Bay Area Municipal Transmission Group (BAMx)
Submitted 09/16/2022, 03:12 pm
Submitted on behalf of
City of Palo Alto Utilities and Silicon Valley Power (City of Santa Clara)
1.
Please provide a summary of your organization’s comments on the Transmission Service and Market Scheduling Priorities Phase 2 straw proposal and August 11, 2022 stakeholder call discussion:
Bay Area Municipal Transmission Group (BAMx)[1] is pleased to submit these comments on the Transmission Service and Market Scheduling Priorities Phase 2 straw proposal and August 11, 2022 stakeholder meeting.
BAMx supports developing a mechanism for entities with loads outside of the CAISO Balancing Authority Area to be able to obtain priority scheduling rights comparable to native load, but has some concerns about CAISO’s straw proposal. CAISO’s benchmarking in Appendix 2 shows that only two of the four ISO/RTOs include a forward reservation process (PJM and MISO). NYISO and ISO NE do not have such a process. If priority scheduling rights are to be made available by CAISO, they should be made available only after undertaking a reasonable determination of available transfer capability (ATC). Such a determination must account for transmission needed to meet native load needs under stressed system conditions, taking into consideration uncertainty. The party receiving the priority scheduling rights should be required to pay for the associated transmission capacity an amount that is commensurate with the benefits received.
BAMx believes that the analysis and mechanisms used to identify ATC available for wheeling should be used to release additional Maximum Import Capability (MIC) on an annual and monthly basis for native load use, prior to releasing the capacity for wheeling.
[1] BAMx comprises City of Palo Alto Utilities and City of Santa Clara, Silicon Valley Power.
2.
Provide your organization’s comments on the design principles discussed in section 4:
BAMx supports the design principles included in section 4:
- Ensure the CAISO maintains sufficient transmission capacity to meet native load needs reliably while providing non-discriminatory access to the transmission system consistent with open access principles;
- Ensure the framework is compatible with the CAISO’s existing, unique market design and does not unduly disrupt that design;
- Minimize seams issues between the CAISO organized market and the OATT framework prevalent across the west, while recognizing differences between the two frameworks exist;
- Support reliable service to load in the CAISO and across western balancing authority areas; and
- Ensure CAISO has the tools and processes necessary to manage the grid reliably.
3.
Provide your organization’s overall comments on calculating ATC in the monthly horizon, as described in section 5.1.1. In particular, the different approaches for calculating native load needs as an existing commitment and other components of the ATC methodology as discussed in the proposal. The ISO encourages stakeholders to share potential alternative methods for consideration in calculating components, particularly native load needs.
BAMx supports CAISO’s proposal to use a rolling 13-month horizon for calculating monthly ATC, but CAISO should use an increasing Transmission Reliability Margin (TRM) value for each future month to recognize there is greater uncertainty about the availability of transmission and the level of imports needed to serve native load the further one looks to the future. CAISO acknowledged this effect in Section 5.1.1 by planning to utilize more informed (and updated) assumptions in month 1 than in months 2-13. But CAISO should explicitly use higher TRM values for each future month to account for greater uncertainty about loads, transmission topology, and hydrological conditions within California that have a significant impact on the need for imports to serve native load. As the delivery month nears, and the transmission topology, California hydro availability and load forecasts are more certain, and actual RA showings are substituted for historical showings, the TRM could be reduced. More investigation is needed about whether a Capacity Benefit Margin (CBM) should be included, as is done by the two eastern RTOs that have a forward reservation process. If a CBM is not included, the TRM should be increased to address the potential EEA2+ emergency conditions.
4.
Provide your organization’s comments on each of the ISO’s proposed approaches for calculating existing transmission commitments (ETC) as it relates to the ATC methodology as described in section 5.1.1.2. Particularly, the ISO seeks comment on the methods or approaches identified for estimating native load needs across a 13-month horizon and encourages stakeholders to suggest potential variations to inputs in deriving the amount of transmission capacity to set aside for native load needs.
BAMx believes that the ATC methodology needs to take into consideration the amount of transmission reasonably expected to be available to support wheel through transactions, after taking into consideration transmission needed to serve native load under stressed conditions in the CAISO BAA. The approaches being considered by CAISO for determining the amount of transmission available to support wheel through transactions are mostly backwards looking. That is, they rely on historical RA showings or historical net interchange to estimate how much transmission to release for wheel through transactions. The approaches do not appear to consider the potential power flow impacts of the wheels and of resources within CAISO, including potential forced outages, on the deliverability of the proposed wheel through transactions. In contrast, CAISO’s benchmarking in Appendix 2 shows that each of the two RTOs that offer forward reservations incorporate forward looking assumptions about loads and the impacts of internal generation into their ATC assessments. PJM incorporates generation effectiveness factors and MISO includes forced outage rates in its assessment. PJM also has limited dependence on imports, unlike CAISO, so the ramifications for PJM’s native load of overstating the ATC are likely to be less severe than for CAISO. Because CAISO’s approaches rely on historical information, rather than a deliverability assessment using power flow modeling, there could be greater risk on native load that there will be insufficient transmission available to meet native load needs under stressed conditions.
Of the three approaches proposed by CAISO, Approach 3, which uses the higher of the amounts determined to be needed to serve native load of Approach 1 (Historical RA showings) and Approach 2 (Historical Flows), is the most appropriate for ensuring that the transmission capacity that has been, and will be, paid for by native load is first made available to meet native load needs. However, modifications may be needed for both Approach 1 and Approach 2 to ensure that native load needs are protected, consistent with approaches used in other BAAs.
Historical RA showings are based on 1-in-2 loads and are limited by MIC allocations that have been determined using conservative assumptions much further from the delivery month than is being proposed by CAISO for priority wheeling. Because of these factors, CAISO may need to use a significantly higher TRM adjustment to reflect that imports are used to address incremental increases in load above 1-in-2 conditions, and to fill in for reductions in hydro generation availability during dry years. The 5% level used in the analysis for Approach 1 could understate the usage of intertie capacity to address extremely variable hydrological conditions and load variations that are met using imports. BAMx suggests CAISO perform more analysis of the historical reliance on imports to serve load before determining the appropriate TRM adjustment for Approach 1. BAMx notes that historical Import RA showings understate CA LSE potential future usage of their MIC allocations, since parties can use these allocations to address increases in the monthly load forecast, or to address known outages of internal resources ahead of their monthly RA showings, which leads to under-utilization of the potential import capacity for RA showings, but preserves the transmission for market transactions and use during stressed conditions. To address this, CAISO should use a higher TRM as the reservation horizon increases. As the delivery month nears, and California hydro availability and load forecasts are more certain, and actual RA showings are substituted for historical showings, the TRM could be reduced.
For the historical import flows serving native load approach, the data provided by CAISO in the spreadsheets showed that for Malin, there are 1200 MW of existing contracts. During June-September 2021 450 MW were made available to the market, thus 750 MW remained as existing commitment. The implication of this is that analysis implicitly assumes that 450 MW of existing contract rights will continue to be made available to support wheel through transactions, without a commitment by the rights holder to do so. CAISO’s methodology, particularly beyond the prompt month, should not assume that existing contract rights will be available to support wheel through transactions. Similar issues apply for the applicable TRM for the historical import flow approach as for the RA Showings approach.
If CAISO does not adopt a forward looking methodology, it should take a conservative approach to determining the transmission to release. That is, it should use the results from Approach 2A (single highest net load peak per month) and Approach 2B (five highest net load peak hours) to identify the maximum amount of capacity needed to meet native load. CAISO also should use more than just a few years of data to make its determination, since the amount of imports needed for native load can vary greatly based on hydrological conditions.
Whichever approach is used, prior to releasing ATC for wheel through purposes, CAISO should provide an opportunity for CAISO LSEs to obtain incremental MIC consistent with the levels indicated in the analysis for each intertie.
5.
Provide your organization’s comments on the Transmission Reliability Margin (TRM) and the Capacity Benefit Margin (CBM) as it relates to the ATC methodology, as described in section 5.1.1.3:
CAISO should use an increasing TRM value for each future month to recognize there is greater uncertainty about the availability of transmission and the amount of imports needed to serve native load the further one looks to the future. CAISO acknowledged this effect in Section 5.1.1 by planning to utilize more informed (and updated) assumptions in month 1 than in months 2-13. CAISO should explicitly use higher TRM values for each future month to account for greater uncertainty about loads, transmission topology, and hydrological conditions within California that have a significant impact on the need for imports to serve native load. As the delivery month nears, and the transmission topology, California hydro availability and load forecasts are more certain, and actual RA showings are substituted for historical showings, the TRM could be reduced. In addition to these factors, TRM also can account for simultaneous path feasibility and loop flow. CAISO did not describe how it intends to account for simultaneous path feasibility and loop flow in determining the appropriate TRM.
CAISO is not proposing to include a Capacity Benefit Margin (CBM), despite the benchmarking in Appendix 2 – Benchmarking of Practices of RTOs and ISOs, Western Transmission Providers that shows that both ISOs/RTOs that offer forward transmission reservations include a CBM to address EEA2 or higher emergencies. More information is needed about why these entities use a CBM, and the ramifications for including/not including a CBM in the CAISO’s forward reservation process.
6.
Provide your organization’s overall comments on calculating the ATC in the daily horizon, as described in section 5.1.2:
BAMx believes a better approach for the daily ATC calculation would be for CAISO to perform operational engineering studies to calculate the daily ATC, rather than to rely only on the updated transmission topology and updated RA showings or the historical import flows. The latest load forecast and resource availability are critical inputs for determining whether import transmission is likely to be available in excess of native load needs, and these would not be reflected in any of the CAISO’s proposed approaches.
7.
Provide your organization’s comments on calculating existing transmission commitments (ETC), particularly native load needs, as it relates to the calculation of daily ATC, as described in section 5.1.2.2:
CAISO is proposing to calculate daily ATC on a rolling two-day basis prior to running the DAM and therefore can update the different inputs based on the most recent information and grid conditions to derive an ATC value across interties. CAISO is proposing to use updated information about the transmission topology, but would not use updated load forecast information or updated information about internal generation availability, for either the historical RA showing approach or for the historical import flow approach. BAMx believes a better approach for the daily ATC calculation would be for CAISO to perform operational engineering studies to calculate the daily ATC, rather than to rely only on the updated transmission topology and updated RA showings or the historical import flows. The latest load forecast and resource availability are critical inputs for determining whether import transmission is likely to be available in excess of native load needs, and these would not be reflected in any of the CAISO’s proposed approaches.
8.
Provide your organization’s comments on the Transmission Reliability Margin (TRM) and the Capacity Benefit Margin (CBM) as it relates to daily ATC, as described in section 5.1.2.3:
BAMx believes CAISO should include a TRM for the daily ATC calculation, but we would expect the daily TRM could be lower than the forward TRM. Conversely, the CBM likely would need to be consistent with the forward assumptions to address potential EEA2+ conditions.
9.
Provide your organization’s comments on the method for accessing ATC to establish wheeling through scheduling priority, as described in section 5.1.3. In particular, consider comments on the requirements identified for accessing ATC.
CAISO is proposing that parties requesting access to the limited ATC provide a demonstration of an executed firm power supply contract, or demonstration of ownership of a resource to serve external firm load, and pre-payment of the transmission charges equal to the monthly volumes associated with the underlying power supply contract. BAMx suggests an alternative approach that would not require demonstration of a firm contract or ownership, and instead prioritize awards based on the proposed length of service. The minimum pre-payment amount would be for 16 hours for the daily product and one month x 16 hours for all other products. Parties requesting longer terms would receive awards over parties requesting shorter terms. The party would pre-pay for the entire award, with a minimum daily payment for 16 hours and a minimum monthly payment for 16 hours/day for each month. There would need to be a true-up to reflect any changes to the WAC charge over the course of the wheeling priority, since WAC rates can be updated multiple times throughout the year.
10.
Provide your organization’s comments on the proposed enhancement to establish a window during which the submitted requests are vying for limited ATC based upon the underlying duration of the supply contract duration of ATC request as described in section 5.1.3:
See response to Item 9.
11.
Provide your organization’s comments on a wheeling through priority rights holder’s ability to resell the wheeling through scheduling priority as described in section 5.1.3:
If BAMx’s proposed approach to not require the contract demonstration and instead apply a minimum commitment quantity is adopted, there would be no reason to prevent a wheeling through priority rights holder from reselling the wheeling through scheduling priority. If, however, the contract requirement remained, questions would need to be addressed about a comparable underlying contract to support the continued priority.
12.
Provide your organization’s comments on the ISO’s proposal to establish a process through which entities seeking to establish wheeling through priority on a long-term basis (longer than 1-year) can do so through submission of a study request and the ability to fund upgrades on the ISO system, including the ability of import (wheel in) requests driving Maximum Import Capability (MIC) upgrades as described in section 5.1.4:
BAMx supports the study process approach proposed by CAISO for long-term (greater than 1 year) wheeling through priority requests, but opposes the CAISO having the choice of moving forward with the project as a reliability, economic or public policy transmission project. Such upgrades should be identified as part of the CAISO’s Transmission Planning Process and should not be influenced by the wheeling priority process. In other words, although the wheeling through priority requests can be studied along with the generator interconnection requests per the Generator Interconnection and Deliverability Allocation Procedures (GIDAP)[1], the transmission upgrades triggered by them should not be offered the same treatment as the generator interconnection requests. After all, the interconnected generation is primarily procured by California LSEs and used to meet California’s public policy goals. On the contrary, CAISO’s proposed approach could result in CAISO LSEs funding upgrades that are not needed to serve CAISO loads, do not provide economic benefits to CAISO loads commensurate with their costs, and do not meet California’s public policy goals. If such projects otherwise would meet these requirements, then they should be identified and pursued as part of the current Transmission Planning Process. Furthermore, the incremental cost associated with any expansion in the scope of the reliability, economic, or public policy transmission projects identified in the CAISO TPP that is driven by wheeling priority requests should be funded by the requesting wheeling through customer.
[1] CAISO Business Practice Manual, Generator Interconnection and Deliverability Allocation Procedures, 2022.
13.
Provide your organization’s comments on compensation for wheeling through scheduling priority, as described in section 5.1.5, along with any suggestions your organization may have regarding other potential ways to assess transmission charges for high priority wheeling through transactions:
As noted in response to Item 9, the minimum pre-payment amount should be for 16 hours for the daily product and one month x 16 hours for all other products. The party would pre-pay for the entire award, with a minimum daily payment for 16 hours and a minimum monthly payment for 16 hours/day for each month. Shorter durations fail to provide adequate compensation for the fixed costs of the transmission used to support the wheeling through priority. In addition, for any duration less than one year, the rate paid should be a premium over the WAC rate (e.g., 140% of the WAC), consistent with how other BAAs charge a premium for their short-term products. The application of such a premium should not require an overhaul of the CAISO transmission rate design, as it is merely a factor to reflect the fact that the WAC rate is based on annual CAISO load assumptions, while the shorter term wheeling priorities would cover periods less than a year.
14.
Provide your organization’s comments on the proposed WEIM decisional classification, as described in section 6:
For the reasons outlined in Section 6 WEIM Decisional Classification, BAMx supports the CAISO’s conclusion that the proposals in this initiative fall outside the scope of joint authority, and because the proposals contemplate changes to the rules of the real-time market the WEIM Governing Body would have an advisory role regarding these changes.
15.
Provide any additional comments on the Transmission Service and Market Scheduling Priorities Phase 2 straw proposal and August 11, 2022 stakeholder call discussion:
No additional comments at this time.
Calpine
Submitted 09/15/2022, 01:39 pm
1.
Please provide a summary of your organization’s comments on the Transmission Service and Market Scheduling Priorities Phase 2 straw proposal and August 11, 2022 stakeholder call discussion:
The CAISO’s historic practice of allocating all transmission on an hourly basis has failed to adequately facilitate the growing demand for high priority, regional transfer capacity on an open-access, non-discriminatory basis. The “wheeling wars” that spawned significant debate as well as interim rules in 2020, provided undeniable evidence of fundamental open-access issues and disagreements between regional partners.
Calpine appreciates the CAISO’s effort to address this tension by attempting to define its own native load obligations. Calpine does not comment on the technical calculations of native load reservations and leaves that effort to experts.
However, Calpine does have significant concerns, as described below, with the CAISO proposals for acquiring high-priority transmission rights from and through, the CAISO service territory. We expand on these three points in more detail below:
- The CAISO fails to address in any manner, how parties will be allowed to obtain firm export capacity.
- The CAISO’s proposal to tie transmission capacity access to energy contracts with external load serving entities is nationally unprecedented, administratively incomprehensible, discriminatory, and create an unsolvable commercial “chicken-and-egg” problem.
- The CAISO’s proposal to force longer-term transmission service requests into the overheated, impenetrable, interconnection queue is similarly unprecedented.
2.
Provide your organization’s comments on the design principles discussed in section 4:
The principles stated in section 4 suggest a need to design transmission reservation mechanisms that accomodate the CAISO’s “unique market design,” "recognizes differences” and does "not unduly disrupt that design”. Calpine believes that once capacity in excess of native load obligations is established, there is little unique or different about that CAISO capacity when compared to other markets. As such, Calpine would prefer a principle stating that once the CAISO determines its native load obligation, access to the remaining capacity “adheres to the just and reasonable provisions and procedures of Order 888 (OATT) to the maximum extent possible.”
3.
Provide your organization’s overall comments on calculating ATC in the monthly horizon, as described in section 5.1.1. In particular, the different approaches for calculating native load needs as an existing commitment and other components of the ATC methodology as discussed in the proposal. The ISO encourages stakeholders to share potential alternative methods for consideration in calculating components, particularly native load needs.
No Comment
4.
Provide your organization’s comments on each of the ISO’s proposed approaches for calculating existing transmission commitments (ETC) as it relates to the ATC methodology as described in section 5.1.1.2. Particularly, the ISO seeks comment on the methods or approaches identified for estimating native load needs across a 13-month horizon and encourages stakeholders to suggest potential variations to inputs in deriving the amount of transmission capacity to set aside for native load needs.
Calpine would support “Approach 1” to estimating native load capacity requirements at the interties. This approach would set aside capacity that was historically contracted under Resource Adequacy provisions (plus, possibly an accommodation for load growth.) Approach 1 preserves the value of the RA program – which in itself is based on reliability metrics – and supports future competitive contracting.
Calpine does not support the alternatives (2, 2A, 2B, 2C, 3) which propose to allocate scarce intertie capacity to native load based on all historical import flows across interties (presumptively adjusted for wheels and exports). This approach includes both economic- and reliability-based transactions. In essence, it would create a superior priority for native load inappropriately based on historic economics, not on reliability metrics. It would do nothing to encourage future RA contracting at the ties.
5.
Provide your organization’s comments on the Transmission Reliability Margin (TRM) and the Capacity Benefit Margin (CBM) as it relates to the ATC methodology, as described in section 5.1.1.3:
No Comment
6.
Provide your organization’s overall comments on calculating the ATC in the daily horizon, as described in section 5.1.2:
No Comment
7.
Provide your organization’s comments on calculating existing transmission commitments (ETC), particularly native load needs, as it relates to the calculation of daily ATC, as described in section 5.1.2.2:
No Comment
8.
Provide your organization’s comments on the Transmission Reliability Margin (TRM) and the Capacity Benefit Margin (CBM) as it relates to daily ATC, as described in section 5.1.2.3:
No Comment
9.
Provide your organization’s comments on the method for accessing ATC to establish wheeling through scheduling priority, as described in section 5.1.3. In particular, consider comments on the requirements identified for accessing ATC.
Calpine does not support the proposals included in Section 5.1.3.
First, we observe that the discussion does not address any conditions, process, or requirements to obtain high priority export service. This service should be a point-to-point service from a resource to an export point that has the same priority as load. The relative priorities of firm exports, wheeling and load must be addressed in the next draft of this initiative.
Second, the conditions of section 5.1.3 create an unsolvable chicken-and-egg problem. The proposed provisions require that in order to qualify for short-term firm transmission service, one must be able to demonstrate an energy consumption contract with an external load-serving entity. Hence a chicken-and-egg – one cannot reasonably execute a delivery contract without transmission and, if the CAISO proposal stands, one cannot get transmission without a contract.
To Calpine’s knowledge, no other OATT in the nation has a requirement tying wheeling or export service to a contract with an external load serving entity – and for good reason. Energy and capacity delivery contracts (especially, ones that attempt to overcome the CAISO’s past practices and the legacy of the “wheeling wars”) will require a demonstration of high priority transmission. Simply put from a commercial standpoint, transmission acquisition must precede supply contracting.
In the next draft of this proposal, if this tying arrangement survives, the CAISO must describe why it is necessary. Specifically, why is the CAISO concerned whether load is being served under long-term, short term, sporadic or opportunistic supply arrangements as long as it is receiving the fully allocated cost-of-service for the reserved transmission?
Third, the CAISO appears to further restrict transmission contracting to the hours of delivery in the underlying LSE supply contract. Again, no other OATT on the planet has a restriction that says, if you buy transmission, you only get priority for the hours in the underlying supply contract. Calpine questions the ability (or wisdom of doing so, even if possible) of the CAISO differentiating transmission rights on an hourly basis – conditions that may change day-to-day or month to month. In other OATT markets, an entity that is paying the full cost-of-service for capacity that is in excess of native load requirements has the rights to use it if, whenever, and however they choose. The CAISO should not depart from this simple and widely accepted precedent.
Fourth, the CAISO proposes that an entity that has a 6 by16 contract would have priority over an entity that has a 5 by 16 contract. Again, if this proposal survives, the CAISO must provide an explanation of the economic efficiency that is promoted by this “hours-based” preference and access mechanism.
These conditions would all create the need for new systems, allocation rules, business practices and ultimately costs. They will raise the reasonable risk premia charged in the market, will create great need for training and will likely result in unintended consequences.
Alternatively, Calpine suggests that the CAISO pattern wheel and export transmission access like all other just and reasonable FERC OATT point-to-point rules. These rules are based on posting available transmission (ATC), request windows, principles of first-come, first-served, full cost-of-service and no undue restrictions on use or resales. Several vendors (including the CAISO’s consultant, OATI) could stand-up a reservation system quickly and at very low cost.
10.
Provide your organization’s comments on the proposed enhancement to establish a window during which the submitted requests are vying for limited ATC based upon the underlying duration of the supply contract duration of ATC request as described in section 5.1.3:
See Answer 9
11.
Provide your organization’s comments on a wheeling through priority rights holder’s ability to resell the wheeling through scheduling priority as described in section 5.1.3:
See Answer 9
12.
Provide your organization’s comments on the ISO’s proposal to establish a process through which entities seeking to establish wheeling through priority on a long-term basis (longer than 1-year) can do so through submission of a study request and the ability to fund upgrades on the ISO system, including the ability of import (wheel in) requests driving Maximum Import Capability (MIC) upgrades as described in section 5.1.4:
Calpine sees no reason why the CAISO cannot adopt an analysis and study process similar to other Transmission Operators. Most TOs maintain two separate queues – one for transmission service and another for generation interconnection service. Transmission service requests that cannot be satisfied with available, posted, ATC are studied independently and are processed under tariff-based timelines independent of, and generally much more quickly than generation interconnection requests.
On the other hand, the CAISO proposes to insert transmission service requests into the generation cluster process. Without further explanation and detailed timelines, Calpine objects to this proposal as it could have the following effects:
- Places a one-year transmission service request behind over 200 Gigawatts of long-lived generation interconnection requests.
- Results in a minimum processing period of two and a half years
- Requires a significant rewrite of the GIDAP, to revise elements like site-control, electrical characteristics, modeling files, study deposits and credit requirements.
- Places all transmission service requests in the same queue window, possibly delaying submissions and defeating the widely-accepted principle of first-come, first-served.
The proposal also grants the CAISO a unilateral “right-of-first-refusal” to build transmission projects proposed in the cluster process and needed to support a transmission service request. An entity that seeks transmission service could therefore have to wait for (1) the queue cluster process to clear (2.5 years) and (2) the full processing of the next sequential TPP process (another 1.5 years) before upgrades would be considered. If an entity is willing to pay for an upgrade, Calpine sees no need for this ROFR.
Finally, the CAISO should clarify its proposal for the nature and duration of rights granted to entities willing to fund upgrades in order to receive firm rights. For instance, why would an investor only receive transmission credits and not all attributes, including the value of congestion and or reductions in losses? Would the rights be granted for the life of the facilities? Would the rights be protected from degradation because of load growth or generation interconnection? Would the CAISO commit to capital investment to avoid such degradation? How would this process interact with merchant development of transmission where the owner can seek full cost-of-service, rate-of-return ratemaking and regulation?
13.
Provide your organization’s comments on compensation for wheeling through scheduling priority, as described in section 5.1.5, along with any suggestions your organization may have regarding other potential ways to assess transmission charges for high priority wheeling through transactions:
No Comment
14.
Provide your organization’s comments on the proposed WEIM decisional classification, as described in section 6:
No Comment
15.
Provide any additional comments on the Transmission Service and Market Scheduling Priorities Phase 2 straw proposal and August 11, 2022 stakeholder call discussion:
Thanks
NV Energy
Submitted 09/15/2022, 07:04 am
1.
Please provide a summary of your organization’s comments on the Transmission Service and Market Scheduling Priorities Phase 2 straw proposal and August 11, 2022 stakeholder call discussion:
Since the start of operations in March 1998, the CAISO has provided wheel-through transmission from the Northwest to the Desert Southwest. While CAISO experienced rolling blackouts in August 2020, these events were not caused by wheel-through transactions.[1] Nevertheless, CAISO acted in April 2021, right before the start of the critical summer season, to impose new, interim restrictions on wheel-though transactions. As approved by FERC in June 2021,[2] and as implemented by CAISO on August 4, 2021, entities can establish a firm (“high scheduling priority”) transmission reservation by registering a wheel-through transaction at least 45 days ahead of the month and demonstrating: (1) a firm power supply contract to serve an external Load Serving Entity’s load throughout the month, and (2) transmission for the month has been procured to deliver the supply to the CAISO border. According to a recent DMM report, a maximum of 408 MW of high priority wheels were used to cross CAISO’s system in July 2022.
On January 27, 2022, CAISO filed to extend the interim wheeling approach through May 31, 2024, to allow the CAISO and stakeholders additional time to develop a durable scheduling priorities framework, while providing certainty regarding the rules for wheeling through the CAISO system during the summer of 2023. On March 15, 2022, FERC approved the extension.[3]
NV Energy appreciates the opportunity to comment on the Initial Phase 2 Straw Proposal. We recognize the challenge for CAISO Staff to balance the needs of CAISO native loads with providing open access transmission to customers across the CAISO Controlled Grid in a manner commensurate with what the other western transmission providers offer under their FERC-mandated OATTs.
On July 29, 2022, CAISO posted the Initial Phase 2 Straw Proposal. The schedule in section 7, anticipates that the initiative will come to the Board of Governors for a decision in March of 2023. A FERC filing in April 2023 would mean a decision in June 2023, less than a year prior to the Summer 2024 season. Moreover, this is likely a “best case”. In accordance with its state requirements, NV Energy manages resource procurement by submitting an integrated resource plan every three years with a Supply Plan that is updated in years two and three. Accordingly, NV Energy is already looking for supply not only for the Summer of 2023, but also for the Summer of 2024. If a decision from FERC is not expected until June 2023, NV Energy would have finished two full requests for proposals (RFPs) for Fall 2022 and Spring 2023 that would be soliciting for Summer 2024 supply. Without certainty on rules, it will be difficult to execute on any high priority wheel through transactions which will lower the amount of available supply to participate in the RFPs. The CAISO should do everything feasible to bring what is likely to be a contested proceeding to FERC at the earliest possible date.
[1] See the CAISO’s April 28, 2021 filing letter in Docket No. ER21-1790 at 7 (“[t]he CAISO did not observe consequential wheeling through transactions during last summer’s load shed events . . .”).
[2] Cal. Indep. Sys. Operator Corp., 175 FERC ¶ 61,245 (2021).
[3] Cal. Indep. Sys. Operator Corp., 178 FERC ¶ 61,182 (2022).
2.
Provide your organization’s comments on the design principles discussed in section 4:
The CAISO proposes five criteria to guide the initiative:
- Ensure the CAISO maintains sufficient transmission capacity to meet native load needs reliably while providing non-discriminatory access to the transmission system consistent with open access principles;
- Ensure the framework is compatible with the CAISO’s existing, unique market design and does not unduly disrupt that design;
- Minimize seams issues between the CAISO organized market and the OATT framework prevalent across the west, while recognizing differences between the two frameworks exist;
- Support reliable service to load in the CAISO and across western balancing authority areas; and
- Ensure CAISO has the tools and processes necessary to manage the grid reliably.
With respect to the first criteria, it should be modified to “Ensure the CAISO maintains sufficient transmission capacity to support the external reservations of native load customers while providing non-discriminatory access to the transmission system consistent with open access principles. Consistent with the OATT principle, transmission reservations for network customers should be based on the CAISO LSE’s demonstration that they own or have committed to purchase the generation pursuant to an executed contract.
In addition, NV Energy would offer an addition to the second criteria so that it includes supporting the resource sufficiency requirements of EIM and EDAM. As the CAISO noted in Initial Phase 2 Straw Proposal:
There are interdependencies between this initiative and the Extended Day Ahead Market Enhancements (EDAM) initiative. The EDAM design reflected in in the EDAM straw proposal contemplates that entities depending upon import resources to meet their resource sufficiency evaluation will need to demonstrate and make available to the market high quality transmission associated with the delivery of that import, i.e., “Bucket 1” transmission. This ensures that high quality transmission supports resources used to demonstrate resource sufficiency, instilling further confidence in transfers and making high quality transmission available to the market to support transfers between EDAM balancing authority areas.
If the goal of this initiative is to establish a durable, long-term framework, it must also be compatible with the anticipated EDAM design.
3.
Provide your organization’s overall comments on calculating ATC in the monthly horizon, as described in section 5.1.1. In particular, the different approaches for calculating native load needs as an existing commitment and other components of the ATC methodology as discussed in the proposal. The ISO encourages stakeholders to share potential alternative methods for consideration in calculating components, particularly native load needs.
As the transmission provider, CAISO bears the burden to establish its native load obligations, as well as the amount of transmission capacity required to serve native load, and CAISO must justify any conditions that it seeks to impose upon the customers’ transmission service.[1] FERC has recognized that a transmission provider may reserve in its calculation of ATC transmission capacity necessary to accommodate native load growth reasonably forecasted in its planning horizon however “the Transmission Provider is obligated to provide transmission service to others… out of capacity reserved for native load growth up to the time the capacity is actually needed for such future needs.”[2] Additionally, “[n]ative load growth may be considered by the Transmission Provider in its calculation of its ATC, so long as the claimed load growth is reasonably forecasted and is supported by a reasonable plan for network resources to meet that native load growth.”[3] Stated another way, a transmission provider cannot simply identify a level of load growth but must identify an expected load growth.
For example, CAISO cannot simply equate a certain percentage of load growth with an increased native load reservation on each and every intertie. Rather there must be a connection to a plan of service similar to the CAISO’s recent solicitation of interest in external wind resources.[4] Increased reservations with the Pacific Northwest would not be needed if CAISO LSEs plan to meet that load growth through a combination of: (1) in-state storage and other in-state resources, (2) off-shore wind, (3) out-of-state wind imported into Southern California from SWIP North, TransWest Express, Sunzia, or other projects connected into southern California, (4) geothermal from Imperial Valley or Nevada connected into southern California, or (5) rooftop solar or distributed generation resources.
CAISO proposes to calculate a monthly ATC value, across a rolling 13-month horizon, stating that this is “largely consistent with the horizon other western transmission providers use, under their OATTs, to calculate monthly firm ATC.” As noted below in response to Question 12, the CAISO misapplies the OATT practice by missing a key step – making an evaluation whether ATC is available, even for a request of more than a year, before initiating a study process. To be clear, the CAISO’s proposed process sets up a discriminatory preference for California LSEs who may engage in multi-year forward contracts. Thus, for any supply agreement with duration more than a year in advance, CAISO LSEs are the only potential counterparties.
[1] Sierra Pacific Power Co., 143 FERC ¶ 61,144 (2013) at P. 115.
[2] Order No. 888, FERC Statutes and Regulations, Regulations Preambles January 1991-June 1996 P 31,036, at pp. 31,693-94; and Order No. 888-A, FERC Statutes and Regulations P 31,048, at pp. 30,219-21.
[3] Arizona Public Service Company v. Idaho Power Company, 87 FERC ¶ 61,303 (1999), on reh’g 89 FERC ¶ 61,061 (1999) at 61,203.
[4] 2021-2022 Transmission Planning Process - Accessing Out-of-State Wind Resources: ISO Responses to Comments, Request for Expressions of Interest Posted (caiso.com).
4.
Provide your organization’s comments on each of the ISO’s proposed approaches for calculating existing transmission commitments (ETC) as it relates to the ATC methodology as described in section 5.1.1.2. Particularly, the ISO seeks comment on the methods or approaches identified for estimating native load needs across a 13-month horizon and encourages stakeholders to suggest potential variations to inputs in deriving the amount of transmission capacity to set aside for native load needs.
The CAISO proposes to calculate ATC across a rolling 13-month horizon and permit entities seeking to wheel through the CAISO to establish a firm transmission scheduling priority by reserving that ATC in advance. CAISO proposes to set aside: (1) a reasonable amount of transmission capacity for meeting native load needs, and (2) transmission capacity to account for different uncertainties because the monthly ATC is calculated far in advance of need. CAISO then potentially doubles up on this uncertainty by applying a transmission reliability margin (TRM) and/or a capacity benefit margin (CBM).
CAISO identifies several approaches to determining the native load set-aside. Approach 1 is based on historical monthly Resource Adequacy showings. Approach 2 is based on historical import flows across interties attributable to serving native load. This would either represent native load needs based on the volume of imports during the single highest net load peak hour for the month; represent native load needs based on the average volume of imports during the five highest net load peak hours for the month; or represent native load needs based on the average volume of imports during the highest 10% of net load peak hours for the month. Approach 3 would be the “higher of” approaches 1 and 2.
NV Energy notes that none of the approaches are based on prospective supply contracts executed by CAISO LSEs for identified physical capacity that is firmly deliverable to the CAISO boundary as is the practice under the Commission’s OATT. NV Energy also challenges CAISO’s description of a 13-month projection as “far in advance”. Again, FERC’s requirement is that the transmission provider is obligated to provide transmission service to others out of capacity reserved for native load growth up to the time the capacity is actually needed for such future needs.
Moreover, with respect to Approaches 1 and 2, CAISO should provide additional information on the proposed TRM and CBM methodology. NV Energy would strongly oppose Approach 3 as it would provide an improper level of conservativeness with respect to native load reservations.
5.
Provide your organization’s comments on the Transmission Reliability Margin (TRM) and the Capacity Benefit Margin (CBM) as it relates to the ATC methodology, as described in section 5.1.1.3:
NV Energy utilizes a TRM, to meet its obligations under the Wester Power Pool Reserve Sharing Agreement. A total TRM of 375 MW is allocated 175 MW to the Sierra Pacific northern system and 200 MW to the Nevada Power southern system. NV Energy does not reserve a CBM. An examination of the OASIS shows that none of the Desert Southwest transmission providers set aside CBM.[1]
NV Energy recognizes that FERC indicated in Order No. 890 that transmission providers may set aside TRM for (1) load forecast and load distribution error, (2) variations in facility loadings, (3) uncertainty in transmission system topology, (4) loop flow impact, (5) variations in generation dispatch, (6) automatic sharing of reserves, and (7) other uncertainties as identified through the NERC reliability standards development process. However, care must be taken to prevent double-counting of uncertainty as it will lead to an unnecessary reduction in ATC. This is especially true under the CAISO proposals where, unlike the methodology typical of OATT providers, CAISO is not basing the reservation of native load only on actual forward contracts, but includes a factor for historical usage and uncertainty under different conditions.
In the Straw Proposal, CAISO repeats the Order No. 890 factors but does not provide examples on how they would be applied. Rather, CAISO “expects” a TRM of 2-10% across interties. This is an extremely wide range. In the next iteration of the Straw Proposal, CAISO should provide additional detail on the methodology that will be used for any final determinations and justifications with respect to TRM and CBM.
[1] NV Energy, Capacity Benefit Margin Policy (“NV Energy Transmission Service Provider (TSP) has not defined a need to maintain CBM on any of its interfaces in the Operating, Planning, or Study Horizons. As such, the importing and exporting CBM on all interfaces is set to zero.”), available at http://www.oasis.oati.com/NEVP/. Arizona Public Service Co. CBM is currently set at zero for all ATC paths for all periods. See http://www.oasis.oati.com/azps/index.html; Salt River Project does not currently set aside CBM. Seehttp://www.oasis.oati.com/SRP/index.html; It is Tucson Electric Power Company’s (“TEP”) practice to not set aside transfer capability for CBM. Therefore, TEP’s CBM value is set to zero (0). Should TEP determine that it is necessary to use an amount other than zero (0) for CBM, TEP will post the required information on its OASIS, including any required reasons and or methodology used in determining the CBM and location, See TEP Capacity Benefit Margin Implementation Document, http://www.oatioasis.com/tepc/index.html.
6.
Provide your organization’s overall comments on calculating the ATC in the daily horizon, as described in section 5.1.2:
The CAISO proposes to calculate Daily ATC across a rolling 2-day horizon ahead of the Day Ahead Market close. Going into the Day-Ahead Market, external entities could know whether they have secured ATC to support a firm wheeling through transaction. In the daily ATC horizon, the CAISO will calculate existing uses similar to the manner in the monthly horizon with the addition that CAISO would include wheel through transactions that secured firm scheduling rights in the monthly time horizon.
NV Energy strongly supports the development and implementation of the day-ahead firm transmission product. Daily firm transmission service is required under the OATT. It also can be a vital tool in EDAM. As noted in the EDAM Revised Straw Proposal,
This revised straw proposal maintains the bucket 1 transmission framework whereby each BAA must make bucket 1 transmission available to the market to support resource sufficiency plans across an intertie with an adjoining EDAM BAA. As such, bucket 1 would consist of transmission rights held by transmission customers of the EDAM entity or other transmission service providers within the EDAM BAA that have contractual agreements for energy or capacity transfers used for RSE accounting purposes in the day-ahead timeframe. In other words, if EDAM entity A relies on a resource located in the adjacent EDAM entity B area, EDAM entity A would need to bring bucket 1 transmission to deliver that resource across the interface.
Bucket 1 transmission must be firm or conditional firm for the market to have confidence in reliable transfers.
Depending on the elements that support any TRM holdback, these could be adjusted from the monthly process based on shorter-term forecasts and current system conditions.
7.
Provide your organization’s comments on calculating existing transmission commitments (ETC), particularly native load needs, as it relates to the calculation of daily ATC, as described in section 5.1.2.2:
Please see response to (6).
8.
Provide your organization’s comments on the Transmission Reliability Margin (TRM) and the Capacity Benefit Margin (CBM) as it relates to daily ATC, as described in section 5.1.2.3:
Please see response to (6).
9.
Provide your organization’s comments on the method for accessing ATC to establish wheeling through scheduling priority, as described in section 5.1.3. In particular, consider comments on the requirements identified for accessing ATC.
The CAISO proposes that ATC be accessible on a first-come first-served basis by qualified entities seeking to wheel through the CAISO system. Monthly ATC can be accessed during the period for which it is calculated, effectively up to 365 days in advance and up to 30 days prior to flow. Daily ATC can be accessed three days prior to flow and up to one day prior to flow by the close of the DA market for the applicable day (10am). The CAISO further proposes that wheeling through scheduling priority be established for the period of the underlying duration of the supply contract supporting the wheeling through priority. For example, if the underlying supply contract provides for firm energy delivery on a 6x16 basis (6 days a week, 16 hours), the wheeling through scheduling priority is established for that particular period. The periods for which wheeling through scheduling priority may be established would be commensurate with the duration of resource adequacy imports that can be secured, e.g., 7x24, 6x16, 6x8, and 6x4, as described further in section 5.1.5. NV Energy supports these proposals.
The CAISO proposes the following pre-requisites must be met in order to access the limited ATC: (1) demonstration of an executed firm power supply contract to serve external load, a firm power supply contract to serve external load where execution is contingent upon the availability of wheeling through scheduling priority on CAISO’s system, or demonstration of ownership of a resource to serve external load; and (2) pre-payment of transmission charges equal to the monthly volumes associated with the underlying power supply contract. Similar to California resource adequacy contracts, CAISO proposes that wheeling through transactions establishing firm service have a duration each month no less than 6x4.
NV Energy supports the requirement that in order to secure firm transmission service the customer demonstrate a contract to serve load. The requirements are similar to those associated with external Designated Network Resources under the OATT paradigm and will help prevent speculation over extremely limited transmission. The CAISO has not demonstrated that pre-payment is necessary. This requirement should be removed from the next proposal as it is unduly discriminatory to the non-CAISO LSEs. Under the existing CAISO Tariff and the OATT’s of the external parties, there is no pre-payment of transmission charges. Rather these are assessed on a monthly basis after-the-fact. Moreover, pre-payment is not needed to differentiate firm transmission from non-firm under the CAISO proposal. Firm transmission is charged on a demand basis based on the type of contract. Non-firm transmission continues to be charged only for the hours in which the energy actually flowed.
One aspect of the requirements of interest is what is not there – a requirement that the external agreement have firm transmission to the California border to secure firm transmission across the CAISO Controlled Grid. At first glance, this change from the current interim rules associated with high priority wheels appears less discriminatory – neither the CAISO LSEs nor the external LSEs need to secure firm transmission to secure firm service into and across CAISO. Upon further analysis, this change appears to be inconsistent with OATT policy and EDAM and could send improper price signals regarding the value of firm transmission external to California. In a pleading before the CPUC, CAISO has noted,
it is common practice among other ISOs to require RA imports be supported by Firm transmission from source to sink which has the highest curtailment priority. Similarly, under non-organized market pro-forma OATT, when it comes to service to Native Loads and Network Loads by “off-system” (import) designated network resources, these resources must be delivered to the BAA on Firm transmission service because these resources are critical to the LSEs ability to serve load.[1]
Again CAISO recognized, under the OATT,
A load serving entity seeking to designate an off system network resource must provide: (a) the source balancing authority area where the resource is located; (b) the transmission arrangements supporting delivery of the “off-system” resource, which must be on firm or conditional firm transmission across intervening transmission systems to the border with the balancing authority area, for the duration of the designation period; and (c) an attestation the capacity is under contract and not committed to any other third parties. Independent system operators and regional transmission organizations impose similar requirements on imports providing resource adequacy or capacity.[2]
The CAISO went on to state that the firm service requirement was, “intended to ensure import resources dedicated to serving load are not speculative and provide greater assurance of delivery to the border with the balancing authority area even when there are supply shortages or conditions across intervening systems may be transmission constrained.”
Thus, the better question may be not why is the CAISO removing the requirement for wheel-through transactions but rather why is the CAISO not imposing a firm transmission requirement to the CAISO border for CAISO resource adequacy resources that will qualify for an allocation of the firm import transmission capacity. Indeed, the practice of all other RTOs and the pro forma OATT appears to be reflected in the Revised EDAM Straw Proposal.
This revised straw proposal maintains the bucket 1 transmission framework whereby each BAA must make bucket 1 transmission available to the market to support resource sufficiency plans across an intertie with an adjoining EDAM BAA. As such, bucket 1 would consist of transmission rights held by transmission customers of the EDAM entity or other transmission service providers within the EDAM BAA that have contractual agreements for energy or capacity transfers used for RSE accounting purposes in the day-ahead timeframe. In other words, if EDAM entity A relies on a resource located in the adjacent EDAM entity B area, EDAM entity A would need to bring bucket 1 transmission to deliver that resource across the interface.
Bucket 1 transmission must be firm or conditional firm for the market to have confidence in reliable transfers.[3]
Absent the requirement that both CAISO LSEs and Non-CAISO LSEs retain the same firm to-the-border requirement, CAISO is creating a dynamic where CAISO LSEs do not need to compete for and properly support the value of firm transmission on external transmission systems. Simply by exercising monopoly control over what goes into and through the CAISO Controlled Grid, CAISO dictates usage of the external transmission, as the CAISO recognized in the Resource Adequacy Enhancements Draft Final Proposal-Phase 1 and Sixth Revised Straw Proposal:
There is a reason why the eastern ISO/RTOs have required that resource adequacy imports be supported like native load in the host balancing authority areas. It sends the signal for parties to procure that service, either from the transmission provider or from the secondary markets. Secondly, if firm transmission is not available, it sends the signal that there may be a need for additional enhancements on existing transmission systems external to the CAISO. Such enhancements may be necessary if California intends to count resource adequacy imports to meet its requirements. It also sends the strong signal to existing holders of firm transmission rights and other parties that there may be an opportunity to trade their rights through secondary markets. Firm transmission procured through such secondary markets retains the firmness of the service traded. Although this might affect the cost of obtaining these arrangements, it may be necessary to ensure California load is served by dependable imports. If California seeks to ensure that dependable capacity is available to it, it must take the actions necessary to ensure that result.[4]
The CAISO must approach the wheel-through initiative and EDAM in a consistent, coordinated manner. Bucket 1 firm transmission should be part of both the resource adequacy and resource sufficiency expectations.
[1] California Independent System Operator Corp., Final Track 3.B Proposals at Attachment B page 39, CPUC Docket. No. 19-11-009 (Dec. 19, 2020) (emphasis added), http://www.caiso.com/Documents/Dec18-2020-FinalTrack3BProposals-ResourceAdequacy-Exhibits-R1911009.pdf In that same pleading, CAISO goes on to state,“Firm transmission rights on interties are used to meet the needs of utilities across the west.” Id. at 47-48.
[2] California Independent System Operator Corp., Track 3B.1 Proposals at 4-5, CPUC Docket. No. 19-11-009 (Jan. 28, 2021), https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M362/K887/362887738.PDF .
[3] August 16, 2002, Revised Straw Proposal at 26 (emphasis added).
[4] California Independent System Operator Corp., Reply Comments on Workshop Report and Proposals at 10-11, CPUC Docket. No. 19-11-009 (Mar. 6, 2020), http://www.caiso.com/Documents/Mar11-2020-ReplyComments-WorkshopReport-Proposals-ResourceAdequacy-R19-11-009.pdf.).
10.
Provide your organization’s comments on the proposed enhancement to establish a window during which the submitted requests are vying for limited ATC based upon the underlying duration of the supply contract duration of ATC request as described in section 5.1.3:
The CAISO is contemplating establishing a limited window during which entities seeking a wheeling through priority submit a request for the limited ATC across an intertie with the request(s) having the longer underlying supply contract receiving preference to the ATC over those supported by a shorter underlying supply contract. For example, a request for ATC to establish wheeling through priority based on an underlying 6x16 supply contract would have preference to the ATC over a 6x8 or a 6x4 supply contract to the extent there is not sufficient ATC to accommodate all requests.
For example, all requests submitted on the same day would compete against each other so that after the request submission period there is certainty regarding who has established scheduling priority. The same process could apply to accessing ATC in the daily timeframe. A request seeking to establish priority for 16 hours would have preference over one seeking to establish priority for 8 or 4 hours.
NV Energy does not have a comment on this aspect of the proposal.
11.
Provide your organization’s comments on a wheeling through priority rights holder’s ability to resell the wheeling through scheduling priority as described in section 5.1.3:
The CAISO proposes that the holder of an established wheeling through scheduling priority can resell the firm transmission right during the term of the priority and based upon the underlying duration of the supporting supply contract. NV Energy supports the proposal with conditions to prevent this proposal to be an end-run of the original requirements. First the reseller should be required to record, subject to DMM’s review the reason for the changed conditions supporting the resale. Second, the buyer must meet the original qualifying conditions, specifically an executed firm power supply contract to serve external load, a firm power supply contract to serve external load where execution is contingent upon the availability of wheeling through scheduling priority on CAISO’s system, or demonstration of ownership of a resource to serve external load.
12.
Provide your organization’s comments on the ISO’s proposal to establish a process through which entities seeking to establish wheeling through priority on a long-term basis (longer than 1-year) can do so through submission of a study request and the ability to fund upgrades on the ISO system, including the ability of import (wheel in) requests driving Maximum Import Capability (MIC) upgrades as described in section 5.1.4:
The CAISO proposes that any request for firm transmission service more than 13 months out would automatically be assigned to the “annual” interconnection request study process. NV Energy understands that the current CAISO interconnection queue contains approximately 236,000 MW of renewable capacity and storage and that study process for the April 2021 supercluster with 62% of the resources will be complete by November 24, 2023. NV Energy further understands that the interconnection cluster 15 study was delayed from April 2022 to April 2023 and that the volume of projects seeking in-service dates of 2026 or earlier is 10 times the amount required to be procured to meet CPUC preferred system plan targets. Thus, the CAISO’s proposal appears to consign any wheeling request greater than a year in length or greater than a year in advance to a prolonged odyssey rather than promote a realistic path consistent with OATT practice.
First, CAISO’s proposal fails to treat interconnection and transmission as separate products with separate queues contrary to long-standing FERC policy.[1] Thus, priority in the interconnection queue does not automatically translate to priority in the award of transmission capacity.[2] By studying the requested transmission service with generator interconnections, the CAISO is arbitrarily assigning transmission capacity to generator interconnections during the study process which would lead to more significant and costly transmission upgrades.
Second, by directly assigning the request to the interconnection study queue, CAISO omits a crucial step from the OATT. Under the OATT, “The Transmission Provider shall notify the Eligible Customer as soon as practicable, but not later than thirty (30) days after the date of receipt of a Completed Application either (i) if it will be able to provide service without performing a System Impact Study or (ii) if such a study is needed to evaluate the impact of the Application.” CAISO simply assumes a study is always needed.
If, for example, NV Energy seeks to purchase 50 MW of capacity in September 2024 not only for the following summer, but also for the Summer of 2026, CAISO’s response is not to even look to see if that would be feasible based on existing ATC. Rather, it is to consign the request to a process that is unlikely to have an outcome prior to the requested service date.
After releasing the facility study, the CAISO will have “first choice” to move forward with the project as a reliability, economic, or public policy transmission project if it meets the applicable criteria under the tariff. If so, the CAISO will reimburse the facility study cost to the original requestor and any other requesting party. If the CAISO does not approve the project under one of these transmission categories, the entity – whether a wheeling through customer or some other entity -- can choose whether to proceed with the transmission upgrade. CAISO should clarify that it not necessarily an elective “choice” but rather a test to see if the project meets the applicable criteria.
[1] Tennessee Power Co., 90 FERC ¶ 61,238, at 61,761-62 (2000) (interconnection service is separate from and does not convey a right to transmission delivery service); Entergy Services, Inc., 91 FERC ¶ 61,149, at 61,559 (2000); Arizona Public Service Co., 94 FERC ¶ 61,027 at 61,076, order on reh'g, 94 FERC ¶ 61,267 (2001). See also Interstate Power & Light Co. v. ITC Midwest, LLC, 144 FERC ¶ 61,052 at P 36 (2013) (“[E]ach generator, or other transmission customer, seeking to use the transmission system to deliver power from the generator must take transmission service and pay the transmission provider’s transmission service rates separate from paying for any interconnection-related network upgrade costs”).
[2] This distinction is reflected in longstanding precedent, Order No. 2003, and the OATT. Order No. 2003, the Commission explained at P 23 that “Interconnection Service or an interconnection by itself does not confer any delivery rights from the Generating facility to any points of delivery.” Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003, FERC Stats. & Regs. ¶ 31,146, 104 FERC ¶ 61,103 at P 23 (2003) (citations omitted) (“Order No. 2003”), order on reh’g, Order No. 2003-A, FERC Stats. & Regs. ¶ 31,160 (2004) (“Order No. 2003-A”), order on reh’g, Order No. 2003-B, FERC Stats. & Regs. ¶ 31,171 (2004) (“Order No. 2003-B”), order on reh’g, Order No. 2003-C, FERC Stats. & Regs. ¶ 31,190 (2005) (“Order No. 2003-C”), aff’d sub nom. National Association of Regulatory Utility Commissioners v. FERC, 475 F.3d 1277 (D.C. Cir. 2007).
13.
Provide your organization’s comments on compensation for wheeling through scheduling priority, as described in section 5.1.5, along with any suggestions your organization may have regarding other potential ways to assess transmission charges for high priority wheeling through transactions:
The CAISO states that applying the transmission charge only during hours when the priority wheeling through is scheduled does not reflect the value conferred to a priority wheeling through customer and proposes that high priority wheeling through transactions prepay for transmission access based upon the underlying quantity and duration of the power supply contract supporting the wheel through transaction to serve external load.
While CAISO would continue to charge its own LSEs on an energy basis, NV Energy can support the proposal to charge firm transmission customers on a demand basis in accordance with the quantity and duration of their supply contract. This is a unique application combining a rate based on energy usage to a demand charge. NV Energy would not support application of a 24/7 demand charge unless the CAISO converts its own LSEs to a similar demand charge for transmission usage.
As noted in response to Question 9, the CAISO has not demonstrated that pre-payment is necessary. This requirement should be removed from the next proposal. Under the existing CAISO Tariff and the OATT’s of the external parties, there is no pre-payment of transmission charges. Rather these are assessed on a monthly basis after-the-fact. Moreover, pre-payment is not needed to differentiate firm transmission from non-firm under the CAISO proposal. Firm transmission is charged on a demand basis based on the type of contract. Non-firm transmission continues to be charged only for the hours in which the energy actually flowed. Based on the CAISO Tariff language, a pre-payment requirement from third party transmission system users seems discriminatory in nature.
14.
Provide your organization’s comments on the proposed WEIM decisional classification, as described in section 6:
The CAISO Board of Governors and the WEIM Governing Body have joint authority over any proposal to change or establish any CAISO tariff rule(s) applicable to the EIM Entity balancing authority areas, EIM Entities, or other market participants within the EIM Entity balancing authority areas, in their capacity as participants in EIM. This scope excludes from joint authority, without limitation, any proposals to change or establish tariff rule(s) applicable only to the CAISO balancing authority area or to the CAISO-controlled grid.
The CAISO proposes to place the initiative under the sole authority of the Board of Governors because,
None of the currently contemplated tariff changes would be “applicable to EIM Entity balancing authority areas, EIM Entities, or other market participants within EIM Entity balancing authority areas, in their capacity as participants in EIM.” Instead, the proposed tariff rules would be applicable “only to the CAISO balancing authority area or the CAISO-controlled grid.” Accordingly, these proposals fall outside the scope of joint authority.
This determination does not withstand scrutiny. The ability to access external supply and bring it on a firm basis to the Desert Southwest is a vital element in passing the EIM Resource Sufficiency Test. CAISO recognizes that there are “interdependencies” with the EDAM initiative because the “EDAM design reflected in in the EDAM straw proposal contemplates that entities depending upon import resources to meet their resource sufficiency evaluation will need to demonstrate and make available to the market high quality transmission associated with the delivery of that import. NV Energy agrees that this demonstrates the wheel-through initiative is a critical element of EDAM. However, the fact that the transmission is not identified as a self-schedule day ahead makes it no less important to the EIM Entity required to pass a real-time resource sufficiency evaluation in order not to be cut-off from the real-time market. The firmness of transfers through CAISO is a vital element of the EIM resource sufficiency process which is itself a vital element in regional reliability.
NV Energy submits that the Transmission service and market scheduling priorities is clearly related to EIM Entities and their customers due to their participation in the EIM and the relation to the EIM resource sufficiency test. Accordingly, the initiative falls within the joint authority of the EIM Governing Body and the CAISO Board of Governors.
Moreover, even if this relationship did not exist, no initiative has been more divisive with respect to a division between the CAISO LSEs and the regional EIM participants. The CAISO Board of Governors should recognize the importance for independent decisional participation and ensure that this initiative is taken up under joint authority. FERC has stated, “[c]ontrol of the Board by one state threatens the CAISO’s ability to treat in-state and out-of-state transmission users on a non-discriminatory basis, thus undermining the prospect of broader regional cooperation in the West.”[1] The Governing Board should take immediate action. As FERC noted in the same order, “even the perception that the authority who controls the interstate grid is biased can be enough to prevent proper market forces from working, thus hindering market reliability and efficiency.” To remove this perceived bias, the CAISO’s proposal will benefit from a joint authority review and approval, prior to a filing at FERC.
[1] Mirant Delta, LLC, 100 FERC ¶ 61,059, at P 57 (July 17, 2002), vacated, California Independent System Operator Corp. v. FERC, 372 F.3d 395, 304 (D.C. Cir. 2004),
15.
Provide any additional comments on the Transmission Service and Market Scheduling Priorities Phase 2 straw proposal and August 11, 2022 stakeholder call discussion:
In the next iteration of the Transmission Service and Market Scheduling Priorities Phase 2 Straw Proposal, the CAISO needs to clarify what it means by establishing a “scheduling priority equal to load.” Currently in the Straw Proposal, there is no discussion of curtailment priority except a desire to develop a holistic and balanced framework under which entities seeking to wheel through the CAISO system can reserve to establish a scheduling priority equal to CAISO load and higher than other wheeling transactions.
Under the FERC-approved OATT, there is a distinction between transmission curtailment and load reductions as a result of resource insufficiency. Transmission curtailment is a reduction in non-firm or firm transmission service in response to a transmission system outage or derate. Non-firm schedules are curtailed first. If the transmission derate makes it impossible to accommodate all firm schedules, there is a pro rata reduction of all the firm schedules in order to alleviate the problem.
On the other hand, if a network customer, including NV Energy on behalf of our native load, has not scheduled and delivered sufficient resources to cover their load, and the shortage is impacting the reliability of the Balancing Authority Area, that customer is directed to immediately implement their Transmission Reduction Plan in accordance with their Network Operating Agreement. In other words, the loss of load is not socialized but rather is directed at the resource insufficient load serving entity. Therefore, NV Energy is requesting CAISO to clarify during what situations a scheduling priority is equal to load and if CAISO has the same distinction for resource insufficiency that is under FERC approved OATTs.
Pacific Gas & Electric
Submitted 09/15/2022, 06:41 pm
1.
Please provide a summary of your organization’s comments on the Transmission Service and Market Scheduling Priorities Phase 2 straw proposal and August 11, 2022 stakeholder call discussion:
PG&E appreciates the opportunity to provide comments on the CAISO’s straw proposal for the Transmission and Market Scheduling Priorities Phase 2 initiative. We offer feedback on the proposed process and substance below.
PG&E is unable to conclude from the current methodology and supporting documentation that reliability is appropriately identified and provided for in the calculation of total and available transmission capability.
Support for total transmission and the reservation estimates of Available Transmission Capacity (ATC) provided by the CAISO is limited and not representative of the full set of analysis expected to ensure CAISO Transmission Providers, Load Serving Entities, and customers are able to determine a sufficient volume of transmission is available to serve native load and provide transmission capability to those entities outside the CAISO seeking access. This raises concerns for overall system reliability, support for native load needs, and support for firm delivery via transmission for those outside of CA.
PG&E provides more detail in response to the questions below which include power flow analysis, internal constraints and loop flow considerations, and connections to the Transmission Planning Process as a basis for information used to calculate these amounts - similar to what is taking place in the other ISO/RTOs as well as by many transmission entities in the western US.
The proposed compensation lacks a connection to value, which is evidenced in pricing structures from other ISO/RTOs as well as by many transmission entities in the western US. Value implies the usefulness and desirability of a product or service to a customer and the CAISO’s proposed compensation does not try to draw out that value through price differences for a product that definitely has different value based on the month, day, hour of the year it is being procured.
Additionally given the early September 2022 heat event in the western US, it would be a valuable exercise for many stakeholders to understand how the CAISOs proposed methodology would have been calculated and utilized during the event.
2.
Provide your organization’s comments on the design principles discussed in section 4:
PG&E generally supports the principles that the CAISO describes in its Straw Proposal. PG&E recommends that the CAISO ensure that native load needs are emphasized within the principles.
Similar to other BAAs in the West, the CAISO has a responsibility to meet native load, since it is the Balancing Authority, and to provide access to its transmission grid to other Western BAAs.
3.
Provide your organization’s overall comments on calculating ATC in the monthly horizon, as described in section 5.1.1. In particular, the different approaches for calculating native load needs as an existing commitment and other components of the ATC methodology as discussed in the proposal. The ISO encourages stakeholders to share potential alternative methods for consideration in calculating components, particularly native load needs.
- TTC (Total Transfer Capability) may not be the right starting point. The CAISO should use the system operating limits (SOL), which accounts for outages and derates, as the starting point for calculating the ATC. The CAISO should also describe how derates are expected to impact ATC reservations that might have been made assuming a higher amount of ATC was available.
- The CAISO should ensure that load uncertainty is explicitly accounted for in the TRM. The use of historical data does not represent a 1-in-5 planning standard that is used in the TPP for bulk system studies. There is a 4%-5% increase in forecasted peak load between a 1-in-2 and a 1-in-5, per the 2022 TPP (Transmission Planning Process).
The CAISO should ensure that load growth is explicitly accounted for in the TRM. In the CAISO’s Approach 2, the use of historical data does not account for load growth. A sufficient TRM could address this deficiency.
4.
Provide your organization’s comments on each of the ISO’s proposed approaches for calculating existing transmission commitments (ETC) as it relates to the ATC methodology as described in section 5.1.1.2. Particularly, the ISO seeks comment on the methods or approaches identified for estimating native load needs across a 13-month horizon and encourages stakeholders to suggest potential variations to inputs in deriving the amount of transmission capacity to set aside for native load needs.
PG&E has several concerns with the ETC calculation:
- While using the legacy transmission contracts and TORs (Transmission Ownership Rights) is a good approach by the CAISO, it is not clear in CAISO’s Approach 2 that the Nominal ETCs are used to calculate the ATC as it appears that the combination of the reserved and used ETCs are used to calculate the ATC.
- Native load needs are what is of greatest concern, since Approach 1 does not account for non-RA flows.
- Load growth is identified as an issue in section 5.1.1.2, but a value is not presented. This should be quantified by the CAISO.
5.
Provide your organization’s comments on the Transmission Reliability Margin (TRM) and the Capacity Benefit Margin (CBM) as it relates to the ATC methodology, as described in section 5.1.1.3:
The TRM should not be based on assessing external entities' use of TRM, but instead it should be based on the unique approach taken by the CAISO. The factors outlined in the straw proposal (i.e., aggregate load forecast, forecast uncertainty in transmission system topology, allowances for simultaneous path interactions, variations in generation dispatch, and loop flow) are the correct parameters to use for developing the TRM. Each of these parameters should be determined independently and summed up to arrive at the appropriate TRM.
The CAISO should consider an appropriate non-zero value for CBM. The CAISO should examine data from when EEA (Energy Emergency Alert) 2 or higher were called and, at a minimum, use the incremental import energy during those periods relative to forecasted needs as a CBM adder.
6.
Provide your organization’s overall comments on calculating the ATC in the daily horizon, as described in section 5.1.2:
In general, a daily horizon for ATC is reasonable for allocating excess transmission capacity. PG&E has several questions for the CAISO on how ATC reservations will be addressed in the Day-Ahead Resource Sufficiency Evaluation (RSE), as proposed in the Extended Day-Ahead Market initiative:
- Do the the methods used to calculate daily ATC consider the transmission requirements for the RSE?
- If the CAISO Daily RSE needs in EIM or EDAM are larger than the native load transmission identified here what happens? Will the ATC be reduced? Will it only reduce the daily ATC?
- How does the CAISO propose addressing these concerns?
- How will the CAISO address a situation when transmission capability has been made “available” though it is needed to pass the RSE?
For example, the Day-Ahead Resource Sufficiency Evaluation, as proposed in the Revised Straw Proposal, will count multiple types of imported resource:
- Forward Contracted Imports (i.e., Resource Adequacy or WSPP Sch. C contracts to meet native load needs) whether self-schedule or bid economically;
- Pseudo-tied and dynamically-scheduled resources that bid in through the interties; and
- Intertie bids that are resource-specific.
These resource bids are available to serve native CAISO BAA load. The native load needs calculation in the daily process should account for these imported resources that are necessary to serve CAISO BAA load and meet its Day-Ahead Resources Sufficiency Evaluation.
7.
Provide your organization’s comments on calculating existing transmission commitments (ETC), particularly native load needs, as it relates to the calculation of daily ATC, as described in section 5.1.2.2:
Calculating the ATC based on historical data (RA showings or actual flows across interties) inherently risks meeting future reliability. Relying on such data does not account for more extreme conditions that could be experienced in the future that were not experienced in the past. The use of a TRM serves as a rough mechanism for accounting for load growth, load uncertainty, and other aspects not accounted for in the CAISO’s proposed ATC calculation.
PG&E has concerns around the methodologies used in both Approach 1 and Approach 2.
- Approach 1 undercounts native load needs by using the historical data and not a forecast and uses TTC rather than the SOL for the applicable season.
- Approach 2 is not using the minimum ATC available, but the peak net load days. The historical data is not based on years of stressed conditions and is not reflective of scenarios used in planning of the transmission system or 1-in-5 scenarios.
8.
Provide your organization’s comments on the Transmission Reliability Margin (TRM) and the Capacity Benefit Margin (CBM) as it relates to daily ATC, as described in section 5.1.2.3:
Similar concerns to Q5.
9.
Provide your organization’s comments on the method for accessing ATC to establish wheeling through scheduling priority, as described in section 5.1.3. In particular, consider comments on the requirements identified for accessing ATC.
While prepaying for the reservation and having a contract in place provide strong disincentives to excess reservations, the CAISO should also maintain active oversight of secondary market transactions and actual use of transmission.
10.
Provide your organization’s comments on the proposed enhancement to establish a window during which the submitted requests are vying for limited ATC based upon the underlying duration of the supply contract duration of ATC request as described in section 5.1.3:
PG&E agrees that this is a reasonable proposal.
11.
Provide your organization’s comments on a wheeling through priority rights holder’s ability to resell the wheeling through scheduling priority as described in section 5.1.3:
The ability for parties to sell wheeling through priority rights offers efficiency in the market. Market oversight over that secondary market should be considered and performed by the CAISO.
12.
Provide your organization’s comments on the ISO’s proposal to establish a process through which entities seeking to establish wheeling through priority on a long-term basis (longer than 1-year) can do so through submission of a study request and the ability to fund upgrades on the ISO system, including the ability of import (wheel in) requests driving Maximum Import Capability (MIC) upgrades as described in section 5.1.4:
PG&E agrees that this is a reasonable proposal. The CAISO should provide preliminary reservation estimates on a long-term basis.
13.
Provide your organization’s comments on compensation for wheeling through scheduling priority, as described in section 5.1.5, along with any suggestions your organization may have regarding other potential ways to assess transmission charges for high priority wheeling through transactions:
The CAISO’s compensation proposal does not fairly reflect the value ATC offers to others, recognizing that the CAISO entities pay for it and use most of that value for themselves. PG&E encourages the use of ATC and supports it being offered based on its value and commitment of those entities to longer length contracts, similar to what is expressed in other RTOs and other Western entities. Other BAAs (Balancing Area Authorities) throughout WECC offer peak pricing for transmission use. The range can be between 1.2 and 1.6 times the base off-peak rate. Such pricing is essential to ensure fair cost allocation amongst CAISO transmission grid users.
The CAISO should provide additional information that describes if a revision to the Transmission Access Charge would be required. Even if the CAISO determined a broader revision to TAC is necessary then that should be addressed either in this initiative or the CAISO should commit to addressing the topic in a future initiative. Such additional revisions should not serve as justification to not include a peak pricing mechanism (e.g., an adder or a multiplier).
14.
Provide your organization’s comments on the proposed WEIM decisional classification, as described in section 6:
PG&E supports this proposal.
15.
Provide any additional comments on the Transmission Service and Market Scheduling Priorities Phase 2 straw proposal and August 11, 2022 stakeholder call discussion:
PG&E requests that the CAISO describe how the proposed enhancements would have interacted with the most recent prolonged weather event in September 2022. The CAISO has traditionally depended upon imports to meet reliability for native load in stressed system conditions. PG&E has the following questions in consideration of the most recent stressed system event:
- What would the reservation estimates have been during the stressed days?
- What would have been the impact in these conditions if the ATC amounts were fully utilized due to wheeling reservations?
- How would the wheeling reservations be impacted by derates during the weather event?
Powerex
Submitted 09/16/2022, 03:33 pm
1.
Please provide a summary of your organization’s comments on the Transmission Service and Market Scheduling Priorities Phase 2 straw proposal and August 11, 2022 stakeholder call discussion:
Powerex appreciates the opportunity to submit comments on CAISO’s July 29, 2022 Transmission Service and Market Scheduling Priorities Phase 2 Straw Proposal (“Straw Proposal”), as further discussed at the August 11 stakeholder meeting in this initiative.
The rules and policies proposed in this stakeholder initiative will have critically important ramifications for entities that seek to use either the California-Oregon Intertie (“COI”) or the Pacific DC Intertie (“PDCI”) to deliver Northwest supply to serve load in the Southwest in the summer season. The COI and PDCI are jointly-funded transmission paths that support approximately 8,000 MW of transfers from the Northwest to California and the Southwest.[1] The CAISO provides transmission access, under its rules, on the southern segments of these coordinated facilities; Northwest transmission service providers, including Bonneville Power Administration, provide transmission access, under their OATTs, on the northern segments. Power cannot flow out of the Northwest on the COI or the PDCI without also obtaining transmission service on the southern segments, just as no power can flow into California on the COI or PDCI without also obtaining transmission service on the northern segments. The reliability, economic, and environmental benefits of delivering surplus supply from the largely hydroelectric generation in the Northwest to serve loads in California and in the Southwest are the combined result of both the northern and southern segments of these paths.
The inherently regional nature of transmission access on these critical paths calls for multi-lateral, collaborative approaches to finding solutions, so that all entities that fund these transmission facilities can benefit equitably. A collaborative approach is especially critical as the region moves toward greater integration in order to achieve the shared goal of transitioning to a lower-carbon fleet while maintaining reliable and affordable service to ratepayers. As discussed more fully in these comments, however, the Straw Proposal continues to take a unilateral approach to determining which entities receive priority access to these jointly-funded facilities during critical conditions, resolving the “seams” issue in favor of load-serving entities in the CAISO BAA.
Specially, the CAISO’s Straw Proposal:
- continues to establish and leverage specific market rules that ensure that transmission service on the CAISO’s southern portion is the key determinant of who flows across (and who benefits from) the jointly-funded facilities; and
- would result in most if not all priority access on the CAISO’s southern portion being preferentially granted to CAISO LSEs, providing these entities with the reliability benefits of the entire jointly-funded facilities. CAISO LSEs would enjoy these benefits without having to obtain and fund priority transmission service on the northern segments, and without having to compete with Southwest entities seeking to procure Northwest supply on a forward basis.
The Straw Proposal Continues To Allocate Priority Access On Jointly-Funded Critical Transmission Corridors To CAISO LSEs
This stakeholder process notionally focuses on transmission access on CAISO transmission facilities, but in fact will impact access to the shared and jointly-funded major transmission corridors that connect the Northwest to California and the Southwest—specifically, the COI and the PDCI. As illustrated below, the CAISO is a transmission service provider only on the southern portion of these facilities; service on the northern segments is provided by Northwest transmission service providers, and funded by their transmission customers.
Despite the inherently regional nature of this issue, the CAISO continues to pursue an approach that is clearly inequitable to transmission customers and load serving entities outside of California. It achieves this by giving CAISO LSEs priority access to the CAISO’s southern segment facilities, while also employing specific market rules that ensure priority on the CAISO’s segment largely dictates priority access on the entire jointly-funded path. In effect, the CAISO is able to effectively use its role as market operator to ensure that other transmission service providers’ systems are used to meet the reliability needs of loads in the CAISO BAA first, without consideration of which entities hold the priority rights on the northern segments of these major transmission corridors.
This approach stands in stark contrast to the steps that would be necessary for CAISO LSEs (or any LSE) to be able to rely on Northwest supply delivered on the COI or PDCI to meet their needs under a framework where priority rights on the southern segment were of equal importance to priority rights on the northern segment. Under an equitable framework, an LSE seeking to rely on available supply in the Northwest to serve load in California or in the Southwest would be required to:
- Compete to procure priority transmission service under the OATT framework from one of the northern segment transmission service providers;
- Compete to procure priority transmission service under equitable, open-access CAISO rules on the southern segment; and
- Compete to procure available surplus Northwest supply from identified physical resources on a forward basis.
Unfortunately, the CAISO’s Straw Proposal will secure the reliability benefit of the full jointly-funded transmission facilities for CAISO LSEs, with these substantial benefits coming at the direct expense of ratepayers outside of the CAISO. First, ratepayers in the Southwest bear the cost and/or reliability consequences of losing access to available supply that could otherwise be committed to serve their loads. Second, ratepayers of Northwest entities with available surplus supply face barriers to competitive wholesale market opportunities to commit that supply and earn revenue to offset their retail rates.
The Straw Proposal repeatedly claims that its proposal “minimizes seams issues.” It does not. Rather, it preserves the seams issues, but then resolves them in the manner most beneficial to CAISO LSEs’ interests.
Powerex is concerned that proposals that would benefit CAISO LSEs to the detriment of ratepayers outside of California, on these two major transmission corridors go beyond the wheel-through issue described in this initiative. Under the latest EDAM proposal, for instance, it appears that the CAISO will use its regional market operator role to establish penalty prices in its software to ensure that CAISO LSEs that are granted priority access to the CAISO-operated southern segments of the COI and PDCI will receive EDAM market awards ahead of entities that do not have these priority rights. More specifically, under the EDAM proposal, when there is insufficient capability on the COI and/or the PDCI to deliver enough external supply to enable all load in the EDAM footprint to be served, it appears that those paths will be used to serve the reliability needs of CAISO LSEs first. In contrast, it is not clear whether OATT transmission priority in the rest of the EDAM footprint will even be recognized in the CAISO’s software. The CAISO has not provided any detail on whether it intends to use penalty prices or other mechanisms in the EDAM to ensure that entities with priority OATT transmission rights receive market awards ahead of those that do not have such rights when all load cannot be served. Most importantly, on the two major transmission corridors of the COI and PDCI, CAISO’s EDAM proposal appears to be designed to ensure that transmission priority granted by the CAISO is enforced, while transmission priority under the OATT framework is ignored during those critical conditions when all load cannot be served due to insufficient transmission.
The preferential elevation of CAISO load interests is also evident in how the CAISO proposes to allocate the economic value (i.e., congestion rents) of the jointly-funded COI and PDCI in the EDAM. Whereas the latest EDAM proposal appears to support an equitable 50/50 allocation of congestion value on inter-BAA transmission paths, this principled approach will not apply for transmission paths involving the CAISO BAA. Instead, CAISO has proposed that all CAISO transmission service, including scheduling limits at the CAISO boundary on jointly-funded, coordinated transmission facilities, will be classified as CAISO “internal” constraints, with the CAISO receiving 100% of the congestion rents when these constraints bind.
The importance of equitably providing access to the jointly-funded COI and PDCI cannot be overstated. These facilities have long been the region’s critical transmission backbone, enabling surplus clean hydro supply in the Northwest to meet the reliability needs of LSEs in California and in the Southwest. The replacement cost of these facilities is enormous, and in practice they would be very challenging to replace. Powerex believes that the only workable approach is one in which the reliability and economic benefits of these facilities accrues equitably between transmission ratepayers of the CAISO and other California TSPs (that fund the southern segment) and transmission ratepayers of Northwest TSPs (that fund the northern segment), with access provided on a non-discriminatory and open access basis such that all entities have comparable opportunity to procure and deliver supply over these facilities to serve their customers.
Absent a major pivot in the CAISO’s approach to regional transmission issues, it is difficult to imagine how the CAISO’s transmission proposals—here and in the EDAM initiative—will be workable for external transmission providers and transmission customers on the region’s two major transmission corridors. These entities are likely to struggle to explain to their ratepayers and regulators the rationale for joining a market with rules that give a disproportionate share of the reliability, economic, and environmental benefits of the transmission facilities they fund to CAISO LSEs. Without a significant change in the CAISO’s approach, Powerex believes that the equitable resolution of regional seams issues will require—and ultimately lead to—a different decision making process, in which no one entity has the unilateral ability to determine access to transmission on jointly funded transmission facilities.
The Straw Proposal Applies Preferential And Discriminatory Measures To Grant Priority Access To CAISO LSEs
Prior to 2021, all CAISO market participants had a comparable opportunity to receive a CAISO market schedule to import at Malin or at NOB, as market schedules were awarded based on the offer price that was submitted (including price-taker self-schedules), regardless of the location of the load served by the import. After an accelerated stakeholder process, the CAISO implemented a set of interim measures that, during critical conditions, explicitly gave priority to self-scheduled imports sinking in the CAISO BAA ahead of self-scheduled wheel-through transactions sinking outside the CAISO BAA.
This framework to expressly elevate load service in the CAISO BAA above load service outside the CAISO BAA has been highly divisive in the region. Notwithstanding FERC’s ultimate acceptance of the interim measures, the filings in that proceeding show that a broad range of entities outside the CAISO view this approach as highly discriminatory, falling far short of open access and denying them access to CAISO transmission service on comparable terms to the access provided by other transmission service providers for deliveries serving load in the CAISO BAA. Rather than replacing these controversial interim measures with a more workable long-term framework, the Straw Proposal expands upon this preferential approach and seeks to cement it under rules that will result in non-CAISO entities largely losing their ability to rely on supply delivered on the COI or PDCI to meet their reliability needs during critical periods.
The Straw Proposal Includes An Over-Broad Calculation Of ETC For Native Load
The core elements of the Straw Proposal relate to how much CAISO transfer capability will be offered to transmission customers on an open access basis, as opposed to how much capability will be pre-emptively set aside for CAISO LSEs. Transfer capability is routinely set aside by transmission providers to enable delivery of load-serving entities’ designated network resources. However, the Straw Proposal’s criteria for calculating the quantity of existing transmission commitments (“ETC”) to serve native load in the CAISO BAA does not reflect the approach historically approved by FERC as just and reasonable. Perhaps most obviously, the Straw Proposal sets aside transfer capability for native load without requiring any demonstration that a CAISO LSE has actually contracted for external supply. Instead of setting aside transfer capability to enable delivery of committed physical resources, the Straw Proposal would set aside transfer capability based on:
- Past quantities of Resource Adequacy showings, which in turn were not required to identify any real physical capacity or external transmission service to the CAISO boundary;
- Past import volumes during high demand hours, which may include significant volumes of energy purchased in the bilateral spot market, rather than delivering the output of supply committed on a forward basis; or
- The greater of 1 and 2, above.
These approaches rely on the past as a predictor of upcoming needs, and they rely on information that is at best tangentially related to the delivery of physical resources that CAISO LSEs have actually committed to serve their load. The Straw Proposal’s calculations reflect this vagueness, producing a wide range of ATC values depending on the specific scenario. For instance, RA import quantities have varied substantially from year to year (Approach 1), and peak import volumes often do not correlate to peak net load (Approach 2).
The CAISO has not identified any impediment to requiring a more robust demonstration of need prior to removing transfer capability from being made available to all market participants. Specifically, the CAISO could calculate the ETC for native load service based on demonstrated executed contracts with identified external resources to be delivered on high-priority external transmission service to the CAISO boundary. This would be most comparable to the criteria used by other transmission providers for setting aside transfer capability for designated network resources serving native load. At the very least, the CAISO could calculate the ETC for native load service based on executed RA import contracts for delivery during the time horizon over which ATC is being calculated.
The Straw Proposal’s use of an overly-broad and permissive calculation has the effect of preferentially setting aside the greatest possible quantity of transfer capability for use by CAISO LSEs, and necessarily making the least possible quantity of transfer capability available to be procured by other entities. It was also apparent at the stakeholder workshop that advocates for California load interests believe the Straw Proposal methodology does not go far enough in setting aside transfer capability for CAISO LSEs.
In addition to maximizing the ETC quantity for native load, the Straw Proposal explains that ATC will be further reduced by its calculation of Transmission Reliability Margin (“TRM”) and Capacity Benefit Margin (“CBM”). While these terms are a standard part of all ATC calculations, the Straw Proposal is vague about how the CAISO will determine those values. What is clear, however, is that any quantity of TRM and CBM will directly reduce the transmission capability available on an open access basis to serve load in the Southwest region, but will not reduce the priority transmission service granted to CAISO LSEs.
Without transparent, objective and robust criteria for calculating ETC for native load, TRM and CBM, the allocation of CAISO priority transmission on the COI and PDCI appears to lead to a predictable outcome: in the critical demand periods, virtually all CAISO transfer capability on the PDCI and COI will be set-aside for CAISO LSEs, with little or no capability on these critical paths being available to be procured by other transmission customers seeking to wheel-through the CAISO BAA.
The Straw Proposal represents a significant expansion of the preferential interim measures. Under the interim measures, entities have registered up to 1,000 MW of Priority Wheeling Through service entering the CAISO system either at Malin or at NOB for the summer 2022 period. The Straw Proposal includes estimates of ATC for Priority Wheeling Through service that would be as little as 10 MW, as shown below:
Under the Straw Proposal, Southwest LSEs that currently rely on about 1,000 MW of surplus Northwest supply delivered on high-priority Northwest and CAISO transmission would lose the ability to rely on much of that supply if the Straw Proposal is adopted, with Southwest ratepayers bearing the cost of finding replacement supply, facing reliability challenges associated with reduced supply commitments, or both.
The Straw Proposal Creates Unreasonable And Discriminatory Barriers To Entities Requesting ATC
In the periods that there happens to be some ATC made available on an open access basis, the Straw Proposal improperly imposes restrictions on transmission customers wishing to procure priority scheduling rights. In particular, transmission customers will be required to demonstrate to the CAISO that they have an executed firm energy contract, and will be limited to requesting priority scheduling rights for the quantity and the delivery periods of that executed contract. Powerex is not aware of any other transmission provider that requires a “demonstration of need” from transmission customers wishing to reserve transmission service. Given that any transmission capacity arguably needed to serve native load will already have been set aside, there does not appear to be any reason to restrict the quantity that transmission customers can compete to obtain in this manner.
Entities That Pre-Pay the CAISO Transmission Access Charge (TAC) For Priority Rights Would Still Not Receive The Economic Value Of The Transmission They Are Funding
Finally, the Straw Proposal would require a transmission customer reserving CAISO priority service to pre-pay the CAISO TAC for the entire duration of the reservation. This, on its own, is not problematic; it is standard for transmission service providers to require payment for the transmission service that is reserved, regardless of whether or not it is ultimately used. But the Straw Proposal would not provide customers with any of the economic benefit (i.e., congestion rents) for the transmission paths they are committing to fund through payment of the TAC. This means that a customer would be charged the TAC to secure scheduling priority on the CAISO system in advance, but still be required to pay congestion charges when it exercises that priority. Congestion charges in organized markets serve as the mechanism for allocating limited transmission space. Where, as here, a new framework is developed for customers to procure that allocation through pre-payment of the TAC, these customers should be hedged against congestion charges in the day-ahead or real-time markets.
The Straw Proposal is in stark contrast to every other transmission service provider in the west, where the customer committing to pay the tariff rate receives both the reliability benefit and the economic benefit associated with scheduling priority on the identified path. It is also in contrast with the proposed design of Markets+, where the entities that procure priority transmission service (and commit to pay the applicable tariff rate) receive both the reliability benefit and the congestion rents associated with those rights.
An Equitable Long-Term Solution Must Not Undermine Transmission Priority On The Northern Segments, Or Limit Wholesale Market Competition
Powerex believes that an appropriate proposal for determining transmission priority on a long-term basis would:
- Set aside a quantity for native load to CAISO LSEs based on executed supply contracts for identified physical capacity that is deliverable to the CAISO boundary;
- Make the remaining quantity available to any transmission customer willing to commit to paying the TAC for the duration and quantity requested; and
- Provide CRRs, as well as scheduling priority, for the priority rights that are issued.
Such an approach would adhere to the principles of open access and non-discrimination applied in the rest of the west. Nothing in the above approach would prevent CAISO LSEs from being able to rely on priority CAISO transmission service for real, deliverable external supply they have already procured, nor from having an opportunity to compete to procure additional priority CAISO transmission service to enable additional imports of shorter-term supply and/or supply for economic displacement.
In addition to making CAISO priority transmission rights available on a non-discriminatory basis, it is essential that CAISO engage in dialogue with transmission service providers on the northern segments to equitably resolve regional seams issues on the COI and PDCI. Powerex has repeatedly brought forward these concepts, and the need for transmission priority on both the CAISO and northern segment transmission systems to be appropriately respected. To date, however, Powerex is not aware of CAISO engaging in this type of dialogue.
[1] Southern of the California-Oregon border, the COI comprises both the Pacific AC Intertie (“PACI”) and the California-Oregon Transmission Project (“COTP”). CAISO imports at the Malin500 intertie scheduling point relate to the PACI transmission capability managed by the CAISO.
3.
Provide your organization’s overall comments on calculating ATC in the monthly horizon, as described in section 5.1.1. In particular, the different approaches for calculating native load needs as an existing commitment and other components of the ATC methodology as discussed in the proposal. The ISO encourages stakeholders to share potential alternative methods for consideration in calculating components, particularly native load needs.
Please see Powerex's comments above.
Powerex’s comments are also available at CAISO Transmission Service and Market Scheduling Priorities Phase 2 Straw Proposal Comments
4.
Provide your organization’s comments on each of the ISO’s proposed approaches for calculating existing transmission commitments (ETC) as it relates to the ATC methodology as described in section 5.1.1.2. Particularly, the ISO seeks comment on the methods or approaches identified for estimating native load needs across a 13-month horizon and encourages stakeholders to suggest potential variations to inputs in deriving the amount of transmission capacity to set aside for native load needs.
Please see Powerex's comments above.
Powerex’s comments are also available at CAISO Transmission Service and Market Scheduling Priorities Phase 2 Straw Proposal Comments
12.
Provide your organization’s comments on the ISO’s proposal to establish a process through which entities seeking to establish wheeling through priority on a long-term basis (longer than 1-year) can do so through submission of a study request and the ability to fund upgrades on the ISO system, including the ability of import (wheel in) requests driving Maximum Import Capability (MIC) upgrades as described in section 5.1.4:
Please see Powerex's comments above.
Powerex’s comments are also available at CAISO Transmission Service and Market Scheduling Priorities Phase 2 Straw Proposal Comments
13.
Provide your organization’s comments on compensation for wheeling through scheduling priority, as described in section 5.1.5, along with any suggestions your organization may have regarding other potential ways to assess transmission charges for high priority wheeling through transactions:
Please see Powerex's comments above.
Powerex’s comments are also available at CAISO Transmission Service and Market Scheduling Priorities Phase 2 Straw Proposal Comments
Public Advocates Office, California Public Utilities Commission
Submitted 09/16/2022, 03:14 pm
1.
Please provide a summary of your organization’s comments on the Transmission Service and Market Scheduling Priorities Phase 2 straw proposal and August 11, 2022 stakeholder call discussion:
Section 345 of the California Public Utilities Code states that the CAISO “shall ensure efficient use and reliable operation of the transmission grid.”[1] The CAISO should ensure that its ability to reliably serve native load is uncompromised under all conditions. Cal Advocates recommends that the CAISO structure the reforms discussed in the straw proposal to recognize that climate-change-driven weather conditions have and are likely to surpass forecasts[2] and that transmission capacity should be allocated accordingly. This approach will, in turn, incentivize non-native market participants that wish to use the CAISO network to fund the upgrades needed to facilitate that use.
[1] California Public Utilities Code Section (§) 345.
[2] The recent September 2022 heatwave in California seat records across the West; Sacramento recorded its highest temperature in almost a century. (California and the West broil in record-setting heat wave. The Associated Press. September 6, 2022. Available at https://www.npr.org/2022/09/06/1121403326/california-and-the-west-broil-in-record-setting-heat-wave.)
2.
Provide your organization’s comments on the design principles discussed in section 4:
Cal Advocates largely supports the design principles discussed in Section 4, as they are consistent with the approach described in Cal Advocates’ response to Question 1.
3.
Provide your organization’s overall comments on calculating ATC in the monthly horizon, as described in section 5.1.1. In particular, the different approaches for calculating native load needs as an existing commitment and other components of the ATC methodology as discussed in the proposal. The ISO encourages stakeholders to share potential alternative methods for consideration in calculating components, particularly native load needs.
Cal Advocates does not comment on this issue at this time but may do so at a later date.
4.
Provide your organization’s comments on each of the ISO’s proposed approaches for calculating existing transmission commitments (ETC) as it relates to the ATC methodology as described in section 5.1.1.2. Particularly, the ISO seeks comment on the methods or approaches identified for estimating native load needs across a 13-month horizon and encourages stakeholders to suggest potential variations to inputs in deriving the amount of transmission capacity to set aside for native load needs.
Regarding Existing Transmission Commitments (ETCs), Cal Advocates supports Approach 3 (the higher of Approaches 1 and 2). Approach 3 – the higher of either historical RA showings or historical peak load calculations – is the only approach that recognizes both the inherent uncertainty of load forecasts and the degree to which climate change could increase the strain on the transmission system.
By using a variety of methods to estimate the capacity needs of native load, Approach 3 better accounts for data quality issues in forecasting. In the Root Cause Analysis report on the August 2020 outages, the CAISO, the CEC, and the California Public Utilities Commission (CPUC) described how accurate load data from load-serving entities is difficult to obtain in real-time.[1] Similarly, the CEC describes how COVID-19, climate change, and other factors introduce uncertainty into load forecasts.[2]
By considering historical import volume and net peak load, Approach 3 accounts for the fact that RA targets are consistently refined to accurately account for load needs. The Root Cause Analysis Report recommended increases to the CPUC’s RA procurement targets, and recent decisions in the CPUC’s RA proceedings revised planning and reserve margins.[3] Given these ongoing changes, it is appropriate to use historical peak load calculations to check against RA targets when calculating ETC.
[1] See Root Cause Analysis: Mid-August 2020 Extreme Heat Wave. January 13, 2021. P.119.
[2] “Climate change is the main culprit causing uncertainty in near- and long-term planning, and recent extreme weather events in California and the rest of the West have had a real impact on energy demand and system planning.” (Final 2021 Integrated Energy Policy Report Volume IV: California Energy Demand Forecast. California Energy Commission. February 2022. P. 5.)
[3] Decision Adopting Local Capacity Obligations for 2023-2025, Flexible Capacity Obligations for 2023, and Reform Track Framework. Decision 22-06-050. Rulemaking 21-10-002. June 24, 2022.
5.
Provide your organization’s comments on the Transmission Reliability Margin (TRM) and the Capacity Benefit Margin (CBM) as it relates to the ATC methodology, as described in section 5.1.1.3:
Cal Advocates is concerned that a 5% TRM or CBM will not account for climate-driven weather conditions and, as such, will not ensure the CAISO can serve load reliably. Cal Advocates recommends that this initiative include a quantitative study process that estimates new TRM and CBM values that will ensure reliability for native load.
The TRM and CBM encompass a variety of metrics that are critical to reliability. They include variations in generation dispatch, such as the “availability of hydro and variable energy resources,”[1] as well as includes the capacity set aside to import energy during emergency conditions. Given the complexity of these factors, it is inadvisable to assume a 5% TRM or CBM, and a more rigorous estimation process should be included in the initiative.
For example, regarding the availability of hydropower, evidence indicates that climate change is decreasing the availability of hydropower. In the lead-up to the August 2020 outages, the snow pack for California mountain regions peaked at 63% of the historical average. In April 2022, it was estimated to be at 38% of the historical average for this date.[2], [3] In 2021, the Energy Information Administration found that California hydropower was at its lowest level since 2015, and Mike O’Boyle of Energy Innovation (a think tank) stated that “[t]here is a growing recognition that hydropower may not be the reliable resource that it has been historically.”[4] All of this needs to be factored into the determination of TRM and CBM.
The TRM and CBM similarly need to account for the substantial variables in the dispatch of other forms of generation. California energy agencies are still working to accurately project the load-carrying capability of variable resources For example, a recent ruling in the CPUC’s Resource Adequacy (RA) proceeding updated the Effective Load Carry Capability (ELCC) values for wind resources to make them region-specific.[5] The ELCC values vary from 56% (offshore wind, projected for July 2024) to 10% (Northern California wind, projected for October 2024).[6] This highlights the nuance and complexity the TRM and CBM must account for.
The Straw Proposal lacks quantitative support for a 5% margin. Given the critical aspects that the TRM and CBM represent, the CAISO should develop a transparent, quantitative process that adopts margins that ensure reliable service for California native load.
[1] Straw Proposal, p. 21.
[2] Root Cause Analysis: Mid-August 2020 Extreme Heat Wave. January 13, 2021. P.22.
[3] Survey Finds Little Snow as Statewide Snowpack Drops to 38 Percent Following Record Dry Months. California Department of Water Resources. April 1, 2022. Available at https://water.ca.gov/News/News-Releases/2022/April-22/April-2022-Snow-Survey.
[4] Pontecorvo, Emily. Report: California hydropower could be cut in half this summer. Grist. May 31, 2022. Available at https://grist.org/energy/report-california-hydropower-could-be-cut-in-half-this-summer/.
[5] See Rulemaking (R.) 21-10-002.
[6] Energy Division Study for R.21-10-002. Regional Wind Effective Load Carrying Capability Study Results for 2024. Table 1. June 1, 2022. Available at https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M482/K148/482148586.PDF.
6.
Provide your organization’s overall comments on calculating the ATC in the daily horizon, as described in section 5.1.2:
The same principles and recommendations that Cal Advocates presented in relation to the longer-horizon ATC apply to the shorter-horizon ATC.
7.
Provide your organization’s comments on calculating existing transmission commitments (ETC), particularly native load needs, as it relates to the calculation of daily ATC, as described in section 5.1.2.2:
The same principles and recommendations that Cal Advocates presented in relation to the longer-horizon ATC apply to the shorter-horizon ATC.
8.
Provide your organization’s comments on the Transmission Reliability Margin (TRM) and the Capacity Benefit Margin (CBM) as it relates to daily ATC, as described in section 5.1.2.3:
The same principles and recommendations that Cal Advocates presented in relation to the longer-horizon ATC apply to the shorter-horizon ATC.
9.
Provide your organization’s comments on the method for accessing ATC to establish wheeling through scheduling priority, as described in section 5.1.3. In particular, consider comments on the requirements identified for accessing ATC.
Cal Advocates does not comment on this issue at this time but may do so at a later date.
10.
Provide your organization’s comments on the proposed enhancement to establish a window during which the submitted requests are vying for limited ATC based upon the underlying duration of the supply contract duration of ATC request as described in section 5.1.3:
Cal Advocates does not comment on this issue at this time but may do so at a later date.
11.
Provide your organization’s comments on a wheeling through priority rights holder’s ability to resell the wheeling through scheduling priority as described in section 5.1.3:
Cal Advocates does not comment on this issue at this time but may do so at a later date.
12.
Provide your organization’s comments on the ISO’s proposal to establish a process through which entities seeking to establish wheeling through priority on a long-term basis (longer than 1-year) can do so through submission of a study request and the ability to fund upgrades on the ISO system, including the ability of import (wheel in) requests driving Maximum Import Capability (MIC) upgrades as described in section 5.1.4:
Cal Advocates supports the CAISO’s proposal to create a process by which entities seeking to wheel through the CAISO’s system fund the corresponding, necessary upgrades as it is consistent with cost causation principles that electric rates are based on.[1] However, Cal Advocates recommends that these entities not receive Congestion Revenue Rights (CRRs) in connection with these upgrades, as suggested in the straw proposal. The CAISO’s Department of Market Monitoring has calculated that CRR auctions cost ratepayers a net $680 million between 2009 and 2017,[2] and increasing CRR payouts to entities that fund upgrades could exacerbate this problem.
[1]“Cost causation means that costs should be borne by those customers who cause the utility to incur the expense.” (Order Instituting Rulemaking on the Commission’s Own Motion to Conduct a Comprehensive Examination of Investor Owned Electric Utilities’ Residential Rate Structures, the Transition to Time Varying and Dynamic Rates, and Other Statutory Obligations. Rulemaking 12-06-013. June 21, 2012)
[2] Market alternatives to the congestion revenue rights auction. CAISO Department of Market Monitoring. November 27, 2017. P. 1.
13.
Provide your organization’s comments on compensation for wheeling through scheduling priority, as described in section 5.1.5, along with any suggestions your organization may have regarding other potential ways to assess transmission charges for high priority wheeling through transactions:
Cal Advocates does not comment on this issue at this time but may do so at a later date.
14.
Provide your organization’s comments on the proposed WEIM decisional classification, as described in section 6:
Cal Advocates does not comment on this issue at this time but may do so at a later date.
15.
Provide any additional comments on the Transmission Service and Market Scheduling Priorities Phase 2 straw proposal and August 11, 2022 stakeholder call discussion:
Cal Advocates does not comment on this issue at this time but may do so at a later date.
San Diego Gas & Electric
Submitted 09/16/2022, 07:04 pm
1.
Please provide a summary of your organization’s comments on the Transmission Service and Market Scheduling Priorities Phase 2 straw proposal and August 11, 2022 stakeholder call discussion:
As a general principle, SDG&E believes that during time periods when native load is at risk of curtailment, CAISO Load Serving Entities (LSEs) seeking to reserve use of the transmission system to import power for reliability purposes should have priority access to that transmission system over non-CAISO entities who have not comparably funded the CAISO transmission system. If native load cannot access the transmission for reliability purposes, then that must have consequences for the Available Transmission Capability (ATC) calculation here in the Transmission Service and Market Scheduling Priorities (TSMSP) initiative. Specifically, SDG&E believes that CAISO native load should have priority access to Available Transmission Capacity (ATC) that is determined after the year-ahead RA showings are made and prior to the month-ahead showings. The timing of the initial ATC calculation should allow enough time to allocate the initial ATC amount among CAISO native loads, to negotiate RA import contracts that would utilize the allocated amounts and then include this RA capacity on monthly RA plans. After the monthly RA plans are submitted, the CAISO would calculate a final ATC amount that would be available for priority wheel-throughs. As for the daily ATC calculation, since CAISO native load cannot make use of daily ATC for their RA plans, the daily ATC calculation should be adjusted for the amount of Maximum Import Capability (MIC) and monthly ATC for which CAISO native load has nominated RA imports, but which could not be accommodated under the MIC allocation and monthly ATC processes.
Additionally, SDG&E suggests that the CAISO conduct power flow analysis to confirm that the calculated amount of ATC is unlikely to be limited by transmission constraints internal to the CAISO Balancing Authority Area (e.g., by contingency-based flows on Path 15 or Path 26).
SDG&E also questions whether charging non-CAISO entities the Wheeling Access Charge (WAC) for the amount of power wheeled under a priority transmission reservation is the appropriate amount to charge for priority transmission rights across the CAISO system.
2.
Provide your organization’s comments on the design principles discussed in section 4:
No comment at this time.
3.
Provide your organization’s overall comments on calculating ATC in the monthly horizon, as described in section 5.1.1. In particular, the different approaches for calculating native load needs as an existing commitment and other components of the ATC methodology as discussed in the proposal. The ISO encourages stakeholders to share potential alternative methods for consideration in calculating components, particularly native load needs.
SDG&E understands that there are CAISO LSEs who have sought allocations in the MIC process that exceed the amounts allocated to those LSEs and have been denied. These are requests for use of the CAISO transmission system, which CAISO LSEs have funded, to support import Resource Adequacy (RA) to serve native load’s reliability needs. The fact that such requests cannot be accommodated in the MIC process has implications for the proposed ATC reservation process. Since ATC is determined after accounting for shown RA (see Approach 1 and Approach 3 in CAISO proposal, p. 13-14), there is, by definition, additional transmission capacity available to serve native load and, it would appear, interest by CAISO LSEs to use that capacity to support additional RA imports.
SDG&E believes that CAISO native load should be given priority access to any ATC identified in this process. The monthly ATC calculations, and reservation decisions, should be done prior to the RA showing deadline (45 days prior to the start of the month). This would then give CAISO native load the chance to utilize transmission capability that was not available through the MIC process, but which was later determined by the CAISO to be available via the proposed ATC calculation process. CAISO native load should have priority in accessing this ATC.
This has implications for CAISO’s proposed methodology for calculating the ATC under Approach 1. CAISO should not wait until the 45-day RA showing deadline to use actual submitted RA plans as this would negate CAISO native load’s ability to take advantage of any identified ATC. CAISO LSEs need enough time prior to the 45-day RA showing deadline to receive their proportional allocations of the ATC, negotiate additional import RA contracts that would utilize the allocations, and include these additional RA resources in their monthly RA showings. Based on the monthly RA showings, the CAISO would calculate a final ATC number that would then be available for priority wheeling-through. This means that CAISO cannot rely on actual submitted RA plans for the month in question. The historical RA showing methodology seems imprecise but may be the next best alternative.
Lastly, a power flow analysis should be done to make sure the ATC amount is simultaneously usable. SDG&E is concerned that simply calculating the ATC based off of the Total Transmission Capability (TTC), without consideration for internal congestion, could create reliability issues. If in this TSMSP process CAISO sells off more priority transmission reservation than is simultaneously useable, then CAISO native loads could be subject to curtailment in order to support wheel-throughs by non-CAISO entities. The best way to confirm that the calculated ATC is physically feasible is to perform a contingency-based power flow analysis.
4.
Provide your organization’s comments on each of the ISO’s proposed approaches for calculating existing transmission commitments (ETC) as it relates to the ATC methodology as described in section 5.1.1.2. Particularly, the ISO seeks comment on the methods or approaches identified for estimating native load needs across a 13-month horizon and encourages stakeholders to suggest potential variations to inputs in deriving the amount of transmission capacity to set aside for native load needs.
SDG&E favors approach 3. SDG&E further believes that Approach 3 should take the worst of Approach 1, 2a, 2b, and 2c. However, if SDG&E has to choose among the different options under Approach 2, then we would choose Approach 2c, in which case Approach 3 would take the worst of Approach 1 or 2c.
5.
Provide your organization’s comments on the Transmission Reliability Margin (TRM) and the Capacity Benefit Margin (CBM) as it relates to the ATC methodology, as described in section 5.1.1.3:
SDG&E agrees that the methodology ought to include both a CBM, as well as a TRM, to properly account for native load needs. SDG&E requests confirmation that the TRM accounts for line derates. For example, on any given day, it is likely that a transmission path with 1000 MW of TTC could have the operating transfer capability derated to 900 MW. If the TRM is not accounting for this, then the ATC calculation needs to capture this derate somewhere.
6.
Provide your organization’s overall comments on calculating the ATC in the daily horizon, as described in section 5.1.2:
To maintain the principle that CAISO native load should have first priority in using the transmission system to support reliability, SDG&E proposes that the amount of MIC allocation that CAISO native load has sought, but which could not be accommodated, should be accounted for in the daily ATC calculation (i.e., resulting in a lower daily ATC). SDG&E proposes three illustrative scenarios:
Scenario 1: CAISO LSEs have collectively sought 2,500 MW of MIC allocation on a particular import path but only 1,500 MW could be accommodated. Subsequently, the monthly ATC calculation showed zero ATC. CAISO LSEs have therefore been denied 1,000 MW of transmission that they would otherwise have used to serve their own reliability needs. Thus, the 1,000 MW that was not granted to the CAISO LSEs should be accounted for when determining the daily ATC.
Scenario 2: CAISO LSEs have collectively sought 2, 500 MW of MIC allocation on a particular import path but only 1,500 MW could be accommodated. Subsequently, the monthly ATC calculation showed 500 MW of ATC. CAISO LSEs get priority access to this 500 MW and are allocated the 500 MW. In total CAISO LSEs have been allocated 2,000 MW of import capability (1,500 MW + 500 MW) and the remaining 500 MW sought by CAISO LSEs could not be accommodated by the close of the monthly ATC process (2,500 MW – 2,000 MW). That is 500 MW remaining that they would otherwise have used to serve their own reliability needs. Thus, 500 MW should be accounted for in the daily ATC calculation.
Scenario 3: CAISO LSEs have collectively sought 2,500 MW of MIC allocation on a particular import path but only 1,500 MW could be accommodated. Subsequently, the monthly ATC calculation showed 500 MW of ATC. CAISO LSEs get priority access to this 500 MW and are allocated the 500 MW under the monthly ATC process. Suppose the CAISO LSEs collectively only use 250 MW out of the 500 MW allocated. The fact that they only used 250 MW out of 500 MW in the monthly ATC should not impact the calculation. In total CAISO LSEs have still been allocated 2,000 MW of import capability (1,500 MW + 500 MW) and 500 MW could not be accommodated by the close of the monthly ATC process (2,500 MW – 2,000 MW). Thus, 500 MW should still be accounted for in the daily ATC calculation.
7.
Provide your organization’s comments on calculating existing transmission commitments (ETC), particularly native load needs, as it relates to the calculation of daily ATC, as described in section 5.1.2.2:
No comment at this time.
8.
Provide your organization’s comments on the Transmission Reliability Margin (TRM) and the Capacity Benefit Margin (CBM) as it relates to daily ATC, as described in section 5.1.2.3:
SDG&E supports including the TRM and CBM in the ATC calculation.
9.
Provide your organization’s comments on the method for accessing ATC to establish wheeling through scheduling priority, as described in section 5.1.3. In particular, consider comments on the requirements identified for accessing ATC.
SDG&E supports the criteria proposed for reserving ATC.
10.
Provide your organization’s comments on the proposed enhancement to establish a window during which the submitted requests are vying for limited ATC based upon the underlying duration of the supply contract duration of ATC request as described in section 5.1.3:
SDG&E supports this structure. We believe the request window should be longer than a day.
11.
Provide your organization’s comments on a wheeling through priority rights holder’s ability to resell the wheeling through scheduling priority as described in section 5.1.3:
SDG&E supports the right to resell.
12.
Provide your organization’s comments on the ISO’s proposal to establish a process through which entities seeking to establish wheeling through priority on a long-term basis (longer than 1-year) can do so through submission of a study request and the ability to fund upgrades on the ISO system, including the ability of import (wheel in) requests driving Maximum Import Capability (MIC) upgrades as described in section 5.1.4:
SDG&E supports this structure.
13.
Provide your organization’s comments on compensation for wheeling through scheduling priority, as described in section 5.1.5, along with any suggestions your organization may have regarding other potential ways to assess transmission charges for high priority wheeling through transactions:
With respect to the CAISO’s proposal to charge the WAC for wheeling-through priority, the CAISO argues that “except for the prepayment requirement, this approach tracks what a CAISO LSE would pay in TAC charges if it utilized all of the hours of the RA import supply contract over the entire month.” (proposal at p. 29) While the proposed charge rate (the WAC) is the same as what CAISO native loads pay, it does not reflect the intrinsic value of the transmission access that non-CAISO entities obtain through priority access. The CAISO’s charge proposal allows non-CAISO entities to effectively cherry-pick the highest value hours of a month and only pay for those hours. CAISO native loads must pay for all hours of the month.
SDG&E believes the charge for priority wheeling-through transmission should be at a rate that is higher than the WAC, consistent with the fact that CAISO native loads are effectively surrendering the native load priority authorized by FERC. One approach to setting the rate would be to scale the WAC up by a factor tied to the number of hours per month for which priority access is obtained. Priority access for every hour of a month would pay the same WAC rate as CAISO native load. Priority access for a single hour of a month would pay a multiple of the WAC rate.
14.
Provide your organization’s comments on the proposed WEIM decisional classification, as described in section 6:
No comment at this time.
15.
Provide any additional comments on the Transmission Service and Market Scheduling Priorities Phase 2 straw proposal and August 11, 2022 stakeholder call discussion:
No additional comments at this time.
Six Cities
Submitted 09/19/2022, 03:06 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 Transmission Service and Market Scheduling Priorities Phase 2 straw proposal and August 11, 2022 stakeholder call discussion:
Although they do not conceptually oppose adoption of a process to enable external parties to engage in and pay for priority wheeling service on the CAISO transmission system, at this time, the Six Cities oppose several key elements of the Straw Proposal, including the proposed methodology for calculation of available transfer capability in the daily and monthly time horizons and the proposed compensation for wheeling-through scheduling priority. In particular, the Six Cities do not support the emphasis on historical transactions in determining native load needs, which does not appear to adequately preserve access to and use of the transmission system for CAISO native load. Further, the CAISO’s proposal to use the existing wheeling access charge (“WAC”) as the rate applicable to customers seeking scheduling priority does not appropriately compensate Participating Transmission Owners and CAISO transmission customers for wheeling parties’ priority access to and use of the CAISO system at critical times. The Six Cities urge that any proposal in this initiative should:
- Assure that CAISO native load, which is responsible for paying the full cost of the CAISO transmission system under the existing rate design, has access to that transmission system on the interties for the purpose of engaging in import transactions, including above historical levels; and
- Require wheeling customers to pay rates that are appropriately scaled to the amount of service priority during peak months and days, instead of the flat WAC.
As discussed below, it would be constructive for the CAISO to hold additional workshops on the issues in this initiative. One workshop should consist of a deep dive into the CAISO’s proposed available transfer capability (“ATC”) methodology. While the Six Cities understand that the CAISO engaged consulting services through OATi to assist in the development of its proposed methodology, there has not been adequate time to socialize the consultants’ work with stakeholders and for stakeholders to ask questions and present either alternatives or modifications. The focus of the workshop at this stage needs to be less on information gathering from external parties and potential priority wheeling customers and more on putting “pen to paper” on ATC methodologies that will be durable and ensure reliable and fair access, including for CAISO native load.
The Six Cities also request that the CAISO dedicate time within this initiative to performing analyses focused on the impacts of the recent extreme heat events of early September. The workshop focused on the proposed ATC methodology and alternatives could encompass a detailed discussion of these events and the use of the transmission system during that time. It would be instructive to see how the CAISO’s proposals in this initiative may have impacted the system or changed operations or market results under those stressed conditions. If appropriate, the CAISO should consider recalibrating its proposals in response to such analyses.
Finally, as discussed below, a workshop dedicated to the rate design for scheduling priorities would also advance this initiative.
2.
Provide your organization’s comments on the design principles discussed in section 4:
The Six Cities do not oppose the design principles articulated in section 4 of the Straw Proposal. Concerningly, however, the design principles do not address compensation for the proposed scheduling priority framework. The Six Cities request that the CAISO adopt a principle that is focused on compensation:
- Ensure that the rate design for wheeling service is just and reasonable, non-discriminatory, and provides appropriate compensation for access to and use of the transmission system.
At this time, the Straw Proposal does not fully meet the principles that the CAISO has set forth. In particular, the Six Cities are concerned that the CAISO’s proposed methodology for calculating ATC does not assure that sufficient capacity will be available for native load service, particularly as needs may evolve. For example, the Six Cities are unclear whether the CAISO’s proposals for ATC may impair reliability to the extent that these proposals do not adequately address concerns such as growth in load, increased reliance on imported resource adequacy resources, changes in transmission topology and usage patterns, and needs driven by extreme weather. Moreover, the Six Cities do not believe that the proposed rate design for scheduling priorities provides appropriate compensation for wheeling customers’ use of the CAISO transmission system, especially during peak months and days. Further work in these areas is needed.
3.
Provide your organization’s overall comments on calculating ATC in the monthly horizon, as described in section 5.1.1. In particular, the different approaches for calculating native load needs as an existing commitment and other components of the ATC methodology as discussed in the proposal. The ISO encourages stakeholders to share potential alternative methods for consideration in calculating components, particularly native load needs.
Please refer to the Six Cities’ discussion on the subsections of section 5.1.1. below.
4.
Provide your organization’s comments on each of the ISO’s proposed approaches for calculating existing transmission commitments (ETC) as it relates to the ATC methodology as described in section 5.1.1.2. Particularly, the ISO seeks comment on the methods or approaches identified for estimating native load needs across a 13-month horizon and encourages stakeholders to suggest potential variations to inputs in deriving the amount of transmission capacity to set aside for native load needs.
The Six Cities are broadly concerned that the CAISO’s proposed options for determining native load needs on the interties understate such needs and may consequently both restrict access by CAISO load serving entities to external resources and impair reliability. Based on the information included in the Straw Proposal, the Six Cities are unable to conclude that the CAISO’s proposed methodology adequately addresses incremental native load needs or load growth. As discussed, the Six Cities urge the CAISO to hold a workshop to discuss its proposed approach and to consider possible alternatives. Among other concerns, the Six Cities request that the CAISO perform power flow analyses that may more fully capture potential needs on the system under an array of conditions. Additionally, the Six Cities ask that the CAISO evaluate the conditions on the grid during this month’s extreme heat events and determine if there are “lessons learned” or other data that may inform the approach to native load needs here.
Turning to the options in the Straw Proposal, the Six Cities do not support use of historical monthly Resource Adequacy (“RA”) showings as the metric for determining transmission needs. This approach seems incompatible with any ability of CAISO load serving entities to rely on imported RA resources to meet increased load needs. This concern is present with respect to both the proposal to average RA values over multiple years or apply the highest value over multiple years. It is also unclear how this proposed approach would synchronize with the CAISO’s calculation of Maximum Import Capability (“MIC”) values. For example, to the extent RA imports have been constrained by MIC, historical RA values will not accurately represent native load needs going forward but instead will perpetuate limitations resulting from MIC caps.
Second, with respect to the variations on Approach 2, the Six Cities are concerned that historical import values may likewise understate native load needs. The Six Cities urge the CAISO to consider providing additional examples under varying scenarios of how this approach will work in practice. For example, how much capacity would be available for native load under stressed system conditions such as those experienced earlier this month? Overreliance on historical metrics without adjustments for projected system conditions and load needs may create reliability risks. Use of historical values could be appropriate as a starting point, but the Six Cities urge the CAISO to explore consideration of a forward-looking methodology.
Third, of the suggested options, Approach 3 may present the preferred alternative if the CAISO insists on use of historical values—whether RA or import flows—to determine native load needs. However, as previously stated, the Six Cities urge the CAISO to spend more time discussing with stakeholders these approaches and possible adjustments to more accurately reflect native load needs under a variety of conditions, including forward looking adjustments. Selection of any of these options at this time is premature.
5.
Provide your organization’s comments on the Transmission Reliability Margin (TRM) and the Capacity Benefit Margin (CBM) as it relates to the ATC methodology, as described in section 5.1.1.3:
With respect specifically to Transmission Reliability Margin (“TRM”), the Six Cities urge the CAISO to provide more details and examples regarding how incremental load needs and load growth projections will be addressed, including load growth uncertainty. The Straw Proposal does not include adequate detail regarding how load growth will be reflected in the derivation of native load needs or TRM. Given the significant increase in the CAISO load that is projected to drive transmission capital expenditures within the CAISO in the long term (and the recent record high loads experienced in the CAISO earlier this month), determining how to reflect load growth in the forward looking projections of native load needs is critical.
The Six Cities do not have specific feedback to provide with respect to the calculation of Capacity Benefit Margin at this time. However, given the recent activation of multiple Energy Emergency Alert (“EEA”) 2 conditions, the Six Cities urge the CAISO to look seriously at adoption of Capacity Benefit Margin (“CBM”) in certain peak load months, such as August and September, to ensure that native load needs are addressed under uniquely stressful EEA 2 conditions. As the recent circumstances illustrate, it would be prudent for the CAISO to plan for the possibility that CBM set-asides may be necessary during certain periods.
6.
Provide your organization’s overall comments on calculating the ATC in the daily horizon, as described in section 5.1.2:
At this time, the Six Cities do not have specific concerns with respect to calculation of daily ATC separate and apart from the conceptual concerns discussed above with respect to the monthly methodology. At a conceptual level, the Six Cities support the idea of providing more granular refinement of ATC on a 2-day look ahead basis, but are not prepared to opine on the particulars of the daily ATC calculation given the broader conceptual issues with the overall proposal.
7.
Provide your organization’s comments on calculating existing transmission commitments (ETC), particularly native load needs, as it relates to the calculation of daily ATC, as described in section 5.1.2.2:
Please refer to the comments above in response to question 6.
8.
Provide your organization’s comments on the Transmission Reliability Margin (TRM) and the Capacity Benefit Margin (CBM) as it relates to daily ATC, as described in section 5.1.2.3:
Please refer to the comments above in response to question 6.
9.
Provide your organization’s comments on the method for accessing ATC to establish wheeling through scheduling priority, as described in section 5.1.3. In particular, consider comments on the requirements identified for accessing ATC.
The Six Cities do not oppose the criteria that the CAISO has set forth to enable external parties to access the proposed scheduling priority. The Six Cities agree that requiring a demonstration of a firm contract to serve load that requires scheduling priority across the CAISO system and prepayment of applicable charges (subject to resolution of concerns over what those charges should be) are appropriate minimum showings for parties seeking the scheduling priority. The Six Cities also agree that the duration of the priority and its applicable hours should not exceed the terms of the underlying supply contract.
More fundamentally, it appears the Straw Proposal will essentially provide external parties with priority access to any incremental ATC, while, at the same time, limiting CAISO load serving entities to historical levels of use on the CAISO’s interties with neighboring systems. The Six Cities therefore suggest that the CAISO consider integrating into its proposed framework a process for CAISO load serving entities to request and obtain access to any incremental ATC that may be available after considering native load needs, either ahead of or on equal footing with, external parties. As outlined above in response to the CAISO’s ATC methodology proposals, the CAISO’s initial options do not appear to adequately account for incremental needs, nor do these options appear to fully address projected growth in load. As native load needs evolve, the Six Cities are concerned that the proposed approaches are unduly restrictive and may preclude CAISO load serving entities from contracting with additional external resources to provide RA services or energy to the CAISO on a forward looking, bilateral basis. At a time when the CAISO is eager to strengthen ties with neighboring entities, restricting the ability of CAISO load to enter into agreements to obtain supply from neighboring regions would seem to reflect a misalignment with policy goals.
It may be that further discussion of either the proposed ATC methodology or whether and how the CAISO’s MIC process interacts with the ATC methodology could obviate the need to consider changing the framework in the Straw Proposal to allow CAISO load serving entities to access incremental ATC. At this time, however, there is not enough information in the Straw Proposal to allow stakeholders to meaningfully weigh the pros and cons of modifying the proposed framework in this way. If the CAISO believes that native load does not need access to incremental ATC, then the Six Cities request that the CAISO explain why.
10.
Provide your organization’s comments on the proposed enhancement to establish a window during which the submitted requests are vying for limited ATC based upon the underlying duration of the supply contract duration of ATC request as described in section 5.1.3:
The Six Cities do not have comments on this element of the Straw Proposal at this time.
11.
Provide your organization’s comments on a wheeling through priority rights holder’s ability to resell the wheeling through scheduling priority as described in section 5.1.3:
The Six Cities do not support making scheduling priority a transactable commodity and oppose establishing the ability of scheduling rights’ holders to resell their rights.
12.
Provide your organization’s comments on the ISO’s proposal to establish a process through which entities seeking to establish wheeling through priority on a long-term basis (longer than 1-year) can do so through submission of a study request and the ability to fund upgrades on the ISO system, including the ability of import (wheel in) requests driving Maximum Import Capability (MIC) upgrades as described in section 5.1.4:
The Six Cities are not necessarily opposed to implementation of a study process to enable external parties to obtain (and pay for) incremental transmission needs. As suggested by the CAISO in the Straw Proposal, CAISO load serving entities should also have the ability to request that the CAISO perform studies to address the need for incremental transmission projects to meet load needs. The Six Cities would like to better understand how the CAISO’s proposed long-term request process would integrate with existing procedures under the Transmission Planning Process.
With respect to the CAISO’s proposal as it pertains to external parties, the Straw Proposal asserts that the CAISO would have the ability to move forward with externally-proposed transmission projects as reliability, economic, or policy-driven upgrades. (Straw Proposal at 27.) The Six Cities interpret this to mean that the CAISO would agree to fund such upgrades through CAISO access charge rates. Given this, would the CAISO also propose to grant external parties a long-term scheduling priority over the new transmission assets, thereby providing external parties with increased rights over CAISO-funded transmission relative to CAISO native load? Or would the proposal to grant the scheduling priority only apply in situations where the external party up-front funds the upgrade? Would the entity also be required to pay WAC charges? Would the funding entity be required to become a CAISO Participating Transmission Owner?
In short, the CAISO’s proposal for potential upgrades may be conceptually appropriate, but more detail is needed.
The CAISO should also consider if the need for external parties to seek long term upgrades on the CAISO system belies flaws in the Inter-regional Transmission Planning Process. Under this process, planning entities should be evaluating new transmission projects on a wide-area, regional basis, including those projects that may provide economic benefits, such as access to inexpensive power located in another planning region. If there is a need to address wheeling firm power across multiple planning area footprints—such as from the Pacific Northwest to the Desert Southwest—then requirements for incremental transmission capacity may need to be addressed on a regional basis to enable coordination of those needs.
13.
Provide your organization’s comments on compensation for wheeling through scheduling priority, as described in section 5.1.5, along with any suggestions your organization may have regarding other potential ways to assess transmission charges for high priority wheeling through transactions:
The Six Cities do not support the CAISO’s proposal on compensation for wheeling through scheduling priority. Although the Six Cities agree that entities obtaining wheeling through scheduling priority should prepay their charges for the duration of the priority, the Six Cities do not support use of the unadjusted Wheeling Access Charge (“WAC”) as the applicable rate. While the Six Cities concur that a complete overhaul of the WAC may not be needed and that the CAISO may use the WAC as a starting point for applicable charges, the Six Cities urge the CAISO to formulate a scalar or an adder to the WAC to reflect that entities will likely seek scheduling priorities during peak times and to provide appropriate compensation for the priority reservation itself.
Before the next iteration of the CAISO’s proposal in this initiative, the Six Cities request that the CAISO hold a workshop on rate design, with a view to development of a scalar or an adder to the WAC to reflect the use of the CAISO transmission system during peak months and days. The workshop should not just include entities external to the CAISO presenting information about their rate structures, but should also include proposals from CAISO entities as to how they believe the wheeling scheduling priority charges should be structured in order to provide just and reasonable compensation for use of the CAISO system.
14.
Provide your organization’s comments on the proposed WEIM decisional classification, as described in section 6:
As this initiative pertains to the rates, terms, and conditions of access to and use of the CAISO transmission system, the Board of Governors should have primary authority to approve the proposals in this initiative.
15.
Provide any additional comments on the Transmission Service and Market Scheduling Priorities Phase 2 straw proposal and August 11, 2022 stakeholder call discussion:
The Six Cities have no additional comments at this time.
Vistra Corp.
Submitted 09/19/2022, 05:24 pm
1.
Please provide a summary of your organization’s comments on the Transmission Service and Market Scheduling Priorities Phase 2 straw proposal and August 11, 2022 stakeholder call discussion:
It has been over 14 months since launching this initiative with more than 10 months of that on phase 2, which is supposed to replace the current design with a durable framework that respects open access. It has been even longer if you consider this discussion began in the summer 2021 readiness initiative launched almost 22 months ago. It appears to Vistra that after 22 months of discussions, the CAISO has not meaningfully incorporated stakeholders input and concerns into its development of this straw proposal.
As the CAISO is aware Vistra protested[1] its tariff amendment filing on May 19, 2021. Vistra protested the rules as applied to imports, exports, and wheels. We reject the notion that this initiative is only to address concerns with wheels as the CAISO seems to be implying. FERC approved the previous Tariff Amendment based on the specific facts and circumstances that CAISO put forward in the ER21-1790 docket at that time[2]. Any future Commission review will be reviewed de novo under any new data and information put forward at the time of any future filing. The previous order does not mean that the Commission will not have to evaluate whether any future filing to determine if it meets the just and reasonable standard based on those specific facts and circumstances. There is a significant amount of new information including day-ahead and hour-ahead performance to balance access to the grid including during the recent stressed conditions between August 31, 2022 and September 9, 2022.
The straw proposal suffers from the same flaws that Vistra raised in its letter[3] to the Board of Governors at the April 19, 2021 board meeting considering the temporary tariff provisions. As we shared with the board in 2021, we continue to believe the following.
Vistra expects this proposal will face an uphill battle at the Federal Energy Regulatory Commission (“Commission”) where the CAISO will need to support it based on a flawed assumption that there is a certain amount of the transmission system to which native load has a right based on reliability needs. Open access rules approved by the Commission conflict with this assumption. Open access rules dictate that native load must share access to the transmission system with other firm rights. Firm rights cannot be withheld in case native load might need them. It is true that native load with the equivalent of a designated network resource may request to secure firm rights. That request does not guarantee their receipt of those rights if all firm rights were previously secured by another party. For non-native load purposes (i.e. wheel-throughs or exports), the commodity contract backing the transaction is not an appropriate way to prioritize transmission reservation or transmission curtailment priorities. We are concerned the proposal is based on this fundamental misunderstanding of open access rules.
Vistra is convinced that ensuring that FERC Order 888 open access rules are maintained when differentiating the complex priorities for wheel-throughs, imports, and exports simply cannot be done through an ad hoc, negotiated process. A short-term solution should not be pursued that could result in discriminatory access to the transmission system. Further, any solution should not be contemplated in relationship to the equivalent Resource Adequacy (“RA”) contracting since for non-native load purposes this is inappropriate criteria for prioritization. Rather, open access should be prioritized based on varying levels of investment to procure the optionality to use the transmission system. We recognize this functionality needs to be developed and have been requesting that the CAISO focus on doing so to address these issues. The appropriate and efficient way to prioritize access to the transmission system is based on forward procurement of a higher priority transmission service with which the intertie transactions are associated. Based on our experience in markets with these systems, selling of transmission reservations allows for non-discriminatory prioritization of the transfer capability to those transactions that have paid to reserve the higher priority service.
Respectfully, open access is foundational to well-functioning, competitive markets. Short cuts to ensuring open access will harm overall market health both in the CAISO and the wider WECC. The CAISO should not move forward with this framework as proposed and it is counterproductive to provide comments on the details proposed as the general framework is flawed, discriminatory, and contrary to open access.
[1] Vistra protest in Docket No. ER21-1790, May 19, 2021, https://elibrary.ferc.gov/eLibrary/filedownload?fileid=020D4AB5-66E2-5005-8110-C31FAFC91712.
[2] Order Accepting Tariff Revisions, Subject to Further Compliance re California Independent System Operator Corporation under ER21-1790. Available at, https://elibrary.ferc.gov/eLibrary/filedownload?fileid=020DD174-66E2-5005-8110-C31FAFC91712.
[3] Vistra letter to the Board of Governors on market enhancements for Summer 2021 readiness – load, export and wheeling priorities, April 19, 2021, http://www.caiso.com/Documents/Public-comment-letter-Vistra-re-decision-summer-readiness-initiative-April-19-2021.pdf.
3.
Provide your organization’s overall comments on calculating ATC in the monthly horizon, as described in section 5.1.1. In particular, the different approaches for calculating native load needs as an existing commitment and other components of the ATC methodology as discussed in the proposal. The ISO encourages stakeholders to share potential alternative methods for consideration in calculating components, particularly native load needs.
Refer to Vistra’s education briefing provided to the CAISO staff and stakeholders on November 10, 2021.
This education was provided so that CAISO staff would have the necessary background to develop a straw proposal that is non-discriminatory and consistent with open access rules. Available at, http://www.caiso.com/InitiativeDocuments/VistraPresentation-ExternalLoadForwardSchedulingRightsProcess-WorkingGroup1-Nov10-2021.pdf.
Vistra is disappointed staff did not avail themselves of the opportunity to learn from our November briefing. No outreach was performed by CAISO staff to Vistra to seek clarity on our views of the FERC native load priority rules. Vistra would have willingly engaged with staff to help them bridge their knowledge gap if afforded the opportunity over the last eleven months. It is disappointing and disheartening that the CAISO is not willing to engage in a collaborative, robust stakeholder process. We strongly prefer a collaborative stakeholder process to contentious litigation at FERC.
4.
Provide your organization’s comments on each of the ISO’s proposed approaches for calculating existing transmission commitments (ETC) as it relates to the ATC methodology as described in section 5.1.1.2. Particularly, the ISO seeks comment on the methods or approaches identified for estimating native load needs across a 13-month horizon and encourages stakeholders to suggest potential variations to inputs in deriving the amount of transmission capacity to set aside for native load needs.
See above responses.
5.
Provide your organization’s comments on the Transmission Reliability Margin (TRM) and the Capacity Benefit Margin (CBM) as it relates to the ATC methodology, as described in section 5.1.1.3:
Refer to Vistra’s education briefing provided to the CAISO staff and stakeholders on November 10, 2021.
This education was provided so that CAISO staff would have the necessary background to develop a straw proposal that is non-discriminatory and consistent with open access rules. This education includes CBM and TRM guidance. The CAISO proposal must meet these guidelines. Available at, http://www.caiso.com/InitiativeDocuments/VistraPresentation-ExternalLoadForwardSchedulingRightsProcess-WorkingGroup1-Nov10-2021.pdf.
6.
Provide your organization’s overall comments on calculating the ATC in the daily horizon, as described in section 5.1.2:
It is premature and unproductive to comment on details of the straw proposal because the basic proposal is contrary to open access rules.
7.
Provide your organization’s comments on calculating existing transmission commitments (ETC), particularly native load needs, as it relates to the calculation of daily ATC, as described in section 5.1.2.2:
It is premature and unproductive to comment on details of the straw proposal because the basic proposal is contrary to open access rules.
8.
Provide your organization’s comments on the Transmission Reliability Margin (TRM) and the Capacity Benefit Margin (CBM) as it relates to daily ATC, as described in section 5.1.2.3:
It is premature and unproductive to comment on details of the straw proposal because the basic proposal is contrary to open access rules.
9.
Provide your organization’s comments on the method for accessing ATC to establish wheeling through scheduling priority, as described in section 5.1.3. In particular, consider comments on the requirements identified for accessing ATC.
Vistra opposes. See response to #1.
10.
Provide your organization’s comments on the proposed enhancement to establish a window during which the submitted requests are vying for limited ATC based upon the underlying duration of the supply contract duration of ATC request as described in section 5.1.3:
It is premature and unproductive to comment on details of the straw proposal because the basic proposal is contrary to open access rules.
11.
Provide your organization’s comments on a wheeling through priority rights holder’s ability to resell the wheeling through scheduling priority as described in section 5.1.3:
It is premature and unproductive to comment on details of the straw proposal because the basic proposal is contrary to open access rules.
12.
Provide your organization’s comments on the ISO’s proposal to establish a process through which entities seeking to establish wheeling through priority on a long-term basis (longer than 1-year) can do so through submission of a study request and the ability to fund upgrades on the ISO system, including the ability of import (wheel in) requests driving Maximum Import Capability (MIC) upgrades as described in section 5.1.4:
It is premature and unproductive to comment on details of the straw proposal because the basic proposal is contrary to open access rules.
13.
Provide your organization’s comments on compensation for wheeling through scheduling priority, as described in section 5.1.5, along with any suggestions your organization may have regarding other potential ways to assess transmission charges for high priority wheeling through transactions:
It is premature and unproductive to comment on details of the straw proposal because the basic proposal is contrary to open access rules.
14.
Provide your organization’s comments on the proposed WEIM decisional classification, as described in section 6:
Vistra opposes the CAISO’s recommendation. The classification for this initiative clearly falls under joint authority.
Vistra disagrees with the CAISO sentence on Page 31 that states “None of the currently contemplated tariff changes would be “applicable to EIM Entity balancing authority areas, EIM Entities, or other market participants within EIM Entity balancing authority areas, in their capacity as participants in EIM.” This initiative scope clearly applies to Energy Imbalance Market entities and other market participants within the non-CISO EIM BAA. For example, an EIM Entity could submit into the CAISO integrated forward market an export bid from the CAISO to plan to use any cleared exports to support imports into their EIM BAA. The CAISO day-ahead market is a tool to pre-arrange exports out of CAISO BAA into BAAs including non-CISO EIM BAAs. These pre-arranged imports are included in the Resource Sufficiency Evaluation tests. Consequently, changes to the ability to pre-arrange imports that are included in and contribute to meeting the RSE today directly apply to EIM entities’ EIM operations.
15.
Provide any additional comments on the Transmission Service and Market Scheduling Priorities Phase 2 straw proposal and August 11, 2022 stakeholder call discussion:
It is unhelpful for the CAISO to imply this initiative only impacts wheels and not imports or exports access to the Available Transfer Capability. It would be beneficial for all if the CAISO could be more precise in its language to avoid creating confusion. Vistra requests at a minimum the CAISO change its language to make it clear that this initiative scope deals with balancing access to transmission capability between equivalent of network customers (Load Serving Entities), native load, and intertie transactions that respect open access rules. Open access should be respected whether the transmission access is being sought to support an import, export, or wheel through.
