Post Date: 5/25/11
General
Q: What if the notes section of the Excel forms does not have enough space for comments?
A: Even though the full text is not visible when viewing the entire form, the data is captured in the cell when you click on the cell.
Q: When are the updated Time of Delivery (TOD) factors going to be available?
A: The TOD factors are available in the form now.
Q: When will Attachment D be finalized?
A: We have asked the CPUC to complete their revisions to the Project Viability Calculator by the end of May.
Q: In Section XX. H, p 51; Required Forms for Short-term Offers, should the reference in this section be to Section VIII.D, and not VIII.C?
A: Yes, the reference should be to section VIII.D “Required Forms”.
Q: Will there be a form biogas contract available for review? If so, when?
A: There will not be a form contract issued. Please submit a detailed term sheet.
Q: Is there a bid deposit required for each proposal?
A: Yes, for each project that is shortlisted. It does not apply to power or RECs from existing resources for terms of less than 5 years.
Q: Do existing, operating projects need to provide the same level of information as new ones?
A: Existing projects will generally require less information than new facilities. As noted on page 23 of the Solicitation Protocol, we do not required tabs 6 and 7 and some of the information in tab 3 related to the construction of a new facility.
Q: Is a PPA mark-up acceptable?
A: PG&E prefers that offers include a term sheet.
Q.Can all variations of an offer be submitted in one Attachment D and one Attachment I?
A: A separate Attachment D should be submitted for each offer variation. One detailed term sheet (Attachment I) is sufficient.
Q: Is there a preference for women-, minority- or service disabled veteran-owned business enterprises (WMDVBE)?
A: WMDVBE status, or intent to subcontract with MWDVBE suppliers, is a consideration in the solicitation.
Q. The RFO seems to use the terms “seller” and “participant” interchangeably on page 22 when limiting the number of Offers to five if the offered projects total more than 200MW. Please confirm that these terms are interchangeable.
A: Yes.
Eligibility
Q: Isn’t 2% equal to about 200 MW of baseload? Is PG&E really going through all of this for the equivalent of 200 MW baseload?
A: As shown on Table III.1 of the RFO Protocol, 200 MW of baseload power is equal to about 2% of PG&E’s bundled sales. Assuming a capacity factor of 25% for intermittent resources, PG&E could procure 800 MW for an equivalent amount of energy.
Q: Does PG&E have a preference for any particular size project?
A: PG&E does not have a specific preference for any particular size project. PG&E will consider the market value of the energy, and the viability of the project. PG&E will also consider counterparty concentration (see page 44 of the protocol).
Q: Does PG&E prefer to treat microgeneration (<=1 MW) differently?
A: As noted on page 7 of the Protocol, the minimum project size for participation in this RFO is 1.5 MW.
Q: Are projects interconnected pursuant to a California IOU’s WDAT considered part of the CAISO control area?
A: Yes.
Q: Is project location “in California” (for PG&E ownership) defined by the first Point of Interconnection or by generator location?
A: It is defined by the first point of interconnection if in the CAISO Balancing Authority area.
Regulatory Policy/RPS Compliance
Q: Are you able to estimate roughly the number of MWh of REC-only products you will likely need to procure?
A: No. PG&E has not specified a particular percentage of REC-only versus other products. However, parties should consider that the 33% RPS legislation does limit PG&E's ability to buy unbundled RECs, so that by 2020 no more than 10% of PG&E’s post-June 1, 2010 energy procurement is from unbundled RECs.
Q: The CPUC capped REC-only prices until 12-31-2013 at approximately $50/MWh. Is that cap effective for this bid?
A: Generally, until the CPUC rescinds its earlier orders, we understand that its directives remain in effect. We expect that the CPUC will address this issue later this year when it implements the provisions of the 33% RPS bill.
However, if your bid is for RECs that would deliver after 12/31/2013, then the current price cap may not apply. However, PG&E is unable to speculate whether the CPUC will choose to extend a price cap to the period after 2013.
Q: Does a project with the first point of interconnection in Pacificorp’s service territory meet the requirements of Bucket #1?
A: This is an issue PG&E expects the Commission to address in its 33% RPS implementation. The 33% legislation does indicate that a California Balancing Authority is located primarily in California. It is unclear whether Pacificorp meets this requirement.
Q: PG&E indicated a preference for COD flexibility and certainty. Please clarify.
A: While the 33% RPS bill sets procurement targets of an average of 20% for the 2011 to 2013 period, 25% by 2016, and 33% by 2020, the targets for the interim years (i.e., 2014, 2015, 2017, 2018 and 2019) are to be set by the CPUC in its 33% RPS proceeding. Therefore, PG&E does not yet know how much it will be required to procure to meet the RPS targets. Therefore, the more flexibility you can provide with your COD the better, given PG&E may have a need to procure more for the 2014 to 2016 period or for the 2017 to 2020 period.
Q: Is there a preference regarding COD?
A: As noted above, the 33% RPS targets have not been fully established. Therefore, given the uncertainty, flexibility in COD is key. In this RFO, our focus is currently on the 2014-2016 period.
Q: What do you mean when you say that flexibility in online date is preferred? Would you like a range, i.e. 1/1/2014 to 12/31/2014 or different fixed dates?
A: PG&E would prefer option with respect to fixed start dates, such as a project that could start on 1/1/2015 or 1/1/2016. Variation in start date by year versus months in a particular year is preferred, given the annual RPS targets have not yet been determined.
Q: Will geothermal projects in Utah be evaluated considering the recent change with respect to in-state and out-of-state RECs?
A: PG&E will consider out-of-state offers, as long as they are in the WECC, but it will have a preference for out-of-state offers that can deliver to a California Balancing Authority, directly connect to the state, or use dynamic transfers to deliver to the CAISO. PG&E has some ability to procure out-of-state energy under firming and shaping arrangements, however, these products must first be defined by the CPUC in its 33% RPS rulemaking. PG&E’s ability to procure unbundled, undelivered RECs will be limited going forward.
Q: What are PG&E’s thoughts on out-of-state projects and what are they looking for from the Project (in light of the California Transmission Planning Group (CTPG) dropping 30%/30% in-/out-of-state constraint)?
A: CTPG’s dropping of the 30%/30% in/out-of-state constraint does not influence PG&E’s thoughts on out-of-state projects, given the 33% RPS requirements override CTPG’s actions. PG&E will consider out-of-state offers, but it will have a preference for out-of-state offers that can deliver to a California Balancing Authority, directly connect to the state, or use dynamic transfers to deliver to the CAISO. PG&E has some ability to procure out-of-state energy under firming and shaping arrangements, however, these products must first be defined by the CPUC in its 33% RPS rulemaking. Furthermore, PG&E’s ability to procure unbundled, undelivered RECs will be limited going forward, given the 33% RPS requirements.
Q: If an out-of-state project can obtain firm transmission, will it be considered bucket #1 or #2?
A: We don’t know at this time. This is an issue that will need to be resolved at the CPUC.
Q: Clarify rules for delivery of unbundled TRECS.
A: Unbundled RECs must satisfy all CEC ERR requirements, meaning the facility must be located in the Western Electricity Coordinating Council (WECC) and the facility must register and comply with the Western Renewable Energy Generation Information System requirements. It is PG&E’s understanding that unbundled RECs have no delivery requirement; rather the generation must be only be delivered somewhere in the WECC and meet other RPS requirements. PG&E expects this will be confirmed in the CPUC’s 33% RPS Implementation proceeding.
Q: The RFO allows offers for California-eligible TRECs generated prior to 2011. Can you provide insight on which vintages would be allowable and most compelling to PG&E? 2010? 2009?
A: This is still being determined. However, parties should consider that RECs will need to be retired within 36 months of their creation for compliance and, should PG&E procure more RECs than needed for compliance, it may not be allowed to carry any extra amounts to future compliance periods. In addition, PG&E’s ability to use out-of-state RECs would depend on clarification of any delivery requirements.
Q: Is there a point of delivery for unbundled RECs?
A: No but the RECs must be tracked in WREGIS.
Q: Is there a requirement for physical transmission capacity?
A: There is no requirement for physical transmission capacity for unbundled RECs.
Q: Please comment on any challenges receiving CPUC approval of PPAs resulting from lag in procurement process while prices decline (PV especially).
A: The CPUC is responsible for approving PG&E’s RPS contracts and must find that the contracts are just and reasonable and in the interest of customers. With respect to recently executed PPAs, CPUC approval has taken 6-12 months, and PG&E’s form PPA allows 240 day for CPUC approval. A recent CPUC draft resolution would reject a solar PV contract that is, accordingly to the CPUC, not priced attractively vis-à-vis other, more recent offers. Accordingly, parties should consider this possibility when submitting bids and offer the most attractive prices possible.
Q: Will PPAs be issued in time for the 1603 grant? Otherwise the price will be higher by $22/MWh.
A: The Section 1603 tax grants are currently expected to expire at the end of 2011. To be eligible for the grant, construction on the project must begin by December 31, 2011. While it may be possible for a contract to be executed before year-end, it is not binding until CPUC Approval (as defined in the contract) is achieved. A party could choose to begin construction prior to CPUC approval and qualify for the grant. However, if CPUC approval is required prior to the start of construction, there is probably insufficient time to achieve CPUC approval by year-end.
Interconnection Issues
Q: For out of state interconnections, are there any connection requirements to PG&E? Or is it all done via wheeling contracts?
A: The interconnection requirements are handled by the interconnecting utility or balancing authority. PG&E requires you deliver energy to a CAISO import point. This may be accomplished with wheeling contracts or with a firming and shaping arrangement.
Q: Would a project connecting to the Sunrise Power Link, but not in the Imperial Valley, be viewed the same as a project physically located in Imperial Valley?
A: Yes. The CPUC decision instructed the utilities to seek out projects that created increased flows on the Sunrise Power Link. Please note that PG&E requests your offer provide detailed information as to you point of interconnection, your status in the interconnection queue and how you will deliver energy to the CAISO if your project is not within the CAISO balancing authority.
Q: For bidders outside of CAISO, how can I gain an understanding of potential costs associated with being a Scheduling Coordinator?
A: The term "Scheduling Coordinator" is a CAISO term. The entity bidding energy imports at a CAISO intertie must be a Scheduling Coordinator with CAISO. Outside CAISO, the term "Scheduling Agent" is commonly used, although other terms may also be used to identify the entity that serves to schedule energy onto the transmission system at the point of interconnection. This entity would be responsible for scheduling transmission for energy transmitted from the project interconnection point to the CAISO intertie, at which point the Scheduling Coordinator would bid the energy into the CAISO market at that intertie node.
To gain an understanding of what it means to be a Scheduling Coordinator, developers should refer to the CAISO tariff. To gain an understanding of what it means to be a Scheduling Agent, developers should contact the applicable Balancing Authority for their project.
Q: The RPS stated that PG&E will consider delivery points outside of its service territory and those include CA locations outside of the CAISO control area and CAISO interface points. Where are the CAISO locations outside of the CAISO control area?
A: PG&E will accept offers from projects located within other California Balancing Authorities, such as LADWP, SMUD and Imperial Irrigation District. The delivery point must be the interface between the other balancing authority and the CAISO.
Q: What are the criteria to be considered as an Independent Study? (as opposed to Fast Track or Cluster study)
A: The Independent Study process is designed to separately study projects that are not expected to impact other project’s interconnection facilities or electric networks. In contrast, projects in the current generation interconnection study queues (CAISO Generation Queue for transmission interconnections and PG&E’s WDT Queue for distribution interconnections) are commonly impacted by other generation interconnection projects in the queues. The screening criteria for the independent studies can be found in greater detail in the following documents:
Transmission Interconnections:
Independent Study Screening Criteria for Transmission Interconnections (CAISO) can be reviewed under Section 4.1 of the CAISO’s Appendix Y GIP For Interconnection Requests Generator Interconnection Procedures (GIP):
Distribution Interconnections:
Independent Study Screening Criteria for PG&E territory Distribution Interconnections can be reviewed under Section 3 of PG&E’s Wholesale Distribution Tariff, Attachment I:Generator Interconnection Procedures (GIP): In addition, Interconnection Customers can view the Independent Study Roadmap that details the Electrical Independence Test for distribution interconnections.
Q: Please give complete examples of Independent Study Process interconnections.
A: A simple example would be either a distribution or transmission interconnection proposal that is interconnecting into a segment of the electric system that has no known electrical equipment impacts that are related to other generation interconnection projects in the current study queues. Please note that for transmission interconnections, the Commercial Operation Date screen must also be met to qualify for the Independent Study Process.
Q: What areas have sufficient capacity?
A: Sufficient capacity can be determined for each area by the network proxy cost amounts for the various levels of potential generation. If the transmission proxy cost is zero then the area has capacity up to the maximum generation amount for that level.
Q: What areas are capacity-constrained?
A: Constrained areas are identified by the proxy costs associated with the interconnection levels determined by MWs. If the transmission proxy cost for that level is nonzero then the area is constrained and would trigger a transmission upgrade.
Q: What if our project is connected on a transmission line connecting two substations in the TRCR, what are our options for choosing a proxy transmission cost? Do we pick one substation over the other? Do we pick the closer substation? or do we do it on a pro-rata basis?
A: TRCRs are used for the purpose of evaluating offers. A single transmission cluster should be selected based on the nearest substation. Since the TRCRs are clusters, it is possible that both substations will fall within the same cluster.
A transmission cluster is not the same as the interconnection point. The interconnection points could be identified in the CAISO scoping meeting, CAISO Phase I, or CAISO Phase II studies.
Q: Is there a requirement for TRCR?
A: TRCR is a proxy estimate of the potential transmission costs used for bid evaluation. The selection of a substation cluster from the TRCR map is needed for this determination. If there is a more accurate estimate of network upgrades from a CAISO study, PG&E will consider those costs.
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