February 2, 2005





What is Project 100?


Project 100 is a legislative mandate that stimulates the development of Class I Renewable Resources in Connecticut by requiring the state’s electric distribution companies to enter into energy power purchase contracts by July 1, 2007 for a minimum ten year term at an average wholesale price plus a premium up to 5.5¢/ kWh. To be considered, projects must receive funding from the Connecticut Clean Energy Fund, begin operation after July 1, 2003, and be at least one (1) MW in capacity or aggregated to one MW under a single contract. Please visit for more details.



We are currently developing two wind farms. Both are at an advanced state of development as both are very near the permitting stage. The Vermont project has a PPA and our Maine wind farm has some REC’s that could be available to CT. I’m not sure what level of benefit must be met to attain funding, are REC’s sales significant enough?



Please refer to the CCEF website at for funding eligibility under Project 100 solicitation. REC sales only will not qualify under this solicitation.


Could you tell me if some reciprocating engines running on biodiesel would qualify for this.  We are considering a site in New Haven and would want to understand if this would qualify before going forward.  I would appreciate a fast response.



No, biodiesel does not qualify under this program. Please refer to the Connecticut Clean Energy Fund’s website for qualifications under this program.


We are developing a number of wind power projects in NY. In reading the EPA, it states that delivery will be at the Interconnection Point as defined in the Interconnection Agreement.


For out-of-state projects, will the import proxy buses in the ISONE network be deemed the Interconnection Point, in lieu of an actual physical interconnection with one of the utilities?  If not, how can out-of-state facilities comply?



The Interconnection Point as defined in the solicitation refers to the location or the PTF on the ISO-NE system that the Connecticut Utilities receive and meter the power from the generating facilities.


How will the CCEF treat the securing of other funding for cost sharing?  Will the award of federal co-funding be considered favorable by the CCEF?



CCEF is not evaluating cost share funding. To the extent co-funding secured by the project developer reduces any funding request from, CCEF it will be considered favorably.



Will an applicant be required to meet and consult with CL&P on interconnection requirements if located in a CMEEC service area?



If the generating facility is located within CMEEC service area and the interconnection is on the CMMEC system, we do not believe that consultations with CL&P are necessary. However, you must demonstrate that dialog with CMMEC has taken place and arrangements are in place or agreed to for the interconnection with CMMEC electrical T&D system.



What is the rational associated with CCEF’s 15 MW cap per project proposal?



The CCEF is seeking multiple, diverse projects in each RFP rounds. We believe the 15 MW limit will allow the CCEF to achieve this objective.



Is there a commercial operation date deadline?



No. However, preference will be given to projects with the earliest In-Service-Date.


Will a project, selected and developed through this CCEF solicitation, be subject to the requirements of the Connecticut Environmental Policy Act?



Staff believes that projects will not be subjected to the requirements of the Connecticut Environmental Policy Act. 


In Section 1.3 of the RFP, it is stated that projects "must first have begun operation on or after July 1, 2003 or are not yet in commerical operation."


We have under option a biomass facility that ran for a number of years (pre-2003) and as currently configured, does not meet the definition of a Class 1 Renewable Energy electric generating resource. With certain changes specifically related to air emissions control technology, we could reduce NOX levels to a level that would allow the facility to qualify.


We believe that with the air pollution retrofits, the facility would be "have begun operation after July 1, 2003" as a Class 1 resource, although the history of the facility clearly predates the 2003 date. Would this facility, as configured (and assuming it otherwise met the emisisons numbers) qualify?



CCEF will rely on the DPUC to determine Class I eligibility of generators that were operating before July 1, 2003 but were later rebuilt or refurbished after July 1, 2003 as discussed in the Decision on Docket 03-07-17 REC01. CCEF would encourage you to petition the DPUC for a ruling for qualification under this program on your facility.


Will there be any benefit or disadvantage in Rounds 2 and 3 to a bidder who bids Round 1 but does not receive an award?



There are no advantages or disadvantages, the projects will be evaluated on its merits.


In Section 1.4 (Pricing) it is stated that the contract pricing must be less than the wholesale market price + up to 5.5 cents per kWh.  How can we determine or obtain the wholesale market price as of today (and with a 2-year look-back).  Or, is this something that is periodically determined by the DPUC?



The wholesale market price will be determined at the time the project is submitted to the electric distribution company for PPA execution. The wholesale price will be the 24 months LMP average at the Node of the project interconnection point plus up to 5.5 ¢/kWh premium. Please refer to ISO-NE website ( for LMP prices for specific Nodes.



After the awards are made will other bidders or the public be able to learn what the winning contract terms and prices were – i.e., can the non-awardees find out what they were competing against?



CCEF will provide contingent funding offers to projects that advance to Step 2 for review by the electric distribution companies. Individual bidders will be notified at that time of their status, however, the names of the bidders submitted to the electric distribution companies will not be made public. The bid prices and terms will be held confidential. When contracts are submitted to the DPUC for approval the names of the bidders will become public.



Where can one find out the CT Class I sustainability criteria for biomass?



The sustainable definition for biomass comes from the paragraph in P.A. 03-135 that includes the following description: Biomass Facility, including, but not limited to, a biomass gasification plant that utilizes land clearing debris, tree stumps, or other biomass that regenerates or the use of which will not result in a depletion of resources, provided such biomass is cultivated and harvested in a sustainable manner and the average emission rate for such facility is equal to or less than .075 pounds of nitrogen oxides per million BTU of heat input for the previous calendar quarter, except that energy derived from a biomass facility with a capacity of less than five hundred (500) kilowatts that began construction before July 1, 2003, may be considered a Class I Renewable Energy Source provided such biomass is cultivated and harvested in a sustainable manner.”



Will a bidder be eligible for consideration in Phase I of Project 100 if he has a request for Pre-Development funding before CCEF at the same time?



The same project cannot be considered for Pre-development funding and at the same time be considered for Phase I of Project 100. Project 100 is a competitive process with projects status well beyond the Pre-Development phase.



We expect to be certified as a generator of Class I RECs and are considering replacing all the old hydro equipment (700 kW) installed with new capacity that would be rated at 2,000 kW or more. However, some of your staff has indicated that you will not be accepting proposals from hydro generators because you do not interpret the mandate use free flowing water as a renewable resource.  Other staff members have said that you will accept applications from hydro that is approved as Class I, i.e. run-of-river hydro that is new capacity regulated by FERC.  However, you will not allow us to negotiate

with the electric utilities until the Legislature confirms that hydro

qualifies as a renewable resource that CCEF can support.  Still others say that it is a waste of time for hydro to apply, so we would better use our time applying to the Massachusetts Technology Collaborate's request for bids to sell RECs to encourage hydro as one of the new technologies. We like the idea of a combined PPA for both energy and REC sales, but don't want to waste our time bidding if you are not going to make any hydro awards among the contracts that you recommend.  Please clarify you policy about hydroelectric generator's applications?



CCEF is authorized to provide support for renewable energy sources, defined as follows in Connecticut General Statutes 16-245(n)(a):  "solar energy, wind, ocean thermal energy, wave or tidal energy, fuel cells, landfill gas, hydrogen production and hydrogen conversion technologies, and low emission advanced biomass conversion technologies and other energy resources and emerging technologies which have significant potential for commercialization and which do not involve the combustion of coal, petroleum or petroleum products, municipal solid waste or nuclear fission."  Due to the legislature's decision not to include hydropower on the list of explicitly authorized technologies, CCEF has traditionally taken the cautious position of not providing financial assistance to hydropower projects.


Due to the legislature's recent addition of certain types of hydropower facilities to the definition of Class I resources under the state's Renewable Portfolio Standard, CCEF is preparing new operating procedures that will include a process for identifying which energy generation technologies qualify as "other clean energy resources" under our authorizing statute.  We plan to recommend, among other things, that "other clean energy resources" should include technologies that: (1) qualify as Class I resources for purposes of the Connecticut Renewable Portfolio Standard; (2) which our statutory mandate does not explicitly mention as eligible technologies for funding or explicitly exclude; and (3) which we determine to be stationary power generation technologies with the potential to provide significant benefits for the Connecticut ratepayers.  Barring unexpected negative comments on this proposed process, we expect to be able to fund Class I hydropower projects once the procedures are finalized, which we hope will be in late March.


Unfortunately, by the time we finalize our new procedures -- which require a public comment period -- the time window for the first Project 100 solicitation will have passed.  We expect the procedures to be in place, however, in time for the next Project 100 solicitation.



Is solar energy contemplated to be a part of the mix of renewable energy in the RFP?  That is, is a certain percentage of the 100 MW earmarked for solar?



As a class 1 renewable resource, solar energy is permitted under the program.  There are no carve-outs for specific resources.



Is the sale of solar energy required to be on the utility side of the meter, rather than an offset to the host’s usage?



Yes, Project 100 is designed to supply the utility with renewable energy.  We have other programs for behind-the-meter solar.


Is the reimbursement from utilities for MWh’s delivered to the grid calculated as the average daytime ISO real time rate for a solar project (which obviously only generates during the day) rather than the 24 hour average?



The reimbursement from the utilities will be capped based on the wholesale market price at the time the project is submitted to the electric distribution company for PPA execution. The wholesale price will be the 24 months LMP average at the Node of the project interconnection point plus up to 5.5 ¢/kWh premium. Please refer to ISO-NE website for LMP prices for specific Nodes. Specific pricing option for individual projects will be bid by the project in accordance with Appendix C of the Standard Electricity Purchase Agreement.



We respectfully request clarification from CCEF regarding the differing technology-based eligibility criteria in the Project 100 RFP and in the Pre-Development Funding RFP. In particular, it is unclear why "other energy resources and emerging technologies which do not involve the combustion of coal, petroleum or petroleum products, municipal solid waste or nuclear fission" are included as eligible for funding under the Pre-Development Funding RFP but not eligible under the Project 100 RFP.


Among other reasons, as the Pre-Development RFP is intended to develop projects that would then flow into the Project 100 process, it would appear to make sense that both RFPs share the same technological eligibility requirements. We believe that Class 1 renewable energy projects employing emerging technologies should be eligible for funding under both RFPs.



Project 100 is a legislative mandate focused at specific technologies identified as Class I renewables only. Additionally, under project 100, only projects that are well beyond the pre-development stage, use commercially available technologies, have already achieved substantial progress in permitting and site control, require minimal investment from the CCEF and are ready for deployment qualify under this program. This would imply, among other things, that “emerging technologies” would not be applicable to Project 100.


We believe that we have a project that is eligible for phase 1 of the solicitation.  However, our project is physically located in NMISA.  The most recent RFP released on December 22, 2004, indicated that facilities must be located “within the jurisdiction of ISO New England, NMISA or the states where the Connecticut DPUC has established a finding of RPS comparability.”  However, it is still unclear whether the Connecticut utilities will accept power at the NE ISO interface in Northern Maine (at Keswick) or whether the project must physically deliver power to Connecticut.   



The Interconnection Point as defined in the solicitation refers to the location or the PTF on the ISO-NE system that the Connecticut Utilities receives and meters the power from the generating facilities. It is the responsibility of the project to physically deliver the power to the Connecticut utility.


The link for \"Download Supporting Documents,\" download for RFP Forms on site seems corrupt or not working properly.  Many of us can open it but cannot print it.  Maybe you can include a PDF of that document as well for printing purposes?



We have tested the documents on our web site internally and were unable to identify any problems printing the documents and forms. There have been reports of difficulty printing the RFP Word form. We believe the problem may be associated with inkjet printers. If you experience problems please help us by providing operating system and printer information to



Section 1.4 of the RFP, which sets forth Pricing, indicates that the “Proposals must include pricing that is firm and not subject to revision for at least 6 months after the proposal due date”.  Further, in that section, it states “…contract pricing must not exceed the wholesale market price at the node of interconnection plus up to 5.5 ¢ per kWh.”  Please clarify whether the pricing for the project is in fact, fixed based on the project location nodal pricing at the time of the negotiation and agreement with the local distribution company, or whether the pricing is floating based on the fluctuation of the nodal pricing going forward.  If the latter, then is it the responsibility of the project developer to attempt to negotiate a floor level of nodal pricing going forward?  This consideration is important in that a floating nodal pricing puts additional risk on the project developer.  Given the size of the intended renewable projects under this RFP, that risk is heightened relative to larger technology projects wherein an economy of scale exists.



The contract pricing will not be finalized until the Power Purchase Contract is executed with the local utility and approved by the DPUC. At this time the contract pricing will be checked to assure it does not exceed the wholesale price for the electricity based on the 24 months average LMP prices at the interconnection node plus up to 5.5¢/kWh. CCEF expects the total process from CCEF RFP submittal through final DPUC approval to take less than 6 months. While we understand there will be opportunities to update the pricing during the process period, however, we have asked proposers to hold their pricing for 6 months to assure consistency between the pricing reviewed by CCEF and that offered for final approval to the DPUC. The contract pricing can be fixed for the term of the contract or could be fixed on a year-by-year basis. Please refer to the DPUC website for various pricing options available to the projects contained in the standard PPA contract filed with the DPUC under Docket 03-07-17.



We would like clarification on the allowable interconnection configuration with the distribution utility for those projects wherein the project is located at a distribution customer end-user site.  Specifically, we would like confirmation that the interconnection of the project with the distribution utility grid can be either on the utility side of the customer’s meter, or on the customer’s side of that meter, providing the eligibility criteria of Sections 1.3 and 1.7 of the RFP are met.  Namely, Section 1.3 which summarizes the criteria for Eligible Facilities, states that the “Projects must have a capacity of at least 1 MW…”, either singly or aggregated from multiple units so long as “…the contract is with one entity using a single pricing scheme and contract terms”.  Further on Section 1.3 also states ”Eligible facilities must deliver greater than 50% of the nameplate rated capacity and energy produced to the wholesale electricity market.”  Section 1.7, Project Size, goes on to clarify that “A facility can submit a proposal for less than [sic] its total output.  A minimum of 1 MW of capacity, however, must be offered for contract. …Proposers can determine if they meet 1 MW minimum by looking at the nameplate rating of the facility net of station use, generator lead losses and transformer losses.”   Sections 1.3 and 1.7 would seem to indicate that some of the aggregated capacity could be used for whatever purposes are warranted by the project sites, so long as the contracted amount meets the criteria.  However, at the Project 100 Information Forum on November 16, 2004, the CCEF voiced the position that this program was not intended to encompass those projects wherein the renewable power project was sited behind the customer meter.  Thus, we seek clarification on this important question.



Project 100 is intended to support the supply of wholesale power for consumption by all Connecticut electricity customers through the ISO NE clearing system. It was not intended to support those projects wherein the renewable power is primarily consumed by an individual customer. However, to be eligible to propose under Project 100 the interconnection of the project with the distribution utility grid can be either on the utility side of the customer’s meter, or on the customer’s side of that meter, providing the eligibility criteria of Sections 1.3 and 1.7 of the RFP are met and projects comply with all interconnection requirements as negotiated with the local distribution company.   As Project 100 is a competition for long term power supply contracts with the electric distribution company for at least 1 MW, bidders must supply at least 1 MW of electricity to the electric distribution company. Projects that receive support from CCEF under Project 100 will not be eligible for any other CCEF programs regardless of their interconnection configuration.



We understand that multiple generating units may be aggregated to reach the 1MW of capacity that must be offered for contract.  We would like confirmation whether generating units operating at multiple project sites can be aggregated, so long as the combined capacity of the units is at least 1 MW and the contract is with one entity using a single pricing scheme and contract terms.  If multiple project sites are permitted, would all of the aggregated sites need to be within the territory of a single electric distribution company?



CCEF is neutral in regard to whether all aggregated sites need to be within the territory of a single electric distribution company. The project must, however, meet all of the previously communicated requirements and reach agreement with the utility on one pricing option and contract term. Keep in mind that individual sites will require individual interconnection agreements and that electric distribution companies may not sign agreements for power delivery with projects identified as load reducers located within another distribution company’s service territory, as the power cannot be delivered.




Section 1.6 addresses CCEF funding, and states that “CCEF funding will not cover the entire cost of any project”, and “Under no condition will CCEF provide additional funding to buy down the price paid under the PPA beyond that necessary to meet the statutory cap.”  We would like CCEF to clarify whether or not CCEF will support on-going projects after installation and commissioning; i.e., will CCEF funding provide support for operations and maintenance in the years following commissioning of the project, where such support is part of the request for CCEF funding in the proposal?



As stated in Section 3.4.1 of the RFP document “There are no constraints on the terms, components and mechanisms used for the additional funding.”



Section 3.4.2 discusses the various Proposal Forms.  Specifically, Form C – Contract Pricing discusses pricing content with the distribution company, and states, “Pricing will incorporate all environmental attributes, renewable energy credits (RECs)…”  We would like clarification whether the developer/ owner of the project retains the RECs ownership and, if it chooses, the right to sell the RECs separate from the Electricity Purchase Agreement.



Please refer to the DPUC Decision as part of Docket No. 03-07-17 entitled “DPUC Review of Long-Term Renewable Energy Contracts.”



Various sections (e.g., Section 1.4, Section 3.4.2- Form C) discuss Pricing.  It is not clear how adjustments for fuel costs are to be handled.  Specifically, how is gas indexing reflected in the electricity pricing?  Is index applied to the nodal wholesale pricing, or to entire pricing including the 5.5 ¢?  Is fuel cost indexing negotiable?



Please refer to the DPUC website for various pricing options available to the projects contained in the standard PPA contract filed with the DPUC under Docket 03-07-17.



Section 1.6 - CCEF Funding, states that “CCEF funding will be provided as a grant under standardized terms…”  Our question is whether that grant money will be provided in one lump sum, or in payments determined by milestones?  How will that grant money be provided to the project developer?  Is this to be proposed by the developer or to be negotiated subsequent to the proposal being accepted by CCEF?





The standard $50,000 will be a grant under standardized terms. These terms will be available on CCEF’s website in the near future. Any additional funding requested by the projects will be project specific and subject to negotiation.



Referring again to the Eligibility Criteria for a project, it is not clear from the various discussions in the RFP (e.g., Section 1.3 described above, or Section 3.3 – Minimum Bid Eligibility Requirements) whether a project proposal can include different renewable technologies.  This might be the case, for example, for a project that might choose to mix fuel cells with solar, or wind and aggregate those multiple technologies to meet the 1 MW minimum capacity criteria.  Please clarify that a project proposal is not limited to a single Class 1 Renewable technology.



A project proposal is not limited to a single Class 1 Renewable technology, however, energy must also be generated by a Renewable Energy electric generating resource within the scope of CCEF’s funding authorization as defined by Conn. Gen. Stat. § 16-245n(a).



Section 2.4 of the RFP, which summarizes the Evaluation Process, states that top-ranking projects will be required to make an oral presentation to CCEF.  Given that such presentations are likely to include sensitive information, we would like confirmation that the presentations will be conducted a non-public forum and will be protected from subsequent public disclosure.



The project presentations must be held as a public meeting however, if confidential information is to be presented, the meeting will enter executive session to maintain the confidentiality of the information.



The RFP does not discuss any State of Connecticut tax implications.  First, will the project be taxable as personal property in the municipality within which it is situated, or is it exempted?  Second, the State of Connecticut has a state income tax.  Are any State income tax exemptions available to the project developer, and if so, will the exemption be applicable over the duration of the PPA?  The tax implications are important to accurately reflecting the financials in the project pro forma.



Developers are encouraged to consult with the project’s local municipality regarding the tax implications of the project. State of Connecticut tax rules can be found on the Department of Revenue Services website ( State of Connecticut incentives can be found on the Department of Economic and Community Development website: