PO Box 383

Madison, CT 06443

Voice: 646-734-8768

Email: fpullaro@renew-ne.org

Web: renew-ne.org

July 31, 2020

By Electronic Mail (mwinkler@iso-ne.com)

Mariah Winkler, Chair

NEPOOL Markets Committee

ISO New England, Inc.

1 Sullivan Road

Holyoke, MA 01040

Subject: RENEW Report on FCA 16 ORTP Calculation Assumptions

Chair Winkler:

At the July 14-15, 2020, Markets Committee (MC) meeting, Concentric Energy Advisors (CEA)

and Mott MacDonald (MM) on behalf of the ISO presented more details regarding their proposed

assumptions for calculating the Offer Review Trigger Price (ORTP) and net Cost of New Entry (CONE)

values for Forward Capacity Auction 16 (FCA 16). While ISO, CEA, and MM have addressed some of

the feedback RENEW Northeast (RENEW) had previously provided, RENEW finds several flawed

assumptions still exist that significantly deviate from current market conditions for planned new clean

energy resources in the Capacity Commitment Period 2025-26.1

The accompanying report prepared by RENEW’s consultant Boreas Renewables with

contributions from Daymark Energy Advisors provides RENEW’s feedback on the ISO’s assumptions

presented at the July 14-15 MC meeting that RENEW believes require adjustment. It is paired with a

worksheet containing the analysis performed for RENEW’s July 15 presentation on implied capital costs

from recently signed offshore wind power purchase agreements and the proposed Renewable Energy

Certificate price forecast methodology.

RENEW believes several of the flawed assumptions will have significant negative effects on the

final ORTP values for clean energy technologies. They will create an unnecessary barrier to entry for

these resources when they attempt to enter the market. One example of a flawed assumption, which also

might be the most significant, is the ISO’s offshore wind capital cost input due to its having roughly

double the prevailing commercial expectation. RENEW projects this one difference in the assumed

project cost will raise the offshore wind ORTP by approximately $45/kW-month and preclude creation of

an ORTP for this technology.

RENEW’s consultants at Boreas Renewables interviewed market participants and non-market

participant developers and turbine manufacturers to verify the ISO’s assumptions against their real-world

experiences. The accompanying report contains information, including publicly available documentation,

from these interviews and RENEW’s recommendations based on them. RENEW respectfully requests the

1 The comments expressed herein represent the views of RENEW and not necessarily those of any particular

RENEW member.

Mariah Winkler, NEPOOL Markets Committee Chair

July 31, 2020

Page Two

ISO use this report and the worksheet to inform its decisions regarding the assumptions to be used in the

final ORTP calculations to make the final ORTP values accurately reflect prevailing commercial

activities.

Thank you for considering RENEW’s positions on the proposed assumptions. I stand ready to

continue this discussion prior to the next MC meeting to clarify RENEW’s recommendations in the

memo. If that continues not be an option for the ISO, I welcome the opportunity for RENEW and the ISO

with our consultants to review information after the next MC meeting.

Sincerely,

Francis Pullaro

Executive Director

Enclosures

copy: Debbie Cooke. Principal Analyst, Market Development, ISO New England Inc.

Danielle Powers, Concentric Energy Advisors

Offer Review Trigger Price Calculation Assumptions

Prepared for RENEW Northeast

July 31, 2020

Summary of Recommendations

ISO Assumption RENEW Recommendation

General

Project lifetime 20-year lifetime, no value

beyond this

25-year lifetime for onshore and

offshore wind, 30 years for

solar. In year 20 of the model,

include expected revenues from

later years net of ongoing O&M

costs, appropriately discounted.

REC Price $21.79/MWh (2025$) based on

average trading prices for 2017-

2019, escalated to 2025$

Use a broader range of years as

the basis for this assumption

rather than selectively using

only the lowest price historical

period.

Day Ahead Market Participation 50% of wind, solar offered in

DAM

ISO should provide assumptions

representative of actual market

offers by DNE Dispatchable

wind with CSOs. We expect this

to be approximately 90%.

Onshore wind production profile Monthly average 24-hour

production profile (12 total)

based on ME and NH historical

data, scaled to assumed capacity

factor

Use the hourly production time

series data for onshore wind

project(s) in a similar location

for the same time period as the

LMP data (2017-2019) created

by DNV-GL for ISO-NE, scaled

to the assumed capacity factor

Offshore wind production

profile

The onshore wind profile, scaled

to the offshore wind capacity

factor

Use the hourly offshore wind

production time series data for

the same period as the LMP data

(2017-2019) created by DNV-

GL for ISO-NE, scaled to the

assumed capacity factor

Stand-alone solar production

profile

Monthly average 24-hour

production profile (12 total)

based on MA and CT projects

Use the hourly solar production

time series data for Connecticut,

for the same period as the LMP

RENEW Memorandum on FCA 16 ORTP Calculation Assumptions 7/31/2020

RENEW Northeast 2

installed since January 2016,

scaled to assumed capacity

factor

data (2017-2019), created by

DNV-GL for ISO-NE, scaled to

the assumed capacity factor

Solar plus Storage: solar

production profile

Monthly average 24-hour

production profile (12 total)

based on MA and CT projects

installed since January 2016,

scaled to assumed capacity

factor

Use the hourly solar production

time series data for SEMA, for

the same period as the LMP data

(2017-2019), created by DNV-

GL for ISO-NE, scaled to the

assumed capacity factor

Offshore Wind

Capital Cost $5,876/kW (2019$) $2,900/kW (2019$) based on

RENEW’s analysis of recent

offshore wind PPA contracts

Project size Gross: 800 MW

Net: Not included in past

presentations

Gross: 820.5 - 840 MW

Net: 800 MW

Based on System Impact Studies

of offshore wind projects

currently in the interconnection

Queue

Onshore Wind

Location Northern NH (POI on Coos loop

near Berlin)

Central NH (south of

Whitefield) to avoid congestion

and interconnection issues

present in Northern NH

Curtailment, localized

congestion

Not included in past

presentations

Provide more detail on

congestion and curtailment

embedded in historical LMP

data and technology efficiency

factor

Interconnection Costs $7M transmission owner

interconnection facilities (new

3-breaker ring bus) + $38M

network upgrade to 25-mi of

115 kV line from Berlin to

Whitefield

Reconsider POIs with lower

interconnection costs. If POI

remains unchanged, revise

$38M upgrade cost to reflect

prior estimate of $4.5M-$6.75M

for this same upgrade.

Solar

Fixed vs Single Axis Tracking Fixed Create a separate ORTP model

for fixed solar arrays and single

axis tracking solar arrays

O&M LTSA Cost $15.77/kW-yr (2025$) $9.40/kW-yr (2025$) Based on

recent Woods Mackenzie

findings and conversations with

current NE solar developers

Battery Storage

E&AS Revenue (without FRM

including scarcity adjustment)

$2.40/kW-mo (2025$) based on

simplified, suboptimal dispatch

methodology

ISO should hire an outside firm

specializing in battery revenue

modeling to provide the battery

RENEW Memorandum on FCA 16 ORTP Calculation Assumptions 7/31/2020

RENEW Northeast 3

dispatch optimization, just as

IMM has done for FCA 15. We

would expect revenues to be

greater than $3.83/kW-mo from

EMM baseline analysis.

Major Equipment Capital Costs $677/kW (2019$) $600/kW based on recent NREL

findings on battery capital costs

Fixed O&M - Augmentation

plan

Included, but details unknown Should reflect level of battery

cycling in model. Unclear if

augmentation costs reflect the

minimal level of cycling in

ISO’s model.

Variable O&M – Augmentation

cost

Unclear what is included in

$10/MWh assumption

VOM should not include cost of

augmentation if that is already

included in fixed O&M

Solar + Battery

AC vs DC Coupling AC coupled DC coupled based on efficiency

and cost advantages

Solar DC:AC ratio 1.4 Closer to 2.0, corresponding to a

DC coupled system

Inverter rating Two 5 MW inverters One 6-7 MW inverter,

corresponding to a DC coupled

system

Battery dispatch First 10 MWh produced by solar

each day used to charge battery,

discharged in Hours Ending 18-

20

“Clipped” solar energy stored in

battery, used for reserves and

discharged for energy to make

room for upcoming clipped

energy. Energy and reserves

optimization should be

performed by same battery

revenue modeling expert as

stand-alone storage.

RENEW Memorandum on FCA 16 ORTP Calculation Assumptions 7/31/2020

RENEW Northeast 4

General

While much of our feedback is specific to a technology, there were several assumptions that are relevant

for multiple technologies.

• Project Lifetime

• REC Pricing

• Day-Ahead (DA) Market Participation

• Wind and solar production profiles

Project Lifetime

Two recently published reports1 regarding project lifetimes by Lawrence Berkeley National Laboratory

reveal that both solar and wind professionals currently anticipate project lifetimes far longer than the

ISO’s standard assumption in previous ORTP calculations of 20 years. The Berkeley Lab wind report

notes that not a single of the wind industry professional surveyed anticipates a lifetime of a project less

than 25 years, and most wind developers anticipate project lifetimes of 30 years. Of the solar industry

professionals surveyed, only 2 anticipate lifetimes less than 30 years and most anticipate lifetimes greater

than 30 years with 42% of respondents anticipating lifetimes greater than 35 years. Understanding the

ISO is limited by the Tariff to 20 years of real-dollar cash flows2, RENEW highly recommends the ISO

include a merchant tail in the twentieth year of its model of the energy revenue that a project would

receive beyond its contracted lifetime net of ongoing O&M costs.

This will ensure the ISO more fully captures the expected revenues of these projects over their projected

lifetimes and reflects the full economic value of the resources, consistent with the assumptions used by

developers making commercial commitments. RENEW understands this is a departure from past

methodology but strongly believe that this is well within the spirit of developing an accurate offer floor

price and permissible by the Tariff, which does not specify the term over which capital costs, expected

non-capacity revenue, and operating costs are to be calculated.

REC Pricing

We believe the ISO’s approach for Renewable Energy Credit (REC) price forecasting for the

recalculation of the ORTP values is unreasonable based on historic trends in REC prices and forward

trading data. ISO is proposing averaging three historic years of REC prices (2017-2019) and escalating

that number to 2025$, resulting in an assumption of $21.79/MWh (2025$). However, this does not

capture longer term REC price trends or current forward trading, and it is unlikely to predict trends in the

future. Available REC prices for the years 2015, 2016, 2020, and 2021 appear to average roughly

$40/MWh, approximately double the value from the period chosen by ISO for its analysis. Picking the

three lowest-priced years as the basis for the REC price forecast is inappropriate. If a historical period is

to be used as the basis for this assumption, a broader range of years should be used as the basis rather than

selectively using only the lowest priced historical period.

1 Lawrence Berkeley National Laboratory, “Benchmarking Anticipated Wind Project Lifetimes,” https://eta-

publications.lbl.gov/sites/default/files/wind_useful_life_report.pdf and Lawrence Berkeley National Laboratory,

“Benchmarking Utility-Scale PV Operational Expenses and Project Lifetimes,” https://eta-

publications.lbl.gov/sites/default/files/solar_life_and_opex_report.pdf 2 III.A.21.1.2.(b) Includes the following provision for the ORTP calculation: “The model looks at 20 years of real-

dollar cash flows discounted at a rate (Weighted Average Cost of Capital) consistent with that expected of a project

whose output is under contract (i.e., a contract negotiated at arm’s length between two unrelated parties).”

RENEW Memorandum on FCA 16 ORTP Calculation Assumptions 7/31/2020

RENEW Northeast 5

RENEW presented an analysis of REC pricing trends at the July MC meeting. A further explanation of

that analysis and our REC pricing recommendation is included at the end of this memo.

DA Market Participation

ISO proposed to use the same strategy for all renewable energy technologies (onshore wind, offshore

wind, solar): offer half of their generation in DA and the remaining in RT. However, beginning June 1,

2019 all DNE Dispatchable Generators with a capacity supply obligation must submit an offer into the

DA market equal to their expected generation for the next day.3

We believe that this certainly should apply to the wind projects proposed by ISO for the ORTP

calculations, but also for the solar projects which ISO has stated its intention to make DNE dispatchable

under equivalent terms well in advance of 2025. Therefore, we suggest that these projects should be

offering approximately 90% of their output in the DA markets (to account for some uncertainty in DA

forecasts) and the remaining 10% in RT. However, we encourage the ISO to look at actual market offers

and provide a reasonable assumption to CEA on an appropriate value for a project to be offering in the

DA markets. From the market pricing assumptions ISO has shared so far, we do not believe that this will

cause a large difference in the settlements that these resources receive but believe it is important to

accurately capture current market rules in these models and should be a fairly easy change to make.

Wind and Solar Production Profiles

We strongly encourage the ISO to use the hourly power production time series data created by DNV-GL

for ISO and presented by Steven Judd at the February and July 2020 Planning Advisory Committee

(PAC) meetings.4 The currently-available datasets that ISO has available in-house contain modeled

hourly historical power production between the years 2012 and 2019 for all existing onshore and offshore

wind sites as well as all currently planned offshore wind sites. The ISO has publicly posted an aggregated

data set representing the full onshore wind fleet, normalized to nameplate capability, and the full planned

offshore wind fleet, also normalized.5 In addition to this aggregate fleet data, ISO has the production time

series data for each individual onshore and offshore project that it can use internally for a project such as

this.

DNV-GL is currently expanding this existing wind dataset for ISO, to cover the years 2000-2011

(resulting in a 20 year data set) and add an aggregate, normalized solar profile for each of the eight load

zones for the same 20-year period. As of the July 22 PAC meeting, ISO expected to have these data sets

available any day.6

3 III.13.6.1.6.1. Beginning on June 1, 2019, Market Participants with DNE Dispatchable Generators with a Capacity

Supply Obligation must submit offers into the Day-Ahead Energy Market for the full amount of the resource’s

expected hourly physical capability as determined by the Market Participant. Market Participants with DNE

Dispatchable Generators having a Capacity Supply Obligation must submit offers for the Real-Time Energy Market

consistent with the characteristics of the resource. For purposes of calculating Real-Time NCPC Charges, DNE

Dispatchable Generators shall have a generation deviation of zero. 4 February ISO presentation: https://www.iso-ne.com/static-

assets/documents/2020/02/a7a_wind_power_time_series_isone.pdf

February DNV-GL presentation: https://www.iso-ne.com/static-

assets/documents/2020/02/a7b_wind_power_time_series_dnvgl.pdf

July ISO presentation: https://www.iso-ne.com/static-

assets/documents/2020/07/a4_scope_of_work_for_stochastic_time_series_modeling_for_iso.pdf 5 https://www.iso-ne.com/static-assets/documents/2020/05/2020_isone_wind_dataset_2012-2019_rev2.zip 6 Our understanding is that these data sets have been delivered to ISO prior to the date of this memo.

RENEW Memorandum on FCA 16 ORTP Calculation Assumptions 7/31/2020

RENEW Northeast 6

There are significant differences between offshore and onshore hourly wind profiles, and we encourage

ISO to look to current onshore and offshore wind measurements, forecasts, and modeled data, including

the DNV-GL datasets, for proof of this statement. We do not believe scaling onshore wind profiles to

offshore capacity factors is an appropriate method for modeling offshore wind profiles.

Finally, weather, load, and intermittent generator output are all strongly correlated. Dispatching monthly

averaged generation profiles over hourly load profiles will create a mismatch between weather conditions,

load, and output and would not accurately capture the relationship between available energy and LMPs

that would be expected from these resource types in the ORTP analysis. Instead of using a monthly

average profile, we suggest using the hourly generation profiles from the same time period as the load and

LMP profiles, scaled to the appropriate capacity factor.

We strongly encourage ISO use its existing DNV-GL data for developing both the onshore and offshore

profiles used in the ORTP calculations. When available, the DNV-GL solar profile for the Connecticut

load zone should also be used for the solar project in Windham County in the ORTP model and the solar

profile for SEMA should be used for the hybrid solar + battery project located in Bristol County, MA.

The ISO has (or will imminently have) all of these hourly profiles available in-house and it should not be

difficult to use them in this analysis.

Offshore Wind

For offshore wind specifically, we appreciated the detailed explanation and information provided by MM

at the July 14-15 MC meeting. However, we still have serious concerns with the following two items:

• Capital Costs

• Nameplate

Capital Costs

RENEW provided extensive feedback regarding capital costs both during our meeting with the ISO on

July 2 and at the MC meeting on July 14-157. RENEW explained its methodology for implying capital

cost expectations from recent PPA pricing, which is explained in further detail in this memo’s section

below on PPAs. RENEW determined the expected capital cost of the offshore wind ORTP project is

approximately $2,900/kW. The ISO’s proposed capital cost assumption of $5,876/kW is roughly double

the capital cost expectation for projects currently under development. RENEW estimates this cost

difference alone would cause an approximately $45/kW-mo difference in the final offshore wind

ORTP value. This difference will result in offshore wind not being anywhere close to receiving an

ORTP. ISO-NE has not provided enough evidence of its methodology and due diligence to justify costs

double those current offshore wind developers are expecting.

While RENEW finds many of the individual line items presented by MM to be flawed.8, Interconnection

costs are one example of line-item level benchmarking the ISO should be performing that will show the

large discrepancy between MM’s assumption and currently available data produced by ISO-NE. This

7 Previously, RENEW Northeast provided feedback to ISO’s initial assumptions presented at the June MC meeting

in a memo on June 29th with the subject line “FCA 16 ORTP Calculation Assumption Review” and on a subsequent

call with ISO, Boreas Renewables, RENEW, CEA, and MM on July 2. RENEW also gave a follow up presentation

at the July 14-15 MC meeting on offshore wind capital costs expectations in the Northeastern U.S. Markets based on

recently signed power purchase agreements (PPA) and Renewable Energy Credit (REC) pricing. 8 Though ISO has asked for feedback on the individual line items in its bottom-up model rather than feedback on the

total cost, ISO and its consultant have not provided sufficient information for stakeholders to understand what is

included in each line item, making it impossible at this time to provide further line-item level feedback.

RENEW Memorandum on FCA 16 ORTP Calculation Assumptions 7/31/2020

RENEW Northeast 7

example illustrates why current industry professionals are questioning MM’s assumptions and perhaps

why ISO-NE should question them. MM’s interconnection cost assumption of $70M does not align with

the cost estimates in the actual offshore wind interconnection studies completed by ISO-NE. The 800

MW (net) interconnection at Brayton point (QP618) studied by ISO had an interconnection cost estimate

of just $15.1M. This is precisely the location and injection level being assumed for this ORTP analysis

yet the interconnection cost assumption used in the ORTP analysis is 464% higher than the actual cost

estimate provided in the interconnection study. A further 288 MW offshore wind injection at Brayton

Point identified an additional cost of just $3.87M (QP669). Of the thirteen offshore wind projects with

interconnection studies completed by ISO, the average interconnection/upgrade cost estimate has been

$35.5M, half of ISO’s assumption. Only three of the thirteen had interconnection costs of $70M or above.

ISO has claimed its consultants have looked at current market data, but participants are struggling to

grasp what data that is. We have not found a single recent publication that indicates expected offshore

wind costs exceeding $4,000/kW, let alone $5,876/kW. The International Renewable Energy Agency9,

the Department of Energy10, NREL11, and Lazard12 all have capital cost ranges that are significantly lower

than ISO’s assumption. While we do not suggest that any one of these reports is precisely representative

of the ISO’s hypothetical project, these reports give a broad range of reasonableness for estimates of

capital costs. Even with this broad range, ISO’s assumption falls well outside expectation whereas

RENEW’s recommended assumption of $2,900/kW based on analysis of recent PPA’s falls within the

ranges reported by all four of these sources.

RENEW requests the ISO thoroughly review all assumptions MM has presented for offshore wind and

contact offshore wind developers and turbine manufacturers (or look at the latest filings with the IMM by

these same firms) to confirm the bottom-up model for the proposed project.

Accounting for Losses between Nameplate Rating of Turbines and Net Injections

As we mentioned in our June 29 memo, the offshore wind projects being planned for the MA offshore

wind lease area are oversizing their gross nameplate rating to account for losses between the turbines and

the Point of Interconnection (POI). In the June 29 memo, we pointed to QP618, QP624, and QP781 which

each had significantly larger gross nameplate values (all by more than 30 MW) than levels of net injection

at their POI’s. Two of these projects have POI injections of 800 MW, which we understand to be the

same as ISO’s intent for the hypothetical ORTP project. At the July 21, 2020 Reliability Committee

meeting, QP624 increased its gross nameplate rating to 840 MW without increasing its POI injection of

800 MW. It was confirmed at the July Reliability Committee meeting that the losses between the turbines

and the POI account for the difference between the gross and net ratings.

Of the thirteen offshore wind projects in the MA offshore lease area for which ISO has completed an

interconnection study (either a Feasibility Study or a System Impact Study)13, all but two explicitly point

9 IRENA, “Renewable Power Generation Costs in 2019,” https://www.irena.org/publications/2020/Jun/Renewable-

Power-Costs-in-2019. $2,800-3,900/kW range of costs for the largest European projects with 2019 CODs (between

400 and 600 MW) and significant cost declines expected as project sizes grow in upcoming years. 10 DOE, “2018 Offshore Wind Market Report,” https://www.energy.gov/eere/wind/downloads/2018-offshore-wind-

market-report. Range of $2,500-$4,000/kW expected between 2020 and 2030. 11 NREL, “2020 Annual Technology Baseline,” https://atb.nrel.gov/electricity/2020/data.php. Class 7 Moderate

(expected) overnight capital cost plus grid connection cost for a 2025 COD project is $3,152/kW with an

Advanced/Conservative (low/high) range of $2,835 - $3,810 (2018$). 12 Lazard, “Lazard’s Levelized Cost of Energy Analysis, Version 13.0,”

https://www.lazard.com/perspective/lcoe2019. $2,350 - $3,550/kW range of offshore wind capital cost 13 Queue positions 618/699/846, 624, 632, 669, 700, 781, 782, 791, 792, 806, 829/922, 830, 909

RENEW Memorandum on FCA 16 ORTP Calculation Assumptions 7/31/2020

RENEW Northeast 8

to a gross nameplate rating that is higher than the net injection at the POI, with the difference being

similar in magnitude to the three specific projects called out above.

In the creation of their dataset for modeled historical OSW production discussed earlier in this memo,

DNV-GL used a generic assumption of 2.5% electrical losses between the turbines and the POI. If ISO’s

intent is to have a plant capable of injecting 800 MW to the grid, consistent with current projects in the

Queue, then we suggest that the gross nameplate rating of the project should be increased by at least 20.5

MW (matching DNV-GL’s electrical loss assumption) and would encourage a 40 MW increase to match

current, similar OSW projects which have run detailed studies regarding their losses.

This is important to the analysis because the 47% offshore wind capacity factor ISO is using is applied to

the gross nameplate rating of the wind plant to determine the MWh produced. We believe the capital costs

in ISO’s model are intended to be based on the assumption that the project will use two undersea AC

cables to deliver the project’s power to the Point of Interconnection. Those cables are able to deliver

approximately 400 MW each.14 These cables along with the interconnection facilities and network

upgrades are a significant share of the capital cost of the project and must be fully utilized in order to

optimize the project’s economics. That is the reason why nominal 800 MW projects (at the Point of

Interconnection) have gross ratings of approximately 840 MW.

By assuming an 800 MW gross project rating in its ORTP model, ISO is forcing the same fixed capital

costs associated with the undersea cables, interconnection facilities, and network upgrades to be spread

across fewer MWh than if it assumed an 840 MW gross project rating (or even an 820.5 MW gross rating

if basing the number on DNV-GL’s generic loss assumption).

Onshore Wind

At the July 14-15 MC meeting, MM provided additional details regarding the location of the proposed

onshore wind project. As several participants noted at the meeting, the classification of this project as

Central NH lead us to expect an easier and less costly interconnection than the one proposed on the Coos

loop in Northern NH. Given this new information about the project location, we provide feedback on the

following items:

• Location Implications

• Curtailment

• Interconnection

Location Implications

This project is connected to a constrained part of the grid that has historically experienced localized

congestion. We believe this congestion has impacted LMP values at the local nodes on this loop. In the

dispatch model, we are unclear whether ISO is using historical LMPs at a specific node in this loop or if a

zonal LMP is being used. If nodal LMPs are being used, we are concerned that they will be lower than

those seen in other parts of the system (such as Central NH) and that this reduces the energy revenues per

MWh produced by the project. Further, we do not fully understand the dispatch model being used, but are

concerned about whether it has caused the project to be curtailed due to locally depressed LMPs. We

14 See slide 11 of the 2019 Economic Study Offshore Wind Transmission Interconnection Analysis from the May

20, 2020 PAC meeting: https://www.iso-ne.com/static-assets/documents/2020/05/osw-econstudy-

transmission-interconnection-analysis-may-2020-nonceii.pdf

RENEW Memorandum on FCA 16 ORTP Calculation Assumptions 7/31/2020

RENEW Northeast 9

suggest that a location in Central NH (south of Whitefield), as was originally proposed, would be a more

appropriate location for this ORTP project.

Curtailment

Slide 19 of the July presentation lists an “efficiency factor” of 0.834 used to adjust from the gross to the

net capacity factor. Among the losses it lists as being accounted for in this efficiency factor is “possible

curtailment (i.e., congestion on the transmission system)”. We would like to confirm whether any

curtailment was accounted for in this efficiency factor as well as whether any curtailment was seen in the

dispatch model and if so, how much.

Interconnection

To meet reliability standards in this part of the grid significant system upgrades will need to be

undertaken by the project, including the installation of a new 115 kV 3-breaker ring bus and 25 miles of

transmission line upgrades between Berlin and Whitefield, according to MM at the MC meeting on July

14-15. To fully understand the proposed interconnection, we ask that ISO provides more details on the

rationale for the interconnection process and the selection of the site location and POI, especially since we

believe that these interconnection costs raised the proposed overnight capital costs ($2,097/kW) over the

range ISO presented in June ($1,250-2,000/kW). Of the seven onshore wind projects that have had an

interconnection study completed as part of the serial study process since the beginning of 2018,15 only one

has required the rebuilding of transmission lines and therefore has had significantly higher

interconnection costs (QP641). The remaining six projects all had significantly lower interconnection

costs. Because “transmission to market was the final differentiator” for choosing NH, according to MM’s

June 10 presentation, we would like to know the other locations that were considered in CEA and MM’s

initial analysis. Projects in the Queue indicate that other areas may be more economically attractive.

Should the POI near Berlin be maintained, we would ask ISO to look more closely at the cost of

increasing the rating of the line from Berlin to Whitefield. Queue Position 280 (which withdrew from the

queue after completing its Feasibility Study), a 172 MW project with a similar Point of Interconnection,

would have required the rating of this same transmission line to be increased. That upgrade carried a cost

estimate of $4.5-$6.75M in the project’s Feasibility Study. Though the study is a bit outdated now, it is

hard to believe that the cost of this same upgrade has increased to $38M as shown on slide 20 of the July

presentation.

Solar

For the solar PV ORTP calculation, we want to expand on a suggestion we made at the July 14 MC

meeting regarding having two ORTP values (one for fixed rack and one for single-axis trackers) for solar

projects and highlight one of the cost estimates MM clarified at the July meeting.

• Fixed vs. Tracking Arrays

• O&M LTSA Costs

Fixed vs. Tracking Arrays

As we suggested at the July 14-15 MC meeting, we believe it would be appropriate to have two ORTP

values for solar projects attempting to participate in FCA 16. Based on conversations with NE developers,

we expect to see both single-axis trackers (SAT) and fixed-rack solar arrays with CODs in 2024-25 as

15 Queue positions 649, 655, 760, 555, 641, 420, and 486

RENEW Memorandum on FCA 16 ORTP Calculation Assumptions 7/31/2020

RENEW Northeast 10

well as the following two years for which this ORTP calculation will apply. Though the ISO does not see

the prevalence of fixed rack versus tracking projects in the queue based on the information collected in

the interconnection process, at least one large solar developer we have spoken with has identified that

they have only tracking projects in the queue at this point. These two types of solar arrays have significant

differences in capital costs and revenues, so much so that a single ORTP value would not be able to be

applied accurately to both technologies. We believe that, where sites with appropriate topography for

trackers is being developed in New England, trackers add about 5% to overall capital costs and O&M

costs and can increase energy production by about 10% and qualified capacity about 50%, as compared

with fixed mount arrays. We strongly encourage the ISO to reach out to multiple developers with SAT

projects in the Queue to better understand the latest costs of this technology if there are concerns with the

economic feasibility of SAT systems. We would be happy to put ISO in touch with these developers. If

there are financial reasons to not include SAT projects in the ORTP calculation process as MM has

implied in our discussions, we would appreciate a detailed cost-benefit based explanation of the reason

for this exclusion.

O&M LTSA Costs

As we suggested in our June 29 memo, we expect O&M costs associated with PV Long Term Service

Agreements (LTSA) to be between $7-11/kW-year for solar projects to be built in 2024-25. This estimate

is based on numerous discussions we have had with current NE solar developers and publicly available

resources. The figure below was taken from an article published in Greentech Media in which Wood

Mackenzie discussed their Global Solar PV Operations & Maintenance 2020 report. It suggests that

LTSA prices near $3.5-5/kW/year are currently being seen but may be too low. Full wrap contracts

(which they have estimated at $9.40/kW/year) are more representative of today’s full solar O&M costs.

Figure 1: Source: https://www.greentechmedia.com/articles/read/solar-om-shortcuts-lead-to-higher-costs-later-per-new-report

Keeping in mind these prices are for contracts signed prior to 2020, this shows a large disparity between

market pricing trends and ISO’s estimate that should reflect prices in 2024-25. If ISO believes that the

$15.77/kW/year is an appropriate value for the LTSA and ongoing maintenance costs for their solar

projects in NE, we ask that they provide a detailed explanation of why the assumed costs for 2024-25 are

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40-125% higher than contracts that have recently been signed. While we recognize that New England

O&M costs may be higher than global averages, we find it hard to believe that local O&M costs would

increase this dramatically especially since New England developers have told us that their current O&M

contract costs fall within these ranges reported by Wood Mackenzie.

Battery Storage

While we realize that the ISO has already received a significant amount of feedback regarding the battery

storage technology, we would like to highlight the following items that we believe are most critical in an

accurate battery storage ORTP value and most likely to cause significant changes in the final ORTP

calculation:

• E&AS Revenue

• Major Equipment Capital Costs

• Fixed O&M

• VOM

E&AS Revenue

We believe that ISO’s E&AS strategy and dispatch methodology vastly over-simplifies the complexity of

potential revenue opportunities for battery storage technologies and represents a fraction of what this type

of technology could earn in the current markets. We strongly encourage the ISO to look at recently filed

requests with the Internal Market Monitor (IMM) for resource-specific offer floor prices for battery

storage projects’ participation in FCA 15. There, we believe you will find many examples of real-world

battery developer strategies that predict revenues far higher than what is currently being assumed.

As another reference to look at, we would encourage you to consider the External Market Monitor’s

methodology found in their November 12, 2019 filing in FERC Docket No. ER20-308. In their analysis

they found that what they called “Approach 3” would have yielded $3.83/kW-mo of energy and

regulation market revenue. They concluded that “although we believe this estimate is a good

representation of the EAS revenues a reasonably competent ESR owner could achieve, we expect that

ESR owners could exceed these levels of EAS revenues.” This is thus a good lower-limit benchmark

against which any analysis should be compared. As the currently proposed $2.40/kW-mo E&AS value

doesn’t even come close to the EMM’s baseline, it implies that the ORTP analysis is modeling what an

incompetent ESR owner would be expected to achieve, to use the EMM’s terminology.

We highly recommend that ISO/CEA contracts with an outside firm that specializes in battery storage

revenue modeling in order to perform the battery dispatch optimization. We understand that this has been

done by the IMM in its review of offer floor price requests for FCA 15, and we believe this would

produce the most reasonable results for this ORTP recalculation process. Given the time constraints of

this process, working with the same outside vendor that the IMM is working with for FCA 15 seems like

it would be a realistic and reasonable option.

Major Equipment Capital Costs

Based on NREL’s 2020 updated report on cost projections for utility-scale battery storage16, we believe

that the ISO’s estimate for major equipment is high for projects with a COD in 2025. The figure below

comes from this report and shows costs that we believe are comparable to the “Major Equipment”

16 NREL, “Cost Projections for Utility-Scale Battery Storage: 2020 Update,”

https://www.nrel.gov/docs/fy20osti/75385.pdf

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category listed by MM in their calculation of overnight capital costs. Here we can see that a 2-hour

battery could be expected to have a capital cost of $600/kW in 2025. The ISO’s estimate of $677/kW is a

13% increase from NREL’s prediction. We request that the ISO adopt NREL’s battery capital cost

prediction for 2025 because we believe that it aligns with current market expectations of developers in

NE. While 13% may not appear significant, we believe that this difference will have a material impact on

the final ORTP value for the battery storage technology.

Figure 2: Cost Projections for 2-, 4-, and 6-hour duration batteries using the mid cost projection. Source:

https://www.nrel.gov/docs/fy20osti/75385.pdf

Fixed O&M

ISO is including augmentation in the Fixed O&M costs; however little detail has been provided on what

this augmentation plan looks like. Under the currently designed revenue model, the battery storage unit

would be primarily providing reserves and therefore not cycle frequently. This is reflected in the 5%

monthly “topping off” procedure ISO is proposing to replenish the parasitic losses from the battery sitting

fully charged. If the battery does not fully cycle frequently then it will experience less degradation than if

it was cycling daily. We want to confirm that this smaller amount of degradation is accounted for in the

fixed O&M number that ISO presented, including the duty cycle of the battery storage unit under the

current dispatch strategy.

VOM

It is our understanding from discussions with battery project developers that VOM should be used as a

dispatch model parameter but is not an actual cost to the project if augmentation is already counted in the

fixed O&M number, as is the case in the fixed O&M costs ISO has presented. VOM is typically used as a

dispatch optimization model parameter to limit the cycling of the battery in the model to avoid cycling the

battery storage unit when the unit would not achieve a certain profit margin. However, because battery

degradation is already accounted for in the fixed O&M costs, the VOM “cost” is then added back to the

model results so that augmentation costs are not double counted. From ISO’s explanation of the proposed

VOM costs at the last MC meeting it appeared that it may be inadvertently double counting the

augmentation costs by treating VOM as a true cost in its model. We ask that ISO review its augmentation

assumptions related to fixed O&M together with the VOM to make sure that they reflect a) the costs of

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the level of cycling performed by the battery in the model and b) that they do not double count these

costs.

Solar + Battery Storage

We object to the proposed configuration and dispatch of the co-located solar + battery storage project

which we believe is inconsistent with optimal project design as well as the logic ISO has provided

regarding the standalone battery revenue opportunities.

• AC vs. DC Coupling

• Battery Dispatch

AC vs. DC Coupling

We believe the configuration of this project should be changed such that the PV and battery are DC

coupled. Of the two coupling methods for co-located facilities (AC or DC), DC-coupling of battery

storage units and solar PV arrays provides significant efficiency and cost advantages over AC-coupled

facilities. In an AC-coupled facility there are losses when energy is converted from DC to AC through the

first inverter from the solar facility and then from AC to DC through the second inverter to the battery

then back from DC to AC through the second inverter again when the battery discharges. In a DC-coupled

facility the energy flows through a single inverter once when either the battery discharges or the PV

array’s energy is flowing to the system. In addition to the loss of efficiency, AC-coupled facilities require

two expensive inverters, sized to the full rated capability of each asset, as well as additional associated

interconnection equipment. Further, because the ISO’s model assumes the solar panels are rated at 140%

of the inverter rating, there will be significant “clipped” solar energy during sunny periods. This energy

can be captured by the battery storage for later discharge to the system if the PV and battery are DC

coupled but is wasted if the two are AC coupled as ISO has proposed. To take advantage of this ability to

store and later discharge the clipped solar energy, recently designed DC-coupled PV + battery projects

typically have a significantly higher DC:AC ratio, with a value of 2.0 or higher appearing to be somewhat

standard.

According to ISO’s current dispatch strategy, the battery and the solar facility would not be producing

their full capacity simultaneously. Therefore, we believe a single inverter slightly oversized to the

capacity of one of the assets (approximately 6-7MW) in a DC-coupled facility would likely provide the

best financial and technological advantage for a co-located facility. Meanwhile, the solar array and battery

storage unit can still be considered separate assets so long as they each have their own DC meters. The

only benefit we see for having an AC-coupled system with 10 MW AC of injection rights would be that

each asset would be able to fully monetize its capacity. However, we believe the cost of increasing the net

injection outweighs the minimal capacity benefit because of the low seasonal qualified capacity of the

solar project. If ISO continues to propose an AC-coupled facility we would expect a detailed explanation

of the financial and technological advantages of this configuration.

Battery Dispatch

In their explanation of their decision to have the standalone battery storage unit provide primarily

reserves, MM explained that a 2-hour battery would not be able to economically provide energy arbitrage.

However, their dispatch methodology for the battery storage unit AC-coupled to the solar facility in the

co-located project (charging on the first 10 MWh of solar production and discharging in hours ending 18-

20) is clearly energy arbitrage. The project would be foregoing the revenue from the first 10 MWh of the

solar facility (equivalent to purchasing 10 MWh of energy during a higher priced period than if it was a

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standalone battery charging in the lowest-priced hours of the day) and selling this energy at a later time

with a theoretically higher price. Because the units are AC-coupled, the battery is receiving no efficiency

benefit from being co-located with the solar facility and is losing approximately 15% of the AC PV

output due to the roundtrip efficiency of the battery, which it would need to overcome to make a profit on

storing this energy. We are wondering where the difference between the battery strategies arises and why

the ISO is justifying an energy arbitrage solution when it clearly stated that this is not a winning strategy

based on their analysis for a standalone battery unit. The only benefit we are aware of that the battery

would receive from ISO’s configuration and operational strategy as compared with a stand-alone battery

is access to the Investment Tax Credit. However, it appears to us that the ITC benefit is not sufficient to

outweigh the reduced revenues that result from the decision to configure and operate the project as

proposed. The ITC could be obtained by DC-coupling the two pieces of the project, gaining capital cost

efficiencies and significantly increased revenue opportunities in addition to the tax credit.

We believe that the dominant, optimal strategy for a battery attached to a solar project would be to DC-

couple the battery and have it store only clipped solar energy. It would then be able to provide reserves

with that stored clipped energy and discharge to provide energy at times that would be most profitable in

order to make room for capturing upcoming expected clipped energy. This would limit the cycling of the

battery, reduce costs, and increase revenues.

We would highly recommend reaching out to developers with co-located facilities in the Queue to

understand how they expect their facilities to perform and hiring a consultant to develop a battery revenue

strategy for such a hybrid project, just as we are proposing with the standalone battery storage unit. We

believe that this will result in a consistent methodology between the ISO’s technologies and accurately

reflect how a co-located facility would participate in the current markets.

Implied Offshore Wind Capital Costs based on Recent PPA Prices

Recently executed power purchase agreements (PPAs) in New England provide the best source of

information for expected offshore wind capital expenditures. They represent actual commercial

expectations and commitments that have been made for projects precisely like the hypothetical ORTP

project being modeled by ISO. As RENEW presented at the July MC meeting, Daymark Energy Advisors

created a financial model to calculate the capital expenditures implied by recent offshore wind power

purchase agreement pricing. The model is a discounted cash flow model which is designed to be

consistent with the model ISO-New England used in the 2016 ORTP calculation. Using this model, we

found that the implied capital costs for the four projects we studied fell between $2,300-$3,700/kW (in

2019$), with a weighted average of $2,900/kW. These costs are 39-62% of ISO’s estimate of $5,876/kW

(in 2019$). The weighted average is 49% of ISO’s estimate. We believe that difference between the

weighted average implied capital cost from our analysis and ISO’s capital cost assumption, will cause an

approximately $45/kW-mo difference in the final ORTP value and will be the difference between

offshore wind projects receiving and not receiving an ORTP value.

Though the Tariff requires ISO to create a bottom-up financial model, if the resulting total costs are out of

line with all indicators of prevailing total costs it indicates that the line-items in the model are not accurate

and needs to be refined. ISO should perform their own similar analysis to benchmark their capital cost

assumption against commercial arrangements being made. In addition to our PPA analysis, we have not

found a single recently published resource that suggests costs even close to $5,000/kW, let alone the

$5,876/kW value proposed by ISO. Attached to this memo we have provided the model we used to imply

project capital costs from PPA pricing. We would be happy to provide additional information on our

modeling methods if this helps ISO understand our methodology or results.

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Projects Studied

Contract pricing is publicly available for four offshore wind PPA’s for projects in New England offshore

lease areas to be built within the next five year. These four PPA’s have been included in our analysis and

are shown in the Table below:

Table 1: Offshore Wind Projects with Publicly Available Pricing

Project Capacity State

RFP

Selection

Date

COD

Expectation at

PPA Execution

First Year PPA

Price

Vineyard Wind

Tranche 1

400 MW MA May 2018 2021 $74/MWh

(Escalating

2.5% Annually)

Vineyard Wind

Tranche 2

400 MW MA May 2018 2022 $65/MWh

(Escalating

2.5% Annually)

Revolution

Wind Tranche

1

400 MW RI May 2018 2023 $98.425/MWh

(Fixed for

contract term)

Mayflower

Wind

804 MW MA October

2019

2024 $77.76/MWh

(Fixed for

contract term)

Three additional offshore wind PPA’s for projects in the same area with similar commercial operation

dates totaling 1104 MW (Park City Wind and Revolution Wind Tranches 2 and 3) have been signed as a

result of Connecticut solicitations. However the pricing for these contracts is not public. Therefore, we

did not include these projects in our analysis.

Project Life

The PPAs for these projects are all for 20-years. However, to model the developers’ expectation that these

projects have lifetimes longer than 20-years, we assumed that the projects would continue to operate for

an additional 5-years as merchant projects. This additional revenue net of O&M costs was incorporated in

our NPV analysis to determine the implied capital costs. This results in a more conservative estimate of

the implied capital costs than assuming the project is to have a NPV of zero over the 20-year contract

lifetime.

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Revenue Assumptions

There are three primary sources of revenue for offshore wind projects: energy, capacity, and renewable

energy certificates (RECs). The PPAs for all the projects were 20-year contracts for energy and RECs.

We used the contract prices for energy and RECs along with an assumed capacity factor of 47 percent to

determine revenue for the first 20-years for those products in the model. The 47 percent net capacity

factor is consistent with ISO-New England’s proposed assumption for the ORTP analysis. Beyond 20-

years, to be conservative, we assumed that the project would continue to get energy revenue by selling

that product at market rates. For the market rates, we assumed an energy value of $40/MWh in 2022,

escalated at 2% annually thereafter.

We assumed that the projects would also participate in and retain any revenue from the ISO-NE capacity

market. We used the actual qualified capacity for the Vineyard Wind Project to calculate an assumed

qualified capacity value for the other projects as shown in the table below, and assumed that each project

cleared its full qualified capacity in the FCA. We developed two capacity price assumptions: $2/kW-

Month based on the FCA 14 clearing price and $6/kW-Month based on a more optimistic view of future

capacity prices that may have been reasonable at the time these PPA bids were made. We assumed 25-

years of capacity revenue. Once again, adding a capacity revenue stream with these assumptions resulted

in a conservative estimate for the implied capital cost.

Table 2: Vineyard Wind Qualified Capacity

Project Nameplate

(MW)

Summer

Qualified

Capacity

(MW)

Summer

Qualified

Capacity as

% of

Nameplate

Winter

Qualified

Capacity

(MW)

Winter

Qualified

Capacity as %

of Nameplate

Vineyard

Wind 800 282.8 35% 522.5 65%

Investment Tax Credit

The Investment Tax Credit for offshore wind will be phased out over the next several years. Projects that

meet both construction start and commercial operation date milestones qualify for declining amounts of

the credit. We used ITC assumptions consistent with the assumed commercial operation date at the time

of each project’s bid into the state procurement. The ITC percentages assumed in the analysis were 18%

for Vineyard Wind and Revolution Wind and 12% for Mayflower Wind.

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Other Assumptions

To complete the model, we needed to make several assumptions regarding the financing and operations

and maintenance of these projects. The financing and operations and maintenance assumptions in our

model came from ISO-NE as shown in the Table below. Where ISO has shared an assumption for the

FCA 16 ORTP calculation, we used that assumption (e.g., fixed O&M costs). Where ISO has not yet

shared an assumption for the FCA 16 ORTP calculation, we used the ISO’s assumption from the 2016

calculation (e.g., After Tax WACC).

Table 3: Financing and O&M Assumptions

Assumption Estimate Source

After Tax WACC 7.29% ISO Estimate

Inflation 2% Daymark Estimate

Federal Tax Rate 21%

State Tax Rate 8%

Fixed O&M Costs $93.47/kW-year ISO Estimate

Site Lease $665/MW ISO Estimate

Insurance 0.3% of installed costs ISO Estimate

Property Tax 1% ISO Estimate

Results

The table below summarizes the results from our PPA analysis. While we do not believe these are the

exact capital costs the projects are expecting, we do believe that this analysis gives a good benchmark for

where capital costs for projects completely analogous to the project ISO has proposed for the ORTP

technology fall as indicated by the contracts that have been signed to actually finance these projects.

In this analysis we have attempted to use ISO’s assumptions wherever possible and when in doubt have

attempted to err on the side of being conservative. We ask that ISO use this data to benchmark their own

offshore wind capital cost assumption, which is currently double the weighted average costs determined

through this analysis.

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Table 4: Results from Daymark Energy Advisor’s PPA analysis to calculate implied capital costs, rounded.

Project Capacity COD

Expectation at

PPA Execution

Implied Capital

Costs ($2/kW -mo

Capacity Revenue)

(2019$)

Implied Capital

Costs ($6/kW-mo

Capacity Revenue)

(2019$)

Vineyard

Wind

Tranche 1

400 MW 2021 $3,100/kW $3,500/kW

Vineyard

Wind

Tranche 2

400 MW 2022 $2,600/kW $3,000/kW

Revolution

Wind

Tranche 1

400 MW 2023 $3,400/kW $3,700/kW

Mayflower

Wind

804 MW 2024 $2,300/kW $2,600/kW

REC Forecasting Methodology

Daymark Energy Advisors created the figure below for the July MC meeting to show trends in MA Class

I REC trading prices from the 2015 vintage year through the latest data on forward trades for vintage

years 2020 and 2021. The data is summarized further in the below table. As can be seen by the yellow

section of the figure and table which highlights the historical period used by ISO for their REC price

assumption, the three years ISO is proposing to use are the three lowest price years in the past five and a

half (the extent of the analysis performed by Daymark).

Table 5: Average REC price for each vintage during the vintage year. Source: Daymark Energy Advisors

2015 2016 2017 2018 2019 2020

$52 $36 $20 $12 $25 $38

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Figure 2: Historic REC prices. Source: Daymark Energy Advisors

Unlike the dispatch model in which it is important to use load, weather, and LMP time series data from

the same time period to capture co-dependencies between model variables, there is no similar reason for

the REC price assumption to be based on the same time period as the LMP data. REC prices were more

than double ISO’s proposed value in the two years prior to the ISO’s selected time period and have

rebounded this year to again nearly double the price during ISO’s selected period. Selectively looking at

only the lowest-priced historical period is inappropriate, as would be an assumption based on only a short

highest-priced period.

There are, unfortunately, no good options for up-to-date, publicly available MA Class I REC price

forecasts that could be used instead of this historical approach. We therefor suggest that ISO take a longer

look at historical REC pricing to determine a reasonable assumption that does not appear to selectively

use only the lowest historical pricing data.

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