AES Clean Energy
Submitted 08/16/2022, 11:54 am
1.
Please provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) – Phase 2 draft final proposal:
AES Clean Energy appreciates the opportunity to offer comments on the draft final proposal for IPE Phase 2. AES’s comments focus on CAISO’s proposal for higher fees and criteria to submit an interconnection request. AES appreciates the CAISO’s desire to take a proactive approach to the Interconnection NOPR and looking to adopt and modify several the policy proposals found in the NOPR[1]. However, AES believes that the CAISO should not cherry pick which proposals to include at this juncture. It appears the CAISO is only looking to adopt measures targeted toward increasing the requirements for interconnection customers to enter the queue and is not addressing the other identified barriers in the NOPR- such as greater transparency and information on available transmission capacity, which leaves the interconnection process the only way to find information out about network upgrade costs. CAISO staff did express on the call that they were exploring internally what it would take to adopt and generate a heat map as proposed in the Interconnection NOPR. However, until interconnection customers can get the necessary information to identify viable Points of Interconnection (POIs) upfront, AES is skeptical that even if all of CAISO’s proposals are adopted as is, they will not adequately address or deter “speculative” projects. Additionally, it remains uncertain whether Cluster 15 will be similar in volume to Cluster 14, and therefore the CAISO should refocus its proposals to incentivize early withdrawals by making all deposits refundable until the start of Phase 1 and incentivize less viable projects not to proceed to Phase 2 by reducing the withdrawal penalty, while continuing to maintain higher standards through site control or other readiness milestones to proceed to Phase 2.
[1] See FERC Docket RM 22-14-000
2.
Provide your organization’s comments on section 3.1 Transparency enhancements:
AES Clean Energy appreciates the CAISO’s willingness to invest more staff time and resources into addressing the data transparency issues raised by stakeholders. AES supports the proposed items being made publicly available. AES also reiterates its comments above to encourage the CAISO to further consider and implement as soon as possible the creation of a heat map or other data visualization tools to help interconnection customers identify viable POIs prior to entering the queue. It is AES’s belief that until the CAISO provides more information on the best places to interconnect, the CAISO will continue to experience overheated interconnection queues.
3.
Provide your organization’s comments on section 3.2 criteria for minimum term for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation:
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4.
Provide your organization’s comments on section 3.2 eligibility criteria for non-LSE PPAs to receive a Transmission Plan Deliverability (TPD) allocation:
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5.
Provide your organization’s comments on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?
AES Clean energy offers several comments on CAISO’s proposed fee and withdrawal penalty proposals.
First, AES would like to thank the CAISO for being responsive to stakeholder comments and revising their study deposit structure. AES supports the new study deposit structure being based on project size and finds the proposed fee structure in line with study deposit requirements in MISO and PJM. AES does not oppose the 90/10 study cost allocation proposal. However, it was unclear from the proposal when any unspent study deposits would be refunded to customers. AES opposes any proposal that would retain study deposits past completion of all relevant study activities. CAISO has floated the idea of retaining study deposits until projects reach COD. Study deposits are meant to cover up front the cost the ISO may incur from completing Phase 1 and Phase 2 interconnection studies and should not be confused with a financial mechanism to deter “speculative” projects or project withdrawal. Therefore, it would be unjust and unreasonable to retain the deposit once all study activities have been completed.
Second, AES opposes the commercial readiness requirements as currently outlined in the DFP. While commercial readiness requirements were a feature of the Interconnection NOPR, there is no guarantee that this policy will make it into the final order. Furthermore, the idea of commercial readiness criteria being required to enter the interconnection queue is taken from non-ISO/RTO regions who have clearer resource solicitation processes that make this concept less viable for the CAISO’s unique RA markets that requires projects to have deliverability to be eligible to provide capacity. In AES’s experience, off-takers are usually unwilling to begin contract negotiations prior to at least Phase 1 study results being known for projects, therefore it is highly unlikely that even the most viable projects will be able to get executed term sheets prior to the start of Phase 1. AES is also concerned that this proposal may inadvertently advantage utility owned generation over merchant generators, since LSEs may be more willing to contract with projects developed by their own utility rather than merchant generators prior to Phase 1 network upgrades being known.
If CAISO is intent on incorporating this aspect of the NOPR, the CAISO should revise this proposal to have the commercial readiness requirements kick in for progression into Phase 2 and allow projects with executed term sheets or are short-listed to proceed without a separate readiness deposit. The deposit in lieu of commercial readiness should be 2x the study deposit, which would be more in line with the $4000/MW readiness milestone payments required by MISO and PJM. Any commercial readiness deposits should be refundable as soon as the project meets the readiness requirements or executes a PPA. Moving this requirement to Phase 2 would allow project developers and off-takers to have a clearer understanding of the network upgrade costs associated with the project and thus better negotiate a contract. In the future, should FERC adopt the commercial readiness in its final rule making, the CAISO could at that time expand the commercial readiness requirements to Phase 1, when the CAISO would likely also have to adopt and implement proposals to increase the information on viable POIs prior to projects filing interconnection applications. This would also give developers time to change their contracting practices to initiate these earlier in the development process.
Third, AES opposes the withdrawal penalties proposal as written in the draft final proposal. AES believes that the withdrawal penalty framework should be revised to incentivize early withdrawal and increase as projects move through the process. MISO’s interconnection process provides a good example of this kind of framework.[1] MISO requires a D1 payment of $5,000, which is non-refundable, to cover costs associated with validation each project’s application and holding scoping meetings. MISO then has D2 payment that ranges from $50,000 for projects below 6MWs to as much as $640,000 for projects over 1000 MWs. MISO has an additional readiness milestone payment (M2) of $4000/MW. If projects withdrawal prior to the start of DPP Phase 1 study, 100% of D2 and M2 are refundable. At Decision Point 1, following DPP Phase 1 study results, 50% of M2 is refundable if the project withdrawals, and M3 (10% of Network upgrades-M2) deposit is required for projects to proceed to DPP Phase 2. At Decision Point 2, following DPP Phase 2 study results, 0% of M2 is refundable, and 100% of M3 is refundable, and M4 (20 of Network upgrades- M3) is due. If projects enter DPP phase 3 all milestone payments become at risk.
Similarly, CAISO should revise its withdrawal penalties to allow 100% of study (minus incurred expenses) or site control deposits to be refundable up until 30 days following the scoping meeting and before the start of the Phase 1 study. This would incentivize projects to drop out even before the start of Phase 1, and the CAISO could still retain some the study deposit to cover application validation and scooping meeting work. If projects proceed into Phase 1, then 50% of their site control and study deposit will be at risk. If projects decide to proceed to Phase 2, then they should be required to provide evidence of site control, evidence of commercial viability or deposit in lieu of 2x the study deposit. If projects withdrawal during Phase 2, then they are penalized 1.5x the study deposit regardless of how they demonstrate commercial readiness. The increased requirements and withdrawal penalty to enter Phase 2 should also incentivize non-ready projects to drop out prior to its start.
[1] See PowerPoint Presentation (misoenergy.org) for more information on MISO’s Generator Interconnection Process
6.
Provide your organization’s comments 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 Clean Energy opposes this proposal. However, if the CAISO adopts this proposal, then they should grandfather all resources currently in queue from this 15% cap and make this policy effective starting with Cluster 15 projects so that developers can better manage the risk of developing projects on lines below 200 KV. While AES appreciates the CAISO’s proposal to allow project to withdrawal without penalty if the 15% cap is reached, this still will not make developers whole to the investments already made to develop the project.
7.
Provide your organization’s comments on section 5.2 Policy for ISO as an Affected System – how is the base case determined and how are the required upgrades paid for?
AES Clean Energy supports this proposal.
8.
Provide your organization’s comments 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 Clean Energy supports this proposal.
9.
Please provide additional comments on the IPE – Phase 2 Draft Final Proposal not mentioned above:
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California Energy Storage Alliance
Submitted 08/16/2022, 04:05 pm
1.
Please provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) – Phase 2 draft final 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 Draft Final Proposal, CESA believes that many of the proposals are moving in the right direction to support the goals and objectives of the IPE Initiative. Most significantly, however, the ISO made major revisions to its proposals to align with the proposed rules published in the Federal Energy Regulatory Commission’s (FERC) Notice of Proposed Rulemaking (NOPR), RM22-14, to address significant current backlogs in the interconnection queues by improving interconnection procedures, providing greater certainty and transparency, preventing undue discrimination against new generation, and ensuring efficient and timely access to the grid. In particular, the ISO’s revisions made in alignment with the NOPR are focused on those related to the higher fees, deposits, and other criteria. Specifically, the ISO’s proposal mirrored that of the NOPR in setting a tiered study deposit structure based on the MW size of the project and whether the project meets commercial readiness criteria at different stages of the interconnection process, along with withdrawal penalties based on the study or site exclusivity deposits provided. To this end, the ISO sought stakeholder feedback on whether it should wait for the FERC process to be completed, or if the ISO should move forward with its own revised proposal that incorporates a number of FERC’s proposals?.
To this key question, CESA recommends that the ISO pull back the current proposal and instead make incremental changes to align higher fees, deposits, and other criteria with that of the NOPR. Specifically, as discussed in our response to Question 5 below, the ISO should adopt the proposed $/MW study deposit structure, without the inclusion of a commercial readiness deposit to enter Phase II study process that is a higher multiplier of the study deposit and more punitive withdrawal penalties for projects that elect to use a commercial readiness deposit. This more incremental proposal recommendation is driven by the fact that CESA (and likely the ISO as well) is unsure of the cumulative and combined impacts of the adopted Phase 1 proposals along with the proposed Phase 2 changes to increase study deposits and fees, increase site exclusivity deposits, modify the transmission plan deliverability (TPD) allocation groups and prioritization, enforce the generator interconnection agreement (GIA) termination period, and increase data transparency across different categories of information. Short of the ISO definitively affirming that the Phase 2 Draft Final Proposals can ensure that a “supercluster” in Queue Cluster (QC) 15 will not be repeated such that QC 16 does not begin in April 2025, CESA believes that the current proposal for higher study deposits and commercial readiness requirements and deposits (i.e., Section 4.1 proposals) will be excessive, deter market participants, and increase the costs of doing business, which will only be passed along into resource solicitations and resulting executed contracts. Again, as previously underscored, the goal of the IPE should not be to minimize the interconnection queue and reduce market competitiveness (i.e., a large queue is not a bad or undesired outcome in itself) but rather to manage the queue efficiently and screen out for truly speculative projects to better utilize limited ISO and utility time and resources. Even if the ISO can estimate that the Section 4.1 proposals would return the QC 15 to a “normal” cluster process and timeline, CESA maintains concerns about the excessiveness in raising the barriers to entry and has questions about whether the same goal could be achieved with the collection of other proposals adopted and considered in the IPE, combined with more incremental changes for the Section 4.1 proposals. At this time, there are too many questions about the cumulative impacts of the proposals, which have yet to take effect.
In previous comments to the Phase 2 Revised Straw Proposal, CESA supported alignment with the intent of the NOPR in a new initiative to tackle more comprehensive reforms to the interconnection process, but the current Phase 2 Draft Final Proposal only incorporates one element of the NOPR without other critical elements, namely the proposed rules intended to improve interconnection queue processing speed. Specifically, the NOPR proposes to impose firm deadlines and establish penalties if transmission providers fail to complete interconnection studies on time, except in instances where force majeure is applicable. In addition, the NOPR proposes to incorporate technological advancements into the interconnection process, such as using the operating assumptions for interconnection studies that reflect the proposed operation of an electric storage resource or co-located resource containing an electric storage resource, with certain exceptions. Altogether, the NOPR tackles interconnection reforms more comprehensively to address the “other side” of the issue, which is ensuring accountability on transmission providers’ timelines, but the current Phase 2 Draft Final Proposal places the burden and costs on interconnection customers (ICs) alone. Even then, the NOPR is still in draft form and has yet to receive comments. Stakeholders may very well propose completely different approaches, find certain elements problematic, and/or express how the proposed rules do not sufficiently address the issues. While appreciative of the ISO’s intent in developing a proposal that aligns more with the NOPR, CESA believes that there is too much uncertainty at this stage with the NOPR to transpose specific proposals into the IPE.
With the ISO aiming to finalize proposals and submit them to the Board of Governors by October 26, 2022, CESA is deeply concerned with the insufficient stakeholder process to review, shape, and refine the final proposals. Currently, the major shift and change in the Section 4.1 proposals have been surprising to our members, who struggle to measure and assess the impact to their pipeline of projects and their project development strategies. In some of their early calculations, the amount of at-risk capital would be disproportionately significant, regardless of the quality of the project. Considering that the ISO plans to move immediately to Final Proposal and draft tariff language by September 13, 2022 according to the ISO’s schedule, CESA believes that this type of significant change should not occur in the late stages of the stakeholder processes, where these comments represent the only opportunity to actually shape the proposals. The final stage is really about translating the stakeholder initiative’s proposals into tariff language, not an opportunity to shape the policy. Too many questions remain on the current Section 4.1 proposals at this stage of the process.
As such, CESA recommends that the Section 4.1 proposals be narrowed to incremental changes at this stage of the process, limited to the NOPR’s $/MW study deposit that could be incorporated in the Phase 2 Final Proposal. If some of the other Section 4.1 proposals inspired by the NOPR are desired, CESA believes that a follow-on Phase 3 of the IPE could be launched to allow for more deliberation on the merits and specifics of these proposals. With QC 15 not launching until April 2023, there may be enough time to focus on a narrow set of issues that could add onto the Phase 1 and 2 IPE proposals. Overall, CESA’s comments on the Phase 2 Draft Final Proposal can be summarized as follows:
- CESA supports the ISO’s proposed categories of project information to be made public to stakeholders but recommends that the other data categories, which were deemed to be too commercially sensitive at the individual project level, to be made available in aggregate form.
- The ISO should develop and publish heat maps showing available transmission capacity on a granular level to further advance data transparency, with further consideration of this proposal in either Phase 3 of the IPE or the Transmission Planning Process (TPP) Enhancements Initiative.
- Though CESA continues to believe that the ISO should not define minimum term lengths for qualifying power purchase agreements (PPAs), if the ISO is intent on doing so, CESA urges that the ISO return to the 3-year minimum contract term requirement to apply for Allocation Groups A and B and retain deliverability for Allocation Groups B and D – a reasonable balance of the ISO’s concerns.
- CESA generally believes that the ISO’s proposal for non-load-serving-entity (LSE) PPAs to receive a TPD allocation is reasonable in providing optionality for the demonstration requirement and in setting a one-year contract term requirement, but we request clarification on whether the qualifying PPA with the non-LSE procurement entities must be for the RA attributes.
- CESA supports the approval of higher study deposits based on MW size and tiers as a reasonable incremental change that is reasonably balanced for managing the overheated queue while not excessively deterring market participation:
- $70,000 plus $2,000/MW (maximum $230,000) for projects less than 80 MW
- $300,000 for projects 80 MW to less than 200 MW
- $500,000 for projects 200 MW or greater
- The ISO should remove the commercial readiness demonstration or deposit requirement as well as the proposal for withdrawal penalties.
- CESA supports the ISO’s reasonable proposal to exercise and enforce the ISO’s existing authorities and procedures (GIA Section 17.1.1, Generator Management BPM) in order to manage the interconnection queue and ensure projects are demonstrating development progress.
- The stakeholder-raised proposal to have transmission owners begin planning for upgrades once ICs give their notice to proceed (NTP) and give timelines for progress and completion should be taken up in the new TPP Enhancements Initiative.
- CESA requests that the ISO revisit and explore the merits of collapsing Group B and C projects in the same group, thus valuing shortlisted PPA projects on the same level as projects that have achieved commercial operations.
2.
Provide your organization’s comments on section 3.1 Transparency enhancements:
The ISO proposed to make the following project information public to stakeholders, likely through RIMS, similar to the existing Queue Report:? PTO study area and sub-area by cluster?; TPD allocation group and percentage allocation (or MW amount allocated) for the project; resource ID(s)?; status of suspension and parking (yes/no); and phase data (generation/fuel type, MW, hybrid or co-located designation, synchronization date, and commissioning or COD date).? CESA supports the ISO’s proposal in this regard, as it will advance greater transparency that could help ease the overheated queue by helping any given IC understand their prospects to succeed in the interconnection queue at their location and by reducing the prospects of “speculative” interconnection requests.
However, the ISO declined to make certain categories of project-specific data transparent and publicly available, including site exclusivity documentation and status?, project milestones?, construction status?, and Affected System status?. Whether due to ISO-specific concerns or opposition from stakeholders regarding the confidential and market-sensitive nature of this information, CESA believes that there may be alternative means to make this information available, which would support smart and rational decision-making by ICs in entering, proceeding through, or withdrawing from the queue, thereby addressing the ISO’s intent of better managing the overheated interconnection queue. If too commercially sensitive to provide information at an individual level, CESA recommends that the ISO provide these data categories in an aggregate form, perhaps by transmission planning or local areas. Already, in the previous Phase 1 Revised Straw Proposal, the ISO provided helpful site exclusivity information for the ISO system as a whole in making the case for site exclusivity as a pre-requisite to enter Phase II studies. If such information could be provided in aggregate form but at a more granular planning area level, it could be an important source of data transparency while protecting project-specific commercially-sensitive information.
Finally, CESA reiterates our call to make data more transparent in a user-friendly and accessible format. Specifically, CESA requests that the ISO develop and publish heat maps showing available transmission capacity, similar to what is currently done by the Alberta Electric System Operator (AESO) and what is done in the Wholesale Distribution Access Tariff (WDAT) sphere for latent deliverability. The ISO has consistently pushed back against such recommendations, citing how such information is already publicly available and how it is not a good use of their time and resources. However, to these points, CESA notes that the current transmission capability estimates do not capture locational granularity or projects already in the queue. Other pieces of basic but useful information, including around specific points of interconnection, have been difficult to identify and confirm, often requiring data requests to the ISO that is both inefficient and burdensome. Accessibility should be one of the goals in these data transparency efforts, where having developers track down and reconcile different pieces of information located in different places poses a significant administrative burden and leads to potential error in analyzing the collection of information. Whether in Phase 3 of the IPE or as part of the recently-launched TPP Enhancements Initiative, this proposal and concept should be further explored.
3.
Provide your organization’s comments on section 3.2 criteria for minimum term for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation:
In light of the NOPR, the ISO maintained its proposal that, beginning with the 2023-2024 TPD allocation cycle, any tariff deliverability requirement for a PPA will require a term of 5 or more years to be able to apply Allocation Groups A and B, including the retention requirements for Group B, and the retention requirements for Group D. At the same time, projects that received an allocation prior to the 2023-2024 TPD allocation cycle will not be subject to the new minimum term requirements at this time. Overall, this proposal would exceed what the ISO agreed to in Phase 1, where a qualifying minimum contract term was set at 3 years.
Without extensively repeating what CESA commented in response to the Phase 2 Revised Straw Proposal, 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 return to the 3-year minimum contract term requirement to apply for Allocation Groups A and B and retain deliverability for Allocation Groups B and D. If the goal is to support Resource Adequacy (RA) obligations through the structure of TPD allocation priority groups, the qualifying minimum contract term requirement should roughly align with the CPUC’s RA forward contracting requirements (i.e., based on a minimum contract length of one year for System RA and three years for Local RA). At the very least, a 3-year minimum contract term would align with the ISO’s past position in the Phase 1 Final Proposal and balance the need for prioritizing projects with sufficiently long off-take agreements in the interest of preserving limited ratepayer-funded transmission capacity for projects that address procurement needs over a reasonable period of time, rather than on an extremely short-term basis. Although the NOPR proposes a 5-year minimum term as part of the commercial readiness demonstration, FERC has yet to even receive comments, making the proposal potentially subject to change. As such, CESA recommends that the ISO modify this proposal to set a 3-year minimum contract term length.
Throughout the IPE Initiative, the ISO has also discussed how it does not see new-build resources being financed under short-term contracts and has not really seen merchant generation and storage entering the ISO’s market. Overall, CESA believes that there are reasonable cases where short-term contracts are rational risk mitigation measures in the face of regulatory uncertainty about RA resource counting rules, for example, which would deter signing a long-term contract until these rules become more certain, even as an LSE may find significant value and has the intent to sign a long-term contract. The regulatory environment continues to be in flux with the workstreams underway at the California Public Utilities Commission (CPUC) regarding slice-of-day reforms. Additionally, pathways for merchant projects should not be dismissed or foreclosed on because the ISO has not seen many of these projects in the queue or in operation today. At the end of the day, several companies view this as a viable development strategy to quickly and efficiently come to market, and merchant projects will ultimately need to sign a long-term RA contract to monetize the secured deliverability.
4.
Provide your organization’s comments on section 3.2 eligibility criteria for non-LSE PPAs to receive a Transmission Plan Deliverability (TPD) allocation:
For non-LSE procurement entities, the ISO proposed qualifying allocation and retention requirements for Groups A, B, and D, respectively, to demonstrate an underlying contract with an LSE with an RA obligation to sell the RA capacity on an at least 1-year term, or to submit a deposit in lieu of contract. CESA generally views no need to set the minimum contract term between LSE with RA obligation and non-LSE procurement entity since there is every incentive to “monetize” the value of the deliverable capacity and ensure that these projects show up on LSEs’ RA supply plans. Notwithstanding this broader point, CESA generally believes that the ISO’s proposal is reasonable in providing optionality for this demonstration requirement and setting a one-year contract term requirement.
However, CESA requests clarification on whether the qualifying PPA with the non-LSE procurement entities must be for the RA attributes, even as they meet the minimum term requirements (i.e., 5 years if the ISO’s current proposal is adopted, or 3 years if CESA’s recommended proposal is adopted). In certain instances, the PPA with the non-LSE procurement entity may be for all of the non-RA attributes (e.g., RECs) while the RA attributes with deliverability are available for LSEs as part of the proposed contracting requirement to entities with an RA obligation. In this case, CESA does not see issue with the intent of the ISO’s proposal, which is to ensure that the TPD allocation criteria prioritize allocating deliverability to projects that will show up on LSE supply plans.
5.
Provide your organization’s comments on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?
The ISO proposes a series of changes in line with the NOPR that would, among other things, allocate study costs on requested MW and number of interconnection requests (IRs) received in a given cluster, set higher $/MW and combine study deposits and tiers for Phases I and II, establish a regime of commercial readiness demonstrations and in-lieu deposits, and set withdrawal penalties depending on whether commercial readiness and/or site exclusivity requirements are met or in-lieu deposit for each is provided. Overall, CESA believes that the full collection of Section 4.1 proposals is premature since the NOPR is still in draft form and have not yet received comments. The ISO’s proposal is also punitive in putting excessive capital at risk, especially as very few or no projects would be able to meet the commercial readiness requirements, with the possible exception of offshore wind projects that are long lead time and may require contracting ahead of completing the full interconnection study process. As expressed earlier, CESA supports the idea of making sure that speculative projects are cleared out quickly, but we remain concerned that the current proposal as-is would only raise the cost of doing business. As such, CESA recommends that the ISO adopt a narrow set of these proposals.
First, regarding the combined study deposits for Phase I/II, CESA supports the adoption of a combined study deposit as proposed in the Phase 2 Draft Final Proposal:
- $70,000 plus $2,000/MW (maximum $230,000) for projects less than 80 MW
- $300,000 for projects 80 MW to less than 200 MW
- $500,000 for projects 200 MW or greater
This proposal is reasonable and aligns with the thresholds set in the NOPR, though the base and MW multiplier rate is double that proposed by FERC. This proposal is also grounded in support from multiple stakeholders, including CESA, who suggested that a $/MW structure would represent a means to reduce the queue, reasonably and incrementally increase the bar to entry, and support greater resourcing and infrastructure to handle the volume of interconnection applications. Notwithstanding the ISO previously expressing that the study time and costs do not scale with the MW of projects (i.e., 20 MW project equals 100 MW project in terms of study time and costs), this proposal is superior to the ISO’s proposal to impose escalating fees and deposits based on multiple interconnection applications by a single developer, which may only 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. This proposal would also, on the most part, raise the bar to market entry from the current MW-agnostic $150,000 deposit, thereby facilitating the ISO’s goal of reducing the interconnection queue volume and incentivizing developers to more strategically focus on a narrower set of potential projects since very few companies have the ability to provide upfront the significant amount of capital to submit a large multitude of IRs.
Second, regarding the commercial readiness requirements, CESA opposes this proposal and recommends that they be removed from the Phase 2 Draft Final Proposal. While FERC proposed such a structure in the NOPR, it still has not received feedback in the form of comments. These requirements also represent an impossible standard in California since LSEs are unlikely or would never execute a binding term sheet, let alone one of at least five years, for a project without Phase I study results or within 30 days following the Phase I study results meeting. Recognizing that Phase I study results are still indicative and not final, it is still the minimum necessary to begin marketing the project to LSEs in their resource solicitations, though most projects are most competitive in solicitations upon completion of Phase II studies. Further, LSEs are unlikely to execute PPAs or other contracts with commercial online dates five years out into the future. In this regard, this aspect of the NOPR is more apt for vertically-integrated utilities centrally manage their planning processes and new resource procurement, not for a California where such processes are decentralized and mostly just coordinated and validated at the state level at the California Public Utilities Commission (CPUC). With the exception of certain special-interest resources such as offshore wind, almost all other IRs would therefore not be able to meet the commercial readiness requirements and would face the high multipliers for withdrawal penalties.
CESA also finds the commercial readiness requirement to be problematic because it provides no way for projects to meet this requirement through a merchant development strategy, making such a path potentially prohibitively expensive even though it represents a reasonable and possible means to bring online capacity quickly. While operating as a merchant facility initially, they are strongly incentivized to market their resource to LSEs in solicitations to monetize key revenue streams, namely RA. Without this path and given the significant multipliers for projects that do not meet the commercial readiness requirement, the ISO would be forcing all projects to work with LSEs first. Based on the state’s recent history of sudden and short lead-time procurement and more volatile and higher weather and load forecasts, merchant generation and storage facilities can play a key role in preparedness for needs that emerge beyond the foresight of any LSE in their normal planning and procurement processes.
Third, regarding withdrawal penalties, CESA is also opposed to the adoption of withdrawal penalties, which are unnecessary given the withdrawal penalties already in place associated with the initial financial security (IFS) posted after Phase I and Phase II studies. These existing withdrawal penalties in place already ensure that ICs have “skin in the game” and incentivize ICs to remain in the queue, particularly after Phase I studies. Consistent with our position on the commercial readiness requirements and in-lieu deposits, CESA believes that withdrawal penalties at stages before and immediately after Phase I studies pose unreasonable at-risk security amounts even though Phase I studies and results are indicative, yet for those who are ready to move forward based on the indicative information on the Phase I results, they already have incentives to continue through the queue process upon making an IFS posting.
By contrast, the structure for commercial readiness requirements, if maintained, would represent excessively high amounts of capital at risk that would deter market participation. The largest projects, greater than 200 MW, could have over $2 million held in deposit and at risk, assuming cases where a project does not have site exclusivity or commercial readiness demonstration. While developers assume a certain amount of lost money in the study process, these amounts are likely excessive and will drastically impact and reduce market participation, while potentially increasing overall ratepayer costs as some of these development risks and costs are passed on. While CESA strongly opposes the commercial readiness requirements, if the ISO is intent on doing so, CESA believes that the commercial readiness requirements and in-lieu deposits must only be applicable later in the interconnection process. For example, this could occur in the Phase II study process, or upon execution of GIAs. Yet even then, the proposal would be incomplete because it does not incorporate timelines and penalties for transmission providers to adhere to timelines, as proposed in the NOPR. Delays could occur as part of the transmission providers’ interconnection or upgrade construction process and timelines, with ICs not at fault for these delays, resulting in ICs facing significant amounts of their deposits at-risk.
Finally, CESA requests that the ISO clarify whether the study deposits must be provided in cash or could be provided via other means, such as letter of credit collateral. Given the high deposit requirements, a cash-only option would have significant impact on company’s cash flows.
6.
Provide your organization’s comments 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 comments at this time.
7.
Provide your organization’s comments on section 5.2 Policy for ISO as an Affected System – how is the base case determined and how are the required upgrades paid for?
CESA has no comments at this time.
8.
Provide your organization’s comments 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 the ISO to invoke the GIA default clause (Section 17.1.1) if the IC does not submit status reports and leverage Section 6.5.2.1 of the Generator Management Business Practice Manual (BPM) for terminating Energy Only (EO) projects unless the project is making progress to COD or would mitigate their impacts to short-circuit duty. As previously expressed, CESA believes that this is a reasonable proposal to exercise and enforce the ISO’s existing authorities and procedures in order to manage the interconnection queue. CESA also appreciates the ISO’s clarifications that, among other things, would assess on a case-by-case basis on whether projects are meeting their milestones. Such nuanced approaches will guard against unintended outcomes and still achieve the overarching intent of the ISO’s proposal to enforce and ensure projects are demonstrating development progress.
9.
Please provide additional comments on the IPE – Phase 2 Draft Final Proposal not mentioned above:
In the Draft Final Proposal, the ISO removed the stakeholder-raised proposal to have transmission owners begin planning for upgrades once ICs give their NTP and give timelines for progress and completion. In past stakeholder calls, the ISO mentioned how such proposals are unnecessary with the quarterly Transmission Development Forum (TDF) in place. However, CESA has found the TDF to be ill-suited for this purpose since discussion of project-specific questions were identified as inappropriate for the TDF. Instead of deferring this issue to the TDF or addressing them in the IPE, CESA recommends that this issue be taken up in the new TPP Enhancements Initiative. Having such a proposal in place will inform procurement and project development activities, as well as ensure accountability on the construction of network upgrades.
In addition to the aforementioned stakeholder-raised proposal, CESA also requests that the ISO potentially revisit one of the IPE Phase 1 proposals in structuring the TPD allocation groups. Specifically, CESA wishes to explore with the ISO the merits of collapsing Group B and C projects in the same group, thus valuing shortlisted PPA projects on the same level as projects that have achieved commercial operations. Even though the ISO has concerns and doubts about merchant generation and storage projects, CESA continues to believe that the ISO should not create disincentives for projects to even attempt to move forward without a PPA and come online efficiently and quickly, especially in light of the reliability concerns and risks expressed by the state’s agencies for the 2024-2026 period. Contrary to the ISO’s statements on this matter, projects following this development path have played a role in supporting near-term reliability needs, such as in response to the Aliso Canyon emergency or for 2021-2023 system reliability needs. In other instances, a large project with a PPA and deliverability may seek to expand its capacity, which could come online quickly since construction of the expansion phase may occur on a quicker timeline than the procurement and contracting process.
Ultimately, having a PPA as the ultimate sign of commercial readiness is narrow; there is no better way of showing viability, commitment, and commercial readiness than a project that has come online. When comparing a shortlisted project versus a project that is online, it does not seem logical for the former to be favored over the latter when the latter could immediately support the LSEs’ near-term needs. By leveling the priority for Group B and C projects, the ISO may also see more projects come online, signaling to developers the higher probability of securing deliverability and eventually securing an off-take contract.
CESA understands that raising this issue at this time may frustrate the ISO staff and its stakeholder process, considering the Phase 1 proposals have been adopted by the ISO Board and submitted to FERC as tariff amendments, with a FERC Order coming by September 1, 2022. Generally, CESA does not wish to “relitigate” issues and aims to be a good-faith stakeholder through the ISO’s process; to this end, we acknowledge that this perspective and proposal should have been shared in Phase 1. However, with the ISO and CPUC crunched for additional capacity resources to address near- and mid-term reliability challenges and mitigate risks associated with supply chain delays and extreme weather events, CESA seeks to narrowly revisit the proposal around TPD allocation groups. Moreover, CESA has learned more about the appetite and feasibility of this development strategy and path from members over the past several months. As such, if possible, CESA requests that the ISO potentially address this issue in a Phase 3 of this initiative.
California Public Utilities Commission - Public Advocates Office
Submitted 08/16/2022, 04:58 pm
1.
Please provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) – Phase 2 draft final proposal:
The Public Advocates Office at the California Public Utilities Commission (Cal Advocates) is the state-appointed independent consumer advocate at the California Public Utilities Commission (CPUC). Our goal is to ensure that all Californians have affordable, safe, and reliable utility services while advancing the state’s environmental goals. Our advocacy efforts to protect California customers span the areas of energy, water, and communications regulation.[1]
Cal Advocates strongly supports the CAISO’s efforts, through the Interconnection Process Enhancements (IPE) 2021 Initiative and draft final proposal, to proactively address generation interconnection issues. The CAISO’s ongoing commitment to improve its Generator Interconnection processes is critical given the urgency of the climate crisis and California’s efforts to both maintain reliability and transition its energy sector to zero-carbon resources. The Commission has emphasized that accomplishing these goals will require careful monitoring of generation interconnection activities, timely analysis of resource interconnection bottlenecks, and identification of improvements in workflow.[2] The CAISO’s Phase 2 Interconnection Process Enhancements draft final proposal makes incremental improvements in each of these areas.
As is discussed in greater detail below, Cal Advocates generally supports the draft final proposal and specifically:
- Section 3.1: Transparency enhancements;
- Section 3.2: Criteria for minimum term for Purchase Power Agreements (PPAs) to be eligible for a Transmission Plan Deliverability (TPD) allocation;
- Section 3.2: Eligibility criteria for non-Load Serving Entities (non-LSEs) PPAs to receive a Transmission Plan Deliverability (TPD) allocation;
- Section 4.1: Fees, deposits, or other criteria required for submitting an Interconnection Request;
- Section 5.1: Alternative cost allocation treatment for network upgrades to local (below 200 kilovolt (kV)) systems:
- Section 5.2: CAISO as an Affected System;[3]
- Section 5.3: Tariff allowance that provides project seven years to achieve Commercial Operation Date (COD).
With 605 active interconnection requests totaling 236,225 MWs currently in the CAISO Interconnection Queue,[4] Cal Advocates is concerned that the draft final proposal reforms alone, will not be enough to reduce the CAISO Queue to a sustainable level. During the previous application window, CAISO was overwhelmed with 373 interconnection requests in the CAISO Interconnection Queue Cluster Study 14, so much so, that CAISO suspended new applications for two years. Cal Advocates opposes future moratoriums on interconnection request applications as it only masks the extent of the problem and it’s also an ineffective way to prioritize interconnections and address California’s reliability and energy goals. By allowing all eligible interconnection requests to be submitted without restrictions, CAISO and stakeholders can better understand the magnitude of demand for interconnection requests. This will enable the development of a strategy to process and prioritize those requests and more efficiently achieve California’s transition to zero-carbon resources.
Given the severity of the problem, Cal Advocates urges CAISO to take additional steps beyond those included in the draft final proposal. Our recommendations, which are detailed below, include support for CAISO’s plan to be more assertive in implementing its Business Practice Manual (BPM) for Generator Management, Section 6.5.2.1. Cal Advocates also supports the CAISO requiring Interconnecting Customers (ICs) to report the status of their projects and if the IC does not respond, then CAISO could invoke the default clause in the Generation Interconnection Agreement (GIA).
Cal Advocates also recommends that CAISO consider additional reforms for inclusion in the draft final proposal or queue process improvements. Specifically CAISO should:
- Along with Participating Transmission Owners, assign additional staff to address the Queue review process and execution of interconnection agreements;
- Develop a public dashboard of queue management performance metrics for decision makers and stakeholders;
- Require Transmission Owners to identify and implement improvements to facilitate approved generation interconnection construction and required network upgrades;
- Change the queue priority from First In/First Out to First Ready/First Serve(Readiness demonstrated by site control and financial milestones);[5]
- Qualify a list of third-party experts to perform study efforts;
- Require developers to perform their own self-study using a qualified third-party entity for local network upgrades;
- Expedite interconnection agreements if no local or system network upgrades are required;
- Provide Transmission Capacity Availability maps, including stoplight coding (e.g., red, yellow, green) transmission lines to reflect the relative costs to interconnect at various locations on the transmission system.
[1] Pub. Util. Code Section 309.5.
[2] California Public Utilities Commission Decision D.21-06-035 in CPUC Rulemaking R.20-05-003 Order Instituting Rulemaking to Continue Electric Integrated Resource Planning and Related Procurement Processes.
[3] A new generation resource in another Balancing Area Authority can request delivery to an LSE inside the CAISO and that the resource may affect the CAISO system reliability. The current CAISO policy is to provide any reliability network upgrades as an Affected System.
[4] CASIO Interconnection Queue https://rimspub.caiso.com/
[5] included in PJM Interconnection Process Reform
2.
Provide your organization’s comments on section 3.1 Transparency enhancements:
The CAISO proposes to make project information public to allow stakeholders to make informed decisions regarding project development. The data fields proposed to be published by the CAISO include participating transmission owner (PTO) study area and sub-area by cluster, transmission plan deliverability (TPD) allocation group and percentage allocation, resources ID(s), status of suspension, and various phase data. [1]
Cal Advocates supports CAISO’s proposal to enhance the transparency of a amount of generator interconnection data and that the data be made available to the public so that developers can make better decisions on proposed projects that are entering the cluster submission and study processes. Cal Advocates supports the CAISO’s intent to put the new reports on its public Resource Interconnection Management System (RIMS) portal so that stakeholders can access the data at any time.
[1] CAISO, Interconnection Process Enhancements 2021 Phase 2: Longer Term Enhancements, Draft Final Proposal. Pg 10.
3.
Provide your organization’s comments on section 3.2 criteria for minimum term for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation:
Cal Advocates supports, beginning with the 2023-2024 Transmission Plan Deliverability (TPD) allocation cycle, the CAISO proposal to require that the generator, in any tariff deliverability requirement for a Purchase Power Agreement (PPA), will deliver energy and capacity for a term of five or more years. Currently, the CAISO does not require a minimum PPA term for projects seeking TPD allocation. This proposed requirement will help to appropriately prioritize projects that are most likely to reach completion and deliver benefits to ratepayers as the highest priority in the TPD allocation process. [1] This proposal also aligns with the current CAISO Tariff where any investment by an Interconnection Customer in a CAISO system network upgrade will be eligible for reimbursement over a five-year period.[21]
[1] CAISO, Interconnection Process Enhancements 2021 Phase 2: Longer Term Enhancements, Draft Final Proposal. Pg 12.
[2] CAISO Tariff, Appendix BB, Section 11.4.1
4.
Provide your organization’s comments on section 3.2 eligibility criteria for non-LSE PPAs to receive a Transmission Plan Deliverability (TPD) allocation:
Cal Advocates supports the CAISO proposal to require that, beginning with the 2023-2024 Transmission Plan Deliverability (TPD) allocation cycle, any tariff deliverability requirement for a non-Load Serving Entity (non-LSE) Purchase Power Agreement (PPA) will include that the generator must deliver energy and capacity for a term of five or more years. Currently, there is no minimum PPA term for projects seeking TPD allocation. This requirement will help to appropriately prioritize projects that are most likely to reach completion. [1] This proposal also aligns with the current CAISO Tariff where any investment by an Interconnection Customer in a CAISO system network upgrade will be eligible for reimbursement over a five-year period.[2]
[1] CAISO, Interconnection Process Enhancements 2021 Phase 2: Longer Term Enhancements, Draft Final Proposal. Pg 12.
[2] CAISO Tariff, Appendix BB, Section 11.4.1
5.
Provide your organization’s comments on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?
The CAISO final draft proposal seeks to manage the interconnection queue by raising the bar for entry into the interconnection process, which will encourage developers to submit well-developed interconnection requests. The final draft proposal incorporates several of the FERC Notice of Proposed Rulemaking (NOPR) Generator Interconnection Procedures and Agreements [1] proposals including:
- Revised allocation of study costs;
- Study deposits based on project MW size;
- Demonstration of commercial readiness, or in lieu deposit; and
- Withdrawal penalties that increase as the Interconnection Customer moves through the study process.
The CAISO Final draft proposal increases the required study deposit amounts for both Phase 1 and Phase 2 studies as follows:
- Projects < 80MWs = $70k + 2k/MW (Max would be $230k)
- Projects 80 MW to <200 MW = $300k
- Projects 200 MW and greater = $500k
The CAISO is also proposing that all Interconnection Customers demonstrate project commercial readiness in order to enter into a Phase 1 study or a Phase 2 cluster study or pay a deposit in lieu of commercial readiness. The Phase 1 study deposit in lieu of commercial readiness is equal to the study deposit required to enter into a Phase 1 study. The Phase 2 study deposit in lieu of commercial readiness is equal to 3.5 times the study deposit required to enter into a Phase 2 study. These deposits would be in addition to any required study and site exclusivity deposit requirements.
Cal Advocates supports these revisions as they are consistent with the FERC NOPR reforms. With these changes, the CAISO Final draft proposal should be able to effectively manage the overheated queue by raising the bar for entry into the interconnection process will discourage numerous and excessive interconnection request submissions by a single developer.
[1] FERC Notice of Proposed Rulemaking - Generator Interconnection Procedures and Agreements: – Docket No. RM22-014-000, June 16, 2022
7.
Provide your organization’s comments on section 5.2 Policy for ISO as an Affected System – how is the base case determined and how are the required upgrades paid for?
In the CAISO Final draft proposal the CAISO states that in the last decade, there have been virtually no instances where a generator’s interconnection to a neighboring balancing area authority would affect the reliability of the CAISO grid. In interconnection terms, the CAISO is almost never an “affected system.” However, recently, the CAISO reports that it has received a few notices from neighboring Balancing Area Authorities (BAAs) that a proposed interconnection may affect the reliability of the CAISO grid, and therefore warrants study. Current CAISO policy does not specify how any network upgrades required to mitigate reliability impacts would be reimbursed.
Currently, it is the CAISO policy to designate any CAISO system upgrades that are determined to be required due to a new supply resources located in another BAA as a Reliability Network Upgrade as part of the Transmission Planning Process.[1]
Cal Advocates supports the CAISO draft proposal to make no changes to the CAISO policy on treatment of an Affected System as it likely will not adversely impact transmission ratepayers.
[1] All Reliability Network Upgrade projects approved in the TPP are paid for through the Transmission Participating Owner FERC filed Transmission Access Charge (TAC).
8.
Provide your organization’s comments 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?
Current CAISO policy allows an Interconnection Customer to keep a project in the queue for seven years. In the CAISO IPE 2021 – Phase 2 June 7, 2022 Revised Straw Proposal, the CAISO considered a reform that if an energy-only project cannot prove that it is moving forward in permitting and construction, then the CAISO could terminate the interconnection project.
In the Draft Final proposal, CAISO withdrew this proposal, favoring instead, a more modest clarification that the CAISO would more strictly implement BPM for Generator Management, Section 6.5.2.1, or Section 17 of the LGIA and Article 7.6 of the SGIA, which takes into account project specific issues and circumstances.
Cal Advocates recommends the CAISO be more assertive in implementing its Business Practice Manual (BPM) for Generator Management, Section 6.5.2.1 that requires projects to demonstrate engineering, permitting, or construction status.
Given the urgency of dealing with resource interconnection bottlenecks and managing an ever growing interconnection queue, Cal Advocates recommends the CAISO take the additional step of requiring ICs to report on an annual basis, the detailed status of its project(s), demonstrate specific issues with engineering, permitting, or construction and, if the IC does not respond, then the CAISO could invoke the default clause in the Generation Interconnection Agreement (GIA), Section 17 in the Large Generation Interconnection Agreement (LGIA) and Article 7.6 of the Small Generation Interconnection Agreement (SGIA).
9.
Please provide additional comments on the IPE – Phase 2 Draft Final Proposal not mentioned above:
Given the severity and magnitude of the interconnection queue problems, Cal Advocates urges CAISO to go beyond the reforms included in the Draft Final proposal. CAISO should look for best practices being implemented in other regional transmission organizations and reforms being considered in the FERC NOPR on Interconnection Improvements. To this effect, Cal Advocates recommends the CAISO consider the following reforms in the Draft Final proposal or queue process improvements:
- Have the CAISO and Participating Transmission Owners add and train additional staff to address the Queue review process and execution of interconnection agreements;
- Develop a dashboard of queue management performance metrics for decision makers and stakeholders;
- Require Transmission Owners to identify and implement improvements to facilitate approved generation interconnection construction and required network upgrades;
- Change the queue priority from First In/First Out to First Ready/First Serve(Readiness demonstrated by site control and financial milestones);[1]
- Qualify a list of third-party experts to perform study efforts;
- Require developers to perform their own self-study using a qualified third-party entity for local network upgrades;
- Expedite interconnection agreements if no local or system network upgrades are required;
- Provide Transmission Capacity Availability maps, including stoplight coding (e.g., red, yellow, green) transmission lines to reflect the relative costs to interconnect at various locations on the transmission system.[2]
[1] included in PJM Interconnection Process Reform
[2] Conceptual Transmission Capacity Availability maps coding:
red: system level upgrades needed for connecting new generation resource to support full capability deliverability status (FCDS)
yellow: minor local upgrades needed for connecting new generation resource up to the yellow capacity addition designation. (e.g. upgrades to local circuit breakers or increased transformer capacity.)
green: no local upgrades needed for connecting new generation resource up to the green capacity addition designation
EDF-Renewables
Submitted 08/16/2022, 03:58 pm
Submitted on behalf of
EDF-Renewables
1.
Please provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) – Phase 2 draft final proposal:
EDF-R appreciates how challenging it is for the CAISO to change complex interconnection processes and consider those changes in the context of an FERC Notice of Proposed Rulemaking (NOPR), and that the CAISO is eager to push through reforms in time to address supercluster drivers in time for Cluster 15. The CAISO’s interconnection procedures have a major impact on the California development environment, and proposed changes require robust and thorough discussion of their merits and potential impacts. FERC’s rulemaking is proposed, not final, and CAISO should not seek to presuppose the contents of the final ruling with these IPE tariff charges. CAISO’s draft final proposal has proposed major changes from the revised straw proposal. CAISO's proposals presuppose the outcome of the FERC Notice of Proposed Rulemaking (NOPR) and are not compatible with CAISO’s unique interconnection and deliverability procedures as well as the proposals in this IPE initiative. Overall EDF-R regards CAISO’s draft final proposal not yet ripe. EDF-R strongly opposes CAISO’s proposal to adopt Draft FERC NOPR language on commercial readiness. The NOPR language is not appropriate for CAISO’s process as written, and the NOPR is sure to go through many changes over the next year or more, and then FERC’s final ruling will allow for some amount of compliance time. If we look to FERC Order 2003 as an example, CAISO may not need to file compliance for the current NOPR until August 2024.[1] This leaves ample time to develop a proposal appropriately matched to California’s reality.
EDF-R sees the following issues as solvable and is committed to continuing robust conversations with the CAISO in the spirit of creating the best possible policy outcomes. Detailed in comments below EDF-R believes the following issues need to be addressed prior to a final proposal:
- There are so many proposals for new deposit structures and deposits in lieu that it is difficult to understand exactly how much capital could be at risk at what milestones on the CAISO’s study process timeline
- Proposal needs additional detail on 5-year PPA requirements.
- Proposal needs additional details on treatment of legacy projects
- Proposal should describe if PPA requirements would apply to Commercial Viability checks or COD extension
- Proposal is inequitable as it creates large new financial risks for cluster 15 while offering no improvements to information available to buyers and sellers (such as improved interconnection queue visiblity)
EDF-R requests the CAISO drop commercial readiness and withdrawl penalties intended for compliance with FERC NOPR compliance from this paper. EDF-R requests CAISO publish, present, and accept comments on a revised draft final proposal before publishing its final proposal. If, for whatever reason, the CAISO cannot push the Board review of the proposal to December, EDF-R suggests an accelerated schedule:
- Sep 6, 2022 Revised draft final proposal published
- Sep 13, 2022 Meeting
- Sep 20, 2022 Comments due
- Oct 04, 2022 Final proposal published
- Oct 14, 2022 Comments due
- Oct 26, 2022 Board of Governors meeting
Finally,EDF-R is concerned about the CAISO’s posture that they are not committed to “conduct[ing] a stakeholder initiative to comply with any final rule FERC issues. The ISO generally does not do so because it can only make tariff revisions consistent with the final rule, and no other” as communicated in footnote 10 of the draft final proposal. EDF-R contends that a transparent discussion of any compliance proposal before it goes to the CAISO’s board for approval is prudent and consistent with many other historical compliance efforts. EDF-R believes a public discussion for CAISO’s future FERC Interconnection NOPR compliance proposal is appropriate.
[1] FERC issued the RM02-1-000 NOPR on October 25, 2001. FERC issued order 2003 on July 24, 2003 and required compliance with the order by January 20, 2004. Total time was 2 years, 2 months.
2.
Provide your organization’s comments on section 3.1 Transparency enhancements:
EDF-R strongly supports CAISO’s proposed transparency additions and appreciates that CAISO will seek to integrate the data into the RIMS system where possible. EDF-R requests CAISO rush publishing of this data. The CAISO's IPE proposal is currently inequitable, as it creates large new financial risks for cluster 15 while offering no improvements to information available to buyers and sellers, such as improved interconnection queue visiblity.
3.
Provide your organization’s comments on section 3.2 criteria for minimum term for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation:
EDF-R very much appreciates CAISO’s summarizing stakeholder responses in a matrix format, this format is very clear compared to discussion in a written narrative. Please continue this format in the future. However, EDF-R echoes stakeholder concerns from the web conference that the idea that using the CAISO’s response matrix as a democratic tool for calculating results as “votes” is misguided. The debate over how to weight each “vote” and who was eligible to “vote” in this decision could actually be an endless one and is not likely to produce the best policy result. EDF-R is concerned that the CAISO has proposed a five-year PPA term, which is a significant commitment for both RA buyers and RA sellers, while also proposing (in section 4.1) that projects should have an executed term sheet or being on a PPA shortlist[1] before entering into Phase I. CAISO’s proposal to mandate 5-year PPA terms is incompatible with CAISO’s proposal for Phase I commercial readiness. With this proposal CAISO has communicated in its policy that they believe buyers and sellers have sufficient information to complete project evaluations sufficient to justify term sheets and shortlists before the CAISO has issues any study results. EDF-R disagrees.
Buyers and sellers need Phase I study results to start meaningful negotiations, and TPD allocation is a critical component to finalizing these items. Likely CAISO’s own data proves this to be true, given how few projects seeked TPD allocation under Group 1.
CAISO should drop the Commercial Readiness item from this proposal.
CAISO’s proposal needs additional clarity:
- CAISO discussion does not specify which PPA demonstrations these requirements apply to. Do these requirements extend through to TPD allocation for group A? TPD retention? COD extension? And Commercial viability reviews? Or some subset?
- Section 3.2 of the draft final proposal states that “Projects that received an allocation prior to the 2023-2024 TPD allocation cycle will not be subject to the new minimum term requirements at this time.” but on the stakeholder call there was some uncertainty on that topic as well as PPAs for COD extension and viability compliance. EDF-R requests clarity on this issue
[1] This is EDF-R’s interpretation of the specific language CAISO’s provided in the paper, which is “Reasonable evidence that the project has been selected in a resource plan or resource solicitation process by or for a load serving entity is being developed by an LSE, or is being developed for purposes of a sale to a commercial, industrial, or other large end-use customer.”
4.
Provide your organization’s comments on section 3.2 eligibility criteria for non-LSE PPAs to receive a Transmission Plan Deliverability (TPD) allocation:
EDF-R supports the idea that non-LSE PPAs should be eligible for TPD allocation. EDF-R commends the CAISO for moving forward with a proposal to support that framework. This demonstrates flexible and future-oriented thinking by CAISO staff. The reality is that commercial development strategies are changing. EDF-R is committed to continuing robust conversations with the CAISO in the spirit of creating the best possible policy outcomes.
With that said, EDF-R has the following concerns about the current proposal:
-
EDF-R is concerned that CAISO views its proposal for minimum deposit of $500,000 “a starting point for discussion” as stated during the stakeholder web conference and requests CAISO clarify the logic and empirical justification for the $500k as opposed to only the $10k per MW equation
-
In the context of the CAISO’s current proposal, could projects provide multiple deposits to move though the TPD allocation process? Could they provide $500K for Option D retention, then $500k for Option B retention, then $500k for Option A retention? in total a $1.5 m deposit? If yes, is the whole $1.5 m refundable on the presentation of the PPA? Or is each preceding deposit forfeit with the provision of the new deposit? Currently the CAISO proposal reads “Deposits in-lieu of RA contracts will be held by the ISO and refunded to the entity providing the deposit after a demonstration of a contract to sell the RA capacity”
Given the unanswered process questions EDF-R requests publish, present, and accept comments on a revised draft final proposal before publishing a final proposal for Board review.
5.
Provide your organization’s comments on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?
EDF-R strongly opposes the CAISO moving forward with this proposal. The proposal is not mature, not appropriate for CAISO’s unique interconnection and deliverability procedures, and the proposal is not consistent with CAISO’s other proposal in this IPE initiative.
EDF-R strongly opposes CAISO’s proposal to adopt draft FERC NOPR language on commercial readiness or withdrawal penalties for the sake of process efficiency at the FERC. The NOPR language is not appropriate for CAISO’s process as written, and the NOPR is sure to go through many changes over the next year or more, and then FERC’s final ruling will allow for some amount of compliance time. CAISO’s effort to comply with the FERC order is premature. If we look to FERC Order 2003 as an example, CAISO may not need to file compliance for the current NOPR until August 2024. This leaves ample time to develop a proposal appropriately matched to California’s reality. EDF-R requests CAISO drop commercial readiness and withdrawal penalties from the proposal.
EDF-R is also concerned about the CAISO’s posture that they are not committed to “conduct[ing] a stakeholder initiative to comply with any final rule FERC issues. The ISO generally does not do so because it can only make tariff revisions consistent with the final rule, and no other” as communicated in footnote 10 of the draft final proposal. There may be many ways to comply with a FERC order, and a transparent discussion of any compliance proposal before it goes to the CAISO’s board for approval is prudent. CAISO does have stakeholder discussions for compliance efforts when appropriate as demonstrated by FERC Order 831, FERC Order 1000, FERC Order 764, and many other efforts. EDF-R believes a public discussion for CAISO’s future FERC Interconnection NOPR compliance proposal is appropriate.
CAISO has proposed refinements that target supercluster drivers that have gone through thorough policy development rounds with stakeholders. In IPE Phase 1 CAISO proposes requiring projects to demonstrate site exclusivity earlier and increasing the site exclusivity deposits and non-refundable portions, which CAISO states would have prevented the majority of Cluster 14 projects from moving into Phase II if the requirement had been in place.
Study Deposits and Cost Allocation Proposal
EDF-R performed its own brief assessment of the CAISO’s proposal using mock cost data and, as a result, is concerned that the proposal may not be logical or equitable. Here is an example where, if total study cost increases, final cost allocation varies significantly. This example also suggested that the $300,000 deposit structure may not be appropriate compared to the other two deposit structures.
|
|
|
|
Study cost is $500k
|
Study cost is $1m
|
|
Project MW
|
Deposit
|
Per Capita Costs Applied
|
Pro Rata Costs Applied
|
Costs refunded to project
|
% of costs refunded
|
Pro Rata Costs Applied
|
Costs refunded to project
|
% of costs refunded
|
|
10
|
$ 90,000.00
|
$ 50,000.00
|
$ 2,571.43
|
$ 37,428.57
|
42%
|
$ 5,142.86
|
$ 34,857.14
|
39%
|
|
20
|
$ 110,000.00
|
$ 50,000.00
|
$ 5,142.86
|
$ 54,857.14
|
50%
|
$ 10,285.71
|
$ 49,714.29
|
45%
|
|
20
|
$ 110,000.00
|
$ 50,000.00
|
$ 5,142.86
|
$ 54,857.14
|
50%
|
$ 10,285.71
|
$ 49,714.29
|
45%
|
|
100
|
$ 300,000.00
|
$ 50,000.00
|
$ 25,714.29
|
$ 224,285.71
|
75%
|
$ 51,428.57
|
$ 198,571.43
|
66%
|
|
150
|
$ 300,000.00
|
$ 50,000.00
|
$ 38,571.43
|
$ 211,428.57
|
70%
|
$ 77,142.86
|
$ 172,857.14
|
58%
|
|
450
|
$ 300,000.00
|
$ 50,000.00
|
$ 115,714.29
|
$ 134,285.71
|
45%
|
$ 231,428.57
|
$ 18,571.43
|
6%
|
|
1000
|
$ 500,000.00
|
$ 50,000.00
|
$ 257,142.86
|
$ 192,857.14
|
39%
|
$ 514,285.71
|
$ (64,285.71)
|
-13%
|
We can only draw questions from mock data, not answers, and so EDF-R requests that the CAISO run a lookback on financial data form cluster 12 to identify what the study outcomes would have been using this methodology. The examples indicate the deposit levels are not right-sized and need more granularity. EDF-R has attached an excel spreadsheet with sample equations.
Commercial Readiness and Withdrawal Penalties Proposal
EDF-R is concerned that the CAISO’s proposal is a literal copy-and-paste of FERC’s NOPR language. The FERC NOPR language is not finalized, and is not compatible with CAISO’s unique interconnection and deliverability procedures, nor aligned with CAISO’s IPE proposal.
Most critical for address is the CAISO’s proposal that to enter Phase I of the study projects should have an executed term sheet or being on a PPA shortlist.4 So, with this draft final proposal CAISO is effectively communicating that they believe RA buyers and RA sellers have enough information to complete project evaluations sufficient to justify term sheets and shortlists before the CAISO issues any study results. EDF-R disagrees. Buyers and sellers need at least Phase I study results to complete meaningful negotiation milestones. CAISO cannot expect other parties to contract before CAISO has provided any meaningful feedback.
In previous comments EDF-R has suggested that prior to Phase I CAISO could and should publish a brief report comparing the makeup of new queue cluster to regional curtailments, known transmission constraints, a DC screening analysis, and known deliverability availability. CAISO acknowledged in its transparency review that though that information may be available in TPP reports, or on the transmission portal it is hard to navigate. EDF-R does not promise support if this approach is adopted, but provides this as an example of the kind of stakeholder discussion that needs to occur before proceeding to a final proposal.
Regarding the commercial readiness deposits and withdrawal penalties, there are proposals for new deposit structures, withdrawal penalties, and deposits in lieu this IPE initiative and it is difficult to understand, on a holistic level, exactly how much capital could be at risk when submitting an interconnection request. EDF-R requests CAISO provide a comprehensive list that outlines each time a deposit could be required if all proposals in IPE Phase 1 and IPE Phase 2 were adopted. EDF-R withholds opinion on this portion of the proposal absent clarification. EDF-R also requests clarification on if withdrawal penalties are a replacement for financial security postings or on top of those postings.
EDF-R requests CAISO clarify how they will collect withdrawal penalties – with a bill due upon withdraw? Against financial security postings? By asking interconnection customers to provide yet another deposit?
In the paper CAISO says, “Withdrawal penalties will increase as the IC moves through the study process and will also increase if a commercial readiness and/or a site exclusivity deposit has been provided in lieu of demonstration of commercial readiness and/or site exclusivity.” (Emphasis ours.) This appears incompatible and punitive in conjunction with CAISO’s IPE Phase I proposal on site exclusivity. Given the unanswered process questions EDF-R requests provide cohesive description of how these proposals interact and publish, present, and accept comments on a revised draft final proposal before publishing a final proposal for Board review.
Finally, EDF-R requests CAISO clarify how all the proposed changes in section 4.1 apply (or do not apply) to legacy projects.
6.
Provide your organization’s comments 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?
EDF-R does not support this proposal and highlights that the ISO does not propose to revise or change its proposal substantially even though the only stakeholder who supported the proposal is the one that stands to benefit (VEA). EDF-R views the proposal as a similar proposal rejected at FERC before and believes it is unjust and unreasonable to impose different and discriminatory refundability rules in different ISO-area locations.
7.
Provide your organization’s comments on section 5.2 Policy for ISO as an Affected System – how is the base case determined and how are the required upgrades paid for?
EDF-R supports the CAISO’s proposal to use its existing policy for RNU reimbursement for RNUs resulting from an affected system study.
8.
Provide your organization’s comments 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 this procedure is already suported by CAISO's tariff and existing GIA language. As a matter of semantics, a party to a GIA can hold another party in breach, and a party can file for GIA termination at the FERC, but GIAs are ultimately terminated by the FERC.
9.
Please provide additional comments on the IPE – Phase 2 Draft Final Proposal not mentioned above:
n/a
Golden State Clean Energy
Submitted 08/16/2022, 05:53 pm
Submitted on behalf of
Golden State Clean Energy
1.
Please provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) – Phase 2 draft final proposal:
Throughout the 2021 Interconnection Process Enhancements initiative, Golden State Clean Energy (“GSCE”) has been concerned that CAISO’s proposals were not going far enough to address the underlying issues with the overheated interconnection queue or prevent future superclusters from forming by providing a structure that encourages commercially viable projects to submit interconnection requests. Our analysis suggests that despite the size of the queue, the rate of success for projects reaching commercial operation is so low that CAISO has insufficient capacity in the queue to meet California’s clean energy policy goals. Since its inception, CAISO has had a total of 1,912 generator interconnection requests representing 386,620 MW at the point of interconnection (excluding Cluster 14 given it has not completed its Phase II studies and does not yet fairly inform the queue’s success rate).[1] Of all these megawatts from interconnection requests filed, 24,351 MW have reached commercial operation, representing a meager 6.3 percent success rate of interconnection request capacity that CAISO has studied that eventually reached commercial operation. The chart below breaks this data down into different queue cluster periods and highlights that much of the operational capacity came from interconnection requests submitted before CAISO’s queue cluster process.
Projecting our analysis of the historical success rate into the future, a 6.3 percent success rate of projects that reach commercial operation will only produce about 10,270 MW of operational capacity net at the POI. This falls well short of what is needed for midterm reliability procurement (considering that obligation is in terms of net qualifying capacity) and is only about a quarter of the megawatts expected to be needed in 2032 according to the CPUC’s preferred system plan that CAISO is studying in this year’s transmission planning process.[2]
Based on our analysis of the queue, we believe that a significant amount of time, money, and precious human resources are currently focused on studying too many projects that will never become operational. GSCE does not believe the current process, or the reforms proposed by CAISO to date, will allow California to meet its GHG reduction goals or reliability needs given the historic success rate and the amount of renewable generation that must be built in the next several years. In order for the state to meet its clean energy goals, this IPE initiative must make serious queue reforms designed to improve the success rate of projects in CAISO’s queue.
With the phase 2 Draft Final Proposal, CAISO suggests that contracting requirements and term length are the hallmarks of commercial viability. However, we believe this focus does not create true signals of likely commercial success, and furthermore, we believe the proposed requirements will harm projects that are commercially viable. We also believe that FERC’s focus on these elements, through its readiness proposal, is misguided and suggest that CAISO should join us in raising concerns with the NOPR on these points. FERC’s proposal is misguided because it narrowly focuses on offtake negotiations too early in the project development timeline without any consideration of other forms of commercial readiness and viability. We believe the NOPR’s proposed reforms will harm California’s ability to meet its ambitious policy goals, and we have the experience to back up this assertion.
CAISO must emphasize different factors as indicative of commercial viability. GSCE is the developer of the Westlands Solar Park, a 20,000+ acre and 2,700 MW competitive renewable energy zone development in California’s Central Valley. We have had complete site control and a programmatic EIR over the entire development footprint since the time our initial interconnection requests were submitted, and we now have solar and battery projects spanning multiple queue clusters. The Westlands Solar Park has strong support from environmental, agricultural, and local stakeholders, as it is located entirely on drainage-impaired farmland that represents a disturbed environment. Our projects have full capacity deliverability status that was initially allocated largely based on the legacy balance sheet financing option, which is an option CAISO has done away with in favor of focusing on contracting even though this deliverability allocation is part of what set up the projects for success and led them to reaching offtake agreements.
GSCE’s success rate within Fresno and Kings County is dramatically better than the rest of the queue. We believe that the elements that have been driving our success include the early site control and programmatic EIR for the entire footprint, as well as the significant up-front investment in a shared gen-tie that supports multiple facilities. The graphs below illustrate GSCE’s success compared to other projects in the same development area.
Site control, a programmatic EIR, development on disturbed land within California in an area with strong environmental and local support, and early financial commitment to interconnection facilities to support multiple projects – these are all elements that should be valued as indicators of commercial viability. We have been able to sign offtake agreements because of these indicators of success; other development activity critically occurred before contracting, including receipt of deliverability on a merchant basis. Westlands Solar Park’s 250 MW Aquamarine project, which reached commercial operation in December of 2021, is operating mostly as a successful merchant facility, with some short-term capacity, energy, and REC contracts, showing that a long-term offtake agreement may never occur with a modern project and need not occur for a project to be commercially successful.
The proposed GIDAP rules that limit commercial value and eligibility criteria to projects with a long-term contract are focusing on the end result of successful projects in the hopes that setting those requirements up-front will improve things. We do not see requiring contracting up-front as an improvement because it is inconsistent with the typical timeline for offtake negotiations and does not allow contracting parties to be informed by the interconnection studies that provide important commercial certainty. Limiting Phase I study readiness demonstrations to offtake negotiations also incentives developers to irresponsibly contract for any price to allow their project to be studied, which will lead to more late-stage price renegotiations and project cancellations as negotiations fall apart.
Focusing on the contract as a means of obtaining deliverability may also incentivize irresponsible contracting. Nothing stops developers from bidding low to obtain a PPA, receiving deliverability based on that PPA, and then confronting the fact that the price they agreed to with counterparties is not financeable. Without other early measures of commercial viability – site control, permitting, nonrefundable deposits, etc. – these projects create unrealistic expectations that they will succeed and waste the time and resources of the CAISO to study them throughout the interconnection process. CAISO needs more data to support a readiness proposal that only focuses on commercial negotiations – something must account for the low success rate of projects in the queue and additional analysis could help reveal an underlying nexus with what makes a project likely to succeed. In the absence of data supporting a narrow focus on commercial negotiations, CAISO should look to developers’ perspectives on how their projects succeed in project development.
For these reasons, and given our experience, we strongly recommend CAISO refocus its attention on different commercial readiness criteria that projects must demonstrate as part of moving into the Phase I studies. We also propose changes to CAISO’s deliverability allocation eligibility so it too does not narrowly focus on offtake negotiations and ignore commercially viable projects that deserve deliverability. By considering the real factors that drive a project’s success, CAISO’s reforms will have a better chance of meaningfully improving the queue while ushering California into a clean energy future.
Finally, GSCE submits this comment to address the following questions:
- Question 3 regarding minimum term requirements for PPAs to be eligible for TPD allocation and retention; and
- Question 5 regarding study deposits and commercial readiness demonstration (including CAISO’s approach to FERC’s NOPR).
[1] This information was pulled from CAISO’s Public Generator Interconnection Queue information on July 14, 2022. We previously provided similar data in our comment on the IPE phase 1 Draft Final Proposal, but this data represents more recent public queue information.
[2] See 2022-2023 Transmission planning process, Draft Study Plan, at 24, Feb. 18, 2022, available at: http://www.caiso.com/InitiativeDocuments/DraftStudyPlan-2022-2023TransmissionPlanningProcess.pdf.
2.
Provide your organization’s comments on section 3.1 Transparency enhancements:
GSCE has no comment at this time.
3.
Provide your organization’s comments on section 3.2 criteria for minimum term for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation:
As with commercial readiness, CAISO is overly focused on contracts and prescribing minimum term requirements at a time when the market no longer requires these factors. CAISO should retain its previous 3-year minimum term proposal, and the deliverability allocation criteria should be expanded beyond commercial negotiations to better reflect other indicators of viability and readiness that warrant deliverability.
At the deliverability allocation stage, there are factors that are not currently valued that indicate a serious, viable project with skin in the game. The allocation groups create a barrier to all without a PPA, except for the limited eligibility of projects that reached commercial operation or those that have just completed their Phase II studies. CAISO does not provide projects that are further along in their interconnection study the ability to seek deliverability unrelated to offtake negotiations. Other important development steps can lag throughout the study process while the project seeks a PPA at any price in order to receive deliverability, even if the price is too low to finance the project. This does not mean CAISO should scrutinize price terms, but that other means of allocating deliverability that rewards viable projects should be available through new allocation groups. Pairing a more open deliverability process with Phase I commercial readiness requirements and increased scrutiny of projects meeting their GIA milestones, as CAISO has proposed, strikes a better balance of moving projects through the queue while allowing viable projects an opportunity to seek deliverability.
GSCE proposes that projects that have made their third security posting or have issued a notice to proceed to construction be added as a new allocation group.[1] We view this as an important way to inject readiness criteria into the deliverability allocation process and incentivize projects to proceed to commercial operation. These represent reasonable TPD eligibility criteria because such projects are fully committed financially and have permits necessary to allow them to proceed to construction, which strongly indicate viability without solely focusing on contracts. These projects also bring a much higher degree of commercial certainty than projects that have been shortlisted, yet shortlisting gives a project the second highest TPD priority. The notice to proceed and third security posting provides a clear, bright-line requirement that is easy for CAISO to confirm.
The role of land permitting in the TPD seeking affidavits should also be strengthened. Currently projects can meet the permitting element required to seek deliverability by merely applying for the necessary governmental permits required for construction. This asks too little of a project that late in the study process, and it is not reasonable given the scarcity of deliverability. It also seems incongruent to require so little of project permitting to allocate deliverability when projects at this stage will be required to have site exclusivity, per CAISO’s phase 1 proposal in this initiative. GSCE supported the phase 1 site exclusivity proposal as an improvement over existing rules, and we think CAISO should continue with this logic and strengthen permitting requirements for TPD.
Not only is deliverability allocation overly focused on contracting, but CAISO is proposing minimum term requirements to dictate a term length that it deems commercially viable. Based on our own experience bringing large-scale projects into commercial operation, we do not agree with the assertion that new greenfield projects or project expansions require a contract of at least ten years. Our experience has shown that using a portfolio approach to contracting, including layering in short-term contracts, contracts for RECs and contracts for RA, renders a project viable for obtaining financing. The focus on a long-term contract is outdated and should not be a threshold for how deliverability is allocated and retained. Setting a minimum term requirement for contracts to receive and retain TPD needlessly interferes with commercial negotiations and financing strategies.
The Draft Final Proposal states that CAISO “believes that many of the arguments for short-term contracts are only valid related to existing resources that are already online and competing to obtain short term RA contracts.”[2] Again, our experience has shown that short-term RA contracts can make greenfield project financeable, and we have already brought significant clean capacity online through such a financing strategy. Also, we believe that operational resources should not be discouraged from receiving deliverability through allocation Group A because these resources provide immediate reliability benefits and maximize existing ratepayer investments. CAISO has already recognized their value by making online projects eligible for Group C. There are rules in place that are supposed to protect against queue jumping, and deliverability cannot be allocated in excess of what a project can use so hoarding TPD should not be a concern. Projects with deliverability are incentivized to continuously sell RA because RA is not bankable or meaningful outside of RA compliance, so selling monthly RA credits is the only way to capitalize on the value that deliverability provides.
A 3-year minimum term requirement would be reasonable given it is only needed to support the resource adequacy program, which is a short-term compliance regime of no more than 3 years. This creates substantially less risk of disruption in the RA marketplace when CAISO has historically avoided inserting itself into the role of scrutinizing contracts and commercial terms. We believe CAISO should continue this historical posture and avoid making significant changes to contract eligibility criteria. And in order to encourage resources, particularly storage, to be developed and qualify to support the resource gap in California, CAISO should consider that pure RA contracts are commonly for one to three-year terms.
Ultimately, CAISO needs to ensure that serious, viable projects have a pathway for receiving deliverability because this is what the market demands of new resources and a lot of procurement must occur in the next couple decades. CAISO should take comfort in the fact that enacting commercial readiness will screen projects earlier in the study process rather than leaving TPD allocation groups to be the first viability checkpoint, so despite TPD’s scarcity, an additional allocation group is reasonable if paired with new readiness requirements. Further, there is no need to adopt prescriptive term length requirements because CAISO can include more exacting term length policy for deliverability allocations in the allocation affidavit points that are used to differentiate projects within a group, rather than the eligibility criteria.
[1] CAISO previously rejected this proposal by stating that projects can take years between the notice to proceed and COD, which does not align with GSCE’s previous proposal to include such projects in the new Group C because that groups is meant for projects that can immediately utilize TPD. But that response does not explain why a new allocation group should not be created. We see a third security posting or having issued a notice to proceed to construction as more in line with commercial readiness while not narrowly focusing on contracting and risking an undesirable contracting landscape. This eligibility criteria could be enacted only for future clusters that are subject to any commercial readiness criteria that is implemented.
[2] Draft Final Proposal, IPE 2021 initiative Phase 2, at 13, July 26, 2022.
4.
Provide your organization’s comments on section 3.2 eligibility criteria for non-LSE PPAs to receive a Transmission Plan Deliverability (TPD) allocation:
GSCE has no comment at this time.
5.
Provide your organization’s comments on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?
GSCE supports some form of commercial readiness demonstration and increased fees to submit an interconnection request, but the eligibility criteria should be expanded to more accurately reflect readiness early in project development. Readiness demonstrations should include site exclusivity, permitting, procurement of major equipment, or an early financial commitment to interconnection facilities to support multiple projects. CAISO must balance the competing need of limiting queue access to only commercially ready projects with the need to add a significant amount of capacity to the system in the coming decade. Our proposal also takes a more prudent approach to FERC’s NOPR where CAISO’s readiness proposal emerged from.
Commercial readiness demonstration
GSCE’s experience shows that commercial readiness prior to Phase I involves elements unrelated to CAISO’s proposal focused on commercial negotiations, and we are concerned this overly limited view of readiness harms California’s ability to develop the amount of capacity called for in long-term planning. The proposal unreasonably ignores other important indicators of commercial readiness to the detriment of viable projects and their offtakers, it forces contract negotiations to occur before projects are studied and have sufficient cost certainty, and it involves details of a mere proposal by FERC that is controversial for being disconnected from commercial realities. Limiting Phase I study readiness demonstrations to offtake negotiations also incentives developers to irresponsibly contract for any price to allow their project to be studied, which will lead to more late-stage price renegotiations and project cancellations as negotiations fall apart.
As mentioned in our response to question 1, we believe our Aquamarine project is a good example of why CAISO’s focus on long-term contract negotiations unreasonably excludes viable projects and places undue focus on long-term contracting which may not be an indicator of commercial success. Short-term contracts executed later in the development process allowed Aquamarine to be financed based on a successful merchant strategy that adapts to the current marketplace. Before that point, the project succeeded in establishing, prior to submittal of the interconnection request, complete site control, a programmatic EIR over the entire development footprint, and development on disturbed land within California in an area with strong environmental and local support. The project also succeeded because it received full capacity deliverability status, and the allocation was based on the previous option to balance sheet finance that was designed for merchant facilities but is no longer available as CAISO has limited eligibility to largely focus on contracting.
For Aquamarine, receiving deliverability and securing rights to develop in a viable zone within California then indicated to offtakers and investors that the project was viable and valuable. This allowed the project to attract financing and proceed to construction. Additional contracts were layered in later but this did not affect the project’s deliverability status. The natural order of finance and development would be thrown off by adopting the commercial readiness proposal as currently constructed, and it would mean other projects like Aquamarine would be significantly disadvantaged and potentially never constructed.
Before CAISO moves forward with a readiness demonstration based on commercial negotiations, CAISO needs more analysis on this and how signing a PPA early really aligns with ultimate commercial success. In addition to potentially including the proposed demonstration options, CAISO should listen to developers to base readiness criteria on real world experience and better ensure an effective proposal.
GSCE supports some form of a commercial readiness demonstration to enter the Phase I study because the queue must improve the success rate of projects that reach commercial operation. However, the eligibility criteria should be expanded to balance the competing need of limiting queue access to only commercially ready projects with the need to add a significant amount of capacity to the system in the coming decade.
We propose CAISO accept, in addition to the proposed readiness demonstration options, a commercial readiness demonstration in the form of site exclusivity, permitting, procurement of major equipment, or an early financial commitment to interconnection facilities to support multiple projects. All of these options strongly indicate a project that has skin in the game by taking serious commercial steps toward developing a project prior to being studied. Any of these demonstrations alone should be accepted to show commercial readiness.
CAISO and the PTOs have limited staff and resources to study interconnection requests, as observed in the delays caused by Cluster 14, which makes it reasonable to adopt commercial readiness criteria. But California must undergo a monumental infrastructure buildout to meet its policy goals, which makes it necessary for CAISO to ensure its interconnection queue facilitates the several tens of gigawatts that need to come online in the next decade. Even if the queue’s success rate improves, many projects will still fail to be constructed, so CAISO must manage a queue that has tens or hundreds of gigawatts more capacity than is expected to be procured. The key to this tension of studying significant new resources while managing the queue size is to install commercial readiness criteria while ensuring commercial viability is accurately defined and inclusive of different development strategies.
FERC’s Notice of Proposed Rulemaking
When adopting the NOPR’s commercial readiness demonstration proposal, CAISO requested stakeholder feedback on how to manage the fact that a readiness demonstration requirement will help prevent future superclusters but that FERC may alter its proposal. A risk with acting on FERC’s proposal if FERC ends up adopting a different proposal is CAISO making multiple major shifts in policy in a short amount of time and creating significant disparity between sequential clusters.
GSCE believes a prudent solution is to expand the readiness demonstration options because it is consistent with the policy direction FERC is broadly heading in and still makes a significant effort to prevent superclusters. Directionally adopting commercial readiness positions CAISO to be more consistent across future interconnection request windows and have less policy work in its eventual FERC rulemaking compliance.
Considering the NOPR’s narrow view of commercial readiness poses a risk to California meeting its expected development needs by aggressively limiting the number of projects eligible to seek interconnection, we believe that CAISO should oppose FERC’s current readiness proposal as well. We intend to make the case at FERC that we have in this comment – that the focus on contract negotiations to enter the study process is misguided, insufficiently supported, and blind to other elements that better indicate a commercially viable project during the earliest development stages. To protect California’s policy interests and reliability needs, CAISO too should support a readiness process with expanded demonstration options.
Study deposits
GSCE supports the proposal to base study deposits on a megawatt amount rather than the number of interconnection requests. This makes CAISO’s proposal directionally consistent with the NOPR while increasing study deposit amounts to create better incentives for projects entering the queue.
The proposed increase in study deposits warrants a reexamination of the use of funds in excess of actual study costs given the study deposit is now also being used as a deterrent to projects entering the queue rather than increasing to cover study costs.
6.
Provide your organization’s comments 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?
GSCE has no comment at this time.
7.
Provide your organization’s comments on section 5.2 Policy for ISO as an Affected System – how is the base case determined and how are the required upgrades paid for?
GSCE has no comment at this time.
8.
Provide your organization’s comments 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 has no comment at this time.
9.
Please provide additional comments on the IPE – Phase 2 Draft Final Proposal not mentioned above:
GSCE has no comment at this time.
LSA
Submitted 08/16/2022, 05:31 pm
Submitted on behalf of
Large-scale Solar Association (LSA)
1.
Please provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) – Phase 2 draft final proposal:
LSA’s positions on the Draft Final Proposal (Proposal) issues are summarized below.
Data Transparency (Q2):
- LSA continues to urge the CAISO to clean up and update the data in the queue, at least for projects currently active.
- LSA supports the disclosure of project-related items listed in the Proposal. LSA encourages the CAISO to include as much of these data in the regular queue listings as possible, facilitated by removal of some data currently in the queue that are not useful.
- LSA continues to support additional data transparency for information on transmission constraints, including “heat maps” and other interactional tools developed by other ISOs.
- LSA supports the CAISO’s proposal to provide a publicly available forum for developers to voluntarily post contact and other additional information.
PPA definitions for TPD Allocations:
- Minimum PPA term for TPD allocation (Q3): LSA continues to oppose CAISO establishment of a minimum PPA term for Transmission Plan Deliverability (TPD) Allocation, or certainly a minimum term that exceeds one year.
- PPAs with non-LSEs (Q4): LSA supports the CAISO’s decision to allow PPAs with non-LSEs to qualify for TPD Allocations and believes that the proposed conditions are reasonable.
- COD extensions (Q3-4): The Proposal states that the 5-year minimum term and non-LSE conditions would apply to projects receiving their TPD Allocations in the 2023-2024 process. Thus, if these proposals are adopted, LSA does believes they should not apply to COD extensions for projects that received their TPD Allocations earlier.
Higher fees, deposits, or other criteria for IR Interconnection Request (IR) submittals (Q5): These proposals go far beyond higher IR submittal requirements. LSA opposes the proposals for: (1) revised cost allocation and Study Deposit structures that do not reflect CAISO costs; (2) Study Deposit amounts that far exceed CAISO costs; (3) Commercial Readiness criteria, which are vague at this time and inconsistent with CAISO-area contracting practices; and (4) Study Deposit retention for years after study completion.
Cost allocation treatment for network upgrades to local (below 200 KV) systems (Q6): LSA recognizes the problem but continues to oppose 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 adopt LSA’s proposed mitigation measures and clarifications.
CAISO as an Affected System – Network Upgrade (NU) reimbursements (Q7): LSA supports the CAISO proposal, for the reasons stated.
Time in queue/GIA milestone enforcement (Q8): LSA supports the CAISO’s proposals for more stringent enforcement of deadlines and communication requirements.
PTO upgrade actions after IC Notice to Proceed (NTP) (Q9): The CAISO shouldn’t reject this issue as too complex. 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.
Provide your organization’s comments on section 3.1 Transparency enhancements:
LSA’s comments are provided below.
- LSA continues to urge the CAISO to clean up and update the data in the queue, at least for projects currently active. For example, projects in the active queue are listed with CODs that have already passed, the fuel data should be standardized by column, and POI substation and other names should be standardized.
- LSA supports the disclosure of the project-related items listed in the Proposal and appreciates the CAISO’s commitment to do the additional work needed to provide this information. These data should preferably be included in the regular queue listings where possible, to avoid having to flip back and forth between different reports. Some of the data in the queue could be removed to facilitate this, including:
- Interconnection Request Receive Date, since the Queue Date is the more relevant date;
- Application Status, which is obvious (i.e., it is Active if the project is on the active list, and Withdrawn if the project is on the withdrawn list);
- Feasibility Study or Supplemental Review, which is N/A for virtually all projects; and
- Optional Study, which is N/A for every project listed.
- LSA continues to support additional data transparency for information on transmission constraints, including “heat maps” and other interactional tools developed by other ISOs. Per our earlier comments, we urge CAISO to further explore the interactive tools deployed by MISO and SPP, especially since FERC may require the CAISO to develop similar tools. As we said before, CAISO will continue to get multiple speculative Interconnection Requests until it provides more information on the best places to interconnect.
- LSA supports the CAISO’s proposal to provide a publicly available forum for developers to voluntarily post contact and additional information.
3.
Provide your organization’s comments on section 3.2 criteria for minimum term for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation:
LSA continues to oppose the CAISO’s proposal for a minimum PPA term to qualify for TPD Allocations that exceeds one year. The CAISO has failed to justify the proposed five-year minimum term: (1) using a misleading portrayal of stakeholder positions; and (2) on the merits. LSA’s objections to the five-year term, and mitigation suggestions if the CAISO proceeds with this proposal, are discussed below.
The CAISO’s “mathematical analysis” of stakeholder positions is misleading.
First, as LSA noted in the stakeholder meeting, groups like LSA, SEIA, and CESA, each with many members, are “given” one vote each, while other single entities get the same single vote.
Second, the CAISO’s stakeholder grouping results in a longer term than the responses indicate. Using the stakeholder position table in the Proposal, LSA shows an alternate interpretation below (BOLD ITALIC CAPS, since colored ) showing that, even with the objectionable one-vote-per-comment-submittal weighting:
- A stakeholder plurality supports no minimum term, i.e., “No Min” gets the most votes;
- Most stakeholders support a minimum term of three years or less and, of that group, the weighted average suggested minimum term is far less than one year;
- The median minimum term supported by all stakeholders is three years.
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Minimum Term
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Entity (Name)
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No Min Term
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1 Year
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3 Years
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5 Years
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10 Years
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ACP-California
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1
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Avangrid Renewables
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1
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California Community Choice Association
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1
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California Energy Storage Alliance
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1
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CPUC Energy Division
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1
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California Wind Energy Association
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1
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Golden State Clean Energy
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1
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Large-scale Solar Association/ LSA
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1
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San Diego Gas & Electric
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1
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Solar Energy Industries Association/SEIA
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0.5 1
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0.5 1
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Six Cities/Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside
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1
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Southern California Edison
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1
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Sum of Comment Categories
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3.5
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1
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2.5
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3
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2
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8.5 Agree to some Min Term 2
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7.0 AGREE TO MIN TERM 0-3 YEARS3
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1 SEIA does not believe CAISO should require any minimum term, but would support 3 years
2 Weighted average of suggested Min Term = 5.1 years
3 WEIGHTED AVERAGE OF SUGGESTED MIN TERM = 0.39 YEARS (0.29 YEARS IF if SEIA IS COUNTED AS ZERO, ITS PREFERENCE)
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The proposal fails to justify a five-year minimum PPA term, on the merits.
The CAISO’s proposal to establish a minimum PPA term for Resource Adequacy (RA) deliverability awards stems from an apparent assumption that long terms are required anyway, and a determination that the viability of a new generation or storage project (and its readiness to move ahead toward development), depends on the length of its offtake contract for RA attributes. However, these assumptions and determinations are mistaken, for several reasons.
First, despite statements in the Proposal to the contrary, “capacity procurement requirements of jurisdictional LSEs” do not “require a contract for a minimum of ten years.” Recent CPUC orders require longer-term procurement for compliance with those orders only. LSA members have direct experience with LSEs using short-term contracts (one month to a few years) to satisfy some portions of their RA obligation; this flexibility reflects the nature of LSE service to their own customers, many of which are able to switch suppliers with little notice. LSA notes that CPUC-jurisdictional RA showings are limited to three years.
Second, while RA is a significant revenue element for some technologies (e.g., energy storage), that is not necessarily true for others, most notably Variable Energy Resources (VERs), which have faced declining RA value for years. For those latter resources, revenue from RECs and energy can be relatively more significant, and those attributes can be contracted on a long-term basis to buttress short-term RA contracts and support project financeability.
Similarly, projects with RA-only contracts may not be “ready to move ahead” on that basis alone if the rest of their revenue base is not contracted, and if other factors affecting development risk (permitting, land acquisition) must still be addressed.
Third, the interaction of price (of RA, RECs, and other elements) and contract term are not considered in the proposal. For example, a project with a shorter-term but higher-priced contract may be more financially viable than a project with a longer-term but lower-priced contract.
Fourth, long-term contracts may not be hedges against uncertainty, especially in times of high inflation. In the current market environment, cost drivers are causing re-negotiation of previously negotiated long-term contracts. Those contracts may not have needed re-negotiation if uneconomic pricing terms not been locked in for 10+ years, because the developers could have borne those cost increases for a shorter period in the expectation of a higher-priced new contract immediately following.
Finally, more generally, the proposal effectively amounts to a determination or judgment by the CAISO about how offtake contracts are structured and financed, and the CAISO is not the proper entity to do that. If the CPUC or other applicable Local Regulatory Authority believes that there should be a minimum term for all RA contracts, those entities can issue that mandate. Otherwise, contract term should be a risk management decision between the Interconnection Customer and the off-taker.
Recommended mitigation if this proposal is adopted
If the CAISO nevertheless proceeds with the five-year minimum PPA proposal, LSA recommends two mitigation measures: (1) In-lieu deposit option; and (2) applicability to future TPD Allocations only. These recommended mitigation measures are discussed below.
In-lieu deposit
The Proposal provides in-lieu deposit options for several key elements, e.g., Site Exclusivity, Commercial Readiness criteria, and TPD Allocations based on PPAs with non-LSEs where an eventual LSE agreement is not yet demonstrated. LSA suggests that this approach be applied also to TPD Allocations where a project has secured a PPA of at least one year but less than an otherwise-applicable minimum term.
For example, to qualify for Group A, a project would be required to provide an executed RA PPA of at least one year, but must also provide a deposit (e.g., $10K/MW of allocated TPD, with a minimum deposit of $500K) if the PPA does not meet the new minimum term. Deposit money should be used to fund future transmission upgrades.
PPAs needed to extend CODs
The Proposal states that the 5-year minimum term and non-LSE conditions (Questions 3-4) would apply to projects receiving their TPD Allocations in the 2023-2024 process or later. However, the CAISO stated in the stakeholder meeting that these provisions might apply to COD extensions requested after FERC approval of the new rules by projects that received their TPD Allocations earlier, e.g.:
- PPAs needed to extend CODs under Permissible Technological Advancements, e.g., for projects in TPD Allocation Group 3; and
- PPAs needed to comply with Commercial Viability Criteria (CVC), to extent CODs beyond 7 years time in queue.
In most other areas, the CAISO has refrained from imposing additional requirements adopted after projects have entered the interconnection process. Consistent with this approach, and its statements in the Proposal, LSA believes that the CAISO should only apply these new requirements (including any minimum PPA term) to COD extensions for projects receiving their TPD allocations in the 2023-2024 process or later, and not those that received allocations earlier.
4.
Provide your organization’s comments on section 3.2 eligibility criteria for non-LSE PPAs to receive a Transmission Plan Deliverability (TPD) allocation:
LSA is pleased to see that CAISO provides a path for PPAs with non-LSEs. Other jurisdictions allow such PPAs, and (as we said in our last comments) non-LSEs will be highly incented to offer valuable RA benefits into the market even if they cannot use those benefits themselves.
The LSE PPA timing requirements seem reasonable, and LSA supports the CAISO’s proposed in-lieu deposit-based alternative to LSE PPAs.
However, the proposed deposit amounts seem excessive, for projects with executed PPAs (especially if those must be long-term PPAs, given the proposed 5-year PPA term). Instead of $10K/MW of allocated TPD ($500K minimum), LSA believes that more reasonable in-lieu deposit amounts would be $5K/MW of allocated TPD ($250K minimum), with a $1 million cap.
PPAs needed to extend CODs
The Proposal states that the 5-year minimum term and non-LSE conditions (Questions 3-4) would apply to projects receiving their TPD Allocations in the 2023-2024 process or later. However, the CAISO stated in the stakeholder meeting that these provisions might apply to COD extensions requested after FERC approval of the new rules by projects that received their TPD Allocations earlier, e.g.:
- PPAs needed to extend CODs under Permissible Technological Advancements, e.g., for projects in TPD Allocation Group 3; and
- PPAs needed to comply with Commercial Viability Criteria (CVC), to extent CODs beyond 7 years time in queue.
In most other areas, the CAISO has refrained from imposing additional requirements adopted after projects have entered the interconnection process. Consistent with this approach, and its statements in the Proposal, LSA believes that the CAISO should only apply these new requirements (including any rules regarding non-LSE agreements) to COD extensions for projects receiving their TPD allocations in the 2023-2024 process or later, and not those which received their allocations earlier.
5.
Provide your organization’s comments on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?
This question is misleading, given the current Proposal. The CAISO proposals go far beyond providing criteria for “submitting an IR” to encompass Interconnection Study cost allocation, new readiness criteria for entering both Phase I and Phase II Studies, and Study Deposit retention far beyond completion of Interconnection Studies.
LSA’s comments on the specific CAISO proposals are provided below.
The proposed cost-allocation and Study Deposit structures bear no relationship to CAISO costs
The CAISO has stated many times that Interconnection Study costs are the same for each project, regardless of size. The CAISO has always allocated study costs per capita (equal costs for each project) on that basis, and it revised the Study Deposit from a base plus $/MW structure (similar to that now proposed) to the current equal cost-per-project basis, many years ago, for that reason.
The CAISO is now proposing a complete about-face in its position, i.e., to: (1) return to a tiered Study Deposit structure by project size; and (2) go even further, to base the study cost-allocation structure almost entirely on project size.
The CAISO has provided no justification for its new position, other than vague statements that “FERC may have a point” that larger projects could be “complicated,” or may require “more complex” solutions to mitigate overloads. No evidence has been offered to document these assertions, or to show that the basis for CAISO’s long-standing statements and structure supporting per-project cost allocations and Study Deposits has somehow changed.
The proposed Study Deposit amounts bear no relationship to actual study costs
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).
It is possible that study costs might have increased since then and if so, higher Study Deposit amounts would be justified. However, the $300K and $500K Study Deposits proposed for larger projects likely far exceed even escalated study costs and therefore are unjust and unreasonable.
The proposed Commercial Readiness (CR) criteria are vague and inconsistent with CAISO-area PPA contracting practices.
Among other things, it is not clear what would constitute “reasonable evidence” that a project would move forward, in particular how a project would demonstrate that it is “being developed for a sale to a commercial, industrial, or other large end-use customer.”
More seriously, it is extremely rare for a project to have progressed to a “binding” term sheet, or be selected in any competitive solicitation for a project sale or PPA, before it even has a Phase I Study. In fact, nearly all LSE competitive solicitations require at least a Phase I Study to even participate in such solicitations. The most competitive projects have not only completed a Phase II Study, they also have received TPD Allocations.
Thus, practically the only projects that would qualify to even enter Phase I Studies would be those developed by LSEs. This result would be extremely anticompetitive and unfair.
The proposed CR criteria are really not ready for application under the CAISO tariff at this time, and certainly require more careful consideration and revisions than implied by their inclusion in a Draft Final Proposal.
The Study Deposit refund proposals are unjust and unreasonable.
While the Proposal document does not mention this topic at all, the discussion at the stakeholder meeting indicates that the CAISO is still intending to delay Study Deposit refunds beyond the current GIA execution milestone to some later time. It’s not clear whether this future milestone would be the project COD (as proposed earlier) or some other timeline; in any case, the CAISO has provided no support for retaining Study Deposit fees for what could be years beyond completion of the actual Interconnection Studies those funds are intended to cover.
As LSA said in its last comments, moreover, the CAISO has not said whether these funds would accrue interest, which should certainly be the case if the CAISO pursues this proposal.
6.
Provide your organization’s comments 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 we have stated before, LSA recognizes the problem and fully supported the CAISO’s proposal to FERC, and we agree that something should be done.
At a minimum, CAISO should clarify the calculation of the cap and the PTO-provided figures, as we requested in our last comments. Specifically, CAISO should clarify whether the calculation would include LV costs associated only with completed projects, projects under construction or with executed GIAs, or forecasts based on study results for additional projects or clusters.
The CAISO’s proposals to post current/projected data on PTO interconnection-related LV costs, and to allow for project withdrawals with security refunds if a PTO reaches the 15% limit while the project is in the queue, improve the proposal marginally. However, LSA continues to believe that the CAISO’s proposal is not just and reasonable, for the reasons described below.
First, as we have said before, despite the “non-discriminatory” verbiage in the Proposal (and all prior versions), this “generic” proposal is clearly aimed at VEA. The CAISO would not be making this proposal (and certainly not at this time) if not for the VEA situation, and no other PTOs would likely reach the 15% threshold for many years, or ever. So, the assertion that this proposal would apply to “any PTO” in a “non-discriminatory” fashion is simply not true.
Second, the proposal would likely have the impact of preventing most future generation development on the VEA system, since the cap is so low that a single project could easily absorb the entire $3.5 million below it. If that is the intent, the CAISO should simply say so.
Developers would not likely take the risk of proposing VEA interconnections in the future, since:
- There is no way a developer can 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.
- The ability to withdraw with IFS refunds if VEA reaches the cap while the project is in the queue is helpful, but not that much. Developers generally invest considerable resources in projects even before Interconnection Requests are submitted, and depending on how late in the study or development process the cap is reached, the losses can be considerable.
Third, LSA is disappointed that CAISO did not explain in any detail its reasons for rejecting the SEIA “Net Importer/Net Exporter” proposals, or 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.
The CAISO even said at the stakeholder meeting that it “really liked” the SEIA proposal but believes that the arguments supporting that structure were “too much like those FERC rejected” in CAISO’s earlier filing. The CAISO should better explain the reasons for this conclusion and consider whether the proposal could be modified in some way to address these concerns.
Alternative recommendations if this proposal is adopted
If the CAISO proceeds with this framework, LSA recommends the following:
- 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. As noted above, the ability to withdraw with an IFS refund does not make up for the considerable resources already invested in projects currently in the queue.
- Projects moving to a higher-voltage POI due to application of the cap should 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, and the CAISO should provide a tariff reference if one exists. Regardless, the cost protection should be retained if this proposal is implemented. It is likely that the original IR would have proposed the most economical interconnection, and so the developer should not lose cost-cap protection for trying to connect in the least-cost manner.
- Projects that did not receive full Network Upgrade reimbursement due to the 15% limit should be entitled to additional reimbursements if the target dollar amount increases. As the CAISO pointed out in the stakeholder meeting, this limit is dynamic, e.g., it could increase with additional investments in low-voltage facilities.
7.
Provide your organization’s comments on section 5.2 Policy for ISO as an Affected System – how is the base case determined and how are the required upgrades 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.
8.
Provide your organization’s comments 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 first proposed, and continues to support, the CAISO’s intent to enforce BPM Section 6.5.2.1 conditions on extending CODs. That section says “projects requesting to remain in the queue” beyond the applicable limit must “clearly demonstrate that:” (1) engineering, permitting, and construction will take longer; (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 proposed earlier that projects be terminated if they contribute to Short-Circuit Duty issues. LSA and others had recommended instead that 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 for SCD reasons alone. The Proposal is somewhat unclear, and the CAISO should clarify that it is no longer proposing such strict termination rules.
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, and terminate if appropriate.
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.
9.
Please provide additional comments on the IPE – Phase 2 Draft Final Proposal not mentioned above:
PTO obligation to begin work on upgrades
LSA objects to the CAISO removing the item about IC Notices to Proceed from the scope of this initiative. Developers would not have raised this issue in the first place unless there is a problem.
In fact, the CAISO’s characterization of this issue has been mischaracterized from the start. Developers are not asking for the PTO to start working on “every project’s network upgrades when the GIA is executed or the [NTP] is received by the [PTO].” 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.
If developers could just “work closely with the PTO” to resolve this problem, it would already be resolved. Instead, PTOs frequently delay work on needed upgrades after NTP is provided, delaying project progress toward the milestone dates the PTO has committed to in the GIA.
To repeat questions (not answered in the Proposal) from our last comments, 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? We again ask the CAISO to respond to these questions.
Rev Renewables
Submitted 08/16/2022, 04:13 pm
1.
Please provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) – Phase 2 draft final proposal:
While REV appreciates CAISO’s efforts to align its proposal with the recent FERC Notice of Proposed Rulemaking (NOPR) on generator interconnection RM22-14-000, REV suggests that CAISO should not fully adopt all NOPR criteria at this time given likely changes to the final ruling. In particular, REV supports the proposed allocation of study costs, and supports the proposed study deposit revisions. However, REV strongly opposes the commercial readiness proposal that would require interconnection customers to submit a substantial deposit if it does not have an executed term sheet (for Phase I) or contract (for Phase II). This commercial readiness requirement is a nearly impossible bar for interconnection customers that require at least Phase I study results to know upgrade costs required, which is a critical component to project viability (let alone being able to offer a price in a RFP solicitation). For a project 200MW or larger, these standards would tie up $2.25 million in commercial readiness deposits alone while the project completes the interconnection process. This is on top of the increase in site exclusivity deposits (from $250,000 to $500,000 in the IPE Phase I) and increase in study deposits (from $250,000 max currently to the proposed $500,000). REV suggests this additional $500,000 in total deposits is already a significant amount that can serve to cool off future clusters (in addition to its other IPE revisions) and CAISO should wait to implement the commercial readiness deposit requirements until FERC finalizes its ruling. Given REV’s position on the commercial readiness, REV also opposes the proposed withdrawal penalties that are tied to the commercial readiness deposit.
2.
Provide your organization’s comments on section 3.1 Transparency enhancements:
REV does not oppose CAISO’s proposal to make the following project information public to stakeholders, likely through RIMS – PUB similar to the existing Queue Report:
- PTO study area and sub-area by cluster;
- TPD allocation group and percentage allocation (or MW amount allocated) for the project. From this information stakeholders could deduce whether a project has a PPA;
- Resource ID(s);
- Status of suspension and parking (yes/no);
- Phase data: Generation and fuel type, MW, hybrid or co-located, synchronization date and COMX or COD date.
3.
Provide your organization’s comments on section 3.2 criteria for minimum term for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation:
REV has no comment at this time.
4.
Provide your organization’s comments on section 3.2 eligibility criteria for non-LSE PPAs to receive a Transmission Plan Deliverability (TPD) allocation:
REV has no comment at this time.
5.
Provide your organization’s comments on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?
REV appreciates CAISO’s efforts to align its proposal with the recent FERC Notice of Proposed Rulemaking (NOPR) on generator interconnection RM22-14-000. REV understands the challenge of fully aligning the CAISO proposal with the NOPR, and suggests that CAISO could make incremental steps towards elements in the NOPR (such as increased study deposits) but to wait to adopt the more controversial elements that are more likely to change in the final FERC ruling (such as commercial readiness deposits).
REV supports the proposed allocation of study costs, and supports the proposed study deposit revisions. This change would double the study deposit for large projects 200 MW and greater from $250,000 today to $500,000. This increase will create an additional financial liability on the interconnection customer thus creating an incentive to submit viable projects.
REV strongly opposes the commercial readiness proposal that would require interconnection customers to submit a substantial deposit if it does not have an executed term sheet (for Phase I) or contract (for Phase II). This is essentially an unreasonable and unreachable high bar for projects entering the CAISO interconnection process. FERC’s proposal is built on the examples of PSCo, PacifiCorp, Tri-State, Dominion, and Duke[1] all of which are primarily vertically integrated utilities and not in organized markets, and therefore have different project development and procurement processes. In CAISO territory, a developer is highly unlikely to execute a contract with a load serving entity (LSE) for a project without knowing at least an estimate of its interconnection and network upgrade costs, which are only known with certainty after completion of Phase 2 studies. These results are a critical component of determining project viability and total project cost, and therefore the price at which the developer can offer. For a project 200MW or larger, these standards would tie up $2.25 million in commercial readiness deposits alone while the project completes the interconnection process. This is on top of the increase in site exclusivity deposits (from $250,000 to $500,000 in the IPE Phase I) and increase in study deposits (from $250,000 max currently to the proposed $500,000). REV suggests this additional $500,000 in total deposits is already a significant amount that can serve to cool off future clusters (in addition to its other IPE revisions) and CAISO should wait to implement the commercial readiness deposit requirements until FERC finalizes its ruling.
Given REV’s position on the commercial readiness, REV also opposes the proposed withdrawal penalties that are tied to the commercial readiness deposit. As CAISO notes in the paper, it already has withdrawal penalties associated with the financial security posted after Phase I and Phase II studies. These financial postings and amounts at risk already serve to incentivize interconnection customers to stay in the queue, particularly after Phase I studies.
[1] FERC NOPR RM22-14-000 paragraph 128.
6.
Provide your organization’s comments 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 does not support an alternative cost allocation treatment for network upgrades below 200 kV. The High and Low voltage transmission in California is configured in a loop arrangement in most locations. Therefore, any network upgrades that get built on the low voltage transmission side provide overall reliability and other benefits to the bulk high voltage transmission as well, similar to upgrades that get built on high voltage transmission. Separating the cost allocation on high and low voltage would not only be cumbersome but would also go against the fundamentals that are in place today.
7.
Provide your organization’s comments on section 5.2 Policy for ISO as an Affected System – how is the base case determined and how are the required upgrades paid for?
REV has no comment at this time.
8.
Provide your organization’s comments 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.
9.
Please provide additional comments on the IPE – Phase 2 Draft Final Proposal not mentioned above:
REV does not agree with CAISO’s assessment and proposal to not pursue 6.1 in the draft final proposal: “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.” As stated in REV’s previous comments, 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.
Six Cities
Submitted 08/16/2022, 03:19 pm
Submitted on behalf of
Cities of Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside, California
1.
Please provide a summary of your organization’s comments on the Interconnection Process Enhancements (IPE) – Phase 2 draft final proposal:
The Six Cities generally support, or do not oppose, most aspects of the Draft Final Proposal, although they raise questions regarding several of the topics. With respect to the CAISO’s proposal regarding allocation of Transmission Plan Deliverability (“TPD”) to non-load serving entities (“LSEs”), the Six Cities support requiring procurement of the underlying resource adequacy (“RA”) attributes for a period of five years rather than one year as proposed by the CAISO.
2.
Provide your organization’s comments on section 3.1 Transparency enhancements:
The Six Cities do not have comments on this item at this time.
3.
Provide your organization’s comments on section 3.2 criteria for minimum term for PPAs to be eligible for a Transmission Plan Deliverability (TPD) allocation:
The Six Cities have no further comments on this topic and generally support the Draft Final Proposal. For clarity, the Six Cities request that the CAISO’s Final Proposal in this initiative confirm that the relevant PPA term to support the TPD allocation is five years, and that the PPA must provide for procurement of the resource’s resource adequacy capacity for that five year term. The Six Cities understand this latter point to be implied in the Draft Final Proposal and urge the CAISO to make this requirement more explicit to avoid confusion.
4.
Provide your organization’s comments on section 3.2 eligibility criteria for non-LSE PPAs to receive a Transmission Plan Deliverability (TPD) allocation:
As explained in prior comments, the Six Cities do not oppose allowing non-LSE PPAs to receive TPD allocations, provided that the requirements to support such allocations are consistent with the requirements applicable to TPD allocations for projects under PPAs with LSEs. The Six Cities understand the CAISO’s Draft Final Proposal to accomplish that, except for the most important requirement, which is the relevant term for sale of the project’s resource adequacy capacity. The Six Cities understand that, as discussed in the CAISO’s Draft Final Proposal at section 3.1, that a PPA term of five years, including the project’s resource adequacy capacity, is required to support a TPD allocation associated with procurement by an LSE having a resource adequacy obligation. For non-LSE PPAs, however, the CAISO proposes to reduce that requirement down to one year. (Draft Final Proposal at 17.) While it appears that the CAISO will require the PPA with the non-LSE to have a term of five years or longer, the Six Cities interpret the Draft Final Proposal to provide that the underlaying sale of the project’s resource adequacy capacity only needs to be for one year. (Id.) The Six Cities do not support reducing the applicable term of the RA sale transaction for non-LSE PPAs. The purpose of requiring PPAs that show procurement of the resource adequacy attributes by an entity with an RA obligation to assure transmission customers, who ultimately pay for the upgrades needed to provide TPD, that the resource is needed to meet RA requirements. Selling the RA attributes of a project for one year does not meet that requirement, for exactly the same reasons that the CAISO proposes a five year period for the RA capacity to support allocations to LSEs, as the Six Cities understand the CAISO’s proposal in section 3.1.
5.
Provide your organization’s comments on section 4.1: Should higher fees, deposits, or other criteria be required for submitting an IR?
At this time, the Six Cities are inclined to support the CAISO’s conclusion that leaving the existing fee and deposit structure intact may contribute to another “supercluster” in Cluster 15, when the request window becomes available next year. However, the Six Cities also concur with the CAISO that a supercluster may be inevitable irrespective of any changes to the fee/deposit structure.
At this time, the Six Cities are not categorically opposed to the CAISO’s proposed revisions to study fees and deposit structures proposed by the CAISO in the Draft Final Proposal, and the Six Cities understand why the CAISO has chosen to make significant revisions at the Draft Final Proposal stage given FERC’s recent issuance of the Notice of Proposed Rulemaking (“NOPR”) in Docket No. RM22-12-000 addressing Improvements to Generator Interconnection Procedures and Agreements. However, the Six Cities note that the CAISO has abandoned its prior proposal to explicitly scale the required study deposits based on the number of interconnection applications submitted by a single company, presumably in favor of the Commission's proposed approach, which appears intended to address this as well to some extent. In the case of the CAISO, the Six Cities had understood that the issue of parties submitting multiple “exploratory” interconnection requests was a significant contributing factor in the CAISO’s decision to revise its fee structure. It may be that the CAISO footprint requires a different approach, or alternative weighting, as compared with the Commission's proposed approach, and the Six Cities query if the proposal as revised fully addresses the scope and extent of this problem within the CAISO. The Six Cities understand that FERC would have the discretion to approve an alternate fee structure for the CAISO that includes escalators or greater weighting based on the number of interconnection applications submitted as a valid regional difference.
6.
Provide your organization’s comments 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 Six Cities have no further comments on this topic at this time, but note that their prior comments included several questions that were not addressed in the Draft Final Proposal, including:
- 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? The Six Cities note the CAISO’s commitment to post relevant amounts on its website. (See Draft Final Proposal at 32.)
- 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?
- 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?
The Six Cities request that the CAISO confirm, 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 just like any other assets that are under the CAISO’s operational control.
The Six Cities request the CAISO to provide in its Final Proposal additional information on how it will implement this proposal.
7.
Provide your organization’s comments on section 5.2 Policy for ISO as an Affected System – how is the base case determined and how are the required upgrades paid for?
The Six Cities do not have further comments on this item at this time, except to reiterate their earlier comment requesting that the CAISO track upgrade costs associated with the CAISO as an Affected System.
8.
Provide your organization’s comments 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 do not have further comments on this item at this time, and generally support the CAISO’s proposal as set forth in the Draft Final Proposal.
9.
Please provide additional comments on the IPE – Phase 2 Draft Final Proposal not mentioned above:
The Six Cities have no further comments at this time.
