Comments on Revised straw proposal

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

See below

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

No comment at this time

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

No comment at this time

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

No comment at this time

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

No comment at this time

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

ACP-California understands CAISO’s interest in ensuring that PPAs which qualify for a TPD allocation have a minimum term. It is critical to ensure that the term required is not too arduous for projects under development to achieve, but also not such a low bar that it effectively is not a barrier to securing a TPD allocation. ACP-California tends to agree with the compromise positions that CAISO and stakeholders arrive at in IPE Phase 1 of a three-year minimum contract term. While this may be longer than many of the “standard” RA contracts that have become the norm, it is also significantly less than the 10-year contracting requirements in venues such as the IRP. Thus, three years, while not ideal for some projects and while it may require some modifications to typical RA contracting, seems to strike a reasonable balance.    

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

In general, it is likely sufficient for CAISO’s TPD allocation process (as it does today) to simply require that, in order to be eligible for a deliverability allocation, a PPA that must only require deliverability from the project. CAISO should not to worry about whether and how the RA attributes are sold to an LSE with an RA obligation, as there are many different and unique contracting structures that exist. And from an economic perspective, if a project is seeking deliverability to meet a PPA requirement, then the offtaker of that PPA (whether an LSE or not) is incented to ensure that the RA attributes are sold or utilized. Failure to utilize or sell those RA attributes would be economically irrational and is highly unlikely to occur. Assuming that PPAs which require deliverability will ultimately sell the RA attributes to an LSE with an RA obligation also allows CAISO to not have to worry about tracing down the contracting structures that are used to get RA in the hands of those who need it. Therefore, ACP-California recommends CAISO not modify the current requirements for PPAs to qualify for deliverability allocations.

If, however, CAISO is determined to implement a requirement that PPA which are not with entities with RA obligations must demonstrate that the RA attributes are sold to an entity with an RA obligation, then these procuring entity should be given extra time to secure a contract with a load serving entity. We suggest that entities be given one-year to secure a contract with an LSE. This timeline is likely necessary given that it will take an absolute minimum of six months to enter into an agreement to sell the RA attributes.

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

In general, ACP-California has been supportive of higher fees and “at-risk” deposits in order to help reduce the number of unviable interconnection requests that are submitted into each cluster. Therefore, we generally support CAISO’s proposal for higher amounts of deposit “at risk” throughout the interconnection process.

While ACP-California also generally supports higher study deposits, we oppose CAISO’s proposal to increase the study deposit based upon how many interconnection requests a parent company has submitted. We recognize that CAISO has provided some statistics that seems to suggest that parent companies that submit more interconnection requests withdraw at a higher rate. However, we suggest a different approach with study deposits based on a $/MW. We suggest this approach as a good middle ground, which will create higher amounts of deposit “at risk” for larger projects. This alternative approach is also necessary because the CAISO’s proposal to increase study deposits based on how many requests a parent company submits may be viewed as discriminatory to large companies. And finally, because the changes that CAISO has already made to the process, and will make through this initiative, may already reduce the number of unviable interconnection requests submitted, we do not believe this approach is warranted at this time. 

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

ACP-California supports re-consideration of an alternative cost allocation treatment for network upgrades to local system in certain instances, such as those faced by Valley Electric Association (VEA). We understand that, while VEA had previously expressed concern with CAISO’s proposal, they now support the proposal to establish a 15% transmission revenue requirement threshold for each PTO, where after the 15% threshold is exceeded, future interconnection customers would be responsible for all incremental low voltage interconnection costs in that area (without reimbursement).

Despite VEA’s support for this approach, ACP-California continues to have concerns about this proposal. Those concerns were outlined in January 5, 2022 comments on the IPE Straw Proposal (which can be found here). In short, we remain concerned that this approach may inhibit generation that interconnects to the VEA area, by making generation above a certain level in this region more expensive to LSEs than generation in other regions (due to the direct inclusion of low-voltage interconnection costs in the cost of the generating facility itself).

We request additional insight and discussion on why CAISO has not further considered the alternative options that VEA had put forth at the time of the original IPE Issue Paper and Straw Proposal.

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

ACP-California supports CAISO’s proposed policy for the ISO as an Affected System.

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

ACP-California supports the proposal that if Energy-Only projects contribute to short circuit duty and are not moving forward, they should be removed from the queue. We also generally support CAISO’s proposal to enforce project status reporting requirements. We also ask that CAISO continue to hold discussions on how to best ensure that transmission owners are meeting their obligations under the GIAs and are moving required upgrade forward as expeditiously as possible to support new resource interconnections and deliverability status. We would also be interested in further discussing standards that might be able to be used to help hold Transmission Owners accountable for timely completion of upgrades under GIAs.

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

No comment at this time

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

No comment at this time

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

ACP-California continues to support increased transparency into how PTOs prioritize the development, permitting and construction of upgrade projects. However, we understand that the specific request for PTOs to immediately begin planning all upgrades required for a project to achieve FCDS as soon as the developer issues a notice to proceed is not feasible, given the large number of projects and limited resources. We support additional, public discussions on how PTOs are prioritizing upgrades to ensure reliability and needed deliverability increases are achieved. These discussions would naturally fit within the ongoing Transmission Development Forums and would help stakeholders better understand the timing and priority of various projects.

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

No comment at this time

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

AES appreciates the opportunity to offer comments on the Interconnection Process Enhancements Phase 2 initiative.

AES is disappointed that the CAISO does not propose to make greater efforts to provide needed data transparency on the best places to file interconnection requests. Without this greater level of information sharing, AES believes that CAISO will continue to experience overheated queues as interconnection customers will not be able to gain the necessary information except through submitting “speculative” interconnection request. AES is encouraged that in FERC’s Notice of Proposed Rulemaking released on June 16^th, FERC proposes to require transmission providers to provide publicly available interactive visual representations of available interconnection capacity and transmission congestion (see paragraph 49-51). Given this signal from FERC, AES requests that the CAISO reconsider their opposition to creating a heat map, similar to MISO, as suggested by numerous stakeholders. AES believes this provision of data coupled with increase site control and study deposits as detailed below would go a long way towards improving the efficiency and efficacy of CAISO’s interconnection process and help ensure that California can meet its decarbonization goals.

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

AES appreciates the CAISO’s willingness to reconsider what data is considered confidential and open to exploring how to provide further transparency to the interconnection queue. More specifically to the data items listed in the CAISO’s revised straw proposal, AES believes the following should be made public:

• Suspension status
• Construction status, but we note that it might be hard to keep track of all phases of construction, so a simple yes/no or check mark that construction has started could be sufficient
• Parking status
• Phase level data: Fuel type and TPD Group and allocation should be made public
• Projects with TPD allocation should be more transparent and identifiable

AES seeks additional clarity on CAISO’s definition of “Project’s Affected System Status”. Does the CAISO intend this to mean that the project requires the completion of an affected system study to move forward and whether this study has been completed? If the answer is yes to both questions, then AES could support the disclosure of this information through simple yes/no check boxes.

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

PPA execution and MWs under contract should remain confidential. While it may be possible to infer a project’s PPA execution status under the revised TPD allocation methodology adopted in Phase 1 where Group A is reserved for projects with executed PPAs, AES still supports efforts to make project’s with TPD allocation more transparent, while also supporting the outright disclosure of a project’s PPA execution status to remain confidential.

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

AES believes that PJM’s public interconnection queue can serve as a helpful model for the kinds of information and in what formats the CAISO should emulate to provide useful and transparent data to interconnection customers without disclosing market sensitive information. PJM’s New Service Queue can be found here: PJM - New Services Queue

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

AES does not believe that data transparency should be left to an optional showing on a customer-by-customer basis. Data items should be made public or classified as confidential across the board if it is to be useful.

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

.

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

.

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

AES has been supportive of the adoption of higher fees, deposits, or other criteria as an effective tool to manage a first ready, first served interconnection queue. However, it strongly opposes the CAISO proposed study deposit proposal that tiers the study deposit amount by the number of projects submitted by a parent company.

While AES appreciates the CAISO’s efforts to provide data to support its proposal, AES believes the data presented is insufficient to support the current proposal. From the data table on page 19 of the revised straw proposal, the CAISO shows that for Cluster’s 10-13, there appears to be a lower retention rate for project’s whose parent company submits more than 3 interconnection request per cycle. However, the CAISO did not conduct any analysis to evaluate whether this apparent difference was statistically significant. AES conducted a difference of proportion’s test for each cluster to determine if the percent remaining in the queue from each group was significantly different from one another and provides a summary of this analysis in the Table below.

The difference of proportion test evaluates whether the difference in percentages across two groups are meaningful or if the differences are the product of random chance, and thus the apparent differences can’t be associated with the difference between the two groups- in this case the number of applications submitted by a parent company per cluster leading to different retention rates. For Clusters 10 and 11, the results show that there is an apparent statistically significant difference between these two groups at a 95% confidence level. For Clusters 12 and 13 there is not, because the alpha values are greater than 0.05. When this was brought up during the stakeholder call, CAISO staff responded that Clusters 12 and 13 had additional milestones that still needed to be met, and so more projects could still drop out of the queue, and thus the difference could become significant. However, this is equally true for both groups, so there is no certainty that these differences will become statistically significant in the future, because Cluster 12 and 13 could have similar withdrawal rates such that the difference between the two groups remains the same and unsignificant.

Furthermore, this apparent difference could be spurious once we control for other factors such as site control. The CAISO should revise this analysis to look at the withdrawal rates for projects that have site control by Phase 2 vs. those that continue with deposit in lieu of site control to see if the difference in the number of applications by parent company remains and is still statistically significant. In AES’s experience, projects that already have site control before the completion of Phase 2 are less speculative in nature, and regardless of how many applications a company submits, if each of those projects have site control, they are less likely to drop out than projects without.

AES reiterates its support for higher fees and higher requirements to enter the queue but thinks the CAISO’s current proposal is misguided and potentially could be ruled as unjust, unreasonable and discriminatory towards larger developers. AES proposes the CAISO should review recent proposals adopted by MISO and PJM and the Interconnection NOPR FERC release on June 16^th as potential models to increase application requirements. First, the CAISO should revise its tariff definition of site control to be 100%, rather than 50% currently defined in the tariff. Second, the CAISO should remove deposit in lieu of site exclusivity and require demonstration of site control before the start of the Phase 1 study. The CAISO should expand the definition of site control to encompass land required for the Gen-Tie line as well as the land needed for the generating facility. This definition of site control would be more in line with MISO and the tariff language recently submitted to FERC by PJM. AES believes that site control is a much more effective way to identify “ready” projects than just increasing fees. AES proposes that the CAISO should revise its study deposit proposal to be tiered based on size of the project rather than the number of applications submitted. Both MISO and PJM have a study deposit based on size of the project. MISO’s rules have already been deemed just and reasonable by FERC, and since PJM’s is based on MISO’s, it is likely that FERC will rule similarly. AES provides excerpts from MISO’s BPM that outlines its study deposit policy and the submitted tariff language from PJM as models for the CAISO to revise their own proposals. AES believes that if CAISO revised its proposal in this manner, it would have a greater chance of being ruled just and reasonable by FERC.

On Page 29 of MISO’s Generator Interconnection BP 015

On page 286 of the submitted tariff language by PJM:

AES does not oppose a refund structure that puts more money at risk as the project moves through each stage. However, it does oppose many of the specifics of the CAISO’s current proposal. The study deposit should be fully refundable until 10 days following the scooping meeting, but if a project chooses to move forward into Phase 1 then some portion of the deposit should become non-refundable. AES also strongly opposes the CAISO retaining the study deposit until COD and this should be revised to be refunded once the GIA is executed. Retaining a study deposit until COD is beyond the practices of other ISO/RTOs and could be viewed as unjust and unreasonable.

AES would also appreciate the CAISO providing further clarity on what the CAISO intends to do with any unspent study deposits that may be forfeited by developers due to project withdrawals.

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

AES opposes this proposal. Rather than requiring generators to fund upgrades once the 15% cap is reached, the CAISO should explore revising its cost allocation to spread any remaining costs to the regional rate base. The current proposal could incentives more developers to only locate on the higher voltage lines to avoid having to fund network upgrades. However, higher voltage network upgrades are more expensive than upgrades needed on lower voltage lines, and thus ratepayers may be charged more to interconnect these projects than they would have if the project had interconnected at the lower voltage and the upgrade costs were share with both the local and regional rate base.

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

AES supports CAISO’s proposal to use the most recently queue projects in the base cases and to apply the CAISO’s current policy on how upgrades are funded.

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

AES supports the CAISO’s efforts to enforce the existing language in its tariff to manage queued projects. AES notes that projects that can demonstrate progress- e.g., have site control, have started construction, etc. should still be allowed to remain in queue, even if the 7-year mark has passed.

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

AES has no comment at this time. 

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

AES has no comment at this time.

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

While project developers do make good faith efforts to coordinate with PTOs, they have little power to force PTOs to implement the necessary upgrades to keep on schedule for project deadlines. The CAISO has greater ability to influence the PTOs, and AES would support the CAISO exploring if there are additional tools and mechanisms at the CAISO’s disposal to keep PTOs on track to meet construction milestones to ensure that projects are able to interconnect on time.

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

AES support’s the CAISO’s decision to move the transmission planning reforms to separate stakeholder processes and looks forward to participating in those venues.

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

See attached PDF

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

See attached PDF

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

See attached PDF

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

See attached PDF

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

See attached PDF

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

See attached PDF

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

See attached PDF

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

See attached PDF

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

See attached PDF

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

See attached PDF

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

See attached PDF

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

See attached PDF

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

See attached PDF

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

See attached PDF

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

See attached PDF

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

Avangrid Renewables offers comments below on proposed requirements for TPD allocation and on early termination of a GIA.

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

No comments at this time.

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

No comments at this time.

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

No comments at this time.

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

No comments at this time.

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

Avangrid Renewables opposes setting a minimum term for a PPA procuring RA, either directly or via a third-party arrangement. Resource adequacy contracts can be long-term or as short as a month, depending on the needs of LSEs, their RA supply strategy, or unexpected supply changes that may occur close to a compliance period. We note there are various LSEs currently seeking short-term 2022 and 2023 RA capacity, which is typical of recent years and may in fact increase as California transitions to a load-profile centered 24-hour slice RA framework. Setting an arbitrary minimum term for an RA contract therefore may not truly reflect that a resource is providing RA capacity in response to a highest and best market and system need.

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

As stated during the Phase 1 process, Avangrid Renewables opposes restricting allocation of TPD only to projects with PPAs where the counterparty is a load-serving entity with an RA obligation. There are non-LSE customers who seek the RA benefits of a project, either because they anticipate a potential future RA obligation or because they seek the full value of a project’s energy and capacity attributes and intend to sell that capacity to a third-party but have not prearranged to do so. Requiring a PPA which includes sale of the capacity attributes of a project (regardless of RA obligation) should be sufficient for CAISO’s purposes of allocating deliverability.

The CAISO should provide non-discriminatory access to TPD allocations and trust that diverse business models and off-takers will ensure that capacity and related deliverability are put to use for the benefit of the system as a whole. If the CAISO does move forward with requiring a direct or third-party contract with an LSE with an RA obligation as a requirement of TPD allocation, then it should provide at least 12 months for the developer or off-taker to sign a contract for that capacity. Given there are contracts currently under negotiation with non-LSE off takers that may be affected by this change, it will be important for the CAISO to provide at least one-year for parties to those negotiations to explore viable options and structures to secure a third-party contract.

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

No comments at this time.

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

No comments at this time.

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

No comments at this time.

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

Avangrid Renewables interprets the Straw Proposal as applying no new milestones or changes to the GIA requirements for FCDS or PCDS customers. Instead, the CAISO is notifying interconnection customers that it will use its authority to enforce requirements regarding status updates and progress toward meeting milestones. We do not object to this proposal, but as described in response to question 13, we would ask the CAISO to approach this enforcement on a case-by-case basis that respects differences between truly “stalled” projects and projects that have faced unexpected and uncontrollable delays.

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

No comments at this time.

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

While it is reasonable for the CAISO to require interconnection customers to respond to requests for project status updates as per milestones set in the GIA, Avangrid Renewables would not support any new rule changes or amendments that impose a higher or faster burden on projects toward achieving COD. We note that multiple years between receipt of a GIA and COD can be consumed by CAISO and TO processing and upgrades. Beyond these factors, unexpected permitting, supply chain, or offtake changes can create disruptions which compromise a project’s ability to achieve COD within seven years, despite developer’s best efforts to keep a project moving forward. The CAISO should provide individual consideration and attention to the circumstances of each project rather than imposing any new automatic termination triggers.

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

No comments at this time.

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

No comments at this time.

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

The Bay Area Municipal Transmission group (BAMx)^[1] appreciates the opportunity to comment on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal. Although BAMx appreciates the importance of 2021 IPE addressing several issues related to enhancing the Generator Interconnection and Deliverability Allocation Procedures (GIDAP), our current comments are limited to a subset of topics raised in the revised straw proposal.

BAMx shares CAISO’s concerns on the following two topics focused on moving resources through the interconnection queue more efficiently and potentially more quickly.

1. Can the interconnection process and procurement activity better align with transmission system capabilities and policy objectives of renewable generation portfolios developed for planning purposes?
2. Should a solicitation model be considered for some key locations and constraints not addressed in portfolio development, where commercial interest is the primary driver?

BAMx intends to provide input on these issues in a separate stakeholder process (envisioned in the first or the second week of July 2022) associated with the transmission planning process (TPP) enhancements.

[1] BAMx consists of City of Palo Alto Utilities and City of Santa Clara, Silicon Valley Power.

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

BAMx agrees with the concept that “Information designated as confidential information is no longer deemed confidential if the party that designated the information as confidential notifies the other parties that it no longer is confidential.” In that spirit, information that could be made public should include

• Phase level data for the project, including gen and fuel type, MW, milestone dates, resource IDs, hybrid or co-located designation, MWh data for storage projects, and TP Deliverability group and allocation.
• Suspension status and timing of a project;
• PPA executed and MW;
• Construction status;
• Project parking status; and
• Project Affected System status.

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

 No comments at this time.

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

 No comments at this time.

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

All market participants, including the load-serving entities, affected systems, and interconnection customers, would benefit from the additional data included in BAMx’s response to Q.2, currently considered confidential by the CAISO.

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

 No comments at this time.

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

 No comments at this time.

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

The CAISO proposes to increase study deposits earlier in the process to encourage developers to submit a reasonable number of interconnection requests (IRs) for high quality resources; and to disincentivize submittal of a disproportionate amount of IRs that overwhelm resources and slow the cluster study process.[1] BAMx believes that the CAISO has a valid concern that, rather than target a single or small number of well-developed, viable projects, parent companies can simply submit numerous interconnection requests to use the ISO interconnection study process to explore even remotely plausible projects. BAMx supports the CAISO’s proposal, which includes a tiered deposit approach so as to not disadvantage small developers that submit one or two IRs and do not contribute to the problem.

^[1] Revised Straw Proposal, p.18.

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

The CAISO has proposed that the addition of the capital costs for low voltage (<200kV) network upgrades driven by generation interconnections to the Local Transmission Revenue Requirement (LTRR) of a Participating Transmission Owner (PTO) will not cause the aggregate of the net investment for all low voltage network upgrades driven by generation interconnections included in the LTRR to exceed fifteen (15) percent of the aggregate of the net investment for all low voltage transmission facilities of that PTO reflected in their LTRR in effect at the time of the in-service date of the network upgrade.[1] The CAISO has further proposed that any costs for low voltage network upgrades in excess of the 15 percent threshold would be financed by interconnection customers without cash reimbursement. BAMx appreciates the CAISO responding to its earlier request to provide a historical quantitative analysis demonstrating the extent of this potential problem.[2]

The Revised Straw Proposal includes high-level estimates provided by each PTO on where they currently stand in relation to the CAISO’s proposal. This table illustrates that there is little chance that SCE or SDGE will reach the proposed 15% cap in the foreseeable future. However, there seems to be a very high likelihood that VEA will reach the cap. Unfortunately, the data is not yet available for PG&E. This data will be essential not only for the local Transmission Access Charge (TAC) payers within the PG&E TAC area, but in general, in considering the efficacy of the current proposal. BAMx shares the concern that the current practice for local upgrades could unduly impact local ratepayers who are not the sole beneficiaries of the upgrades, but who solely bear their costs. However, BAMx would reserve its opinion on the CAISO’s proposal on this issue until PG&E-specific data is available. BAMx strongly urges the CAISO to provide the high-level estimates for PG&E on where they currently stand concerning the CAISO’s proposal as part of the draft final proposal, if not sooner.

^[1] CAISO 2021 Interconnection Process Enhancements, Revised Straw Proposal, p.22

^[2] BAMx comments on Preliminary issue paper and stakeholder workshop Initiative: Interconnection process enhancements 2021, November 2, 0221.

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

 No comments at this time.

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

BAMx supports all three (3) elements of the CAISO proposal in section 5.3. That is,

     I.  Section 6.5.2.1 states that “projects requesting to remain in the queue” beyond the applicable limit “clearly demonstrate that: “(1) engineering/permitting/construction will take longer than that; (2) the delay is beyond the IC’s control; and (3) the requested COD is achievable in light of any engineering, permitting and/or construction impediments.” BAMx supports the CAISO’s proposal that it will be more assertive in using Section 6.5.2.1 of the BPM for Generator Management.

    II.  Energy-Only (EO) projects that have not achieved COD after seven (7) years and contribute to short circuit duty will be terminated. We understand that this applies to projects that require upgrades that the interconnection customer is not willing to pay for, which the CAISO has claimed is typical for EO projects.

  III.  The CAISO will be invoking the breach clause if the information is not supplied when requested, if milestone dates are not met, or if other terms and conditions of the GIA are not being met.

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

 No comments at this time.

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

 No comments at this time.

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

 No comments at this time.

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

 No comments at this time.

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

CalCCA generally supports the California Independent System Operator Corporation’s (CAISO's) Interconnection Process Enhancements (IPE) Phase 2 Revised Straw Proposal. This initiative comes at a critical point when load-serving entities (LSEs) are expanding procurement activities at a rapid pace to meet procurement orders and state clean energy policies. As a result, the CAISO interconnection queue is experiencing an unprecedented number of study requests. Proposals that can reduce interconnection queue backlog and prioritize the most viable projects when allocating deliverability will enhance the ability of LSEs to conduct procurement of new resources and the CAISO to conduct studies on new projects in a timely and orderly manner. Such proposals must balance (1) the need to get the most viable projects through the queue in a timely and orderly manner that can support grid reliability and state policy goals, and (2) the ability for all prospective projects to be able to compete for power-purchase agreements (PPAs) with LSEs.

Planning Resource Adequacy (RA) procurement in the context of deliverability creates a “chicken and egg” problem. Today, the interconnection queue holds 10 to 15 times more megawatts (MW) than what is needed to meet procurement orders.[1] LSEs face challenges narrowing down the number of projects available to contract because not all the projects in the queue will obtain the deliverability status needed to provide RA. At the same time, the CAISO faces challenges when narrowing down which projects to study for and allocate deliverability to using the limited time and staff resources available. Two solutions are available. The CAISO can assign deliverability to projects, signaling to LSEs to sign PPAs with those projects.  Alternatively, developers can contract with LSEs first, then the CAISO can assign deliverability to those projects with PPAs. The CAISO’s proposal aims at advancing the second approach.

The CAISO’s proposal to prioritize projects with PPAs that sell RA attributes for a minimum term will help ensure deliverability is allocated to the projects most likely to reach commercial operation and provide reliability to California. In these comments, CalCCA supports the requirement for PPAs to have a minimum term and asks additional clarifying questions to ensure projects can be reallocated in the event a project with a PPA fails such that LSEs can meet their procurement orders with deliverable projects.     

In summary, CalCCA:

• Does not object to the data items in section 3.3 being made public so long as counterparties to PPAs are not identified publicly;
• Supports a minimum PPA term with a contract for RA capacity of 10 years to be put in the highest priority allocation group;
• Supports requiring entities without an RA obligation to have a contract with an LSE with an RA obligation prior to being placed in the highest allocation group for Transmission Plan Deliverability (TPD); and
• Supports higher deposit fees that will encourage developers to submit a reasonable number of interconnection requests for high-quality projects.

[1]           CAISO Revised Straw Proposal at 5.

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

No comments at this time. 

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

CalCCA does not object to the items in section 3.3 being public so long as the “PPA executed and MW” item on Slide 12 would not make the counterparty(ies) to the PPA public, as releasing this information would raise competitiveness concerns.

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

No comments at this time.  

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

No comments at this time.  

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

Yes, the allocation of TPD should require a PPA that procures the project’s RA capacity for a minimum term. CalCCA understands that this requirement would not preclude projects that do not meet this requirement from getting TPD. Rather, it would prioritize those projects with PPAs with RA capacity for a minimum term in allocation group A, above those PPAs without procuring RA capacity for at least the minimum term. The CAISO should clarify if and how, in the event a project in allocation group A fails, other projects would be reprioritized within the allocation groups. For example, if a project with a PPA fails and the LSE executes a new PPA with another project, does that new project get placed in allocation group A, effectively replacing the failed project? This clarification is important because LSEs need to be able to determine which projects to pursue to have the best chances of obtaining TPD and - in turn - meet procurement orders in the event a prior project fails.

The minimum term should reflect the standard term of PPAs many CCAs are encountering for new resources, which is 10 years. Minimum term requirements shorter in length may not have the desired outcome of creating meaningful criteria for getting placed in allocation group A, because a majority of PPAs are for terms of 10 years or longer.  

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

A PPA with an entity that does not have an RA obligation should be eligible for an allocation of TPD only if the procuring entity demonstrates it has a contract with an LSE that has an RA obligation. This contract should be in place at the time of the deliverability allocation. Because LSEs are the ones with the RA obligations, the capacity they have under contract should be first in line to receive allocations of deliverability. This rationale is consistent with the Maxim Import Capability (MIC) process, in which MIC is allocated to LSEs first (the ones with the RA obligation) and then to others.

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

CalCCA supports the CAISO’s proposal to increase study deposits to encourage a more reasonable number of interconnection requests.

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

No comments at this time.   

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

No comments at this time.   

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

No comments at this time.   

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

No comments at this time.   

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

No comments at this time.   

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

No comments at this time.   

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

No comments at this time.   

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

CESA appreciates the ISO’s continued efforts to enhance the interconnection process in Phase 2. The collective proposals of the 2021 Interconnection Process Enhancements (IPE) will go a long way to managing overheated and large interconnection queues, better aligning cost allocation and various procurement and planning processes, and efficiently bring on the new capacity resources needed to support the state’s decarbonization goals and reliability needs. In reviewing the Phase 2 Revised Straw Proposal, however, CESA is concerned that the Phase 2 proposals are focused on improving the interconnection process at the margins or would reduce the interconnection queue in ways that would discriminatorily screen out high-quality and viable projects by targeting certain parent companies without necessarily making substantive improvements that ensure an efficient and effective interconnection process.

In light of the recently-issued Notice of Proposed Rulemaking (NOPR) at the Federal Energy Regulatory Commission (FERC) and the establishment of Interconnection Innovation e-Xchange (i2X) at the Department of Energy (DOE), CESA believes that the ISO and its stakeholders would be better served by quickly concluding Phase 2 by addressing a narrow set of proposals, such as data transparency issues and the carryover Phase 1 issues related to the Transmission Plan Deliverability (TPD) allocation prioritization criteria, and immediately launching a new IPE Initiative to tackle bigger and more fundamental reforms to the interconnection process and queue. The NOPR (RM22-14) represents a major milestone at the federal level in proposing significant and innovative reforms to rethink the interconnection process, which can be instructive and provide guidance for CESA’s proposed new IPE Initiative.

While the NOPR is still preliminary in nature and subject to its stakeholder process, and some of the NOPR’s proposals are already incorporated in this ISO’s status-quo process (e.g., single, annual cluster study application window), there are other key proposals that warrant deeper consideration in a new IPE Initiative that may go a longer way in improving interconnection procedures, providing greater certainty and transparency, preventing undue discrimination against new generation, and ensuring efficient and timely access to the grid. For example, FERC proposes to use a “waiting room” or pre-application structure to help with the data transparency and information needs of interconnection customers, combined with a structure that imposes additional financial commitments and readiness requirements on interconnection customers, facilitating a first-ready, first-served that only invites interconnection customers who are ready to move into and advance through the queue. In addition, the NOPR also proposes to improve interconnection queue processing speed by imposing firm deadlines and establishing penalties if transmission providers fail to complete interconnection studies on time, except in instances where force majeure is applicable, and proposes to incorporate technological advancements into the interconnection process, such as requiring interconnection studies to reflect the proposed operation of an electric storage resource or co-located resource containing an electric storage resource. In CESA’s view, even as further improvements could be made, the NOPR tackles interconnection reforms in a more comprehensive way, in contrast to the incremental, more piecemeal set of proposals included in the ISO’s Phase 2 Revised Straw Proposal.

Along these lines, CESA urges the ISO to quickly conclude Phase 2 by addressing a narrow set of proposals, such as data transparency issues and the carryover Phase 1 issues, and immediately launching a new “2023 IPE Initiative” to tackle bigger and more fundamental reforms to the interconnection process and queue. Informed and guided by the FERC NOPR, a fundamental rethink of the ISO queue is sorely needed to improve the way projects move through the queue. This new initiative should consider, but not necessarily be limited to, the following proposals:

• Establishing a single impact study phase rather than the current two phases, achieved, for example, by creating a pre-application structure for indicative costs, having concrete study timelines, and/or conducting auctions to allow projects to enter the queue in areas with transmission capacity and up to the available level of transmission capacity, among other approaches
• Establishing and enforcing a structure of rewards and penalties to process interconnection requests, timeline to build interconnection facilities and upgrades, etc.
• Improving the ability of interconnection customers to self-provide work, such as interconnection request model validation, and to self-build standalone facilities
• Incorporating operational assumptions of standalone or hybrid/co-located storage resources in interconnection studies

To avoid another supercluster in QC15 in April 2023, CESA understands that the new initiative would have to launch immediately and be resolved expeditiously. As such, Phase 2 of this initiative should expeditiously address a narrow set of issues, perhaps with an eye toward incremental changes targeting issues that might impact QC15, but the focus should quickly pivot to a new initiative that should work expeditiously to these broader and more fundamental reforms.

Notwithstanding these higher-level comments, CESA’s responses to the questions and specific proposals can be summarized as follows:

• CESA generally supports greater transparency on many of the project-specific data categories listed in the Phase 2 Revised Straw Proposal and, at this time, does not see how any of these data categories would be commercially sensitive to disclose.
• The ISO should not define minimum term lengths for qualifying PPAs since shorter-term contracts can be reasonably pursued as a regulatory risk-mitigation strategy, but if the ISO is intent on setting a minimum term length, it should be one year to align with forward System Resource Adequacy (RA) requirements and TPD allocation cycles.
• The ISO should not deter the development of deliverable projects to non-LSE parties who have valid reasons to do so and could require a certain time window (e.g., two years) by which the project would need to secure a contract with an LSE with an RA obligation.
• CESA strongly opposes the ISO’s proposal to establish a tiered fee approach based on parent company as discriminatory and would be better targeted by applying policies, fees, or processes based on defined criteria for “speculative” projects.
• CESA sees potential in the ISO’s proposal to increase the non-refundable portion of deposits based on the stage of the interconnection process, but it should be refined and considered in a new IPE initiative focused on more fundamental reforms.
• CESA supports the common-sense proposal for the ISO to exercise its authorities to ensure projects are meeting their milestone requirements.

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

CESA generally supports greater transparency on many of the project-specific data categories listed by the ISO in the Phase 2 Revised Straw Proposal, including gen/fuel type, MW, milestones, resource IDs, hybrid or co-located designation, MWh data for storage, and TPD group and allocation. CESA also generally supports greater transparency into the status (e.g., PPA executed, online, suspended, withdrawn, parking, affected system) of projects in the queue. As expressed in comments to the April 5, 2022 Data Transparency Workshop, CESA also recommended (and is pleased to see it included in the Phase 2 Revised Straw Proposal) that the ISO include information on whether interconnecting projects have site control as part of generator-related data transparency efforts. Overall, each of these enhancements are likely easy to implement and could support efficient decision-making for interconnection customers to move forward in the process. For example, knowing that many other projects in the queue and at a given area have site control, it may inform developers on whether to move forward with submitting a deposit in lieu of site exclusivity, which was recently adopted in Phase 1 to have a greater portion of the deposit at risk.

While we cannot definitively say that all our members support this position, no members to date have expressed their opposition to CESA staff that they would oppose transparency of these data categories. At this time, CESA does not see how any of these data categories would be commercially sensitive to disclose, unlike contract prices and terms. In sum, these data categories point to project viability and certain general configurations, which reveals a general level of project competitiveness and/or project development strategy but does not constitute specific privileged information or trade secrets that warrants confidential treatment. Rather, transparency to these ends could help ease the overheated queue by helping any given interconnection customer understand their prospects to succeed in the interconnection queue at their location.

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

As expressed in our comments to Question 2, CESA does not oppose making any of the data categories listed in the Phase 2 Revised Straw Proposal.

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

CESA has no further recommendations at this time.

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

CESA generally supports allowing interconnection customers to make their data public. Presumably, the ISO seems to be suggesting in this question that this data can be made public on an opt-in and volunteer basis, but it is unclear how effective such an approach would be. It does not seem likely that any interconnection customer would share their project-specific information, which would only confer an advantage to projects that do not share this information. Proposed transparency for any of the project-specific information should be required of all interconnection customers in order to level the playing field and benefit all interconnection customers by mutually understanding their competitiveness and viability relative to other projects in the queue.  

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

CESA reiterates our principled position that the ISO should not define minimum term lengths for qualifying PPAs, but if the ISO is intent on doing so, CESA urges that the ISO minimize the term length as much as possible. There are several reasons why shorter PPA term lengths may be pursued. For energy storage resources where there has been ongoing uncertainty of RA counting rules and values, shorter-term contracts may be pursued as a regulatory risk mitigation strategy. Over the past couple years, there has been uncertainty regarding whether energy storage would be counted using effective load carrying capacity (ELCC) methods or based on maximum capabilities (Pmax) for shown hours under a slice-of-day framework. Under an ELCC approach in particular, there has been uncertainty about potential derated capacity depending on year of commercial operation, penetration of storage resources, and/or available charging energy. While much of this uncertainty is reduced with the CPUC’s adoption of slice-of-day frameworks, there is still some uncertainty around how it may be refined (e.g., use of UCAP) or how it interfaces with counting conventions for IRP compliance purposes. Furthermore, LSEs may pursue shorter-term contracts to address portfolio imbalances due to load migration concerns, among other reasons. As such, there are valid reasons for pursuing shorter-term contracts for deliverable capacity.  

Despite landing at a minimum contract term of three years in the Phase 1 Final Proposal, the ISO proposed a starting point of five years for a qualifying PPA in the Phase 2 Revised Straw Proposal, pointing to the ISO’s preference for longer-term contracts more in line with IRP procurement requirements (i.e., 10 years or more) and goal of using scarce ratepayer-funded transmission investments in prudent ways. CESA understands the ISO’s intent and goal with preferring longer-term contracts in TPD allocation prioritization, but we find flaws in the ISO’s assumption that projects with shorter-term contracts will not be financed or will not utilize the allocated TPD when the contract “expires” at the end of its term. The project developer has every motivation to monetize the deliverable capacity through follow-on or extended contracts with off-takers.

To this end, if the goal is to support RA obligations through the structure of TPD allocation priority groups, the qualifying PPA definition should align with the CPUC’s RA forward contracting requirements. With System RA contracts typically ranging from a few months or a year at minimum and Local RA contracts requiring at least three years in length, CESA proposes that the ISO define qualifying PPAs based on a minimum contract length of one year, as a one-year RA contract with a resource would still support LSE RA obligations. A minimum one-year term also aligns with the annual TPD allocation cycles, better minimizing any perceived risk that TPD allocations will not be utilized for the full 12-month period between cycles if shorter-term contracts indeed expire and are not extended. Overall, the ISO should avoid narrowly defining qualifying PPA terms, which may only serve to constrict the RA supply.

Finally, if despite CESA’s comments ISO staff decides to require minimum contract terms for a project to be eligible for TPD, we request the ISO clarify how said requirement would apply for all resources that will seek to retain their deliverability allocation as part of the 2023-2024 TPD allocation cycle. In the Revised Straw proposal, the ISO notes that, if applied, the modifications considered under Section 3.4 would be in effect beginning with the 2023-2024 TPD allocation cycle; nevertheless, it does not specify the implications of these novel requirements for capacity that has come online prior to the supercluster that spurred the Interconnection Process Enhancements, or that that is awaiting deliverability allocation but is part of prior clusters. Thus, if additional minimum term length requirements are adopted for TPD eligibility, CESA requests the CAISO clarify the potential reach and implications of these requirements for capacity that is online and is seeking incremental deliverability, for capacity that is online and wishes to retain its deliverability, and for capacity seeking or retaining deliverability allocation as part of any cluster prior to supercluster 14.

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

CESA generally favors allowing the market to evolve to allow developers to provide more flexible products to LSEs and not deter the development of deliverable projects to non-LSE parties who have valid reasons to do so (e.g., reduce RA obligations to LSEs, pursue 24x7 carbon-free goals). If such PPA counterparties are able to procure and bring on additional deliverable capacity, the ISO should not discourage such efforts, especially if these non-LSE entities provide the initial capital and investment to do so. To address the ISO’s concerns about ensuring that TPD-allocated projects show up on RA supply plans, the ISO could require a certain time window (e.g., two years) by which the project would need to secure a contract with an LSE with an RA obligation, similar to how the ISO has created a “conditional allocation” process via TPD Allocation Group D. Ultimately, the non-LSE entities and developers will want to “monetize” the value of the deliverable capacity, which would occur through a transaction with an LSE with an RA obligation, thus creating every incentive to ensure that these projects show up on RA supply plans.

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

Consistent with the FERC NOPR in RM22-14, the ISO should comprehensively consider how all of the various reforms fit together to align with a defined goal and to foster a competitive market while advancing high-quality and more viable projects. To this end, CESA strongly opposes the ISO’s proposal to establish a tiered fee approach based on parent company, but we see potential in the ISO’s proposal to increase the non-refundable portion of deposits based on the stage of the interconnection process.  

First, on the tiered fee approach, the ISO re-introduced its Phase 1 Straw Proposal but presented new data as justification that, when parent companies submit more than two interconnection requests, those projects withdraw at a higher percentage rate than parent companies that only submit one or two interconnection requests. Given this data, the ISO expressed that it believes that increasing fees with more at risk earlier in the process will be an effective tool to discourage excessive interconnection requests, where a tiered fee approach is appropriate to maintain a level playing field.

However, CESA maintains our opposition to this proposal and finds flaws in the logic of deterring interconnection requests through escalated study deposits based on the number from any given parent company. Though the data is indicatively helpful, it is portrayed at an arbitrary “3 or more” threshold that may not present the full picture of the point at which developers may not be presenting the highest quality or viable projects. If the intent is to eliminate “speculative” projects in order to more efficiently use ISO staff and resources, the ISO should define the criteria for “speculative” and set policies, fees, or processes accordingly to more narrowly target these projects; however, CESA is not convinced that higher withdrawal rates by parent company is an appropriate proxy for this criterion. More fundamentally, escalating fees and deposits based on the number of projects may penalize high-quality, viable projects simply as a result of being from the same developer, who may be submitting multiple interconnection applications as a result of understanding the transmission system and market/procurement landscape, not because of a scattershot approach. As it stands, according to the ISO’s proposal, it is unclear on what the intended benefit is in forcing the interconnection queue to be submitted by a larger number of entities and by penalizing all entities who submit a higher number of interconnection requests (rather than the entities that actually submit such a high volume of “speculative” interconnection requests). A proposal targeting parent company and promoting developer diversity in this way runs the risk of not being deemed just and reasonable and not being unduly discriminatory by FERC. More generally, avoiding superclusters as an end or goal should not be what the CAISO strives for. High volumes of interconnection applications in itself could be a sign of significant commercial interest in developing renewable and energy storage projects to meet procurement obligations and market needs in support the state’s decarbonization goals and reliability objectives.

Second, on the escalating portion of the study deposit that is put at risk, CESA is generally supportive of the ISO’s proposed approach, which is in line with the FERC NOPR to subject interconnection customers to additional study deposits, continued commercial readiness demonstrations, and penalties for leaving the queue at different stages to ensure that ready projects can proceed through the queue in a timely manner. While supportive of the spirit of this proposal, CESA offers two recommendations. First, if ISO staff moves forward with this proposal, they should consider allowing a higher portion of the deposit to be fully refundable (minus costs) after the Scoping Meeting given the relevance of this milestone in understanding project viability. Second, CESA considers that these proposals should be incorporated into broader and fundamental reform discussions in a new IPE Initiative, where this component of a broader and comprehensive reform proposal can be incorporated in tandem with better data transparency and preliminary/indicative (non-committal) interconnection information gathering processes, as well as approaches to anticipate and streamline “large” clusters. To this end, this proposal should be suspended and held to then.

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

CESA has no comment at this time.

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

CESA has no comment at this time.

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

CESA supports the ISO’s proposal to allow it to invoke the default clause (GIA Section 17.1.1) and Section 6.5.2.1 of the Generator Management BPM for interconnection customers that do not meet certain milestones and requirements, which is a reasonable application of the existing terms and conditions to ensure that interconnection customers are in adherence and compliance. This is an example of a clear-cut change to manage the overheated queue and apply accountability to projects to ensure progress to commercial viability and operations.

CESA nevertheless requests clarification on the applicability of the proposal since, as we understand it, this is not intended to impact projects requesting to remain in the queue beyond the applicable limit if they clearly demonstrate that engineering, permitting, or construction will take longer than that and are actively advancing projects, per the Business Practice Manual for Generator Management, Section 6.5.2.1. This clarification is warranted as some long-lead time resources, such as some long duration energy storage resources, may require additional time in the queue but can bring much needed diversity to the system. 

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

CESA has no further comment at this time.

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

As discussed at the beginning of these comments, CESA believes that a new IPE Initiative should be launched to more fundamentally reform the interconnection process in light of the NOPR in RM22-14 at FERC to address the overheated queue.  

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

The ISO found it impractical to further pursue this proposal given the volume of projects with executed GIAs, but we maintain that how work plans for network upgrades are prioritized and initiated merit deeper discussion in a new IPE Initiative tackling more fundamental reforms.

In upcoming venues, the ISO should consider that it is feasible to start planning for project network upgrades when the GIA is executed or when the notice to proceed is received. Doing so would provide a plan and timeline to the interconnection customer, which would provide vital information that is not currently made available. Key information regarding these upgrades would include prioritization, if any, to upgrades coming out of study processes such as the TPP, as well as considerations to the cost of the shared upgrade.

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

CESA generally concludes that Phase 2 should conclude with resolution of a narrow set of issues, such as the carryover TPD allocation topics from Phase 1 and data transparency considerations in particular. Soon after in Q3 2022, the ISO should launch a new IPE Initiative focused on fundamental reforms.

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

• CPUC staff appreciated this opportunity to comment and the CAISO’s ongoing work to improve the interconnection process.  CPUC staff sincerely appreciate the continuing cooperation between the CAISO and the CPUC on complex policy matters related to resource planning, transmission planning and generation development and interconnection.
• The CPUC staff support the CAISO making public as much data as possible to improve transparency and allow utilization of this data by stakeholders for procurement and resource planning and tracking.
  • The CAISO should reconsider blanket confidentially on several sets of information listed in Section 3.3.
  • Information that has been publicly revealed elsewhere should be considered not confidential and be publicly available in CAISO data sets.
  • The CAISO should consider making a name and contact info for interconnection customers (IC) publicly available to enable better communication between developers and LSEs seeking to procure resources.
  • Interconnection customers should have the ability to make all their information publicly available for the CAISO to share.
• CPUC staff supports the CAISO’s minimum PPA term length for deliverability allocation eligibility.
• The CAISO should consider allowing multiple sequential power purchase agreements (PPAs) or a combination of signed PPAs and shortlisted PPAs to count towards minimum term.
• CPUC staff support requirements for projects with a PPA with an entity without a Resource Adequacy (RA) obligation to also be required to have a RA sale contract with an LSE, or be in negotiations for such a contract, under similar requirements as the CAISO has established for PPAs in general in order to receive a deliverability allocation.
• CPUC staff supports the CAISO’s ability to terminate the generator interconnection agreement (GIA) earlier than seven years if the project is not proving it is moving forward with permitting and construction; the CPUC strongly encourages the CAISO to make public summary information about how many projects are potentially at risk to be terminated (i.e. designate in the public queue report when a project is put on notice), and designate when the GIA has been terminated by the CAISO (and which requirement triggered the termination).
• The CPUC encourages the CAISO to identify ways to make queue terminations a more transparent process, and/or a process possibly supported by an independent verification process.

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

CPUC staff support making public as much data as possible to improve transparency and allow as much information as possible for use by stakeholders, particularly LSEs in their procurement efforts, while recognizing the need for some information (particularly pricing and market sensitive data) will need to remain confidential. CPUC staff emphasizes the importance of publicly available CAISO queue information for regulatory oversight of resources planning.

Of the data the CAISO listed in section 3.3, CPUC staff support making two items in the first list of data (on page 12 of the Revised Straw Proposal) at least optional for disclosure by the applicant on a voluntary basis to ease tracking of resource development:

• Identification of projects in the queue with executed PPAs should be readily available if the projects have publicly disclosed their PPA status in another forum, especially to a federal, state or local entity.  While PPA pricing is sensitive, the existence of a full or partial PPA for the project, the MWs under contract, and the expected online date of the MWs in contract is frequently publicly available when the contract is with an investor-owned utility or community choice aggregator. In addition, PPA status is sometimes disclosed publicly during public permitting or construction processes. The CPUC’s Renewable Portfolio Standard public database provides significant quantities of information about projects in contract with PPAs but is not easily cross referenced with the CAISO queue.[1]   As stated on the CPUC website, “Public information of investor-owned utility renewable contracts under the RPS program includes: contract summaries, contract counterparties, resource type, location, delivery point, expected deliveries, capacity, length of contract, and online date.  Other terms of renewable contracts are confidential for three years from the date the contract begins deliveries or until one year following expiration, whichever comes first.”
• Identification of alternative project names may be confidential due to business reasons, but allowing, but perhaps not requiring, project owners to voluntarily disclose former or alternative project names can only lead to easier resource planning and procurement.

Of the data listed in the second list (on p12 of the Revised Straw Proposal), CPUC staff support the CAISO’s re-considering of blanket confidentiality for the follow information:

• Percentage of PCDS and IDS could be interpreted as market sensitive and pricing information.
• Phase level data for the project including: gen and fuel type, MW, milestone dates, resource IDs, hybrid or co-located designation, MWh data for storage projects, and TP Deliverability group and allocation.
• Suspension status and timing of a project
• PPA executed and MW
• Construction status
• Project parking status (including date project was originally parked)
• Project Affected System status

CPUC staff note that the percentages of PCDS of a projects, gen and fuel type, hybrid vs co-located designation, and MW and MWh for storage projects would be particularly useful for IRP’s development and mapping of portfolios used as inputs for the TPP process.

Of the data the CAISO listed in the third list of items for possible disclosure, the CPUC supports CAISO staff trying to find ways to make the PTO Study Area and the TP Deliverability Allocation Group publicly available in a report.

In general, CPUC staff support any information on an interconnection project that has been publicly revealed elsewhere via a publicly disclosed PPA (with an IOU or CCA), or via a permit application or public communication with a permitting authority should also be made publicly available in any CAISO data set.

CPUC would encourage the CAISO to optimize the inclusion of this information in existing interconnection related documents the CAISO already publicly releases, requiring applicants to allow its disclosure if disclosed publicly elsewhere and allowing applicants to voluntarily disclose if they do not find it confidential.

[1] RPS Reports and Data (ca.gov)

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

No Comment at this time.

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

CPUC staff ask the CAISO to consider making a name and a point of contact for the interconnection customer publicly available. The CAISO should at least consider allowing interconnection customers to voluntarily identify themselves as the owner of a project in the queue. Many projects have readily identifiable project developers with a simple web search based on the project information already publicly available. While it is true that the projects frequently have developer names that include a project specific LLC (e.g. a special purpose legal entity) and such LLC’s can change hands multiple times over the course of a project’s development trajectory – providing a point of contact for each project provides a simple way to facilitate potential transactions between developers and load-serving entities. With over 40 load serving entities (LSEs) in the market for procuring nearly 15 GW of new resources by 2026, CPUC staff note the time-consuming processes often undertaken by LSEs to identify and contact developers. With no centralized information source for contacting developers of projects going through the CAISO interconnection process, many LSEs must actively solicit contact information for developers so that they can have a circulation list for future RFOs (SCE for example has an open website input to be added to SCE’s RFO Distribution list). If developers do not receive RFOs, they miss out on opportunities to sell their project(s). In the past few years, the number of entities procuring large quantities of new resources has expanded significantly, and as such, the need for increasing transparency around how to get in contact developer is increasingly important.

CPUC staff would also encourage the CAISO to make more detailed information about project phasing and/or downsizing public, if possible. For phasing, if a project is listed as 500 MW, but it is only in PPA to develop the first 100 MW by a certain date, then it would be helpful if the queue report could identify the first date by which a certain amount of MWs of the overall project will come online. For downsizing, if the project has decided to downsize due to permitting restrictions or other development difficulties, it does not currently appear that the queue report reflects this lower expectation for total size of the interconnection’s development plan.

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

CPUC staff support and encourage allowing interconnection customers to allow all information that the CAISO would generally consider confidential could be made public for their project and included in the public interconnection information released by the CAISO. The CPUC would encourage the CAISO to consider requiring disclosure of information that is already publicly disclosed by the interconnection customer via other processes, in particular with local, state or federal authorities.

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

CPUC staff support the inclusion of a minimum term requirement to be eligible for a TPD allocation. As the CAISO noted on p15 of the Revised Straw Proposal, the CPUC requires 10-year contracts for its two recent procurement decision. Thus, most viable projects will likely have 10-year or longer contracts. CPUC staff recognize that projects can come online under alternative circumstances and thus support the CAISO’s proposed term requirement of five years. To also address unique circumstances where shorter-termed PPAs may occur, CPUC staff ask the CAISO to consider allowing sequential PPAs or a sequential combination of PPAs and PPA shortlistings or in-negotiations that sum up to a time longer than the minimum term requirement to qualify a project for inclusion in the appropriate deliverability allocation groups

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

CPUC staff support a requirement to have a contract to sell the RA to an LSE with a RA obligation.  The ratepayers developed the transmission system to support reliability and so the transmission system should be utilized by projects that are providing reliability via resource adequacy supplied via the transmission system, as noted with the proposal’s reference to the CPUC IRP process on page 15. While CPUC staff realize there may be some nuances to implement around that principle, CPUC supports the requirement of an RA sale contract and that the term lengths should be generally consistent with the general PPA allocation group requirements. The status of that RA sale contract impact on obtaining a deliverability allocation should be consistent with the PPA status allocation requirements per allocation group. For example, if a project is in negotiations for such a contract, it should have the same amount of time as projects in the allocation group, which are shortlisted for a PPA or negotiating a PPA.

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

The CPUC staff does not oppose higher fees or other criteria be required for submitting an interconnection request; however, increasing fees, as noted by the proposal itself, may not achieve the result of reducing interconnection requests per parent company. Also, although the queue appears overheated now, under the recently requested CPUC transmission study under high electrification 30 MMT high electrification sensitivity, the CPUC expects there to be a need for 83 GW of new resources by 2035. Having a steep increase in costs for interconnection requests above a fixed number per entity may just incentivize the creation of LLCs and increase costs to customers without actually addressing how to efficiently and effectively manage interconnection requests. Also, unfortunately a fixed number may become stale as the magnitude of the need for resources fluctuates [and composition of the developer market modifies.]  The CPUC appreciates and supports the CAISO seeking to ways to address the problem this fee proposal seeks to address, i.e. overall queue management and overall process efficiency.

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

No comment at this time.

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

No comment at this time.

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

CPUC staff supports the CAISO’s ability to terminate the GIA earlier than seven years if the project is not proving it is moving forward with permitting and construction.

CPUC staff encourages the CAISO to make public summary information about how many projects are potentially at risk to be terminated (i.e. designate in the public queue report when a project is put on notice), and designate when the GIA has been terminated by the CAISO (and which requirement triggered the termination).

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

No comment at this time.

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

CPUC staff encourages the CAISO to consider whether it can identify ways to make queue termination procedures a more transparent process, and/or a process possibly supported by an independent verification process.  At present, there does not appear to be an obvious way for outside observers to know whether CAISO is actively sending notices of potential breach and to how many ICs, etc. 

CPUC staff suggest that the CAISO might want to investigate whether an interconnection customer should be required to remove themselves from the queue if they receive a final non-appealable decision from a permitting authority that denies their project permit.

CPUC staff also suggest that the CAISO might explore whether there are any small incentives that can be offered to motivate interconnection customers to remove themselves from the queue rather than wait the full 7 years for queue expiration.  Given the vast quantities of resources needed to ensure reliability, it may be worthwhile for ratepayers to encourage interconnection customers to not block more viable projects just because they have an ability to do so.

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

No comment at this time.

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

No comment at this time.

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

 CalWEA’s primary concerns are as follows.

• CalWEA urges the ISO to take care not to discourage companies from submitting a reasonable number of projects into the queue – i.e., a number of projects for which due diligence can reasonably be expected to have been conducted, and not to penalize companies before they are able to obtain specific information in the scoping meeting.  We therefore recommend that the first tier of the study deposit include up to 5 Interconnection Requests (IRs), and that deposits be fully refundable up to 30 days after the scoping meeting.  Higher deposits with capped non-refundability are reasonably applied to developers that submit a higher number of applications.  In combination with additional penalties later in the process, these measures provide sufficient discouragement of speculation without unduly penalizing developers with well-formed projects.
• CalWEA opposes requiring Interconnection Customers (ICs) to finance network upgrade costs exceeding a certain threshold of the net investment for all low voltage transmission facilities of the PTO. The cost should be borne by all parties that benefit from accessing the generation enabled by the transmission upgrades.  

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

CalWEA supports making public the following data:

• PCDS and IDS %
• Phase level data of gen and fuel type, MW, operational dates
• MWh of storage
• Suspension status and timing of a project
• Parking status
• Construction status 

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

CalWEA believes that these data are market sensitive and should not be made public:

• TP deliverability group and allocation
• PPA executed and MW
• Project Affected System status

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

 No comment at this time.

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

 No comment at this time.

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

CalWEA supports requiring a minimum PPA term of three years, which will indicate that a project is commercially viable without creating an unduly high barrier to obtaining TPD status.

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

Yes, to facilitate contracts with non-LSE buyers, CalWEA supports the TPD eligibility of a PPA with an entity that does not have an RA obligation. The procuring entity should be allowed one year after its TPD allocation to demonstrate that it has a contract to sell the RA capacity to a California load serving entity that has an RA obligation.

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

CalWEA believes it is reasonable for an interconnection customer to submit up to five interconnection requests in one cluster window because it is reasonable to assume that sufficient due diligence can be conducted on this number of projects (whereas more speculation will likely be involved as that number increases). Therefore, the first tier should be for 1 to 5 IRs. To discourage speculation, CalWEA supports higher deposits if more than 5 IRs are submitted by the same parent company.

CalWEA opposes any non-refundability of unused study deposits if withdrawn within 30 days from the scoping meeting. The scoping meeting is the first opportunity to get transmission information for a particular project. CAISO should encourage, not discourage, interconnection customers to make informed decisions based on transmission conditions as this stage.  Penalties for withdrawing after the scoping meeting are sufficient to discourage speculation. 

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

CalWEA opposes requiring ICs to finance network upgrade costs exceeding the funding cap. The cost should be borne by all parties that benefit from accessing the generation enabled by the transmission upgrades

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

CalWEA has no objection to the ISO proposal. 

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

CalWEA supports the ISO invoking the default clause in the GIA to manage this. 

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

CalWEA supports the ISO proposal with the clarification ISO made during the stakeholder call that the energy-only project is terminated if it contributes to the short circuit duty that requires mitigation.  

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

No comments at this time. 

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

No comments at this time. 

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

No comments at this time. 

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

EDF-R supports many aspects of the CAISO's Phase 2 IPE proposal, as detaield in the comments below.

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

EDF-R’s requested interconnection queue data items are:

• Resource ID
• Transmission Planning Study Area and Sub Area
• TPD Deliverability Allocation Group
• Partial Capacity Deliverability Status percent or MW amount
• Phase level nameplate MW, interconnection capacity MW, Fuel Type, Technology, In-Service Date, COD, hybrid or collocated designation, MWh data for storage projects1
• Restructure the fuel type by column (wind, solar, BESS) rather than Fuel-1, Fuel-2, Fuel-3
• Cleanup of POI Data
• Application LGIA suspension information
• Project parking status

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

EDF-R questions the need for PPA execution information to be made public via the CAISO and opposes that data item. PPAs are reviewed and approved by the CPUC, making the CPUC the appropriate steward for the distribution of that information (which is available in advice letters and other filings).

If the CAISO moves forward with adding TPD Deliverability Allocation Group, Partial Capacity Deliverability Status percent or MW amount, and Project parking status (all of which EDF-R supports) EDF-R believes that will be sufficient for deliverability-related analysis. All of these data items are statuses and amounts that are produced by CAISO processes, thus making CAISO the steward and authority on those data points.

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

EDF-R submitted comments on this item on the on the Data Transparency April 5, 2022 stakeholder call discussion.[1] EDF-R believes the CAISO should do more to increase Transmission Planning Data accessibility. CAISO’s responses to that request in the Data Transparency Stakeholder Process document[2] illustrate that even though significant data is available, its spread across multiple documents and difficult for the non-expert user to synergize.

[1] https://stakeholdercenter.caiso.com/Comments/AllComments/aaac6858-9147-49a3-96df-4d087925378b#org-1d41812e-4219-45a3-bfed-347ac321900c

[2] http://www.caiso.com/InitiativeDocuments/ISOResponse-DataTransparencyMatrix-InterconnectionProcessEnhancements2021.pdf 

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

EDF-R submitted comments on this item on the on the Data Transparency April 5, 2022 stakeholder call discussion.[1] Those comments include requested data points, requested format, brief discussion of the item, and a suggested priority level for the information. EDF-R believes the data should be transparent, and by transparent data we mean data that is accurate, available to the interconnection customers, and accessible to the average stakeholder. This specifically means (1) clear definitions on what the data represents, (2) clear naming conventions that allow the data to be mapped and related to other CAISO data, and (3) formatted in a manner that allows analysis of the data. EDF-R encourages CAISO integrate new data into the existing interconnection queue report or another report delivered from RIMS where possible.

[1] https://stakeholdercenter.caiso.com/Comments/AllComments/aaac6858-9147-49a3-96df-4d087925378b#org-1d41812e-4219-45a3-bfed-347ac321900c

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

If CAISO chooses to move forward with a minimum contract term for PPAs eligible for TPD allocation, EDF-R believes strongly that such a limit shuold only be imposed if the time-limit is rooted in some objective and emperical process or construct, rather than a general feeling.

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer.

EDF-R sees no reason that an LSE must directly be contracting with an interconnection customer to serve RA. Commercial needs, and thus contracting needs, will forever be changing as the electric industry changes. The bottom line is if a generating facility is serving the RA needs of an LSE, it should be eligible for TPD allocation.

A simplified example of a possible contractual arrangement:

Interconnection customer:

• Owns and operates the generating facility
• Sells 15 years of RECs and associated energy products to XYZ Corp

XYZ Corp:

• Sells RA to LSE with RA obligations

The various contracting arrangements for that generating facility (who owns it, who operates it, who procured its associated energy products, ect) are not relevant to the TPD allocation process so long as the generating facility is serving the RA needs of an LSE.

b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer.

EDF-R believes CAISO should have the ability to exercise reasonable discretion in its TPD process, allowing for minor delays. For example, if a contract to sell the RA to the LSE is in final form, but hasn’t completed the signature routing process, it does not serve the CAISO, the LSE, nor California to revoke that generator’s TPD status. Rather in that situation, CAISO could give a 30-day extension to the compliance date to allow for administrative items to be competed.

c) If yes, what length of extra time should be provided and what is the basis for that? *

            See above.

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

EDF-R has concerns about the first refund threshold and opposes its adoption with caveat.

The first refund threshold is:

If an interconnection request is withdrawn for any reason, the study deposit is 20% non-refundable once the interconnection request is determined complete up until 30 calendar days following the scoping meeting.

Because information presented at scoping meetings is inconsistent from region to region, this item in the CAISO’s proposal does not represent an equitable “service level agreement” between the CAISO and the interconnection customer. It is frustrating to hear (or receive written meeting notes) that respond to basic questions with “we don’t know until we study it.” The CAISO and PTO are experts in this field and deeply familiar with their assigned study regions, some insight can always be shared.

If the CAISO proceeds with the 20% threshold, EDF-R believes the CAISO should include with it tariff language that requires the provision of basic information on feasibility at scoping meetings and in the written meeting notes. Data should include: a summary of the area’s history including historical queue drop out information (which indicates that Points of Interconnection is not viable), Transmission Plan Deliverability availability, congestion, and the magnitude of upgrades needed to accommodate new supply.

To put it plainly, EDF-R believes that for $30k (or in some cases $160k) interconnection customers should get the opportunity to meet with the CAISO and PTO on their specific project and receive basic information.

EDF-R also requests additional transparency on the process it will use to identify affiliated interconnection customers as they apply to the scaling costs.

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

No comment at this time

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

No comment at this time

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

EDF-R believes the CAISO already has sufficient tariff authority to seek FERC approval to terminate GIAs that are in breach.

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

No comment at this time

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

No comment at this time

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

EDF-R enthusiastically supports the notion that when a developer issues a notice to proceed to the PTO, the PTO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects.

This is logical, will likely reduce the number of PTO triggered ISD delays, and may have the long term benefit of reducing the need for Limited Operations Studies or projects coming online with IDS instead of FCDS. All of these items are evidence that transmission sometimes trails generation.  

EDF-R notes that in the June 16 NOPR, FERC proposes eliminating the “Reasonable Efforts” standard and imposing penalties for delayed interconnection studies, and that the discussion in the NOPR is directly related to this topic[1]. In short, the timely provision of interconnection service is critical to supporting supply development and maintaining just and reasonable rates, and it is appropriate to establish mechanisms to hold transmission providers accountable for the timely execution of their duties under the tariff. The NOPR is directed at study timelines, but the same logic applies with respect to the integrity of the dates a PTO quotes for in-service and deliverability status achievement.

It is only with the CAISO’s recent creation of the Transmission Development Forum that stakeholders have a transparent and accessible forum and document set for understanding transmission construction status. Historically such meetings were via invitation only, or internal to the CAISO and PTO. EDF-R strongly supports the continuing of the Transmission Development Forum. EDF-R views the forum as a responsible and initiative-taking practice that will prevent last minute discovery of crisis level delays, and ensure equitable information distribution. As with CAISO’s RUG and TUG and Release Planning meetings, a smooth Transmission Development Forum is an indicator that the forum is working well, not the opposite. EDF-R requests the CAISO affirm its commitment to this holding this meeting.

In response to the first two Transmission Development Forums stakeholders have asked about the PTOs’ process and criteria for prioritizing transmission upgrades for new-resource interconnection vs. other work, prioritizing work between interconnection-related projects. For example, whether upgrades get higher priority based on: (1) First-come, first served; (h) original in-service date; (2) how many projects or how much capacity is depending on them; (3) whether they are RNUs (needed for interconnection) vs DNUs (needed for deliverability). EDF-R requests CAISO work with PTO’s to provide more transparency on this item. The Jan 21, 2022 CAISO response only provided brief feedback from one PTO[2].

EDF-R requests that the CAISO clarify that there is no strict limit on the nature of Transmission Development Forum questions asked on the call, provided the question is about a transmission project being reviewed in the forum. Wholesale question deferrals on the call have a chilling effect on questions and undermine the goal of the forum.

[1] https://www.ferc.gov/media/rm22-14-000 PDF page 122

[2] http://www.caiso.com/Documents/ISOResponsestoCommentsMatrix-TransmissionDevelopmentForum-Jan212022.pdf question 5a

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

No comment at this time

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

Golden State Clean Energy (“GSCE”) appreciates the opportunity to comment on the California ISO’s 2021 Interconnection Process Enhancements initiative phase 2 Revised Straw Proposal.

This second phase of the 2021 IPE provides an important opportunity for a more holistic review of the interconnection process and comes at a critical inflection point for the grid where meaningful reforms are needed to efficiently manage the queue while facilitating the interconnection of a record number of new generator and storage resources needed to meet California policy goals. CAISO must use this opportunity to position the interconnection process to sustainably manage this growth.

We believe there is a substantial risk of future superclusters if CAISO does not do more now to increase the success rate of those seeking interconnection. Based on our analysis discussed in our March 31 IPE comment,[1] if the historic success rate of projects in CAISO’s queue continues then more clusters the size of Cluster 14 will be needed to get sufficient resources connected and built to address California’s goals. This is not tenable. GSCE believes that going forward site exclusivity must be a requirement to submit an interconnection request, in line with rule changes the Federal Energy Regulatory Commission has proposed in its recent generator interconnection Notice of Proposed Rulemaking.[2]  We see projects with site exclusivity as much more likely to be able to proceed to commercial operation, and we agree with FERC that “more stringent site control requirements will help prevent interconnection customers from submitting interconnection requests for speculative, non-commercially viable proposed generating facilities.”[3]

In this comment, GSCE addresses the following sections from the phase 2 Revised Straw Proposal:

• Sections 3.1 and 3.2 regarding transmission related interconnection issues
  • Summary of GSCE comment: We support CAISO removing these topics from IPE and raising them in the context of the transmission planning process. To the extent new proposals emerge in this round of comments, they can form a basis for the future TPP discussion.
• Section 3.3 regarding data transparency
  • Summary of GSCE comment: We disagree with the shift of focus from what can CAISO do to improve its data transparency to only focusing on what project information should interconnection customers divulge. We do not see the focus on customer-specific information as assisting with the transparency needed to avoid prospecting interconnection requests, which was one of the main reasons for this topic.
• Section 3.4 regarding eligible PPAs for deliverability allocation and retention 
  • Summary of GSCE comment – minimum term: A one-year minimum term requirement would be reasonable considering deliverability is intended to support the resource adequacy program, which is a short-term compliance regime. Also, a one-year minimum term requirement creates substantially less risk of disruption in the RA marketplace.
  • Summary of GSCE comment – PPA offtaker: GSCE opposes distinguishing corporate PPAs from other PPAs requiring deliverability, and to the extent CAISO creates conditions for corporate PPAs to qualify, it must make accommodations to ensure that reasonable commercial arrangements are able to qualify so projects seeking to receive deliverability and provide RA are not needlessly prevented or discouraged from doing so.
  • Additional response to PPA eligibility:
    • CAISO has leaned heavily on the position that making PPA eligibility criteria stricter is reasonable because it merely determines the highest priority for a deliverability allocation. However, this argument ignores the fact that a project with a PPA that does not qualify for Group A would be unlikely to qualify for any other allocation group unless it reaches commercial operation (Group C) or just completed Phase II studies (Group D).
    • If CAISO intends for this PPA eligibility criteria to apply to all PPA references in the GIDAP (as initially proposed in the phase 1 draft tariff language), CAISO needs to make that clear in the subsequent papers because its policy papers have narrowly focused on the TPD allocation and retention process. CAISO should also provide support for why this PPA restriction is warranted under the other provisions.
• Section 4.1 regarding study deposits
  • Summary of GSCE comment: We support the comments stakeholders made on the June 14 stakeholder call that raised site exclusivity as a potentially more accurate way to address speculative projects and deter interconnect requests that have a high risk of failure. We believe a combination of site exclusivity and study deposit reforms has a better chance of reducing speculative projects. GSCE proposes that study deposits be scaled upward in two separate tier systems based on whether site exclusivity has been secured. For interconnection customers with site exclusivity, CAISO should maintain the status quo. For ICs without site exclusivity, CAISO should impose more stringent study deposit requirements and forfeiture provisions.
• Section 5.3 regarding the ability to terminate a GIA prior to seven years in queue
  • Summary of GSCE comment: GSCE generally supports CAISO terminating the GIA of projects that are clearly lingering in the queue or not responding as a way of managing the queue and encouraging more viable projects to remain. We also request additional information on CAISO’s proposed change in enforcement of BPM for Generator Management Section 6.5.2.1.

[1] Comment of Golden State Clean Energy on CAISO’s 2021 IPE phase 1 Draft Final Proposal, at response to question 5, March 31, 2022, available at: https://stakeholdercenter.caiso.com/Comments/AllComments/c544f3b8-cc88-4cb9-8eab-0d954017ac94#org-d05b52aa-5c55-49b2-aef0-c169e81d9f19.

[2]Improvements to Generator Interconnection Procedures and Agreements, RM22-14, at ¶ 115, June 16, 2022.

[3] Id.

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

 GSCE would support the following data being made public:

• Percentage of partial or interim deliverability
• Deliverability allocation group and year of allocation

Given the importance of deliverability, a better understanding of TP deliverability availability is the type of transparency effort that could better inform interconnection requests. For instance, potential interconnection customers may decide not to submit an interconnection request if their prospective project is in areas where there is no deliverability and where there is little chance that previously allocated deliverability will fail to be retained (e.g., a project that receives TPD via new Group D is more likely to fail to retain it than a project that receives TPD via new Group A).

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

No comment at this time. 

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

No comment at this time. 

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

GSCE requests that CAISO be explicit in the potential benefits to be gained from each piece of data that CAISO proposes to make public in future papers. Any proposal to make data public should be grounded in potential benefits and not based on a few stakeholders’ support or a lack of direct opposition. Without clear benefits and substantial support without much opposition, it is prudent to opt not to make interconnection customers’ data newly public. CAISO must respect the commercial sensitivity of interconnection customers’ data and should not propose to end confidential treatment without substantial support.

Considering our desire for future proposals to be grounded in clear benefits, GSCE is generally unsure how most of the requested data could provide benefits such as better informing future interconnection requests. These types of benefits seemed to underly the initial drive for data transparency, so if such benefits no longer seem likely to occur then project developers are being asked to divulge commercially sensitive information and potentially disadvantage their project without receiving a clear benefit or improved marketplace.

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

In response to the two sub-questions posed, GSCE believes that (a) it is reasonable for CAISO to impose a minimum term requirement on qualifying PPAs, but (b) we find a one-year term sufficient to protect minimal standards for ensuring PPAs are associated with projects that deserve the highest priority TPD allocation.

We disagree that short-term contract length is a reason to question the potential success of a project, especially considering this deliverability question should only consider the contract length for RA attributes. Contract length and product bundling is an evolving issue in the contracting landscape. CAISO has historically avoided inserting itself into the role of scrutinizing contracts and the commercial value of contract terms. We believe CAISO should continue this historical posture and avoid making significant changes to PPA eligibility criteria, especially given the lack of data or support CAISO has provided for enforcing a significant minimum term. The Board had many questions that could not be fully answered during phase 1 policy approval, and this highlights the danger of regulating commercial terms and determining which terms justify deliverability.

Further, because deliverability is allocated to support the RA program it is questionable to consider Integrated Resource Planning in this topic. CAISO suggested that the 10-year minimum term requirement in IRP procurement orders supports a 10-year minimum term requirement for deliverability allocations, a dubious position given the Board was unwilling to approve of the phase 1 proposal for a three-year minimum term. IRP involves long-term planning that should drive major investments through TPP and not prevent modest investments in delivery network upgrades that enable new RA resources. Transmission-related questions coming from the generator interconnection process should focus more on open access and reliability considerations, such as RA.

The CPUC has repeatedly chosen to maintain a short-term compliance program for RA and has even rejected proposals for system RA to evolve from one to three-year requirements. Beyond compliance timeframes, IRP and RA differ in capacity counting, planning reserve margin, energy-only assumptions, and analytical assessment, providing further reason to focus on how deliverability can support RA and not borrowing elements of long-term planning that make it more difficult for new resources to receive deliverability and provide RA.

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

GSCE opposes distinctions for corporate PPAs and commercially unreasonable conditions for corporate offtakers. In response to the sub-questions posed, we believe that:

• (a) an entity without an RA obligation such as a corporate offtaker should be able to execute a PPA that qualifies for deliverability outright because the RA resource will eventually be used to meet an LSE’s RA obligation and CAISO has not proven anything to the contrary;
• (b) additional time should be provided for offtakers to meet such unique conditions because it is needed to line up a secondary offtake agreement that CAISO proposes to require to make an otherwise viable PPA eligible for a TPD allocation; and
• (c) we defer to non-LSE offtakers’ views of what is necessary to make these commercial arrangements because they would have to comply with any hurdles placed on them to prove the commercial reality that the RA they procure is being provided to LSEs with RA obligations.

GSCE opposed distinguishing PPA offtakers in IPE phase 1 and does not believe CAISO has had the support for this proposal as it claims. There have been calls for more data to support the underlying concern that ratepayer funds may not be prudently invested if TPD is allocated based off corporate PPAs, but CAISO has not provided this. Instead, generalized ratepayer concerns have been reiterated, ignoring the fact that potential C&I offtakers are actually ratepayers themselves (while LSEs are not, but CAISO is assuming only LSE investments are in the interest of ratepayers).

CAISO’s approach to this topic should change since the Board did not accept the proposal in IPE phase 1. There is an insistence around this proposal when it appears to be a relatively new issue and without much stakeholder support or agreement that an issue even exists. CAISO instead could propose a tracking system where CAISO logs all projects that received TPD via a corporate PPA and can assess how often that RA eventually ends up on a supply plan or evaluate other metrics of concern. If withholding or otherwise is found to be an issue, CAISO can propose changes in a future IPE to provide conditions for corporate PPAs to be eligible for deliverability.

To the extent CAISO creates conditions for corporate PPAs to qualify for deliverability, it must make sure that reasonable commercial arrangements are accommodated so that projects that deserve to receive deliverability are not needlessly prevented from doing so. Stakeholder comments in phase 1 repeatedly called to CAISO’s attention that re-selling RA may limit other types of transfer arrangements, yet CAISO never seemed to acknowledge this or work to incorporate this type of eligibility process that was in line with what CAISO was already proposing.

Lastly, if CAISO does create a unique process for corporate PPAs to become eligible for TPD (e.g., the re-sell requirement), then CAISO should not place corporate PPAs in a lower tier within Group A. There would be no justification at that point to treat the resource differently than a resource that had sold its RA directly to an LSE, so CAISO would needlessly punish an RA resource for being initially purchased by a non-LSE.

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

We appreciate CAISO’s examination of how to limit speculative interconnection requests and the data provided that shows a correlation between the number of interconnection requests submitted in a single cluster and project withdrawal rate. While the data seems to support CAISO addressing interconnection customers with multiple project submittals, especially the handful of companies that submitted several times as many projects in Cluster 14 as all other interconnection customers, stakeholder comments during the meeting to discuss this paper called that conclusion into question. Based on those stakeholder comments, GSCE requests that CAISO conduct further analysis to understand why projects withdraw. It may be that other factors are more directly connected to the failure rate, such as the lack of site exclusivity.

Considering serious reforms are needed to ensure more projects in the queue are viable and able to reach commercial operation, GSCE supported CAISO taking its site exclusivity proposal in phase 1 even further to reduce speculative projects. We think there is room for additional policy changes in phase 2 that strengthen the site exclusivity requirements. CAISO should get in front of FERC’s recent generator interconnection NOPR and require site exclusivity from future interconnection requests. Our analysis discussed in our March 31 IPE comment[1] concludes that not only is the current queue unlikely to be sufficient to meet California’s long-term climate change objectives (based on the queue’s historical success rate), but a significant amount of time, money, and precious human resources are currently focused on studying projects that will never become operational. Analysis from Lawrence Berkley National Laboratory supports the urgent need for CAISO to address its interconnection process by showing that projects in CAISO’s queue reach commercial operation at one of the lowest rates in the nation.[2]  Further analysis by CAISO to understand why projects withdraw will help pinpoint solutions, but FERC has already expressed a belief that more stringent site control requirements are needed to ensure more viable projects are presented in interconnection requests.

Given there is reason to address both those who submit numerous interconnection requests and site exclusivity, GSCE proposes study deposits be scaled upward in two separate tier systems that are based on whether a project has site exclusivity. CAISO can maintain its current study deposit proposal but apply it only to interconnection requests without site exclusivity. CAISO can then create a second tier system for interconnection requests with site exclusivity where the study deposit increases more gradually and has overall lower deposit amounts. This eases the burden on those with site exclusivity that feel unfairly punished for submitting numerous interconnection requests by allowing them a meaningful way to disprove that their projects are speculative. CAISO should not punish legitimate project applications.

[1] Comment of Golden State Clean Energy on CAISO’s 2021 IPE phase 1 Draft Final Proposal, at response to question 5, March 31, 2022, available at: https://stakeholdercenter.caiso.com/Comments/AllComments/c544f3b8-cc88-4cb9-8eab-0d954017ac94#org-d05b52aa-5c55-49b2-aef0-c169e81d9f19.

[2] Lawrence Berkley National Laboratory, Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection As of the End of 2021, at slide 11, April 2022, available at: https://emp.lbl.gov/sites/default/files/queued_up_2021_04-13-2022.pdf.

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

No comment at this time. 

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

No comment at this time. 

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

GSCE supports CAISO terminating the GIA of projects that are clearly lingering in the queue or not responding or meeting reporting obligations. This seems like a modest way to manage the bloated queue and is based on reasonable business expectations. The ability to cure deficiencies before being withdrawn means that reasonable interconnection customers will not be surprised by any new enforcement.

However, CAISO proposes to adopt by reference the following stakeholder proposal, to which we request that CAISO more clearly and in its own words propose in the next policy paper: “LSA/SEIA notes that BPM for Generator Management, Section 6.5.2.1 states that ‘projects requesting to remain in the queue’ beyond the applicable limit ‘clearly demonstrate that:’ (1) engineering/permitting/construction will take longer than that; (2) the delay is beyond the IC’s control; and (3) ‘the requested COD is achievable in light of any engineering, permitting and/or construction impediments.’ This language does not seem like a license to stay in the queue ‘forever.’ However, LSA/SEIA do not object to consideration of reasonable Energy-Only viability criteria or time limits.”

GSCE recognizes this BPM language currently exists, but we request CAISO explicitly document what would change compared to its current enforcement of this provision.

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

No comment at this time. 

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

No comment at this time. 

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

No comment at this time. 

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

Sections 3.1 and 3.2 in the phase 2 Revised Straw Proposal address transmission related issues that involve the generator interconnection process. GSCE supports CAISO removing these topics from IPE to be part of a more robust and holistic discussion in the context of the transmission planning process. The examination of these issues raises questions and may require analysis that could be deemed out of scope for the 2021 IPE, rendering the value of examining these topics in IPE questionable if they would be limited in scope. We also appreciate CAISO undertaking a transmission planning process enhancement.

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

Hanwha Q Cells (HQC) appreciates the continued opportunity to provide feedback as part of CAISO’s Interconnection Process Enhancements 2021.

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

CAISO is seeking feedback regarding the public availability of the following project data items:

• Percentage of PCDS and IDS
• Phase level data
• Suspension status and project timing
• PPA executed (with MW)
• Construction status
• Project parking status
• Project affected system status

HQC supports the inclusion of advanced data such as phase level data and construction status. 

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

HQC is opposed to the public availability of PPA execution status in any form.

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

HQC potentially supports the inclusion of other data items (not included on the provided list) and is eager to review those additional items in the next round of review. HQC has no additional items for CAISO to consider at this time.

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

HQC requests CAISO to consider moving this conversation to a separate stakeholder discussion where HQC and other developers can provide feedback and discuss new suggestions in depth.

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

HQC does not have any other comments at this time.

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

HQC does not have any other comments at this time.

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

HQC supports the use of higher fees, deposits, and other criteria as a mechanism to parse out less viable projects from the queue. However, HQC believes the tiered approach to application costs unfairly penalizes larger developers and may result in fewer viable projects in queue. HQC believes this proposal incentivizes fewer, larger, and more speculative submissions into the queue.

HQC believes that a cost structure based on project size is a better alternative to CAISO’s proposal.

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

As a developer involved in markets across the country, HQC’s own experience points to a lot of grey area when assigning costs. So far, the necessary reforms have not taken place, and these have generally not been calculated fairly.

That said, HQC is generally supportive of a methodology that employs a cost cap for network upgrades. HQC believes that a cost cap enables developers to make prudent and sound financial decisions. HQC looks forward to reviewing CAISO’s detailed proposal. 

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

HQC does not have any other comments at this time.

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

CAISO is requesting feedback on the following items:

• Should projects that are energy-only be allowed to stay in the queue forever?
  • HQC does not believe any project should be allowed to indefinitely stay in the queue.
• If a project does not reply to queries for information, should there be a time limit as to when the project must reply before a default of the GIA is declared? Currently, the ISO generally does not invoke the default clause if the project does not reply to inquiries, should the ISO invoke this clause for this reason?
  • HQC supports the removal of un-responsive projects so long as a reasonable effort to contact developers is made within a reasonable amount of time.
• If a project needs an MMA (because it has missed a major milestone or its’ COD) but will not initiate the process, how long should the ISO wait before invoking the default clause?
  • HQC supports a fair and reasonable effort on CAISO’s part to obtain the needed information before removing a project from queue.
• If a project is not moving to permitting, procurement, and construction of the interconnection facilities or generating facilities, should the ISO do anything other than requiring the project to meet the GIA Milestones? Stakeholders may offer other suggestions about moving stalled projects through the queue to completion or withdrawal.
  • HQC has no comment at this time.
• Any other stakeholder suggestions about moving stalled projects through the queue to completion or withdrawal?
  • HQC does not have any other suggestions at this time, but looks forward to reviewing CAISO’s detailed proposal regarding this matter.

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

HQC does not have any other comments at this time.

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

HQC does not have any other comments at this time.

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

HQC does not have any other comments at this time.

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

 HQC does not have any other comments at this time.

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

LSA’s positions on the Revised Straw Proposal (Proposal) issues are summarized below.

Data Transparency (Q2-Q5): 

• LSA supports disclosure of project-related items listed in the Proposal, with just a few exceptions. 

• LSA continues to support additional data transparency for information on transmission constraints, including “heat maps” and other interactional tools developed by other ISOs.

• LSA believes that Interconnection Customers (ICs) should be allowed to disclose their own project information, directly (which LSA believes that they are allowed to do today) or in CAISO documents.

PPA definitions for TPD Allocations (Q6-7):

• Minimum PPA term for TPD allocation:  LSA continues to believe that a minimum term greater than one year is not needed.

• PPAs with non-LSEs:  LSA continues to believe that restrictions are not needed but, if a non-LSE off-taker is required to have an LSE Resource Adequacy (RA) contract with an LSE, one year should be adequate for execution of that additional contract.

Higher fees for Interconnection Request (IR) submittals (Q8):  As before, LSA does not object to higher Study Deposits generally.  However, LSA opposes the CAISO’s proposal for: (1) tiered Study Deposits; (2) additional Study Deposit forfeits (both earlier and later in the process); and (3) Study Deposit retention for years after study completion.

Cost allocation treatment for network upgrades to local (below 200 KV) systems (Q9):  LSA recognizes the problem but opposes the CAISO’s proposal for fixing it, asking the CAISO to consider a different direction.  If the CAISO nevertheless proceeds with this proposal, it should modify it in certain key respects.

CAISO as an Affected System – Network Upgrade (NU) reimbursements (Q10):  LSA supports the CAISO proposal, for the reasons stated.

Time in queue/GIA milestone enforcement (Q11-13):  LSA generally supports the CAISO’s proposals for more stringent enforcement of deadlines and communication requirements.

PTO upgrade actions after IC Notice to Proceed (NTP):  The CAISO shouldn’t just reject this issue as too complicated.  Instead, LSA favors CAISO oversight to ensure that PTOs actually proceed after receiving an IC’s NTP, at a timing/pace to meet the PTO’s GIA commitments.

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

LSA is somewhat confused by the deferral of this issue to Phase 2.  The CAISO indicated in its May 24th document, Data Transparency Stakeholder Process as part of the Interconnection Process Enhancements 2021 (Paper), and the discussion about the Paper at a May 31st stakeholder meeting (Meeting), that it may not have the capability to make the improvements stakeholders want for data transparency. 

Specifically, both the Paper and the Meeting presentation were generally explanations of why the CAISO cannot or would not agree to virtually any of the 40-odd data transparency changes suggested by stakeholders.  The reasons include: (1) Data that are “already available” in bits and pieces; (2) systems that do not communicate with one another; (3) systems that cannot easily be updated or modified; and/or (4) workload issues. 

However, inclusion of the confidentiality issues indicates that the CAISO may be able to provide at least some of these data.  The CAISO should clarify the communication disparities between the two efforts.

Generally speaking, LSA does not have issues with providing the requested data discussed in the Proposal.  LSA members understand that they would be required to provide the data they desire to see from others.

The table below summarizes LSA’s views on the specific data items in the Proposal.  LSA’s input is organized by the characterization of the data in the Proposal.  (This application has issues with formatting when cutting & pasting tables - please try to read across.)

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

LSA does not have serious problems with the data shown above.  However, to be clear:

• There is no need to provide individual PPA information (price, products, etc.) – only whether the project has a PPA or not, and the associated MWs.

• There is no need to describe the degree of Site Exclusivity obtained thus far – just whether or not the project has provided an in-lieu deposit.

• Construction and/or Affected System status are not necessary.

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

 Please see the project location assistance discussed below in Q8.

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

LSA has no objections to allowing Interconnection Customer to make its data public.  In fact, LSA thought that ICs already had that right today to do so directly.

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

The proposed three-year minimum PPA term is better than the previously proposed five-year minimum.  Because TPD allocations, and the RA status they convey, are such critical elements of project viability, imposition of a minimum term would significantly influence PPA contracting generally.

LSA continues to oppose the proposed minimum term, for the reasons explained below.  LSA understands the CAISO’s latest position that, all other things equal, a longer-term contract is easier to finance and a may be a better project viability indicator than a shorter-term contract.  However, there are many features besides contract length that contribute to project viability, e.g. project price.

• The CAISO has provided no evidence that lack of a PPA minimum term has caused any problems, though there has never been a minimum PPA term to qualify for a TPD allocation.   For example, it is highly implausible that an operating project with valuable RA attributes would withhold those attributes from the market, and willingly forego the associated revenue stream, just because its PPA expires, and there is no indication that this is happening.   

• PTO upgrade durations have pushed many projects farther into the future, some well into and beyond the required 2023-2026 CPUC Mid-Term Reliability (MTR) on-line dates.  It is very difficult for projects with such late CODs to acquire PPAs, since they count for little or nothing toward MTR obligations.  

• Some buyers are wary of contracting long-term with projects that do not already have TPD allocations.  Once a project secures TPD using a shorter-term contract, the off-taker will often be willing to seriously negotiate a longer-term agreement.

• PPA contract length is beyond the purview of the CAISO.  PPA term length, and the other key elements of PPAs, are under the jurisdiction of the regulatory authorities for the LSEs executing them.  The CAISO tariff recognizes the oversight of these regulatory authorities through deference to their rules for RA Qualifying Capacity and other important features.

• Efficient markets for RA generally depend on short-term availability of at least some RA capacity.  For example, CAISO instituted last year a requirement that RA resources obtain substitute RA capacity during planned maintenance outages, and their ability to comply with that requirement depends on short-term RA availability of substitute resources.

• The CAISO proposal would undermine market flexibility at a time when increased flexibility is needed.  While developers typically rely on longer-term contracts to support project development, the PPA market is struggling with many issues that are pushing parties in the opposite direction.  Among those are:

• • Regulatory uncertainty:  The CPUC is conducting an extensive and lengthy effort to significantly revise how RA resources are counted, among other things.  The Mid-Term Procurement counting rules are not consistent with current rules, adding uncertainty. 

The CAISO itself has contributed to this uncertainty through its Unforced Capacity (UCAP) proposal.  That proposal, which has been public for a couple of years but has not yet moved forward, has nevertheless greatly complicated RA contracting, and it is unclear whether or when it might be imposed and what the eventual rules might be.

• • Cost uncertainty:  Equipment markets – e.g., for batteries – have been especially hard hit by the combination of inflation and supply-chain shortages.  Equipment has become harder to obtain, and equipment suppliers are quoting cost increases of 30% or more in some cases.  This situation could persist far into the future as renewables and storage construction ramps up considerably, raising the possibility of higher operating costs after Commercial Operation as well.

This makes it extremely difficult for developers to quote the kinds of long-term firm prices that buyers have become accustomed to in long-term PPAs.  LSA is aware of PPAs that have been cancelled by developers because they are no longer economic, and longer-term contracts are, all other things equal, riskier in this respect. 

• • COD uncertainty:  The discovery of additional upgrade requirements very late in the study process, or even later than that (e.g., through a Reassessment) make committing to a longer-term PPA very risky; generally, security posting requirements to the off-taker are significantly higher for longer-term agreements than for short-term agreements.  LSA notes that the longer the contract term, the greater the development security required, and the greater the risks associated with later COD delays.

• The CAISO proposal would disadvantage new projects compared to existing projects with expired shorter-term contracts.  These existing projects, which were and are not subject to any minimum terms, could contract for any term agreeable to their off-takers, while new projects would be hobbled by any CAISO minimum-term requirements.

For these reasons, LSA concludes that the CAISO should not impose mandatory minimum PPA term lengths on an already fraught situation without any demonstration of need.  The trade-offs between contract/revenue certainty and regulatory/cost risk should be left to free interaction between contracting parties, and approval of LSE regulators, and not dictated by the CAISO. 

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

LSA continues to believe that restrictions are not needed, as non-LSE off-takers are strongly incented to offer any unneeded RA into the market.  However, if a non-LSE off-taker is required to have an LSE Resource Adequacy (RA) contract with an LSE, one year should be adequate for execution of that additional contract.

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

 The Proposal has several parts in this area, including elements beyond just increasing requirements for submitting an Interconnection Request (IR):

• Increased Study Deposits for “parent companies” submitting multiple IRs;

• Increased Study Deposit forfeits, both earlier and later in the process, for IRs that are withdrawn; and

• Delays in Study Deposit refunds to the Commercial Operation Date (COD), from the current refund date of Generator Interconnection Agreement (GIA) execution.

LSA strongly opposes all of these proposals, for the reasons listed below and further explained in the rest of this section.

• These proposals fail to address the root cause of developers submitting multiple IRs.

• The proposed fees far exceed actual study cost and thus are arbitrary, unjust, and unreasonable.

• The “evidence” provided does not justify the Study Deposit levels or structure.

• The proposed Study Deposit retention and forfeit revisions are not justified, including their applicability years beyond the studies themselves. 

• While the CAISO may believe that it can identify “parent companies,” it has yet to articulate how it will treat more complex project ownership structures, or those that change over time.

The Proposal fails to address the root cause of multiple IR submittals.

The CAISO proposals miss completely the strong connection between multiple developer IR submittals to determine the best sites and the lack of readily available information on transmission constraints/deliverability availability.  As LSA pointed out in its comments on the Data Transparency effort, developers do not have enough information to determine in advance which sites are likely to be viable, and they need studies to help them determine that. 

The addition of the TPD Allocation to the interconnection process has greatly increased project viability uncertainty.  Prior to Cluster 5, developers could fund Delivery Network Upgrades (DNUs) for their projects and be confident that their projects would receive Full Capacity Deliverability Status (FCDS) once those upgrades were complete. 

Now, developers often do not find out which projects will receive deliverability (a key viability attribute, especially for projects with energy storage) until after the Phase II Study is complete.  Even locations that might look promising before IR submittal can later turn out to be non-viable.

For example, the 2021 Transmission Plan Deliverability (TPD) Allocation Report contained 8 different transmission constraints, but the 2022 TPD Allocation Report contained 20 constraints (some “nested” within others).  It is difficult or impossible for developers to anticipate, with the information available years earlier when the applicable IRs were submitted, which projects might receive deliverability allocations in these cycles and thus which would be the most viable. 

The information CAISO cited in the Data Transparency effort as “already available” – including the annual TPD Allocation Reports or the Transmission Capability Reports – does not provide information developers need about transmission constraints and deliverability availability in the future, or even the amount of deliverability left in areas where constraints are not yet binding.  No matter how “well developed” proposals may be when they are submitted to CAISO, in many cases developers cannot really tell which ones might look viable 2+years later.

Before penalizing developers for using the tools available to them – i.e., information discovery via interconnection studies – the CAISO should first improve its own information transparency about desirable sites. 

Other jurisdictions have improved their offerings to assist developers in this manner.  As LSA pointed out in its Data Transparency comments, MISO provides a “heat map,” shown below, indicating areas of the system where constraints limit deliverability.  MISO also provides an accompanying tool that screens for constraints and provides information for potential POI testing.  (See https://giqueue.misoenergy.org/PoiAnalysis/index.html.) 

SPP has now launched a similar queue information tool, including a heat map of transmission constraints.  (See https://app.powerbi.com/view?r=eyJrIjoiNDFiMTkzMGItOTZlZS00NzZmLTg1ODMtMzEzMmQ3MThmYWYxIiwidCI6IjA2NjVkY2EyLTExNDEtNDYyNS1hMmI1LTY3NTY0NjNlMWVlMSIsImMiOjF9.)

LSA also notes that paragraph 49-51 of the FERC NOPR on Improvements to Generator Interconnection Procedures and Agreements (Docket RM22-14-000) posted here  https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20220616-3082), proposes to require Transmission Owners to provide publicly available interactive visual representations of interconnection capacity and transmission congestion.  This feature may be mandated by FERC if retained in the final rule making.

Finally, as LSA recommended in its Data Transparency comments the CAISO is proposing above a major increase in Study Deposit amounts, far in excess of actual study costs, and the CAISO should consider diverting some fees from each project (or using the higher forfeited Study Deposits), toward funding those improvements. 

The Proposal bears no relationship to actual study costs

The CAISO has stated many times that actual study costs are the same for each project.  The CAISO actually lowered the Study Deposit from $250K/project to $150K/project several years ago to reflect actual study costs (estimated at about $156K per project at that time). 

Based on that fact alone, the CAISO’s proposal is unjust and unreasonable.  Study Deposits that are in excess of five time the costs they are intended to cover are simply not justifiable and are unlikely to be approved by FERC.

The arbitrariness of the proposed structure is illustrated by the CAISO’s modification to its own earlier proposal.  The current Study Deposit for a developer submitting, say, 10 IRs is $1.5 million.  The CAISO’s earlier graduated proposal would have required an increase to $7 million (a 460% increase). 

The CAISO’s new, tiered proposal (where every IR submitted by a developer is subject to the higher amounts) would increase that Study Deposit to $8 million (a 530% increase).  The Proposal does not justify the extra $1 million in terms of fairness or cost-justification, but because “it will be easier to administer” (Proposal, p.19).

The “evidence” provided by the CAISO does not justify the proposals.

The project withdrawal information provided in the Proposal as a percentage of IRs submitted is divided into two categories – those submitting: (1) “1-2 requests;” or (2) “3 or more.”  However, the CAISO proposal has five increasingly punitive tiers, even though no information is provided, for example, that developers submitting 3 IRs have a better project retention record than those submitting 10 IRs.  Thus, the project withdrawal information provided by the CAISO does not justify the proposal tiering structure. 

More generally, the project continuation data provided in the Proposal do not show which proposals are “well-considered” – i.e., more likely to succeed, i.e., reach Commercial Operation – and which are not.  The data simply show current project retention in the queue starting with Cluster 10, not likeliness to reach Commercial Operation. 

It could be, for example, that larger developers are better able to determine eventual project success earlier in the process than smaller developers, and then withdraw projects earlier (which the CAISO says it wants to encourage).  Smaller developers may have more at stake for each project, and thus may ultimately withdraw at a similar or higher rate but later in the process. 

This hypothesis is supported by the Proposal data, where the project retention difference between developers submitting higher/lower numbers of IRs is much narrower for C12-13 than C10-11. 

The Study Deposit forfeit and refund proposals are unjust and unreasonable.

The Proposal contains no information indicating that the current forfeit structure has any impact on project withdrawal levels.  The punitiveness of imposing withdrawal penalties much earlier in the process, of course, is multiplied by the potential huge increase in Study Deposit levels.

The Proposal would impose new Study Deposit forfeit provisions for withdrawal:

• After an IR is “complete” (seemingly, before the IR is even validated).  Thus, a developer, after devoting considerable resources to prepare and submit an IR, is not allowed to even obtain the sometimes-sparse information provided in a Scoping Meeting before the penalties start to apply.  A developer should at least have the opportunity to discuss its IRs with the CAISO and applicable PTO (and Potential Affected Systems) before deciding whether the IR should proceed.

• After GIA execution, apparently.  The Proposal would refund unused Study Deposit funds after Commercial Operation, much later than the current GIA execution milestone.  The Proposal does not explain why – it simply states (at p.20):

The ISO also believes that execution of a GIA is no longer the appropriate milestone to refund remaining deposits to interconnection customers, and believes reaching commercial operation is a more appropriate milestone to achieve this initiative’s objectives.

The rationale for the CAISO’s change in “belief” is not explained or justified in any way.  There is simply no justification, years after studies are already complete, for:

• Retaining Study Deposit money, for projects reaching COD, even if interest is paid (which should be a requirement, as it is for other interconnection-related refunds); or

• Imposing Study Deposit forfeits, for projects withdrawing after GIA execution but before COD, e.g., for reasons having nothing to do with study results.

The Proposal does not address more complex or changed ownership situations.

For example, there is no indication how the CAISO will treat:

• Partnerships, joint ventures or other shared or complex ownership models.  Would participation in those types of structures could against partners or members submitting separate IRs?

• Acquisitions by other entities with different ownership profiles.  A project may be acquired by an entity owning only that project.  Would that entity be subject to the same punitive provisions in this area as the original developer?

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

LSA recognizes the problem and fully supported the CAISO’s proposal to FERC, and we agree that something should be done.

At a minimum, the CAISO should clarify the calculation of the cap, including the PTO-provided figures in the table on p.24 of the Proposal.  Specifically, the CAISO should clarify whether the calculation would include LV-TRR costs associated only with completed projects, projects under construction or with executed GIAs, or projections based on study results for additional projects or clusters.

More specifically, LSA continues to believe that the CAISO’s proposal is not just and reasonable, for the reasons described below.

First, contrary to the assertions in the Proposal, this proposal would impose different and discriminatory refundability rules in different CAISO-area locations.  Despite the “non-discriminatory” verbiage used in the Proposal (and all prior versions of this proposal), as well as the CAISO’s earlier filing at FERC, this “generic” proposal is clearly aimed at GLW/VEA.  The CAISO would not be making this proposal (and certainly not at this time) if not for the GLW/VEA situation.  So, the assertion that this proposal would apply to “any PTO” in a “non-discriminatory” fashion is highly misleading and disingenuous at best.

Second, the proposal would likely have the impact of preventing most future generation development on the VEA system.  The cap is so low that a single project could easily absorb the entire $3.5 million below it.  Developers would not likely take the risk of proposing VEA interconnections in the future, because: 

• There is no way at this point to know whether or when the cap will be reached, depending on how the interconnection costs counted toward the cap are calculated (see above), i.e., when developer ability to secure NU refunds would be exhausted.

-  There is no way for a project to know the impact of the cap until it gets an Interconnection Study.  Even after the cap is reached, for example, there may still be “room” for new capacity, depending on the location, estimated upgrade costs, and how interconnection costs are counted toward the cap (see above). 

-  Moving the POI to a higher-voltage point could yield worse study results and (based on earlier CAISO assertions – see below) would sacrifice any “lower of” Network Upgrade cost-cap protection for the developer for the Phase I and Phase II Studies.   

Third, LSA is disappointed that the CAISO did not consider any of LSA’s alternative suggestions.  These alternatives included, for example, addressing FERC’s problems with the earlier proposal by allocating “excess” LV-TRR costs to other PTO LV-TRRs based on LSE contracting of projects in the VEA area, which would provide the direct connection to beneficiaries required by FERC.  Those transmission costs could then be addressed through the “Least-Cost, Best Fit” framework used by most LSEs to assess generation-project economics. 

Alternative recommendations if this proposal is adopted

If the CAISO proceeds with this framework, LSA offers the following recommendations:

• Any such significant rule changes should not apply to projects already in the queue.  As with other significant rule changes, it would be unfair to change NU refundability rules after a project has already entered the interconnection process. 

• Projects moving to a higher-voltage POI due to application of the cap should still qualify for “lower of” Phase I/Phase II cost-cap protection.  LSA has not found any tariff provision stating that this protection would not apply in that situation, but it should be retained if this proposal is implemented.  It is likely that the original IR would include the most economical interconnection, and so the developer should not lose cost-cap protection for trying first to connect in the least-cost manner. 

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

LSA continues to fully support the CAISO’s proposed policy for refunds for CAISO-area Network Upgrades funded by resources interconnecting in other BAAs.  LSA still urges the CAISO to seek reciprocal arrangements with other jurisdictions, so that CAISO-area projects can receive similar treatment from those other jurisdictions.

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

LSA provides the following feedback on the CAISO’s questions in this Proposal section.

1. Should EO projects be allowed to stay in queue forever?

LSA first proposed and continues to support the CAISO’s intent to enforce BPM Section 6.5.2.1 conditions on extending CODs.  That section states that “projects requesting to remain in the queue” beyond the applicable limit “clearly demonstrate that:” (1) engineering/permitting/construction will take longer than that; (2) the delay is beyond the IC’s control; and (3) “the requested COD is achievable in light of any engineering, permitting and/or construction impediments.” 

The CAISO is also proposing that projects be terminated if they contribute to Short-Circuit Duty issues.  LSA recommends instead that, consistent with the stakeholder meeting discussion between the CAISO and GridBright, the CAISO allow such projects to remain in queue if they comply with the BPM provisions above and agree to fund their share of any SCD mitigation needed, i.e., not terminate these projects for SCD reasons alone.

2) Should a project have a time limit for replying to CAISO information queries before a GIA default is declared?

LSA continues to support the CAISO proposal to issue a deficiency notice under GIA Section 17.1.1 when projects fail to comply with regular status-report requirements, & terminate if appropriate.

3) If a project needs an MMA (e.g., has missed COD or other major milestone but won’t initiate the process), how long should CAISO wait before declaring a GIA default?

4) Should CAISO take action if project does not move to permitting, procurement, & construction but doesn’t miss GIA milestones?

LSA comments on Q3-Q4:  LSA agrees with the CAISO proposal to require projects to meet GIA milestones, and to be more proactive if a milestone is not achieved by providing a notice of breach, consistent with LGIA Section 17 and SGIA Article 7.6.

LSA comments on SCE proposal

SCE proposed to limit COD extension MMAs to securing tax credits, obtaining a PPA, or securing permits, and to otherwise require a project to suspend until an appropriate timeline can be determined. 

LSA agrees with the CAISO proposal to keep MMA rules as is, since projects are already limited to 7 years in queue, except for PTO Delay, PPA alignment, or “legal actions.”  In other words, delaying GIA execution just gives the project less time for construction and testing.

LSA also notes procedural issues with SCE’s proposal, i.e., SCE is concerned that these issues are causing projects to delay GIA execution, while the project suspension provisions are contained in the GIA; thus, it is not clear how GIA provisions could apply before the GIA is even executed.

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

LSA’s comments on Section 5.3 are contained above.  LSA does not understand the CAISO’s additional question here.

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

LSA continues to believe that close monitoring and enforcement of milestones are the best way to clear the queue, given the existing contractual tools and deliverability-retention rules.  LSA also continues to support voluntary incentives to projects for leaving the queue, e.g., forgiving security forfeits that would otherwise apply.

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

With all due respect, it is not sufficient for the CAISO to wash its hands of this issue simply there are many “projects inflight.”  This issue would not have arisen if Interconnection Customers have been able to “work closely with” PTOs “to ensure that both the generation and transmission projects are on track to meet the GIA milestone dates.”

More specifically, what is the purpose of an Interconnection Customer “Notice to Proceed” (often accompanied by a third (non-refundable) posting) if the PTO does not, in fact, actually proceed?  Why should ICs make a unilateral commitment when the PTO is not doing the same?

Even more specifically, it is not necessary for a PTO to begin work on “all upgrades” needed for a project once the GIA is executed and the IC provides a Notice to Proceed.  Instead, the PTO should be required to begin work on all upgrades in time for the project to achieve its COD and deliverability status.  Work on the longest lead-time upgrades should begin first, followed by work on shorter lead-time upgrades, so the PTO can fulfill its commitments under the GIA.

Moreover, initial work – design, engineering, and permitting – on significant upgrades (like typically consists of relatively low-cost, low-regrets activities.  Thus, such significant upgrades could still be readily cancelled if enough projects drop out that the upgrade(s) is not needed. 

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

LSA has no additional comments.

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

NCPA appreciates CAISO’s willingness to explore opportunities for more viable projects to move forward towards COD, make more data available to the public, and explore different cost allocation methodologies.

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

No comment at this time.

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

No comment at this time.

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

No comment at this time.

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

No comment at this time.

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

NCPA supports efforts to ensure more viable projects will move forward, however where the Interconnection Customer (IC) is also the off taker for a project's output, the IC should be allowed to provide supporting information to satisfy such requirements without a formal PPA.

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

No comment at this time.

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

No comment at this time.

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

NCPA supports the allocation methodology of costs to those that receive the benefits. We request PG&E provide data showing available investment before the 15 percent cap is reached. NCPA further supports LV facilities to be competitively bid, which can also reduce the overall cost to ratepayers.

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

No comment at this time.

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

NCPA supports the ISO developing a criteria in Phase 2 of the IPE that grants the ISO and PTO(s) the ability to remove project(s) allocated for partial or full deliverability or are energy-only from the queue that fail to advance towards commercial operation in less than seven years or do not respond to ISO inquiries within a reasonable amount of time by terminating its GIA, unless an interconnection customer(s) can demonstrate that the delay is due to an event not reasonably within their control.

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

No comment at this time.

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

No comment at this time.

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

NCPA agrees for the PTO(s) to start planning for upgrades once studies are complete. The PTO(s) should have the ability to sequence and schedule upgrades in the most cost efficient way.

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

No comment at this time.

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

PG&E appreciates the opportunity to provide its perspectives on the revised straw proposal issue and looks forward to working with the CAISO and other stakeholders through the IPE Phase II process. 

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

PG&E recommends that the CAISO consult with the Federal Energy Regulatory Commission (FERC) on which data elements can be made public as requested by stakeholders, and which data elements should remain confidential.    Some of the currently confidential data elements listed in the revised straw proposal may be used by energy market firms to influence or get ahead of market pricing information.  Therefore, PG&E recommends that any data that is or could be used to correctly identify the specific project and/or its location should remain confidential (i.e., “personally identifiable information”).

PG&E also respectfully requests that CAISO clarify what is meant by the term “affected system status” (last bullet, p. 12) and the context of that term be used.

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

See response above.

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

PG&E does not have any recommendations for other data elements to be made public, but we do recommend that the CAISO maintain certain data on a regular basis and share the data with Participating-Transmission Owners (PTOs).  Specifically, data on ISO-controlled facilities/circuits within each PTO territory should be shared with PTOs on a regular basis.

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

If a customer chooses to make their own data public, PG&E believes that’s their decision and right.

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

At this time, PG&E does not have comment on this proposed enhancement.

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

PG&E recommends that CAISO require entities seeking an allocation of TPD to meet certain qualifications prior to receiving an allocation.  For example, CAISO could require entities in the queue provide a third financial security posting or submit a “quality” application (e.g., proof of site control / site exclusivity / site accessibility, etc.).  Setting a standard of qualifications that need be met prior to receiving a TPD allocation will likely reduce the risk of speculative projects, that may not materialize, from receiving scarce TPD and taking it away from other resources that are more likely to come online in a timely manner and provide the necessary reliability.

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

PG&E is supportive of any enhancements CAISO can deploy to discourage the submission of speculative interconnection requests.  The particular approach the CAISO has laid out may not be sufficient due to potential gaming by “parent” companies setting up separate LLCs to skirt around the rules.  PG&E believes CAISO may need to look at other methods of containing the number of IRs submitted, such as developing a refined set of criteria for submitting what is deemed a “quality” application to help weed out speculative projects that are not adequately advanced in development.  One criterion that could be strengthened is site control / site exclusivity / site accessibility.

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

PG&E does not have comment on this proposed enhancement.

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

PG&E does not have comments on the study base case assumptions determined for Affected System Studies.  However, PG&E disagrees with CAISO’s cost allocation proposal for network upgrades due to CAISO being an Affected System.  Instead, PG&E agrees with SCE’s and other prior stakeholder comments supporting CAISO’s cost allocation proposal regarding Affected Systems in its Contract Management “COMA” Enhancements Initiative Draft Final Proposal issued September 30, 2021.  In that initiative, CAISO proposed that “[p]articipating TOs will not reimburse external interconnection customers for network upgrades. This practice is consistent with neighboring utilities’ practices for ISO interconnection customers” and PG&E supports this approach.

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

PG&E supports the proposed enhancement and proposal to put Interconnection Customers in breach of contract if they don’t achieve their milestones, regardless of the project being Energy-only or Full Capacity Deliverability Status (FCDS).

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

PG&E does not have any comment.

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

PG&E suggests the CAISO consider if projects should not be able to “park” or be suspended to help manage the queue and resources.

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

PG&E supports the enhancement, which proposes for Interconnection Customers to work with the PTOs on timing of network upgrades.

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

For the proposal in Section 6.1 (i.e., ICs sharing gen-tie line, interconnection facilities, etc.) PG&E recommends the CAISO create provisions to document and define shared Interconnection Facilities or Interconnection Reliability Network Upgrades (IRNUs) as Conditional Upgrades to be included in the Maximum Cost Exposure (MCE). This identifies both costs and duration dependencies that could impact downstream projects.

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

While CAISO’s revised straw proposal on Phase 2 makes progress in some areas, there are two areas in particular that REV Renewables (REV) believed need significant revisions: section 4.1 on deposits and 6.2 on PTO planning for upgrades.

REV Renewables (REV) continues to strongly oppose the ISO’s current proposal for higher deposits based on the total number of interconnection requests. In general, REV supports higher fees, deposits, and criteria in general to limit IRs and increase commercial viability of projects. However, CAISO’s proposal is discriminatory to large developers and is not justified given that the amount is not tied to any increase in costs to conduct the study nor to project viability criteria. REV suggests that, if CAISO’s goal is to decrease the number of interconnection requests, it could instead increase project viability with transparently developed criteria such as technical documents, site control, and increasing deposits at risk.

Also, REV does not agree with CAISO’s assessment and proposal on whether the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS. REV suggests CAISO and PTOs should start planning for project network upgrades when the GIA is executed and a notice to proceed is received by PTO from IC. Often times PTOs wait until enough projects execute GIAs and issue notice to proceed to start planning for shared network upgrades that are required to interconnect and/or deliver all projects. This leads to uncertainty for the projects that are ready to proceed and hence providing a plan and timeline to the interconnection customers that are ready would be helpful. While the actual construction may not start right away, it is just and reasonable for the PTO to provide a plan for the upgrades and not defer the project until some date unknown by the interconnection customer.

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

From the list provided by CAISO, REV supports making the following items public:

• Project “formerly known as” names are considered confidential due to business affairs.
• Percentage of PCDS and IDS could be interpreted as market sensitive and pricing information.
• Phase level data for the project including: gen and fuel type, MW, hybrid or co-located designation, MWh data for storage projects.
  • As noted below, REV does not support making public milestone dates, resource IDs and TP Deliverability group and allocation.
• PTO study area

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

REV does not support the following items being public as they are information that could significantly hinder the competitiveness of the project if made public. CAISO should maintain confidentiality on these items.

• PPA status is considered confidential due to pricing information and market sensitive.
• Site exclusivity documentation and status are considered confidential due to price and commercially sensitive.
• Phase level data for the project including: milestone dates, resource IDs, and TP Deliverability group and allocation.
• Suspension status and timing of a project
• PPA executed and MW
• Construction status
• Project parking status
• Project Affected System status
• TP Deliverability Allocation Group

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

REV does not have other recommendations on data that should be public.

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

REV does not have a problem with allowing Interconnection Customers to make their data public if they choose to do so. However, it should be an option and customers should be able to maintain confidential information as private if they choose.

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

REV has no comment at this time.

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

1. Yes, REV suggests that a PPA that is with an entity that does not have an RA obligation should be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation. CAISO should be encouraging all entities, not just LSEs, to procure deliverable capacity and should be encouraging this capacity to be contracted with LSEs with an RA obligation.
2. REV has no comment at this time
3. REV has no comment at this time

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

REV continues to strongly oppose the ISO’s current proposal for higher deposits based on the total number of interconnection requests. In general, REV supports higher fees, deposits, and criteria in general to limit IRs and increase commercial viability of projects. However, CAISO’s proposal is discriminatory to large developers and is not justified given that the amount is not tied to any increase in costs to conduct the study nor to project viability criteria. Large developers could genuinely have several viable projects, and given the resource needs in the state to meet its reliability needs and policy goals, projects should not be so severely discouraged. CAISO’s analysis on page 19 is too coarse to draw the conclusion that a project is more likely to drop out if the developer has three or more interconnection requests in the cluster. As suggested previously, REV suggests that CAISO could increase project viability with transparently developed criteria such as technical documents, site control, and increasing deposits at risk. REV’s suggestions are also more in line with the new FERC NOPR RM22-14-000, “Improvements to Generator Interconnection Procedures and Agreements,” which includes several proposals to increase the speed and certainty of queue processing through increased readiness requirements, and a deposit framework based on size of project rather than number of requests filed by each Interconnection Customer.

The increase in fees should not be based on the number of requests. However, if CAISO continues to pursue this proposal it should, at a minimum, adjust the bands so as not to set the barrier to entry too high for developers that may have several viable projects. For example, for 1-4 projects the deposit could be $250,000; for 5-8 projects the deposit could be $300,000, and 9 or more could be $350,000.

REV also opposes the ISO’s revised study deposit refund criteria. In particular, REV suggests that the deposit should be fully refundable (minus costs) within 30 days after the scoping meeting because this is the first opportunity the developer has to discuss the project with CAISO and PTO and learn basic information necessary to help determine project viability. REV proposes the following revisions, and suggests CAISO clarify whether each amount is refundable before or after ISO costs. REV suggests the following study deposit refund criteria: If an interconnection request is withdrawn for any reason, the study deposit is:

• Refundable minus costs once the interconnection request is determined complete up until 30 calendar days following the scoping meeting.
• 25% non-refundable minus costs after 30 days following the scoping meeting and up to 30 days following the Phase I study results meeting.
• 100% non-refundable minus costs after 30 days following the Phase I study results meeting.
• 100% refundable minus costs upon reaching commercial operation.

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

 REV has no comment at this time.

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

 REV has no comment at this time.

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

 REV has no comment at this time.

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

 REV has no comment at this time.

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

 REV has no comment at this time.

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

REV does not agree with CAISO’s assessment and proposal.  REV suggests that when a developer executes GIA and issues NTP to the PTO, PTO/CAISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects. Sometimes there are upgrades such as new Remedial Action Schemes that are triggered by a group of projects, and not by individual projects themselves, and CAISO/PTOs wait to start planning for these upgrades until enough projects achieve commercial operations/sign LGIAs and provide NTPs. This can cause material risk to the first project which stays under an Interim Deliverability status until the required upgrade is built. The deliverability status of this project is tested every year under the annual process which is conducted around middle of the year and if enough deliverability is available this project is allowed to be full capacity for the upcoming year. The concern with this approach is if the annual deliverability process does not show enough deliverability, CAISO and PTO may then decide to build the required upgrade but this may be too late for this project to sell full capacity RA for the upcoming year.

At minimum, REV believes it is just and reasonable for the PTO to provide a plan for the upgrades and not defer the project until some date unknown by the interconnection customer. If needed, PTO could require the first project that issues NTP to post security for the entire network upgrade and not just the cost allocated to this project, so PTO has coverage for the financial obligations to build these upgrades. As more projects start executing GIAs and issuing NTPs these projects could reimburse their portion of cost obligation to the first project.

While the Transmission Forum provides a helpful venue for PTOs to provide general updates, it is not specific to interconnection customer projects. PTOs should provide this transparency to interconnection customer-driven upgrades as well. Some of the items that will be helpful to understand the PTO process for these upgrade could be:

• Prioritization, if any, to upgrades coming out of study processes, such as TPP and GIP.
• Considerations to the cost of the shared upgrade. For example, posting amounts received by PTO or number of project level thresholds, if any, that the PTOs use to decide to build the shared upgrades, and whether these thresholds are consistent among different PTOs.

In addition, it will be helpful to further discuss issues related to deliverability status if the project achieves COD and does not trigger the need of shared upgrade itself. In this instance, REV strongly believes that giving FCDS status to projects creates financial incentive to bring the project online in a timely manner and reduces development risks for projects.

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

 REV has no additional comments at this time.

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

• SDG&E commends the CAISO’s efforts in this 2021 IPE stakeholder initiative. SDG&E is thankful for the opportunity to provide its comments on the topics below. 

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

• SDG&E supports making data public that better informs developers and leads to more realistic projects being submitted to the interconnection queue.

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

No comments.

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

• SDG&E noted CAISO’s statement that “The ISO does not currently have…” MWh capacity data for storage projects.  This data is provided by the IC in the Attachment A to Appendix 1, Project Configuration tab, Section VI. Energy Storage Information.  

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

•  No comments.

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

• SDG&E believes it is imperative to maintain a minimum term for PPAs to be eligible for a TPD allocation to ensure entities are seeking allocations in good faith, especially as deliverability becomes increasingly scarce. Nearly all procurement obligations for new capacity mandated by the California Public Utilities Commission (CPUC) require Load Serving Entities (LSEs) with an RA obligation to enter into agreements with a minimum term.  For example, CPUC procurement directed under D.19-11-016 (Near-Term IRP) and D.21-06-035 (Mid-Term IRP) – together mandating the procurement of approximately 15 GW of new resources – required contracts for new capacity to be at least ten years in duration. Providing equal access to deliverability to contracts with a materially shorter-term requirement, or no term requirements at all, creates additional hurdles and undue burdens for CPUC-regulated entities’ efforts to procure for long-term grid reliability. As such, SDG&E believes a five-year minimum is a good compromise for those not subject to the CPUC’s requirements. The proposed three-year minimum term does not ease those concerns, however, if supported by a majority of stakeholders, it is sufficient as it still supports RA needs and provides a manageable long-term commitment to those without an RA obligation.

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

• SDG&E does not yet have a position on this but does note that it raises concerns and questions that require further consideration and development. Chief among those is whether PPA counterparties without an RA obligation have rights allowing participation in the CAISO interconnection process and what, if any, is the appropriate role for non-jurisdictional entities in the interconnection process. To that end, we offer the following suggestion to consider placing the requirement on the generator, rather than the “procuring entity,” to demonstrate that it has a contract with an RA-obligated entity to also sell the RA for at least the minimum term. This alleviates potential concerns that the procuring entity is arguably buying and selling energy capacity in the wholesale markets and would need to meet the regulatory requirements to do so. Further, CPUC-regulated entities, Investor-Owned Utilities (IOUs) in particular, are potentially disadvantaged by the proposal as they must seek commission approval for their PPAs which could take several months. Non-CPUC regulated entities are not subject to this review process and may move more quickly, which could work in the favor of private procurement and inadvertently provide a competitive advantage over projects seeking longer term commitments.

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

• SDG&E supports CAISO’s proposal. 

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

• SDG&E supports CAISO’s efforts to ensure that local ratepayers are protected from the cost impact of low voltage (below 200 kV) generation interconnection-driven network upgrades that benefit all customers in the CAISO’ system. SDG&E also agrees with the CAISO that if the current cost allocation structure remains unchanged it might lead to inequitable cost allocation in the future.
• Under CAISO’s current proposal, generation interconnection-driven network upgrades will be limited at 15% of the low voltage transmission revenue requirement (LTRR) of a Participating TO. SDG&E is concerned with the 15% limit selected by the CAISO and would appreciate if the CAISO could provide more data that explains why a 15% limit is just and reasonable compared to a 30% limit or a 10% limit. It is unclear in the current proposal that only 15% of generation interconnection-driven network upgrade costs only benefit local ratepayers.  At a minimum, SDG&E believes that the CAISO should try to find a clear correlation between a selected limit and the benefits received by local ratepayers.
• Furthermore, although SDG&E believes the CAISO is taking a step in the right direction to protect local ratepayers, SDG&E is also concerned that CAISO’s proposal does not address the fact that generation interconnection-driven network upgrades benefit all ratepayers irrespective of their location. This essentially means that all ratepayers should share the cost of generation-driven network upgrades that are part of the CAISO-controlled grid. The current proposal as it stands, might not be consistent with FERC’s cost causation principles and might lead generators to avoiding cost-efficient and feasible point of interconnections for more expensive high-voltage interconnection points.

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

• No comments. 

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

• SDG&E supports CAISO’s proposal. 

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

• No comments. 

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

• No comments. 

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

• No comments. 

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

• SDG&E seeks additional clarification to CAISO’s proposal to drop Topic 6.1 (IRNU across clusters).  Though a small number has been found which require non-conforming agreements to address this issue, the consideration of GIA and 3^rd IFS alignment is insufficient to address the potential financing back-stop responsibility for the PTO.  Specifically, SDG&E requests CAISO to consider that IRNU-SANU (Switchyards), which are one of the most expensive type of upgrades, have little to no 3^rd IFS posting requirement for those costs when ICs choose to self-build during the GIA negotiation.  GIDAP section 11.3.1.4.4 attempts to address this, but the difference in adjusted IFS would still not be sufficient even with applying section 11.4.2.4.  This also does not allow for additional IFS posting to be collected after termination of the GIA.

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

SEIA appreciates the opportunity to provide comments on the CAISO IPE Phase II revised straw proposal. SEIA supports certain transparency enhancements, TPD allocation for projects with a PPA with a non-LSE off-taker, more stringent interconnection request requirements, and the affected system proposal. SEIA opposes a minimum RA term length for TPD allocation and the alternative cost allocation for local network upgrades. These items are detailed below.

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

SEIA supports the following items being made public:

• Suspension status 
• Construction status
• Parking status 
• Phase level data: Fuel type and TPD Group and allocation should be made public
• Projects with TPD allocation should be more transparent and identifiable

SEIA seeks additional clarity on CAISO’s definition of “Project’s Affected System Status”. Does the CAISO intend this to mean that the project requires the completion of an affected system study to move forward and whether this study has been completed? If the answer is yes to both questions, then SEIA could support the disclosure of this information through simple yes/no check boxes.

SEIA believes that PPA execution and MWs under contract should remain confidential. While it may be possible to infer a project’s PPA execution status under the revised TPD allocation methodology adopted in Phase 1 where Group A is reserved for projects with executed PPAs, SEIA still supports efforts to make project’s with TPD allocation more transparent, while also supporting the outright disclosure of a project’s PPA execution status to remain confidential.

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

No comment.

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

No comment.

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

No comment.

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

SEIA does not believe CAISO should require any minimum term length for RA capacity to be eligible for TPD allocation. That said, SEIA understands that CAISO might prefer projects with longer term lengths since TPD and the associated network upgrades funded by ratepayers are intended to support RA. If CAISO decides to proceed with a minimum term length, SEIA supports the 3 year minimum term requirement.

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

SEIA supports the proposal to allocate TPD to projects with PPAs with entities that do not have an RA obligation but has a contract to sell RA capacity to an LSE. SEIA believes the TPD allocation process should recognize emerging market opportunities beyond those with LSEs, noting that these market opportunities will likely be important in meeting California clean energy goals. If the RA has to be sold to keep TPD allocation, we think at least a year, two preferred, should be given for the RA to be sold from a corporate PPA after the project receives TPD allocation.

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

SEIA supports the use of more stringent readiness criteria so long as it does not serve as a barrier to entry for commercially viable projects. The criteria adopted should balance the benefits of a more efficient interconnection process with a more transparent and manageable risk profile for developers regardless of the size of the project or company.

SEIA believes that the CAISO proposal to increase study deposit amounts depending on the number of interconnection requests submitted per parent company will be difficult to enforce and could disadvantage larger developers. SEIA supports a study deposit framework like that employed in MISO, SPP, and PJM that increases according to the size of the interconnection request. 

SEIA also supports putting more of the deposit at risk earlier in the interconnection process, noting that this provides a firm but fair disincentive for both small and large developers. As in the MISO, SPP, and PJM construct, CAISO could also employ additional financial and/or readiness milestones throughout the interconnection process that are non-refundable if the interconnecting customers withdraws with few exceptions.

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

SEIA opposes the CAISO proposal to allocate network upgrade costs to local systems above the proposed threshold to developers. This proposal will create additional uncertainty for developers that will directly impact project economics. If CAISO decides to proceed with this proposal, SEIA requests that a cost cap be implemented to provide developers with cost certainty. SEIA believes that FERC should adopt a methodology that encourages developer certainty for any cost allocation of upgrade costs, such as a cost cap.

SEIA believes there are alternative options that can reduce the risk to developers. CAISO can classify local systems as net importers or net exporters and base cost allocation for network upgrades on that classification. More specifically, SEIA believes such a classification system could justify socializing network upgrade costs regionally. A demonstration that a local system is a net exporter of power means the benefits are realized more regionally, and the costs should therefore be shared regionally. Network upgrades to local systems identified as net importers would be reimbursed by local ratepayers since local ratepayers will be benefitting. SEIA believes that such a proposal would align costs with the beneficiaries in a just and reasonable and not unduly discriminatory manner. 

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

SEIA supports the CAISO proposal.

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

No comment.

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

No comment.

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

No comment.

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

No comment.

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

SEIA believes a percentage of the interconnection request fees should be used to directly support the interconnection process (i.e., staffing, training, etc.). 

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

The Six Cities either support, do not oppose, or take no position on the proposals included in the Revised Straw Proposal, as follows.  Specifically, the Six Cities

• Support a minimum term for procurement of resource adequacy (“RA”) capacity in a power purchase agreement (“PPA”) that supports allocations of deliverability and do not oppose the proposed minimum term of five years. 
• Support the use of RA capacity “sub-contracts” with load serving entities (“LSEs”) having RA obligations in the deliverability allocation process, but believe that the same criteria and requirements should be applicable to these types of arrangements as apply where the RA capacity of an interconnecting resource is sold directly to an LSE with an RA obligation.  The Six Cities do not support giving commercial entities extra time to market the RA attributes of their PPAs after having been allocated deliverability.
• Support the CAISO’s proposed changes to its interconnection study deposit structure and refund rules.
• Although they remain unconvinced of the need for this change, the Six Cities do not oppose the CAISO’s proposal regarding the treatment of low voltage network upgrades.  The Six Cities continue to have outstanding questions about this element of the Revised Straw Proposal. 
• Do not oppose the CAISO’s proposal regarding reimbursement for the costs of affected system mitigation. 
• Generally support the various measures in the Revised Straw Proposal to enable the CAISO to accomplish more effective queue management. 

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

The Six Cities do not have comments on this item at this time. 

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

The Six Cities do not have comments on this item at this time. 

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

The Six Cities do not have comments on this item at this time. 

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

The Six Cities do not have comments on this item at this time. 

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

Requiring a minimum contract term for PPAs associated with a project’s RA capacity in order to support an allocation of Transmission Plan Deliverability (“TPD”) is reasonable, and the Six Cities support the CAISO’s proposed term of five years.  As explained by the CAISO, the upgrades associated with full or partial capacity deliverability status are ultimately paid for by CAISO transmission customers.  (See generally Revised Straw Proposal at 15.)  As such, it is appropriate to ensure that these upgrades are used for the purpose of actually delivering the capacity of RA resources to the LSEs that fund these upgrades.  The Six Cities do not oppose the proposed term of five years. 

Additionally, the Six Cities would like to clarify one element of the CAISO’s Revised Straw Proposal that does not comprise part of the CAISO’s proposals, but appears to underpin part of the CAISO’s rationale for requiring the five year minimum term.  Specifically, the Revised Straw Proposal explains that “TPD capacity on the ISO system is designed to the level dictated by the CPUC Integrated Resource Planning process” and “transmission upgrades are paid for by ratepayers through the Transmission Access Charges of the Participating TOs.  The amount of TPD capacity available to allocate to interconnection projects is limited to the amounts and locations of TPD capacity needed to meet the IRP resource portfolios the CPUC provides to the ISO.”  (Revised Straw Proposal at 15.)  As the CAISO is aware, some LSEs within the CAISO, including the Six Cities, engage in resource planning and RA resource procurement, but are not subject to the CPUC’s jurisdiction, including with respect to the CPUC’s IRP processes.  As such, the CPUC portfolios do not represent procurement determinations by non-CPUC jurisdictional LSEs.  At the same time, non-CPUC jurisdictional LSEs also require deliverability for their RA resources.  The Six Cities urge the CAISO to consider procurement by non-CPUC jurisdictional LSEs as well as CPUC policy decisions in determining the amount and locations of deliverability to be allocated.

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

As to the first question (at item (a)), the Six Cities believe it is reasonable to permit developers of interconnection projects that are supported by PPAs with entities that do not themselves have RA obligations, but where the RA capacity procured in the PPA is being sold to an LSE that does have an RA obligation, to participate in the deliverability allocation process via the same groupings as projects where the RA capacity is procured by the LSE directly.  In other words, arrangements whereby the RA capacity in a PPA has been “sub-contracted” to an LSE with an RA obligation should be permitted to support a deliverability allocation based on the same rules—including the minimum contract term—as apply to arrangements where the PPA is with the LSE directly.  However, the CAISO should balance the administrative burden of validating contractual arrangements with the benefit of permitting enhanced transactability of RA capacity and should look for ways to require applicants for deliverability to provide documentation of the underlying arrangements in a way that is not unduly burdensome for the CAISO to evaluate.

As to the second question (at item (b)), the Six Cities do not support giving entities that wish to re-sell the RA attributes of interconnection projects “extra time” to market their projects as compared with projects that are selling to LSEs directly.  Deliverability is intended to facilitate the ability of LSEs to procure RA capacity.  Allowing commercial entities extra time to market the RA attributes of projects would appear to provide these types of “RA resellers” with an unfair advantage as compared with other types of developers.  If the CAISO believes that extra time should be afforded to projects to engage in marketing of their RA capacity following a deliverability allocation, then that extra time should be available to all participants in the deliverability allocation process.

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

The Six Cities support the CAISO’s proposal to adopt a revised deposit structure that is tiered according to the number of interconnection requests that are submitted.  The Six Cities also support tightening the refundability criteria for study deposits as outlined in the Revised Straw Proposal. 

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

At this time, there appears to be no compelling reason to revise the CAISO’s long-standing classification for high and low voltage facilities or to change the methodology for determining low voltage (or local) Transmission Access Charges. 

That said, the Six Cities do not oppose the CAISO proposal to cap the investment associated with new low voltage network upgrades at 15% of each Participating TO’s low voltage transmission revenue requirement (“TRR”) and to require interconnection customers to fund, without reimbursement, all network upgrade costs in excess of this threshold, subject to resolution of the questions and comments below. 

• First, the Six Cities request that the CAISO provide information regarding the applicable threshold for Pacific Gas and Electric Co.  (See Revised Straw Proposal at 24.)
• Second, how is the amount of investment in low voltage network upgrades for each Participating TO being determined?  Are these amounts self-reported?  How are the proposed amounts validated?  Is the basis for the reported investment included in any FERC-filed financial reports?
• Third, how will the 15% threshold be applied on a going forward basis, as the value of the plant-in-service associated with the low voltage TRR and low voltage network upgrades depreciates?  If the applicable threshold is reached in one year, such that interconnection customers are required to fund low voltage network upgrades, and then falls below the 15% threshold in a subsequent year, will interconnection customers become eligible for reimbursement until the 15% threshold is again reached?
• Fourth, how will the 15% threshold apply for Participating TOs that do not have low voltage transmission facilities at this time, but could develop low voltage facilities or network upgrades in the future?
• Finally, the Six Cities request that the CAISO confirm that, notwithstanding that there will be no reimbursement of network upgrade costs in excess of the proposed threshold, that there will likewise be no restriction on the ability of interconnection customer-funded network upgrades to be part of the CAISO controlled grid and available for the use of CAISO transmission customers on an unrestricted basis just like any other assets that are under the CAISO’s operational control. 

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

The Six Cities take no position at this time on the base case data that is used in affected system studies.

The Six Cities do not oppose the CAISO’s proposal to provide reimbursement for network upgrades to the CAISO system that are necessary when the CAISO is an affected system.  The Six Cities request that the CAISO track the cost of such network upgrades and report this information to CAISO transmission customers, so that transmission customers may monitor costs associated with affected system mitigation that occurs due to interconnections within neighboring systems.  Although the CAISO reports these costs have not been significant in the past (see Revised Straw Proposal at 26, noting that there have been “virtually no” instances of affected system impacts in the last decade), this may change going forward.  For this reason, it may be appropriate to revisit the cost allocation for affected system mitigation on the CAISO grid in the future, in case costs to the CAISO footprint are significant and neighboring transmission service providers continue their existing practices of non-reimbursement.

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

The Six Cities support the CAISO having the ability to exercise termination rights earlier than the seven year period in such circumstances.  The Six Cities note that they previously requested information on the average time-in-queue for resources that ultimately are developed and observe that the CAISO’s data suggests retention of the seven year period is likely appropriate.  But for projects that are not advancing, there appears to be no reason to wait out the full seven years before the CAISO may exercise termination rights. 

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

The Six Cities do not have concerns with the CAISO’s proposed implementation of the approaches described in this section of the Revised Straw Proposal.    

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

The Six Cities do not have comments on this item at this time. 

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

The Six Cities support the CAISO’s determination that it would not be reasonable to require Participating TOs to immediately commence all network upgrades upon receipt of a notice to proceed or an executed interconnection agreement. 

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

The Six Cities have no further comments at this time.

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

SCE commends the CAISO for undertaking a review of the IPE 2021 – Phase 2 topics intended to present proposed solutions that focus on long-term enhancements to the interconnection process. SCE appreciates the opportunity to present its comments on the Phase 2 topics identified below

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

SCE has no comment. 

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

SCE has no comment. 

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

SCE has no comment. 

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

SCE has no comment. 

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

Yes, the allocation of TPD should require a PPA that procures the project’s RA capacity for some minimum term.  As a Load Serving Entity (LSE), SCE is responsible for the ongoing safe and reliable operation of its transmission system, including undertaking efforts to ensure it reliably serves its Load by securing PPAs to attain sufficient RA levels. The longer-term component of a PPA is a desirable feature since it provides greater stability in an LSE meeting its RA obligation and reduces the need to more frequently negotiate new energy contracts.  SCE supports a minimum PPA term of ten years to receive an allocation of TPD since this duration would provide greater RA stability and would be consistent with the CPUC’s 2019 and 2021 procurement orders which require virtually all new capacity to be procured through 2026 to be under contract for a minimum of 10 years.

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

SCE supports the requirement that an entity eligible to be allocated TPD continue to be an LSE and opposes expanding eligibility to include the allocation of TPD to non-LSEs who would subsequently sell the TPD in a secondary market. The deliverability transmission upgrades which provide the TPD are paid for by ratepayers through the PTOs’ Transmission Access Charges and thus ratepayers should be the beneficiaries of TPD.

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

SCE supports increasing application fees or deposits as a deterrent to developers submitting highly speculative projects.  SCE believes higher fees or deposits should, to some degree, lead to developers being more thoughtful in which IRs to submit and agrees with the CAISO that increasing fees with more at risk earlier in the process will be an effective tool to discourage excessive interconnection requests.  SCE supports the tiered fee approach of the study deposit per interconnection request, ranging from $250,000 to $800,000, dependent on the number of interconnection requests submitted per parent company.  In recognition of the substantial time and effort devoted to validating an IR and preparing for and conducting scoping meetings, SCE also supports the CAISO’s proposal that a portion of the study deposit should be immediately at risk after the IR has been deemed complete.  Modifying the milestone to refund remaining deposits to interconnection customers from the execution of the GIA to achieving commercial operation would appropriately account for projects that linger in the queue after the execution of a GIA.

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

SCE does not oppose CAISO’s proposal. 

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

SCE supports the CAISO’s proposal that the base case assumptions for the study be based on previously queued projects as of the affected system study agreement execution date.  

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

Yes, the CAISO in coordination with the Affected Participating TO and Interconnecting Participating TO, or the Participating TO, should have the ability to terminate an UFA or GIA earlier than the seven-year period to achieve COD; if the interconnection customer cannot prove that its project is meeting its milestone(s) and advancing the permitting, procurement, and construction phases of the project.  SCE agrees with the CAISO’s concerns that there are interconnection customers occupying space (a queue position), that potentially triggered facilities (Interconnection Facilities, Distribution Upgrades, if applicable, and Network Upgrades) that later-queued project(s) maybe relying on, or as equally important, holding on to an allocation of deliverability (PCDS or FCDS) that could have been allocated to project(s) that are advancing towards commercial operation. Projects in the interconnection queue that cannot demonstrate advancement towards COD should not be allowed to remain in the queue indefinitely.  However, if interconnection customers can satisfy the conditions in Section 6.5.2.1 of the Generator Management BPM, the CAISO will not be able to terminate the UFA or GIA in coordination with the PTO(s) within the seven (7) year period pursuant to Article 2.3.2 of the UFA or GIA.  

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

SCE supports the CAISO being more assertive in using Section 6.5.2.1 of the BPM for Generator Management to remove lingering projects, which are not making headway towards commercial operation, from the queue. In instances where a developer does not reply to queries from the CAISO for information on the status of their projects, SCE supports the CAISO invoking the default clause in the GIA.  Developers will then have 30 calendar days within receipt of the Default notice to cure the breach. 

Regarding the situation when a project needs an MMA (e.g., because it has missed a major milestone or its COD) but will not initiate the process, the IC should be given ten (10) business days to acknowledge that a major milestone has been missed or that a COD MMA extension request is required before the PTO in coordination with the CAISO, or visa-versa, issue a notice of default.   

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

If not already addressed in the CAISO’s BPM’s or GIDAP, the CAISO should strip the IC of its deliverability allocation within the seven (7) year time frame if the project does not satisfy the requirements in Section 6.5.2.1 of the CAISO’s Generator Management BPM and convert the project to Energy-Only.  If the project as Energy-Only contributes to SCD issues and fails to advance toward commercial operation, then the CAISO in coordination with the PTO(s) should seek to terminate the applicable interconnection agreement(s).  

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

SCE agrees with the CAISO’s conclusion in the Revised Draft Proposal and discussed during the June 14 stakeholder call. With the large quantity of projects with executed GIAs and inflight, it’s not practical to require the PTOs to start every project’s network upgrades when a notice to proceed is received.  The network upgrades need to be planned in a particular order to meet CODs while also taking into consideration work force and outage availability. A particular example of this is a RAS/CRAS upgrade, which requires significant coordination between multiple teams of skilled personnel across a region. Diverting those resources to start on newly triggered projects could jeopardize the timely completion of existing in-flight work. Regarding updates on the status of transmission projects, SCE would refer developers to the quarterly Transmission Development Forum.  

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

SCE has no additional comments.

1. Provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) 2021 – Phase 2 revised straw proposal:

Valley Electric Association provides comments below in response to Question 9.

2. Please comment on section 3.3 - Transparency enhancements: Which data items do you support being public?

No comments

3. Please comment on section 3.3 - Transparency enhancements: Which data items do you support not being public and why?

No comments

4. Please comment on section 3.3 - Transparency enhancements: Are there other data items you would like to see as public information?

No comments

5. Please comment on section 3.3 - Transparency enhancements: What are your thought on allowing Interconnection Customers to make their data public?

No comments

6. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should the allocation of TPD require a PPA that procures the project’s RA capacity for some minimum term? Please provide reasoning supporting your answer. b) If yes, what should that minimum term be and what is the basis for that?

No comments

7. Please provide comments on the following question related to section 3.4: Revisiting the criteria for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation: a) Should a PPA that is with an entity that does not have an RA obligation be eligible for an allocation if the procuring entity demonstrates that it has a contract to sell the RA capacity procured to a load servicing entity that has an RA obligation? Please provide reasoning supporting your answer. b) If yes, should the procuring entity be given extra time after the project receives an allocation to secure a contract with a load serving entity with an RA obligation? Please provide reasoning supporting your answer. c) If yes, what length of extra time should be provided and what is the basis for that?

No comments

8. Please comment on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?

No comments

9. Please comment on section 5.1: Should the ISO re-consider an alternative cost allocation treatment for network upgrades to local (below 200 KV) systems where the associated generation benefits more than, or other than, the customers within the service area of the Participating TO owning the facilities?

Valley Electric Association, Inc. (“Valley”) appreciates the efforts of the CAISO to propose an alternative cost allocation mechanism for network upgrades related to generator interconnections to local low-voltage transmission facilities.  

The CAISO proposes to limit the cost exposure of Participating TOs for low-voltage network upgrades driven by generator interconnections to 15% of the Participating TOs net transmission rate base reflected in its approved low-voltage transmission revenue requirement (“TRR”).  Any costs for low-voltage network upgrades in excess of the 15% threshold would be financed by the interconnection customers without cash reimbursement.  

While Valley was hoping for a different outcome for resolution of this issue (i.e. allowing these network upgrades to be included in high voltage transmission costs, or creating a new category of interconnection cost allocation for carbon free resources that interconnect to low-voltage facilities of a Participating TO located outside of California), Valley supports the CAISO’s proposal because it is  a significant improvement from the circumstances today, in which Valley’s members are wholly exposed to all of the costs of low-voltage interconnections (subject to overall cost caps imposed by the CAISO Tariff).  However, even with a 15% cap, Valley’s retail electric members would still have exposure to significant costs of network upgrades associated with generator interconnections which do not materially benefit Valley or its members.

VEA understands that several parties are opposed to the 15% cap proposal because it is not consistent with cost-causation.  VEA appreciates these positions and – as several of those parties pointed out – VEA itself supported a more direct cost allocation initially.  While VEA continues to see the merits in our prior proposals, VEA is supporting the CAISO’s 15% proposal as a regulatory solution to try to bridge parties’ positions toward a more workable policy.

10. Please comment on section 5.2: Policy for ISO as an Affected System – a) How the base case determined b.) How required upgrades are paid for:

No comments

11. Please comment on section 5.3: While the tariff currently allows a project to achieve its COD within seven (7) years if a project cannot prove that it is actually moving forward to permitting and construction, should the ISO have the ability to terminate the GIA earlier than the seven year period?

No comments

12. Please comment on section 5.3: Do you have any concerns with the ISO’s proposed implementation?

No comments

13. Please comment on section 5.3: Are there other opportunities the ISO should consider with respect to projects not moving through the queue?

No comments

14. Please comment on section 6.2: Examining the issue of when a developer issues a notice to proceed to the PTO, requesting the PTO/ISO should start planning for all upgrades that are required for a project to attain FCDS, including the upgrades that get triggered by a group of projects:

No comments

15. Additional comments on the IPE 2021 revised straw proposal and June 14, 2022, stakeholder workshop discussion particularly focused on any Phase 2 issues:

No comments