Susan Hudson
Vermont Public Service Board
112 State Street, Drawer 20
Montpelier, VT 05620-2701
Re: Docket 7523
Implementation of Standard Offer Prices for Sustainably Priced Energy Enterprise
Development (SPEED) Resources
Following please find comments from Daniel L. Scruton for the Vermont Agency of
Agriculture, Food and Markets. Comments, as appropriate, are after the question from the list
and in bold typeface.
Docket 7523 - Issues List
Renewable Cost Issues
1. Gathering data on costs of different renewable sources
a. Is there publicly available information that the Board can rely upon? If so, how can we access
and apply the information?
b. Do earlier Board dockets provide useful cost data on renewable energy projects? If so, which
ones and what data?
c. If not, should we require information from all developers/vendors?
There needs to be information gathered for each technology that justifies the price when
we comment on Docket 7533. For this docket there should only be data required from a
particular technology if there is compelling questions as to the reasonableness of the
prices stated in the legislation.
d. Confidentiality - should some data be protected? If so, how do other parties evaluate?
There will be some data that is confidential and needs to be protected as with any other
docket. However, for the purposes of this docket it would be reasonable for the board to
ask for a generic version of the data that could be shared at least in an aggregate form to
allow all parties to see the substance of the testimony. I see this as more of a concern in
Docket 7533.
e. Will electric utilities be required to disclose their cost of renewable energy projects that they
construct?
Utilities should be required to release data in the same fashion as any other project that
may require them, and others to submit two versions of their testimony so the Board has a
version that can be shown publically that the board rules sufficient for conveying the
substance of the project but perhaps without some of the detailed proprietary
information.
2. Evaluation of data
a. The Board is considering hiring a contractor to assist with data development and analysis.
Are there any issues with this approach?
It would seem logical that the Board needs to hire an economist and perhaps a contract or
other specialist with renewable energy experience to help them through this process.
b. What process should the Board employ to obtain input from developers/vendors and other
stake holders?
The workshop format with written comments that go to all interested parties is a good
format for this docket. Docket 7533 should be a more formal docket with hearings on
specific technology pricing needs. 7533 will need more precise data-sets to get to the
proper granularity. Standardization of terms need to be set so that each technology can
present data in a uniform fashion. As an example, there needs to be agreement on what
return on equity means and how that is calculated.
c. What is the standard of review that the Board should employ when looking at cost data?
Should the Board only alter the statutory prices if it finds a major difference?
For this docket the prices in the legislation should be deemed adequate unless there is
compelling evidence presented that they are significantly wrong. For farm methane
projects the price n the legislation is likely low for small farms. We have been working
with Glenn Rogers of UVM Extension to determine the economics on the existing dairies
that have at least one year of data and should have that ready for 7533 and will probably
be presenting an approach that has three tiers for different sized systems, but for 7523 we
consider the price in the legislation reasonable for the short period of time it will be in
force.
d. How will the Board determine whether new deployment or the pace of new deployment of
renewable projects is occurring as a direct result of the Standard Offer?
The number of systems that apply for contracts will be the initial indicator of interest but
the best marker will be the amount of power that comes on-line with SPEED contracts.
3. What level of granularity should prices have? One for each type of resource, or different
prices based upon certain characteristics?
To encourage the technology on the average farm there will need to be granularity. We
anticipate the data will support three levels based on kW output of the system. The
average size dairy farm in Vermont is around 130 cows. To achieve about a 10% return
on investment the price of power will need to be significantly higher for a 200 cow (40kW)
farm than for a farm with 1000 cows (200kW).
a. If we aim for granularity, is there enough data to support each set of prices?
Farm systems for this stage of the process will accept the $0.12 per kWh plus the amount
of the REC should the farm decide to sell it. For 7533 we will have an economist, Glenn
Rogers, work with other experts in the field to develop data sets to determine the logical
price points and appropriate sizes to recommend to the Board.
b. What costs, and thus prices, of different capacity sized plans of the different renewable
resources should be addressed?
Each technology will need to make their case to the Board for size and develop the data to
support those divisions.
c. What is the appropriate capacity differentiation?
The approach needs to be technology dependent. Each technology needs to look at their
data sets and decide what makes the most sense. After the data is presented in 7533 there
may be some similarities in the economy of scale that supports a similar size breakdown
for different technologies.
d. How will the Board determine the price for each type of technology?
For this docket, considering the short time window, the majorities of the time allowed
should be spent on determining process and use the prices in the legislation until 7533 is
completed.
4. How do we value the tax credits and other support, such as grant programs?
Each technology will have different grants and credits available. For some technologies
the grants are dependent on the location and owner of the technology. An example would
a farm that may have access to USDA Rural Development grants that a homeowner or
other business might not be able to access. The Board is going to have to look at those and
do some averaging so that there is one price per size unit of a particular technology and
not have to look at each system. The alternative would be too burdensome both for the
Board and applicant as both would need to gather data to support the different prices.
There are practical realities in how much time the Board can spend on each system. A
standard offer is supposed to simplify the process and predictability of outcome not make
it more complex.
a. What credits and grants are available?
Credits and grants and different for various technologies and vary with where they are
located. Each technology will need to present what is available so that the Board can
determine a factor for what is likely available. Grants also are often competitive and may
change as the priorities of the grantors changes. What is available today may change
significantly by next year. These are all issues that need to be explored in 7533.
b. Should standard offers differentiate between plants that can and cannot take advantage of tax
credit(s) available?
In the end, the Board needs to develop a set of prices that are available and will need to
protect against having to custom design a rate for each facility. It may not be practical to
try and predict into a standard offer if a particular tax credit will be useable or not.
5. How should the Board value the cost of any system impact or facilities or stability studies
required in order to interconnect? In particular, does this create a barrier for smaller projects?
The safety and stability of the system should not be compromised to make this tariff work.
Projects that are large enough to need the studies need to be able to pay for the studies.
There should be systems that do not need such studies that meet criterion that they are
small enough in proportion to the system they are interconnecting that the Board exempts
them from studies unless the serving utility shows a compelling need.
a. What share of the interconnection costs should be borne by the project developer?
If the study is needed, as determined by the Board, than the developer should pay the cost.
That cost should be built into the system cost when determining the appropriate rate. If
the utility wishes to do a study that is not related to a particular project but rather a
group of projects than the Board should allow them to do those studies and recover the
cost in rates.
6. How should the Board determine the return on equity for purposes of setting a standard rate?
The Board needs to issues guidelines, including the acceptable rate and how they allow
utilities to determine return on equity. If no such guidelines exist they need to be
developed based on how the investor owned utilities are allowed to do it. This will assure
that the data presented is done so in a consistent fashion that is understood by all parties.
This is going to become critical to Docket 7533.
a. What proportion of the cost should be assumed to be equity?
Once the guidelines suggested in 6 are established this should be easy to determine but
will vary with individual technologies.
7. How should the Board calculate the adjustment factor so that prices are high enough, but not
excessive?
There are apt to be three rates for each technology to accommodate economies of scale, to
factor more adjustments onto those could prove onerous and make the feed in tariff too
complicated to easily administer.
a. Should this adjustment factor incorporate an incentive associated with production at the most
valuable times (i.e., peak) or associated with the geographic location of the generation unit (i.e.,
constrained areas)?
Peak adjustments should be done at the discretion of the utility in excess of the base rate
to encourage peak production on technologies that can control when they produce power.
Encouraging production in constrained areas should be done with other venues such as
extra grants that do not count against the price paid for the power to allow an
incrementally higher return on equity without complicating the SPEED process further.
8. How should the Board incorporate wheeling charges for power purchased pursuant to a
standard offer contract?
The wheeling issues will be addressed in a subcommittee but I urge a “keep it simple”
approach where the wheeling, loses and other costs of moving this power be done in a
fashion that prorates the net difference across all utilities and is not factored into the price
to producers. In the end it does not matter as it is ultimately the ratepayers who bear
these costs. If it is charged to the project than the price paid to the project goes up to
maintain the allowed return on equity, if charged to the utility it is a recoverable expense
and builds into the retail tariff.
a. Can these charges be minimized or avoided and still be consistent with FERC requirements?
b. If strategies can be developed to minimize or avoid wheeling charges, will they be
precedential and what are the long-term policy implications?
c. Should system avoided losses be incorporates as well?
d. Do FERC requirements apply in the case of distribution connected generation?
Implementation Issues
9. Under the statute, the utilities receive RECs associated with SPEED projects.
a. Should the owner be required to apply for RECs and, if so, for resale into what markets?
The Board should require the developer to cooperate with the serving utility but the
producer should not have to spend any money or extra equipment to make the RECs
certifiable. Any cost associated with making the RECs certifiable should be born by the
pro-rated group that will own those RECs.
b. Should the producers have affirmative obligations to work with the utilities to assist in the
sale and retirement of RECs and other attributes associated with power purchased under a
standard offer contract?
The only obligation should be one of cooperation, not cost.
c. Should the attribute be tracked in the NEPOOL GIS?
d. Should the Board create a mechanism to ensure that REC’s are not claimed by more than one
party?
Yes
e. How will we ensure that those developing projects are given adequate notice that
participation in the standard offer program limits their ability to make claims regarding on-site
renewable energy use?
We have been educating farm projects on this and it is not a hard distinction for anyone
to understand. They can say they are producing renewable power but unless they are a
farm customer and choose to keep their RECs or they buy them back from the group they
cannot say they are using renewable power beyond their serving utility’s mix percentage.
10. Similarly, for capacity, ancillary services and other products including emerging products,
are there any steps that need to be taken to assure that utilities receive any associated payments
or credits?
This should go to a committee to flush out the potential items and money to see if they
should be somehow accounted for.
a. Should the asset be administered in the ISO system or remain outside the ISO system and be
treated as a load reducer?
11. Project Eligibility Issues
a. What steps must a developer take to qualify for the rates in effect at a particular point in
time? Contract? Construction? CPG? Letter of intent? Who will manage the queue?
Place in line should be based on a particular point in the process where the project has a
“demonstrated probability” that is going to be built. If grants requiring a letter of intent
of power purchasing is required, they would go into the line and receive the letter. As soon
as they get notified of the grant outcome they either remain in the queue or are removed
until they trigger another point in time that shows the process is moving forward such as
the first hearing of the 248 process would be when they could apply for a contract that
would not be awarded until the CPG is granted.
b. What process should the Board put in place to allow developers who want to put projects into
service if the interim rates are set in September? Should the Board develop a separate project
queue for such projects? Would this be consistent with the statute?
The board needs to rule on a starting date. For non-utility projects it is unclear in the
legislation. Logical date would be that the projects need to have come on-line after
January 1, 2005 (The year the Speed program came into existence) and as soon as the
board has a process, those projects with CPGs in place could apply to the Speed
Facilitator for a contract. To require the project come on line after September of this year
would penalize the innovators and slow down projects that are actively under
construction. If they have contract for power now they would have to negotiate for release
of those or wait until they naturally lapse.
c. How long can a developer hold a rate, or their spot in the queue?
Projects in the queue should be reviewed every six months to assure they are actively
moving forward and can demonstrate a probability of success. If they are not actively
moving the process along they will be moved to the back of line. If they have their CPG
but have not started construction they will be moved to the back of line. If they are
actively under construction the Board will grant a reasonable length of time to complete
the project or they will move to the back of line but not out of the program if the 50
megawatt cap has been reached unless the Board rules the project is not going to be
completed.
d. Should there be two queue’s, one for rate, and one for interconnection?
No, the interconnection would be based on the 248 process utilized. The power contract
queue with the Speed facilitator should be the only queue.
e. Should there be formal eligibility requirements for contract award or participation in the
program? If so, what should these eligibility requirements be? Should they vary by technology?
There should be requirements stated by the board by technology but they only need to be
broadly stated.
f. Given the limits on the program size is there need to prevent strategic behavior (e.g.,
hoarding of contracts or project queue positions)? If so, how can this be done without creating
excessive barriers to entry? Should some form of security be required or the proponent be
required to demonstrate that they have advanced the development of the project?
The grants available may dictate a need for a letter of intent for projects that have specific
grants they are applying too. For farmer methane projects USDA can be a slow and
onerous process but projects coming into the Speed program would score very well and
have a good probability of being funded with the letter of intent. If no letter of intent is
going to be issued than the power price to farmers should be based without the USDA
grant as they will not score well without a power contract letter of intent. If the letter of
intent is issued it would only reserve the space until the grant source is heard from. If no
grant is given then they need to get in line with other technologies. Technologies not
needing a letter of intent would get into the queue when they have filed for the
appropriate 248 process and are far enough along (Except for 248j) to have had a hearing
called. Also no one developer should have more than 5 megawatts of development in
docket at the same time and no one technology should be allowed to obtain more than
30% of the cap at least until the next rate review in January 2012.
g. How should the Board address the fact that the standard offer must be in place until 50 MW
have been commissioned (not approved)? Does the standard offer need to contain provisions so
that only the first 50 MW qualify for the rates?
The Speed facilitator would continue to allow projects into the queue until the 50
megawatts are on-line. Once the cap has been reached with projects that have been
offered contracts, no other contracts are offered unless a project does not get approved or
fails to show progress at their 6 month evaluation. All projects in the queue are notified
once the cap has been reached and given the option to stay in the queue or go to the open
market for a contract.
h. Should the Board reserve a portion of the 50 MW for smaller projects or projects from
particular types of resources? What shares should be so reserved?
No one technology should be allowed to develop more than 30% of the projects. This will
help assure there is a diverse set of technologies developed and be less prone to wide
swings if problems with that technology develop.
i. How should the Board factor in utility projects (that may reduce the 50 MW maximum)?
i. Should the entire project count towards the owning utility's cap, or should only their load
share (percentage) count toward the cap?
All Speed projects that are prorated for rate purposes should be prorated for cap
purposes.
j. Can existing facilities, such as net metering projects, qualify for the new SPEED rates?
Should refurbished projects or the output from expanded projects be able to participate?
Logical date would be the projects need to have come on-line after January 1, 2005 (The
year the Speed program came into existence) and as soon as the board has a process, those
projects with CPGs in place could apply to the Speed Facilitator for a contract. To
require the project come on line after September of this year would penalize the
innovators that jumped out ahead and slow down projects that are actively under
construction. If they have contract for power now they would have to negotiate for release
of those or wait until they naturally lapse. Net meter projects would have to file for a
modification to the CPG and, if granted, be allowed to receive a Speed contract. Projects
started after September of 2009 would not be allowed to switch so that we do not get
projects using net metering to bypass the normal 248 process.
k. On a going-forward basis, what is the interrelationship between the Standard Offer Contract
and the SPEED and net-metering programs?
Net metering is a separate but of value moving forward. The Standard offer is part of
SPEED.
l. Should the Board set a minimum kW size to qualify?
i. Should the Board set qualifications criteria that are inclusive of residential scale systems?
12. How should future renewable energy technology be considered or addressed?
The legislation lists specific technologies and I think that new technologies would need to
convince the legislature they are ready. Otherwise technologies that are really still
research projects in action would come in for a guaranteed 10%+ return on equity.
13. Interconnection. Is it necessary or appropriate to revise the Board's interconnection rule for
smaller (150 kw or less) renewable projects?
Interconnection rules are already in place and have been successfully utilized. It would be
appropriate for the board to allow a fast-track approach to systems of 250 kW or less with
a hearing process and application the same as the net metering application. This would
also alleviate some of the backlog of PSB time that might occur if all systems went
through the full 248 or 248j process.
a. Should the Board reconsider its net-metering interconnection standards under Rule 5.100 and
the terms and conditions of the interconnection Rule 5.500 to create a unified interconnection
standard for all interconnected electric generation?
There is no need to reconsider them. If someone has a specific concern they can already go
to the board to consider a change to the rule. But, that would be a separate docket.
b. Should interconnection of projects with a capacity of 250 kW and less follow the net
metering rule?
Yes, if the power company or a neighbor has a concern they can ask for hearings and will
be heard but for uncontested projects it would significantly streamline the process..
c. Should there be a different interconnection rule for different technologies?
Only if a technology can show the existing standards do not work for them and that
should be a separate docket.
14. What, if any, standard should the Board adopt for metering and reporting of SPEED
projects eligible for the cost-based pricing under a Standard Offer Contract?
The metering would need to meet the same accuracy standards as the meters already used
to sell power to customers.
a. Who will be responsible for metering and reporting in connection with standard offer power
allocated by the SPEED Facilitator to utilities?
The serving utility would be responsible for meter reading and reporting to the speed
facilitator with the producer paying a reasonable fee for the metering.
15. The statute specifies that the term of the contract varies from 10 to 25 years. Who should
decide on the duration?
The seller should be able to specify within the legislatively stated range. In the case of
farm systems they are being asked to risk changes in REC and attribute prices as well as
locking in at a particular rate. The producer should be allowed to decide how much risk
they want to take.
16. Do all projects have to apply under Title 30, Section 248 (or 248(j))?
a. Do all projects apply under Board Rule 5.500?
b. Is the Board prepared to handle a large quantity of Section 248 or 248(j)
dockets, and is there potential to delay other Utility 248 requests for
infrastructure upgrades?
c. Is the applicant subject to the standard rate at the time of application or
approval in the event of an unusual delay in granting a Section 248 permit?
The applicant should go into the queue and the rate set upon approval to go into the
queue. The six month review process stated above would then be set in motion.
17. Should this proceeding address the development of a Section 248 permitting
process for standard offer plants that is similar to what is done for net metered
systems? If so, what is the appropriate avenue for developing such a review
process?
Systems of less than 250 kW should use the net metering application process and then be
expanded if there are concerns expressed by the notified parties. There is no need for
developing a new process.
18. If farm methane projects are allowed to retain ownership of the RECs:
a. Will this require a separate standard contract for farm methane projects?
The price paid to farms coming out of the 7533 hearings will have about the same rate of
return as the rest including the value of the REC. The only difference in the contract will
be the REC and attribute ownership. A single contract with sections that change with
technologies should be able to be developed with little trouble.
b. Should the value of the RECs be included in determining an appropriate rate for methane
projects?
Yes, the value of potential RECs should be included but it not always $.04 per kWh. Those
details can be taken care of in Docket 7533. It is likely that in 20 years RECS will have
little value as a higher percent of renewable come on line.
19. The eligibility date for standard offer contracts for non-utility-owned plants is not clearly
listed in the statute, thus the PSB may need to make a determination on the eligibility date for
non-utility plants as soon as possible.
a. What date should be selected?
January 1, 2005 see answers to 11 b and j.
b. What criteria should the Board employ in determining an eligibility date?
The date is to encourage implementation of renewable technologies not to discourage
those who have been pro-active and stepped out on the limb. The current drop in
wholesale power prices are putting several farm projects in the situation where they are
losing significant amounts of money and may well shut down if they are not allowed to
migrate to this program.
c. How should this Board establish, as quickly as possible, parameters that will enable project
development to continue without a construction season hiatus while we work out the standard
offer program process?
The board should put out this ruling in pieces. First drafted should be the findings on a
start date for eligible projects and allow the SPEED Facilitator to start a queue. This
could be put out in draft form, allowing for a fairly short comment period. Following that
could be ruling on the other aspects of implementation but projects that are already active
could get in line.
20. The law establishes a 2.2 MW size limit on projects.
a. Does this prohibit expanding a project if it is eligible for feed-in rates?
If a project expands the 248 amendment date would be used to determine if it could
receive the feed in tariff rate. If the system is below 2.2 megwatts after the expansion and
there is SPEED capacity available than they should be able to apply to add that to their
capacity. The rate may change, as the contract should be revised and if the price is
different because it puts the project into a different price range that new price will be
different for the entire project. If the project is modified to exceed 2.2 megawatts the feed
in tariff rate is nullified and the whole project needs to negotiate for a new contract unless
the Board determines the expansion is done just for the purpose of negating the contract.
b. Could a developer, at a later date, add additional solar panels or wind turbines to an existing
SPEED project?
See answer to 22 a.
21. What process should the Board use, and what standards should the Board rely on, to
determine where “equity requires” that a retail electricity provider be relieved, in whole or in
part from standard offer purchases, if it makes a showing that it receives at least 25% of its
energy from qualifying SPEED resources?
22. Would an auction mechanism be a useful means for determining the rates necessary to meet
the statutory directive that requires a price “sufficient . . . for the rapid development and
commissioning of plans and does not exceed the amount needed to provide such an incentive”?
An auction would not work well for farm methane projects that take several years to
typically develop, so should not be considered for farm methane projects. If an auction is
considered it should only be for specific technologies and a specific amount of power.
SPEED Contract/Facilitator Issues
23. SPEED Facilitator. Board rules limit the SPEED Facilitator’s ability to enter into contracts.
Do these need to be amended? Or has the statute obviated the need to change the rule? Can the
matter be resolved through an order issued in this investigation?
Legislative intent is fairly clear and statutes over-ride rules so incorporate it into the
outcome of this docket.
24. SPEED Facilitator standard contract. What should a standard contract contain?
Refer this to committee.
a. Can we use the VEPPI contracts as a model?
b. What reporting requirements should be included?
25.How should the costs of the SPEED Facilitator be apportioned between developers
and utilities?
Because the price paid is factor of return on equity if it were to go to the producer it
would just increase the pay price anyway so it is simpler to just prorate it out the utilities
to add to what is in rate recovery for the utility.
a. Should the allocation be 50/50 as in the small power arrangements?
See answer to 25.
b. How would this allocation occur for small projects?
See answer to 25.
26. What skills/expertise should the SPEED facilitator have? For example, should the SPEED
facilitator have deep knowledge of the NEPOOL GIS system for tracking attributes of a
project?
27. Will all Standard Offer generation projects be treated the same way as far as paying costs
for metering, transformers, losses, data collection, etc. or will ther be different rules for smaller
generators, and if so where will the cutoff be?
On-going costs should be pro-rated out to the group. See 25
28. What contract provisions are needed to protect ratepayers? What contract provisions should
be avoided to limit undue barriers to these projects?
The cap is the instrument that the legislature put in place to mitigate the amount this
power could swing the overall power rate. The contract needs to be simple to understand
and put the burden of REC and attribute, value and sales to the utility group. Except for
farm customers with methane systems that retain their attributes and can contract them
separately if they wish.
Utility Settlement and Billing
29. How will extremely small SPEED projects be allocated to utilities? (This is especially
important in the context of small resources – i.e., 10kW – where a pro rata allocation could
result in some utilities being allocated less than 1 kW on an hourly basis.)
Projected size would determine the frequency the prorating would be done. It may be the
prorating could be daily or weekly on small projects.
30. Are there any barriers to implementation inherent in the ISO New England settlement
process used by utilities to settle generation contracts and, if so, how can they be overcome?
31. How will the utility allocations be treated in the context of settlement with ISO New
England?
32. How will REC’s be allocated, especially in the context of utility allocations of less than 1
kW?
RECS could be aggregated by the facilitator and prorated in blocks by generation type.
33. Will a minimum generator size be required to facilitate utility settlement?
34. How will the utility generator provisions of the legislation be implemented?
a. If CVPS and GMP build large numbers of utility owned generators, standard offer charges
could be shifted to the remaining municipal and cooperative customers, skewing overall rate
impacts. Should there be limits on utility offsets?
b. Credits received for projects developed by retail electricity providers appear to allow for a
proportional reduction in obligations to receive power under the feed-in tariff program. In
addition to reviewing the effects of development by retail providers on the 50 MW ceiling, how
will the Board implement the adjustment for the retail electricity providers?
Other Cost and Pricing Issues
35. How should factors like outage rates, availability, capacity factor, and generic performance
criteria be used in developing the appropriate rate?
36.How should the end of life value be considered in the cost calculation for the
various technologies?
a. Should the projects become the property of the ratepayers upon the expiration of the
contract?
That may be nice, as farm systems will probably have a negative value to have them
removed at end of life but it is not consistent with other utility assets that ratepayers have
largely paid for yet remain in the hand of the owner.
37. Should the rate structures differentiate components of each project, such as energy,
capacity, and RECs.?
The rate structure would not be impacted but the value of the RECs will change over time
and need to be accounted for in the rate process of the prorated utilities.
38. Should rates be designed to include peak and off peak components as well as incentives to
produce at the most useful times?
The legislation does not list time of day or power need as a factor in determining the
needed price. If peak power is desired a premium should be offered for peak power
delivery.
39. Should rates include a geographic component to promote generation in constrained areas?
The legislation does not list constrained areas as a factor in determining price. The state
has other ways to encourage that through targeted grants that would not be generally
available and not count in the rate changes.
40. Should property tax implications for the installation of renewable systems and income tax
implications from the sale of output from the facilities be addressed in developing costs?
41. Should the rate reflect any needed system improvements resulting from the installation of a
renewable system on the grid?
System improvements needed are generally paid by the project and averaged costs would
be factored into the tariff rate. If a change were desired for SPEED it would have no
affect overall because it get paid either by the ratepayers in the price paid to the producer
or through the prorated utility costs.
42. How should the contract price reflect: (1) the fact that a portion of project costs will escalate
over time? (2) there may be economies of scale related to larger capacity projects?
All of these factors should be built into the modeling used to come up with the granulation
and price for each technology.
43. Should the Board establish a Vermont-manufactured multiplier to promote the installation
and use of technology manufactured in the state? If so, what level of support would be
appropriate?
That is not in the legislation.
44. How should the Board address public (non-taxable) entities versus private (taxable) entities
in determining generic costs?
45. Wind energy has different generic costs at different mean average wind speeds; how should
the Board decide the appropriate state mean wind speed used to determine costs?
46. How should issues related to capital structure and financing be addressed in developing
pricing information?
All of these factors should be built into the modeling used to come up with the granulation
and price for each technology.