System to conduct initial and on-going vulnerability assessments of thepotential impact of benchmark geomagnetic disturbance events on the Bulk-Power System equipment and theBulk-Power System as a whole.67 NERC requested the FERC approve a five-year phased implementation planfor compliance with TPL-007-1. As of the date of this Report, the FERC has not noticed a proposed rulemakingproceeding or otherwise invited public comment.


On December 18, 2014, NERC filed for approval changes to PRC-005-4 (Protection System, AutomaticReclosing, and Sudden Pressure Relaying Maintenance), one new (Sudden Pressure Relaying) and four reviseddefinitions (Protection System Maintenance Program, Component Type, Component, and Countable Event),associated VRFs and VSLs (together, the “PRC-005 Changes”). NERC stated that the PRC-005 Changes addressFERC concerns expressed in the Order 758 proceeding that NERC’s proposed interpretation of PRC-005-1 maynot include all components that serve in some protective capacity.68 NERC requested that the PRC-005 Changesbe approved, effective on the first day of the first calendar quarter following FERC approval. As of the date ofthis Report, the FERC has not noticed a proposed rulemaking proceeding or otherwise invited public comment.

66 The currently effective Standards being replaced are PRC-010-0 (Assessment of the Design and Effectiveness ofUVLS Program); PRC-020-1 (Under-Voltage Load Shedding Program Database); PRC-021-1 (Under-Voltage LoadShedding Program Data); and PRC-022-1 (Under-Voltage Load Shedding Program Performance).

67 Reliability Standards for Geomagnetic Disturbances, Order No. 779, 143 FERC ¶ 61,147 (“Order 779”).

68 Interpretation of Protection System Reliability Standard, Notice of Proposed Rulemaking, 133 FERC ¶ 61,223(2010) at P 11; Interpretation of Protection System Reliability Standard, Order No. 758, 138 FERC ¶ 61,094 (“Order 758”),order on reh’g, 139 FERC ¶ 61,227 (2012).


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On December 31, 2014, NERC filed for approval a new Standard, PRC-026-1 (Relay PerformanceDuring Stable Power Swings) and associated VRFs and VSLs (the “PRC-026 Standard”) in response to theFERC’s directive in Order 73369 to develop a Reliability Standard addressing undesirable relay operation due tostable power swings. NERC requested that PRC-026 be approved, effective as follows: R1 on the first day of thefirst full calendar year that is 12 months after FERC approval; R2-R4 on the first day of the first full calendar yearthat is 36 months after FERC approval. As of the date of this Report, the FERC has not noticed a proposedrulemaking proceeding or otherwise invited public comment.

• Revised Reliability Standard: EOP-011-1 (RM15-7)

On December 29, 2014, NERC filed for approval a new Standard, EOP-011-1 (Emergency Operations), arevised definition of “Energy Emergency”, and associated VRFs and VSLs (together, the “Emergency OperationsChanges”). NERC stated that the purpose of the Emergency Operations Changes is to address the effects ofoperating Emergencies by ensuring each Transmission Operator and Balancing Authority has developedOperating Plans to mitigate operating Emergencies, and that those plans are coordinated within a ReliabilityCoordinator Area. EOP-011-1 consolidates requirements from three existing Reliability Standards, EOP-001-2.1b, EOP-003.1, and EOP-003-2, into a single new Reliability Standard. NERC stated that the EmergencyOperations Changes address seven FERC directives from Order 693. NERC requested that the EmergencyOperations Changes be approved, effective on the first day of the first calendar quarter that is 12 months afterFERC approval. As of the date of this Report, the FERC has not noticed a proposed rulemaking proceeding orotherwise invited public comment.


On December 15, 2014, NERC filed for approval changes to PRC-002-2 (Disturbance Monitoring andReporting Requirements), associated VRFs and VSLs, and requested retirement of PRC-002-1 (Define RegionalDisturbance Monitoring and Reporting Requirements) and PRC-018-1 (Disturbance Monitoring EquipmentInstallation and Data Reporting) (together, the “PRC-002 Changes”). NERC stated that the PRC-002 Changesaddress FERC concerns expressed in Order 69370 with the “fill in the blank” aspects in PRC-002-1 and PRC-018-1.71 NERC requested that the PRC-002 Changes be approved, effective on the first day of the first calendarquarter six months following FERC approval. As of the date of this Report, the FERC has not noticed a proposedrulemaking proceeding or otherwise invited public comment.

• Order 802: New Reliability Standard: CIP-014-1 (Physical Security) (RM14-15)

Rehearing remains pending of Order 802. As previously reported, the FERC approved, in Order 802,NERC’s Physical Security Reliability Standard (CIP-014-1).72 CIP-014 is designed to enhance physical securitymeasures for the most critical Bulk-Power System facilities and thereby lessen the overall vulnerability of theBulk-Power System to physical attacks. CIP-014 requires Transmission Owners and Transmission Operators toprotect those critical Transmission stations and Transmission substations, and their associated primary controlcenters that, if rendered inoperable or damaged as a result of a physical attack, could result in widespreadinstability, uncontrolled separation, or cascading within an Interconnection. CIP-014 also includes requirements

69 Transmission Relay Loadability Reliability Standard, Order No. 733, 130 FERC ¶ 61,221 (2010); order on reh’gand clarif., Order No. 733-A, 134 FERC ¶ 61,127 (2011); clarified, Order No. 733-B, 136 FERC ¶ 61,185 (2011) (“Order733”).

70 Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, 72 FR 16416, FERC Stats. & Regs.¶ 31,242, at PP 1131-1222, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007) (“Order 693”).

71 Interpretation of Protection System Reliability Standard, Notice of Proposed Rulemaking, 133 FERC ¶ 61,223(2010) at P 11; Interpretation of Protection System Reliability Standard, Order No. 758, 138 FERC ¶ 61,094 (“Order 758”),order on reh’g, 139 FERC ¶ 61,227 (2012).

72 Physical Security Reliability Standard, Order No. 802, 149 FERC ¶ 61,140 (Nov. 20, 2014) (“Order 802”).


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for: (i) the protection of sensitive or confidential information from public disclosure; (ii) third party verification ofthe identification of critical facilities as well as third party review of the evaluation of threats and vulnerabilitiesand the security plans; and (iii) the periodic reevaluation and revision of the identification of critical facilities, theevaluation of threats and vulnerabilities, and the security plans to help ensure their continued effectiveness. CIP-014 will become effective June 1, 2015. In approving CIP-014, the FERC required NERC within six months ofthe effective date of the Rule,73 to remove the term “widespread” from the Standard or, alternatively, to proposemodifications to the Reliability Standard that address the FERC’s concerns. In addition, the FERC directedNERC to submit, by June 1, 2017, an informational filing that addresses whether there is a need for consistenttreatment of “High Impact” control centers for cyber security and physical security purposes through thedevelopment of Reliability Standards that afford physical protection to all “High Impact” control centers.74 Arequest for rehearing of Order 802 was filed by the Foundation for Resilient Societies (“FRS”), which identifiedas problematic: (i) exemptions for Reliability Coordinators, Balancing Authorities, and Generator Operators andGenerator Owners; (ii) 2-year exemptions for high impact control centers; (iii) FERC’s failure to address FRS’comments on the critical role of RCs under the Standard; (iv) failure to require modeled contingency planning forphysical attack scenarios; (v) lack of requirements for specific security measures for critical grid facilities; and(vi) failure to address FRS’ cost-effectiveness comments. On January 21, the FERC issued a tolling orderaffording it additional time to consider the FRS rehearing request, which remains pending before the FERC.

• NOPR: Revised Reliability Standard: COM-001-2 and COM-002-4 (RM14-13)

The FERC’s September 18, 2014 NOPR proposing to approve changes to COM-1 (Communications) andCOM-2 (Operating Personnel Communications Protocols) (together, “COM Changes”)75 remains pending. Aspreviously reported, proposed COM-001 establishes a clear set of requirements for what communicationscapabilities various functional entities must maintain for reliable communications. Proposed COM-002 improvescommunications surrounding operating instructions by setting predefined communications protocols, requiringuse of the same protocols regardless of the current operating condition (whether normal, alert, and Emergencyoperating conditions), and requiring entities to reinforce the use of the documented communication protocolsthrough training, assessment, and feedback. NERC requested that the COM Changes be approved effective as ofthe first day of the first calendar quarter that is 12 months after the date that the COM Changes are approved bythe FERC. Comments on this NOPR were due on or before December 1, 2014,76 and were filed by 7 parties,including by NERC, the ISO/RTO Council, EEI/EPSA, and NRECA. On March 6, NERC submittedsupplemental comments to update the FERC on NERC Board of Trustees’ actions with respect to revisions tocertain proposed TOP and IRO Reliability Standards referenced by NERC in its early comments in thisproceeding.

• NOPR: Revised Reliability Standard: BAL-001-2 (RM14-10)

On November 20, 2014, the FERC issued a NOPR proposing to approve changes to BAL-001-2 (RealPower Balancing Control Performance) (“BAL-001 Changes”) and to require NERC to submit an informationalfiling that would address the impact of the proposed Reliability Standard on inadvertent interchange andunscheduled power flows.77 As previously reported, the BAL-001 Changes add a frequency component to themeasurement of a Balancing Authority’s Area Control Error (“ACE”) and allow for the formation of “RegulationReserve Sharing Groups.” NERC requested that the BAL-001 Changes be approved, and the existing BAL-001-1Standard be retired, effective on the first day of the first calendar quarter that is 12 months after the date that theBAL-001 Changes are approved by the FERC. Comments on this NOPR were due on or before January 26,

73 Order 802 was published in the Fed. Reg. on Nov. 25, 2014 (Vol. 79, No. 227) pp. 70,069-70,085.

74 Id. at P 57.

75 Communications Reliability Standards, 148 FERC ¶ 61,210 (Sep. 18, 2014).

76 The Communications Reliability Standards NOPR was published in the Fed. Reg. on Sep. 30, 2014 (Vol. 79, No.189) pp. 58,709-58,716.

77 Real Power Balancing Control Performance Reliability Standard, 149 FERC ¶ 61,139 (Nov. 20, 2014).


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2015,78 and 12 sets of comments were filed, including comments by NERC, EEI, and ISO-NE (in joint commentswith MISO and PJM). This NOPR is pending before the FERC.

• Order 803: Revised Reliability Standard: PRC-005-3 (RM14-8)

On January 22, 2015, the FERC approved changes to PRC-005-3 (Protection System and AutomaticReclosing Maintenance) (“PRC-005 Changes”).79 The PRC-005 Changes include in PRC-005 the maintenanceand testing of reclosing relays that can affect the reliable operation of the BPS. While the FERC was persuadednot to direct NERC to submit a report based on actual performance data, and simulated system conditions fromplanning assessments, it instead directed NERC to “obtain, maintain, and make available to the Commission uponrequest, one year following the effective date of the standard and on an annual basis thereafter, data sufficient toanalyze the effectiveness of PRC-005-3”.80 In addition, the FERC directed NERC to modify PRC-005-3 toinclude maintenance and testing of supervisory relays associated with auto-reclosing relay schemes to whichPRC-005-3 applies.81 The PRC-005 Changes will become effective, and the existing PRC-005-2 retired, as ofApril 1, 2016.82

• NOPR: Revised Reliability Standard: MOD-001-2 (RM14-7)

On June 19, 2014, the FERC issued a NOPR proposing to approve changes to MOD-001-2 (Modeling,Data, and Analysis — Available Transmission System Capability) (“MOD Changes”) proposed by NERC. TheMOD Changes replace, consolidate and improve upon the Existing MOD Standards in addressing the reliabilityissues associated with determinations of Available Transfer Capability (“ATC”) and Available FlowgateCapability (“AFC”). MOD-001-2 will replace the six Existing MOD Standards83 to exclusively focus on thereliability aspects of ATC and AFC determinations. NERC requested that the revised MOD Standard beapproved, and the Existing MOD Standards be retired, effective on the first day of the first calendar quarter that is18 months after the date that the proposed Reliability Standard is approved by the FERC. NERC explained thatthe implementation period is intended to provide NAESB sufficient time to include in its WEQ Standards, prior toMOD-001-2’s effective date, those elements from the Existing MOD Standards, if any, that relate to commercialor business practices and are not included in proposed MOD-001-2. The FERC seeks comment from NAESB andothers whether 18 months would provide adequate time for NAESB to develop related business practicesassociated with ATC calculations or whether additional time may be appropriate to better assure synchronizationof the effective dates for the proposed Reliability Standard and related NAESB practices. The FERC also seeksfurther elaboration on specific actions NERC could take to assure synchronization of the effective dates.Comments on this NOPR were due August 25, 2014,84 and were filed by NERC, Bonneville, Duke, MISO, andNAESB. Since the last Report, NAESB supplemented its comments with a report on its efforts to develop WEQBusiness Practice Standards that will support and coordinate with the MOD Standards proposed in thisproceeding. The MOD-001-2 NOPR remains pending before the FERC.

78 The Real Power Balancing Control Performance Reliability Standard NOPR was published in the Fed. Reg. onNov. 26, 2014 (Vol. 79, No. 228) pp. 70,483-70,488.

79 Protection System Maintenance Reliability Standard, Order No. 803, 150 FERC ¶ 61,039 (Jan. 22, 2015) (“Order803”). Order 803 also approved one new definition and six revised definitions, the assigned VRFs and VSLs, and NERC’sproposed implementation plan.

80 Id. at P 25.

81 Id. at P 31.

82 Order 803 was published in the Fed. Reg. on Jan. 27, 2015 (Vol. 80, No. 17) pp. 4,195-4,201.

83 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.

84 The MOD-001-2 NOPR was published in the Fed. Reg. on June 26, 2014, (Vol. 79, No. 123) pp. 36,269-36,273.


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• NOPR: Revised TOP and IRO Reliability Standards (RM13-15, RM13-14, RM13-12)

On March 18, NERC submitted a notice of withdrawal of its proposed changes to the Standards filed inthese proceedings,85 on which the FERC had issued a NOPR,86 but had not issued a final rule. NERC explainedthat, since the issuance of the TOP/IRO NOPR, it had developed superseding changes to the TOP and IROReliability Standards, and those changes were filed concurrently with the notice of withdrawal. (See RM15-16above).

• NOPR: BAL-002-1a Interpretation Remand (RM13-6)

This May 16, 2013 NOPR, which proposes to remand NERC’s proposed interpretation of BAL-002(Disturbance Control Performance Reliability Standard) filed February 12, 2013 (which would prevent RegisteredEntities from shedding load to avoid possible violations of BAL-002), remains pending.87 NERC asserted that theproposed interpretation clarifies that BAL-002-1 is intended to be read as an integrated whole and relies in part oninformation in the Compliance section of the Reliability Standard. Specifically, the proposed interpretation wouldclarify that: (1) a Disturbance that exceeds the most severe single Contingency, regardless if it is a simultaneousContingency or non-simultaneous multiple Contingency, would be a reportable event, but would be excludedfrom compliance evaluation; (2) a pre-acknowledged Reserve Sharing Group would be treated in the samemanner as an individual Balancing Authority; however, in a dynamically allocated Reserve Sharing Group,exclusions are only provided on a Balancing Authority member by member basis; and (3) an excludableDisturbance 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 interpretationchanges 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, 2013,88 and were filedby NERC, EEI, ISO/RTO Council, MISO, NC Balancing Area, Northwest Power Pool Balancing Authorities,NRECA, and WECC. This NOPR remains pending before the FERC.

XI. Misc. - of Regional Interest

• 203 Application: Iberdrola/CMP/ Emera (EC15-103)

On March 25, Iberdrola89 and UIL Holdings Corp (“UI”) requested FERC authorization for a transactionwhereby UI will become an indirect, wholly-owned subsidiary of Iberdrola, S.A (and a Related Person of CentralMaine Power Company, Iberdrola Renewables, LLC, and New York State Electric & Gas Corporation). Thus fara doc-les intervention has been filed by Eversource. Comments on this filing are due on or before April 15, 2015.If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).

85 Changes were proposed to the following Standards: IRO-001-3 (Reliability Coordination — Responsibilities andAuthorities); IRO-002-3 (Reliability Coordination – Analysis Tools); IRO-005-4 (Reliability Coordination – Current DayOperations); IRO-0014-2 (Coordination Among Reliability Coordinators); TOP-001-2 (Transmission Operations); TOP-002-3 (Operations Planning); TOP-003-2 (Operational Reliability Data); TOP-006-3 (Monitoring System Conditions); and PRC-001-2 (System Protection Coordination).

86 Monitoring System Conditions - Transmission Operations Reliability Standard, Transmission OperationsReliability Standards and Interconnection Reliability Operations and Coordination Reliability Standards, 145 FERC ¶61,158 (Nov. 21, 2013) (“TOP/IRO NOPR”).

87 Electric Reliability Organization Interpretation of Specific Requirements of the Disturbance ControlPerformance Standard, 143 FERC ¶ 61,138 (2013) (“BAL-002-1a Interpretation Remand NOPR”).

88 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.

89 For purposes of this proceeding, “Iberdrola” is Iberdrola, S.A., Iberdrola USA, Inc., Iberdrola USA Networks,Inc., and Green Merger Sub.


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• 203 Application: Dynegy/EquiPower (EC14-140)

On March 27, the FERC authorized Dynegy’s acquisition of EquiPower and its related generating assets(Dighton, Elwood, Kincaid, Lake Road, Liberty, MASSPOWER, Milford, Richland-Stryker Generation andBrayton Point) (together, the “ECP Utilities”)).90 On April 7, Dynegy and the ECP Utilities notified the FERCthat the transaction was consummated on April 1, 2015 (making Dynegy Marketing & Trade, EquiPower andBrayton Point Related Persons). Unless the March 27 order is challenged, this proceeding will be concluded. Ifthere are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• LVA/PSNH IA Complaint (EL15-9)

As previously reported, Lower Village Hydroelectric Associates (“LVA”) filed a complaint, onOctober 23, 2014, against PSNH requesting FERC direct PSNH to recognize the existing LVA IA, rescind itsdemand for LVA facility modifications, and close the air break switch so LVA can complete relay testing andresume generating/ selling electricity. PSNH responded to the Complaint on December 11, urging the FERCto dismiss the Complaint. LVA answered PSNH’s response on December 26 and PSNH answered LVA’sanswer on January 9, 2015. This matter remains pending before the FERC. If you have any questionsconcerning this Complaint, please contact Pat Gerity ([email protected]; 860-275-0533).

• FirstEnergy PJM DR Complaint (EL14-55)

On May 23, 2014, the same day that DC Circuit vacated Order 745 (see Section XV below),FirstEnergy filed a complaint against PJM requesting that the FERC require the “removal of all portions ofthe PJM Tariff allowing or requiring PJM to include demand response as suppliers to PJM’s capacitymarkets.” FirstEnergy also requested that the results of the PJM capacity auction due to be released that sameday, to the extent it included and cleared demand response resources, be considered void and legally invalid.PJM’s response, and all comments and interventions were initially due on or before June 12, 2014. However,on June 11, the FERC extended that date to 30 days after the submission by FirstEnergy of an amendedcomplaint. FirstEnergy filed its amended complaint on September 22, 2014.

Comments on the FirstEnergy Complaint were due October 22, 2014. More than 40 parties filedcomments or responses to the FirstEnergy amended complaint. Many parties filed comments supporting thecomplaint (including Calpine, PSEG and PPL), while others opposed the complaint in its entirety (includingDirect Energy and Enerwise). PJM’s response argued that the complaint failed to justify the marketdisruption that would result from recalculating past capacity auction results, PJM was instead more focusedon minimizing “litigation risk.” A number of parties filed supporting comments in favor of removing demandresponse resources from the PJM tariff moving forward, but opposed to recalculating the results of pastcapacity auctions (including Exelon, the PJM IMM and NRG). Comments were also filed by National Gridand NYISO. A number of New England parties intervened, including NEPOOL (stressing that the FERCshould not apply any ruling in this docket to the New England Market), Dominion, Duke Energy, Dynegy,Essential Power, Macquarie Energy, NEPGA, NESCOE, and NextEra. On November 14, FirstEnergy filedan answer to the answers, protests and comments submitted in response to its Complaint and AmendedComplaint. Environmental Advocates91 filed an answer to FirstEnergy’s answer on November 21. Since thelast Report, CPower and Advanced Energy Management Alliance filed answers to the FirstEnergy and otheranswers and pleadings. On December 23, Environmental Advocates moved to lodge the US SolicitorGeneral’s application for an extension of time in which to file a petition for writ of certiorari, the SupremeCourt Clerk’s notice to the DC Circuit that the extension had been granted, and the DC Circuit’s orderextending the stay of its mandate pending the Supreme Court’s final disposition of the writ of certiorari. Thismatter remains pending before the FERC. If you have any questions concerning this matter, please contact

90 Dynegy Inc., et al., 150 FERC ¶ 61,231 (Mar. 27, 2015).

91 “Environmental Advocates” are Sustainable FERC Project, Natural Resources Defense Council (“NRDC”),Sierra Club, Environmental Defense Fund, Environmental Law and Policy Center, and Acadia Center (f/k/a EnvironmentNortheast).


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Jamie Blackburn ([email protected]; 202-218-3905) or Pat Gerity ([email protected]; 860-275-0533).

• EPC Agreement: Blue Sky West & Emera Maine (ER15-1459)

On April 7, Emera Maine filed an executed Engineering, Procurement, and Construction Agreement (“EPC Agreement”) Agreement with Blue Sky West, LLC (“Blue Sky West”) to facilitate the interconnectionof the Blue Sky West’s 191 MW wind farm in Bingham, Mayfield Township and Kingsbury Plantation,Maine. While the Blue Sky West facility will be located in CMP’s service territory, upgrades andmodifications at Orrington Substation, in part owned by Emera Maine, are required and will be covered underthe EPC Agreement. A March 6, 2015 effective date was requested. Comments on the EPC Agreement filingare due on or before April 28. If there are questions on this matter, please contact Pat Gerity (860-275-0533;[email protected]).

• Emera MPD OATT Changes (ER15-1429)

On April 1, Emera Maine filed changes to the Open Access Transmission Tariff (“OATT”) for MainePublic District (“MPD OATT”), including to the rates, terms, and conditions set forth in MPD OATTAttachment J. Emera Maine, as successor to Maine Public Service Company (“Maine Public”), providesopen access to Emera Maine’s transmission facilities in northern Maine (the “MPD Transmission System”)pursuant to the MPD OATT. The changes to the MPD OATT are needed to ensure that, in light of the filingby Emera of consolidated FERC Form 1 data (data comprising both the former Bangor Hydro and MainePublic systems), charges for service under the MPD OATT reflect only the costs of service over the MPDTransmission System. Emera Maine also proposed additional, limited changes to the MPD OATT. A June 1,2015 effective date was requested. Comments on this filing are due on or before April 22, 2015.

• Emera Maine MPD OATT Order 676-H Compliance Filing (ER15-1419)

On March 31, Emera Maine submitted an Order 676-H compliance filing, and requested waiver ofcertain standards not applicable to, the Maine Public District OATT. A May 15, 2015 effective date wasrequested. Comments on this filing are due on or before April 21, 2015.

• NSTAR/HQ US CMEEC Use Rights Transfer Agreement (ER15-1383)

On March 26, NSTAR filed an agreement by which it will transfer CMEEC’s use rights over thePhase I/II HVDC facilities to HQUS (CMEEC itself does not have a mechanism to effectuate the transfer). AMat 26, 2015 effective date was requested. Comments on this filing are due on or before April 16, 2015. Ifthere are questions on this matter, please contact Eric Runge (617-345-4735; [email protected]).

• SGIA Termination: CMP/Gallop Power Greenville (ER15-1189)

On March 6, CMP filed a notice of termination of a Small Generation Interconnection Agreement(“SGIA”) with Gallop Power Greenville. CMP reported that Gallop Power’s interconnection rights wereterminated pursuant to Section III.13.2.5.2.5.3(d) of the Tariff (having been deemed retired by the ISO as aresult of not operating commercially for a period of three calendar years), and the notice is consistent withthat retirement and related notices. A January 22, 2015 effective date (to coincide with the ISO’s retirementof the Gallop Power generating facility and its loss of interconnection rights) was requested. Comments onthis filing are due on or before March 27, 2015; none were filed. On April 2, the FERC accepted the notice oftermination. Unless the April 2 order is challenged, this proceeding will be concluded.

• LCC Services Agreement – NSTAR/Braintree (ER15-1040)

On April 8, the FERC accepted a Local Control Center (“LCC”) Services Agreement betweenNSTAR and Braintree Electric Light Department (“Braintree”) that sets the terms pursuant to which NSTARwill operate and maintain a LCC to operate Braintree’s transmission facilities, implement the instructions,orders and directions received from the ISO related to the Braintree facilities, and perform other centraldispatch functions all as delineated in and required under the TOA. LCC costs are billed directly to the ISO


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and recovered under Schedule 1 of the ISO Tariff. The LCC Agreement will supersede Braintree’sparticipation in REMVEC, which is scheduled to end on May 1, 2015. The LCC Agreement was acceptedeffective as of May 1, 2015, as requested. In accepting the LCC Agreement, the FERC noted that unless afiling is made to terminate the currently effective LCC agreement with REMVEC, Braintree could potentiallyhave two LCC Agreements in effect. Accordingly, the FERC directed National Grid to file, on or beforeApril 29, a notice terminating the REMVEC LCC Agreement. Unless the April 8 order is challenged, thisproceeding will be concluded. If there are questions on this matter, please contact Pat Gerity (860-275-0533;[email protected]).

• E&P Agreement Terminations: Spruce Mountain Wind (ER15-975); Record Hill Wind (ER15-974);Highland Wind (ER15-973); Patriot Renewables (ER15-972)

On February 4, CMP filed a notice of termination of four Engineering and Procurement Agreement(“E&P Agreements”) with Spruce Mountain Wind (superseded by IA-CMP-11-04); Record Hill Wind(superseded by IA-CMP-10-01); Highland Wind (all services completed); and Patriot Renewables (allservices completed). CMP requested that each of the terminations become effective April 6, 2015.Comments on these filings were due on or before February 25, 2015; none were filed. The terminations ofthe four E&P Agreements were accepted on March 2, 2015. Those orders were not challenged, and theseproceedings have been concluded.

• LSA Termination: Emera/ Black Bear HVGW (ER15-962)

On March 10, the FERC accepted the Emera Maine/ISO notice of termination of the Black BearHVGW, LLC (“Black Bear”) Local Service Agreement (“LSA”). Black Bear operated the HowlandHydroelectric Project (“Howland”) located on the Penobscot River in central Maine, which as of January 2,2015, however, ceased operations in preparation for decommissioning and dismantling. On January 5, 2015,Emera Maine’s electric transmission facilities were disconnected from Howland and Emera Maine ceasedproviding electric transmission service for Howland. The notice of termination was accepted effectiveJanuary 6, 2015, as requested.

• IA – CL&P/Energy Stream (ER15-947)

On March 19, the FERC accepted a non-conforming92 interconnection agreement between CL&P andEnergy Stream (IA-NU-29) governing the interconnection of Energy Stream’s 120 kW hydroelectricgeneration unit located on the Quinnebaug River in Putnam, Connecticut. The IA was accepted as of March31, 2015, as requested. Unless the March 19 order is challenged, this proceeding will be concluded. If thereare questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• HG&E Demarcation Agreement (ER15-939)

On January 30, WMECO filed a revised Asset Demarcation Agreement by and between WMECOand Holyoke Gas and Electric Department (“HG&E”). The Agreement established the parties agreement onthe demarcation of ownership of their respective electric transmission facilities, and the revisions reflect therecent construction by HG&E of a new transmission substation. WMECO requested that the Agreement beaccepted for filing as of January 5, 2015. Comments on this filing were due on or before February 20, 2015;none were filed. On March 17, as supplemented on March 18, Eversource filed a complete copy of theRevised Agreement as requested by FERC Staff. Final comments were due on or before April 8; none werefiled. This matter is again pending before the FERC. If there are questions on this matter, please contact PatGerity (860-275-0533; [email protected]).

92 Because the IA continues an existing interconnection arrangement, the submission of the IA does not constitute anew “Interconnection Request” or require a new three-party IA (and, as a two-party agreement, is a non-conforming SGIA).


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• Opinion 531-A Compliance Filing: NGrid IFA Amendments (ER15-418)

As previously reported, National Grid submitted, on November 17, 2014, an amendment to theformula rates for integrated facilities service (“IFA Amendment”) under Schedule III-B of New EnglandPower’s (“NEP’s”) Tariff No. 1. The IFA Amendment modifies the ROE components of the Tariff No. 1formula rates so that they mirror those recently ordered in Opinion 531-A. The proposed IFA amendmentalso implements Opinion 531-A’s ROE cap to ensure that the total ROE does not exceed 11.74%. NationalGrid reports that the overall effect of the IFA Amendment is a rate decrease of approximately $2.2 million.An October 16, 2014 effective date was requested. Comments on this filing were due on or before December8; none were filed. NU submitted a doc-less intervention on December 5. On January 15, 2015, the FERCissued a deficiency letter directing National Grid to provide additional information in order for the FERC toprocess the filing. National Grid submitted that information on February 18, 2015. Comments on thatdeficiency filing were due on or before March 11; none were filed. This matter is pending before the FERC.If there are questions on this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• MISO Methodology to Involuntarily Allocate Costs to Entities Outside Its Control Area(ER11-1844)

On December 18, 2012, Judge Sterner issued his 374-page initial decision which, following hearingsdescribed in previous reports, found at its core that “it is unjust, unreasonable, and unduly discriminatory toallocate costs of Phase Angle Regulating Transformers (“PARs”) of the International Transmission Company(“ITC”) to NYISO and PJM”,93 which the Midwest ISO (“MISO”) and ITC proposed unilaterally to do(without the support of either PJM or NYISO) in its October 20, 2010 filing initiating this proceeding. For asummary of specific findings, please refer to any of the January to June 2013 Reports.

On January 17, 2013, ITC and MISO challenged the Initial Decision through their Brief onExceptions. Briefs opposing exceptions were filed by the FERC Trial Staff, MISO TOs, NYISO, NY TOs,PJM, and the PJM TOs. On February 25, Joint Applicants moved to strike a portion of the PJM BriefOpposing Exceptions. On March 12, PJM answered Joint Applicants February 25 motion. MISO (nowcalled “Midcontinent Independent System Operator, Inc.”) moved to lodge a NYISO “Broader RegionalMarkets Informational Report” filed March 19, 2014 in ER08-1281 and a related January 16, 2014 “Ontario-Michigan Interface PAR Performance Evaluation Report” (“Evaluation Report”) prepared by MISO, IESOand PJM. Oppositions to that motion to lodge were filed by FERC Staff, NYISO, NY TOs, PJM, and PSEG.This matter remains pending before the FERC. If there are any questions on this matter, please contact EricRunge (617-345-4735; [email protected]).

• FERC Enforcement Action: City Power Marketing and Tsingas (IN15-5)

On March 6, 2015, the FERC issued an order directing City Power Marketing, LLC (“City Power”)and K. Stephen Tsingas (“Tsingas”, and together with City Power, the “City Power Respondents”) to showcause (i) why they should not be found to have violated the FERC’s Anti-Manipulation Rules by engaging infraudulent Up To Congestion (“UTC”) transactions in PJM’s energy markets and (ii) why they should not bejointly and severally required to disgorge unjust profits of $1,278,358 and to be jointly and severally assessed$15 million in civil penalties (City Power ($14 million) and Tsingas ($1 million)).94 As previously reported,OE Staff alleges that (i) City Power and Tsingas violated the FERC’s Anti-Manipulation Rule by engaging inmanipulative Up To Congestion trading in PJM during July 2010; and (ii) City Power violated the FERC’smarket behavior rules (18 C.F.R. § 35.41 (2014)) by making false statements and omitting materialinformation during the investigation. On April 1, as it did in the Powhatan proceeding, PJM submittedcomments requesting FERC guidance with respect to certain matters should disgorgement be ordered in thisproceeding. (See IN15-3 below for details.) On April 7, City Power Respondents responded to the Show

93 Midwest Indep. Trans. Sys. Op., Inc., 141 FERC ¶ 63,021 (Dec. 18, 2012) (“MISO Initial Decision”) at P 923.

94 City Power Mkt’g, LLC and K. Stephen Tsingas, 150 FERC ¶ 61,176 (Mar. 6, 2015) (“City Power Mktg ShowCause Order”).


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Cause Order and invoked their statutory rights to prompt assessment of a penalty and a de novo review of thatpenalty in federal district court. This matter is pending before the FERC. If you have any questionsconcerning this matter, please contact Pat Gerity (860-275-0533; [email protected]).

• FERC Enforcement Action: Maxim Power and K. Mitton (IN15-4)

On February 2, 2015, the FERC issued an order directing Maxim Power (USA), Inc., Maxim Power(USA) Holding Company Inc., Pawtucket Power Holding Co., LLC, Pittsfield Generating Company, LP, andKyle Mitton (collectively, “Maxim Respondents”)95 to show cause (i) why they should not be found to haveviolated the FERC’s Anti-Manipulation Rules through a scheme to obtain payments for reliability dispatchesbased on the price of expensive fuel oil when Maxim in fact burned much less costly natural gas; and (ii) whythey should not be assessed civil penalties as follows: Maxim and its affiliates ($5 million civil penalty,jointly and severally); and K. Mitton ($50,000 civil penalty).96 As previously reported, OE Staff alleges thatMaxim engaged in three schemes in New England that violated the FERC’s Anti-Manipulation Rule. In thefirst, during 2012-13, Maxim received millions of dollars of inflated make-whole payments from the ISO bygaming Market Rules intended to mitigate the market power of generators needed for reliability; in thesecond, July-August 2010, staff alleges that Maxim told the ISO it needed to offer based on high oil pricesbecause of supposed gas supply problems, and collected make-whole payments based on those high prices,but in fact burned much less expensive gas. In many cases Maxim had already purchased gas when itsubmitted Day-Ahead offers based on oil prices because of supposed gas supply issues; in the third, 2010-2013, Maxim obtained inflated capacity payments by artificially raising the reported output of three of itsplants by employing extraordinary measures during capacity tests that it did not use, and did not intend to use,during the ordinary operation of the plants. Staff also alleged that Maxim executives John Bobenic and KyleMitton engaged in certain of these schemes, and that Maxim also violated the FERC’s Market Behavior Rulesthrough schemes two and three.

On February 18, Maxim Respondents requested an extension of time, until March 30, 2015, to submittheir answer to the Maxim Show Cause Order, stating that that additional time was needed to prepare aresponse to OE’s report and accompanying documents. On February 20, 2015, OE filed a response opposingthe Maxim Respondents’ motion. On February 24, the FERC denied the Maxim Respondents’ motion for anextension of time. On March 4, 2015, the Maxim Respondents filed answers to the Maxim Show CauseOrder. Since the last Report, on March 23, OE Litigation Staff replied to the Maxim Respondents’ March 4answers. The Maxim Respondents replied to the Staff’s reply on April 6. This matter is pending before theFERC. If you have any questions concerning this matter, please contact Pat Gerity (860-275-0533;[email protected]).

• FERC Enforcement Action: Powhatan Energy, HEEP Fund, CU Fund, and Chen (IN15-3)

On December 17, 2014, the FERC issued an order directing Houlian “Alan” Chen, HEEP Fund, Inc.,CU Fund, Inc., and Powhatan Energy Fund, LLC (together, “Powhatan Respondents”) to show cause (i) whythey should not be found to have violated the FERC’s Anti-Manipulation Rules by engaging in fraudulentUTC transactions in PJM’s energy markets and (ii) why they should not disgorge unjust profits with interestand be assessed civil penalties as follows: Powhatan Energy Fund ($16.8 million civil penalty; $3.47 milliondisgorgement); CU Fund: ($10.08 million civil penalty; $1.08 million disgorgement); HEEP Fund ($1.92million civil penalty; $173,100 disgorgement); H. Chen ($1 million civil penalty for trades executed throughand on behalf of Powhatan and the Funds).97 As previously reported, OE Staff alleges that, between June andAugust 2010, Powhatan Respondents engaged in manipulative Up To Congestion trading in PJM, trades

95 Maxim’s Related Person, Pawtucket Power Holding Company, is a member of the Generation Sector Group Seat.In addition to Pawtucket, Maxim operates units in Pittsfield, MA and Hartford, CT (Capitol District Energy CenterCogeneration Associates).

96 Maxim Power Corp. et al., 150 FERC ¶ 61,068 (Feb. 2, 2015) (“Maxim Show Cause Order”).

97 Houlian Chen, Powhatan Energy Fund, LLC, HEEP Fund, LLC, and CU Fund, Inc., 149 FERC ¶ 61,261 (Dec.17, 2014), as revised, 149 FERC ¶ 61,263 (Dec. 18, 2014) (“Powhatan Show Cause Order”).


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which amounted to wash trading, long prohibited by the FERC. Specifically, Staff alleges that thetransactions were designed to falsely appear to be spread trades, as a vehicle for collecting Marginal LossSurplus Allocation (“MLSA”) payments from PJM, by placing millions of megawatt hours of offsettingtrades between the same two trading points, in the same volumes and the same hours—an intentional effort tocancel out the financial consequences from any spread between the two trading points while capturing largeamounts of MLSA payments. On December 31, the answer period was extended by the FERC, so thatPowhatan Respondents’ answers were due on or before February 2, 2015.

On January 12, Powhatan Respondents invoked their statutory rights to prompt assessment of apenalty and a de novo review of that penalty in federal district court. On January 27, Powhatan Respondentsrequested a two-week extension of time for its answers, citing a need to review yet-to-be disclosedexculpatory evidence. On January 29, FERC staff opposed the requested extension, but provided additionalmaterials. On January 30, the FERC denied the requested extension, but indicated that PowhatanRespondents would be permitted to provide by February 9 a supplemental answer in response to the materialsprovided with staff’s Jan 29 motion. Powhatan Respondents submitted their answers to the Powhatan ShowCause Order on February 2. The Powhatan Respondents provided a supplemental answer on February 9,noting that the data that they expected to see was not in what Enforcement produced and, therefore, itsFebruary 2 answers need not be further supplemented. OE responded to the February 2 answers on March 2.In addition, on February 19, the Powhatan Respondents submitted a letter to the FERC Commissioners (otherthan Commissioner Bay, who did not participate in the Powhatan Show Cause Order) highlighting two post-order ex parte concerns. On March 3, OE replied to the answers provided by Powhatan Respondents.

Since the last report, on March 18, Chen replied to OE’s March 3 materials. On April 1, PJMsubmitted comments requesting FERC guidance with respect to certain matters should disgorgement beordered in this proceeding. Specifically, PJM requested that the FERC:

direct Staff be to provide PJM with a breakdown of the amount to be disgorged on an hourly basis,per Operating Day at issue

provide guidance regarding what PJM should do with refunds owed to entities that are no longerPJM Members

suspend any refund requirement, or direct or allow PJM to hold the disgorgement monies in escrow,until such time as a final order has been received from a court of competent jurisdiction if appealed

indicate the date from which interest should be calculated on the disgorgement, or provide PJM witha specific breakdown of the total amount due including interest, on an hourly basis from each of theRespondents.

specify in its order that any portion of the disgorged funds can be applied to reduce the amount ofany outstanding default

indicate whether the other entities referred to OE in the same referral are entitled to receive theportion of the disgorged funds or whether they should be excluded from any such refunds.

These matters are pending before the FERC. If you have any questions concerning this matter, pleasecontact Pat Gerity (860-275-0533; [email protected]).

XII. Misc. - Administrative & Rulemaking Proceedings

• Technical Conferences on Implications of Environmental Regulations (AD15-4)

The FERC initiated this proceeding, on December 9, 2014, in order to discuss, in a series of technicalconferences, the implications of compliance approaches to the Environmental Protection Agency’s (“EPA”)


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proposed Clean Power Plan issued June 2, 2014.98 The technical conferences will focus on issues related toelectric reliability, wholesale electric markets and operations, and energy infrastructure. There has been one,Commissioner-led National Overview technical conference held February 19. There will be three, staff-ledregional technical conferences; as noted below, the Eastern region conference was held March 11.

Feb 19 National Overview technical conference. This conference included discussion of thefollowing overarching topics: (1) whether industry participants (state utility and environmental regulators,regulated entities, etc.) have the appropriate tools to identify reliability and/or market issues that may arise; (2)potential strategies for compliance with the EPA regulations and coordination with FERC-jurisdictionalwholesale and interstate markets; and (3) how relevant planning entities, industry, and states coordinatereliability and infrastructure planning processes with state and/or regional environmental compliance efforts toensure the adequate development of new infrastructure and to manage any potential reliability and operationalimpacts of proposed compliance plans. Comments have been filed by more than 15 parties, including theEnergy Policy Group, the ISO/RTO Council (“IRC”), AWEA, NEI, NRECA, CAISO, and PJM.

Mar 11 Eastern99 Regional conference. This conference included discussion of the following topics:(1) potential reliability impacts in each region under various compliance approaches; (2) potential impacts onpower system operations and generator dispatch in each region under various compliance approaches; and (3)potential impact on each region’s current or expected infrastructure (electric transmission, natural gaspipelines, generation, etc.) to address compliance with the proposed rule, and additional infrastructure that maybe required. Speaker materials and post-conference comments are posted on the FERC’s eLibrary.

• Price Formation in RTO/ISO Energy & Ancillary Services Markets (AD14-14)

On June 19, 2014, the FERC initiated a proceeding to evaluate price formation issues in RTO/ISOenergy and ancillary services markets. In its notice, the FERC announced a series of staff workshops tofacilitate a discussion with market operators and their stakeholders on the existing market rules and operationalpractices related to:

use of uplift payments;

offer price mitigation and offer price caps;

scarcity and shortage pricing; and

operator actions that affect price.

Sep 8 Workshop. The FERC held its first workshop on September 8, 2014. The September 8workshop focused on the technical, operational and market issues that give rise to uplift payments and thelevels of transparency. The workshop also previewed the scope of the remaining price formation topics. Thewebcast of the September 8 workshop will be archived and available for 3 months on the FERC’s website athttp://ferc.capitolconnection.org/. Speaker materials have been posted in the FERC’s eLibrary. Also posted ineLibrary is a FERC staff report issued August 21 that analyzes “Uplift in RTO and ISO Markets.”

Oct 28 Workshop. The FERC held its second workshop on October 28, 2014. The October 28workshop focused on the technical, operational, and market issues related to offer price mitigation and offerprice caps, and scarcity and shortage pricing in energy and ancillary services markets operated by RTOs/ISOs.In advance of the workshop, FERC staff posted on October 21 two reports, one on shortage pricing inRTO/ISO markets (http://www.ferc.gov/legal/staff-reports/2014/AD14-14-pricingrto-iso-markets.pdf), theother on energy offer mitigation in RTO/ISO markets (http://www.ferc.gov/legal/staff-reports/2014/AD14-14-mitigation-rto-iso-markets.pdf).

98 Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units, Noticeof Proposed Rulemaking, 79 Fed. Reg. 34,830 (June 18, 2014).

99 The Eastern Region includes New England, Northern Maine Independent System Administrator, New York,PJM, Southeastern Regional Transmission Planning (“SERTP”), South Carolina Regional Transmission Planning(“SCRTP”), and the Florida Reliability Coordinating Council (“FRCC”).


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Dec 9 Workshop. The third and final workshop was held on December 9. The December 9 workshopfocused on RTO/ISO operator actions that affect price. New England speakers included, among others, JoelGordon, Tom Kaslow, David Patton, Pete Brandein, and Matt White. Speaker materials are posted in theFERC’s eLibrary.

Post-Technical Workshop Comments. On January 16, the FERC invited all interested to file post-technical workshop comments on any or all of the 12 questions listed in the attachment to its January 16Notice, with any such comments due on or before February 19. A 15-day extension of time to file suchcomments, to and including March 6, was jointly requested by APPA, EPSA and NRECA. CAISO, NYISO,PJM and SPP jointly filed a motion supporting the trade associations’ request. On February 3, ISO-NE alsoasked for an extension of time, but only with respect to questions 5-12, but to and including March 20, 2015.On February 9, the FERC extended the deadline to submit comments to and including March 6, 2015. Sincethe last Report, nearly 40 sets of comments were submitted, including by: ISO-NE, APPA, Brookfield,Calpine, Direct Energy, EEI, EPSA, Exelon, and PSEG.

The FERC web page for this issue is at http://www.ferc.gov/industries/electric/indus-act/rto/energy-price-formation.asp.

• RTO/ISO Winter 2013/14 Operations and Market Performance (AD14-8)

On November 20, the FERC issued an order directing RTOs/ISOs to file reports on or before February18, 2015, on the status of their efforts to address fuel assurance issues.100 While the FERC noted that it “couldtake action to impose solutions, and may need to in the future if the steps RTOs/ISOs have taken or plan totake prove inadequate, [it found] that the appropriate next step is for each RTO/ISO to provide the [FERC]with additional information to explain how its market rules address fuel assurance challenges.”101 Since thelast Report, INGAA submitted comments related to the November 20 order.

On February 18, 2015, the RTOs/ISOs submitted their reports in compliance with the November 20order. In its report, ISO-NE highlighted a number of initiatives to address fuel assurance concerns. The ISOstated that the centerpiece of its efforts is the Pay-For-Performance PCM design, which will take full effect in2018. The ISO described its interim solutions, the two most recent Winter Reliability Programs and the yet-to-be-finally-determined program(s) to be implemented until PFP takes full effect. The ISO also identified thefollowing additional initiatives helping to address fuel assurance and generator performance issues: increasedRCPFs, Energy Market offer flexibility, clarification of generator fuel procurement obligations, Day-AheadEnergy Market timing changes, Replacement Reserves RCPF, information sharing with natural gas pipelines,fuel cost recovery in extraordinary circumstances, expansion of the FCM Shortage Event rigger, increasedfrequency of fuel surveys, and improvements to the ETU process. Comments on the RTO/ISO reports weredue on or before March 20 and were filed by over 15 parties, including by: EPSA, Eversource, Exelon,NESCOE, NHPUC, and UCS.

100 Winter 2013-2014 Operations and Market Performance in Regional Transmission Organizations andIndependent System Operators, 149 FERC ¶ 61,145 (Nov. 20, 2014). The FERC explained that “fuel assurance” describes“the broad set of issues that have emerged in the RTOs/ISOs with respect to generator access to sufficient fuel supplies andthe firmness of generator fuel arrangements. Fuel assurance is a broad concept that includes a range of generator-specific andsystem-wide issues, including the overall ability of an RTO’s/ISO’s portfolio of resources to access sufficient fuel to meetsystem needs and maintain reliability.” Fuel assurance may also “encompass impacts on fuel availability of any industry inthe supply chain, including contingencies and other risks stemming from those industries.”

101 Id. at P 19.


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• NOPR: Third-Party Provision of Primary Frequency Response Service (RM15-2)

On February 19, the FERC issued a NOPR proposing to foster competition in the sale of primaryfrequency response service102 by permitting its sale at market-based rates by sellers with market-based rateauthority for energy and capacity. The FERC stated that this NOPR is an extension of its policy reforms begunwith Order 784103 and anticipates the potential interest in purchase of primary frequency response servicefrom third-parties as a result of a new reliability standard (BAL-003-1) that requires a Balancing Authority tomaintain a minimum frequency response obligation. Comments on this NOPR are due on or before April 27,2015.104

• NOPR: MBR Authorization Refinements (RM14-14)

On June 19, the FERC issued a NOPR proposing to revise its current standards, and to streamline certainaspects of its filing requirements, for obtaining market-based rates (“MBR”) for sales of electric energy, capacity,and ancillary services.105 In addition, the FERC clarified certain standards for obtaining and retaining MBRauthority. Among other changes, the FERC proposes (i) to permit sellers in RTO/ISO markets with Commission-approved market monitoring and mitigation to include a statement that they are relying on such mitigation toaddress any potential horizontal market power concerns in lieu of submitting the indicative screens; (ii) to permitsellers to explain that their qualified capacity is fully committed in lieu of including indicative screens in theirfilings in order to satisfy the FERC’s horizontal market power tests and to submit a change in status filing whenthere is a net increase of 100 MW or more; (iii) to relieve sellers of their obligation to file quarterly landacquisition reports and of the obligation to provide information on sites for generation capacity development inmarket-based rate applications and triennial updated market power analyses; (iv) to require a change in statusfiling if there is a 100 MW increase in cumulative nameplate capacity added in any relevant geographic market;and (v) require corporate org charts with all MBR applications and notices of change in status. Comments on thisNOPR were due September 23, 2014.106 Over 25 parties filed comments and Berkshire Hathaway, Barrick Mines,and EPSA filed reply comments. This NOPR is pending before the FERC.

• Order 807: Open Access and Priority Rights on ICIF (RM14-11)

On March 19, the FERC issued Order 807,107 which waives the Open Access Transmission Tariff(“OATT”) requirements of 18 CFR 35.28 (2013), the Open Access Same-Time Information System (“OASIS”)requirements of Part 37 of its regulations, 18 CFR 37 (2013), and the Standards of Conduct requirements of Part358 of its regulations, 18 CFR 358 (2013), for any public utility that is subject to such requirements solelybecause it owns, controls, or operates Interconnection Customer’s Interconnection Facilities (“ICIF”),108 in wholeor in part, and sells electric energy from its Generating Facility. Order 807 also finds that those seekinginterconnection and transmission service over ICIF that are subject to the blanket waiver adopted in Order 807may follow procedures applicable to requests for interconnection and transmission service under sections 210,211, and 212 of the FPA, which also allows the contractual flexibility for entities to reach mutually agreeable

102 Primary frequency response service would be a reserve product that involves dedicating capacity on a generatoror other resource for autonomous, automatic, and rapid action to change its output (within seconds) to rapidly dampen largechanges in frequency.

103 Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric StorageTechnologies, Order No. 784, 78 Fed. Reg. 46,178 (July 30, 2013), FERC Stats. & Regs. ¶ 31,349, at PP 6-7 (2013), order onclarif., Order No. 784-A, 146 FERC ¶ 61,114 (2014) (“Order 784”).

104 The NOPR was published in the Fed. Reg. on Feb. 26, 2015 (Vol. 80, No. 38) pp. 10,426-10,432.

105 Refinements to Policies and Procedures for Market-Based Rates for Wholesale Sales of Elec. Energy, Capacityand Ancillary Srvcs. by Public Utils., 147 FERC ¶ 61,232 (June 19, 2014) (“MBR NOPR”).

106 The MBR NOPR was published in the Fed. Reg. on July 25, 2014 (Vol. 79, No. 143) pp. 43,536-43,572.

107 Open Access and Priority Rights on Interconnection Customer’s Interconnection Facilities, Order No. 807, 150FERC ¶ 61,211 (Mar. 19, 2015) (“Order 807”).

108 ICIF is the term used by the FERC in the NOPR to refer to “generator tie lines”.


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access solutions. Order 807 establishes a modified rebuttable presumption for a 5-year safe harbor period toreduce risks to ICIF owners eligible for the blanket waiver during the critical early years of their projects. Finally,Order 807 modifies several elements of the NOPR, including the entities eligible for the OATT waiver, the dateon which the safe harbor begins, the rebuttable presumption that the ICIF owner should not be required to expandits facilities during the safe harbor, and the facilities covered by Order 807. Order 807 will become effectiveJune 30, 2015.109 Challenges, if any, to Order 807 will have to be filed on or before April 20.

• WIRES Request for Policy Statement on ROE for Electric Transmission (RM13-18)

On June 26, 2013, WIRES110 petitioned the FERC to institute an expedited generic proceeding and toprovide such policy and clarifications as necessary to provide “greater stability and predictability regardingregulated rates of return on equity for existing and future investments in high voltage electric transmissioninfrastructure.” Specifically, WIRES recommended a new policy that (1) standardizes selection of proxygroups; (2) denies complainants a hearing on rates of return for existing facilities unless it is shown thatexisting returns are at the extremes of the zone of reasonableness; (3) allows consideration of competinginfrastructure investments of other industries; (4) permits use of other rate of return methodologies; and (5)supports use of more forward-looking data and modeling. In addition, WIRES urged the FERC to supportconsideration of a project’s actual and anticipated benefits when a complaint is filed against the ROE for anexisting project. Although the WIRES petition has not been noticed for public comments, more than 16 setsof comments have been filed. On October 3, 2013, WIRES submitted a summary of the comments andanalysis filed to that point in the proceeding. On October 16, the Organization of PJM States noted itsposition that the WIRES petition did not present a compelling reason for the FERC to initiate a genericrulemaking proceeding or abandon its Discounted Cash Flow methodology. On November 5, 2013, a letterfrom US Senator Angus King, urging the FERC to establish a more certain regulatory environment thatprovide investors the level of confidence necessary to support and encourage needed infrastructureinvestments, was posted in eLibrary. This matter is pending before the FERC.

• Order 771: Availability of e-Tag Information to FERC Staff (RM11-12)

Rehearing of portions of Order 771 has been requested and remains pending. As previously reported,Order 771,111 issued December 20, 2012, granted the FERC access, on a non-public and ongoing basis, to thecomplete electronic tags (“e-Tags”) used to schedule the transmission of electric power interchange transactionsin wholesale markets. Order 771 requires e-Tag Authors (through their Agent Service) and Balancing Authorities(through their Authority Service) to take steps to ensure FERC access to the e-Tags covered by this Rule bydesignating the FERC as an addressee on the e-Tags. The FERC stated that the information made available underthis Final Rule will bolster its market surveillance and analysis efforts by helping it detect and prevent marketmanipulation and anti-competitive behavior. In addition, Order 771 requires e-Tag information be made availableto RTO/ISOs and their Market Monitoring Units, upon request to e-Tag Authors and Authority Services, subjectto appropriate confidentiality restrictions. Order 771 became effective February 26, 2013.112 In response torequests for clarification and/or rehearing of Order 771 filed by EEI/NRECA, Open Access TechnologyInternational, Inc., NRECA (separately), and Southern Companies (collectively, the “Rehearing Requests”), theFERC issued, on March 8, 2013, Order 771-A.113 Order 771-A addressed only those issues that needed to beanswered on an expedited basis to allow affected entities to comply with the requirement to ensure FERC access

109 Order 807 was published in the Fed. Reg. on Apr. 1, 2015 (Vol. 80, No. 62) pp. 17,654-17,682.

110 WIRES, the Working group for Investment in Reliable and Economic Electric Systems, describes itself as anational non-profit association of investor-, member-, and publicly-owned entities dedicated to promoting investment in astrong, well-planned, and environmentally beneficial high voltage electric transmission grid. Information about its principlesand members is available on its website www.wiresgroup.com.

111 Availability of E-Tag Info. to Comm’n Staff, Order No. 771, 141 FERC ¶ 61,235 (Dec. 20, 2012) (“Order 771”),order on reh’g and clarif., 142 FERC ¶ 61,181 (2013).

112 Order 771 was published in the Fed. Reg. on Dec. 28, 2012 (Vol. 77, No. 249) pp. 76,367-76,380.

113 Availability of E-Tag Info. to Comm’n Staff, Order No. 771-A, 142 FERC ¶ 61,181 (Mar. 8, 2013) (“Order 771-A”).


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in a timely manner to the e-Tags covered by Order 771.114 The FERC noted that it would issue an additionalrehearing order, addressing the remaining issues raised on rehearing and clarification, which therefore remainpending before the FERC.

• Order 676-H: Incorporation of WEQ Version 003 Standards (RM05-5)

On September 18, 2014, the FERC issued Order 676-H,115 which proposes to amend FERC regulationsby incorporating by reference, with certain enumerated exceptions, Version 003 of the Standards for BusinessPractices and Communication Protocols for Public Utilities adopted by the Wholesale Electric Quadrant (“WEQ”)of the North American Energy Standards Board (“NAESB”). The Version 003 Standards update earlier versionsof these standards previously incorporated by reference into FERC regulations at 18 CFR 38.2. The Version 003standards include modifications to support Order Nos. 890, 890-A, 890-B and 890-C, including the standards tosupport Network Integration Transmission Service on an OASIS, Service Across Multiple Transmission Systems(“SAMTS”), standards to support FERC policy regarding rollover rights for redirects on a firm basis, standardsthat incorporate the functionality for transmission providers to credit redirect requests with the capacity of theparent reservation and standards modifications to support consistency across the OASIS-related standards. TheVersion 003 Standards also include modifications to the OASIS-related standards that NAESB states supportOrder Nos. 676, 676-A, 676-E and 717 and add consistency. In addition, there are modifications to theCoordinate Interchange standards to compliment recent updates to e-Tag specifications, modifications to theGas/Electric Coordination standards to provide consistency between the two markets, and re-organized andrevised definitions to create a standard set of terms, definitions and acronyms applicable to all NAESB WEQstandards. The Version 003 Standards include the Standards addressed in Order 676-G and the recent Smart GridStandards. Order 676-H will become effective October 24, 2014.116 Requests for rehearing of Order 676-H werefiled by EPSA and the NYISO on October 20, 2014. On November 19, the FERC issued a tolling order affordingit additional time to consider the rehearing requests, which remain pending before the FERC.

Compliance Deadlines Extended. On January 15, the FERC extended for all entities subject to theserequirements the deadline for compliance with the Version 003 business practice standards, with the exception ofthe OASIS template (for which compliance is required by March 24, 2016), to and including May 15, 2015. Allother compliance obligations set forth in Order 676-H remain in force.

114 Order 771-A clarified that: (1) Balancing Authorities and their Authority Services will have until 60 days afterpublication of this order to implement the validation requirements of Order 771; (2) validation of e-Tags means that the SinkBalancing Authority, through its Authority Service, must reject any e-Tags that do not correctly include the FERC in the CCfield; (3)the requirement for the FERC to be included in the CC field on the e-Tags applies only to e-Tags created on or afterMarch 15, 2013; (4) the FERC will deem all e-Tag information made available to the FERC pursuant to Order 771 as beingsubmitted pursuant to a request for privileged and confidential treatment under 18 CFR 388.112; (5) the FERC is to beafforded access to the Intra-Balancing Authority e-Tags in the same manner as interchange e-Tags; and (6) the requirementon Balancing Authorities to ensure FERC access to e-Tags pertains to the Sink Balancing Authority and no other BalancingAuthorities that may be listed on an e-Tag.

115 Standards for Bus. Practices and Communication Protocols for Pub. Utils., Order No. 676-H, 148 FERC ¶61,205 (Sep. 18, 2014) (“Order 676-H”).

116 Order 676-H was published in the Fed. Reg. on Sep. 24, 2014 (Vol. 79, No. 185) pp. 56,939-56,955.


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For further information on any of the natural gas proceedings, please contact Joe Fagan (202-218-3901;[email protected]), Jennifer Galiette (860-275-0338; [email protected]) or Jamie Blackburn (202-218-3905; [email protected]).

• Inquiry Into Natural Gas Trading, and Proposal to Establish an Electronic Information and TradingPlatform (AD14-19)

On September 18, 2014, Commissioner Moeller convened a meeting to discuss issues related to howtransactions are conducted on the natural gas system and potential transactional improvements to address theneeds of electric generators for natural gas. The meeting included representatives/speakers from varioussectors of the natural gas and electric industries (load, suppliers, marketers, exchanges, gas associations, andISOs) and environmental interests. Representatives from NYISO and PJM were among the speakers on theelectric side (ISO-NE was not present). A summary of that meeting is posted on the Litigation Updates &Reports webpage (http://nepool.com/uploads/Lit_Supp_AD14-19_20140918_Mtg_Summary.pdf ). Writtencomments on issues discussed at the meeting, limited to 5 pages, were due on or before October 1, 2014.Comments were filed by more than 30 parties. There was no published activity in this proceeding since thelast Report.

• NOPR: Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and PublicUtilities (RM14-2)

On March 20, 2014, the FERC issued a series of orders addressing gas-electric coordination. At the forefront,was this NOPR, in which the FERC proposes to revise its natural gas act regulations in order to better coordinate thescheduling of natural gas and electricity markets and to provide additional flexibility to natural gas shippers.117

Specifically, the NOPR proposes to: (i) start the Gas Day earlier, at 4:00 a.m. Central Clock Time (“CCT”)118 ratherthan 9:00 a.m., in order to ensure that gas-fired generators are not running short on gas supplies during the morningelectric ramp periods; (ii) institute a later start to the first day-ahead gas nomination opportunity (called the TimelyNomination Cycle), from 11:30 a.m. to 1 p.m. The FERC said that because the Timely Nomination Cycle is the mostliquid of the gas nomination cycles, this change will allow electric utilities to finalize their scheduling before gas-firedgenerators must make gas purchase arrangements and submit nomination requests for natural gas transportation serviceto the pipelines; and (iii) modify the current intraday nomination timeline to provide 4 (rather than 2) intradaynomination cycles in order to provide greater flexibility to all pipeline shippers. The NOPR adds an early morningnomination cycle with a mid-day effective flow time and a new late-afternoon nomination cycle during which firmnominations would have precedence over or be permitted to bump already scheduled interruptible service. Ultimately,the standard cycles will be 8:00 a.m. CCT (bump), 10:30 a.m. CCT (bump), 4:00 p.m. CCT (bump) and 7:00 p.m. CCT(no-bump).

To provide shippers additional flexibility, the NOPR also proposes to: (i) clarify its policy with respect to the“No-Bump” Rule for Pipelines with Enhanced Nomination Services (the ability of a pipeline to permit firm shippers tobump an interruptible shipper’s nomination during any enhanced nomination opportunity proposed by the pipeline(beyond the standard nomination opportunities). The FERC indicated that under the revised intraday nominationtimelines proposed here, pipelines offering enhanced nomination services should be permitted to bump interruptibleshippers at least until the time when the bumping notice under the newly proposed Intra-Day 3 schedule is provided (inthe Commission’s proposal 6:00 p.m. CCT); and (ii) require Multi-Party Transportation Contracts; and (ii) FERCproposes to require all interstate pipelines to offer multi-party service agreements, providing multiple shippers theflexibility to share interstate pipeline capacity to serve complementary needs in an efficient manner.

117 Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and Public Utilities, 146 FERC ¶61,201 (Mar. 20, 2014).

118 CCT, pursuant to the NAESB WGQ standards, reflects daylight savings changes.


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Noting that the natural gas and electricity industries are best positioned to work out the details of how changesin scheduling practices can most efficiently be made and implemented, consistent with the policies discussed in theNOPR, the FERC provided the industries 6 months to reach consensus on standards, consistent with FERC’s guidancein the NOPR, including any revisions or modifications to the proposals provided herein. Comments were dueNovember 28, 2014.119 The FERC also noted its expectation that the electric industry (particularly the ISO/RTOs)would participate in these efforts to help ensure that the resulting consensus reasonably accommodates the interests ofboth industries.

On September 29, NAESB submitted a status report and record of its activities in response to Gas-ElectricScheduling Coordination NOPR. In that report, NAESB identified the modifications to the NAESB Wholesale GasQuadrant (WGQ) Business Practice Standards specific to the NOPR. The modified NAESB WGQ Business PracticeStandards propose revisions to the nomination timeline that result in three intra-day nomination cycles in addition to thetimely and evening nomination cycles. The nomination cycles are not dependent upon a specific start time to the gas dayand are implementable with whichever time the FERC chooses as a start of the gas day. Comments on the NAESBstatus report were due on or before November 28, 2014 and were filed by over 80 parties, including, among others, byISO-NE, the ISO/RTO Council, NESCOE, Calpine, Direct, Dominion, EEI, EPSA, Essential Power, Exelon, and theNew England LDCs. This matter is pending before the FERC.

On December 12, 2014, the FERC issued a data request to ISO-NE (along with other ISOs) related to theCommission’s proposal to move the start of the gas day. Specifically, the FERC asked ISO-NE a series of questionsregarding the frequency and timing of generators’ exhausting their daily nomination of natural gas transportation serviceprior to the end of the gas day during 2013 and 2014. The ISO the ISO/RTO Council requested an extension of time, toand including January 22, for the RTO/ISO responses to the December 12 data requests., which the FERC granted.

On January 22, 2015, ISO-NE submitted its response to the data request.120 The ISO stated that moving the gasday will “help minimize the risks of generators running out of gas during the morning ramp,” but also stressed that ithad already taken a number of actions to alleviate these issues. The ISO also acknowledged that it needs its generatingresource owners and other entities to invest in firm fuel supplies and transportation and to maintain on-site fuelinventory and dual fuel capability. On February 2, comments in response to the ISO/RTO data responses were filed byfour parties: the Coalition for Enhanced Electric and Gas Reliability, the Natural Gas Council, the New England LocalDistribution Companies (“LDCs”), and the American Public Gas Association (“APGA”).

• Posting of Offers to Purchase Capacity (Section 5 Proceeding) (RP14-442)

Similar to the ISO/RTO 206 Order in EL14-22 et al. (see Section I above), the FERC also instituted aproceeding under Section 5 of the Natural Gas Act to examine whether interstate natural gas pipelines areproviding notice of offers to purchase released pipeline capacity in accordance with section 284.8(d) of theCommission’s regulations.121 On or before May 19, natural gas pipelines were required to either revise theirrespective tariffs to provide for the posting of offers to purchase released capacity, or otherwise demonstrate thatthey are in full compliance with FERC regulations.122 The FERC also requested that NAESB develop businesspractice and communication standards specifying: (1) the information required for requests to acquire capacity;(2) the methods by which such information is to be exchanged; and (3) the location of the information on apipeline’s website. The Show Cause Order required each pipeline to explain in its compliance filing how it willfully comply with section 284.8(d) until NAESB develops, and the FERC implements, the requested standards,including how the pipeline will provide shippers the ability to post offers to purchase capacity on theInformational Posting section of its Internet website.

119 The NOPR was published in the Fed. Reg. on Apr. 1, 2014 (Vol. 79, No. 62) pp. 18,223-18,243.

120 Responses to the data request were also submitted by NYISO, MISO, PJM and SPP.

121 Posting of Offers to Purchase Capacity, 146 FERC ¶ 61,203 (Mar. 20, 2014).

122 Id. at P 6.


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In total, the FERC received, and addressed in one omnibus order, 157 compliance filings.123 Of the 157filings, 64 pipelines revised their respective tariffs to provide for the posting of offers to purchase releasedcapacity in a manner that complies with section 284.8(d), and 23 pipelines demonstrated that their tariffs alreadycomply with that section. The FERC found that, and identified in its omnibus order on the compliance filings the,69 compliance filings that did not appear to be in full compliance with that section, and directed furthercompliance filings from those companies as described in the omnibus order.

• Natural Gas-Related Enforcement Actions

The FERC continues to closely monitor and enforce compliance with regulations governing open accesstransportation on interstate natural gas pipelines. Since the last Report, there was a great deal of activity in thefollowing on-going, gas-related enforcement proceeding:

Company Alleged Violation(s) CivilPenalty/Disgorgement

BP America Inc.BP Corp. N. Amer.BP Amer. ProductionBP Energy Co.(together, “BP”)(IN13-15)

The FERC established a hearing to determinewhether BP violated section 4A of the Natural GasAct and the FERC’s Anti-Manipulation Rule asalleged by OE Staff. OE Staff alleged that BPtraded physical natural gas at Houston Ship Channel(“HSC”) to increase the value of BP’s financialposition at HSC, uneconomically using BP’stransportation capacity, making repeated earlyuneconomic sales at HSC, taking steps to increaseBP’s market concentration at HSC. In doing so, OEstaff alleged, BP suppressed the HSC Gas Dailyindex with the goal of increasing the value of BP’sfinancial position at HSC. The activity occurredfrom mid-September 2008 through November 2008.

Show Cause Order124

$28 million (civil penalty)$800,000 (disgorgement)

On October 29, BP and Enforcement Staff agreed to a modified procedural schedule for the hearingprocedures underway. Pursuant to that schedule, hearings before Judge Cintron will begin March 30, 2015, withan Initial Decision due August 14, 2015.

• New England Pipeline Proceedings

The following New England pipeline projects are pending before the FERC:

• Algonquin Incremental Market Project (AIM Project) (CP14-96)

Algonquin Gas Transmission filed for Section 7(b) and 7(c) certificate Feb. 28, 2014

342,000 dekatherms/day of firm capacity to NY, CT, RI and MA.

37.6 miles of take-up, loop and lateral pipeline facilities in NY, CT, and MA and systemmodifications in NY, CT and RI. The system upgrades would also require the removal ofsome facilities.

10 firm shippers: Yankee Gas, NSTAR, Connecticut Natural Gas, Southern Connecticut,Narragansett Electric, Colonial Gas, Boston Gas, Bay State, Norwich Public Utilities, andMiddleborough Gas and Electric (eight LDCs and two municipal utilities).

Final EIS issued on Jan 23, 2015.

90-day Federal Authorization Decision Deadline April 23, 2015.

123 See BR Pipeline Co. et al., 149 FERC ¶ 61,031 (Oct. 16, 2014).

124 BP America Inc. et al., 144 FERC ¶ 61,100 (Aug. 5, 2013).


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Certificate of public convenience and necessity granted Mar 3, 2015 (must be constructedand in service within two years).125

In-service: Nov 2016 (anticipated).

• Connecticut Expansion Project (CP14-529)

Tennessee Gas Pipeline filed for Section 7(c) certificate July 31, 2014.

72,100 dekatherms/day of firm capacity.

13.26 miles of three looping segments and facility upgrades/modifications in NY, MA andCT.

Three firm shippers: Connecticut Natural Gas, Southern Connecticut Gas, and Yankee Gas.

Authorization requested by July 31, 2015.

Construction expected to begin Winter 2015/16.

In-service: Nov 2016 (anticipated).

• Constitution Pipeline (CP13-499) and Wright Interconnection Project (CP13-502)

Constitution Pipeline Company and Iroquois Gas Transmission (Wright Interconnection)concurrently filed for Section 7(c) certificates on June 13, 2013.

650,000 dekatherms/day of firm capacity from Susquehanna County, PA through NY toIroquois/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 granted Dec 2, 2014 (must be constructed and in service within two years);

Construction expected to first-quarter 2015.

• Salem Lateral Project (CP14-522)

Algonquin Gas Transmission filed application Jul 10, 2013.

115,000 dekatherms/day of firm capacity.

1.2 miles of pipeline to 630 MW Salem Harbor Station and other Salem, MA facilities.

Footprint Power sole firm customer.

Authorization requested by Apr 17, 2015.

FERC environmental assessment issued Dec 2, 2014.

In-Service: Nov 2015 (anticipated).


No Activity to Report.

XV. Federal Courts

The following are matters of interest, including petitions for review of FERC decisions in NEPOOL-relatedproceedings, that are currently pending before the federal courts (unless otherwise noted, the cases are before theU.S. Court of Appeals for the District of Columbia Circuit). An “**” following the Case No. indicates thatNEPOOL has intervened or is a litigant in the appeal. The remaining matters are appeals as to which NEPOOL

125 Order Issuing Certificate and Approving Abandonment, Algonquin Gas Transmission LLC, 150 FERC ¶ 61,163(Mar. 3, 2015), reh’g requested.


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has no organizational interest but that may be of interest to Participants. For further information on any of theseproceedings, please contact Pat Gerity (860-275-0533; [email protected]).

• FCM Administrative Pricing Rules Complaint (15-1071)Underlying FERC Proceedings: EL14-7126

Appellants: NEPGA

On March 31, 2015, NEPGA filed a petition for review of the FERC’s orders on NEPGA’s FCMAdministrative Pricing Rules Complaint. A Docketing Statement Form, Statement of Issues to be Raised, andAppearances must be filed by Petitioners by April 30, 2015.

• Demand Curve Changes (15-1070)Underlying FERC Proceedings: ER14-1639127

Appellants: NextEra, NRG and PSEG

On March 30, 2015, NextEera, NRG and PSEG filed a petition for review of the FERC’s orders in theDemand Curve Changes proceedings. A Docketing Statement Form, Statement of Issues to be Raised, andAppearances must be filed by Petitioners by April 30, 2015.

• FCA8 Results (14-1244, 14-1246 (consolidated))Underlying FERC Proceedings: ER14-1409128

Appellants: Public Citizen and CT AG

On November 14, 2014, Public Citizen and the CT AG filed petitions for review of the FERC’s action onthe FCA8 Results Filing, which became effective by operation of law on September 16, 2014. These proceedingshave been consolidated. A Docketing Statement Form and Statement of Issues to be Raised were filed byPetitioners by December 22, 2014. On January 2, 2015, the FERC filed a motion to dismiss the petitions for lackof jurisdiction. The FERC argued that the Court lacks jurisdiction because Petitioners did not challenge a FERC“order” within the meaning of section 313 of the FPA, or “agency action” reviewable under the AdministrativeProcedures Act. On January 15, EPSA and NEPGA jointly filed a motion supporting the FERC’s motion todismiss. On January 26, Connecticut129 and Public Citizen opposed the FERC’s motion to dismiss. On February5, the FERC replied to the Public Citizen and CT AG responses. On April 7, the Court ordered that the motion todismiss be referred to the merits panel and parties were directed to address in their briefs the issues presented inthe motion to dismiss rather than incorporate those arguments by reference.

• 2013/14 Winter Reliability Program (14-1104, 14-1105, 14-1103 (consolidated))Underlying FERC Proceedings: ER13-1851130 and ER13-2266131

Appellants: TransCanada and RESA

On June 6, 2014, TransCanada and the Retail Energy Supply Association filed petitions for review of theFERC’s orders on the 2013/14 Winter Reliability Program (14-1104 and 14-1105, respectively). Also on June 6,2014, TransCanada filed a petition for review of FERC’s orders on the 2013/14 Winter Reliability Program BidResults Filings (ER14-1103). On July 3, 2014, these proceedings were consolidated. On July 7, the FERCrequested a minimum of 60 days after Petitioners’ opening briefs to file its brief. On July 23, leave to intervenewas granted to ISO-NE, NEPGA, PSEG and Essential Power. On September 29, TransCanada, RESA, FERC,

126 150 FERC ¶ 61,064 (Jan. 30, 2015); 146 FERC ¶ 61,039 (Jan. 24, 2014).

127 150 FERC ¶ 61,065 (Jan. 30, 2015); delegated letter order (Nov. 13, 2014); 147 FERC ¶ 61,173 (May 30, 2014).

128 Notice of Filing Taking Effect by Operation of Law, ISO New England Inc., Docket No. ER14-1409 (Sep. 16,2014); Notice of Dismissal of Pleadings, ISO New England Inc., Docket No. ER14-1409 (Oct. 24, 2014).

129 For purposes of this proceeding, “Connecticut” means the CT AG, CT PURA and CT OCC.

130 144 FERC ¶ 61,204 (Sep. 16, 2013); 147 FERC ¶ 61,026 (Apr. 8, 2014).

131 145 FERC ¶ 61,023 (Oct. 7, 2013); 147 FERC ¶ 61,027 (Apr. 8, 2014).


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ISO-NE, Essential Power MA, PSEG and NEPGA filed a proposed joint, unopposed briefing format andschedule. A Joint Brief for Petitioners was filed on November 24 (as corrected on December 1). At the FERC’srequest, the Court ordered that a revised briefing schedule be applied in this case (effectively extending the overallbriefing schedule by one month. Briefs for Respondent and Respondent-Intervenors were filed February 13 andMarch 2, respectively. Since the last Report, Petitioners’ Joint Reply Brief was filed on March 25; the DeferredAppendix, April 1, 2015. Final Briefs are due to be filed on April 15, 2015.

• Orders 773 and 773-A (2nd Cir., 13-2316)Underlying FERC Proceedings: RM12-6 and RM12-7132

Appellants: NY PSC and People of the State of New York

The NY PSC and the People of the State of New York have petitioned the Second Circuit Court ofAppeals for review of FERC’s orders on Orders 773 and 773-A (Revised “Bulk Electric System” Definitionand Procedures). Briefs were filed as follows: NYPSC/State of NY (May 2, 2014); NARUC (May 28); FERC(August 22); NERC (August 27); NERC reply brief (September 10, 2014); FERC and NY/NY PSC finalbriefs (September 24); NERC and NARUC intervenor briefs. Oral argument was held on November 20, 2014and this matter is pending before the Court.

• New England’s Order 745 Compliance Filing (12-1306)Underlying FERC Proceedings: ER11-4336133

Appellants: EPSA and NEPGA

On July 16, 2012, EPSA and NEPGA filed a petition for review of FERC’s orders on New England’sOrder 745 (Demand Response Compensation) filings. On August 16, 2012, EPSA and NEPGA filed astatement of issues as well as an unopposed motion to hold case in abeyance pending the final resolution ofCase Nos. 11-1486, et al. (EPSA et al. v. FERC) (see Orders 745 and 745-A below). On August 23, 2012, theCourt granted the motion to hold the case in abeyance. Motions to govern future proceedings will be due 30days following the issuance of the mandate in the Order 745 appeal.

• Orders 745 and 745-A (FERC v. EPSA, Supreme Court, 14-840 and 14-841)Underlying FERC Proceedings: RM10-17-000134

Appellants: FERC and EnerNOC

On January 15, the Solicitor General of the United States, on behalf of the FERC, filed with theSupreme Court a petition for a writ of certiorari seeking review of the District Court’s May 23 Decision.135

Respondents brief in opposition to that writ, pursuant to an order of the Court extending the time forresponses, was filed on March 19. The FERC’s petition and EPSA et al.’s response thereto is scheduled to goto conference on April 24, 2015.

As previously reported, the DC Circuit vacated Order 745136 in its entirety as impermissiblyencroaching on “states’ exclusive jurisdiction to regulate the retail market” in a 2-1 decision (“Decision”)issued on May 23, 2014. The DC Circuit vacated Order 745 on two separate and independent grounds. First,it held that the FERC does not have jurisdiction to regulate demand response. The Court reasoned that: (i) thestates retain exclusive authority to regulate the retail market; (ii) absent an express statutory grant of authority,the FERC cannot regulate areas left to the states; (iii) the FPA provides the FERC with authority overwholesale sales of electricity, but demand response is not such a sale; (iv) the authority of the FERC to

132 141 FERC ¶ 61,236 (Dec. 20, 2012); 143 FERC ¶ 61,053 (Apr. 18, 2013).

133 138 FERC ¶ 61,042 (Jan. 19, 2012); 139 FERC ¶ 61,116 (May 17, 2012).

134 134 FERC ¶ 61,187 (Mar. 15, 2011); 137 FERC ¶ 61,215 (Dec. 15, 2011).

135 EPSA v. FERC, 753 F.3d 216 (May 23, 2014).

136 Order 745 required RTOs and ISOs to include provisions in their tariffs that assured demand response would bepaid at LMP for interrupting their loads when such interruption was cost effective.


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regulate wholesale power rates under the FPA cannot be read so broadly as to allow direct regulation ofdemand response; and (v) demand response, while not necessarily a retail sale, is part of the retail market,involving retail customers, their decision whether to purchase at retail, and the levels of retail electricityconsumption. Therefore, the Court concluded, the FERC has no authority to directly regulate demandresponse. “FERC’s authority over demand response resources is limited: its role is to assist and advise stateand regional programs.”

As an alternative and secondary basis for its decision against Order 745, the Court concluded that theFERC order was “arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with law.” TheCourt found that the FERC failed to reasonably consider and address arguments that Order 745 will result inover-compensation of demand response resources, resulting in unjust and discriminatory rates. The Courtfurther found that the FERC failed to demonstrate how its proposed pricing construct would result in justcompensation. The Decision and preliminary implications of the Decision were summarized in more detail inthe memo included with the supplemental materials circulated and posted for the June 6 meeting.

On July 7, the FERC petitioned the Court for rehearing en banc of the May 23 Decision. On July 18,the Court, on its own motion, directed EPSA, APPA, NRECA, Old Dominion and EEI (“Petitioners”) to file ajoint response to the FERC petition for rehearing. That response was filed on August 4, 2014. The petitionfor rehearing en banc was denied on September 17, 2014. As previously reported, the DC Circuit directed itsclerk to withhold the Court’s mandate pending the Supreme Court’s final disposition.

• CPV Maryland, LLC v. PPL EnergyPlus et al. (Supreme Court, 14-623)

A petition for a writ of certiorari in this case was filed on November 26, 2014 and placed on the SupremeCourt’s docket on November 28, 2014 as No. 14-623. The parties consented to the filing of amicus curiae briefs,and such briefs were filed by NARUC, the State of Connecticut, and APPA. Respondents (PPL EnergyPlus,LLC, et al.) filed a response on February 11. Petitioner CPV Maryland, LLC replied on February 24. On March23, the Court invited the Solicitor General to file a brief in the case expressing the views of the United States.This matter is now before the Court.

As previously reported, on June 2, 2014, the 4th Circuit Court of Appeals affirmed the September 30,2013 decision of the United States District Court for the District of Maryland137 which found that a MarylandPublic Service Commission (“MD PSC”) order directing three Maryland distribution utilities to enter into a‘contract for differences’ for capacity and energy in the PJM control area (the “CfD”) with a gas-fired merchantgenerator selected by the MD PSC (the “MD PSC Order”) violated the Supremacy Clause of the United StatesConstitution and cannot be enforced.138 In affirming the District Court decision, the 4th Circuit found the MDPSC Order both field139 and conflict pre-empted.140

137 PPL EnergyPlus, LLC v. Nazarian, 974 F.Supp. 2d 790 (D. Md. Sep. 30, 2013); 2013 U.S. Dist. LEXIS 140210,2013 WL 5432346 (“District Court Decision”). The District Court Decision was summarized in past Litigation Reports.

138 PPL EnergyPlus, LLC v. Nazarian, 753 F.3d 467; 2014 U.S. App. LEXIS 10155.

139 “Field preemption” is a doctrine based on the Supremacy Clause of the U.S. Constitution that holds that anyfederal law, including regulations of a federal agency, takes precedence over any conflicting state law. Preemption can beimplied when federal law/regulation “occupies the field” in which the state is attempting to act/regulate. Field preemptionoccurs when there is "no room" left for state regulation. Accordingly, a state may not pass a law or take any action in a field,like the regulation of wholesale power sales, pervasively regulated by federal law/regulation.

140 “Conflict preemption” occurs where there is a conflict between a state law and a federal law. (“[E]ven ifCongress has not occupied the field, state law is naturally preempted to the extent of any conflict with a federal statute.”).Such a conflict occurs when “the challenged state law stands as an obstacle to the accomplishment and execution of the fullpurposes and objectives of Congress. The court must look to 'the entire scheme of the statute' and determine '[i]f the purposeof the [federal] act cannot otherwise be accomplished--if its operation with its chosen field [would] be frustrated and itsprovisions be refused their natural effect. Where a state law conflicts with a federal law, the Court does not balance the


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With respect to field pre-emption, the 4th Circuit stated that a “wealth of case law confirms FERC’sexclusive power to regulate wholesale sales of energy in interstate commerce, including the justness andreasonableness of the rates charged.”141 It found the federal scheme (i.e. the PJM Market) “carefully calibrated toprotect a host of competing interests” (representing “a comprehensive program of regulation that is quite sensitiveto external tampering”),142 and leaving “no room either for direct state regulation of the prices of interstatewholesales of [energy], or for state regulations which would indirectly achieve the same result.” Accordingly, the4th Circuit concluded that the MD PSC Order “field preempted because it functionally sets the rate that CPVreceives for its sales in the PJM auction.”143 The MD PSC Order “compromises the integrity of the federalscheme and intrudes on FERC’s jurisdiction” because the MD PSC Order “effectively supplants the rategenerated by the auction with an alternative rate preferred by the state.” The 4th Circuit rejected arguments thatthe CfD payments “represented a separate supply-side subsidy implemented entirely outside the federalmarket.”144 And, even if the presumption against preemption were to apply, the Court found that that it was“overcome by the text and structure of the FPA, which unambiguously apportions control over wholesale rates toFERC.”145

With respect to conflict pre-emption, the 4th Circuit found that the MD PSC Order “presents a direct andtransparent impediment to the functioning of the PJM markets, and is therefore preempted”.146 Preemption wasappropriate because of the “extensive and disruptive” impact of the MD PSC Order on matters within federalcontrol (the PJM markets). It found that the MD PSC Order had “the potential to seriously distort the PJM’sauction’s price signals, thus ‘interfer[ing] with the method by which the federal statute (i.e. the PJM Markets) wasdesigned to reach its goals.”147 “Maryland’s initiative disrupts [the PJM scheme] by substituting the state’spreferred incentive structure for that approved by FERC.”148 “Maryland has sought to achieve through thebackdoor of its own regulatory process what it could not achieve through the front door of FERC proceedings.Circumventing and displacing federal rules in this fashion is not permissible.”149

Petitions for rehearing en banc were filed by MD PSC and CPV Maryland on June 16, 2014. On June 17,2014, the 4th Circuit stayed the mandate pending the en banc ruling on the Petitions. On June 30, 2014, the 4th

Circuit denied the petitions for rehearing en banc.

• CPV Power Development, Inc., et al. v. PPL EnergyPlus, LLC, et al. (Supreme Court, 14-634, 14-694)

Petitions for a writ of certiorari in this case were filed on November 26, 2014 and December 10, 2014 andplaced on the Supreme Court’s docket as Case Nos. 14-634 and 14-694, respectively. The parties consented to thefiling of amicus curiae briefs, and such briefs were filed by NARUC, the State of Connecticut, APPA, AWEA,and the NY PSC. Since the last Report, Respondents (PPL EnergyPlus, LLC, et al.) filed a brief opposing the writof certiorari on February 11. Petitioners (CPV Power Development, Inc., et al.) replied to that brief on February

competing federal and state interests. Any state law, however clearly within a State’s acknowledged power, which interfereswith or is contrary to federal law, must yield.”

141 Slip op. at p. 14.

142 Id. at p. 10.

143 Id. at p. 16.

144 Id. at pp. 18-19.

145 Id. at p. 20. The Court noted the limited scope of its holding, which “is addressed to the specific program atissue” and did not “express an opinion on other state efforts to encourage new generation.” Id. at p. 21.

146 Id. at p. 27.

147 Id. at p. 23.

148 Id. at p. 24. (“Two features of the Order render its likely effect on federal markets particularly problematic.First, as noted, the CfDs are structured to actually set the price received at wholesale. They therefore directly conflict with theauction rates approved by FERC. Second, the duration of the subsidy -- twenty years -- is substantial.”)

149 Id. at p. 25.


Page 4641536280.149

20. On March 23, the Court invited the Solicitor General to file a brief in the case expressing the views of theUnited States.

As previously reported, on September 11, 2014, the 3rd Circuit Court of Appeals affirmed150 theanalogous October 11, 2013 decision of the United States District Court for the District of New Jersey declaringunconstitutional (and therefore null and void) New Jersey’s Long Term Capacity Agreement Pilot Program Act(“LCAPP”).151 In affirming the New Jersey District Court’s decision, the 3rd Circuit concluded:

LCAPP compels participants in a federally-regulated marketplace to transact capacity atprices other than the price fixed by the marketplace. By legislating capacity prices, NewJersey has intruded into an area reserved exclusively for the federal government.Accordingly, federal statutory and regulatory law preempts and, thereby, invalidatesLCAPP and the Standard Offer Capacity Agreements.152

No petition for rehearing or rehearing en banc was filed on or before September 25, 2014. Accordingly,the mandate was issued on October 3, 2014. As noted above, petitions for certiorari to the U.S. Supreme Courtwere filed and are pending before the Supreme Court.

• Entergy Nuclear Fitzpatrick, LLC et al v. Zibelman et al (NY PSC Commissioners) (N.D.N.Y. 5:15-cv-00230-DNH-TWD)

In a new matter since the last Report, Entergy153 filed, on February 27, in the United States District Courtfor the Northern District of New York, a Complaint that seeks a declaratory judgment that the NYPSCCommissioners’ order (“Order”) approving an agreement to keep NRG’s 435 MW Dunkirk facility in the NYISOmarket, “repowered” as a natural gas-fired (rather than coal-fired) plant (the “Term Sheet”)154 is preempted bythe FPA and invalid under the dormant Commerce Clause of the U.S. Constitution. Entergy also seeks apermanent injunction requiring the NYPSC Commissioners to withdraw its Order and/or preventing the NYPSCCommissioners from continuing to treat the Order as valid and binding. This case is noteworthy given therelationship of the issues raised to the Maryland and New Jersey CfD cases summarized above.

150 PPL EnergyPlus, LLC v. Hanna, 977 F.Supp.2d 372 (D. NJ. Oct. 11, 2013); 2013 U.S. Dist. LEXIS 147273,(“NJ Order”).

151 PPL EnergyPlus, LLC v. Hanna, 766 F.3d 241; 2014 U.S. App. LEXIS 17557 (Sep. 11, 2014).

152 Id. slip op. at 31.

153 Plaintiffs are Entergy Nuclear FitzPatrick, LLC (“FitzPatrick”); Entergy Nuclear Power Marketing, LLC(“ENPM”); and Entergy Nuclear Operations, Inc. (“ENOI”).

154 The Term Sheet provides that, in exchange for Dunkirk’s commitment to participate in the NYISO energy andcapacity markets through 2025, Dunkirk will receive out-of-market payments of $20.4 million per year from National Gridand a $15 million one-time subsidy from a New York State agency. Entergy asserts that the contract structure will leadDunkirk to bid below its actual costs in the capacity auction, causing the auction market to “clear” at a lower price thanotherwise would have resulted, and resulting in all generators receiving lower capacity revenues than they otherwise wouldhave received.


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INDEXStatus Report of Current Regulatory and Legal Proceedings

as of April 9, 2015

I. Complaints

206 Investigation: Consistency of ISO-NE (DA) Scheduling Practices withNatural Gas Scheduling Practices to be Adopted in Docket RM14-2 ................................. (EL14-23) ..............................6206 Investigation: FCM Performance Incentives (Compliance Proceeding)........................ (EL14-52; ER14-2419) ..........5206 Proceeding: Importers’ FCA Offers Review/Mitigation ............................................... (EL14-99; ER15-117) ............3Base ROE Complaint (2011) ................................................................................................ (EL11-66) ..............................7Base ROE Complaints (2012 and 2014) (Consolidated) ...................................................... (EL13-33 and EL14-86).........4LVA/PSNH IA Complaint.................................................................................................... (EL15-9) ..............................27NEPGA DR Capacity Complaint ......................................................................................... (EL15-21) ..............................2NEPGA Peak Energy Rent (PER) Complaint ...................................................................... (EL15-25) ..............................1NESCOE FCM Renewables Exemption Complaint............................................................. (EL13-34) ..............................7New Entry Pricing Rule Complaint ...................................................................................... (EL15-23) ..............................2NRG Canal 2 2015/16 ARA3 Complaint/Waiver Request................................................... (EL15-57) ..............................1


Base ROE Complaint (2011) ................................................................................................ (EL11-66) ..............................7Base ROE Complaints (2012 and 2014) (Consolidated) ...................................................... (EL13-33 and EL14-86).........4FCA9 Results Filing ............................................................................................................. (ER15-1137) ..........................9FCA-10 Capacity Zone Boundaries ..................................................................................... (ER15-1462) ..........................9Opinion 531-A Compliance Filing: TOs .............................................................................. (ER15-414) ............................8


206 Investigation: Consistency of ISO-NE (DA) Scheduling Practices withNatural Gas Scheduling Practices to be Adopted in Docket RM14-2 ................................. (EL14-23) ..............................6206 Investigation: FCM Performance Incentives (Compliance Proceeding)........................ (EL14-52; ER14-2419) ..........5206 Proceeding: Importers’ FCA Offers Review/Mitigation ............................................... (EL14-99; ER15-117) ............3CSO Termination: DFC-ERG CT......................................................................................... (ER15-1201) ........................10Demand Curve Changes ....................................................................................................... (ER14-1639) ........................10eTariff Corrections ............................................................................................................... (ER15-1455) ........................10FCM Performance Incentives Jump Ball Filing ................................................................... (ER14-1050) ........................12FCM PI Jump Ball Compliance Filing I .............................................................................. (ER14-2419-001)...................5FCM PI Jump Ball Compliance Filing II ............................................................................. (ER14-2419-002)...................5FCM Redesign Compliance Filing: FCA8 Revisions........................................................... (ER12-953 et al.) .................12Forward Reserve Obligation Charge Changes...................................................................... (ER15-1009) ........................10ISO Response to Show Cause Order .................................................................................... (ER15-117) ...........................3LMP Calculator Replacement............................................................................................... (ER15-1238) ........................10NEPGA DR Capacity Complaint ......................................................................................... (EL15-21) ..............................2NEPGA Peak Energy Rent (PER) Complaint ...................................................................... (EL15-25) ..............................1NESCOE FCM Renewables Exemption Complaint............................................................. (EL13-34) ..............................7New Entry Pricing Rule Complaint ...................................................................................... (EL15-23) ..............................2NRG Canal 2 2015/16 ARA3 Complaint/Waiver Request................................................... (EL15-57) ..............................1PER Mechanism Elimination (FCA-10)............................................................................... (ER15-1184) ........................10

IV. OATT Amendments/Coordination Agreements

ETU Rule Changes ............................................................................................................... (ER15-1050, -1051).............13Order 676-H Compliance: PTOs, SSPs, CSC et al. ............................................................. (ER15-517) ..........................14Order 676-H Compliance: Revisions to Schedule 24........................................................... (ER15-519) ..........................14Order 1000 Compliance Filing............................................................................................. (ER13-193; ER13-196)........15Order 1000 Interregional Requirements Compliance Filing ................................................ (ER13-1960; ER13-1957)....14Order 1000 November 15 Compliance Order Changes........................................................ (ER13-193; ER13-196)........15


Page I-241536280.149



VI. Schedule 20/21/22/23 Updates

LGIA – NU/CPV Towantic .................................................................................................. (ER15-200) ..........................17Opinion 531-A Compliance Filing: CTMEEC .................................................................... (ER15-584) ..........................17Opinion 531-A Compliance Filing: GMP............................................................................. (ER15-412) ..........................17Schedule 20A-EM and 21-EM Changes............................................................................... (ER15-1434) ........................17Schedule 21-NEP: BIPCO and Narragansett TSAs.............................................................. (ER15-1466) ........................17




Capital Projects Report - 2014 Q4........................................................................................ (ER15-1036) ........................18ISO-NE FERC Form 715 ..................................................................................................... (not docketed) ......................19Future Winter Reliability Program Progress Reports ........................................................... (ER14-2407) ........................18IMM Quarterly Markets Reports - 2014 Q4......................................................................... (ZZ14-4) ..............................19Quarterly Reports Regarding Non-Generating Resource Regulation Market Participation (ER08-54) ............................18Order 755 Regulation Market Progress Report ................................................................... (ER12-1643) ........................18Reserve Market Compliance (18th) Semi-Annual Report .................................................... (ER06-613) ..........................18


April 2015 Membership Filing ............................................................................................. (ER15-1417) ........................19March 2015 Membership Filing .......................................................................................... (ER15-1131) ........................19Suspension Notice (New England Confectionary Co.)......................................................... (not docketed) ......................19


FFT Report: March 2015...................................................................................................... (NP15-23) ............................20New Reliability Standard: EOP-011-1 ................................................................................. (RM15-7) .............................23New Reliability Standard: PRC-026-1 ................................................................................. (RM15-8) .............................23New Reliability Standard: TPL-007-1.................................................................................. (RM15-11) ...........................22NOPR: BAL-002-1a Interpretation Remand ........................................................................ (RM13-6) .............................26NOPR: Revised Rel. Standard: BAL-001-2 ......................................................................... (RM14-10) ...........................24NOPR: Revised Rel. Standard: COM-001-2 and COM-002-4............................................. (RM14-13) ...........................24NOPR: Revised Rel. Standard: MOD-001-2 ........................................................................ (RM14-7) .............................25NOPR: Revised TOP and IRO Reliability Standards ........................................................... (RM13-15, -14, -12) ............26Order 802: New Reliability Standard: CIP-014-1 (Physical Security)................................. (RM14-15) ...........................23Order 803: Revised Rel. Standard: PRC-005-3.................................................................... (RM14-8) .............................25Revised Reliability Standard: PRC-002-2 ............................................................................ (RM15-4) .............................23Revised Reliability Standard: PRC-004-3 ............................................................................ (RD14-14)............................21Revised Reliability Standard: PRC-005-4 ............................................................................ (RM15-9) .............................22Revised Reliability Standard: PRC-006-2 ............................................................................ (RD15-2)..............................20Revised Reliability Standard: PRC-010-1 ............................................................................ (RM15-12) ...........................22Revised Reliability Standards: CIP-003-6, CIP-004-6, CIP-006-6, CIP-007-6,

CIP-009-6, CIP-010-2, CIP-011-2 (RM15-14) ...................................................... (RM15-14) ...........................21Revised Reliability Standards: PRC-004-2.1(i)a, PRC-004-4; PRC-005-2(i),

PRC-005-3(i), VAR-002-4 (RD15-4) .................................................................... (RD15-3)..............................20Revised TOP and IRO Reliability Standards........................................................................ (RM15-16) ...........................21

XI. Misc. Regional Interest

203 Application: EquiPower/Dynegy................................................................................... (EC14-140) ..........................27203 Application: Iberdrola/UI ............................................................................................. (EC15-103) ..........................26E&P Agreement Termination: Spruce Mountain Wind ....................................................... (ER15-975) .........................29E&P Agreement Termination: Record Hill Wind ................................................................ (ER15-974) ..........................29E&P Agreement Termination: Highland Wind .................................................................... (ER15-973) ..........................29


Page I-341536280.149

E&P Agreement Termination: Patriot Renewables .............................................................. (ER15-972) ..........................29Emera MPD OATT Changes................................................................................................ (ER15-1429) ........................28Emera MPD OATT Order 676-H Compliance Filing .......................................................... (ER15-1419) ........................28EPC Agreement: Blue Sky West & Emera Maine............................................................... (ER15-1459) ........................28FERC Enforcement Action: City Power Marketing and Tsingas ......................................... (IN15-5) ...............................30FERC Enforcement Action: Maxim Power and K. Mitton................................................... (IN15-4) ...............................31FERC Enforcement Action: Powhatan Energy, HEEP Fund, CU Fund, and H. Chen ........ (IN15-3) ...............................31FirstEnergy PJM DR Complaint........................................................................................... (EL14-55) ............................27HG&E Demarcation Agreement........................................................................................... (ER15-939) ..........................29IA – CL&P/Energy Stream................................................................................................... (ER15-947) ..........................29LCC Services Agreement – NSTAR/Braintree .................................................................... (ER15-1040) ........................28LSA Termination: Emera/ Black Bear HVGW .................................................................... (ER15-962) ..........................29LVA/PSNH IA Complaint.................................................................................................... (EL15-9) ..............................27MISO Methodology to Involuntarily Allocate Costs to Entities Outside Its Control Area .. (ER11-1844) ........................30NSTAR/HQ US CMEEC Use Rights Transfer Agreement.................................................. (ER15-1383) ........................28Opinion 531-A Compliance Filing: NGrid IFA Amendments.............................................. (ER15-418) ..........................30SGIA Termination: CMP/Gallop Power Greenville............................................................. (ER15-1189) ........................28

XII. Misc: Administrative & Rulemaking Proceedings

NOPR: MBR Authorization Refinements ............................................................................ (RM14-14) ...........................35NOPR: Open Access and Priority Rights on ICIF................................................................ (RM14-11) ...........................35NOPR: Third-Party Provision of Primary Frequency Response Service.............................. (RM15-2) .............................35Order 676-H: Incorporation of WEQ Version 003 Standards .............................................. (RM05-5) .............................37Order 771: Availability of E-Tag Information to FERC Staff ............................................. (RM11-12) ...........................36Price Formation in RTO/ISO Energy & Ancillary Services Markets................................... (AD14-14) ...........................33RTO/ISO Winter 2013/14 Operations and Market Performance.......................................... (AD14-8) .............................34Technical Conferences on Implications of Environmental Regulations............................... (AD15-4) .............................32WIRES Request for Policy Statement on ROE for Electric Transmission ........................... (RM13-18) ...........................36


206 Investigation: Consistency of ISO-NE (DA) Scheduling Practices withNatural Gas Scheduling Practices to be Adopted in Docket RM14-2 ................................. (EL14-23) ..............................6Enforcement Actions: BP ..................................................................................................... (IN13-15) .............................40Inquiry Into Natural Gas Trading, and Proposal to Establish an Electronic Informationand Trading Platform............................................................................................................ (AD14-19) ...........................38New England Pipeline Proceedings...................................................................................... .............................................40NOPR: Coordination of the Scheduling Processes of Interstate Natural Gas Pipelinesand Public Utilities ............................................................................................................... (RM14-2) .............................38Posting of Offers to Purchase Capacity (Section 5 Proceeding)........................................... (RP14-442) ..........................39



XV. Federal Courts

2013/14 Winter Reliability Program and Bid Results ..........................................................14-1104 (DC Cir.)................42CPV Maryland, LLC v. PPL EnergyPlus et al. ....................................................................14-623 (Supreme Court) ......44CPV Power Development, Inc., et al. v. PPL EnergyPlus, LLC, et al. ................................14-634/694 (Supreme Ct) ....45Demand Curve Changes ......................................................................................................15-1070 (DC Cir.)) ..............42Entergy Nuclear Fitzpatrick, LLC et al v. Zibelman et al ....................................................5:15-cv-00230 (N.D.N.Y.)...46FCM Administrative Pricing Rules Complaint ....................................................................15-1071 (DC Cir.)................42FCA8 Results .......................................................................................................................14-1244 (DC Cir.)................42New England’s Order 745 Compliance Filing .....................................................................12-1306 (DC Cir.)................43Orders 745/745-A ................................................................................................................14-840 (Supreme Court) ......43Orders 773/773-A .................................................................................................................13-2316 (2nd Cir.) ...............43

SEAPORT HOTEL

FROM Points West via I-90:

Follow the Massachusetts Turnpike/Interstate 90 East to Exit 25 – South Boston. At the top of the ramp, bear left

towards Seaport Boulevard. At the first set of lights, proceed straight onto East Service Road. At the next set of

lights, take a right onto Seaport Boulevard. The Seaport Boulevard entrance to the Seaport Garage is located

ahead on the right.

FROM Points South via I-93:

Heading northbound on I-93 towards Boston, take Exit 20, which will be immediately after Exit 18. Follow the signs

to “I-90 East.” Take the first tunnel exit to "South Boston.” At the first set of lights at the top of the ramp, proceed

straight onto East Service Road. At the next set of lights, take a right onto Seaport Boulevard. The Seaport

Boulevard entrance to the Seaport Garage will be ahead on the right.

FROM Points North via I-93:

Heading southbound on Interstate 93 Boston, take Exit 23, Purchase Street and move into the left lane. At the top

of the ramp, take a left turn onto the Evelyn Moakley Bridge/Seaport Boulevard. Follow Seaport Boulevard for

approximately .8 miles, the Seaport Boulevard entrance to the Seaport Garage will be on the right, after the

Seaport Boulevard/B Street intersection.

FROM Logan International Airport and Route 1A South:

Follow the signs towards I-90 West - Ted Williams Tunnel. Take the Ted Williams Tunnel to Exit 25. At the top of

the ramp proceed straight onto B Street. Follow B Street to the end and take a right onto Seaport Boulevard. The

Seaport Boulevard entrance to the Seaport Garage will be on your right.

PUBLIC TRANSPORTATION

The MBTA Silver Line Waterfront (SL1) provides service from the WTC Station to Logan International Airport

terminals every 10 minutes during the weekday and every 15 minutes during the weekend. The Silver Line station

is located adjacent to the hotel.

Seaport Boston is about 3 miles from Logan Airport, one of several hotels near the Boston Convention Center

and a quick ride away from all Boston attractions. Taxis are readily available from the lobby of our hotel.

This scenic way to travel is a great way to avoid traffic. Hop on the water taxi shuttle at your terminal and enjoy

the ride. The stop for pick up and drop off is at the Seaport World Trade Center, directly across the street from the

Seaport hotel.