Question # 1 

a. The RFP mentions assignment of an ISO-NE queue position. However, it also appears that energy may be imported to ISO-NE. Could you please clarify as to whether projects outside ISO-NE can be bid into this solicitation?

b. Could you please elaborate on the extent of site control the project must prove? The RFP implies full site control. Would you consider projects underdevelopment that have some site control but have not yet achieved 100% site control?

Answer: 

a. Yes, projects sited outside of ISO-NE can be bid into this Request for Proposals, assuming that all eligibility requirements are met. Any such bidders should include their queue position for the associated control area.

b. With the exception of a bidder proposing an offshore wind energy, the bidder must demonstrate that it has control, or an irrevocable option (conditioned only upon the payment of a reasonable amount) to acquire control, over the site for its proposed generation project, including any rights necessary to access the project site and any rights to the generator lead to the Delivery Point under the PPA (or, if the project is not within ISO-NE, to the point of interconnection for the project). Please refer to section 2.2.3.3 of the RFP for full Site Control requirements.

Question # 1

Would you kindly send me the link where I can download the study, “Base Case, Class 1 Market Price for Rhode Island” by Sustainable Energy Advantage? It is referred to on page 13 of the RFP, and I have search for it but only found related studies by SEA.

Answer: 

Please contact Sustainable Energy Advantage to learn how to access the “Base Case, Class 1 Market Price for Rhode Island”.

1) Please see questions below. 

a. May bidders use a template for the response or do we have to use the word document that RI provided?

b. Will the evaluation committee/National Grid accept USB with password protected?

c. When is payment submitted for bid fees?

d. How should CEII information be treated? If bidders have attachments/materials that contain CEII, can bidders wait for the evaluation team to request this information? “During the evaluation of bids, ISO-NE will, and other authorities may, be requested to provide information to National Grid, OER, and the Division concerning proposals as part of the proposal evaluation process. Information classified as Critical Energy Infrastructure Information (“CEII”) will only be shared with National Grid, OER, and the Division who are cleared to receive CEII by ISO-NE or any applicable other authorities. By participating in this RFP, bidders agree that ISO-NE and the other authorities may release information related to the projects which may otherwise be considered confidential under the relevant rules or policies of such organizations, to the entities and individuals involved in the evaluation of bids.”

e. Under section 2.2.2.3 it is explained that eligible bids must be below the forecasted market price of energy and RECs over the term of the proposed contract. What indices(s) will bids be compared to?

Answer: 

a. Bidders may submit their own template in lieu of populating the Appendix B Bidder Response Form, although such a template should provide the data requested in the Appendix B Bidder Response Form and utilize the same section numbering to facilitate review.

b. Password-protected USB flash drives will not be accepted.

c. For a bid to be considered “complete”, full payment for bid fees should be submitted at the same time the proposal is submitted. If a bid is submitted prior to the deadline, but the payment is received after the deadline for proposals, the bid may be rejected as “incomplete” and not considered.

d. If relevant to their proposal, to facilitate bid evaluation, bidders are encouraged to provide Critical Energy Infrastructure Information as part of their original bid submission.

e. National Grid plans to use the ENELYTIX model employed by the consulting firm of Tabors Caramanis and Rudkevich. The model will forecast the energy and REC price based on publically available market information and will compare the project developer’s bid price to the summation of the model’s energy and REC price.

2) Regarding question for next week’s Bidder’s conference see below..

 a. Are you considering behind the meter solar as part of the this RFP?

b. Are you considering working with third party suppliers on alternative deal structures to incorporate the renewable power project(s) selected into the supply to your metered location?

c. Is the Bidder’s Conference “live” only, or will there be a call-in number?

Answer: 

a. No. As noted in Section 2.2.2.2 of the RFP, a generation unit is not eligible under this RFP if it is net-metered or located behind a retail meter.

b. No, this is not something National Grid is considering.

c. There will be a teleconference number provided to registered attendees of the Bidder Conference.

3) We have the following question in relation to the RI Clean Energy RFP:

In Section 1.2(c) of the RFP, it states “regardless of whether it is located in Rhode Island or not, the project must provide substantial direct economic benefits to Rhode Island…..”. For projects which are not located within the State of Rhode Island (and therefore do not generate RI tax revenue or employment), if possible please provide examples of the type (and if able, magnitude) of direct benefits that would be considered as acceptable to meet the RFP requirement.

Answer: 

One example would be a proposal’s operational production data (hourly delivered energy). As noted in Section 2.3.1 of the RFP, all projects, regardless of their location, shall provide other direct economic benefits to the State of Rhode Island. A project’s effect upon locational marginal prices and REC market prices will be evaluated in the price analysis of Stage Two.

1) My question is the following:

Would you please confirm if a separate nonrefundable deposit is required for each of the following scenarios for the same project:

• 15 year PPA

• 20 Year PPA

• Collocated storage option

Answer:

The fee for an additional pricing offer only applies for variations in pricing and/or alternate contract term lengths for the same project. For all other cases a new bid fee is required. As such, an additional $25,000 fee would be required for each of the 15 year and 20 year contract term lengths. Proposing a collocated storage option would require a new bid fee.

2) a. Please post the presentation from the Bidders Conference held on Wednesday, September 26, 2018. b. Please clarify if bidders are required to submit pricing scenarios for each of the pricing scenarios contemplated in Section 2.2.4.2.1 Allowable Forms of Pricing: in the RFP or if bidders may submit their preferred pricing scenario only.

 Answer:

a. The presentation from the Bidder Conference was posted to the RFP website at https://ricleanenergyrfp.com/ on September 27, 2018. b. Bidders must submit at least one of the pricing options stated in Section 2.2.4.2.1 Allowable Forms of Pricing of the RFP, but may submit additional options, if desired.

3) a. Given that resources are eligible to participate in other RFPs that are pending or will be issued during this RFP, can an additional pricing offer be contingent on an award under  another RFP? If so, would such a pricing offer require an additional $25,000 bid fee?

b. Section 5.3 of the LTCS Regulations (RFP Appendix C-2) requires that all Long-Term Contracts contain provisions to allow the Electric Distribution Company to terminate the contract after 3 years if material progress is not being made on the project. PPA Section

3.1 will include Critical Milestones that may extend beyond that 3 year period and provides for extensions of those Critical Milestones (including potentially four six month periods under Section 3.1(c)). When filing for approval of any PPA resulting from this RFP, will National Grid seek a waiver or other appropriate relief from applicable regulations to preserve the integrity of the PPA structure regarding Critical Milestones?

c. Please confirm that the reference to "PPA capacity" in RFP Section 2.2.2.3 relates to the authorization of National Grid to procure capacity, energy and RECs under applicable law for the Long-Term Contracting Standard, rather than the contractual terms and conditions of a PPA resulting from this RFP.

d. When will National Grid determine whether to require pricing at the Rhode Island zone per RFP Section 2.2.4.2.2?

e. Regarding the bid fee calculated under Section 2.2.4.4 of the RFP and assuming a 100 MW nameplate project, please confirm:

(i) the bid fee would be $150,000 if the bidder proposes three pricing options but all other elements of the project remain the same (e.g., project size, technology,

delivery point, in-service date, length of PPA term, etc.);

(ii) another $75,000 bid fee would be due if the bidder proposed the exact same project as in clause (i), including the three pricing alternatives, but the length of the proposed PPA term differs from that proposed in clause (i); and

(iii) increasing the size of the project from 100 MW, would require the payment of a $100,000 minimum bid fee (assuming a nameplate size 100 MWs or greater),

plus $25,000 for each pricing option and/or PPA term variation. 

f. If a bidder proposes a 100 MW project with a 15 year contract term (base bid) and the bidder is also proposing a 150 MW project with a contract term greater 15 years (alternative bid), then does the bidder need to additionally submit a bid for 150 MWs with a contract term of 15 years?

g. Are there any parameters on a bidder's ability to reconcile the requirement of the contract being unit specific (RFP Section 2.2.2.3), with the ability to propose a pro rata portion of a larger project (RFP Section 2.2.2.5). Would metering be an acceptable way to accomplish the sale of 50% of the energy and RECs produced by a 100 MW project?

h. Please clarify the basis in Section 6.1 of Appendix B for requiring wind and solar projects that provide hourly data to supply an hourly profile specific to 2012 weather

patterns. Is it acceptable to provide a projection of ‘weather normalized’ production based on more recent information? If not, please provide more specificity on how a

bidder should provide an hourly profile specific to 2012 weather patterns.

i. Section 6.1 of Appendix B states, “If your bid includes a delivery forecast which is substantially different than NREL data would suggest, please reconcile the differences.”. In order to allow bidders to accurately calculate this could you please provide a link to the specific NREL data being referenced in Section 6.1?

j. At the Bidder Conference a question was asked if more insight could be given surrounding the language in the RFP from Section 2.3.1 that states, “National Grid plans

to use a price forecast that will incorporate the effects of future federal or state regulation of carbon dioxide emissions on relevant energy prices.” The response from

the Bidder Conference suggested that only a RGGI forecast will be used for carbon. Will only an estimate of RGGI costs be used or will some other federal carbon price forecast be incorporated in addition to RGGI costs? If an estimate for a federal carbon program will be utilized, what will be the basis for this cost?

Answer:

a. Related to bid fees, additional pricing offers cannot be contingent on an award under another RFP. That is to say, no pricing offer can be contingent on an award under another RFP, nor will an award another RFP alter bid fees for additional pricing offers.

b. At this time, National Grid does not plan to seek a waiver or relief from Section 5.3 of the Public Utilities Commission’s (“PUC”) Long Term Contracting Standard regulations, which allows the Company or the PUC to terminate, without penalty, a long-term contract after 3 years if material progress on the project is not being made.

c. The reference to "PPA capacity" in RFP Section 2.2.2.3 refers to the contractual requirements of a potential PPA resulting from this RFP.

d. Such a determination will be made during the Stage Two Price and Non-Price Analysis portion of the bid evaluation and selection process.

e. The fee for an additional pricing offer only applies for variations in pricing and/or alternate contract term lengths for the same project. For all other cases a new bid fee is required. As such:

(i) Confirmed.

(ii) Confirmed

(iii) If there are changes to any physical aspect of a project, including but not limited to project size, technology type(s), production/delivery profile, in-service date,

or delivery location, then another bid fee will be required. So, a bid fee of $100,000 would be required for the 100 MW nameplate capacity project, plus an

additional $100,000 for the higher nameplate capacity project, plus an additional $25,000 for each pricing offer.

f. In such an instance, a bidder must submit a pricing schedule for 10 to 15 years for the 150 MW project. Bidders seeking contract terms longer than 15 years must demonstrate that the longer contract term is a contract cost savings, and must submit pricing schedules for: (1) a contract of 10 to 15 years; and (2) for the longer contract term and the required bid fee.

g. Subject to review of the exact proposed changes to the Draft Contract submitted by a bidder, metering may be an acceptable means of structuring such a sale.

h. The evaluation team uses a modeling system whose annual hourly profiles are benchmarked against 2012 datasets; specifically, the profiles for variable generation

such as PV and wind are configured against 2012 weather patterns. By providing 2012 hourly generation data, the bidder is (a) maintaining consistency with the modeling system, as well as other bids, thereby ensuring fairness in evaluation, and (b) providing granular data that allows the team to model the bid unit with fewer differences. In addition to 2012 hourly shapes, a bidder may provide a 12x24 profile that accurately represents the unit’s capacity factor, with the latitude and longitude of the Eligible Facility. The latitude and longitude of the Eligible Facility will allow the evaluation team to determine an estimated generation profile for the project, based on 2012 weather patterns which will reflect the bidder provided capacity factor. Typically, historic hourly weather data for 2012 may be obtained for the specific project location through a variety of available resources e.g. NREL, NOAA, NCDC. The weather data can then be used to determine the hourly unit performance for 2012 using OEM performance curves, proprietary simulation models or various other numerical methods.

i. The NREL data source is the NREL wind toolkit (https://www.nrel.gov/grid/windtoolkit.html) and the solar data sets (https://www.nrel.gov/grid/solar integrationdata.html). NREL may be contacted to obtain the full set of hourly data points.

j. While National Grid was considering various options at the time the RFP was issued, after further planning of its evaluation protocol, RGGI pricing for carbon will be the only carbon cost incorporated in relevant forecasted energy pricing. 

4) a. Under section 2.2.2.3 it is explained that eligible bids must be below the forecasted market price of energy and RECs over the term of the proposed contract. What

indices(s) will bids be compared to?Note: We contacted Tabors Caramanis and Associates as well as SEA. SEA indicated they have the REC index, but neither seems to have the energy index and referred us back to NationalGrid. Can you please provide the index, the model and/or assumptions that will be used to evaluate the bids?

b. Please clarify that the inclusion of storage in a proposal will not disqualify a bid.

c. Please clarify that the inclusion of co-located behind- the- meter/generation storage) will not disqualify a bid.

Answer:

a. National Grid plans to use the ENELYTIX model employed by the consulting firm of Tabors Caramanis and Rudkevich. The model will forecast future energy and REC prices and will compare them to the bid prices received to determine if the bids are below the forecasted market price of energy and RECs. The model does not use published forecasts for energy and REC prices.

b. The inclusion of storage in a proposal will not automatically disqualify a bid but the bidder must explain how the output from the storage facility is a qualified resource.

c. Behind-the-meter projects are not eligible for this RFP, including co-located, behind-the meter generation and storage

5) After reviewing the RFP materials for Long-Term Contracts for Renewable Energy, we just have a couple questions related to the Bid Fees that we would like to clarify. Please see below for our questions:

a. In Section 2.2.4.4 of the RFP (Non-Refundable Bid Fees), it states that “each additional pricing offer for the same project, including those with alternate contract lengths, will cost an additional fixed fee of $25,000.” Section 2.2.4.2.1 sets forth the allowable forms of pricing, with options (a) through (c). Does the additional $25,000 fixed fee apply if a bidder would like to submit pricing offers in more than one of (a) through (c), such as a fixed price and then a price with an annual escalator, but everything else is the same about the project (i.e. it is the same project size, location, technology, contract length, etc.)?

b. What would be the case if a bidder wanted to propose a standalone project option (i.e. no storage component) as well as a project option with storage, but the other details of the project remain the same? Would this be considered two pricing offers and require the additional $25,000 fee? From playing with the CPPD form, it appears that the situations described above would require additional $25,000 bid fees, but we wanted to confirm.

Answer:

a. Correct, the additional fixed fee of $25,000 will apply to the additional pricing offer. This will be in addition to the initial minimum bid fee. The initial minimum bid fee will be $25,000 for a project with a minimum nameplate capacity of 20 MW, and bid fees will increase by $1,000 for each MW above 20 MW to a maximum bid fee of $100,000.

b. The $25,000 fee for an additional pricing offer only applies for variations in pricing and/or alternate contract term lengths for the same project. For all other cases a new bid fee is required. As such, proposing a collocated storage option would require a new bid fee. Please see also the response to 5(a), above.

6) a. Contract form

Please confirm that all resources outside of the ISO-NE control area should use the “Import” form of PPA.

b. Minimum Required Deliveries (Definition, 4.3)

Can you confirm that the Minimum Required Deliveries Definition and usage in Section

4.3 do not imply a production guarantee (and any redundancy therefore with the Biennial Delivery Deficiency), but rather solely apply to the relationship and accuracy

between metered vs. scheduled energy?

c. Reliability Curtailment (Definition, 4.4)

Can you provide further detail and examples of what is meant by part (ii) of the definition (“any other order or directive…”)?

d. Delay Damages (3.2)

In the event of termination by Buyer for Seller failure to meet Guaranteed COD, are Delay Damages owed under 3.2(a) netted against the Seller Termination Payment in 9.3(b), or in addition to?

e. Capacity Deficiency

(Definition, 3.3(b)) If there is a Capacity Deficiency at COD, can the Seller declare COD on the completed portion and then continue to build out the remainder of the project and pay Delay Damages, or is a permanent reduction the only option?

f. Forecasts (3.5(f)) 

What is the purpose of the requested Forecasts and are there any associated Damages or Breach provisions for the Seller?

g. Qualification of RECs

for other states (4.7(c)) Noting that the Breach clause in 9.2(j) only applies to 4.7(b) – maintaining Renewable Energy Standard eligibility – can you clarify Seller obligations to qualify for other states as outlined in 4.7(c) and what, if any, default and breach provisions apply here?

h. Credit replenishment

(Article 6) (i) Can you detail what, if any, obligations Seller has for replenishment of Development Period Security and/or Operating Period Security in the event of a draw by Buyer and as it relates to events of Default by Seller in 9.2(b), Failure to Maintain Credit Support (and the statement therein about failure to replenish)? (ii) In 6.3, the PPA states that “Buyer may request… Credit Support having a Value of at least the Collateral Requirement”. Can you clarify what is meant by this, and specifically how and why Buyer might request credit support in excess of the Collateral Requirement if that is implied in the meaning?

i. Termination Payment (9.3b)

What is meant by the statement “probability of exceedance basis of 50%”?

j. Adjusted Price (Exhibit D, 4.7(b)(ii)), 5.1)

(i) What are the specific limitations and thresholds for the Adjusted Price vs. the Product Price?

(ii) Is there meant to be a relationship between the Adjusted Price for Scheduled Energy and the Scheduled Energy component of the Product Price?

(iii) Put differently, can Seller propose an Adjusted Price for Scheduled Energy as allowed under 4.6(b)(ii) (Change in law impacting REC qualification) of its choosing, or must it be computed from the implied REC value as a component of the (bundled) Product Price?