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The DPUC will ensure that all Bidders have access to the same information from the DPUC and that no Bidder will have selective or otherwise preferential access to information from the DPUC through this RFP Process.

All questions and comments submitted by Bidders, as well as DPUC responses to such questions will be posted here. The DPUC’s objective in posting these questions, comments, and responses is to ensure that all Bidders are treated in a fair and equal fashion and have equal access to information that may be relevant for the proposals. The DPUC will not identify the name of the party submitting the questions.

The DPUC is under no obligation to provide additional information but it may do so at its sole discretion.

Email: RFPCoordinator@Connecticut2006RFP.com with comments and questions.

 

09/20/2006
 Question: When will the contracts be available? 
Answer: The contract templates issued in June and July  2006 are being revised to reflect stakeholder input received over the last two months.  We will be posting the revised generation contract on the RFP website later this week. The other contracts - for Demand Response and Other Demand Resources, will be posted on the RFP website within the next five to seven business days. We will be accepting bidder comments and questions on these revised contracts through October 6, 2006 and the contracts will be finalized by the end of October 2006.  

  

09/20/2006
 Question: For generation resources, who gets to keep ISO ancillary services revenues.  Supplier or Buyer?

Answer: 

We do expect the suppliers to participate in all relevant ISO-NE Markets. However, there may be situations where the generator does not keep all ISO-NE profits. The settlement process may require that some of the money they receive from ISO-NE for FCM and LFRM (if elected) (and Energy, if Call Option feature is selected) gets refunded back to the electricity distribution companies (Buyer)  if the market prices in those ISO-NE Markets exceeds the relevant Contract Price.  For those suppliers that are only settling against the Forward Capacity Market, the Supplier will be entitled to keep any additional revenue it is able to receive for providing ancillary services. However, if the Supplier chooses to also settle against the Locational Forward Reserve Market, which is one type of ancillary services, then the revenues for locational forward reserves will be allocated according to the settlement process, with the Supplier receiving its Annual Contract Price for such services.  Other ancillary services revenue are not included explicitly in the RFP or the settlement process in the Contract; however, the DPUC expects that bidders will take into account the profits that they may earn in these other markets in setting their Financial Bid for settling against the capacity market (FCM).

09/20/2006
 Question: Are Financial Bids escalated by an inflationary index only if the regulatory process is not completed by November 8, 2007?  Or are they escalated regardless of whether the regulatory process is completed in a timely fashion? 

Answer: Financial Bids will only be escalated by the inflationary index if the regulatory process is not completed by November 8, 2007. Thus, Financial Bids submitted on December 13, 2006 must be held fixed through November 8, 2007.



09/25/2006
 Question: The registration form (appendix D) requests the bidder to enter a Commercial Operation Date. Can the COD change when Technical and Financial Bids are due? Is there any penalty for changing the COD from registration to final bids? 

Answer: Bidders can update the Commercial Operation Date that they provided on their Bidder Registration Form in their Financial Bid form if needed, though bidders should indicate the reason for such a change. The COD date, and other information provided on the Financial Bid Template, will be contractually binding.  



09/25/2006
 Question: Can Bidders change information submitted on Appendix D:  Bidder Registration Form prior to the submission of Bidder Qualifications?

Answer: Bidders can change information on Appendix D: the Bidder Registration Form in their Financial Bid, if needed, although information such as contact name and contact information as well as project name should remain the same so that the DPUC can be sure that the project did indeed register by the Bidder Registration Date. If major elements, such as project Commercial Operation Date or Capacity, are changed between the Registration Form submission and the Financial Bid Template submission, bidders should provide an explanation of such change with their Financial Bid.  All information submitted on the Financial Bid form will be contractually binding.

09/26/2006
 Question: Is the Contract Quantity (MW) on Appendix D: Bidder Registration Form and Appendix J based on Summer Capacity, Winter Capacity, or an average of the two?

Answer: The Contract Quantity is a fixed amount to be designated by the Supplier in its Financial Bid, and will not vary by season. Bidders will have to provide an FCM Contract Quantity, and, if they choose to also settle against the Locational Forward Reserve Market, an LFRM Contract Quantity. The LFRM Contract Quantity can not exceed the FCM Contract Quantity.  The FCM Contract Quantity is a fixed amount for each Contract Year and will not vary by season. However, the Contract Quantity in the contract may be amended from time to time based on the results of seasonal claimed capability tests, as detailed in Section 3.2 (c) of the generation contract. 

09/26/2006
 Question: Will a supplier's monthly capacity payments be based on different Summer Capacity and Winter Capacity levels?  

Answer: Suppliers' monthly capacity payments will be based on the Contract Quantity listed for that Contract Year, although the Contract Quantities may be amended in the contract from time to time, as per Section 3.2(c) of the contract. 

09/27/2006
 Question: I am having problems saving the PDF template for the Bidder Registration Form. 
Answer: You can only save this form with information filled in if you have  the full version of Adobe Acrobat or Adobe Business Tools. If you only have Adobe Acrobat Reader, you will have to save the blank template, fill it out and print it. You can then scan this print-out to create an electronic document to email to the RFP Coordinator. 

09/27/2006
 Question: If the sponsor of a Distributed Generation (DG) project registers as a
bidder under the RFP to reduce impact of FMCCs, and is not awarded a
contract or does not submit a bid, is the sponsor eligible to apply for
grants under section 8 (a) of the EIA?
Answer: DG can bid into this RFP process and seek DG grants, but they cannot receive both a contract through this RFP and a one-time award pursuant to 16-243i. Thus, if a DG project that bids into this process was not awarded a contract, it would still be eligible to seek DG grants under the EIA.

10/04/2006
 Question: Section 3.9 of the  RFP states that a Bidder may submit up to three Proposals for the same site.  Mutually exclusive proposals will only be required to submit one deposit, the amount of which will be based on the largest (MW) project. If a Bidder submits a total of up to three proposals from two separate sites, will the Bidder be required to submit one deposit, the amount of which will be based on the largest (MW) project, or will the Bidder be required to submit two deposits, the amount of which will be based on the largest (MW) project for each separate site.

Answer: The Bidder must submit a deposit for every proposal that is not mutually exclusive. For projects that are mutually exclusive, the amount of the deposit will be based on the largest (MW) project.  To illustrate how this might work, if a bidder submitted three proposals for two different sites (A and B), and the two proposals for site A were mutually exclusive, the Bidder would pay the deposit for the proposal on Site B, and the deposit for the largest project on site A. If the two proposals for site A were not mutually exclusive, however, the Bidder would be required to pay the deposit for all three proposals. 

10/04/2006
 Question: Where will the Pre-Bid Conference be held and at what time?


Answer: The Pre-Bid Conference will take place on October 10, 2006, starting at 10 AM in Room 2C of the Legislative Office Building, 300 Capitol Avenue, Hartford, CT. The event will likely last all day. We request that you email the RFPCoordinator to register for the event.

10/11/2006
 Question: Are transcripts for the Pre-bid conference available?


Answer: Yes, the transcript is available on the RFP website - please see the RFP Documents page at the bottom.

10/11/2006
 Question: Is a list of participants at the Pre-Bid conference available? 


Answer: This list is not publicly available. While participants were requested to register with the RFP coordinator to attend the meeting, they were not required to publicly disclose their identity at the meeting, as stated by Chairman Downes in his introductory remarks.  For information that is publicly available on the current participants in the RFP process who have not requested a motion for a protective order for confidentiality, you can look through the bid registrations that are listed in Docket 05-07-14-PH02 on the DPUC’s website.

10/13/2006
 Question: If a bidder has not been in existence for more than two years, how should it respond to the financial questionnaire, which asks for the last two years of financial data?


Answer: In this context, the bidder should sumbit all financial data that is available for the organization, including any other data that may help communicate to the DPUC that the bidder has the financial wherewithal to develop and operate the project.

10/13/2006
 Question: Will the Q&A from the conference be posted on the RFP website? If so, when?
Answer:Yes, the Q&A is being finalized and will be posted on the RFP website early the week of October 16th. In the meantime, we have also posted the PowerPoint presention and the transcript from the Pre-Bid Conference on the RFP website.

10/17/2006
 Question: Section 3.4 of the RFP states that “Bidder registration is required in order to participate in the RFP. The deadline for bidder registration is September 29, 2006 (the Bidder Registration Date). The Bidder Registration Form … should be completed and submitted to the RFP Coordinator by the Bidder Registration Date …” We note that a number of developers have attempted to register projects after the Bidder Registration deadline.  What is the status of those untimely projects vis-à-vis those developers who complied with the rules and filed their registrations on time?
Answer: The September 29th deadline was firm and that has been communicated to anyone that has tried to register after that date.

10/17/2006
 Question: The RFP bid evaluation process will consider the benefits of each project based on cost reductions to Connecticut Load (Interim Decision, page 15).
The evaluation of the energy benefits of Demand Resources would need to be
considered as part of that calculation.  Demand Resources have varying
energy savings based on the length of time the demand is reduced, typically
referred to as hours of use.  The range of variation can be a few hours on
a single day to several thousand hours per year.  Since there is currently no requirement for hours of use to be submitted as part of the RFP submission, how will the energy benefit of various Demand Resources be calculated?

Answer: We are currently revising the project description templates and the revised versions will incorporate this additional information. We will be posting the revised versions on the RFP website later this week.

10/17/2006
 Question: With regard to section 2.5(e) of the Generation Contract: that damages set out in Sections 2.5(a) and 2.5(b) will not apply if the delay is due to (i) a Force Majeure event; (ii) a material breach by the Buyer of its obligations under this Agreement, pursuant to Article 4; or (iii) a delay in obtaining regulatory approval from the Department of Environmental Protection or the Connecticut Siting Council (or any other relevant Government Agency), which was not caused by the Supplier or by the Supplier’s failure to perform a required task, I request clarification of this provision in the context of remarks from the DPUC that, in effect, permitting is the risk of the Supplier. In the following three scenarios, what happens in the case that a Supplier misses a Milestone Date: (1) Assume that a Project seeks a discretionary special permit or a variance from local zoning requirements, and that relief is denied, not just delayed or conditioned. The Supplier can take no action to obtain the relief; (2)  Assume that a Project requests an Interconnection from the Independent System Operator, and the required upgrades or operating restrictions are prohibitively expensive. (3) Assume that a Project's relevant applications to the Connecticut Siting Board or the Department of Environmental Protection for an Air Permit are denied. (4) Assume that any of the above applications granted but appealed.Are full damages due, or are these cases where the "delay" is not caused by the Supplier? Does "delay" include "denial"?

Answer: In cases 1 through 3 outlined above, the Supplier would be responsible for the delay and/or the denials. On the question of appeal (case 4 outlined above), and as long as the appeal is not the fault of the Supplier, an appeal should not result in delay unless there is a stay.

10/17/2006
 Question: We have a few questions regarding Connecticut licensing requirements and what might be applicable with respect to projects implemented via the RFP. 1. Is a Connecticut general contractor's license required for demand resource work?  
1b. If so, must the license be obtained prior to making a bid, or rather prior to performing any work under the program? 2. Are there any other specialty licenses required for this type of work?

Anwer: Developers and their subcontractors must have the requisite skills to develop and operate their projects and must follow the laws of the State of Connecticut including obtaining any licences that are required.  It is up to Bidders to determine which licenses - and other qualifications - are needed and to comply with these requirements.  Bidders do not have to submit such licenses in the RFP though possession of them would clearly demonstrate the technical wherewithall of the Bidder.

10/19/2006
 Question: Could you provide us with feedback on what we can expect values for Demand Response resources will be?

Answer: The DPUC will not be releasing any specific pricing benchmarks for potential bidders as this would conflict with the intended competitive nature of the procurement process. Bidders should in developing Financial Bids for this process consider what compensation they require for the project over the anticipated term of the contract, given other possible revenue sources that exist for the project. For additional input into Bidder reflections on this topic, we recommend that bidders review ISO-NE’s Settlement Agreement filed with FERC, which provides an indication of ISO-NE’s expectations regarding pricing expectations for the FCM and describes in details the FCM pricing rules.


10/19/2006
 Question: 

Section 2.6 (g) a. i. of the Master Agreement for Generation Projects states that “The equivalent required for maintaining operations at the facility’s annual  load factor for a minimum of (5) calendar days unless the Facility’s annual load factor, as defined by the Target availability listed in Exhibit C, is less than 15%.”

 1)       Is the annual load factor the same as the Facility’s annual capacity factor?  That is actual MWH produced divided by the plants nameplate capacity times annual hours.

2)       How will the annual load factor be determined for the Facility’s first year of operation?  An estimate by the Supplier?

3)       How will the annual load factor be determined for the Facility’s subsequent years of operation?  Based on prior years actual results, or an average of several previous years?

          4)      Why is the annual load factor defined by the Target Availability?  A project                        could have 100% Availability yet not run at all during a year due to market                            economics.

       5)  Assuming a five day supply is required for purposes of this provision,                how quickly does the alternative fuel need to be replaced in the event                the initial five day supply is consumed.?


Answer: (1) The load factor is the same as the annual capacity factor. (2) The annual load factor in a Facility's first year of operation should be based on the average load factor of all other New England units with a similar technology and heat rate in the previous year. (3) Once the Facility has started commercial operation, its load factor for purposes of 2.6 (g) will be determined by its load factor the previous year. (4) We will be editing this provision in the contract in the next round to reflect theses comments and will eliminate any references to target availability in Section 2.6 (g). (5) If some or all of the required fuel supply is consumed, the supplier must replace that supply within five Business Days.

10/20/2006
 Question: Have the proposal security requirements been amended in light of bidder comments?

Answer: Yes, the DPUC has amended the structure of the Project Security Deposit requirements based on stakeholder comments. The revised security requirements for the proposal process are listed below.

On December 13, 2006, when bidders submit their Financial Bid, bidders with a generation project will be required to post $10/kW and bidders with a Demand Resource project will be required to post $2/kW.  This Project Security Deposit must be provided in cash or through a Letter of Credit. Bidders will not be allowed to net this security requirement with any security provided to ISO-NE.  

On the day that winning bidders are contacted by the DPUC (no later than April 23, 2007), winning bidders must post an additional security (again in the form of cash or a Letter of Credit) such that winning bidders with a generation project post a total of $25/kW and winning bidders with a Demand Resource project post a total of $5/kW for the Project Security Deposit.

On the date that the contracts are approved by the DPUC (the Effective Date of the contract), bidders will be required to increase or replace the Project Security Deposit such that Suppliers with a generation project post $100/kW and Suppliers with a Demand Resource project post $35/kW for their Completion and Performance Security until the project reaches Commercial Operation. The Completion and Performance Security can be established in the form of cash, a Letter of Credit, or a performance bond that meets the requirements in the  Master Agreements.  The Completion and Performance Security can be netted against any security provided to ISO-NE, as long as such security is not in the form of guarantees. After Commercial Operation, the Completion and Performance Security decreases to $25/kW for generation and $15/kW for Demand Resources for the remaining Term of the Agreement.

All entities posting their security requirements in the form of cash will be paid the interest that accrued on their deposit from the date it was provided until the date it was returned on the date the security is returned to them. For entities posting an incremental amount of security, the accrued interest can be added to the existing security, effectively decreasing the incremental amount that must be posted.  

10/25/2006
 Question: We had some questions about the motion for a protective order.  Should we submit this filing before or with the Qualifications Submission?  Also, is it sufficient to just submit the motion in order to receive confidential treatment, or is there an approval process?  Please explain.

Answer: 

A bidder must file a motion for protective order, a protective order and an affidavit in support of the protective order from an appropriate employee or agent of the company seeking protected treatment.  The motion should explain why the material should be exempt from public disclosure under CT's Freedom of Information law.  The information the bidder seeks to protect should be filed under seal and each page labeled confidential protected material.  The information will not be disclosed publicly pending a ruling on the motion.  If the bidder only seeks to protect a portion of their filing, they should file a public version with redactions to protect the material they seek to protect along with the version under seal that contains the protected material.  If the motion is granted, the material will be protected.  If the motion is denied, the bidder will receive a letter directing the bidder to come retrieve the material they sought to protect.  The bidder can also request that the DPUC destroy any materials if protected treatment is not granted.  The DPUC website under the link for Filer Instructions has a link providing basic information about how to seek protected treatment of information filed with the DPUC.   Bidders can go on the Active Docket link to the DPUC website and Search "protective order" to locate templates of the standard motion for protective order and accompanying documents that have been approved by the DPUC in recent dockets.

We would also direct bidders with questions about this to carefully review Section 3.3 of the RFP that describes the process for seeking protected treatment as well as the DPUC's expectations about what types of material the DPUC wishes to ultimately disclose about each selected project.

10/31/06 Question: Your response in the Pre Bid Conference Q&A – the Answer to Question 2.2 states – any projects that receive other ratepayer funding that covers 100% of a project’s development costs, including but not limited to the Conservation and Load Management Fund, Project 100 (and the renewable contracts), Clean Energy Fund and the various DG programs authorized though the EIA (such as DG capital grants….will not be eligible for funding for any capacity that was already funded. (1)  What is meant by 100% of a project’s development cost?  (2)  If project’s development cost is very broadly defined, can an exception be made for the following specific case?  Assuming in a the specific case that a recipient of a DG grant for customer-side distributed generation is funded to take their electrical load off the grid and to self generate, why should the recipient be penalized if it decides to enter into the FMCC reduction RFP by load shedding its internal load and making its self-generation available to the grid?  The CT ratepayers will receive a double benefit when (i) the recipient’s load is off the grid through the DG grant program and then (ii) making available very low cost power to the Grid through the FMCC reduction RFP.  By permitting the recipient’s participation in the FMCC Reduction RFP, you are accessing the potential pool of low cost power available to bid for the benefit of the CT ratepayer for which this program was intended. The payment under the FMCC reduction program can be viewed in this case as an incentive to the recipient to load shed and provide low cost power to the grid since the FMCC reduction RFP payment would be in an amount to offset the opportunity cost associated with the load shedding.
Answer: (1) The project's development costs refers to the full cost of developing and constructing the facility. (2) Projects that received any funding from the conservation fund,   DG grants, and/or  Project 100 are not eligible to participate in this procurement process.

10/31/2006
 Question: Do the liquidated damage provisions in Sections 2.5(b), 2.5(c), 3.2 (c), 3.3(e).b. and 3.3(f).b. of the Demand Resource Contract apply to demand response projects?  If your answer to any of these questions is “yes,” please explain why each such liquidated damages provision applies to a demand response project.


Answer:  Yes, all of these liquidated damages provisions could apply to a demand resource project.

Section 2.5(b) is applicable as the determination to award a contract to the demand resource project will have been based on the project’s COD (or CODs if the project capacity is coming on line in a staggered manner).as warranted in the proposal.  As such, the Supplier must pay liquidated damages to compensate the Buyer (and indirectly CT ratepayers) for not meeting its warranted online date.  The CT ratepayers will forego anticipated financial benefits from having that capacity in place if the warranted milestone is not met.  Therefore, the liquidated damages are meant to compensate for the replacement costs for that capacity.

The logic for Section 2.5(c) is similar: the Buyer was promised a fixed number of MW in the proposal. If the Supplier is unable to deliver this amount of MW, then the Supplier must compensate the Buyer for its deficiency in order to make up for the present value of the replacement costs for that capacity until new demand resources can come online. The same logic holds for Sections 3.3(e)b and 3.3 (f) b. The DPUC wants the Supplier to submit Contract Quantity levels that it can commit to for the life of the contract.


10/31/06 Question: With respect to the definitions of “Commercial Operation” and “Commercial Operation Date” in Article 1 of the Demand Resource Contract, (i) is there a Commercial Operation Date for a demand response project; and (ii) if your answer to the question in subsection (i) above is “yes”, then please identify which of the Milestones for Commercial Operation in Section 2.5 applies to a demand response project and which of the requirements for Commercial Operation in Section 2.6 applies to a demand response project?

Answer: Yes, the demand resource project must submit a date-certain Commercial Operation Date. This COD can vary by “batch,” effectively allowing the aggregate capacity for the demand resource project to come on-line in a staggered manner.

The demand resource project must meet all milestones listed in Section 2.5, however liquidated damages will only be incurred for missing the Commercial Operation Date under the Master Agreement for Demand Resources.  

All requirements for commercial operation listed in Section 2.6 are applicable for demand resources projects, though some provisions may not apply to all Demand Resources.

10/31/06 Question: If LEI and the Department conclude that Section 2.5(b) of the Demand Resource Contract applies to demand response projects, is “Commercial Operation” within the meaning of Section 2.5(b) an event that will occur once for a demand response project (e.g., the date upon which the Supplier first signs-up all of the necessary MWs of Demand Reduction Value in an amount equal to the Supplier’s Base Level FCM Contract Quantity and/or Base Level LFRM Contract Quantity, as appropriate), or could a demand response project be subject to the liquidated damages in Section 2.5(b) if, at any time during the term of the Demand Resource Contract, its Demand Reduction Value falls below the Base Level FCM Contract Quantity and/or Base Level LFRM Contract Quantity, as appropriate, for any reason?


Answer:Section 2.5 (b) is intended to apply only when a project first reaches Commercial Operation. In the context of a demand resource project that is coming online in a staggered manner, that has scheduled several different CODs for different “batches” of capacity, Section 2.5(b) would apply one time to each batch until that batch of capacity achieves commercial operation. 

Deficiencies in capacity after commercial operation are governed by Sections 2.5 (e) and 2.5 (f).


10/31/06 Question:  If LEI and the Department conclude that Section 2.5(c) of the Demand Resource Contract applies to demand response projects, is the liquidated damage provision of $200 per kW in Section 2.5(c) assessed to the Supplier on a one-time basis (or until a cure is achieved) if, upon the Commercial Operation Date, the Supplier’s Demand Reduction Value is less than the Original Base Level FCM Contract Quantity (and if relevant its Original Base Level LFRM Contract Quantity)? 


Answer:  The liquidated damage of $200/kW is indeed a one-time assessment at the time the project reaches its Commercial Operation Date.  Again if a demand resource is coming on-line in a staggered manner, with a set of different CODs for different “batches” of capacity, section 2.5 (c) would apply one time to each batch.  The $200/kW figure, as discussed above, represents the present value of replacement costs that can be anticipated today for deficient capacity until such time as “new” demand resources can enter the market to replace the deficiency (it typically takes 1-3 years for new demand resources to be implemented).




10/31/06 Question:  If LEI and the Department conclude that Section 3.2(c) of the Demand Resource Contract applies to demand response projects, does the liquidated damages provision in Section 3.2(c) apply only if the Supplier is unable to participate in the applicable ISO-NE Market(s) due to “the termination of its membership (or the membership of its agent), or suspension of membership rights or termination of its Market Participants Service Agreement” pursuant of Section 8.1(b).b of the Demand Resource Contract and if such failure to participate was not caused by an event of Force Majeure?  Or does this liquidated damage provision in Section 3.2(c) apply if the Supplier is unable to participate in the applicable ISO-NE Market(s) for any reason, including but not limited to the reasons set forth in Section 8.1(b).b of the Demand Resource Contract, as long as such failure to participate in the ISO-NE Market(s) was not caused by an event of Force Majeure?
Answer:  We have clarified the language in Section 3.2(c) of both Master Agreements to better reflect our intention that the liquidated damage in this provision was to compensate the Buyer for any circumstances for which the Supplier is unable to participate in the ISO-NE Markets (except those caused by Force Majeure) until a cure is achieved.  If there is a legitimate Force Majeure, no liquidated damages are due.

 

10/31/06 Question:  If LEI and the Department conclude that Sections 3.3(e).b and 3.3(f).b apply to demand response projects, if the demand response project’s Demand Reduction Value falls below the Base Level FCM Contract Quantity and/or Base Level LFRM Contract Quantity, as appropriate, by more than 2% and if such deficiency is not cured on the 46th day, is the Supplier automatically entitled to have its Base Level FCM Contract Quantity reduced by the appropriate corresponding amount via a Contract addendum, or is the scope and degree of such reduction to the Base Level FCM Contract Quantity subject to prior Department approval and/or Department discretion?

Answer:  Once the 46th day has passed, the Base Level FCM (or LFRM) Base Level Contract Quantity would be automatically reduced by a corresponding amount such that the revised Base Level FCM/LFRM Contract Quantity is equal to the project’s Demand Reduction Value, as demonstrated in accordance with ISO-NE procedures and/or the Measurement and Verification Plan.  The Department does not have any role in approving or denying or altering the amendment of the Contract Quantity in this context.

10/31/06 Question:   Assuming arguendo that a demand response bid to provide 30 MWs of Base Level FCM Contract Quantity over a Demand Resource Contract term of 5 years is approved by the Department, what measure of liquidated damages would this winning bidder be exposed to under the following circumstances: (1)  the Demand Reduction Value of the demand response project is 20 MWs on the Milestone for the Commercial Operation Date; (2) the Demand Reduction Value of the demand response project is 20 MWs 22 days after the Milestone for the Commercial Operation Date; (3) the Demand Reduction Value of the demand response project is 20 MWs 46 days after the Milestone for the Commercial Operation Date; (4)the Demand Reduction Value of the demand response project is 20 MWs one year after the Milestone for the Commercial Operation Date; (5)  the Demand Reduction Value of the demand response project is 30 MWs, but only 20 MWs is eligible to participate in the applicable ISO-NE Markets due to a Market Change; (6)the Demand Reduction Value of the demand response project is 30 MWs, but only 20 MWs is eligible to participate in the applicable ISO-NE Markets due to an ISO-initiated change to an ISO-NE document other than a Market Change; (7) the Demand Reduction Value of the demand response project is 30 MWs, but only 20 MWs is eligible to participate in the applicable ISO-NE Markets due to an event other than a Market Change and other than an event of Force Majeure; (8) the Demand Reduction Value of the demand response project is 0 MWs on the Milestone for the Commercial Operation Date and, six months later this deficiency has not been cured and the Demand Reduction Value has not increased at all.

Answer:  NOTE THAT ANSWERS TO THIS QUESTION REFLECT CERTAIN REVISIONS TO CONTRACTS THAT WILL BE ISSUED BY NOV. 1, 2006.

(1) If this is all the project can deliver (after the 30 calendar day cure), the project would then owe liquidated damages of $200/kW for each MW of deficient capacity (namely, 30 MW from Proposal – 20 MW made available at COD = 10 MW).  Once the liquidated damage is paid ($200/kW * 10 MW = $2,000,000), then the Parties would prepare an Addendum to the Agreement and reset the Base Level FCM Contract Quantity at 20 MW for the Term of the Agreement.  The Supplier, from that point on, would be responsible for the operation and performance of only 20 MW of demand resources.  If the project is just late coming online with the remaining amount, the project would owe liquidated damages of $50/MW/calendar day until the full amount is ready for commercial operation.

(2) The liquidated damages for being 22 days late is equal to the Base Level FCM Contract Quantity of 30 MW * days late (22) * $50/MW and thus equals $33,000.
If 20 MW is all the project can deliver (after the 30 calendar day cure), the project would then owe liquidated damages of $200/kW for each MW of deficient capacity and could effectively reset the Base Level FCM Contract Quantity at 20 MW for the term of the Agreement. Thus, in this context, the LDs for insufficient capacity would be equal to $2 million. Total LDs in this context would be equal to $2,033,000.

(3) The liquidated damages for being 46 days late is equal to the Base Level FCM Contract Quantity of 30 MW * days late (46) * $50/MW and thus equals $69,000.
If 20 MW is all the project can deliver (after the 30 calendar day cure), the project would then owe liquidated damages of $200/kW for each MW of deficient capacity and could effectively reset the Base Level FCM Contract Quantity at 20 MW for the term of the Agreement. Thus, in this context, the LDs for insufficient capacity would be equal to $2 million. Total LDs in this context would be equal to $2,069,000.

(4) If 20 MW is all the project can deliver (after the 30 calendar day cure), the project would then owe liquidated damages of $200/kW for each MW of deficient capacity and could effectively reset the Base Level FCM Contract Quantity at 20 MW for the term of the Agreement. Thus, in this context, the LDs for insufficient capacity would be equal to $2 million. Note that this LD would be payable once the 30 day cure has expired – not one year later as per the question. 

(5) No liquidated damages would be due in this case pursuant to Article 3.3 (d). The Supplier and the Buyer would amend the contract such that the Base Level FCM Contract Quantity was reset to 20 MW. 

(6) As described, this sounds as though it would qualify as a Market Change, according to the definition in the Agreements. As such, no liquidated damages would be due in this case pursuant to Article 3.3 (d). The Supplier and the Buyer would amend the contract such that the Base Level FCM Contract Quantity was reset to 20 MW. 

(7) If 20 MW is all the project can deliver (after the 30 calendar day cure), the project would then owe liquidated damages of $200/kW for each MW of deficient capacity and could effectively reset the Base Level FCM Contract Quantity at 20 MW for the term of the Agreement. Thus, in this context, the LDs for insufficient capacity would be equal to $2 million.

(8) Missing the COD is an Event of Default with a 90 calendar day cure. Thus, the Supplier would incure liquidated damages equal to $135,000 and then be liable for the Early Termination Payment.

10/31/06 Question:  The pre-bid Q&A said there would be a place to submit heat rate curves as part of the Qualifications submission.  Can you point us to where that is located?

Answer:  On Sheet H1-C of the Generation Project Description Template, the instructions state that if the bidder has additional information regarding a facility’s heat rate, including any production output-heat rate curves, that that information should be submitted in addition to the information requested in Form H1-C. Thus, this information should be submitted separately, clearly labeling what it is.

10/31/06 Question:  Order number one in Docket 05-07-14PHI required Connecticut’s electric distribution companies to assist vendors in achieving their contractual
obligation for supplying resources to ISO-NE in response to ISO’s GAP RFP.
What assistance should vendors expect to receive from the electric
distribution companies in fulfilling their obligation under this RFP.

Answer: Section 4.3 of the Master Agreements lays out the Buyer’s obligations under this Agreement, although section 2.6 (i) of the Master Agreement for Demand Resources and Section 2.6 (h) of the Master Agreement for Generation also require the Buyer to provide commercially reasonable assistance in the Supplier’s efforts to attain Commercial Operation. Outside of these basic contractual obligations, Suppliers should not expect any other major assistance from the EDCs (i.e., bill inserts or advertising).

10/31/06 Question:  The RFP requires bidders to disclose funding already received for their
projects.  Would projects selected through the RFP be eligible for capital
awards under 05-07-17 in the future?  Would projects selected be eligible
to receive funding from the Conservation and Load Management fund
administered by the electric distribution company?  Would projects be
eligible to receive funding from the Connecticut Clean Energy Fund?
Answer:  As stated in Section 3.6 (d) of the revised Master Agreement for Demand Resources and Section 3.5 (d) of the revised Master Agreement for Generation (both issued Nov.1, 2006), the Supplier must notify the Buyer and the DPUC 30 calendar days before it would receive any Additional Ratepayer Funding. Such Additional Ratepayer Funding includes but is not limited to the Conservation & Load Management Fund, the Connecticut Clean Energy Fund, and any other funding authorized under the EIA (except for this RFP process).  The DPUC shall instruct the Buyer to reduce payments to the Supplier by an amount equal to the Additional Ratepayer Funding such that the total ratepayer funding for the Facility does not exceed the total amount payable to the Supplier anticipated under this Agreement.

10/31/06 Question:  The RFP requires bidders to disclose public funding they have received for their projects as part of the bid package.  Are resources that have
received capital awards as authorized in Docket 05-07-17 eligible to
receive any awards under this RFP?

Answer:  No. Per the capacity procurement provision, Conn. Gen. Stat. Section 16-243m(g), anyone recieving a DG grant per Section 16-243i is not eligible for a capacity contract under Section 16-243m.

11/07/2006
 Question:  Since combustion turbines aren’t allowed to run below 50% of their maximum capacity for environmental reasons, must bidders enter a value of 0 (zero) in the response for “heat rate at 50% capacity” on technical template form H1-C Heat Rate Information?
Answer: The DPUC is collecting partial load heat rate data to allow it to model the cost vs. output and efficiency of proposed generators.  The form H1-C “Heat Rate Information” has been amended to eliminate a minimum stipulated output level of 50%.  Bidders are encouraged to provide Heat Rate and output data for generators at 1) the lowest stable operating point, 2) at a point roughly midway between the lowest stable point and full load, 3) at full load and 4) at full load with power augmentation in operation (if applicable), to the extent stipulated percentage values on form H1-C do not achieve the foregoing objective for the particular generator proposed.

11/07/2006
 Question: If a bidder is proposing 3 separate scenarios at the same generating
site, is he or she  required to submit a completely separate qualification
submission for     each scenario or can they be packaged together in one
qualification submission.?

Answer:  The DPUC would prefer that a separate qualification submission be made for each proposed project/scenario so that there are no mistakes about which qualifications are for which projects/scenarios. If bidders are submitting multiple project proposals, and hence multiple qualifications submissions, the DPUC requests that the qualifications submissions for each project/scenario be clearly labeled and sent as separate emails/packages.

11/07/2006
 Question: Question regarding the relative humidity conditions specified for the
summer and winter inlet temperatures:  Gas turbine manufacturers typically
provide the winter and summer performance data with a standard relative
humidity value of 60% as the ambient humidity.  The gas turbine inlet
temperature is the most influential value on the performance of the gas
turbine, secondly barometric pressure, thirdly relative humidity.
Relative humidity has a very minor affect on the performance of the gas
turbine unless inlet fogging is added to the gas turbine.  Will the DPUC
accept the performance data for winter and summer inlet temperatures as
specified on Form H1-C using the standard relative humidity value of 60% as
the performance data for the turbine is readily available from the turbine
manufacturers?  

Answer:  The DPUC is no longer requiring the use of specific humidity conditions (see the 10/25 Project Description Template on the RFP website) for the Qualifications Submissions. Rather, the DPUC has stated that bidders should comply with all ISO-NE guidelines regarding assumed atmospheric and humidity conditions, and in the absence of such guidelines use generally accepted industry practice. 

11/07/2006
 Question: It seems that questions 6-16 on worksheet “Form H2-B Technical Description” do not apply to real-time demand response resources. Can you confirm this?

Answer: The intent of questions #6-16 on Form H2-B of the Demand Resource Project Description Template is to collect information regarding the operating profile of the capacity.  If the DR project utilizes a form of electric generation, we would like to know what the bidder can tell us about how the capacity will operate, how quickly it comes on line, whether there  is ramping or load following capability, etc.

If the DR project is an instantaneous load curtailment, those questions therefore would not apply.  If on the other hand, the DR mechanism is an “emergency” generator, then we would like bidders to answer the questions as best they can.

11/09/2006
 Question: Page 11 of 92 of the subject RFP states:  The DPUC will also accept bids
from refurbished or re-powered capacity as long as all of the following
conditions are met:   the aggregate summer demonstrated capacity on the facility site
   increases;    the original unit being refurbished or re-powered is at least 30 years
   old;    new investment at a pre-existing site electrically located in the state
   of Connecticut results in an increase in output greater than 20% of the
   site's demonstrated summer capacity, or 40 MW, whichever is greater; If a pre-existing site can support the installation of a new 47 MW Combustion Turbine and the upgrade of an existing 43 Mw Hydro Plant to 53 MW, would the developer obtain full credit for the 47 Mw Combustion Turbine and the 53 Mw Hydro Upgrade.

Answer:  Section 2.1 of the RFP states that the DPUC will accept bids for the entire capacity of a refurbishment proposal as long as all of the following conditions are met: 1) the aggregate summer capacity increases; 2) the original unit being refurbished is at least 30 years old; 3) the new investments result in an increase in output that is greater than 20% of the site’s demonstrated summer capacity or 40 MW, whichever is greater; and 4) the bidder will commit to the number of years that they will maintain a net increase in capacity at the site. If the bidder does not meet all of these conditions, the bidder would only be able to bid the incremental capacity into this RFP process.

 Based on the description provided above, the project appears to meet all of 4 conditions (assuming that the original unit is at least 30 years old and that the bidder will commit to a number of years of maintaining the new total capacity). As such, the bidder of such a project could bid the new 47 MW Combustion Turbine project with the 10 MW upgrade of the hydroelectric facility on the same site as an aggregate 53 MW + 47 MW = 100 MW facility.

Note however that the DPUC will evaluate proposals for refurbished capacity in the following manner, as stated in Section 2.1 of the RFP on p. 11: the DPUC will consider the full cost of the amount of capacity that is bid into the RFP process for the entire term of the contract. On the benefits side, however, the DPUC’s going forward assumption is that there will be no asset retirements or refurbishments in Connecticut until 2010. Thus, the project’s estimated benefits in the bid evaluation will only reflect the value of the incremental change in capacity in the near term (until 2010).

11/09/2006
 Question: Regarding the qualification submission, I understand 3.6 of the RFP to
specify that the electronic copies of the submission are due to LE and
DPUC on Monday by 5pm EST, with a hard copy to DPUC to follow.  Does
that mean the hard copy can arrive to DPUC on Tuesday morning?

Answer: Yes, this is acceptable as long as the electronic copies arrive by 5 PM on Monday November 13, 2006 by 5 PM.

11/09/2006
 Question: Exhibit H requests supporting documentation if the project meets Connecticut LSR requirements. Can you give us example of supporting documention that would suffice?



Answer: The bidder should submit documentation from ISO-NE or an independent engineer attesting to the fact that the facility will be electrically located in Connecticut.  For Demand Resource Projects, such documentation such state that the project is physically located in Connecticut.


11/09/2006
 Question: We are building one plant and are considering making three alternative bids, either different price paths or different contract durations, or a combination of the two. The material in the Submission Package does not change regardless of which bid(s) we propose. In other words, the identical Submission Package would support any or all of the bids.

As we prepare our filings for Friday (in order to reach you on Monday), it seems wasteful to duplicate identical Qualification Submission packages, particularly where we have bulk materials and confidential materials requiring special handling (e.g., labeling and sealed envelopes, etc.). In fact, other than labeling the packages A, B, and C, there would be no way to distinguish one package from the other. Moreover, we are concerned that such duplicate submission would contribute to a data overload and actually confuse things.


Answer: The DPUC is evaluating each proposal on its own merits and as such needs to evaluate the qualification submission of each proposal individually. We do not want to miss any nuances to the specific qualifications that a bidder may be highlighting for a given specific project. We believe that the additional administrative effort on both ends will be worth avoiding any confusion during the qualifications assessment process. As such, we request that bidders submit qualifications submission for each proposal they have.

11/09/2006
 Question: How do I submit a request for a delay in the Financial Bid Deadline?


Answer: To request a delay in the Financial Bid deadline, you can submit a letter with this request to the DPUC within Docket No. 05-07-14PH02, which will be considered by the DPUC in its deliberations on this issue.

11/09/2006
 Question: Can we make amendments to the Milestone dates that we provide in the Qualification Submission later in the Financial Bid.


Answer: Yes, if need be, you can amend the milestone dates in the Financial Bid, which will contain the contractually binding dates.

11/17/2006
 Question:Did “Company ABC” file its Bidder Registration statement on or before September 29, 2006?
Answer: As noted in previous Q&A, the DPUC is not releasing an official list of registered bidders, nor is the DPUC publicly releasing a list of entities that qualified pursuant to the November 13, 2006 qualifications submission process. Rest assured that the DPUC and the RFP Coordinator have carefully monitored and documented the timeliness of submissions. Each Bidder has received a confirmation regarding its registration and its qualification submission, if these were submitted in a timely fashion. Any entity that did not receive a receipt confirmation for its Qualification submission from the RFP Coordinator is not qualified to submit a Financial Bid on December 13, 2006.  The RFP Coordinator will be contacting those entities that submitted Qualification packages with their qualification status on or about December 1, 2006.