Docket 7523 – VPIRG comments on Issues List
July 2, 2009
Renewable Cost Issues
3. What level of granularity should prices have? One for each type of resource, or
different prices based upon certain characteristics?
a. If we aim for granularity, is there enough data to support each set of prices? VPIRG
believes that for each technology where there is significant differentiation between a few
different size classes under 2.2 MW we should seek that level of granularity. For farm
methane systems I believe there is already information being compiled to develop three
size categories. For wind, the statute laid out two size classes and I believe that we will
hear a case that three might be more appropriate. For solar, I think developers and our
utilities will be able to show there are just two or three subsets needed (if any). For
hydro, the standard offer should for practical reasons focus on existing generation
stations being repowered not new dams being constructed so we may only need one
class? For biomass, I think that one class will suffice.
Bottom line is that I think it should be incumbent on those who are involved in this
process to request greater granularity, and then provide as much information as possible
to support that.
b. What costs, and thus prices, of different capacity sized plans of the different
renewable resources should be addressed?
c. What is the appropriate capacity differentiation? I don’t think all resource types will
need the same level of granularity.
d. How will the Board determine the price for each type of technology?
4. How do we value the tax credits and other support, such as grant programs?
a. What credits and grants are available? There should be a standard or what is
reasonably available based on current policy and past projects ability to secure grants and
credits.
b. Should standard offers differentiate between plants that can and cannot take
advantage of tax credit(s) available? Yes, in cases where different types of customers
(corporate or non-corporate) have significantly different tax credits we should strive to
take that into consideration.
8. How should the Board incorporate wheeling charges for power purchased pursuant
to a standard offer contract?
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? If possible, and not overly
complicated, it would be good to recognize the avoided loss benefits of this distributed
generation.
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? Ideally the SPEED administrator could collectively apply for the RECs and not
leave that to every business and homeowner (who isn’t going to get the REC’s anyways)
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?
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?
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? At a minimum I think that it needs to be
very clearly spelled out in the contract that is signed so that the power producer knows he
or she can not sell the REC’s. It may also be possible to have a check box where the
power producer can keep the REC and have their standard offer price adjusted down by 3
cents per kWh or another appropriate amount.
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?
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? Given there are interim rates I think it is appropriate for the
board to put an interim limit on the capacity of projects that can take those rate. If by the
January deadline the rate analysis will be significantly more robust than it would be a
shame if all 50 MW were already in the queue based on prices that needed further
refinement. For the interim time period between Sept and Jan VPIRG would suggest that
10 MW of capacity can enter the queue.
c. How long can a developer hold a rate, or their spot in the queue?
d. Should there be two queue’s, one for rate, and one for interconnection?
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?
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? VPIRG would strongly support a requirement
showing that a project has been and is being advanced, but a security requirement might
very well exclude a lot of smaller developers from participation.
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?
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? VPIRG would support checks being put in place that would limit the ability of
one type of generation to dominate the 50 MW capacity cap. One way to do this would
be to require that no single generation type can have more than 50% of what is available
under the cap in any given year. So for year one of the standard offer, no single
generation type could represent more than 25 MW. If going into year two 10 MW of
capacity has yet to be built than no single type of generation could represent more than 5
MW, and so on. This would allow for future policy adjustments that might be desired to
see a greater diversity of resources and at the same time allow for one type of resource, if
it is more ready to go than others, to move forward.
i. How should the Board factor in utility projects (that may reduce the 50 MW
maximum)? Utilities should be required to participate in the queue just as other
developers would. Their development of a project late in the game should not bump a
project from the queue that thought they had the right to build.
i. Should the entire project count towards the owning utility's cap, or should
only their load share (percentage) count toward the cap?
j. Can existing facilities, such as net metering projects, qualify for the new
SPEED rates? No, existing projects should not qualify. The standard offer was designed
to get new generation built not offer a different or better deal to existing generation.
Projects that were commissioned after the passage of H446, and may have anticipated
being able to participate in the standard offer should be allowed to qualify.
Should refurbished projects or the output from expanded projects be able to participate?
Only the incremental renewable power from expanded projects should qualify for
standard offer rates. If a project has been out of service for a long time (years) and it is
redeveloped than I think a strong case could be made that it should qualify for standard
offer rates.
k. On a going-forward basis, what is the interrelationship between the Standard
Offer Contract and the SPEED and net-metering programs?
l. Should the Board set a minimum kW size to qualify? No. The legislature specifically
did not make additional changes this past year to the net-metering program citing the
standard offer as an option for those customers. There is nothing in the statute that
implies the standard offer should only qualify for projects over a certain size and in fact
the inclusion of specific rates (wind) for projects under 15 kW indicates that the
legislature intended the standard offer to be available to small projects as well as larger
projects.
i. Should the Board set qualifications criteria that are inclusive of residential
scale systems? Yes, see comment above
12. How should future renewable energy technology be considered or addressed? The
legislature listed out what they wanted to qualify pretty specifically. Allowing “future
renewable” technologies to participate could have unanticipated and excessively high
impacts on consumers. If technology X would need $1.50 per kWh for example the rate
impact would be well outside of what was contemplated by the legislature. Two ways of
dealing with this would be 1) If the legislature would like to include future technologies
they can pass future legislation or 2) make the default rate (average residential rate)
available to all technologies that are not currently listed.
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 be subject to the standard rate at time of application. This will avoid the
possibility that a lot of projects go through the permit process only to find that at the end
the financial picture has changed significantly and they can’t built the project. Similarly,
why should rate payers pay more if a standard offer price increases over the course of the
permitting process, if the higher price was not needed for the project to enter and move
forward with the permitting 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?
b. Should the value of the RECs be included in determining an appropriate rate
for methane projects? The value of the REC’s should be included just as other tax credits
and or grants are included.
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? The date H.446 became law would be a reasonable date
and would allow the renewable energy installation market to move forward over this
building season rather than be put on hold until some later date.
b. What criteria should the Board employ in determining an eligibility date?
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?
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? Projects should
be allowed to expand but any capacity that exceeds 2.2 MW should not qualify for the
standard offer rates.
b. Could a developer, at a later date, add additional solar panels or wind turbines
to an existing SPEED project? They should be able to do this up to 2.2 MW of capacity.
However, if the statewide capacity cap has been reached than the developer would have
to sell the new electricity through some other agreement with a utility.
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”? The legislature laid out a cost plus basis for the
development of rates. If the rates need to be adjusted in the future than it might be
helpful to enter into an auction but doing this at the beginning could lead to delay and
might unnecessarily limit those that could participate (pushing out small developers or
project developers who will need more time to develop their proposals).
SPEED Contract/Facilitator Issues
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.) Ideally the SPEED administrator can allocate to the utilities their
percentage of the total rather than each project.
32. How will REC’s be allocated, especially in the context of utility allocations of less
than 1 kW? Ideally the SPEED administrator can allocate to the utilities their percentage
of the total REC’s rather than a percentage of REC’s from each project.
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? No. Ultimately rate payers pay for all generators in the system, should
VY default back to rate payers when the current contract is up (I hope not).
39. Should rates include a geographic component to promote generation in constrained
areas? Yes
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? The standard offer should provide an incentive for wind projects to be
built where there is a good wind resource, not where the investment will be less efficient.
My guess is that if three sub groups of generation size (less than 100 kW, 100-250kW,
and more than 250 kW) are established than picking a wind speed for each sub group that
represents a quality wind resource will not be difficult given the wind expertise in
Vermont. That speed can be used to help establish an appropriate rate for that turbine
size.