Comments to FERC on the Installed Capacity Requirement: Give Consumers Value for Renewable Distributed Generation Investment

Legal Document

Dated: November 25, 2014

Posted in:

Authored by:

United States of America Before the Federal Energy Regulatory Commission

ISO New England Inc.
Docket Nos. ER15-325-000

Motion to Intervene and Comments of the New England States Committee on Electricity

Pursuant to Rules 212 and 214 of the Federal Energy Regulatory Commission’s (“Commission” or “FERC”) Rules of Practice and Procedure (the “Rules”), 18 C.F.R. §§ 385.212 and 385.214 (2014), and the Commission’s November 4, 2014 Combined Notice of Filings #1, the New England States Committee on Electricity (“NESCOE”) hereby files this Motion to Intervene and Comments in the above-captioned proceeding.

On November 4, 2014, ISO New England Inc. (“ISO-NE” or the “ISO”) filed with the Commission the Installed Capacity Requirement (“ICR”), Local Sourcing Requirements, and Hydro Quebec Interconnection Capability Credits (“HQICCs”) for the 2018/2019 Capacity Commitment Period (the “ICR Filing”).[1] The Forward Capacity Auction (“FCA”) to be held in February 2015 (“FCA 9”) is the corresponding auction for the 2018/2019 Capacity Commitment Period.[2]

NESCOE’s comments below focus on two issues it raised through the stakeholder process that are critical to calculating an accurate ICR value: (1) the need to reflect in the ICR the significant growth in New England’s renewable distributed generation (“DG”) resources, and (2) a disconnect between ISO-NE’s expectation of resource availability under the Pay-for-Performance (“PFP”) program and its resource availability assumptions for the 2018/2019 Capacity Commitment Period. NESCOE, along with many New England state government agencies and stakeholders, worked closely with ISO-NE during the development of a DG forecast to capture the increased penetration of solar photovoltaic (“PV”) resources projected to occur over the next ten years—growing, as ISO-NE describes, at “rapidly increasing rates” and driven primarily by state policies.[3] In failing to account for these increased levels of DG resources, as well as the improved resource availability that ISO-NE expects to result from PFP, the region’s power needs are overstated and consumers are exposed to potentially hundreds of millions of dollars in unnecessary costs.[4]

NESCOE does not challenge in this pleading ISO-NE’s adherence to the market rules and approved methodologies in calculating the ICR to be used for FCA 9. NESCOE is not seeking changes to the ICR values with respect to the next auction. However, NESCOE expects that assumptions used in setting the ICR for future years—beginning with FCA 10—will incorporate contributions to resource adequacy from incremental ratepayer investments in renewable DG resources and investments in improved performance that ISO-NE anticipates through the implementation of PFP. There is both sufficient time and information for ISO-NE to make the necessary market rule changes to ensure that these investments are captured in the ICR calculation going forward. Not acting on that timeframe will impose unnecessary costs on New England consumers and result in unjust and unreasonable rates. NESCOE looks forward to working with ISO-NE and interested stakeholders in developing and proposing appropriate market rule changes.

  1. Communications

Pursuant to Rule 203, 18 C.F.R. § 385.203 (2014), the person to whom correspondence, pleadings, and other papers in regard to this proceeding should be addressed and whose name is to be placed on the Commission’s official service list is designated as follows:

Jason R. Marshall
Senior Counsel
New England States Committee on Electricity
655 Longmeadow Street
Longmeadow, MA 01106
Tel: (617) 913-0342



NESCOE is the Regional State Committee for New England. It is governed by a board of managers appointed by the Governors of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont and is funded through a regional tariff that ISO-NE administers.[5] NESCOE’s mission is to represent the interests of the citizens of the New England region by advancing policies that will provide electricity at the lowest reasonable cost over the long-term, consistent with maintaining reliable service and environmental quality.

The instant proceeding has system reliability, consumer cost and environmental implications. The ICR and ICR-related values are key inputs into FCA 9, and HQICCs are an input into the ICR calculation. Like past auctions, the ICR for FCA 9 represents the amount of installed capacity to be procured in the auction and, in turn, the quantity that load-serving entities will be obligated to buy.   The setting of these key input values thus directly affects system reliability and the costs borne by New England electricity consumers.

NESCOE has a direct, immediate, and substantial interest in this proceeding, which will not be adequately represented by any other party. In addition, NESCOE’s participation in this proceeding as the representative of the New England Governors will serve the public interest. NESCOE respectfully requests leave to intervene in this matter.



  1. ISO-NE’s DG Forecast

In 2013, at the request of stakeholders and the states, ISO-NE established a Distributed Generation Forecast Working Group (the “Working Group”) to provide input to ISO-NE in quantifying the growth of DG resources and developing a methodology to forecast the installation of DG resources in the region.[6] This forecast would help to ensure that state policies and programs relative to DG resources are accurately reflected in ISO-NE’s system planning studies and resource adequacy analysis. As ISO-NE has recently stated, DG resources, in the aggregate, “are likely to make a significant impact in the load profile in New England.”[7] ISO-NE focused exclusively on solar PV resources for its first forecast because they “constitute the largest segment of DG resources throughout New England.”[8]

The New England states, DG program administrators, electric distribution companies, and other interested stakeholders have participated in the Working Group. From the inception of the Working Group, NESCOE expressed its strong commitment to support ISO-NE’s work and, along with individual states and stakeholders, has provided ISO-NE with information on existing and planned PV capacities and projections of state renewable programs and budgets over the ten-year system planning horizon. NESCOE has been acutely interested in ensuring that consumers receive appropriate value for their substantial investments in renewable DG resources.[9]

From late 2013 into 2014, ISO-NE developed an interim solar PV forecast (the “DG Forecast”).[10] The DG Forecast, finalized in April 2014, is conservative: it is discounted for both seasonal claimed capability and policy implementation uncertainty.[11] The DG Forecast projects that solar DG resources, after factoring in these discounted values, will increase in New England from roughly 175 megawatts (“MW”) in 2013 to 489 MW in 2018 and 632 MW by 2023.[12] On a going forward basis, without accurately accounting for DG resources in the load forecast, there could be hundreds of uncounted MW over the planning horizon that are installed and contributing to resource adequacy.

At the April 2, 2014 Working Group meeting at which ISO-NE presented the DG Forecast, ISO-NE stated its intention to use the forecast in transmission planning studies, proposed plan application studies, and system impact studies.[13] ISO-NE stated that it needed to defer incorporating the DG Forecast into the resource adequacy process given uncertainty around certain pending market rules and the need for guidance from FERC.[14] In September 2014, in its presentation of the 2014 RSP, ISO-NE indicated that it would use the DG Forecast in resource adequacy studies beginning in FCA 10.[15] However, the 2014 RSP as finally adopted by ISO-NE retreats from this statement. In it, ISO-NE again cites uncertain market rules as an impediment to using the forecast in resource adequacy studies and again promises to “work with stakeholders to explore how to use the DG forecast in [transmission planning analyses and economic studies] and possibly apply it to other market-related assessments . . . [such as] the development of the Installed Capacity Requirement.”[16]

  1. Implementation of PFP

In late 2012, ISO-NE began a discussion to address concerns with performance incentive components of the Forward Capacity Market (“FCM”). In an October 2012 paper, FCM Performance Incentives, ISO-NE stated that “[e]mpirical analyses of generating unit performance indicate that, at times of high system stress, a significant share of the region’s generating fleet fails to respond to ISO dispatch instructions according to their offered capabilities.”[17] Among the benefits of the PFP design noted in the paper was that it “should lead suppliers to revise their operating procedures to maximize availability . . . .”[18] As ISO-NE recently highlighted, fleet-wide forced outages began to increase from almost 4% prior to 2010 to 8.0% in 2013.[19]

ISO-NE filed its PFP program with the Commission in January 2014 to incent resource performance during defined periods of system stress.[20] In a May 30, 2014 order, the Commission approved ISO-NE’s PFP program.[21] The implementation of PFP will begin concurrent with the 2018/2019 Capacity Commitment Period, the same period over which the ICR values filed in this proceeding would apply if approved by the Commission.


NESCOE appreciates ISO-NE’s significant efforts over the past year to develop a DG Forecast. Like the forecast developed for energy efficiency resources, the DG Forecast is the product of a close and largely data driven collaboration among ISO-NE, the New England states, program administrators, electric distribution companies, and other interested parties. NESCOE looks forward to its continued work with ISO-NE and others on the DG Forecast, including integrating other DG resources into the forecast.

It is critical that the load forecast and system planning studies reflect the rapid growth of renewable DG resources, including their increasing contributions to system reliability. For example, in the context of discussions within the NEPOOL Load Forecast Committee this past July, ISO-NE is reported in meeting minutes to have stated that “solar peak load response had almost tripled in one year.”[22] Unfortunately, as described above, ISO-NE remains unclear whether it will apply the DG Forecast in resource adequacy determinations made for FCA 10, at potentially great expense to consumers if it does not. That work needs to begin today. Consumers should not pay unnecessary costs that will occur if ISO-NE delays action.

The ICR values associated with FCA 9 are fundamentally disconnected from ISO-NE’s own outlook on the New England power system in 2018. ISO-NE’s DG Forecast estimates close to 500 MW of solar PV installed by that date, a conservative number that reflects a substantial discount factor under the forecast methodology. ISO-NE’s calculation of the ICR used for FCA 9 wholly disregards the very forecast it developed, ignoring hundreds of MW of solar resources required by state policies, which ISO-NE itself tracked and verified will come online over the next three years.

In addition, while one of the purported benefits of ISO-NE’s proposed PFP program was to ensure better resource performance, the ICR value for the first year under the PFP construct, the 2018-2019 Capacity Commitment Period, fails to reflect any projected increase in resource availability resulting from this new market design. This is at odds with why ISO-NE explained the need for PFP in the first place. Consumers should not pay to strengthen financial incentives under PFP and then be forced to purchase more resources than are needed to achieve resource adequacy standards as if these strengthened incentives were not in place.

An ICR that excludes ISO-NE’s own assumptions in these two critical areas is illogical. It also adds unnecessary—and potentially substantial—costs to consumers through an over procurement of resources. While NESCOE is not challenging through this pleading whether the assumptions used for calculating the ICR are consistent with the market rules and approved methodologies, future assumptions that fail to consider the DG Forecast and the impacts of PFP on resource availability cannot be considered reasonable. Nor can resulting rates based on an ICR value that over procures resources be considered just and reasonable. The process for developing any enabling market rule changes should begin now to ensure that appropriate changes are in place in time for FCA 10.

  1. ISO-NE Is Well Aware of Concerns that NESCOE and Stakeholders Raised Regarding FCA 9 and the Need for Rule Changes


In its ICR Filing, ISO-NE states that one of NESCOE’s responsibilities is to provide feedback on the ICR through the NEPOOL stakeholder process and that NESCOE was “in attendance for the meetings in which the ICR-Related Values for the 2018/2019 Capacity Commitment Period’s FCA were discussed.”[23] This description may leave the mistaken impression with the Commission that NESCOE was silent through the NEPOOL process and only now raises concerns about the ICR values that are the subject of this proceeding. In fact, NESCOE stated its point of view on this important matter at the NEPOOL Power Supply Planning Committee, Reliability Committee, and Participants Committee. At these stakeholder meetings, NESCOE expressed the very same concerns regarding the DG Forecast that NESCOE repeatedly articulated during its participation in the Working Group.

At the October 3, 2014 NEPOOL Participants Committee, where NEPOOL was asked to vote on the proposed ICR values, NESCOE provided the following observations about the ICR to be used for FCA 9 and changes that should be made in time for FCA 10:

While the [ICR] calculations conform to the market rules, ISO-NE’s proposed ICR for FCA9 is higher than it should be. A[t] least two issues – assumed generator availability and distributed generation – must be addressed to arrive at an accurate ICR value.


. . . . Pursuant to the market rule, ISO-NE calculates generator availability on a 5-year historic average basis.  The average generator availability has dropped annually.  ISO-NE indicated in its presentation to the Reliability Committee that it is increasing the ICR for FCA9 by 178 MW over that in FCA8, which also saw a large increase from the prior year, because of decreased generator availability. However, in the commitment period for which ISO-NE is purchasing, [PFP] will be in place, and ISO-NE has stated that [PFP] will result in increased generator availability.  There is accordingly a disconnect between the assumed generator availability that ISO-NE is using in the ICR calculation and the improved generator availability ISO-NE says [PFP] will deliver – and what consumers are paying for – in the commitment period. The disconnect will result in consumers over-purchasing resources to meet the ICR.


. . . . ISO-NE’s ICR calculation ignores its interim, conservative forecast of hundreds of MWs of solar PV projected to come on-line in the next three years. ISO-NE’s forecast includes small net-metered installations and MW-sized resources, all of which have benefited from state policies and programs. By excluding these resources from the three-year forward ICR calculation, consumers are paying for unneeded future capacity. Further, as noted at the recent [Working Group] meeting, by accounting only for currently installed and operating solar PV resources as load reducers, the forecast undervalues their contribution to reducing load in the interim until finally almost “catching up” ten years out (far beyond the commitment associated with the next FCA auction).


Over the past year, NESCOE and states have repeatedly raised the issue of using the DG forecast to accurately determine the ICR value. In the past month, ISO-NE indicated market rules are a barrier. At the last [Working Group] meeting, ISO-NE also stated that its preferred solution is to have individual DG resources – including 10 kW residential net metered projects – go through the FCA qualification process.


The market rules must take a realistic approach to including DG in the ICR. Without that change, consumers will over-procure capacity at a significant cost and there will be an increasing disconnect between the operative market rules and just and reasonable market rules that provide accurate and appropriate signals to the market.


NESCOE understands ISO-NE’s calculations conform to the market rules and restates these observations to suggest that ISO-NE, NEPOOL and the states need to work on changes to the market rules before ISO-NE determines the ICR for FCA10 and also examine potential modifications to the Annual Reconfiguration Auctions to address the current issues.[[24]]

A number of stakeholders expressed similar concerns at the Participants Committee meeting about the failure of the ICR calculation to sufficiently reflect DG resources.[25]   The Participants Committee did not support the proposed ICR values, with only 38.61% voting in favor.[26]

At the September 16, 2014 Reliability Committee meeting, NESCOE stated that:

[W]hile . . . it is too late in the timeline to include DG values for FCA 9. . . by not including the DG coming to the region in the next several years, [New England] will be over purchasing ICR for FCA 9. This should be addressed for FCA 10.[27]


NESCOE also stated that “with the advent of [PFP], the rolling availability average . . . will be changing and this should be considered as well for FCA 10.”[28] Several stakeholders agreed with NESCOE’s comments, with at least one entity expressing that it would vote against supporting the ICR value and another indicating that it would abstain because of the concerns.[29]

Throughout the development of the DG Forecast in 2013-2014, NESCOE repeatedly underscored the importance of considering the growing penetration of DG resources in resource adequacy determinations. For example, in a June 13, 2014 letter, NESCOE urged ISO-NE to use the DG Forecast “in the nearest possible term” in needs assessments undertaken in the transmission planning process and in calculating the ICR value.[30] The letter describes the implications for consumers if the forecast failed to account for the increased installation of solar MW on the system and seeks to understand how to address any continued reservations ISO-NE may have about applying the forecast to resource adequacy analyses.

Less than two months later, NESCOE communicated to ISO-NE its support for use of the DG Forecast in transmission planning studies, but noted concerns about the level of installed PV captured in the forecast values, noting that “[u]nderstating the impact of solar PV growth will lead to overly conservative planning and reliability analyses, thereby increasing the overall consumer costs unnecessarily.”[31] Even before the first meeting of the Working Group in 2013, NESCOE signaled the importance of the potential for the forecast to reduce the ICR in future FCAs.[32] NESCOE stated that this benefit, among others, was critical in “achiev[ing] for consumers the full range of benefits from distributed generation[.]”[33]

  1. The Process of Developing Any Needed Rule Changes Should Begin Now to Ensure that the Significant Growth of DG Resources in Future Capacity Commitment Periods Is Reflected in the ICR Calculation and ISO-NE Should Additionally Consider the Impacts of PFP on Resource Availability


NESCOE appreciates ISO-NE’s commitment to using the DG Forecast in transmission planning studies and economic studies. ISO-NE needs to take the additional and critical step of using the forecast in resource adequacy determinations beginning with FCA 10. It is unclear why the desire for greater certainty around changing market rules that relate to resource adequacy should impede the application of predicted DG growth to the load forecast. To the extent there are concerns about overestimating the amount of solar PV projected to come online—even despite the substantial discount factor applied—that issue should be addressed in the DG Forecast methodology. It should not serve as an absolute bar to integrating the forecast, continuing a fiction that, outside of the resources reflected in the FCM, zero incremental solar MW will be installed in the future.

To ensure that any necessary changes are in place by FCA 10, at the Reliability Committee on November 19, 2014, NESCOE initiated the process of introducing through the stakeholder process appropriate market rule revisions to integrate the DG Forecast into the load forecast for the 2019-2020 Capacity Commitment Period and beyond. NESCOE will work with ISO-NE and stakeholders in developing and refining its proposal.

ISO-NE should at the same time begin refining its analysis of resource availability to consider the effects of PFP’s implementation in the FCM. Any improved resource availability that is assumed under the PFP construct needs to be reflected through reductions in ICR calculations. Consumers should get the full benefits of their investments in improved performance in the year in which they pay for the improved performance. Alternatively, ISO-NE should explain why it now expects that the PFP program will not affect resource availability.


For the reasons stated herein, NESCOE respectfully requests that the Commission (i) grant its Motion to Intervene, and (ii) consider the above comments in this proceeding.

Respectfully submitted,

/s/ Jason R. Marshall
Jason R. Marshall
Senior Counsel
New England States Committee on Electricity
655 Longmeadow Street
Longmeadow, MA 01106
Tel: (617) 913-0342

Date: November 25, 2014


[1]           Capitalized terms not defined in this filing are intended to have the meaning given to such terms in the ISO-NE Transmission, Markets and Services Tariff (the “Tariff”).

[2]           ICR Filing at 1.

[3]           ISO-NE, 2014 Regional System Plan (“2014 RSP”), at 48, available at

[4]           As NESCOE explained in a June 13, 2014 letter to ISO-NE (“June 2014 Letter”), at 1-2, available at

When ISO-NE determines the ICR, the amount of MW to be procured in the Forward Capacity Auction, each incremental MW increases consumer cost and depending on the MW increase, could increase the price paid to all other MW procured. If ISO-NE does not reduce ICR by the MW in the [forecast of DG growth], consumers could pay millions of dollars of additional – and perhaps unnecessary – costs. While these costs be could contingent on a variety of competitive risks, market perception, and economic variables, they could range from [annual costs of] $100 million to over $1 billion [.]

[5]           ISO New England Inc., 121 FERC ¶ 61,105 (2007).

[6]           See generally ISO-NE, Distributed Generation Forecast Working Group, at

[7]           ISO-NE, Final Comments on the U.S. Department of Energy Quadrennial Review (QER), Oct. 10, 2014 (“QER Comments”), at 5, available at

[8]           2014 RSP at 48.

[9]           See, e.g., NESCOE, Letter to Don Gates, Chair, ISO-NE Planning Advisory Committee, Sept. 27, 2013, at 1-2 (“September 2013 Letter”), available at (“NESCOE’s aim while participating in the [Working Group] will be to fully account for the megawatts of distributed generation . . . to achieve for consumers the full range of benefits from distributed generation—benefits which include potentially reducing megawatts purchased in future forward capacity auctions and eliminating or deferring some future investments in transmission and other infrastructure.”).

[10]          ISO-NE focused exclusively on solar PV resources for its first forecast because they “constitute the largest segment of DG resources throughout New England.” 2014 RSP at 48.

[11]          ISO-NE, 2014 Interim Forecast of Solar Photovoltaic (PV) Resources, Apr. 2014 (“Final PV Forecast”), available at NESCOE has expressed several concerns regarding the forecast methodology that could result in significantly less forecasted PV over the ten-year period. These include the discount factor level and an adjustment that ISO-NE appeared to make to the methodology subsequent to its presentation of the final forecast, whereby installed PV would only apply to future years and existing PV would be discounted to zero. See NESCOE, Comments on ISO-NE Draft Interim PV Forecast, Jan. 7, 2014, available at; NESCOE, Comments on Use of PV Forecast presented at July 11 DGFWG, Aug. 1, 2014 (“August 2014 Comments”), available at

[12]          Final PV Forecast at Slide 24. For 2023, the nameplate capacity value would be approximately 1,800 MW. See QER Comments at 6.

[13]          ISO-NE, Update: Use of DG Forecast and Interconnection Issue, Distributed Generation Forecast Working Group, Apr. 2, 2014, at Slide 3, available at

[14]          Id. at Slide 4.

[15]          ISO-NE, 2014 Regional System (RSP): 2014 Public Meeting, Sept. 11, 2014, at Slide 11, available at

[16]          2014 RSP at 52.

[17]         ISO-NE, FCM Performance Incentives, Oct. 2012, at 1, available at

[18]         Id. at 4.

[19]          ISO-NE, Meeting Natural Gas Electric Interdependency Challenges Through Market Enhancements, U.S. Department of Energy’s Electricity Advisory Committee, Sept. 25, 2014, at Slide 4, available at

[20]          See, e.g., ISO New England Inc. and New England Power Pool, Order on Tariff Filing and Instituting Section 206 Proceeding, 147 FERC ¶ 61,172 (May 30, 2014) (“PFP Order”), at PP 3-7, 29, 36; QER Comments at 4.

[21]          See generally PFP Order.

[22]          Draft Minutes of the NEPOOL Load Forecast Committee, Meeting No. 77, July 17, 2014, at 1 (comments of D. Ehrlich), available at

[23]          ICR Filing at 6 (footnote omitted).

[24]          NESCOE’s complete statement is available at

[25]          See, e.g., Minutes of October 3, 2014 NEPOOL Participants Committee Meeting, at 3345, available at

[26]          Id. at 3346. As ISO-NE notes, the HQICCs were part of the consent agenda and received NEPOOL support. ICR Filing at 16.

[27]          Minutes of the Reliability Committee Meeting, Sept. 16, 2014, at 5 (describing comments of Dorothy Capra, Director of Regulatory Affairs, NESCOE), available at

[28]          Id.

[29]          Id. (describing comments of VELCO, VEPSA, and United Illuminating).

[30]          June 2014 Letter at 1.

[31]          August 2014 Comments at 3.

[32]          September 2013 letter at 2.

[33]          Id. at 1-2.