Massachusetts DOER – RPS Advisory Group
Thursday, April 27, 2000
Facilitator: Dr. Jonathan Raab, Raab Associates, Ltd.
Meeting # 8: Summary
37 people attended the meeting, which began at 9:15 and concluded at 3:30.
Prior to Meeting:
1. Agenda for today’s meeting, Raab Associates, Ltd.
2. Meeting Summary of March 30th meeting, Raab Associates, Ltd.
3. “Massachusetts Renewables Portfolio Standard, Analysis of Costs & Impacts”,
Douglas C. Smith, et al. (3/21/00)
4. White Paper # 9: “Evaluation Methodology”, Wiser, Ryan et al.
At the Meeting:
Overhead slide presentations:
1. “Existing Renewable Supply/Demand”, Douglas Smith (La Capra Assoc.)
2. “Massachusetts RPS Preliminary Design”, Nils Bolgen (DOER)
1. There was one correction to the March 30th Meeting Summary: p.3, first bullet
under “Accounting for Losses” – change “contested area” to “congested area.”
Existing Renewable Supply/Demand
Doug Smith from La Capra Associates reviewed draft analysis on the projections of
existing renewable supply vs. demand thru 2020 in New England. He looked at the
demand from the RPS requirements in MA, CT, and ME and also made some projections
regarding additional demands from green marketing. On the supply side he included all
potentially qualifying renewables, including all hydro and biomass. According to La
Capra’s analysis, demand is not projected to exceed supply for approximately 12 years
when estimated green demand is included, and approximately 16 years with all the RPS
requirements but assuming no additional green demand.
[Note: It was discovered during the course of the presentation that some of the supporting
tables were not the ones that matched the graph. Corrected slides were distributed via
email the day after the meeting.]
Group members asked numerous questions, and made some observations and requests for
additional data documented below:
HQ sales may be higher than shown. Numbers do not appear to include HQ sales
to NY that are passed thru to New England. Figures need to be checked.
Imports may be more 8 or 9 million MWh.
Do the renewable facilities’ licenses last beyond their contract period?
The Maine Standard for eligible hydro is under 100 MW
Did you estimate the price premium that might be anticipated over time based on
your projections of the supply and demand balance over time. [Answer: not yet.]
At the close of the discussion, numerous Group members requested that La Capra run
other scenarios and sensitivities on the data, including:
1. Alternative hydro assumptions:
a. Leave out “large” hydro
b. Leave in only “low impact” hydro
c. Leave in only hydro that can be considered “daily cycle hydro”
2. Alternative Biomass assumptions
3. Do sensitivity analyses on the following 3 variables:
b. Green demand
c. Going forward operation costs
La Capra agreed to make some additional runs, and try and distribute the output prior to
the next meeting. (Please contact Jonathan Raab immediately if you feel that
anything was left off the list of scenarios and sensitivities.)
DOER’s Preliminary RPS Design
Following opening remarks by Commissioner David O’Conner, Nils Bolgen spent the
rest of the day stepping the Group through DOER’s preliminary RPS design [see handout
for description of DOER’s recommendations]. After each major topic, the Group asked
clarifying questions and then provided DOER with some initial feedback. These
questions and comments are captured below, organized by topic.
Some of the DISCO’s have standard offer contracts through 2004 or 2005. How
will they comply, specifically how will DISCO’s stockholders be sheltered from
any cost increases caused by meeting the RPS?
Compliance with the RPS will be mandatory for all suppliers, but will be
voluntary for generators (i.e., generators who want to be eligible for selling RECs
will need to comply with DOER’s requirements).
Change “owner of any generation” to “owner, operator, or holder of contract for
Would it be unfair for munis to be able to sell RECs but not have to buy RECs?
Perhaps you need to require reciprocity to make sure accounting system clears
(i.e., RECs are associated with equivalent amount of power sold to non-muni MA
DOER probably can’t design standards for existing renewables that adequately
protects those in need of protection (i.e., the higher priced renewables).
Maine’s inclusion of existing renewables, at a minimum had a psychological
If no great cost to consumers, then why not include requirements for existing
If there’s attrition of existing renewables, let new renewables replace them.
Even if there’s not a lot of activity related to existing renewables in the short run,
it would still be useful to have a standard for existing renewables at least to clarify
the standards (e.g., for biomass).
If DOER holds off on implementing a standard for existing renewables, it should
use the questions identified on slide #12 to monitor the market.
Not implementing a standard for existing renewables now can impact the green
market, perhaps making it more meaningful and more environmentally beneficial
by accelerating adoption of new renewables by green marketers.
DOER shouldn’t give up on trying to design meaningful requirements for existing
If DOER limits hyrdo eligibility could lead to a more meaningful RPS for existing
DOER should have the authority to restrict hydro based on market power issues.
One option would be to not allow any generator to control more than 35% of the
RECs; 55% for 3 generators; and 75% for top 5 generators. [Others asked whether
DOER had the authority to address market power issues.]
Early Start Trigger:
Will early compliance complicate things for those coming on-line in 2003 by
reducing the price they could get for their RECs?
Eligibility for New Renewables:
It will be challenging to figure out the renewable content of dual fuels. Maybe
put onus on owner to demonstrate amount of renewables actually used.
DOER should also look at capacity expansion (i.e. MW) in addition to increased
energy production (MWh).
Biomass and Landfill Gas:
What does DOER mean for biomass by “most recent MA air quality permit?”
How does DOER propose to treat out-of-state biomass plants built between 1997
and today? Should it apply 1997 or current MA BACT standard? Is this
differential treatment with in-state facilities?
Another approach for biomass is to have DEP do a BACT analysis now and put
numbers in the regulations, given that the Pinetree facility, which was DEP’s last
biomass BACT analysis is nearly a decade old.
Pipelines probably won’t take landfill gas, so DOER should only include landfill
gas that is converted to electricity on-site or is transported by a dedicated pipe to
an electricity plant nearby.
Be consistent with transmission tariffs.
RECs created either at the plant or at the border to New England would need to be
derated for distance.
What’s an adequate demonstration that a supplier in MA made a purchase? What
if anything beyond just buying the credits?
It could be a chilling problem if every REC from an import needs to show a
bilateral contract to prove that the power came into New England.
Interstate commerce could allow restrictions on imports if good policy rationale.
DOER needs to do a comprehensive legal analysis of the issue.
DOER should consider issuing credits to generators, only to those states outside
New England where credits have value (i.e., reciprocity where the other states
also have an RPS or certificate systems).
Generators need to demonstrate sales not suppliers.
At least 2 other states have put some restrictions on imports.
DOER should just limit imports to contiguous states and provinces.
Restrict imports to only those places with comparable comprehensive GIS
(generation information system) [to the one that ISO-NE may eventually have in
place]. Make sure that exporting state treats energy as null energy once RECs are
Make sure generators in exporting states can’t resell energy as renewables again
once sold RECs as a contractual matter.
Attendees were unanimous in their lack of support for DOER’s recommendation
that customer-owned generation not be eligible for the RPS. Arguments included:
1) it would be inefficient; 2) force people to structure strange deals to qualify; 3)
it’s inconsistent w/state support for DSM; and 4) customer-owned generation
could be considered a "pre-paid" sale of energy. People felt that DOER was
reading too much into “retails sales” language in the legislation, and some pointed
out that will likely be sales to the grid sometimes during the year or day in any
Suppliers’ use of the RECs should appear on the register to help avoid double use.
Product vs. Company and the Disclosure Label:
Most attendees disagreed with DOER’s preliminary recommendation to require
compliance on a Company basis rather than a product basis. Some pointed out
that they were very surprised given the recommendations of the white paper and
the seeming consensus of the Group on this issue at the session where it was
discussed. DOER pointed out that they did not feel that they had the authority to
require product-based compliance. Many disagreed with DOER’s interpretation
of the law.
Some attendees were also skeptical about the workability and advisability of
DOER’s recommendations to change the disclosure label which would effectively
turn disclosure into a product-based system. Some felt that this would create
problems w/disclosure in other states and with the GPS.
The Maine Legislature was convinced to effectively administer the RPS on a
product basis and amended the law.
Show customers what resources RPS compliance comes from. Customers may
also want to see what’s new vs. existing renewables.
Emission rates need to show up, and would be inconsistent with what DOER is
recommending for fuel type. This could be a “disconcerting mismatch.”
Can you change the regional disclosure label to accommodate MA RPS?
There’s a math error in DOER’s supporting table (slide 46), should be 5 MWh
MA and CT RPS allocation (not 10 MWh).
Don’t add a statement regarding compliance w/RPS on the label. If they weren’t
in compliance they ultimately won’t be selling in MA or have a label.
DOER should go back to the Legislature, if it feels it need to, to clarify that the
RPS should be on a product rather than a company basis.
DTE regulations have some restrictions already about what can be marketed as
green energy above RPS requirements.
Use term “EPS” and not “GPS”.
The Group was divided regarding DOER’s recommendation not to include
banking. Some argued that customers and suppliers could be adversely impacted
without banking, while others felt that banking wouldn’t work with disclosure.
Some wondered whether banking would circumvent the letter of the law which
requires that certain levels be met in certain years.
Look at symmetry of the flexibility mechanisms.
Isn’t the penalty set up to deal with shortcomings of supply?
Can early compliance credits be banked for use in years after 2003?
Sanctions for Non-Compliance:
Consider accelerating future requirements for those in non-compliance.
Options for placement of any penalty money: general fund; MTC, or purchasing
and retiring RECs.
What about all the penalty details recommended in the Consultants’ white paper,
is that being dropped? [DOER, we have streamlined the recommendations
The penalty will act as a de facto cost cap.
Next meeting, on Thursday May 18, will once again be at Foley, Hoag, & Eliot. DOER
will refine its recommendations and prepare a draft of its comprehensive RPS proposal
for discussion at the meeting. La Capra Associates will also be updating its analysis on
supply vs. demand of existing resources and running various alternative scenarios. Both
sets of documents should be circulated prior to the meeting.
t:\renewabl\rps\advisory group\meeting #08-0427\mtg#8 summary-0427.doc