Q&A: RMI Shine Texas RFP

NOTE: This information was last updated on February 7th, 2018.

Q: The RFP refers the upper boundary system sizes as 2 X 0.99MW. Does this mean two separate 0.99 MW projects with different interconnections, or a single interconnection?

A: This means two 0.99 MW AC projects with separate interconnections. Projects ≥ 1 MW AC do not avoid transmission demand charges (ERCOT 4CP) or some of the other benefits. Since this can be more than 50% of a project’s lifetime value, every 0.99 MW AC project should have a separate interconnection.  

Q: Do projects need to be decommissioned after year 20?

A: No, projects are not required to be decommissioned at end of PPA. Bidders can model the post-PPA revenue in any way Bidder’s financiers will support (e.g., merchant, continued agreement with Buyer, no revenue).

Q: What is meant by the request for PPA prices for different portfolio sizes in tab 9 (columns T through X)?

A: We ask for a PPA bid for every project (16 in total, 15 if CoServ: Oak Point’s solar-and-storage bid is excluded). The baseline assumption should be the PPA price if the Bidder wins the entire portfolio, of approximately 12 MWs across three Buyers. These baseline PPA prices (again, one for each project) should be pasted in the RFP bidsheet’s tab 9, column V. Buyers are interested to understand how PPA prices change if the portfolio shrinks (individual project or 8 MW) or increases (to 20 or 40 MWs). Please submit your PPA prices for each project for different portfolio sizes in tab 9, columns T, U, W, and X. You can assume that all additional projects for the 20 MW and 40 MW portfolios are 0.99 MW in size and in a 250 mile range of the three Buyers in this RFP.

Q: For tab 10 of the RFP bidsheet, should we take Bluebonnet’s Maxwell Service Center 0.99 MW at a 12 MW portfolio size as the baseline, or 1.98 MW at an 8 MW portfolio size?

A: Please use the 0.99 MW system at a 12 MW portfolio size as baseline. Tab 10’s value should have read “This is the value of tab 9 cell V9”.

Q: Cells D10 and E10 of tab 14 of the RFP bidsheet don’t have a list. What should we do?

A: You can leave these cells blank.

Q: Is the land cost for Shadow Glen substation $19,000/acre-year?

A: Yes. We are aware that this assumption is too high. It is based on land rates available at time of RFP preparation. Please use this assumption ($19,000/acre-year) in your PPA modeling. This will not negatively influence your bid.  

Q: Is it acceptable that 8760s will be exempt of night time and auxiliary losses, showing gross production, ensuring that the RECs produced will equal the solar energy produced?

A: Any power use for auxiliary power or night-time power should be included as a operation cost for the project, but should not be reported in the 8760s. 8760s should report AC power injected into the grid.  

Q: Does including a storage bid for sites other than CoServ: Oak Point (SOLAR-PLUS-STORAGE) influence this first round? Are the buyers interested in bidders proposing solar-plus-storage for other sites than this? Or is this postponed to later rounds?

A: Bidding more than one storage bid will not influence round 1 evaluation. The Buyers are interested in more storage bids if economics prove favorable, this will be included in round 2.

Q: If a bidder is aware of a more optimized solar and storage solution, can this be bid into the bid sheet in the bid sheet Tab 13 “Solar + Storage 8760”?

A: Other than as stated in the bid sheet as it relates to ERS, please only optimize your response within the boundaries given in the bid sheet and model. Specifically, please keep combined battery and solar output and input upper-bound limited at 0.99 MW-AC, independent of greater combined solar and battery power DC discharge capacity. We will provide a new set of common guidelines to all Round 2 bidders on solar and storage if the buyers continue to pursue such projects.

Q: If Buyers default on a project between PPA signature and COD will the RMI fee be returned?

A: No, although only one third of RMI’s success fee is due on PPA signature (0.5 cents per W-DC, or $5,000 per MW-DC).

Q: What is the Roanoke roof tilt and what type of roof is it?

A: The roof is flat and the roofing material is thermoplastic polyolefin (TPO).

Q: You list multiple sites by entity. What if we were able to identify a single site per Buyer that could achieve the maximum solar capacity or more? Would Buyers consider that given the interconnection costs would be lower thus improving the project economics?

A: In principle, no. Systems of 0.99 MW AC or less avoid transmission demand charges and generation demand charges (for CoServ projects). In order to collect these benefits each 0.99  MW AC array must have a separate interconnection. While it is possible to build multiple systems with separate interconnections on a single site the Buyers believe it is unwise to extend this practice to more than two interconnections on a single site. As an aside, if you have had contact with landowners in Bluebonnet territory, please list this in Appendix E.

Q: What should we use for irradiance assumptions? How will you be able to ensure that the irradiance assumption for all bidders is equal?

A: Please use hourly Typical Meteorological Year data (TMY3) from the nearest weather station. A tool like PVSyst or SAM will automatically default to this when you enter site or substation latitude and longitude. We will analyze all RFP responses to see if specific production is within reasonable bounds. Each Bidder is held to production clauses in the PPA and therefore should use appropriate irradiation values.

Q: I noticed there is a price in the Land Cost ($/acre-year lease) in the Shadow Glen Substation and Chappell Hill Substation project sites.  How do we know how many acres we need to apply the land cost to?  

A: Your submitted bid should maximize NPV for the specified land costs and the irradiance at substation location. The required acreage follows from your optimum system design.

Q: Can RMI provide an outline for each site within the Google Maps data set for the specific boundaries of land available?

A: RMI is not making detailed site plans available at this stage. Bidders are not required to do detailed site plans and can and should use only the information available in Appendix B.  

Q: Have RMI and/or the participating Buyers determined the feasibility to apply for, and obtain, property tax exemptions for all sites?

A: Please assume that it is not feasible to get property tax exemptions.

Q: If not, is there a default $ assumption we should incorporate into the financial modeling for purposes of applying for, and obtaining, such exemptions?

A: Please assume that it is not feasible to get property tax exemptions.

Q: Is there just 1 PPA to sign for all of the projects?

A: Each power buyer signs their own PPA(s). Whether each project is signed individually, in a subgrouping of buyer’s projects, or for all projects of each power buyer is TBD.

Q: Who will be the off-taker and PPA counterparty for the UNT front-of-the-meter project?

A: UNT is in discussions with their utility to decide how this will be managed.  

Q: Are clarifying questions due 1/29 (see RFP’s cover page), or 2/2 (see RFP 1.6 Schedule)?

A: Clarifying questions are due by February 2nd.

Q: What was the term for the Colorado PPA and did it escalate?

A: 25 year PPA, 0% escalator. Additional discussion of Colorado RFP results can be found here.

Q: What PPA term are you asking for in Texas?

A: 20 year PPA, 0% escalator

Q: What discount rate does RMI use when calculating NPV?

A: Discount rate depends on buyer, these are listed in the Financial Evaluation Model’s INPUTS menu tab.

Q: Who is responsible for monetizing the Investment Tax Credits?

A: Bidders are responsible for monetizing the ITC.

Q: For performance guarantees, should the module degradation rate be the degradation rate reflected in the performance guarantee?

A: Yes, please use the warrantied degradation rate in your modeling. You can specify the degradation rate in the RFP Bidsheet’s tab 9, columns L and M.

Q: Should bidders use same solar resource in model regardless of site?

A: No, please model solar resource specifically for each site. You can use the latitude and longitude per site as specified in RFP Appendix B.

Q: Are bidders required to submit the site designs corresponding to 8760s submitted in the model?

A: The 8760s in the model are simply dummy entries. Bidders should not do anything with these 8760s except replace them with their own modeled 8760 data.

Furthermore, Bidders are not required to specify site designs. However, if Bidders believe their site design has a competitive advantage, Bidders can upload the site designs with their RFP response using the Dropbox link on our website.

Q: The model does not allow for substation deferral for the Bluebonnet EC Gay Hill site under any modeling circumstances. Is this an error?

A:  Our apologies, though while not an error, it is admittedly confusing. Please ignore substation deferral for that site, as deferral is not possible. It should have been marked as “NA” rather than provided inputs related to substation deferral in the INPUT Menu worksheet.

Q: Are any of the sites space constrained? How will module efficiency advantages be evaluated for space challenged sites such as the rooftop project (CoServ’s Roanoke Substation)?

A: Yes, some sites are space constrained, such as the site at CoServ’s Custer Substation (visible on Google Maps) and the rooftop close to CoServ’s Roanoke Substation. The Buyers are interested in maximum economic benefit, not necessarily maximum MW-AC output. If Bidders think a different technology will benefit the Buyers, they can submit site designs with the RFP response. Technology specifics can be specified in tab 5 of the RFP Bidsheet.

Q: Do we have the option to provide PPA price without EPC if we are not interested in pure EPC services?

A: Yes, although Bidders are asked to specify installed price in $/W-DC in tab 9 of the RFP Bidsheet.

Q: Will a single Bidder be awarded the contract for all sites, or will multiple Bidders be selected?

A: Most likely the Buyers will select a single winning Bidder, unless round 2 bid data shows that all Buyers would be better off with selecting more than one winning Bidder.