Summer 2023 Review
ERCOT CEO, Pablo Vegas, began his August update to the ERCOT Board by thanking Texas citizens for their response to ERCOT’s conservation requests. He noted the summer’s challenges and that the ten new records have been remarkable. The CEO reported that ERCOT’s load has grown approximately 5,000 MW since last summer, a 7% increase, “a tremendous number.” He noted that population growth is great for the state but also brings challenges.
ERCOT launched its ERCOT Contingency Reserve Service (ECRS) this summer and it has been very complementary to the other ancillary services. ECRS is an off-line ancillary service that complements the online Non-Spinning Reserve Service (NSRS). Each of these ancillary services is designed to meet specific purposes and ERCOT now has a set of tools that can rapidly fill in and provide the operational flexibility that is getting increasingly complicated.
Mr. Vegas noted that renewables have generally performed strongly and predictably through the summer, as has thermal generation. However, things have been different recently, beginning with a conservation call on August 17, 2023, a very high demand day coupled with low wind production. All available ancillary services were required to manage that ramp, including Emergency Response Service (ERS), involving customers taking load off-line, a product typically only used as a last resort. Transmission service providers were also asked to reduce voltage. Mr. Vegas reported that ERCOT came within 600 MW of having to implement emergency operations.
Since August 17 there have been seven voluntary conservation appeals due to high demand and low wind output. The -tight situation continued over the last few days because, even though temperatures and demand were lower, because thermal generation outages increased, with mechanical breakages not surprising after a long stretch of high demand and high utilization. Mr. Vegas concluded that reliability on any given day depends on demand on the system, the availability of thermal generation and availability of intermittent renewables.
ERCOT’s ‘Big 5’ Market Design Initiatives
Mr. Vegas informed the board that key market design initiatives and an ERCOT reliability standard are in the planning and development stages. Mr. Vegas explained that the timing of the various initiatives drives a lot of the conversation and decisions on these projects.
Market Initiatives Timeline
Source: ERCOT
Reliability Standard
The reliability standard has three key elements, including the determination of parameters for loss of load expectation: frequency, magnitude and duration. Once the parameters are chosen, an analysis of the Cost of New Entry (CONE) is necessary, identifying the next lowest cost unit for meeting the reliability standard. A Value of Lost Load (VOLL) study will then be undertaken to determine whether meeting the proposed reliability standard is cost-effective. Mr. Vegas noted that it will also be necessary to look at the evolving resource mix to see if the reliability standard will be met in the future and, if not, the market needs to begin sending the correct signals to create the future grid. This work will be completed in the first half of 2024.
Operating Reserve Demand Curve (ORDC)
Mr. Vegas informed the Board that ORDC enhancements, which will be relatively quick to implement, adding a multi-step “floor” to the online ORDC price to provide self-commitment incentives and increase revenues for resources during scarcity conditions. This change is expected to be in place by November 2023 and be in effect prior to the winter. This ORDC change will bring revenue into the market that will target resources that are available during times of scarcity. A backcast revealed that approximately 80% of the additional revenue will flow to dispatchable resources.
As a result, dispatchable resources in the current market will have an additional revenue stream to help sustain them. In addition, if it remains in place, it will represent longer-term revenue for longer-term planning and incent additional dispatchable resources in the long-term. Mr. Vegas cautioned that this would need to be a mechanism the market could plan on but is now scheduled to be removed with the implementation of the Performance Credit Mechanism (PCM).
Dispatchable Reserve Reliability Service (DRRS)
DRRS is a new ancillary service legislatively required to be implemented by December 2024. Resources must be able to come online in two hours and run at their highest sustainable limit for 4 hours. Mr. Vegas explained that DRRS is not intended to be part of a long-term resource adequacy solution but instead to fill in the gap between short-term and long-term resource commitments. Reliability Unit Commitment (RUC) is currently used to address this but DRRS implementation requires an equivalent reduction in RUC. DRRS is designed to increase operational flexibility. It will have a limit on daily procurement with limits on compensation. DRRS is required to be implemented by December 1, 2024.
Performance Credit Mechanism (PCM)
Mr. Vegas noted that PCM is intended to be a more reliability-oriented change to provide a revenue source that incentivizes reliability resources to deliver during periods of scarcity. Resources earn credits when committing and performing during the tightest hours in a period. PCM will create a long-term reliability revenue stream to complement the energy-only market, allowing investors to make investments to bring dispatchable resources online. Some definitions and design decisions still need to be made, including addressing changes to the PCM made during the legislative session. A cost study will be done in conjunction with the ERCOT Independent Market Monitor (IMM) to determine if PCM is cost-effective as a long-term solution and market change. The PCM timetable has been extended and it is now expected to be completed in 2026.
Real-Time Co-optimization (RTC)
RTC is the process of simultaneously procuring energy and ancillary services (AS) from available resources at the lowest production cost to meet the real-time system demand for energy and AS. RTC will be developed over the same time period as PCM. ERCOT anticipates having the “state-of-charge” technology changes associated with NPRR1186 completed before the summer of 2024 in order to reallocate those resources to developing the Real-Time Co-optimization and Single Model ESR (RTC+B) solution that is being designed.
Board member Bill Flores asked if the CONE study would provide the actual consumer cost, not just the cost at the point of interconnection, including the cost of conditioning the power, delivering it, giving it inertia, backup, and making it reliable, “the challenge that renewables have.”
Mr. Vegas agreed, adding that CONE studies typically focus solely on the cost of siting a combustion turbine but believed ERCOT would investigate both in order to be consistent, adding that it will be important to know the total impact.
Woody Rickerson, ERCOT Senior Vice President & Chief Operating Officer, added that ERCOT is in the early part of scoping what CONE will look like so there will be a chance to shape that analysis to include those considerations.
PUCT Commissioner Will McAdams stated that one of the features of this schedule is that VOLL and CONE will be developed concurrently. He noted a discussion from the previous day concerning subsynchronous condensers that will be necessary in West Texas, at a cost of over $1 billion, adding that this will be an important consideration in knowing the overall bundled cost to the system of continuing to provide continuous and adequate power. The commissioner suggested that the two studies should provide a comprehensive view of the marginal production cost of power and what consumers are willing to pay. He suggested that the ERCOT Board should have a more universal view of the cost to consumers.
Commissioner McAdams noted that the Midcontinent Independent System Operator, Inc. (MISO) has a collaborative approach between MISO staff and their IMM. On the other hand, PJM has an external consultant assisting them. He asked which approach ERCOT would be using.
Mr. Vegas reported that ERCOT would be using an outside firm but expected to utilize the insight of the ERCOT Independent Market Monitor (IMM) and market participants, who would both be part of that conversation.
PUCT Commissioner Lori Cobos noted that, based on her conversations with the Brattle Group concerning Northeastern markets, some component of transmission is taken into account in CONE but to get a full picture of what transmission you really need requires a transmission deliverability study.
Mr. Vegas agreed, adding that to really understand the overall impact of a change in the resource mix to the market, you have to factor in a comprehensive transmission plan. ERCOT is working on how to do that for the short-term and long-term, including expectations for long-term growth and generation resource changes. ERCOT’s CEO stated that ERCOT would be well-served by developing a comprehensive transmission plan that will help them understand where investments will be needed, in order to plan how to manage the cost in clear steps over the 5-, 10- and 15-year timeframes.