Sustainable Energy Advantage, LLC
i
Table of Contents
1 Executive Summary ......................................................................................................................................................... 1
2 Introduction..................................................................................................................................................................... 3
2.1 LD 327 Reporting Requirements ............................................................................................................................ 4
2.2 General Approach & Data Sources ......................................................................................................................... 4
2.3 Components Included in the Cost / Benefit Analysis ............................................................................................. 5
2.4 Choosing a Perspective for the Net Benefits Analysis ............................................................................................ 6
3 Detailed Approach to Modeling ...................................................................................................................................... 6
3.1 General Issues and Approach ................................................................................................................................. 6
3.2 AESC Inputs ............................................................................................................................................................ 8
3.3 Quantification of Program MW and MWh ............................................................................................................. 9
3.4 Revenue from Energy Resale ................................................................................................................................. 9
3.5 Capacity Buyout Revenue .................................................................................................................................... 10
3.6 Uncleared Capacity .............................................................................................................................................. 10
3.7 Reduced Share of Capacity Costs ......................................................................................................................... 11
3.8 Transmission and Distribution Benefits ............................................................................................................... 12
3.8.1 Avoided Transmission and Distribution Investments .................................................................................... 12
3.8.2 Avoided Maine Regional Network Service Share ........................................................................................... 13
3.8.3 Avoided Transmission and Distribution Line Losses ...................................................................................... 13
3.8.4 Transmission And Distribution Upgrades Funded by NEB Customers ........................................................... 14
3.9 Demand Reduction Induced Price Effects (DRIPE) ............................................................................................... 15
3.10 Renewable Energy Certificate (REC) Price Suppression ....................................................................................... 15
3.11 REC revenue ......................................................................................................................................................... 16
3.12 Reduced RPS Requirements ................................................................................................................................. 16
3.13 Societal Benefits from Greenhouse Gas Reduction ............................................................................................. 17
3.14 Avoided Environmental Compliance Costs .......................................................................................................... 18
3.15 Modeling Cost Components ................................................................................................................................. 18
4 Results and Findings ...................................................................................................................................................... 20
4.1 General Societal Perspective ................................................................................................................................ 20
4.2 Quantification of REC Revenue ............................................................................................................................ 23
4.3 Sensitivity Analysis of Maine Societal and Ratepayer Impact Perspectives ......................................................... 24
Sustainable Energy Advantage, LLC
ii
5 Maine Solar Energy Development and Basic Solar Energy Market Trends .................................................................... 26
A Appendix A – Component-level Results ........................................................................................................................ A-1
A.1 Solar Programs (2023) – Societal Perspective ..................................................................................................... A-1
A.2 Solar Programs (2023) – Maine Perspective ....................................................................................................... A-3
A.3 Solar Programs (2023) – Ratepayer Perspective ................................................................................................. A-5
Sustainable Energy Advantage, LLC
1
1 Executive Summary
In 2023, L.D. 327 “An Act to Provide Maine Ratepayers with Equitable Access to Interconnection of Distributed Generation
Resources” was enacted (the Act).
1
The Act directs the Maine Public Utilities Commission (Commission) to provide annually,
by January 1
st
, a summary report of its findings under 35-A M.R.S. § 3473(1) to the Committee on Energy, Utilities and
Technology (Committee). The Committee was notified that the report for calendar year 2023 would be submitted at the
same time as the report due pursuant to LD 1986 (Public Law 2023, ch. 411).
The Act requires the Commission to monitor the level of solar energy development in Maine in relation to the goals set
forth in 35-A M.R.S. § 3474
2
, as well as the basic trends in solar energy markets, and the relative costs and benefits from
solar energy development, including but not limited to:
A. Revenue from the sale of renewable energy credits;
B. Societal benefits through avoided greenhouse gas emissions;
C. Reduced electricity prices; and
D. Avoided or reduced costs associated with:
(1) Electricity capacity requirements;
(2) Environmental compliance requirements;
(3) Portfolio requirements established in section 3210;
(4) Renewable energy credit price suppression; and
(5) Electricity transmission and distribution costs.
The Commission has engaged Sustainable Energy Advantage, LLC (SEA) for consulting services to conduct an in-depth,
structured, and comprehensive analysis of Maine’s solar energy development for calendar year 2023. This document
describes SEA’s methodology and quantification of the basic trends in the solar markets in calendar year 2023 and the
relative cost and benefits of Maine solar installations for projects during the 2023 calendar year within three electric
distribution companies (EDCs) service territories.
• Central Maine Power (CMP);
• Versant Power - Bangor Hydro District (Versant-BHD); and,
• Versant Power - Maine Public District (Versant-MPD).
Leveraging both public, soon to be public and confidential data sources, including the most recent relevant publicly available
New England regional avoided energy supply cost study, SEA quantified the benefits and costs of Maine’s solar energy
development for calendar year 2023. A graphical summary of the analysis provided in Figure 1 and a tabular summary in
Table 1. Importantly (and with more detail provided in Section 2.4), unless otherwise stated explicitly, the analysis takes a
general societal impact perspective (versus, for example, a ratepayer impact perspective).
1
See Public Law 2023, ch. 307 http://www.mainelegislature.org/legis/bills/getPDF.asp?paper=SP0148&item=3&snum=131
2
See https://www.mainelegislature.org/legis/statutes/35-a/title35-Asec3474.html
Sustainable Energy Advantage, LLC
2
Figure 1 –
Maine’s Calendar Year 2023 Solar Energy Development Summary Costs & Benefits in Millions
of Dollars
Table 1 -
Maine’s Calendar Year 2023 Solar Energy Development Summary Costs & Benefits in Millions
of Dollars
Benefit / Cost Category
Costs
Benefits
Program Expense
$103.76
N/A
RPS Cost Reductions
N/A
$26.37
Energy Resale Revenue
N/A
$13.30
Energy Price Suppression
N/A
$27.72
Capacity Benefits
N/A
$0.80
Transmission and Distribution (T&D)
Benefits
N/A
$35.46
GHG and Environmental Benefits
N/A
$38.09
Totals
$103.76
$141.74
SEA calculates that in calendar year 2023 program expenses for solar projects were $103.76 million and the program
benefits for solar projects were $141.74 million. Note that these numbers include the cost and expenses for all NEB and
renewable procurement solar projects operating in 2023. Thus, the impact of projects as old as 1994 are included in the
analysis.
Sustainable Energy Advantage, LLC
3
These results were based on recent large increases in the growth of the NEB program and to a lesser extent the renewable
procurements (see Figure 2) which ended calendar year 2023 with installed capacity of 618.3 and 77.3 MW
AC
respectively.
Likely drivers of the growth included the open-ended structure of the NEB program (i.e., no MW cap) with a large
addressable market and favorable economics; this occurred even with the headwinds of a difficult interconnection
environment.
Figure 2 –
Incremental Maine Solar Development by Calendar Year and Program Type
2 Introduction
In 2023, L.D. 327 “An Act to Provide Maine Ratepayers with Equitable Access to Interconnection of Distributed Generation
Resources” was enacted (the Act).
3
The Act directs the Maine Public Utilities Commission (Commission) to provide annually,
by January 1
st
, a summary report of its findings under 35-A M.R.S. § 3473(1) to the Committee on Energy, Utilities and
Technology (Committee). The Committee was notified that the report for calendar year 2023 would be submitted at the
same time as the report due pursuant to LD 1986 (Public Law 2023, ch. 411).
The Commission has engaged Sustainable Energy Advantage, LLC (SEA) for consulting services to conduct an in-depth,
structured, and comprehensive analysis of Maine’s solar energy development for calendar year 2023. This document
describes SEA’s methodology and quantification of the basic trends in the solar markets in calendar year 2023 and the
relative cost and benefits of Maine solar installations for projects during the 2023 calendar year within three electric
distribution companies (EDCs) service territories.
• Central Maine Power (CMP);
• Versant Power - Bangor Hydro District (Versant-BHD); and,
3
See Public Law 2023, ch. 307 http://www.mainelegislature.org/legis/bills/getPDF.asp?paper=SP0148&item=3&snum=131
Sustainable Energy Advantage, LLC
4
• Versant Power - Maine Public District (Versant-MPD).
2.1 LD 327 Reporting Requirements
The Act requires the Commission to monitor the level of solar energy development in Maine in relation to the goals set
forth in 35-A M.R.S. § 3474
4
, as well as the basic trends in solar energy markets, and the relative costs and benefits from
solar energy development, including but not limited to:
A. Revenue from the sale of renewable energy credits;
B. Societal benefits through avoided greenhouse gas emissions;
C. Reduced electricity prices; and
D. Avoided or reduced costs associated with:
(1) Electricity capacity requirements;
(2) Environmental compliance requirements;
(3) Portfolio requirements established in section 3210;
(4) Renewable energy credit price suppression; and
(5) Electricity transmission and distribution costs.
We observe that the statutory reporting requirements listed above in this subsection notably do not include project sponsor
costs (i.e., the costs to develop, install and maintain a solar project). As such we infer that the requested cost / benefit
analysis was from a programmatic basis perspective (versus a project sponsor basis). More detail on analysis perspective is
provided in Section 2.4.
2.2 General Approach & Data Sources
SEA has endeavored to conduct a detailed, bottom-up analysis practicable within the legislatively mandated schedule and
data constraints. As such, in coordination with the Commission, SEA conducted a comprehensive review of publicly available
data to support the legislatively mandated analysis. A majority of modeling inputs, if not available through historic data,
were taken from the 2021 Avoided Energy Supply Costs in New England (AESC) study. Much of the non-AESC sourced data
to support this analysis is collected by the two EDCs and then reported to the Commission in both publicly available and
confidential formats. SEA, via the Commission, requested and worked collaboratively with the EDCs to access data to
support the analysis herein. We note the following data was incorporated into this analysis.
• Some data leveraged are currently publicly available. For example, data from the
o AESC 2021 study;
o CMP and Versant monthly NEB reports (see Docket 2020-00199);
o January and February 2023 monthly data from EDC’s stranded cost filings (e.g., Docket 2023-00039, Filing
#2 of March 31, 2023, and Docket 2023-00076, Filing #2 of March 31, 2023).
• Some data leveraged will become publicly available. For example, March through December 2023 monthly data
that will be submitted as a component of the spring 2024 EDC stranded cost filings, expected to be submitted on
or about April 1, 2024.
5
4
See https://www.mainelegislature.org/legis/statutes/35-a/title35-Asec3474.html
5
We note that these data will be subject to an adjudicatory proceeding at the Commission, which has yet to occur at the time of writing.
Sustainable Energy Advantage, LLC
5
• Some data are confidential and will remain so per SEA’s non-disclosure agreement with the EDCs. For example,
hourly production data for individual projects. As applicable, SEA aggregates data reported to respect
confidentiality.
2.3 Components Included in the Cost / Benefit Analysis
In Table 2 we detail our approach to quantifying the costs and benefits for solar projects for calendar year 2023 for each of
the following components organized by the legislatively mandated net benefit categories presented in Section 2.1.
Table 2 –
Adopted Benefits by Legislatively Mandated Benefit Category
Legislatively Mandated Benefit Category
SEA Adopted Benefit Category
Revenue from the sale of renewable energy credits
Revenue from the sale of renewable energy certificates
(RECs). We note that this benefit was quantified separately
from other benefits, as it is not a benefit transferred to the
EDC through contracts for projects operational in 2023.
Societal benefits through avoided greenhouse gas
emissions
Societal Benefits from Greenhouse Gas (GHG) Reduction
Reduced electricity prices
SEA quantified the following benefits associated with
reduced electricity prices:
• Energy Resale Revenue
• Energy Demand reduction induced price effects
(DRIPE)
• Cross-Fuel DRIPE
Avoided or reduced costs associated with electricity
capacity requirements
SEA quantified the following benefits associated with
recued capacity costs:
• Capacity Buyout Revenue
• Uncleared Capacity Value
• Capacity DRIPE
• Reduced Share of Capacity Costs
Avoided or reduced costs associated with
environmental compliance requirements
Avoided Environmental Compliance Costs
Avoided or reduced costs associated with portfolio
requirements established in section 3210
Avoided/Reduced Costs Associated with RPS Requirements
Avoided or reduced costs associated with renewable
energy credit price suppression
REC price suppression
Avoided or reduced costs associated with electricity
transmission and distribution (T&D) costs
SEA quantified the following benefits related to reduced
T&D costs:
• Avoided Transmission Upgrades
• Avoided Distribution Upgrades
• Avoided Transmission and Distribution Line Losses
• T&D plant extensions or upgrades funded by solar
project sponsors
Sustainable Energy Advantage, LLC
6
2.4 Choosing a Perspective for the Net Benefits Analysis
While the Act prescribed many aspects of the required annual report (as summarized in Section 2.1), it did not prescribe
the perspective of the net benefit analysis. Examples of perspectives that have been applied to related energy efficiency
evaluation analyses can be found here, but importantly for this analysis the question is whether to take:
• A ratepayer impact perspective,
• A general societal impact perspective; or
• A Maine only societal impact perspective
Given that the Act requires the consideration of GHG benefits, a general societal impact perspective is justified in that GHG
benefits relate to the global impact of emissions, as opposed to impacts specific to Maine or, more specifically, Maine
ratepayers.
A Maine-only societal impact perspective also could be justified, in that some benefits (e.g., NEB projects that lower Maine’s
ISO-NE coincident peak demand, and thus lower its share of ISO-NE Regional Network Service transmission costs allocated
to Maine ratepayers) would be included in such a perspective.
Importantly, the general societal impact perspective of solar project net benefits analysis does not include benefits from
the reduction of Maine’s ISO-NE coincident peak demand costs, as such a perspective views such reductions as a cost shift
from Maine ratepayers to ratepayers of other New England states and so are netted out to zero. Conversely, a Maine-only
societal impact perspective does not include energy price suppression impacts experienced by other states in ISO-NE.
Given the above considerations, for this report we have decided to primarily take a general societal impact perspective. As
such, all our base analysis is conducted from this perspective. Nonetheless, in Section 4.3 we provide a sensitivity analysis
of the Maine-only societal impact perspective in addition to the ratepayer impact perspective as compared to the general
societal impact perspective for a subset of our analysis.
3 Detailed Approach to Modeling
3.1 General Issues and Approach
The Act requires an analysis of all program-supported solar development. The two programs supporting development
assessed in this analysis are:
• The Net Energy Billing (NEB) Program – The NEB program, in its current form, functions like a combination of a net
metering program and a virtual net metering program open to distributed generation 5 MW
AC
and under; and
• Renewable Procurements – SEA’s analysis focused on projects in operation in 2023. A majority of such projects
were selected in a 2015 procurement pursuant to 35-A M.R.S. §3210-C and Chapter 316 of the Commission’s rules.
A single project was selected through the community based renewable energy pilot program pursuant to 35-A
M.R.S. §3602 and Chapter 325 of the Commission’s rules. These procurements involve competitive bidding for
distributed and utility-scale renewable energy. Notably, the procurements do not necessarily require RECs to be
included as a product taken title to by the EDC via a resulting Power Purchase Agreement (PPA).
Our analysis considered many of the idiosyncrasies of the NEB program and the Maine electricity landscape, which included:
Sustainable Energy Advantage, LLC
7
• While most of Maine (~95% of Maine’s load)
6
is within the Independent System Operator – New England (ISO-NE)
footprint including CMP and Versant-BHD, Versant-MPD (~5% of Maine’s load) is within the Northern Maine
Independent System Administrator (NMISA) footprint for which there is no comprehensive, publicly available,
regional avoided energy supply cost study, as AESC only covers ISO-NE. At times we adapt ISO-NE analysis to apply
to the Versant-MPD service territory.
• Several considerations are specific to the NEB program. First, the NEB program is comprised of two program
variants:
o kWh Credit program, which provides kWh credits on the EDC electric bills of program participants. The kWh
Credit program existed for years prior to the expansion of the NEB program to include the Tariff Rate
program variant, with generators online as early as 1994. The kWh Credit program is largely dominated by
solar photovoltaic (PV) projects but contains some quantity of non-solar generators. Given the dominance
of solar PV in the program, and the expectation that solar PV will constitute the vast majority of installations
going forward, SEA chose to focus exclusively on the benefits and costs of solar PV in the kWh Credit
program.
o Tariff Rate program, which provides monetary credits. Tariff Rate projects include non-solar projects. To
produce results for only solar projects, SEA designated the technology of each project for the purposes of
categorizing project-level data by technology. For aggregated program-wide data (e.g., program costs),
values were assigned by technology based on the share of production contributed by each technology for
each EDCs. For context, the SEA’s analysis considered all operational Tariff Rate projects, including non-
solar projects. The Tariff Rate program variant itself has two variants.
▪ The original Tariff Rate program where the monetary credits are calculated as a function of the
retail rates set at the beginning of each calendar year.
7
▪ The alternative Tariff Rate program where the monetary credits are set as a fixed 2.25% annual
inflator applied to the 2020 original Tariff Rate program rates. The alternative Tariff Rate is
applicable to projects failing to meet certain milestone requirements and represents 42 MW of
operational capacity as of end-of-year 2023.
8
o NEB Program generators either can be electrically connected with an EDC customer’s load and, from a
utility’s perspective, behind the EDC customer’s revenue meter (i.e., behind-the-meter or BTM) and thus
physically offsetting some or all the electricity that would have been consumed from the EDC’s distribution
grid without the program generator. Alternatively, program generators can be connected not with an EDC
customer’s load, with the only electrical load being the requirements of the project itself (e.g., project
lighting, inverters, communications); this load is called (project) parasitic load. If a NEB project only has
parasitic load, it is electrically connected (from the EDC’s perspective) in front-of-the-meter (FTM). This
detail is relevant here because, while the EDCs meter the total project output for FTM projects (as the
parasitic load is typically miniscule compared to gross project electricity production), the EDCs do not meter
the production of BTM NEB projects (though they do measure the input and output channels with their
metering and are able to calculate net consumption). As a result, our analysis and quantification approach
differs for FTM vs. BTM NEB projects. Specifically, we have confirmed with the EDCs that it is reasonable to
assume all Tariff Rate projects are FTM and that kWh Credit projects are a mix of FTM (e.g., community
solar projects) and BTM (e.g., residential household solar).
6
See the “Load” tab of https://www.maine.gov/mpuc/sites/maine.gov.mpuc/files/inline-
files/Standard%20Offer%20Migration%20Stats%20through%20Nov%202023.xls to make the calculation.
7
See 35-A MRSA §3209-B(5)(A), here: https://www.mainelegislature.org/legis/statutes/35-a/title35-Asec3209-B.html
8
See 35-A MRSA §3209-B(5)(A-1), here: https://www.mainelegislature.org/legis/statutes/35-a/title35-Asec3209-B.html
Sustainable Energy Advantage, LLC
8
• Renewable procurements generally select larger resources as compared to the NEB program. As such, SEA assumed
that such facilities are transmission-connected (as opposed to NEB projects which are assumed to be distribution-
connected). This assumption has implications for the calculation of T&D benefits, as discussed in various sections
below. In addition, projects may or may not include the sale of RECs to the EDC under PPAs. However, it is SEA’s
understanding that none of the selected solar projects operational in 2023 included the sale of RECs to the utility.
As such, REC revenue was not included in the benefit stack for such projects (but is discussed separately, see Section
Quantification of REC Revenue4.2).
In addition to the program-specific considerations described above, SEA considered several general methodological
decisions relating to cost benefit analyses of DG programs. The most significant consideration is if economic development
benefits should be considered in the analysis. SEA decided not to include economic development benefits because the
consideration of such benefits was not required by statute and because prior cost-benefit analysis of the NEB program
conducted by Synapse Energy Economics and SEA on behalf of the DG Stakeholder Group (see final report) determined that
economic development benefits should not be quantified in the benefit stack, but should instead be considered separately
as a supplemental consideration.
Given the general issues just detailed, in the following subsections for each net benefit component, we describe the
o data sources for the component,
o methodology in calculating the net benefits of the component,
o any simplifying assumptions made, and
o additional clarifying commentary as appropriate.
3.2 AESC Inputs
As discussed above, most inputs informing benefit quantification, if not provided directly by the EDCs, were derived from
the AESC 2021 Study. The AESC is a forward-looking study released every three-years and is the product of a study process
overseen by New England regulators, state energy offices, and a team of consultants (including the prime author Synapse
Energy Economics and SEA as a contributor). The study is designed to assist New England States in evaluating the cost
effectiveness of policies and programs. The AESC was originally developed in the context of evaluating energy efficiency
programs, but most inputs are applicable to the evaluation of renewable energy programs.
We note that, although an updated AESC 2024 study is currently available, AESC 2021 was utilized given the AESC study is
strictly forward looking and SEA’s analysis presented here is strictly retrospective. As such, a quantification of 2023 benefits
and costs would not be possible using AESC 2024 inputs.
For the purposes of this analysis, SEA utilized the “All-in Climate Policy” sensitivity, as it most closely approximates a future
in which states pursue the development of renewable energy. According to the AESC 2021, the sensitivity “models a future
with ambitious levels of energy efficiency, building electrification, and transportation electrification, as well as a policy which
achieves 90 percent clean energy regionwide by 2035. As a result, it can be interpreted not as an avoided cost, but as a
projection of expected energy prices, capacity prices, and other price series in a future with ambitious climate policies.”
AESC 2021 inputs used in this analysis were translated to nominal dollars assuming a discount rate of 2% (the default
assumption in AESC 2021).
Sustainable Energy Advantage, LLC
9
3.3 Quantification of Program MW and MWh
All benefits considered in this analysis are either energy (MWh) or capacity (MW) denominated. As such, quantifying the
applicable volumes of energy and capacity for each EDC, program variant, technology, and commercial operation date is a
necessary first step to assessing the total benefits per segment. SEA utilized actual program volumes wherever possible in
its analysis. Specific data sources, assumptions, and limitations are discussed below.
• Production Data: The approach to quantifying production varied by program variant, discussed below.
o Renewable Procurement: The EDCs provided hourly production data for all solar facilities procured through
renewable procurements.
o Tariff Rate: SEA received actual hourly production data for all CMP projects enrolled in the Tariff Rate
program. Versant provided actual monthly production data by project for the Tariff Rate Program.
o kWh Credit Program: SEA received actual monthly production data for kWh exports from both EDCs,
disaggregated by rate class. Because the EDCs do not meter production used on-site of BTM NEB projects,
such production was estimated by SEA based on the assumed capacity of BTM kWh Credit program projects
(discussed below). Production estimates assumed an 18% AC capacity factor, an annual production
degradation rate of 1%, and a de-rate to year-one production of 60% to reflect that projects typically
achieve commercial operation in the second half of the year.
• Capacity Data: SEA collected data on project capacities by EDC, technology, and commercial operation dates from
the EDC’s monthly NEB reports in Docket 2020-00199, as of December 31, 2024. The reports do not designate the
metering arrangement for each project. As such, SEA imputed the capacity of FTM facilities in the kWh Credit
program based on the exported kWh reported by both EDCs. The remainder net capacity (FTM minus total kWh
Credit program capacity) was assumed to be BTM. Renewable Procurement solar project capacities were provided
to SEA by the EDCs and verified with public data.
3.4 Revenue from Energy Resale
Overview
Energy re-sale revenue gained by the EDCs from production provided by operational procured and NEB-enrolled projects
was considered in this analysis. For the purposes of this analysis, this benefit is unique to the Tariff Rate program, as projects
enrolled in the Tariff Rate program variant serve as generators in ISO-NE markets. This is distinguished from projects in the
kWh Credit program that act as load reducers. This can take effect on the level of an individual EDC customer for BTM
consumption of NEB production, or for the EDC as whole for out channel export NEB production.
Data Source
EDC revenue from energy re-sale from Tariff Rate program and renewable procurement projects was provided by the EDCs
to SEA on a monthly basis.
Discussion
In the context of the AESC, this benefit is most similar to “avoided energy”, which represents the avoided costs of having
load serving entities procure energy on the wholesale market because of the energy transferred to the EDCs through
participation in DG programs. However, given that FTM projects procured and in the NEB program do not physically avoid
the consumption of energy, in the context of renewable procurement and the NEB Tariff Rate program variant, the
analogous benefit is energy re-sale revenue. For projects in the kWh Credit program variant, the costs of avoided energy
Sustainable Energy Advantage, LLC
10
are not considered in this analysis (see discussion in Section 3.15). As such, any potential avoided energy benefits are not
quantified to provide consistent accounting of both costs and benefits.
3.5 Capacity Buyout Revenue
Overview
This benefit captures revenue received by the EDCs from NEB or procured project owners electing to buyout capacity rights
from the EDC.
Data Source
Revenue collected in 2023 from capacity buyouts was provided to SEA by the EDCs.
Discussion
In the context of the AESC, this benefit is most similar to “avoided capacity”, which represents the avoided cost of building
or procuring capacity to meet the peak demand of the generation system. Generally, avoided capacity benefits would be a
function of capacity benefits monetized by the EDCs through successfully bidding project capacity into the Forward Capacity
Market (FCM). However, Both CMP and Versant stated that NEB project capacity is not currently being monetized for either
the Tariff Rate or kWh Credit program, instead projects are treated as “load reducers”. For Renewable Procurement
projects, the EDCs reported that, after commercially reasonable efforts, all projects failed to obtain capacity supply
obligations. As such, SEA only focused on revenues from capacity buyout.
The monetization of NEB program capacity represents a potential source of untapped program benefits. However, the
challenges associated with successfully bidding DG project capacity into the FCM, and the risk of penalties associated with
failure to perform during a scarcity event, have generally dissuaded EDCs in the region from monetizing capacity rights
associated with DG projects. Given this, it is SEA’s expectation that potential benefits associated with monetizing capacity
are modest. In addition, there are benefits from having the projects treated as load reducers, and these benefits may well
outweigh the modest potential benefits of monetizing capacity (see Section 3.6).
Capacity buyout agreements differ in structure depending on the buyout agreement in question (e.g., upfront payment vs
revenue share agreement). For the purposes of this analysis, SEA only considered revenues collected in 2023. As such,
revenues from projects electing to pay an up-front fee for capacity buyout prior to 2023 was not included in the analysis.
Versant noted that any capacity buyout revenues collected were folded into aggregate program revenues reported to SEA
(which are predominantly energy related and utilized in the “Energy Resale Revenue” component). As such, SEA did not
apply separate capacity buyout revenue for Versant to prevent double counting of revenues.
3.6 Uncleared Capacity
Overview
Despite not monetizing capacity rights (e.g., not bidding project capacity into the FCM), the capacity of projects still provides
benefits to ratepayers in Maine and ISO-NE more broadly via uncleared capacity value. Uncleared capacity value reflects
Sustainable Energy Advantage, LLC
11
how uncleared project capacity impacts the development of inputs to ISO New England’s FCM.
9
Specifically, the impact on
historical data utilized by ISO-NE of projects serving as load reducers are assumed to reduce forecasted Installed Capacity
Requirement (ICR) utilized in the FCM. Given that this benefit relies on load reductions from the perspective of the
transmission system, transmission-connected facilities (which are assumed to include renewable procurement facilities) do
not accrue this benefit.
Data Source:
SEA utilized AESC 2021 (All-in Climate Policy case) assumptions for the value of uncleared capacity.
Discussion:
Uncleared capacity utilizes a “phase-in” and “phase-out” schedule that relates the value per MW in any given year to the
resource’s commercial operation date. The phase in and out is applied to reflect the lag between a resource coming online
and the resource’s impact influencing ISO-NE study assumptions. Specifically, the 2021 AESC assumes that benefits from
uncleared capacity do not start until 5 years after their installation date. As such, SEA’s analysis assumes no uncleared
capacity benefits in 2023 for Tariff Rate projects, which have their earliest commercial operation date in 2019. Given the
limited capacity of NEB project online pre-2019, uncleared capacity benefits are modest relative to other benefit
components.
3.7 Reduced Share of Capacity Costs
Overview
BTM, distribution-connected resources that generate energy during Maine's monthly peak hours can reduce the share of
capacity costs paid for by Maine (thereby resulting in a cost shift to other New England ratepayers). Transmission-connected
facilities (which are assumed to include renewable procurement facilities) do not accrue this benefit.
Data Source:
AESC 2021 inputs were utilized.
Discussion:
To calculate the estimated load reductions during peak periods resulting from NEB project production, SEA calculated the
average 12-month coincident MW (expressed as a percent of nameplate capacity), as described above. The coincident
factor was then used to calculate the reductions in capacity costs assigned to Maine, per MW of solar.
Given that this benefit represents a shifting of costs to other regional states, it is only included as a benefit in this analysis
for the Maine-only societal impact perspective and the ratepayer impact perspective.
9
See page 125 of 2021 AESC for detailed discussion of such benefits, here: https://www.synapse-energy.com/sites/default/files/AESC%202021_20-
068.pdf
Sustainable Energy Advantage, LLC
12
3.8 Transmission and Distribution Benefits
3.8.1 Avoided Transmission and Distribution Investments
Overview
Distribution-connected resources that generate energy during periods of high demand could reduce future-needed
transmission investments. Similarly, distribution-connected BTM resources that generate energy during periods of high
demand could reduce future-needed distribution-level grid investments. As such, the value of such avoided investments is
considered in this analysis.
Transmission benefits are only applicable to projects connected to the distribution system, as transmission-connected
facilities do not reduce transmission-level load. For distribution benefits, this benefit is only applicable to projects connected
to the distribution system that are BTM, as FTM facilities do not reduce distribution-level load. As such, transmission-
connected facilities (which are assumed to include renewable procurement facilities) do not accrue this benefit.
Data Source:
For transmission benefits, SEA utilized AESC 2021 assumptions specific to Maine for the value per MW-year of avoided
transmission capacity. Specifically, the AESC provides separate values per MW-year of avoided transmission for intrastate
transmission upgrades and transmission upgrades serving ISO-NE (which are referred to as Pooled Transmission Facilities
(PTF) upgrades). For distribution benefits, SEA utilized AESC 2021 assumptions specific to Maine for the value per MW-year
of avoided distribution capacity. The studies referenced by the AESC 2021 provide a range of possible values. Consistent
with the AESC 2021, SEA adopted mid-point estimates. Both values were provided in 2020 dollars and were translated to
2023 dollars assuming an inflation rate of 2% (consistent with the inflation rate assumed in AESC 2021).
Discussion:
To calculate the estimated load reductions on the transmission system during peak periods resulting from DG projects, SEA
calculated the average 12-month coincident peak MW (expressed as a % of nameplate capacity) by comparing peak Maine
ISO-NE load in each month (as provided by AESC 2021) to a representative production curve for solar in Maine. The
representative production curve was taken from PVWatts, assuming a facility located in Southern Maine.
10
The resulting
factor was used to de-rate the full value per MW-year of avoided transmission capacity to a technology-specific value, based
on each technology’s production coincidence with peak periods.
Avoided intrastate transmission investments were only applied to BTM projects, as such, FTM projects are not assumed to
reduce the load of transmission assets within Maine. FTM projects were assumed to contribute to avoided PTF investments.
Intrastate and rest-of-pool values for avoided investments were calculated separately, based on Maine’s share of the
transmission costs as provided by ISO-NE.
11
To calculate the estimated load reductions on the distribution system during peak periods resulting from DG resources, SEA
calculated the share of annual production contributing to reductions in the top 100 peak hours of the year. To do this, SEA
utilized a forecast of hourly load (as provided by AESC 2021) as compared to a representative production curve for solar in
10
PVWatts is a tool developed by the National Renewable Energy Laboratory (NREL) which estimates hourly PV production based on specific
locations, found here: https://pvwatts.nrel.gov/
11
See ISO-NE 2023 peak demand by state here: https://www.iso-ne.com/static-assets/documents/2023/02/2023_smd_monthly.xlsx
Sustainable Energy Advantage, LLC
13
Maine. The resulting factor was used to calculate a per MWh value capturing avoided distribution capacity, based on solar
production’s coincidence with peak periods.
For both transmission and distribution benefits, SEA considered the use of actual system peaks, as reported by ISO-NE, in
2023 as compared to actual project production (for Tariff rate projects for which hourly production data was supplied).
However, given that this benefit is intended to capture the impact of load reducing resources on system planning, using
weather-neutral values are more likely to approximate the assumptions in forming system planning. In practice, system
planning occurs on longer time horizons than the single year focused on in this analysis. As such, it is unlikely that a single
year’s production would influence system planning and yield such benefits. However, when viewed in the context of the
broader NEB program, which has had multiple years of projects come online (and thereby influencing system planning over
longer time horizons), it is likely that such benefits would be realized. As such, the benefits contained in this report represent
the share of total program benefits that could be attributed to production occurring in 2023.
3.8.2 Avoided Maine Regional Network Service Share
Overview
BTM, distribution-connected resources that generate energy during Maine's monthly peak hours can reduce the share of
Regional Network Service (RNS) transmission costs paid for by Maine (thereby cost shift to other New England ratepayers).
Transmission-connected facilities (which are assumed to include renewable procurement facilities) do not accrue this
benefit.
Data Source:
SEA utilized the 2023 RNS charge as provided by ISO-NE.
Discussion:
To calculate the estimated load reductions during peak periods resulting from DG projects, SEA calculated the average 12-
month coincident MW (expressed as a percent of nameplate capacity), as described above. The coincident factor was then
used to calculate the reductions in RNS expenses, per MW, for each technology assessed.
Given that this benefit represents a shifting of costs to other regional states, it is only included in this analysis for the Maine-
only societal impact perspective and the ratepayer impact perspective.
3.8.3 Avoided Transmission and Distribution Line Losses
Overview
Generation from distribution-connected distributed generation reduces the load on the transmission system and, for BTM
generators, reduces the load on the distribution system. This avoids the transfer of energy across distribution or
transmission lines and thereby reduces any lost energy associated with such transfer. This yields both energy and capacity
related benefits. Transmission-connected facilities (which are assumed to include renewable procurement facilities) do not
accrue this benefit.
Sustainable Energy Advantage, LLC
14
Data Source:
AESC 2021 recommended transmission and distribution line losses were adopted.
12
These values were informed by
assumptions adopted by ISO-NE.
Discussion:
To compute a total benefit related to avoided line losses, the adopted energy line losses input was multiplied by kWh-
denominated benefits discussed elsewhere in this analysis, and the adopted capacity line losses input was multiplied by
kW-denominated benefits discussed elsewhere in this analysis. Half the value of line loss benefits were applied to FTM
facilities since they do not avoid distribution losses (assuming distribution losses are roughly half of total distribution and
transmission line losses reported by the AESC).
3.8.4 Transmission And Distribution Upgrades Funded by NEB Customers
Overview
Distributed generation interconnecting to the distribution system is often required to fund system upgrades to the
distribution or transmission system to facilitate such interconnection. These upgrades can deliver shared benefits to all
ratepayers if they provide reliability benefits or accelerate upgrades that would have been required eventually in business-
as-usual system planning.
Data Source:
The EDCs provided a list of NEB projects interconnecting in 2023, and the associated costs, if any, paid to fund upgrades to
the transmission and distribution system. No renewable procurement projects came online in 2023, so no such costs were
provided for these facilities.
Discussion:
Assigning the share of interconnection fees that contribute to shared benefits for all ratepayers is a difficult task.
Nonetheless, inclusion of such investments as a benefit component is required by statue. Shared benefits delivered will be
a function of the specific location, timing, and grid conditions in question. An analysis of this depth was not possible for the
purposes of this report. As such, SEA assumed that 25% of total interconnection costs paid to fund system upgrades were
shared benefits based on SEA’s professional judgment.
13
Given that the actual share of costs delivering shared benefit may
be different, SEA conducted a sensitivity analysis assuming either 50% or 0% share of costs delivered shared benefits. A
table providing the range of benefits, program wide, by assumption is provided below in Table 3:
Table 3 –
T&D upgrade benefits – Sensitivity Results
Share of costs assumed to deliver
shared benefits
Program-Wide Benefits (Million $)
0%
0
25%
8.89
50%
17.79
12
See Table 147 of AESC 2021, here: https://www.synapse-energy.com/sites/default/files/AESC%202021_20-068.pdf
13
SEA notes that, pursuant to Ch 324 of the Commission’s rules, certain T&D upgrade costs are socialized for Level 1 projects. This cost was not
quantified in this analysis. Given that Level 1 projects are not expected to trigger significant system upgrade expenses, SEA does not expect this cost
to be substantial relative to the benefits quantified in Section 3.8.4.
Sustainable Energy Advantage, LLC
15
3.9 Demand Reduction Induced Price Effects (DRIPE)
Overview:
DRIPE benefits relate to the impact on market prices resulting from an increase in low-cost supply or reduction in demand
for a commodity. In the context of this analysis, renewable resources with low marginal costs tend to drive down prices by
shifting the supply curve to the right. This dynamic applies to capacity, energy, and natural gas prices (through reduced
demand for gas-generated electricity, called “Cross-Fuel DRIPE”).
Data Source:
AESC 2021 (All-in Climate Policy Case) DRIPE values specific to Maine were utilized.
Discussion:
For Energy DRIPE, which varies based on peak/off-peak period and season, hourly 2023 production data from all CMP Tariff
Rate projects was utilized to calculate the share of annual production occurring in each period for the NEB program. These
shares were applied to production from Versant or kWh Credit program projects, for which hourly data was not available.
For renewable procurement projects, actual hourly production data was used for each EDC.
Given that Energy DRIPE and Cross-Fuel DRIPE values are partially a function of the underlying price of electricity each year,
SEA applied an adjustment to such prices equal to the delta between the average load-weighted annual LMP in Maine
reported by ISO-NE and the average load-weighted annual LMP assumed in AESC 2021. This adjustment resulted in a
reduction of 1% to Energy DRIPE and Cross-Fuel DRIPE values.
DRIPE values in any given year are contingent on the commercial operation date of the resource in question. As such, DRIPE
values were calculated separately for each commercial operation year represented in projects operational in the NEB
program in 2023 (i.e., were calculated separately for each cohort year).
Given that Versant–MPD operates outside of ISO-NE and does not have an organized wholesale energy or capacity market,
SEA did not quantify DRIPE benefits for projects in this area. Although DRIPE benefits could theoretically apply, as even
bilateral contracts are negotiated with a theoretical supply curve in mine, the quantification of such benefits for the MPD
would be very difficult and speculative at best.
3.10 Renewable Energy Certificate (REC) Price Suppression
Overview:
Similar to DRIPE benefits, additional supply of Class I RECs into the regional marketplace can suppress regional Class I REC
prices, thus reducing the cost of meeting RPS obligations for impacted RPS markets. Given that most RECs generated from
NEB-participating projects are eligible in all Class I markets, this price suppression effect is realized in more than just Maine’s
RPS market. Although this is not a DRIPE benefit contained in the ASEC (given the AESC’s focus on energy efficiency
programs, which do not involve the generation of RECs) the concept behind this benefit is largely similar.
Data Source:
SEA utilized production data from the EDCs to estimate Class I REC creation. REC price suppression was calculated using
SEA’s suite of New England Renewable Energy Market Outlook (REMO) models, discussed below.
Sustainable Energy Advantage, LLC
16
Discussion:
To calculate the REC price suppression impact of the NEB program, SEA utilized modeling completed for its 2023-3 REMO
briefing.
14
Base case assumptions were adopted. Two separate modeling runs were completed, one containing NEB
program capacity, and one excluding NEB program capacity. The differences in forecasted 2023 Class I prices in each state
market were then calculated. Results demonstrated a reduction of $1.75 in the price of regional Class I markets (including
Massachusetts, Rhode Island, New Hampshire, Maine, and Connecticut). This price delta was then translated to total dollar
savings by multiplying the delta by the 2023 compliance obligation for each Class I market. Results were then categorized
by intrastate (Maine Class I) and regional (all other markets) benefits.
3.11 REC revenue
Overview:
Projects in both the NEB program and participating through procurements are eligible to generate Maine Class I RECs and
are also eligible for most of the regional New England Class I markets (with certain exclusions for out-of-state RECs
generated by BTM facilities, though even Maine BTM facilities are eligible to register as Massachusetts Class I RECs). In both
the NEB program and the power purchase agreements (PPAs) from procured facilities operational in 2023, RECs are not a
product transferred to the EDCs included in the cost of such contracts. As such, RECs represent an additional value stream
to program revenue through the sale of such RECs to the regional market.
Data Source:
Price quotes in March of 2024 for 2023 Maine Class I were taken from multiple REC brokers and averaged to derive a price
for use in modeling.
Discussion:
Given that the primary perspective of this analysis is from a societal lens, REC revenue is not accounted for in the benefit
stack presented in Section 4. This is because, from the general societal perspective, REC revenue is considered a cost shift
from buyers to sellers of RECs, and thus cancels out to zero net benefits (putting aside small transaction costs). Nonetheless,
LD 327 requires a quantification of such benefits. To address this requirement, SEA describes estimated revenues in Section
4.3.
3.12 Reduced RPS Requirements
Overview:
RPS costs are a function of the cost of RECs, the RPS requirement (expressed as a percentage of obligated load), and the
size of the obligated load (in MWh). BTM production acts as a load reducer, thereby decreasing the total load from which
the compliance obligation for any given year is calculated. Thus, BTM projects provide benefits in the form of reductions in
total RPS costs.
To address this, in its orders granting new RPS certification, the Commission requires that for BTM facilities, “the facility
owners must retain GIS certificates or otherwise obtain GIS certificates necessary to satisfy Maine’s RPS for that portion of
the BTM load that is served by the facilities.” As such, in the context of Maine, the total volume of RECs retired should not
change because of BTM load reductions, but the party responsible for fulfilling RPS requirements with such load does
14
For details on the New England REMO service, see here: https://www.seadvantage.com/new-england-remo/
Sustainable Energy Advantage, LLC
17
change. Thus, SEA only applied this benefit for the ratepayer impact perspective to reflect that RECs retired to fulfill RPS
obligations related to BTM load reductions bears a cost on the facility owner to the benefit of the general ratepayer. For all
other tests, this component is considered a cost shift, and thus does not yield any net benefits.
Data Source:
Price quotes in March of 2024 for 2023 Maine Class I and II REC prices were taken from multiple REC brokers and averaged
to derive a price for use in modeling.
Discussion:
SEA considered the benefits of avoided Class I and II RPS costs. Assumed 2023 REC prices by class were de-rated by the
applicable 2023 RPS minimum standard for each class (17.3% for Maine Class I, 30% for Maine Class II), to reflect that one
MWh of load reduction results in the avoided purchase of only a partial REC.
3.13 Societal Benefits from Greenhouse Gas Reduction
Overview:
Renewable energy contributes zero-carbon energy to the grid, reducing the greenhouse gas (GHG) intensity of energy
consumed. The benefits of these GHG emissions reductions are quantified and considered in this analysis.
Data Source:
AESC 2021 values (from Counterfactual #1) were used to compute the marginal non-embedded emissions benefits per
MWh of generation. “Non-embedded” refers to the portion of benefits that are not already accounted for (or “embedded”)
in wholesale energy prices via fees from the Regional Greenhouse Gas Initiative (RGGI). AESC 2024 values for the social cost
of carbon (SCC) were used to translate abated emission volumes into dollar values.
Discussion:
The impetus behind much of the focus on incenting renewable energy relates to the impacts of climate change and the
GHG reduction benefits offered by renewable generators. Given this, the inclusion of such benefits in a benefit-cost analysis
of renewable energy programs is critical to capture the scope of costs and benefits informing the genesis of such programs.
Quantifying the GHG benefits from renewable generation is a function of the estimated volume of GHG avoided multiplied
by the assumed SCC. Each component is discussed below:
Marginal GHG reduction: The marginal reduction in GHG resulting from a MWh of renewable generation is
calculated in the AESC based on the applicable peak/off-peak period and season. Similar to the approach taken for
Energy DRIPE, SEA utilized hourly production data from CMP for Tariff Rate projects to inform the share of annual
MWh applicable to each period. Inputs from Counterfactual #1 were utilized because the All-in Climate Policy
sensitivity models GHG benefits using incremental regional clean energy policy compliance cost (IRCEP) rather than
the SCC. The IRCEP approach does not produce GHG benefits prior to 2025.
SCC: Quantification of a SCC is complex and well-studied. Given that the costs of carbon emissions (namely, climate
change) occur over long time spans including impacts distant in the future, the specific year under which carbon is
assumed to be emitted is less relevant to SCC quantification than assumptions like the discount rate used to put
future costs in present dollar terms. Unlike other inputs in the 2021 AESC, which reflect the specific resource mix
Sustainable Energy Advantage, LLC
18
and grid conditions in ISO-NE during the study period, the adopted SCC in AESC 2021 primarily reflects SCC values
adopted in regional and national agencies at the time of study release which have since been updated.
Given this, SEA determined it was most appropriate to use an updated SCC based on inputs adopted in AESC 2024,
which represents the most up to date SCC adopted by the U.S. Environmental Protection Agency (EPA) as of
November 2022. Specifically, AESC 2024 recommends a 2023 SCC between $218 and $375 per short ton
(representing a discount rate between 2% and 1.5%). For the purposes of this analysis, SEA adopted the low end of
this range, representing a discount rate of 2%.
The SCC is then transformed by the AESC “user interface” to remove embedded costs attributed to RGGI costs, thus
preventing the doubling counting of costs that are embedded in energy costs.
Finally, SEA subtracts the assumed average ME Class I REC price in 2023 from the total $/MWh non-embedded GHG benefit
(see Section 3.12 for a discussion of assumed REC values). This is done because RECs represent an environmental attribute
whose value includes the benefits of GHG reduction from renewable generation. Given that RECs are not taken title to
under the NEB program, meaning project owners can sell RECs independently, failing to subtract assumed REC value from
the total non-embedded GHG benefit would result in double counting of environmental benefits, as a portion of the
environmental value will be claimed outside of the program via the purchase and retiring of RECs.
3.14 Avoided Environmental Compliance Costs
Overview:
Renewable energy contributes zero-carbon energy to the grid, offsetting the dispatch of fossil generation. Fossil generation
produces co-pollutants in addition to GHG, including NO
X
. The benefits of these NO
X
emissions reductions are quantified
and considered in this analysis.
Data Source:
AESC 2021 values (All-in Climate Policy sensitivity) were used to compute the marginal NOx benefits per MWh of generation.
Discussion:
The marginal reduction in GHG resulting from a MWh of renewable generation is calculated in the AESC based on peak/off-
peak period and season. Like the approach taken for Energy DRIPE, SEA utilized hourly production data from CMP for Tariff
Rate and renewable procurement projects to inform the share of annual MWh applicable to each period.
3.15 Modeling Cost Components
Overview:
The costs of the solar program differ substantially by program variant. A discussion of costs by program variant is provided
below.
Renewable Procurements: The cost of procured facilities was provided by the EDCs on an aggregate basis and is a function
of each facility’s production multiplied by the facility’s applicable PPA rate. Given that procured projects are expected to be
transmission-connected, SEA added costs associated with the integration of transmission-connected facilities applicable to
Sustainable Energy Advantage, LLC
19
such projects. Costs per MWh of transmission-connected solar was derived from National Renewable Energy Laboratory
(NREL) analysis and was broken out by intrastate and “Rest of Pool” (ROP) impacts.
15
Tariff Rate Program:
As discussed in Section 3.1, Tariff Rate Program variant provides monetary credits to participating customers based on
facility production of the project to which they are subscribed. The specific rate is dependent on if a project is enrolled in
the original Tariff Rate program (where the monetary credits are calculated as a function of the retail rates set at the
beginning of each calendar year) or the alternative Tariff Rate program (where the monetary credits are set as a fixed 2.25%
annual inflator applied to the 2020 original Tariff Rate program rates).
For the purposes of SEA’s analysis, SEA did not distinguish between the two Tariff Rate compensation variants, as total Tariff
Rate program variant costs were provided by the EDCs on a monthly basis aggregated across all Tariff Rate projects. Such
costs represented the actual monetary credits applied to participating customers’ bills in 2023.
kWh Credit Program:
As discussed in Section 3.1, the kWh Credit program variant provides kWh credits on the EDC electric bills of NEB
participants. As a result, billed kWh offset through the program results in a reduction in revenues received by the EDCs. The
“lost revenue” represents a cost that must be recovered from ratepayers.
To quantify such costs, kWh program costs for energy exports were provided by the EDCs in the form of lost distribution
revenues, consistent with filings made through regular stranded cost proceedings. These costs, however, do not represent
the full costs associated with the kWh Credit Program, as other wire charges designed to cover costs associated with
transmission costs, Electricity Lifeline Program (ELP) costs, and Efficiency Maine Trust (EMT) costs are impacted as well. As
such, SEA utilized the kWh of energy exports under the kWh Credit program, by rate class, provided by the EDCs to compute
total costs based on all volumetric (per-kWh) wire charges.
Lastly, SEA computed the lost revenues associated with BTM production consumed on-site (which are, of course, not
included in the kWh of energy exports provided by the EDCs) based on the estimated production from BTM facilities, as
discussed in Section 3.3.
We note that the kWh Credit program variant results in a reduction in billed kWh as compared to the kWh consumed by
EDC customers. This disconnect of billed kWh to consumed kWh likely increases the Standard Offer pricing (as compared
to the counter factual of the absence of the kWh Credit program). Regardless of the likely increase on Standard Offer pricing
resulting from the structure of the kWh Credit program variant, such indirect impacts are difficult to quantify and more
importantly outside the legislative mandate and the scope of this analysis.
Administrative Costs:
In addition to per-kWh program expenses, SEA collected total costs associated with the administration of the solar program
from the EDCs. CMP provided costs associated with the NEB program only, while Versant provided costs for both renewable
procurement and the NEB program. NEB costs were allocated to each program variant based on the share of capacity
participating in each program. Overall, administrative costs are insignificant compared to other program expenses.
15
See Gorman et al. 2019, here: https://eta-publications.lbl.gov/sites/default/files/td_costs_formatted_final.pdf
Sustainable Energy Advantage, LLC
20
4 Results and Findings
4.1 General Societal Perspective
The results of SEA’s analysis quantifying the benefits and costs of the Maine solar programs for calendar year 2023 is
provided below, with a graphical summary of the analysis provided in Figure 3 and a tabular summary in Table 4. Benefit
components displayed below are an aggregation of more granular components, organized by component category. For a
more detailed breakdown of individual benefit components, please see Appendix A.
Figure 3 –
Calendar Year 2023 Maine Solar Programs Summary Costs and Benefits
Table 4 -
Calendar Year 2023 Maine Solar Programs Summary Cost and Benefit in Millions of Dollars
Benefit / Cost Category
Costs
Benefits
Program Expense
$103.76
N/A
Renewable Portfolio Standard (RPS)
Cost Reductions
N/A
$26.37
Energy Resale Revenue
N/A
$13.30
Energy Price Suppression
N/A
$27.72
Capacity Benefits
N/A
$0.80
T&D Benefits
N/A
$35.46
GHG and Environmental Benefits
N/A
$38.09
Totals
$103.76
$141.74
Sustainable Energy Advantage, LLC
21
SEA calculates that the Maine solar programs 2023 calendar year program expenses were $103.76 million, and the program
benefits were $141.74 million. Note that the cost and expenses are for all solar projects operating in 2023. Thus, the impact
of projects as old as 1994 are included in the analysis.
Figure 4 and Table 5 provide a summary of the Maine solar program costs and benefits by the program described in Section
3.1. Solar projects from both the NEB program and renewable procurements are found to have benefits exceeding costs.
Figure 4 –
2023 Maine Solar Programs Summary Costs and Benefits in Millions of Dollars
Table 5 -
2023 Maine Solar Programs Summary Costs and Benefits in Millions of Dollars
Program Variant
Costs
Benefits
Benefit-Cost Ratio
NEB Program for Solar Projects
$99.37
$127.82
1.29
Renewable Procurement Solar Projects
$4.39
$13.92
3.17
Total – Solar Projects
$103.76
$141.74
1.37
Next, Figure 5 provides a summary of the Maine solar programs costs and benefits on a million dollar per MW
AC
basis. The
solar only projects for the NEB program have benefits exceeding costs by about a 30% margin, while the solar only
renewable procurement projects have benefits exceeding costs by more than a 3:1 margin.
Sustainable Energy Advantage, LLC
22
Figure 5 –
2023 Maine Solar Program Summary of Costs and Benefits per MW
Table 6 provides a breakdown of component categories by total value, whereas Table 7 provides such figures on a million
dollar per MW
AC
basis for apples-to-apples comparisons across program. A discussion of the relative benefits and costs of
each program is provided below in approximate order of significance:
• Program Costs: The costs for the solar components of the NEB and renewable procurements are (as noted above)
a fraction of the total benefits.
• T&D Benefits: While T&D benefits are a significant fraction of NEB program benefits (27.6%), the renewable
procurements have no T&D benefits. This occurs because we assume the renewable procurement projects are
interconnected at the transmission system level, while all the NEB projects are interconnected at the distribution
level.
• GHG and Environmental Benefits / Energy Price Suppression / RPS Cost Reductions: Benefits that are a function of
project production (e.g., GHG benefits, energy price suppression, REC price suppression) are roughly equal per-MW
for the renewable procurements vs the NEB program. This is because, although the capacity factor of procured
projects is generally higher as compared to NEB projects (which includes smaller BTM projects), multiple procured
projects were offline in 2023, which resulted in roughly equal production per MW with solar in the NEB program.
Procured solar had a greater share of production during winter peak periods, resulting in marginally higher energy
price suppression benefits.
• Energy Resale Revenue: The energy resale benefits for the NEB program are much smaller than renewable
procurement benefits on a relative basis (to total benefits for each program) because there are no energy resale
benefits for the solar production under the NEB kWh Credit program variant.
• Capacity Benefits: Capacity Benefits are negligible for the NEB program. Rarely do NEB projects try to qualify for
capacity benefits and even fewer successfully qualify. This contrasts to the procured solar projects that typically
attempt to qualify for ISO-NE capacity benefits. However, given that the projects assessed in this analysis were
Sustainable Energy Advantage, LLC
23
unable to obtain competitive capacity supply obligations (CSOs), benefits are negligible for procured projects as
well.
Table 6 -
Summary Comparison of NEB Solar vs. Renewable Procurements (Total $)
Benefit / Cost Category
NEB Solar Program
(Millions $ or MW
AC
w/ % of
Total Benefits)
Renewable Procurements
(Millions $ or MW
AC
w/ % of
Total Benefits)
Renewable Procurements
as % of NEB
MW
AC
618.30
77.27
12.5%
Program Expense
$99.37
$4.39
4.4%
T&D Benefits
$35.46
$0.00
0.0%
GHG and Environmental
Benefits
$33.91
$4.19
12.3%
Energy Price Suppression
$23.82
$3.90
16.4%
RPS Cost Reductions
$23.49
$2.88
12.3%
Energy Resale Revenue
$10.35
$2.95
28.5%
Capacity Benefits
$0.80
$0.00
0.0%
Total Benefits
$127.82
$13.92
10.9%
Table 7 -
Summary Comparison of NEB Solar vs. Renewable Procurements ($/MW)
Benefit / Cost Category
NEB Solar Program
(Millions $/MW
AC
)
Renewable Procurements
(Millions $/MW
AC
)
Renewable as % of NEB
Program Expense
$0.161
$0.057
35.4%
T&D Benefits
$0.057
$0.000
0.00%
GHG and Environmental
Benefits
$0.055
$0.054
98.8%
Energy Price Suppression
$0.039
$0.050
131.0%
RPS Cost Reductions
$0.038
$0.037
98.2%
Energy Resale Revenue
$0.017
$0.038
228.1%
Capacity Benefits
$0.001
$0.000
0.0%
Total Benefits
$0.207
$0.180
87.1%
4.2 Quantification of REC Revenue
As discussed in Section 3.11, REC revenue is not accounted for in the benefit stack presented in Section 4. This is because,
from the general societal perspective, REC revenue is considered a cost shift from buyers to sellers of RECs, and thus cancels
out to zero net benefits (putting aside small transaction costs). Nonetheless, the Act requires a quantification of such
benefits which is provided below in Table 8.
Sustainable Energy Advantage, LLC
24
Table 8 - Estimated REC Revenue by Solar Program
Program
REC Revenue (M$)
NEB (Solar only)
26.66
Renewable Procurements
3.27
Total
29.93
4.3 Sensitivity Analysis of Maine Societal and Ratepayer Impact
Perspectives
Per the discussion in Section 2.4, we have conducted the above net benefit analysis from a societal impact perspective
(Societal Perspective). In this subsection we provide a sensitivity analysis from the Maine-only societal impact perspective
(Maine Perspective) in addition to a ratepayer impact perspective (Ratepayer Perspective). Before doing so it is instructive
to compare what net benefit analysis components are included in each perspective as is provided in Table 9, where ROP
stands for “Rest of Pool”, or the rest of the ISO-NE power pool outside of Maine.
As should be expected, any components that only impact the ROP (i.e., New Hampshire, Vermont, Massachusetts,
Connecticut, and Rhode Island) are excluded from the Maine Perspective and the Ratepayer Perspective but are included
in the Societal Perspective. In addition, “Reduced Share of Capacity Costs” and “Reduced Share of Transmission Costs” to
Maine ratepayers are included in the Maine Perspective and the Ratepayer Perspective but excluded from the Societal
Perspective because the overall ISO-NE (more or less) fixed capacity and transmission costs are allocated to each state
based on each state’s impact on the regional T&D system. Thus, from the Societal Perspective, a reduction in Maine’s share
of such costs just represents a cost transfer to other New England state ratepayers, and not a true benefit. As discussed in
Section 3.12, reduced RPS requirements are only considered a benefit for the Ratepayer Perspective as this benefit
represents a cost shift from general ratepayers to facility owners.
Notably, SEA has chosen to include Non-embedded GHG emissions benefits in the Maine Perspective. This is because the
recognition of the importance of reducing GHG emissions is a primary motivator for establishing programs like the NEB
program. Such goals have been legally recognized by Maine, as the legislature has formalized GHG reduction requirements
in P.L. 2019 Chapter 476, which requires the State to reduce carbon emissions by 45% relative to 1990 levels by 2030 and
80% by 2050. Given this, although such benefits are global in scale, omission of them would be antithetical to the
motivations informing the establishment of the solar incentive programs.
This determination is in line with best practices and prior analysis. First, the National Standard Practice Manual for Benefit-
Cost Analysis of Distributed Energy Resources notes that societal impacts should be accounted for to the extent that they
contribute to a jurisdiction’s energy policy goals.
16
In contrast, ROP energy suppression benefits are not an express goal of
Maine, but rather are a side effect of the NEB program (and are thus not included in the Maine Perspective). Lastly, prior
benefit-cost analysis of the NEB program conducted by Synapse Energy Economics and Sustainable Energy Advantage on
behalf of the DG Stakeholder Group (see final report) adopted a Maine Perspective and included GHG benefits. GHG benefits
are excluded from the Ratepayer Perspective.
16
See page 16, here: https://www.nationalenergyscreeningproject.org/wp-content/uploads/2020/08/NSPM-DERs_08-24-2020.pdf
Sustainable Energy Advantage, LLC
25
NOx emission benefits are also included in the Maine Perspective, as such benefits are a more local pollutant (e.g., ground-
source ozone) as compared to GHG emissions. However, such benefits are minuscule compared to other benefit
components, and thus do not materially impact results. The benefits are excluded from the Ratepayer Perspective.
Table 9 -
Benefit & Cost Components Included by Analysis Perspective
Component
Societal Impact
Perspective
Maine-only Societal
Impact Perspective
Ratepayer Impact
Perspective
Project PPA Expenses
Include
Include
Include
Lost Utility Revenues
Include
Include
Include
Program Admin
Include
Include
Include
Energy Resale Revenue
Include
Include
Include
Capacity Buyout Revenue
Include
Include
Include
Interconnection upgrade benefits
Include
Include
Include
Uncleared capacity value (Intrastate)
Include
Include
Include
Uncleared capacity value (ROP)
Include
Exclude
Exclude
Reduced Share of Capacity Costs
Exclude
Include
Include
Price suppression - energy (Intrastate)
Include
Include
Include
Price suppression - energy (ROP)
Include
Exclude
Exclude
Price suppression - capacity (Intrastate)
Include
Include
Include
Price suppression - capacity (ROP)
Include
Exclude
Exclude
Price suppression - electric-gas (Intrastate)
Include
Include
Include
Price suppression - electric-gas (ROP)
Include
Exclude
Exclude
Price suppression - electric-gas-electric
(Intrastate)
Include
Include
Include
Price suppression - electric-gas-electric (ROP)
Include
Exclude
Exclude
Reduced transmission costs (Intrastate)
Include
Include
Include
Reduced transmission costs (ROP)
Include
Exclude
Exclude
Reduced Share of Transmission Costs
Exclude
Include
Include
Reduced distribution costs
Include
Include
Include
Reduced T&D losses - capacity (Intrastate)
Include
Include
Include
Reduced T&D losses - capacity (ROP)
Include
Exclude
Exclude
Reduced T&D losses - energy (Intrastate)
Include
Include
Include
Reduced T&D losses - energy (ROP)
Include
Exclude
Exclude
Non-embedded GHG emissions
Include
Include
Exclude
NOx emissions
Include
Include
Exclude
Reduced RPS Obligation
Exclude
Exclude
Include
REC Price Suppression (Intrastate)
Include
Include
Include
REC Price Suppression (ROP)
Include
Exclude
Exclude
Table 10 provides a summary comparison of the cost and benefits by modeling perspective. Overall, the Maine Perspective
benefits are slightly less than the solar project program expenses. This is primarily because the Maine Perspective has
significantly lower benefits for the RPS Cost Reductions and Energy Price Suppression categories than the Societal
Perspective because the Maine Perspective does not include the benefits of the Maine NEB and procurement programs
that are reaped by other New England states (e.g., does not include the benefits associated with ROP). Conversely, the
Capacity Benefits and T&D Benefits are greater for the Maine Perspective and the Ratepayer Perspective, because some of
Sustainable Energy Advantage, LLC
26
those benefits accrue to Maine ratepayers only while increasing rates by the same aggregate amount for ratepayers in other
New England states (and are thus considered cost shifts from the Societal Perspective). The Program Expense, Energy Resale
and GHG & Environmental Benefits benefit / cost categories do not vary from the Societal Perspective to the Maine
Perspective. The Ratepayer Perspective is identical to the Societal Perspective apart from marginally higher RPS cost
reductions (see Section 3.12) and the exclusion of benefits relating to GHG or NOx emissions reductions.
Details on the individual component level results that make up the results of each component category by benefit-cost
analysis perspective, program type, EDC and technology are provided in Appendix A.
Table 10 -
2023 Solar Program Summary Cost and Benefit in Millions of Dollars by Analysis Perspective
Benefit / Cost
Category
Costs
Societal
Perspective
Benefits
Maine
Perspective
Benefits
Ratepayer
Perspective
Benefits
Maine
Perspective
Benefits (% of
Societal)
Ratepayer
Perspective
Benefits (%
of Societal)
Program Expense
$103.76
N/A
N/A
N/A
N/A
N/A
RPS Cost
Reductions
N/A
$26.37
$3.02
$3.73
11.5%
14.1%
Energy Resale
Revenue
N/A
$13.30
$13.30
$13.30
100.0%
100.0%
Energy Price
Suppression
N/A
$27.72
$3.70
$3.70
13.3%
13.3%
Capacity Benefits
N/A
$0.80
$0.50
$0.50
63.0%
63.0%
T&D Benefits
N/A
$35.46
$24.12
$24.12
68.0%
68.0%
GHG and
Environmental
Benefits
N/A
$38.09
$38.09
$0.00
100.0%
0.0%
Totals
$103.76
$141.74
$82.73
$45.34
58.4%
32.0%
5 Maine Solar Energy Development and Basic Solar Energy Market
Trends
LD 327 requires the Commission to monitor the level of solar energy development in Maine in relation to the goals set forth
in 35-A M.R.S. § 3474,
17
as well as the basic trends in solar energy markets, which state in part the following:
2. State solar energy generation goals. When encouraging the development of solar energy generation, the State shall
pursue cost-effective developments, policies and programs that advance the following goals:
A. Ensuring that solar electricity generation, along with electricity generation from other renewable energy
technologies, meaningfully contributes to the generation capacity of the State through increasing private investment
in solar capacity in the State;
B. Ensuring that the production of thermal energy from solar technologies meaningfully contributes to reducing the
State's dependence on imported energy sources;
17
https://www.mainelegislature.org/legis/statutes/35-a/title35-Asec3474.html
Sustainable Energy Advantage, LLC
27
C. Ensuring that the production of electricity from solar energy meaningfully contributes to mitigating more costly
transmission and distribution investments otherwise needed for system reliability;
D. Ensuring that solar energy provides energy that benefits all ratepayers regardless of income level;
E. Increasing the number of businesses and residences using solar technology as an energy resource; and
F. Increasing the State's workforce engaged in the manufacturing and installation of solar technology.
The incremental growth in installed state-contracted / incented solar is provided in provided in Table 11 which ended
calendar year 2023 with installed capacity of 618.3 and 77.3 MW
AC
respectively. Graphically, the recent large incremental
increases in the growth of the NEB program and to a lesser extent the renewable procurements are shown in Figure 6 and
cumulatively in Figure 7.
Table 11 -
Incremental Growth in Maine Solar MW
AC
Installed by Year & Program Type
End of Calendar Year
NEB Tariff Rate
NEB kWh Credit
Renewable Procurement
2010
0.0
2.8
0.0
2011
0.0
1.2
0.0
2012
0.0
1.7
0.0
2013
0.0
2.6
0.0
2014
0.0
3.2
0.0
2015
0.0
5.9
0.0
2016
0.0
7.1
0.0
2017
0.0
8.5
0.0
2018
0.0
11.4
0.0
2019
1.1
12.9
9.9
2020
4.1
10.3
0.0
2021
34.6
38.5
34.2
2022
99.1
96.9
33.2
2023
173.5
102.7
0.0
Total
312.5
305.8
77.3
Sustainable Energy Advantage, LLC
28
Figure 6 –
Cumulative Maine Solar Development by Calendar Year and Program Type
Figure 7 –
Cumulative Maine Solar Development by Calendar Year and Program Type
Sustainable Energy Advantage, LLC
29
Likely drivers of the growth included the open-ended structure of the NEB program (i.e., no MW cap) with a large
addressable market and favorable economics; this occurred even with the headwinds of a difficult interconnection
environment.
As for adherence to Maine’s solar energy generation goals, goals A, E and F have been met by the large amount of in-state
solar development. Goal D (Ensuring that solar energy provides energy that benefits all ratepayers regardless of income
level) was more the focus of the Maine analysis, and it appears that the costs slightly outweigh the benefits from that
perspective. At this time, it is unclear whether goals B (Ensuring that the production of thermal energy from solar
technologies meaningfully contributes to reducing the State's dependence on imported energy sources) and C (Ensuring that
the production of electricity from solar energy meaningfully contributes to mitigating more costly transmission and
distribution investments otherwise needed for system reliability) have been met.
Sustainable Energy Advantage, LLC
A-1
A Appendix A – Component-level Results
A.1 Solar Programs (2023) – Societal Perspective
Component Category
Components
CMP –
Procurements
Versant - BHD -
Procurements
Versant - MPD -
Procurements
CMP - NEB
Versant - BHD
- NEB
Versant - MPD - NEB
Program Expense
Project PPA Expenses
$2,857,236
$1,018,934
$0
$54,379,441
$7,223,105
$3,543,866
Program Expense
Lost Utility Revenues
$0
$0
$0
$27,325,510
$5,694,226
$542,266
Program Expense
Program Admin
$0
$7,189
$0
$446,968
$162,403
$52,616
Energy Resale Revenue
Energy Resale Revenue
$1,648,637
$1,300,618
$0
$8,593,935
$1,240,664
$511,400
Capacity Benefits
Capacity Buyout
Revenue
$0
$0
$0
$0
$0
$0
T&D Benefits
Interconnection upgrade
benefits
$0
$0
$0
$6,663,326
$1,989,344
$0
Program Expense
Transmission integration
costs (Intrastate)
$31,523
$15,215
$0
$9,593
$1,267
$315
Program Expense
Transmission integration
costs (ROP)
$311,835
$150,515
$0
$123,204
$16,277
$4,041
Capacity Benefits
Uncleared capacity
value (Intrastate)
$0
$0
$0
$9,593
$1,267
$315
Capacity Benefits
Uncleared capacity
value (ROP)
$0
$0
$0
$123,204
$16,277
$4,041
Capacity Benefits
Reduced Share of
Capacity Costs
$0
$0
$0
$0
$0
$0
Energy Price
Suppression
Price suppression -
energy (Intrastate)
$232,798
$130,319
$0
$1,937,173
$260,531
$0
Energy Price
Suppression
Price suppression -
energy (ROP)
$1,474,944
$852,272
$0
$12,449,851
$1,670,161
$0
Capacity Benefits
Price suppression -
capacity (Intrastate)
$0
$0
$0
$46,911
$6,141
$0
Capacity Benefits
Price suppression -
capacity (ROP)
$0
$0
$0
$521,203
$68,230
$0
Energy Price
Suppression
Price suppression -
electric-gas (Intrastate)
$901
$522
$0
$7,931
$1,067
$0
Energy Price
Suppression
Price suppression -
electric-gas (ROP)
$13,638
$7,902
$0
$120,069
$16,147
$0
Energy Price
Suppression
Price suppression -
electric-gas-electric
(Intrastate)
$98,457
$58,710
$0
$855,751
$115,347
$0
Sustainable Energy Advantage, LLC
A-2
Component Category
Components
CMP –
Procurements
Versant - BHD -
Procurements
Versant - MPD -
Procurements
CMP - NEB
Versant - BHD
- NEB
Versant - MPD - NEB
Energy Price
Suppression
Price suppression -
electric-gas-electric
(ROP)
$640,330
$389,888
$0
$5,629,408
$757,005
$0
T&D Benefits
Reduced transmission
costs (Intrastate)
$0
$0
$0
$1,678,231
$325,135
$74,229
T&D Benefits
Reduced transmission
costs (ROP)
$0
$0
$0
$8,874,265
$1,216,837
$538,676
T&D Benefits
Reduced Share of
Transmission Costs
$0
$0
$0
$0
$0
$0
T&D Benefits
Reduced distribution
costs
$0
$0
$0
$5,885,169
$1,405,236
$173,193
T&D Benefits
Reduced T&D losses -
capacity (Intrastate)
$0
$0
$0
$1,229,774
$186,079
$69,526
T&D Benefits
Reduced T&D losses -
capacity (ROP)
$0
$0
$0
$488,640
$73,896
$27,131
T&D Benefits
Reduced T&D losses -
energy (Intrastate)
$0
$0
$0
$1,633,714
$248,569
$64,215
T&D Benefits
Reduced T&D losses -
energy (ROP)
$0
$0
$0
$2,201,128
$330,820
$83,902
GHG and
Environmental
Benefits
Non-embedded GHG
emissions
$2,773,911
$1,348,100
$0
$28,253,762
$3,976,400
$1,158,043
GHG and
Environmental
Benefits
NOx emissions
$42,544
$20,670
$0
$439,539
$61,860
$18,015
RPS Cost Reductions
Reduced RPS Obligation
$0
$0
$0
$0
$0
$0
RPS Cost Reductions
REC Price Suppression
(Intrastate)
$222,811
$107,546
$0
$2,277,241
$320,496
$93,338
RPS Cost Reductions
REC Price Suppression
(ROP)
$1,721,985
$831,160
$0
$17,599,534
$2,476,937
$721,356
Sustainable Energy Advantage, LLC
A-3
A.2 Solar Programs (2023) – Maine Perspective
Component Category
Components
CMP –
Procurements
Versant - BHD -
Procurements
Versant - MPD -
Procurements
CMP - NEB
Versant - BHD
- NEB
Versant - MPD - NEB
Program Expense
Project PPA Expenses
$2,857,236
$1,018,934
$0
$54,379,441
$7,223,105
$3,543,866
Program Expense
Lost Utility Revenues
$0
$0
$0
$27,325,510
$5,694,226
$542,266
Program Expense
Program Admin
$0
$7,189
$0
$446,968
$162,403
$52,616
Energy Resale Revenue
Energy Resale Revenue
$1,648,637
$1,300,618
$0
$8,593,935
$1,240,664
$511,400
Capacity Benefits
Capacity Buyout
Revenue
$0
$0
$0
$0
$0
$0
T&D Benefits
Interconnection upgrade
benefits
$0
$0
$0
$6,663,326
$1,989,344
$0
Program Expense
Transmission integration
costs (Intrastate)
$31,523
$15,215
$0
$9,593
$1,267
$315
Program Expense
Transmission integration
costs (ROP)
$0
$0
$0
$0
$0
$0
Capacity Benefits
Uncleared capacity
value (Intrastate)
$0
$0
$0
$9,593
$1,267
$315
Capacity Benefits
Uncleared capacity
value (ROP)
$0
$0
$0
$0
$0
$0
Capacity Benefits
Reduced Share of
Capacity Costs
$0
$0
$0
$341,246
$88,300
$8,639
Energy Price
Suppression
Price suppression -
energy (Intrastate)
$232,798
$130,319
$0
$1,937,173
$260,531
$0
Energy Price
Suppression
Price suppression -
energy (ROP)
$0
$0
$0
$0
$0
$0
Capacity Benefits
Price suppression -
capacity (Intrastate)
$0
$0
$0
$46,911
$6,141
$0
Capacity Benefits
Price suppression -
capacity (ROP)
$0
$0
$0
$0
$0
$0
Energy Price
Suppression
Price suppression -
electric-gas (Intrastate)
$901
$522
$0
$7,931
$1,067
$0
Energy Price
Suppression
Price suppression -
electric-gas (ROP)
$0
$0
$0
$0
$0
$0
Energy Price
Suppression
Price suppression -
electric-gas-electric
(Intrastate)
$98,457
$58,710
$0
$855,751
$115,347
$0
Sustainable Energy Advantage, LLC
A-4
Component Category
Components
CMP –
Procurements
Versant - BHD -
Procurements
Versant - MPD -
Procurements
CMP - NEB
Versant - BHD
- NEB
Versant - MPD - NEB
Energy Price
Suppression
Price suppression -
electric-gas-electric
(ROP)
$0
$0
$0
$0
$0
$0
T&D Benefits
Reduced transmission
costs (Intrastate)
$0
$0
$0
$1,678,231
$325,135
$74,229
T&D Benefits
Reduced transmission
costs (ROP)
$0
$0
$0
$0
$0
$0
T&D Benefits
Reduced Share of
Transmission Costs
$0
$0
$0
$1,939,873
$501,957
$49,109
T&D Benefits
Reduced distribution
costs
$0
$0
$0
$5,885,169
$1,405,236
$173,193
T&D Benefits
Reduced T&D losses -
capacity (Intrastate)
$0
$0
$0
$1,229,774
$186,079
$69,526
T&D Benefits
Reduced T&D losses -
capacity (ROP)
$0
$0
$0
$0
$0
$0
T&D Benefits
Reduced T&D losses -
energy (Intrastate)
$0
$0
$0
$1,633,714
$248,569
$64,215
T&D Benefits
Reduced T&D losses -
energy (ROP)
$0
$0
$0
$0
$0
$0
GHG and
Environmental
Benefits
Non-embedded GHG
emissions
$2,773,911
$1,348,100
$0
$28,253,762
$3,976,400
$1,158,043
GHG and
Environmental
Benefits
NOx emissions
$42,544
$20,670
$0
$439,539
$61,860
$18,015
RPS Cost Reductions
Reduced RPS Obligation
$0
$0
$0
$0
$0
$0
RPS Cost Reductions
REC Price Suppression
(Intrastate)
$222,811
$107,546
$0
$2,277,241
$320,496
$93,338
RPS Cost Reductions
REC Price Suppression
(ROP)
$0
$0
$0
$0
$0
$0
Sustainable Energy Advantage, LLC
A-5
A.3 Solar Programs (2023) – Ratepayer Perspective
Component Category
Components
CMP –
Procurements
Versant - BHD –
Procurements
Versant - MPD -
Procurements
CMP - NEB
Versant - BHD
- NEB
Versant - MPD - NEB
Program Expense
Project PPA Expenses
$2,857,236
$1,018,934
$0
$54,379,441
$7,223,105
$3,543,866
Program Expense
Lost Utility Revenues
$0
$0
$0
$27,325,510
$5,694,226
$542,266
Program Expense
Program Admin
$0
$7,189
$0
$446,968
$162,403
$52,616
Energy Resale Revenue
Energy Resale Revenue
$1,648,637
$1,300,618
$0
$8,593,935
$1,240,664
$511,400
Capacity Benefits
Capacity Buyout
Revenue
$0
$0
$0
$0
$0
$0
T&D Benefits
Interconnection upgrade
benefits
$0
$0
$0
$6,663,326
$1,989,344
$0
Program Expense
Transmission integration
costs (Intrastate)
$31,523
$15,215
$0
$9,593
$1,267
$315
Program Expense
Transmission integration
costs (ROP)
$0
$0
$0
$0
$0
$0
Capacity Benefits
Uncleared capacity
value (Intrastate)
$0
$0
$0
$9,593
$1,267
$315
Capacity Benefits
Uncleared capacity
value (ROP)
$0
$0
$0
$0
$0
$0
Capacity Benefits
Reduced Share of
Capacity Costs
$0
$0
$0
$341,246
$88,300
$8,639
Energy Price
Suppression
Price suppression -
energy (Intrastate)
$232,798
$130,319
$0
$1,937,173
$260,531
$0
Energy Price
Suppression
Price suppression -
energy (ROP)
$0
$0
$0
$0
$0
$0
Capacity Benefits
Price suppression -
capacity (Intrastate)
$0
$0
$0
$46,911
$6,141
$0
Capacity Benefits
Price suppression -
capacity (ROP)
$0
$0
$0
$0
$0
$0
Energy Price
Suppression
Price suppression -
electric-gas (Intrastate)
$901
$522
$0
$7,931
$1,067
$0
Energy Price
Suppression
Price suppression -
electric-gas (ROP)
$0
$0
$0
$0
$0
$0
Energy Price
Suppression
Price suppression -
electric-gas-electric
(Intrastate)
$98,457
$58,710
$0
$855,751
$115,347
$0
Sustainable Energy Advantage, LLC
A-6
Component Category
Components
CMP –
Procurements
Versant - BHD –
Procurements
Versant - MPD -
Procurements
CMP - NEB
Versant - BHD
- NEB
Versant - MPD - NEB
Energy Price
Suppression
Price suppression -
electric-gas-electric
(ROP)
$0
$0
$0
$0
$0
$0
T&D Benefits
Reduced transmission
costs (Intrastate)
$0
$0
$0
$1,678,231
$325,135
$74,229
T&D Benefits
Reduced transmission
costs (ROP)
$0
$0
$0
$0
$0
$0
T&D Benefits
Reduced Share of
Transmission Costs
$0
$0
$0
$1,939,873
$501,957
$49,109
T&D Benefits
Reduced distribution
costs
$0
$0
$0
$5,885,169
$1,405,236
$173,193
T&D Benefits
Reduced T&D losses -
capacity (Intrastate)
$0
$0
$0
$1,229,774
$186,079
$69,526
T&D Benefits
Reduced T&D losses -
capacity (ROP)
$0
$0
$0
$0
$0
$0
T&D Benefits
Reduced T&D losses -
energy (Intrastate)
$0
$0
$0
$1,633,714
$248,569
$64,215
T&D Benefits
Reduced T&D losses -
energy (ROP)
$0
$0
$0
$0
$0
$0
GHG and
Environmental
Benefits
Non-embedded GHG
emissions
$0
$0
$0
$0
$0
$0
GHG and
Environmental
Benefits
NOx emissions
$0
$0
$0
$0
$0
$0
RPS Cost Reductions
Reduced RPS Obligation
$0
$0
$0
$555,815
$132,715
$16,357
RPS Cost Reductions
REC Price Suppression
(Intrastate)
$222,811
$107,546
$0
$2,277,241
$320,496
$93,338
RPS Cost Reductions
REC Price Suppression
(ROP)
$0
$0
$0
$0
$0
$0
