market fundamentals #1, day two: and then there were three: … ma sms... · 2018. 1. 17. ·...

Copyright © Sustainable Energy Advantage, LLC.

Market Fundamentals #1, Day Two: And Then There Were Three: Welcoming SMART to the MA Solar Family

2017 Massachusetts Solar Market StudyMay 12, 2017


Overview – Day Two

• SMART◦ The “Known Knowns” (Program Development Status)

◦ The “Known Unknowns”, “Unknown Unknowns” and the Development of Scenarios)

◦ Analysis Methodology (and planned refinements) Cost Analysis

DBI Supply/Demand

Technical Potential

◦ Analytical Results Retail/Export Compensation Rate Forecasts

Cost of Entry (for BTM) and Levelized Cost of Energy (for Stand-alone)

Supply Composition

Block Clearing/Timing Results

Incentive Values by Segment by Quarter

◦ Discussion and Analysis of Results

2


Charting Risks and Uncertainties: Mapping SMART’s “Known Knowns, Known Unknowns and Unknown Unknowns”


The “Known Knowns”: Sources of SMART Near Certainty

4

• Program Type and Capacity◦ Baker Admin not interested in an SREC-III framework (despite the

multiple extensions of SREC-II)

◦ Program capacity expected to remain at 1,600 MW

◦ DOER expected to maintain 20% set-aside for residential <= 25 kW

• Two-Stage DOER Development/DPU Approval Process◦ If SREC-III not used, DPU must approve a tariff after DOER completes

rulemaking and EDCs complete Block 1 Procurement

• Use of Size-Based Base Incentives + Adders Framework◦ Stakeholders suggest DOER is unlikely change the proposed system of

Capacity-Based Incentives with location, offtaker and policy-based adders, or the proposed adder values


The “Known Knowns”: Sources of SMART Near Certainty

5

• Block 1 Procurement/Auction◦ DOER still expected to opt for EDC-driven 100 MW Block 1

Procurement◦ 1-2 MW value from procurement to be based (at least in part) on the

weighted average of the procured capacity on a statewide basis

• Land Use Subtractors◦ DOER expected to maintain the subtractor values, but minimize the

square footage impact to panel area

• Rate Design◦ Eversource likely will have an MMRC approved in late 2017/early 2018

• Availability of Net Metering Cap Space◦ SMART-incentivized systems (particularly in Eversource EMA territory)

will have access to Market Net Metering Credits (public and private) through at least 2018

◦ <=25 kW capacity will have net metering at G+T+T+D in perpetuity


The “Known Unknowns”: Sources of SMART Risk

6

• The BIGGEST: Block 1 Procurement◦ Will there be a higher procurement ceiling value, and how might it balance

with a “weighted average” approach?◦ How will the procurement actually shake out? Will the EDCs actually get 100

MW of bid-in capacity, or might larger projects stay in SREC-II, and they fall short? How might this affect the 1-2 MW segment?

◦ Will requiring only projects with ISAs, non-ministerial permits, etc. be enough to ensure that speculative bidding does not distort price outcomes?

• Attrition◦ Will attrition rates positively correlate with procurement clearing price? In

other words, will a low clearing price cause more attrition or will projects self-select out of not trying to qualify for a marginally uneconomic block?

• Land Use Subtractors◦ Systems not on “previously developed” land receive at least a “half-

subtractor” - how will “previously developed” be defined?


The “Known Unknowns”: Sources of SMART Risk

7

• Rate Design◦ How substantial will the actual Eversource EMA and WMECO MMRC be?

How might it be phased in?

• On-Bill Crediting Mechanism◦ What value will an on-bill credit be (e.g., Basic Service G rate or average

DA LMP)?◦ What limits will be placed on credit offtakers?◦ When would it be proposed, and by whom?◦ How the heck will it actually work?

• Storage◦ Is the storage adder the maximum (storage) compensation a owner can

receive beyond demand charge reduction, or can the storage receive ISO-NE market revenue as well?

◦ Will storage affect the deployment of solar projects under SMART?

• The Trump Factor◦ How might the new Administration approach corporate tax reform and

other federal tax benefits for solar?


• The General Court has indicated that it is waiting until the DOER emergency rulemaking to “weigh in” on SMART, but that it likely will.◦ Could the General Court choose to raise the net metering caps?

◦ Ask DOER to start over?

• Will someone sue over the on-bill credits, or the long-term contract element of the program? If so, will it pass legal muster?

• Could SMART get stuck in limbo SREC-II is open for business until 2028??? (Probably not, but you get the point…)

The “Unknown Unknowns”: Could it All Still Blow Up?

8


Analytical Methodology: Cost Analysis, Rate Forecasting, Supply/Demand and Technical Potential


Solar Cost Analysis Key Highlights: Market Segmentation

10

34 Distinct Project Types

5 EDCs (+ MLPs Treated as a Bloc)

3 Possible Ownership Types (3rd Party, Host, & Public)

SEA SMART DBI Cost Model (Across High, Medium & Low Cost Cases)

SEA SREC-II Cost Model (Across High, Medium & Low Cost Cases)

612 Supply Blocks, from 2014-2020

*Assumes separate forecast for Unitil & NGrid Nantucket, and a combined Eversource EMA post-rate case

66 Distinct Project Types

3 Main EDCs*3rd Party + Host Ownership Only

396 Supply Blocks, from 2018-2025


Solar Cost Analysis Key Highlights: Installed Costs

11

Range of Assumed 2018 Installed Capital Costs by Project Type

Broad Project Types

$/kWDC Range @

37.5th Percentile

(Base Cost Cases)

$/kWDC Range @ 12.5th

Percentile

(Low Cost Cases)

$/kWDC Range @

62.5th Percentile

(High Cost Cases)

<=25 kW (Residential & Small C&I) $3,186-$3,450 $2,842-$3,077 $3,569-$3,864

Building Mounted* (100 kW-2 MW) $1,897-$2,510 $1,771-$2,322 $2,034-$2,783

Solar Canopy (100 kW-2 MW) $2,754-$3,284 $2,585-$2,908 $2,880-$3,769

CSS** (1 MW-2.5 MW) $2,660-$2,936 $2,386-$2,526 $2,901-$3,014

Low Income CSS** (1 MW-2 MW) $2,646-$2,743 $2,317-$2,361 $2,767-$2,867

Greenfield Ground Mount (500 kW-4

MW)$2,105-$2,202 $1,776-$1,820 $2,226-$2,326

Landfill (1 MW-4 MW) $2,324-$2,334 $2,130-$2,138 $2,512-$2,571

Brownfield (1 MW-4 MW) $2,253-$2,337 $2,004-$2,057 $2,464-$2,531

*Includes on-site Low Income projects

**Includes SEA estimate of CSS incremental customer acquisition costs


Solar Cost Analysis Key Highlights: CSS Incremental Cost

12


Rate Forecasting Approach

13

• BTM incentive is a levelized value over the term of the incentive representing the difference between the value of the system + adder and the 3-year average of G+T+T+D

• Thus, rate forecasting is required to determine incentive requirement, as well as potential incentive value.

• Eversource rate case = source of uncertainty• To compare the rates currently active to the consolidated rates

proposed in the Rate Case, SEA unified the NSTAR R-1, R-2, G-1 & G-2 rates for BECo & CommElec (creating a new “Eversource EMA”)

• Rates were forecasted and escalated based on: ◦ An indexed wholesale energy forecast from SEA’s forthcoming Renewable Energy

Market Outlook (REMO) 2017 #1◦ An indexed transmission & distribution rate forecast based on the EIA’s Annual

Energy Outlook 2017 values for the Northeast; and,◦ Transition charges diminishing to zero (and charges related to renewables and

efficiency) held constant.

• SEA plans to revisit this forecast approach in coming SMS analyses


DBI “Supply/Demand/Incentive” Model

14

• Purpose of DBI model is to take the outputs from the cost model and determine which systems are most likely to be built ◦ For BTM: Model takes “Incentive Requirements” for each “supply block” and

compares them to available SMART program BTM incentives

◦ For Standalone: Model takes “Revenue Requirement” (for Standalone systems) for each “supply block” and compare them to expected SMART program “offer blocks”

• The process of comparing incentive requirements and revenue requirements with incentives is to compare the “Required NPV” per supply block, with the incentive’s “Expected NPV” on either the incentive requirement in a process known as “block clearing”

• The “block clearing” results are then able to show which systems will economically qualify in a given quarter, and what incentive are available on a very granular basis for each project in each quarter (key info for developers!)


Technical Potential

15

• DBI model assumes both a minimum and maximum possible MW of solar PV that can deploy in each supply block in each utility territory (to serve as growth “guardrails”)◦ Advantage of a minimum: ensures that sufficient capacity is deployed regardless of

economics (given that cost analysis results can sometimes overstate the actual ability of projects to deploy and meet investor returns in the process)

◦ Advantage of a maximum: ensures that the model does not oversaturate the program with one particular market subsector in one particular utility, or assume that a given sector has few realistic constraints

◦ E.g.: Post-1600 survey of developers found that several sectors were reaching greater saturation levels, SMART program design assumes fairly substantial land-use subtractors. Utilizing a maximum can ensure that these sectors do not (in some cases) over deploy relative to development “reality”.

• SEA approach to SREC-II technical potential: market was “functionally unconstrained”, given it was not at a high level of maturity

• Approach to SMART technical potential: use a mixture of sectors that are considered “functionally unconstrained”, and others that are constrained using minimum and maximum market shares◦ Maximum market shares based on (an extreme) assumption that a given sector could

comprise a majority of the program


Technical Potential

16

Market SubsectorApproach to Calculating

Maximum Share

Source for Starting or

Minimum Values

Deployment

Rate/Qtr.

<=25 kW (inc. Resi, Low-

Income Resi and Small C&I)

“Functionally

Unconstrained”

Assumed Starting

Block Size Post-SREC-II

Based on SREC-II

historic quarterly

growth rateBuilding Mounted (inc. On-

Site Low-Income >25 kW)

Solar Canopies

CSS/Off-Site Low Income

>25 kWConstrained based on

extreme cases (sector

receiving most SMART

program capacity)

SREC-II market share

(or slightly below)

Uniform

deployment per

quarter

Landfill/Brownfield

Ground Mount BTM

Large-Scale Greenfield


Initial SMART Scenario Matrix: PV Cost/Revenues

17

Scenario Name

Installed / O&M Cost

%tiles

Installed Cost Decline Rate (Smoothed)

IC Cost

%tiles

Retail Rates (for BTM Systems)

Export Compensation Pathway (for >25 kW BTM

Systems)

Assumed NMCredit Discounts

Base Case (Base Supply &

Attrition)

37.5th Redacted 50th

Status Quo (Eversource MMRC

Implemented)

Status Quo (Market NMCs Give Way to OBC at “G”

Rate)Redacted

High Supply/ Low Attrition

12.5th Redacted 25th Eversource MMRC Denied


Rate)Redacted

Low Supply/ High Attrition



Implemented)


Rate)Redacted

“Ugly” (SuperLow Supply/ Super High

Attrition)



Implemented)

Market NMCs Give Way to OBC at W/S

Redacted


Initial SMART Scenario Matrix: Policy/Market Outcomes

18

Scenario Name

Market “Ratchet”

Value (Clearing

Value for 1-2 MW)

>25 kW Block

Attrition %

Program Start

Timing

Federal Corporate Tax Reform

Outcome

Base Case

(Base Supply &

Attrition)

$130/MWh Medium (10%)

Q3 2018

Status Quo

High Supply/

Low Attrition$150/MWh Low (5%) Status Quo

Low Supply/

High Attrition$110/MWh High (20%)

Corporate Tax Rate Change

Phased in + FMV Approach to

ITC/MACRS Curtailed by IRS

“Ugly”

(Super Low

Supply/

Super High

Attrition)

$90/MWh Super High (30%)

Corporate Tax Rate Change

Phased in + ITC Eliminated Post-2018

+ FMV Approach to ITC/MACRS

Curtailed by IRS


Analytical Results: Supply Composition, Block Clearing/Timing and Incentive Availability


Caveats to Presented Results

20

• Incremental and cumulative “supply composition” totals represent the total capacity qualified, and their calendar quarter of qualification. They do not (yet) represent:

◦ Which projects within various project types will reach commercial operation (or when) in the original block the system qualified in (or in a different block); nor

◦ Which projects will fall out entirely and never reach commercial operation.

• Similarly, the supply composition by offer blocks values represent the capacity of systems that must qualify by block (and by when) to ensure the blocks fill with projects that are assumed to be economical. The timing of the clearing of each block is also based on when systems must qualify in order to receive allocation within a given block

• Incentive values represent the levelized available standalone or BTM incentive

◦ For a developer/financier’s purposes, the range between the minimum and maximum incentive values is similar to the range between the SREC-II ACP and the “soft floor”

◦ In essence, the “minimum” incentive values are intended to represent the most conservative estimate of the levelized available incentive by project (and thus are the value a financier will most likely use – much like the “soft floor” in SREC-II)

◦ However, some minimums won’t apply to certain project supply blocks because those minimums may be associated with a subtractor for certain project types


Overarching Observations

21

• BTM systems (and particularly <=25 kW within that subset) are likely to dominate the program under nearly all cases surveyed. The dominance of the BTM portion of the market is driven largely by a mixture of 1) the permanence of near-retail net metering for <=25 kW systems, as well as the existence of an on-bill crediting mechanism equal to the Basic Service or “G” rate for the fast-moving Building Mounted subsector

• The relatively high rates proposed for exported generation proposed for the program for both <=25 kW and >25 kW systems result in their “cost of entry” (the amount of program incentive required to meet investor returns) being well below even the lowest incentives available under the program

• The 1-2 MW clearing price of the 100 MW Block 1 procurement will dictate the pace of the market. In the base case (with a clearing value of $130/MWh), we forecast the program would clear Block 8 by Q1 2022. With clearing price at the proposed ceiling price of $150/MWh, the market will qualify sufficient systems to clear Block 8 by Q4 2020, and by Q1 2025 in the “ugly” case (where it clears at $90/MWh)

• The is likely to determine whether or not standalone systems (including major SREC-II subsectors like CSS, Low Income, Landfill/Brownfield, and Large-Scale Greenfield) will have any chance of covering their costs and meeting investor returns

• In the absence of a procurement clearing price near the proposed ceiling price, it is unlikely that many standalone projects will generally thrive in the marketplace without substantial price cuts. However, given that developers have shown resourcefulness in cutting costs before, SEA is tentatively using its minimum technical potential value to approximate SREC-II market shares for these projects, so as to account for this uncertainty


Rate Forecasting: R-1 & R-2 Low Income (All EDCs)

22


Rate Forecasting: G-1 (All EDCs)

27


NGRID BTM Cost of Entry – Base Case

32


NGRID BTM Cost of Entry – “Ugly” Case

33

Market Sector Project Type 2018 2019 2020 2021 2022 2023 2024 2025

Medium Cost Residential Roof Mount (7 kW) -$ 34$ -$ -$ -$ -$ -$ -$

Medium Cost Residential Roof Mount Low

Income (7 kW) 107$ 155$ 123$ 88$ 59$ 20$ -$ -$

Medium Cost Small C&I (15 kW) 77$ 121$ 87$ 51$ 20$ -$ -$ -$

Commercial Lot Canopy (100 kW) 176$ 223$ 192$ 159$ 121$ 87$ 60$ 33$

Commercial Lot Canopy (1 MW) 77$ 115$ 89$ 61$ 29$ -$ -$ -$

Campus Lot Canopy (1 MW) 77$ 115$ 89$ 61$ 29$ -$ -$ -$

Industrial Lot Canopy 86$ 121$ 96$ 69$ 39$ 9$ -$ -$

On-Site Low Income (100 kW) 147$ 181$ 157$ 130$ 100$ 73$ 50$ 28$

Medium Cost Small Building Mounted (100 kW) 147$ 181$ 157$ 130$ 100$ 73$ 50$ 28$

Medium Cost Medium Building Mounted (500 kW) 60$ 86$ 64$ 41$ 16$ -$ -$ -$

Large Building Mounted (1 MW) 60$ 90$ 69$ 48$ 22$ -$ -$ -$

Ginormous Building Mounted (2 MW) 47$ 70$ 51$ 30$ 6$ -$ -$ -$

Medium Ground Mount BTM (500 kW) 113$ 141$ 121$ 98$ 71$ 46$ 25$ 5$

Large Ground Mount BTM (2 MW) 63$ 93$ 72$ 50$ 24$ 1$ -$ -$

<=25 kW

Solar

Canopies

Building

Mounted

Ground Mount

BTM

BTM Cost of Entry - "Ugly" (Super Low Supply/Super High Attrition)


Available BTM Incentives by Quarter (Base Case – NGrid & Eversource EMA)

34

NGRID Base Case

(Minimum Value)

Final Quarter of

Incentive Availability:

Q1 2022



34

NGRID Base Case

(Minimum Value)

Final Quarter of


Q1 2022

NGRID Base Case

(Maximum Value)



34

NGRID Base Case

(Minimum Value)

Final Quarter of


Q1 2022

NGRID Base Case

(Maximum Value)

Eversource EMA

Base Case

(Minimum Value)



34

NGRID Base Case

(Minimum Value)

Final Quarter of


Q1 2022

NGRID Base Case

(Maximum Value)

Eversource EMA

Base Case

(Minimum Value)

Eversource EMA

Base Case

(Maximum

Segment Incentive

Value)


Available Standalone Incentives by Quarter (All Cases/Non-Unitil/Nantucket EDCs)

38

Case #1: Base

Supply & Attrition

(Minimum Value,

All EDCs)

Final Quarter of


Q1 2022



38

Case #1: Base

Supply & Attrition

(Minimum Value,

All EDCs)

Final Quarter of


Q1 2022

Case #1: Base

Supply & Attrition

(Maximum Value,

All EDCs)



38

Case #1: Base

Supply & Attrition

(Minimum Value,

All EDCs)

Final Quarter of


Q1 2022

Final Quarter of


Q4 2020

Case #1: Base

Supply & Attrition

(Maximum Value,

All EDCs)

Case #2: High

Supply/Low

Attrition

(Minimum Value,

All EDCs)



38

Case #1: Base

Supply & Attrition

(Minimum Value,

All EDCs)

Final Quarter of


Q1 2022

Final Quarter of


Q4 2020

Case #1: Base

Supply & Attrition

(Maximum Value,

All EDCs)

Case #2: High

Supply/Low

Attrition

(Minimum Value,

All EDCs)

Case #2: High

Supply/Low

Attrition

(Maximum Value,

All EDCs)



38

Case #1: Base

Supply & Attrition

(Minimum Value,

All EDCs)

Final Quarter of


Q1 2022

Final Quarter of


Q4 2020

Final Quarter of


Q1 2023

Case #1: Base

Supply & Attrition

(Maximum Value,

All EDCs)

Case #2: High

Supply/Low

Attrition

(Minimum Value,

All EDCs)

Case #2: High

Supply/Low

Attrition

(Maximum Value,

All EDCs)

Case #3: Low

Supply/High

Attrition

(Minimum Value,

All EDCs)



38

Case #1: Base

Supply & Attrition

(Minimum Value,

All EDCs)

Final Quarter of


Q1 2022

Final Quarter of


Q4 2020

Final Quarter of


Q1 2023

Case #1: Base

Supply & Attrition

(Maximum Value,

All EDCs)

Case #2: High

Supply/Low

Attrition

(Minimum Value,

All EDCs)

Case #2: High

Supply/Low

Attrition

(Maximum Value,

All EDCs)

Case #3: Low

Supply/High

Attrition

(Minimum Value,

All EDCs)

Case #3: Low

Supply/High

Attrition

(Maximum Value,

All EDCs)



38

Case #1: Base

Supply & Attrition

(Minimum Value,

All EDCs)

Final Quarter of


Q1 2022

Final Quarter of


Q4 2020

Final Quarter of


Q1 2023

Final Quarter of


Q3 2024

Case #1: Base

Supply & Attrition

(Maximum Value,

All EDCs)

Case #2: High

Supply/Low

Attrition

(Minimum Value,

All EDCs)

Case #2: High

Supply/Low

Attrition

(Maximum Value,

All EDCs)

Case #3: Low

Supply/High

Attrition

(Minimum Value,

All EDCs)

Case #3: Low

Supply/High

Attrition

(Maximum Value,

All EDCs)

Case #4: “Ugly”

(Minimum Value,

All EDCs)



38

Case #1: Base

Supply & Attrition

(Minimum Value,

All EDCs)

Final Quarter of


Q1 2022

Final Quarter of


Q4 2020

Final Quarter of


Q1 2023

Final Quarter of


Q3 2024

Case #1: Base

Supply & Attrition

(Maximum Value,

All EDCs)

Case #2: High

Supply/Low

Attrition

(Minimum Value,

All EDCs)

Case #2: High

Supply/Low

Attrition

(Maximum Value,

All EDCs)

Case #3: Low

Supply/High

Attrition

(Minimum Value,

All EDCs)

Case #3: Low

Supply/High

Attrition

(Maximum Value,

All EDCs)

Case #4: “Ugly”

(Minimum Value,

All EDCs)

Case #4: “Ugly”

(Maximum Value,

All EDCs)


Supply Composition

39

Base Case (Base

Supply & Attrition)


Supply Composition

39

Base Case (Base

Supply & Attrition)

High Supply/

Low Attrition


Supply Composition

39

Base Case (Base

Supply & Attrition)

High Supply/

Low Attrition

Low Supply/

High Attrition


Supply Composition

39

Base Case (Base

Supply & Attrition)

High Supply/

Low Attrition

Low Supply/

High Attrition

“Ugly” (Super Low

Supply/Super High

Attrition)


Supply Composition/Block Timing (NGRID as Example)

43

Base Case (Base Supply & Attrition)



43

Base Case (Base Supply & Attrition)High Supply/Low Attrition



43

Base Case (Base Supply & Attrition)High Supply/Low AttritionLow Supply/High Attrition



43

Base Case (Base Supply & Attrition)High Supply/Low AttritionLow Supply/High Attrition“Ugly” (Super Low Supply/Super High Attrition)


Discussion/Analysis of Results: The Winners and the Losers


The Winners … and the Losers

• Winners◦ Low-income: they have more of a

premium than necessary

◦ Preferentially sited projects with offtaker adders: Potentially the combined revenue may override a challenging base rate compensation

◦ EDCs: they get their tariffed rates and the initial auction, and pushing projects to be sized to load

◦ DOER: Will hand off many implementation headaches to the 3rd

party administrator Though it might kill them to get there

◦ Consultants: if it were easy then DOER and you wouldn’t need a consultant

◦ All BTM sectors: if you believe that the 3-year average G+T+T+D upon which incentives are near their low point

• Losers◦ Greenfield projects: the subtractor

hurt a lot

◦ Community Shared Solar: it does not look like the CSS premium will cover the cost of all the logistics associated maintaining participants

◦ Offtakers: As the project economics get squeezed, the virtual offtakers (which include many public entities) may lose any leverage, particularly with QF option that gets the project the owner equivalent revenue

◦ MLPs: they lost their free ride

◦ G-1 BTM sectors: if you believe that the 3-year average G+T+T+D upon which incentives are near their highpoint

55


NGRID Benchmarks

(Used in All Cases)

BTM Incentive Benchmarks (3-Year G+T+T+D Averages)

49


NGRID Benchmarks

(Used in All Cases)

Eversource EMA

Benchmarks Based on

Current Rates (Used in

High Supply/

Low Attrition Case


49


NGRID Benchmarks

(Used in All Cases)

Eversource EMA

Benchmarks Based on


High Supply/

Low Attrition Case

Eversource EMA

Benchmarks Based on

Proposed Rates

w/MMRC (Used in

Base Case and Low

Supply Cases)


49


NGRID Benchmarks

(Used in All Cases)

Eversource EMA

Benchmarks Based on


High Supply/

Low Attrition Case

Eversource EMA

Benchmarks Based on

Proposed Rates

w/MMRC (Used in

Base Case and Low

Supply Cases)

WMECO Benchmarks

Based on Current

Rates (Used in High

Supply/

Low Attrition Case


49


NGRID Benchmarks

(Used in All Cases)

Eversource EMA

Benchmarks Based on


High Supply/

Low Attrition Case

Eversource EMA

Benchmarks Based on

Proposed Rates

w/MMRC (Used in

Base Case and Low

Supply Cases)

WMECO Benchmarks

Based on Current

Rates (Used in High

Supply/

Low Attrition Case

WMECO Benchmarks

Based on Proposed

Rates w/MMRC (Used

in Base Case and Low

Supply Cases)


49


Limitations and Future Refinements


Storage

• Assumption for the first model is that storage would have no material impact on deployment (i.e., the economics that drive which supply blocks are deployed and when they are deployed)

• Our goal is to incorporate storage COEs / LCOEs into the SMART analysis. To get there we plan to:◦ Speak with you and other market participants about drivers and

analysis needs regarding storage

◦ Analyze storage and its interactions with the SMART program in Q3 Market Brief

◦ Incorporate storage options into the SMART DBI model for Market Fundamentals #3

62


Areas for Model Improvement

• Freshest and Bestest Data & Trajectories◦ Costs

◦ Financing

◦ Technical potential

◦ Storage (again)

• Rate Forecasting

• Model Structure◦ Interconnection constraints

Including utility capability to deal with SREC-II slop-over and SMART interconnecting simultaneously

◦ Probability of success

63

Your and other market participants thoughts will help drive SEA’s SMART DBI modeling. We look forward to reaching out and getting your input.

Sustainable Energy Advantage, LLC161 Worcester Road, Suite 503

Framingham, MA 01701http://www.seadvantage.com

Tom MichelmanSenior Director 508-665-5854 [email protected]

Jim KennerlyConsultant 508-665-5856 [email protected]

Contacts:

Ted SnookAnalyst 508-665-5868 [email protected]

Benjamin WaltonMarket Analyst Fellow 508-665-5869 [email protected]

http://www.seadvantage.com/

mailto:[email protected]





Appendix A: Rate Forecasting: G-2 (All EDCs)

58


More Detail to Rate Forecasting Approach

63

For Behind the Meter (BTM) systems, the SMART Incentive is calculated:

BTM Solar Generation Unit Compensation Rate = (Capacity Based Rate + Adders) – (3 Year Average of Volumetric Delivery Rates +

3 Year Average of Basic Service Rate)

The incentive is constant over time, and sits atop whatever the value of energy is at that time, as shown below, in a graph produced by DOER and distributed in their January 31st presentation on the program.

Redacted

http://www.mass.gov/eea/docs/doer/rps-aps/final-program-design-1-31-17.pdf

market fundamentals #1, day two: and then there were three: … ma sms... · 2018. 1. 17. ·...

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