ERCOT Planning Working Group Meeting Notes - 9/19

Agenda           

1.     Antitrust Admonition

2.     Agenda Review

3.     Review of PLWG Meeting Minutes (Aug 15th)

4.     General update:

a.     PGRR105, Deliverability Criteria for DC Tie Imports: ROS endorsed and forwarded to TAC

                                               i.     No comments

b.     ROS confirmed not assigned to PLWG: KTC 15-6 RMR and MRA Services

                                               i.     The group was reminded that this is now being addressed at ROS.

5.     ERCOT New SOL Methodology and NERC FAC-014-3 R7 Requirements

a.     ERCOT presentation posted and given.

b.     The group discussed the types of instabilities encompassed by these criteria. A stakeholder asked about the operational impacts of these changes, in particular, whether ERCOT’s calculated system-wide limits, such as GTC’s, and IROL’s are impacted Yes, theses limits are implicated. ERCOT stated that the TSP planning departed could identify and instability and then they would take any action plan to mitigate that, this needs to be communicated to ERCOT.

c.     Questions were asked about how to fill out the corrective action plan under various scenarios and how they interplay with the requirements. The deadline for when TPL assessments to be updated doesn’t have specific date and month specified for ERCOT to receive that. However, they expect that the next time after April 2024 that the TSP’s files their assessments, this information will be included. Then, going forward it is an annual review.

d.     ERCOT explained that the reason the FAC-10 was being retired, and these changes were necessary, was due to an acknowledgement that TSP’s should identify limits and stability issues, but that the grid operator needed to be making this operational decision because they have additional things that they have to consider.

6.     Break

7.     ERCOT Congestion Cost Savings (CCS) Test Discussion

a.     ERCOT summarized the SB1281 process and that they hired E3 to examine test options for the CCS test. Stakeholders were asked to limit their commentary to information covered by the E3 presentation. ERCOT is talking to PUC staff about the test development. Their next steps include consultation with the PUC and may include PGRR’s or NPRR’s.

b.     Presentation posted and given by E3. They view the goal of the CCS test as needing to look at the economics from the perspective of ERCOT load customers. The CCS (consumer) test is the 2^nd test in addition to the PCS (societal test). Both of these use a model that considers power users, power producers, and transmission. 

c.     They noted that there are other things that influence cost to benefits outside of the CCS part – various other benefits, which some RTO’s consider and others don’t. They sharply focused on the cost delta piece to address this part first before looking at anything else. A stakeholder asked whether there were plans to look at other benefits, but that is not ERCOT’s focus at this time.

d.     E3 summarized the tests reviewed: Production Cost Savings test (PCS), Gross Load Cost test (GLC), Net Load Cost test (NLC), Generator Revenue Reduction test (GRR), and the TEAM approach. The recommended test, the GLC calculates cost savings to consumer by using the LMP’s at their locations. They think this is similar to the GRR because it considers the quantity of generation and the gross load at the same. The difference is the pricing used. The GRR calculates cost at the generator locations, and the GLC calculates them at the customer’s LMP’s.

e.     A stakeholder asked about the differences between the GRR and the GLC related to settlement optimization. One small difference is line losses, a larger difference is the treatment of congestion because GLC measures prices changes at the customer’s load point, and load settles at load points in load zones. The presenter talked through an example of two load zones where, during certain hours the lines to import the less expensive power into the larger load zones maxes out and more expensive local generation has to be dispatched. They continued to say that the actual generator dispatch would be the same either way, but the GRR assumes that all the power is deliverable, when, in reality, it isn’t, due to congestion.

f.      A commenter asked about why the TEAM approach was ruled out, since it accounts for purchase agreement of vertically integrated utilities, and there are vertically integrate NOIE’s in ERCOT. While that is true, there are a lot of contracts for power, but these cover different things and are not transparent to ERCOT. This makes the implementation a challenge. Additionally, the contracted amounts can change dramatically year over year.

g.     A commenter asked if their analysis of NLC would look different if the current load zones were changed based on the study being done by the IMM. E3 answered that t wouldn’t. They don’t like NLC for ERCOT because in PJM, where that test is used, the pricing is paid zonally, instead of postage stamp, like ERCOT. The noted that results of the GLC won’t change if the load zones are changed. Additionally, the GRR results don’t change if the load zones change.

h.     Folks asked what the C:B ratio would be. While the range of C:B ratios they observed varies between 0.8 -1.2, with 1.0 being common, this was outside the scope of their study. ERCOT noted that the cost side has already been fixed by PUC rule, based on the average of the revenue requirement for the first three years. This derives down to 12.9% of capex.

i.      There were questions about whether some loads would not benefit due to changes in the results for the CRR auction, because their congestion revenue might decrease. The congestion revenue mechanism is not uniform, which makes it difficult to incorporate. Over the long-term, LSE’s could choose to take a different position in the CRR market. Additionally, another commenter noted that congestion revenue is a product of system topology, which changes, and bid choices that entities make, not something that has a guaranteed value.

j.      Next steps: ERCOT will provide an update at next month’s PLWG or will send something out via the list serve, including when the new test might go into effect. There are more details to be worked out and there will have to be planning guide revisions. It will take some lift to implement this, but ERCOT is evaluating and beginning to test their system.

8.     PGRR109, Dynamic Model Review Process Improvement for IBR Modification

a.     PLWG was waiting for stakeholder comments and Southern Power stated that they still are working to draft comments with redlines. They believe that these adjustments will address some stakeholder’s concerns while implementing ERCOT changes. They are concerned about some of the time frames in the revision and the necessary dynamic models. They stated that adding this review may add another 150 days to the review. ERCOT, disagreed with that timeframe, saying they expect is would add between 10-30 days, not 150.

b.     ERCOT says that any of these reviews before 1/1/2028 would not require compliance with IEEE2800, those units would maintain the legacy requirements.

c.     Some commenters thought that all the models were already required before commissioning the resource. ERCOT answered that this is correct in order to qualify as a QSE. However, this PGRR adds one more check point to compare the as-built and design configurations.

d.     The earliest this could be effective would be in February 2024 based on meeting schedules.

9.     Review Open Action Items

a.     NPRR1180/PGRR107 – PLWG still waiting on comments between Oncor and ERCOT to review them together. These should be ready for the October meeting.

b.     NERC FAC-004.2 for interconnections, will be wrapped up by the end of this year.

c.     The CCS test and NPRR1070, including resource adequacy aspects

10.  Other business

a.     None

11.  Adjourn