Comments on Draft Final Proposal and 9/17 Stakeholder Meeting

1. Please provide a summary of your organization’s overall comments on the gas resource management stakeholder meeting on September 17, 2025.

Comments on Gas Resource Management:

Draft Final Proposal

Department of Market Monitoring

October 3, 2025

Summary

The Department of Market Monitoring (DMM) appreciates the opportunity to comment on the Gas Resource Management Draft Final Proposal.[1] DMM supports or does not oppose most elements of the draft final proposal. However, DMM has significant concerns about the proposed benchmark approach to establish default costs and reference level change request (RLCR) thresholds for units that face much higher gas price volatility than the benchmark resources. 

DMM provides comments here on the following topics discussed in the draft final proposal:

• Informing fuel procurement. DMM supports the ISO’s efforts to provide scheduling coordinators with accurate advisory gas burn schedules. DMM previously recommended the ISO provide analysis of the appropriateness of using various alternative bid sets to fill in bids for resources that do not submit in time for the two-day advisory (D+2) market run. DMM does not oppose moving forward without this preliminary analysis and views the current proposal as an incremental improvement to gas resource management. DMM recommends the ISO conduct future analysis to continue to refine things such as the appropriate inputs into the D+2 report.
• Managing gas burn limitations. DMM continues to support the exclusion of operation flow order (OFO) costs in reference level calculations, and supports the conditions and guidelines the ISO developed for interested market participants to follow if they want to pursue implementing a gas nomogram in the market.
• Accommodating cost variation. DMM supports allowing customized default costs and RLCR thresholds based on analysis of historical data on the difference between (1) available gas price indices at the most appropriate hub for each resource, and (2) the unit’s actual gas procurement costs.  However, DMM has major concerns about the benchmark group approach outlined in the proposal for setting default costs and RLCR thresholds for units with much higher gas price volatility. At a minimum, this approach should be developed in more detail, and subject to further review and analysis based on actual historical data on gas price volatility and the frequency of RLCR requests. If the ISO proceeds to seek regulatory approval for this proposal at this time, DMM believes that any policy or tariff changes submitted for approval must provide significant flexibility in what ultimately gets implemented through the business practice manual (BPM). DMM believes many concerns might be addressed by setting a cap on the maximum level of scalar applied to default costs and RLCR thresholds that might result from any default methodology established by the ISO.

Comments

1. Informing fuel procurement

DMM does not oppose the proposal to move forward with the D+2 report without further analysis, but recommends future analysis to refine the inputs to the D+2 advisory schedules

In the straw proposal, the ISO sought feedback on what to do when bids are not submitted in time for the D+2 market run. The proposal suggested using the day-ahead bid set submitted for the day-ahead market on the day the D+2 is run (day-ahead bids), bids from 7 days prior, or—at the discretion of operators—using either of those options  as inputs to the D+2 market run. DMM suggested the ISO analyze historical data to determine if using day-ahead bids or 7 day prior bids result in more accurate gas burn forecasts on average, and if there are specific situations where one set of bids outperforms the other (e.g., when weather conditions are drastically different than the previous week, or when using weekend bids would cause issues for early weekday forecasts).

The ISO is proposing in the draft final proposal to move forward with the D+2 report, without additional analyses beyond what was presented in the straw proposal. The ISO plans on performing a more comprehensive analysis sometime after extended day-ahead market (EDAM) go-live when new data becomes available. DMM acknowledges historic analyses may provide limited insight into the accuracy of the D+2 as advisory schedules once the changes for EDAM are implemented, such as expanded balancing authority area (BAA) participation and imbalance reserves. However, DMM believes an analysis that includes only the pre-EDAM CAISO BAA would still be informative.

While DMM believes additional analysis would be valuable to determine the bid set that produces the most accurate advisory forecast, DMM does not oppose the proposal to move forward with the D+2 report without further analysis as a near-term approach, and supports the ISO’s commitment to assessing the difference in gas burn between the D+2 and day-ahead, and assessing the impact different bid sets have on D+2 accuracy in the future.

In addition to these future analyses, the ISO is proposing to expand the D+X reporting from the current practices. First, the ISO proposes to publish advisory energy schedules and RUC awards separately as opposed to combined. Second, the ISO is proposing to publish descriptive statistics to indicate the accuracy of market results, such as the balancing area (BA) level uncertainty requirement. Third, the ISO is proposing to publish residual unit commitment (RUC) advisory results from the D+3 and D+4 reports, which should be useful for Mondays and holidays. DMM supports all these proposals to expand the D+X reporting practices to improve transparency for market participants.

2. Managing gas burn limitations

DMM supports the ISO providing guidelines to extend the use of the gas nomogram constraint to areas outside the CAISO balancing area

The ISO proposes a process to allow use of the gas nomogram constraint to regions outside the Southern California Gas Company (SoCal Gas) and San Diego Gas & Electric gas regions. Market participants outside the CAISO balancing area who want to make use of a gas nomogram to reflect gas limitations in the market for specific zones must meet certain conditions informed by the ISO’s previous experiences seeking FERC approval for gas nomograms. These conditions include:

• Establishing a relationship between the BA and the gas pipeline operator,
• Demonstrations from the BA and gas pipeline operator that a gas system limitation can impact electric system reliability,  
• Determination by the gas pipeline operator, BA, and the ISO that a gas nomogram constraint is needed and a reasonable approach, and
• Confirmation from the ISO that the requested procedure is consistent with existing operational procedure.

DMM supports this proposal to further improve gas-electric coordination to reduce inefficiencies in electric market outcomes during gas supply limitations. DMM would monitor use of any gas nomograms for any indication of potential capacity withholding.

3. Accommodating gas cost variation

DMM supports allowing customized RLCR thresholds based on analysis of historical data on the difference between (1) available gas price indices at the most appropriate hub for each resource, and (2) the unit’s actual gas procurement costs. Ideally, such analysis should be based on data for a significant time period (e.g., at least 1 year, but longer if possible, since it is often 2 to 4 years in between major gas price spikes).  While DMM supports this general framework, DMM has concerns about some aspects of the specific approach described in the draft final proposal.

The proposed initial screening approach to request volatility scalar adjustment may be susceptible to gaming 

DMM appreciates the ISO’s desire to set some kind of screen to determine units for which RLCR thresholds above current levels may be appropriate. A resource will pass the proposed screen if the frequency of their RLCRs exceeds the average of the benchmark resources. To prevent gaming, the ISO is proposing to not publish the benchmark RLCR frequency, and require resources that request a fuel cost parameter adjustment but do not pass the initial screen to wait a year to re-request evaluation. However, DMM notes there is still potential for gaming by frequently submitting automated RLCR requests just below the threshold to ensure a resource’s RLCR request frequency is above the average of the reference group. DMM recommends the ISO commit to auditing all, or at least a significant random sample of, RLCR requests after an individual resource requests a fuel volatility scalar adjustment that the ISO had not audited before the request in order to mitigate this potential gaming risk.

DMM does not believe it is appropriate to use the benchmark group approach as outlined in the proposal to determine fuel cost adjustments for units with much higher gas price volatility

DMM has major concerns about the benchmark group approach outlined in the proposal for determining fuel cost adjustments for units with much higher gas price volatility.

DMM’s sense is that the frequency of gas units in the CAISO using RLCRs may be extremely low (e.g., potentially less than 1 percent of intervals throughout the year). If so, the approach outlined in example 1 of the fuel cost adjustment determination section of the draft final proposal would seek to set customized default costs and RLCR thresholds so that each unit’s potential procurement cost may exceed the threshold in less than 1 percent of cases (e.g., at the 99^th percentile of observed percentage differences between a unit’s reported fuel costs and the most relevant gas hub price).[2] In areas outside of the CAISO with much greater gas price volatility, setting default costs and RLCR thresholds in this way could result in extremely high thresholds that are driven by a very small number of extreme outcomes. DMM believes this issue might be addressed by setting a cap on the maximum level of scalar applied to RLCR thresholds used in automated cost verification, as discussed later in these comments.

Also, as a matter of principle, DMM does not believe that it makes sense to seek to limit the frequency with which participants in areas with very high gas volatility may need to request use of gas prices in excess of the RLCR threshold, based on the frequency of RLCR requests in excess of the threshold in areas with very low gas price volatility (such as the CAISO). DMM thinks it is reasonable to expect that units in areas with very high gas volatility may submit RLCRs in excess of the thresholds more often than units in areas with very low gas price volatility. Instead, the RLCR thresholds should be set so that the frequency that non-automated mechanism for gas cost review and justification is manageable for participants and the ISO. For example, just because units in areas with low gas price volatility may submit RLCRs in excess of their threshold only 1 percent of days, it may still be reasonable for units facing extremely high gas price volatility to submit RLCRs in excess of their threshold 3 percent of days.

DMM also notes that the higher the RLCR is set (e.g., in terms of headroom above actual fuel costs on most days), the greater the need for the ISO to perform review of RLCRs under the thresholds, which are automatically “verified” prior to the market process, but subject to potential audit. Thus, if the ISO sets thresholds for automated verification extremely high, the ISO may need to be prepared to devote significantly more resources to ex post review of RLCRs that are automatically approved. The ISO and stakeholders should consider this potential tradeoff.

More analysis of actual data is needed

DMM believes there is a wealth of data currently available that could be used to assess the feasibility and implications of the general framework outlined in the draft final proposal. Such analysis may help identify very different variations of this general approach than those suggested in the draft final proposal. For example, such analysis might indicate the potential for some extremely high or unexpected RLCR thresholds under the approach currently envisioned by the ISO, and might help identify ways of mitigating these potential outcomes.

As noted above, one mitigation measure might be to set a hard cap on threshold scalars that results from any default methodology (e.g., 150 to 175 percent). With this approach, participants could also seek higher scalars under the negotiated option of the tariff when necessary. The tariff could also be changed to allow the negotiated option to be used for gas prices used in setting commitment costs, as well as default energy bids. Presumably, if the default methodology and cap are set appropriately, use of this negotiated option should still be quite limited.

If the ISO proceeds to seek regulatory approval for this proposal at this time, DMM believes that any policy or tariff changes submitted for approval must provide significant flexibility in what ultimately gets implemented through the BPM. And any approach specified in the BPM should be based on further analysis of actual data available to the ISO, and consideration of approaches that may vary significantly from the draft final proposal, as discussed above.

DMM supports expanding after-the-fact cost recovery rules to physical supply disruptions in certain documented circumstances

The ISO requires resources to submit a cost adjustment request before the day-ahead market to be eligible for after-the-fact cost recovery. Since physical supply disruptions can occur after the cost adjustment deadline, the ISO is proposing to allow resources to be eligible for after-the-fact cost recovery if they can demonstrate with supporting documentation that a physical supply disruption occurred after the day-ahead bidding deadline on the fuel region actively indexed in the resource’s reference levels, and provide documentation on the incurred fuel costs that were not covered in the market.

DMM supports this proposal to expand after-the-fact cost recovery for physical supply interruption circumstances that were not foreseeable in advance of the day-ahead market timeline. DMM supports the level of granularity of the documentation requirement the ISO outlined in the guidelines and conditions that must be met for resources to qualify for after-the-market cost recovery for physical disruptions.

[1]  Gas Resource Management Draft Final Proposal, California ISO, September 17, 2025: https://stakeholdercenter.caiso.com/InitiativeDocuments/Draft-Final-Proposal-Gas-Resource-Management-Sep-17-2025.pdf

[2]  Gas Resource Management Draft Final Proposal, California ISO, September 17, 2025, p 16: https://stakeholdercenter.caiso.com/InitiativeDocuments/Draft-Final-Proposal-Gas-Resource-Management-Sep-17-2025.pdf

2. Please provide a summary of your organization’s comments on the gas resource management draft final proposal, published on September 17, 2025.

Please see the PDF attached below the final question for DMM's fully formatted complete set of comments. For the reader's convenience, the complete text of the comments is pasted in response to #1, but there may be some formatting errors.

3. Please provide your organization’s feedback to the ISO’s proposed changes to fuel procurement (GRM DFP Section 3) by:

1. improving the quality of the bid set used to run the D+2 by using D+1 bids if available, and DA bids if not; 2. publishing D+2 advisory energy schedules to day-ahead participating SCs; and 3. publishing D+3, D+4 RUC advisory results to market participants

Please see the PDF attached below the final question for DMM's fully formatted complete set of comments. For the reader's convenience, the complete text of the comments is pasted in response to #1, but there may be some formatting errors.

4. Please provide any feedback regarding the ISO’s proposed fuel cost parameter adjustments process (GRM DFP Section 4.3)

Please see the PDF attached below the final question for DMM's fully formatted complete set of comments. For the reader's convenience, the complete text of the comments is pasted in response to #1, but there may be some formatting errors.

5. Please provide any feedback regarding the ISO’s proposal to provide more flexibility through the automated cost adjustment process to manage fuel procurement uncertainty (DFP Section 4.4).

Please see the PDF attached below the final question for DMM's fully formatted complete set of comments. For the reader's convenience, the complete text of the comments is pasted in response to #1, but there may be some formatting errors.

6. Please provide any feedback regarding the ISO’s proposal to make existing gas nomogram procedure accessible to EDAM/WEIM BAAs (GRM DFP Section 5.1)

Please see the PDF attached below the final question for DMM's fully formatted complete set of comments. For the reader's convenience, the complete text of the comments is pasted in response to #1, but there may be some formatting errors.

7. Please provide any feedback not already captured.

Please see the PDF attached below the final question for DMM's fully formatted complete set of comments. For the reader's convenience, the complete text of the comments is pasted in response to #1, but there may be some formatting errors.

1. Please provide a summary of your organization’s overall comments on the gas resource management stakeholder meeting on September 17, 2025.

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2. Please provide a summary of your organization’s comments on the gas resource management draft final proposal, published on September 17, 2025.

IPC appreciates the opportunity to be a part of the GRM and we support the final proposal moving forward. We know the GRM team has done a fantastic job outlining and defining the different aspects of the proposal. We do still suggest care and time be spent clearly outlining and defining all the different parts of the proposal as it is translated into practice.

3. Please provide your organization’s feedback to the ISO’s proposed changes to fuel procurement (GRM DFP Section 3) by:

1. improving the quality of the bid set used to run the D+2 by using D+1 bids if available, and DA bids if not; 2. publishing D+2 advisory energy schedules to day-ahead participating SCs; and 3. publishing D+3, D+4 RUC advisory results to market participants

1. Improving the quality of the bid set used to run the D+2 by using D+1 bids if available, and DA bids if not;

2. Publishing D+2 advisory energy schedules to day-ahead participating SCs; and

3. Publishing D+3, D+4 RUC advisory results to market participants

 IPC supports the proposal moving forward.

4. Please provide any feedback regarding the ISO’s proposed fuel cost parameter adjustments process (GRM DFP Section 4.3)

IPC supports the reference levels, cost adjustments, and a post cost recovery review. We do not agree with limiting the frequency of reference level change requests (RLCRs) or using RLCR frequency solely as an approve/not approved parameter. It’s okay to consider it as a parameter, but natural gas pipelines are dynamic and differ system to system. We agree the after-the-fact cost recovery rule for physical disruptions does address this concern. But it needs to be noted, that a new constraint or condition might appear that historically has never been a market/flow factor. Financial market disruptions can be just as impactful and physical supply disruptions. The rational for why a RLCR or a fuel cost adjustment was requested should always be the most important factor/parameter and evaluated case by case with some level of reasonability that might not always be clearly defined.

5. Please provide any feedback regarding the ISO’s proposal to provide more flexibility through the automated cost adjustment process to manage fuel procurement uncertainty (DFP Section 4.4).

IPC supports the proposal moving forward. Increased flexibility and a reduction of manual review is always preferred. That said, IPC suggests a review or spot checking of the automated process to ensure market participants aren’t abusing the process.

6. Please provide any feedback regarding the ISO’s proposal to make existing gas nomogram procedure accessible to EDAM/WEIM BAAs (GRM DFP Section 5.1)

 IPC supports the initiative.

7. Please provide any feedback not already captured.

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1. Please provide a summary of your organization’s overall comments on the gas resource management stakeholder meeting on September 17, 2025.

N/A

2. Please provide a summary of your organization’s comments on the gas resource management draft final proposal, published on September 17, 2025.

LADWP appreciates CAISO’s continued engagement with stakeholders on aligning gas procurement practices with electric market operations. The September 17 meeting was productive, providing clarity on the proposed changes and helping to surface key concerns regarding procurement timing, advisory schedules, and alignment with EDAM/WEIM participation. We also value CAISO’s ongoing efforts to strengthen gas-electric coordination, including its proposal to publish more granular advisory market results, extend advisory results for D+X, expand fuel cost parameterization enhancements, and provide additional flexibility to manage uncertainty.

These initiatives represent meaningful progress in supporting system reliability, particularly as natural gas remains a vital fuel source for balancing supply across the region. We continue to emphasize the importance of ensuring fuel certainty for gas resources while balancing flexibility for market participants.

3. Please provide your organization’s feedback to the ISO’s proposed changes to fuel procurement (GRM DFP Section 3) by:

1. improving the quality of the bid set used to run the D+2 by using D+1 bids if available, and DA bids if not; 2. publishing D+2 advisory energy schedules to day-ahead participating SCs; and 3. publishing D+3, D+4 RUC advisory results to market participants

LADWP supports CAISO’s initiative to provide increased transparency on market information through the D+X improvements. The additional D+2 details and supplemental D+X advisory schedules will serve as a critical input to SCs procurement planning.

LADWP reiterates the importance of CAISO working closely with Scheduling Coordinators to improve the Day-Ahead load forecast to minimize forecast error to the greatest extent possible. Forecast accuracy will have a significant impact on advisory schedules as well as forecasted gas burn.

LADWP would like to offer clarification regarding the following statement for Section 3. Informing Fuel Procurement on Page 7 of the proposal:

LADWP would like to ensure that we appropriately distinguish financial procurement deadlines, which determine the cost of fuel, and natural gas scheduling deadlines, which affect the physical delivery priority and ranking of that fuel. The Timely nomination deadline of 11 AM PST serves as the key natural gas scheduling deadline. In contrast, the financial procurement deadline, which governs financial settlements and enables market participants to transact at an index price, typically occurs at 6:00 AM PST on standard trading days, though it can start earlier under high demand or uncertain market conditions.

4. Please provide any feedback regarding the ISO’s proposed fuel cost parameter adjustments process (GRM DFP Section 4.3)

LADWP supports an automated process for administrative simplicity over a negotiation process. However, we value the  flexibility in the negotiation process and solutions to accommodate unique circumstances. LADWP supports the enhancement being made to accommodate gas cost variations, ensuring greater alignment between market outcomes and actual operating conditions.

LADWP would like to highlight the following items in addition to Example 1 and 2 on page 12 of the proposal:

1. Natural gas is not always procured at flat index pricing, even at highly liquid hubs. Premiums may be negotiated and added to the index, particularly during periods of extreme weather, pipeline constraints, or heightened market uncertainty.
2. Each pipeline manages operating conditions and physical constraints differently, which in turn influences how indexes clear at each hub and directly impacts financial settlement.

Given that CAISO’s market footprint extends beyond PG&E and SoCal Citygate, both which benefit from ample storage, evaluating volatility solely in these two hubs may misrepresent the true level of price volatility and system constraints in other gas regions. This approach risks understating the gas cost volatility experienced by generators outside of these zones.

LADWP recommends that CAISOs expands its volatility analysis to include gas price indexes from hubs beyond PG&E and SoCal Citygate. In addition, LADWP continues to encourage CAISO to maintain ongoing dialogue with interstate pipeline operators to gain a better understanding of their reliability practices and, where appropriate, incorporate those practices into CAISO’s operational tools.

5. Please provide any feedback regarding the ISO’s proposal to provide more flexibility through the automated cost adjustment process to manage fuel procurement uncertainty (DFP Section 4.4).

LADWP agrees with other stakeholders and would also like to reiterate that advisory information is only useful if there’s high confidence in the accuracy of the information. LADWP also supports CAISO efforts to provide additional flexibility to request cost adjustments.

LADWP would like to offer a clarification regarding the following statement for Section 4.4. Flexibility to manage fuel procurement uncertainty on Page 18 of the proposal:

Uncertainty in timely cycle might not only lead to higher real-time pricing and reduce liquidity availability but also risk flows on transportation ranking when physical gas is procured on later cycles (ID1-ID3). Because of the inherent gas procurement target uncertainty, analytics are as important for gas procurement as the confidence level in gas forecasting.

For section 4.5 After-the-fact cost recovery rules for constraints and supply disruptions it states the following:

LADWP agrees that the physical supply disruptions should be eligible for ex-post cost recovery, provided these guidelines are in addition to the existing ex-post cost recovery process.

However, if these guidelines are intended to replace the current process, limiting after-the fact cost recovery strictly to physical supply disruptions would significantly constrain the ability to recover cost when price volatility causes spikes, driven by factors outside of physical gas constraints. LADWP recommends that CAISO re-asses this requirement to allow cost recovery to also be eligible for the ex-post cost recovery when stakeholders can demonstrate to the CAISO that the cost of gas that was paid for was higher than the projected index or pricing. Cost adjustment request should not be limited to only physical constraints as demand itself can also be the driving factor for price spikes . Flexibility is necessary, but CAISO should ensure that adjustments do not disadvantage participants with limited access to real-time gas prices and verified settlement data.

6. Please provide any feedback regarding the ISO’s proposal to make existing gas nomogram procedure accessible to EDAM/WEIM BAAs (GRM DFP Section 5.1)

LADWP supports CAISO’s consideration of establishing a gas nomogram constraint for a BA or gas region outside of the CAISO BA, as well as developing a clear plan outlining the steps and criteria required for doing so. Overall, LADWP supports extending nomogram access to EDAM and WEIM participants to enhance market reliability and promote greater alignment across the footprint.

7. Please provide any feedback not already captured.

LADWP finds CAISO’s draft proposal to be a helpful step forward and encourages recognition of the regional differences in pipeline operations and the electric market. LADWP also encourages CAISO to carefully consider the feedback provided by stakeholders at the Market Surveillance Committee session on September 19^th, 2025, including input on gas forecasting accuracy, analysis of stakeholders and BAs outside of CAISO BA, and considering the potential limitations of a standardized approach. In some cases, a tailored, per-pipeline solution may be more effective for supporting economic and reliable management, modeling, and maintenance of gas resources.

1. Please provide a summary of your organization’s overall comments on the gas resource management stakeholder meeting on September 17, 2025.

NV Energy appreciates CAISO’s efforts for launching the Gas Resource Management stakeholder initiative to address persistent challenges within the EIM and to proactively incorporate gas management considerations in the forthcoming EDAM. NV Energy supports the proposed changes outlined in the draft final proposal and offers the following comments for further refinement ahead of the final proposal. Additionally, NV Energy views this draft final proposal as a reasonable outcome for Phase 1 and encourages continued dialogue in a Phase 2 to further advance gas management solutions.

2. Please provide a summary of your organization’s comments on the gas resource management draft final proposal, published on September 17, 2025.

No comment.

3. Please provide your organization’s feedback to the ISO’s proposed changes to fuel procurement (GRM DFP Section 3) by:

1. improving the quality of the bid set used to run the D+2 by using D+1 bids if available, and DA bids if not; 2. publishing D+2 advisory energy schedules to day-ahead participating SCs; and 3. publishing D+3, D+4 RUC advisory results to market participants

NV Energy appreciates CAISO’s initiative to enhance the D+2 advisory market schedules to better support the Timely gas nomination cycle. Accurate and reliable D+2 results are critical for informed gas procurement decisions, and while we acknowledge that these forecasts will never be perfect, NV Energy strongly supports any improvements that increase their utility and precision.

4. Please provide any feedback regarding the ISO’s proposed fuel cost parameter adjustments process (GRM DFP Section 4.3)

NV Energy supports CAISO proposed changes to the fuel cost parameter adjustments and appreciates the inclusion of commitment costs in the reference level change request process. Additionally, CAISO proposes to allow all new entrants participating in the day ahead or real time market to automatically pass the screen which should alleviate issues as participants make changes to their business practices to participate in the market and accommodate market awards.

While NV Energy appreciates and supports these proposals, we recommend that CAISO reconsider the one year restriction placed on participants who fail the screen. Given that gas conditions can vary seasonally, it is not reasonable to prevent reapplication for a full year. This provision may be more appropriate after a year or two of operational experience, but should not be implemented at the outset of the initiative.

5. Please provide any feedback regarding the ISO’s proposal to provide more flexibility through the automated cost adjustment process to manage fuel procurement uncertainty (DFP Section 4.4).

NV Energy appreciates the proposed changes to provide more flexibility through the automated cost adjustment process but recommends that CAISO further refine this trigger to not only evaluate at the EDAM market footprint as a whole but to evaluate at individual Balancing Authority Areas (“BAA”).  The market footprint may not experience changes when individual BAAs might see swings from the forecast. It would be more beneficial for the automated process to trigger for specific fuel regions if that region deviates from the forecasts.

6. Please provide any feedback regarding the ISO’s proposal to make existing gas nomogram procedure accessible to EDAM/WEIM BAAs (GRM DFP Section 5.1)

NV Energy supports extending the nomogram functionality to the broader market footprint beyond California. Market participants in the Western U.S. region face their own unique gas constraints other than just California, and it is important that this functionality be available to benefit the entire footprint rather than being limited to a single geographic area.

7. Please provide any feedback not already captured.

During the Market Surveillance Committee (“MSC”) call, CAISO and the MSC discussed the commitment cost bidding cap that was designed as part of Commitment Cost and Default Energy Bid Enhancements (“CCDEBE”) but not implemented. NV Energy agrees with the MSC that the implementation challenges associated with this market design warrant further stakeholder engagement. NV Energy is encouraged by CAISO’s intention to initiate this discussion during Phase 2 of the Gas Resource Management initiative. NV Energy supports continued dialogue on this topic and recommends that CAISO formally launch phase 2 of this initiative in 2026.

1. Please provide a summary of your organization’s overall comments on the gas resource management stakeholder meeting on September 17, 2025.

• PG&E requests targeted improvements, clarity on bid set expectations, and transparency on assumptions regarding the proposal for informing fuel procurement. These points are discussed in Comment #3.
• PG&E advises against using the D+2 forecast to determine cost adjustment eligibility. While the D+2 forecast can support planning when bids are submitted accurately, it is not financially binding. PG&E is concerned about tying the D+2 forecast to compensation as it could introduce risks of inappropriate bidding behavior and manipulation.

2. Please provide a summary of your organization’s comments on the gas resource management draft final proposal, published on September 17, 2025.

 No comment.

3. Please provide your organization’s feedback to the ISO’s proposed changes to fuel procurement (GRM DFP Section 3) by:

1. improving the quality of the bid set used to run the D+2 by using D+1 bids if available, and DA bids if not; 2. publishing D+2 advisory energy schedules to day-ahead participating SCs; and 3. publishing D+3, D+4 RUC advisory results to market participants

PG&E reiterates our comments submitted on the Straw Proposal[1] regarding the D+2 accuracy assessment:

• Targeted Improvements Based on Confidence Levels: PG&E supports CAISO’s efforts to improve D+2 forecast accuracy and recommends identifying hours with lower confidence for targeted enhancements. We share MSC’s concerns that forecast accuracy may vary during specific hours due to unique market or system conditions. We encourage CAISO to analyze these instances and their underlying drivers to inform focused improvements.
• Clarity on Bid Set Expectations: The reliability of D+2 advisory schedules is highly dependent on market participants’ understanding of the inputs used in simulated market processes. PG&E recommends that CAISO clarify its expectations for bid submissions—what is required versus preferred—and specify the forecasts used as inputs. Additionally, it would be helpful for CAISO to indicate the completeness of the market runs (e.g., whether they include processes beyond the raw IFM algorithm and whether transmission modeling matches the fidelity of the Day-Ahead market).
• Transparency on Import/Export Assumptions: PG&E seeks greater transparency regarding import/export assumptions, as these directly impact CAISO’s gas generation needs. We believe this information will be more accessible in the EDAM context and should be incorporated into D+2 forecasts to improve planning accuracy.

[1] PG&E’s comments submitted on Aug 25, 2025, available at https://stakeholdercenter.caiso.com/Comments/AllComments/51f2d361-6310-44a0-90e6-127acab51a4d#org-bc9068ad-4233-46cd-b6f3-46ae400dcab4

4. Please provide any feedback regarding the ISO’s proposed fuel cost parameter adjustments process (GRM DFP Section 4.3)

 No comment.

5. Please provide any feedback regarding the ISO’s proposal to provide more flexibility through the automated cost adjustment process to manage fuel procurement uncertainty (DFP Section 4.4).

PG&E strongly recommends against using the D+2 forecast as a basis for cost adjustment eligibility. While the forecast can serve as a useful planning tool when bids are submitted truthfully, its accuracy hinges on the cooperative behavior of all market participants, particularly the submission of accurate D+1 bids used in the advisory D+2 market runs.

However, because the D+2 market run is not financially binding, participants can submit bids without penalty, even if those bids deviate from their actual procurement behavior. This creates a risk of gaming: resources could strategically understate their day-ahead (DA) gas demand in the D+2 forecast to qualify for cost adjustments, while avoiding the premium costs associated with procuring more than their bids suggest.

In this context, PG&E emphasizes that meaningful D+2 forecasts require collective cooperation. When used solely for planning, the forecast may offer value or, at worst, provide inaccurate information without financial consequences. But tying compensation—such as cost adjustments—to a forecast vulnerable to manipulation undermines market integrity and introduces unnecessary risk.

6. Please provide any feedback regarding the ISO’s proposal to make existing gas nomogram procedure accessible to EDAM/WEIM BAAs (GRM DFP Section 5.1)

 No comment.

7. Please provide any feedback not already captured.

 No comment.

1. Please provide a summary of your organization’s overall comments on the gas resource management stakeholder meeting on September 17, 2025.

See PGE's response to Question 2

2. Please provide a summary of your organization’s comments on the gas resource management draft final proposal, published on September 17, 2025.

Portland General Electric supports the key enhancements in the Draft Final Proposal, particularly those that improve cost reflectiveness and operational alignment for gas-fired resources across the WEIM and future EDAM footprint. Specifically, PGE supports:

• The proposed updates to reasonableness thresholds, which allow greater flexibility under volatile gas conditions.
• The approach to fuel cost benchmarking, which combines participant data and index-based logic to determine Gas Price Index (GPI) inputs for use in DEB and commitment cost calculations.
• The two-path framework to address fuel procurement uncertainty, offering important flexibility for both RT and DA cost adjustments.

Collectively, these changes provide more consistent and equitable treatment of gas-fired resources in markets where fuel cost risk is dynamic and non-trivial.

3. Please provide your organization’s feedback to the ISO’s proposed changes to fuel procurement (GRM DFP Section 3) by:

1. improving the quality of the bid set used to run the D+2 by using D+1 bids if available, and DA bids if not; 2. publishing D+2 advisory energy schedules to day-ahead participating SCs; and 3. publishing D+3, D+4 RUC advisory results to market participants

PGE supports the CAISO’s proposed improvements to the D+2 advisory run and the publication of advisory energy schedules to day-ahead participating SCs. PGE does not take a position on the proposal to publish D+3 and D+4 RUC advisory results at this time.

4. Please provide any feedback regarding the ISO’s proposed fuel cost parameter adjustments process (GRM DFP Section 4.3)

PGE supports the CAISO’s effort to streamline the fuel cost parameter adjustment process using the proposed automated framework based on benchmark screening and ISO-determined multipliers. However, PGE recommends that the CAISO retain the option for a negotiated approach in parallel (at least on a limited or pilot basis) to evaluate its continued value in cases where automated methods may not fully capture resource-specific conditions.

PGE also seeks clarification on whether fuel cost adjustments will apply consistently across both DEB and NDEBs. Applying the adjustment only to DEBs could lead to price misalignments and create inequities for resources that primarily bid under the NDEB structure.

Regarding the initial screening methodology (Section 4.3.1), PGE requests further detail on how the benchmark group of resources will be selected and maintained. The current reliance on CAISO BAA resources mapped to PG&E and SoCal Citygate may not reflect the full diversity of gas procurement conditions across the WEIM and future footprint. PGE asks that the CAISO clarify (1) how the benchmark composition will evolve as the resource mix changes, and (2) how the framework accounts for constrained or regionally unique gas conditions to avoid disadvantaging certain participants.

Finally, for the fuel cost adjustment determination process, PGE requests additional detail on data expectations. Specifically:

• Does “volumetric gas purchase information” require submission of invoice-level or transaction-level information?
• Will participants need to provide hub-level purchase data across multiple cycles, and how should this be submitted if purchases span more than one trading hub?

Further clarity on these issues will help ensure consistent implementation and reduce the administrative burden of the proposed process.

5. Please provide any feedback regarding the ISO’s proposal to provide more flexibility through the automated cost adjustment process to manage fuel procurement uncertainty (DFP Section 4.4).

PGE agrees that providing more flexibility through the automated cost adjustment process is necessary, particularly given the increasing volatility of same-day gas procurement and challenges aligning DA and RT commitments. PGE recommends prioritizing implementation of Section 4.4.3 since this directly addresses real-time only adjustments.

6. Please provide any feedback regarding the ISO’s proposal to make existing gas nomogram procedure accessible to EDAM/WEIM BAAs (GRM DFP Section 5.1)

No comment

7. Please provide any feedback not already captured.