ERCOT IMM Offers Six New Recommended Market Changes In State Of The Market Report

IMM: More Robust Reserve Margin "May No Longer Be Required" To Cover Load Forecast Errors, Generator Availability Risks, Given Size of System, Projected Growth

IMM: Risk From Generator Outages Should Decrease With Smaller, Distributed Resource Proliferation

Reports On Net Revenues, Shortage Pricing Durations

June 6, 2019

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Copyright 2010-19 EnergyChoiceMatters.com
Reporting by Paul Ring • ring@energychoicematters.com

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The ERCOT Independent Market Monitor filed the State of the Market report for 2018

The report contains six new recommendations, listed below:

1. Evaluate and improve the Reliability Deployment Price Adder

"The current calculation method for the Real-Time On-Line Reliability Deployment Price Adder (RTRDPA) is producing results that are inconsistent with its original intent and should be changed. The existing RTRDPA mechanism is flawed and the IMM believes these flaws should be addressed before expanding the number and types of actions that trigger the RTRDPA," the IMM said in the report

"When the RTRDPA is triggered by reliability unit commitment (RUC) instructions, the intent of the RTRDPA should be to produce prices sufficient to have encouraged a competitive resource to commit and produce energy. We do not support the position held by some that the RTRDPA should produce prices that reflect the total absence of the resource. The current RTRDPA misses achieving this goal in two main ways; first, most RUCs address local reliability concerns and have significant local impact with relatively minor global impacts. The IMM recommends that nodal adders should be reexamined in ERCOT because the local impacts are more important. Second, although the mitigation of resources with RUC instructions is appropriate, the mitigation should in some way reflect the startup and minimum load costs of that Resource," the IMM said in the report

"Further, the IMM believes that reserves should not be paid the RTRDPA. While it makes sense to pay the Operating Reserve Demand Curve (ORDC) adder to reserves due to the added reliability that they afford, the RTRDPA is intended to be a 'but for' price adjustment. That is, the RTRDPA is an attempt to pay Resources the price that a competitive market would have produced 'but for' the reliability actions taken by the system operator. This 'but for' price would have been paid to Resources generating energy in the competitive 'but for' scenario, not to reserves," the IMM said in the report

"Finally, the IMM believes that any proposed changes to the RTRDPA calculation should be thoroughly analyzed with past market data and scenarios prior to adoption and deployment. This is a complicated calculation and the risk of unintended consequences is high without significant analysis," the IMM said in the report

"The flaws in the current calculation method for the RTRDPA are currently being discussed as part of stakeholder deliberations regarding NPRR904, Revisions to Real-Time On-Line Reliability Deployment Price Adder for ERCOT-Directed Actions Related to DC Ties and to Correct Design Flaws, introduced in October 2018. This NPRR would revise the categories of ERCOT-directed actions that trigger the RTRDPA to include DC Tie related actions. At a minimum, we recommend improving the methodology for determining the adder prior to expanding the situations in which it would apply," the IMM said in the report

2. Explore options to consider commitment costs for RUC-committed units

"The IMM recommends evaluating RUC mitigation and exploring options to consider commitment costs for RUC-committed units. Mitigation is used to ensure competitive outcomes in noncompetitive situations. The cost to commit a unit should be factored in to the offers and market price that results from ERCOT making a commitment decision. Consideration of commitment costs will make it more likely that prices are at a level that would support the market participant to have committed the unit on their own. Conversely, offers that reflect only marginal energy costs will likely produce prices too low to support self-commitment," the IMM said in the report

3. Eliminate the OPTOUT option for RUC-committed Resources

"For generators unsure about whether to self-commit, the ability to OPTOUT of RUC instructions provides the incentive for generators to defer the decision to self-commit as long as possible with no risk. The implementation of NPRR744, RUC Trigger for the Reliability Deployment Price Adder and Alignment with RUC Settlement served to exacerbate this disincentive to self-commit by allowing generators even more time to OPTOUT once a RUC instruction is received," the IMM said in the report

"ERCOT operators typically have exhibited great restraint, deferring their decisions to issue a RUC instruction to last possible moment. This restraint was recently codified in NPRR864, RUC Modifications to Consider Market-Based Solutions, which modified the RUC engine to consider fast-start generators (less than 1 hour start times) as self-committed for future hours. The culmination of these RUC changes has enabled ERCOT to defer supplementary commitment decisions, allowing market participants full opportunity to make their own unit commitment," the IMM said in the report

"The current OPTOUT option provides the incentive for units to not commit by giving those units access to more market information than other Market Participants via the RUC instruction. Because of the disincentive to self-commit, the IMM recommends eliminating the OPTOUT option for RUC-committed Resources," the IMM said in the report

Revenue Neutrality Allocation

"Revenue neutrality allocation (RENA) causes uplift to the market, which is difficult to hedge against, creating uncertainty for load as to what prices will be. The next two recommendations are intended to reduce RENA," the IMM said in the report

4. Review PTP obligations linked to options

"Point-to-Point (PTP) Obligations with Links to an Option (PTPLO) are cleared as obligations but settled as options. This variance is what often leads to uplift, and its effects are more pronounced now than ever before. The settling of PTPLOs as options dates back to 2011 and adoption of NPRR322, Real-Time PTP Option Modeling. This NPRR provided that all PTP Options would be settled in the day-ahead market. If a Non-Opt-In Entity (NOIE) purchases a PTP Obligation in the day-ahead market and owns a PTP Option for the same source and sink pair, and the MWs of the PTP Obligation are not more than the MWs of the PTP Option, then the PTP Obligation would settle in Real-Time as only the positive difference between the sink and source Settlement Point Prices, much like a PTP Option. This NPRR also included a requirement that NOIEs shape the PTP Options going to Real-Time according to their Load forecast and added a new type of Congestion Revenue Right (CRR) to handle the treatment of PTP Obligations that are treated as PTP Options for Settlement purposes," the IMM said in the report

"Since 2017, we have seen significant increases in uplift related to PTPLOs, and this trend continued in 2018. The IMM recommends a review into the effects of NPRR322 and settling PTPLOs as options on RENA," the IMM said in the report

5. Evaluate and Improve Load Distribution Factors (LDFs) used in the Congestion Revenue Right (CRR) and Day-Ahead Market clearing activities

"Load Distribution Factors (LDFs) are developed using historical State Estimator or SCADA data and deal with load levels within a load zone. Per Protocol Section 4.5.1, ERCOT shall generate and maintain the appropriate LDF libraries for use in the day-ahead market and CRR Auctions," the IMM said in the report

"ERCOT updates the LDF libraries by maintaining the existing LDF sets and generating new LDF sets when required, based on significant changes in system-wide load patterns. Updates are regularly required for seasonal load patterns due to weather changes," the IMM said in the report

"Our concern with the current LDF procedure is that it is entirely backwards looking (i.e. using the most recent hot day profile). There are challenges transitioning that process to be more forward looking, such as being able to accurately predict the month that a load is going to come online, but the IMM views those challenges as worth addressing, especially since the CRR balancing account was emptied for the first time in 2018," the IMM said in the report

"This year, due mostly to differences in the West Load Zone day-ahead and CRR load distribution factors, the CRR balancing fund was drawn on heavily in June and depleted entirely in July. While the balancing fund was once again up to its capped value of $10 million by August, another shortfall lowered it in November and at the end of the year it sat at a little less than $8 million," the IMM said in the report

6. Evaluate Transmission Demand Curves

"A key part of real-time co-optimization design will be to determine demand curves for each ancillary service. Since all demand curves – energy, ancillary services and transmission – should coordinate in a rational manner, the following recommendation may be considered as part of the efforts underway to design real-time co-optimization for ERCOT. Regardless, we believe the following recommendation is valuable on its own merits," the IMM said in the report

"As the demands curves for each type of reserve service (potentially including locational reserve products in the future) are being evaluated under a co-optimized system, it is a good opportunity to also evaluate transmission penalty curves. Currently there are single values applied to limit the amount spent to resolve a transmission constraint. These Shadow Price Caps vary by voltage level. Much like the concept of demand curves for ancillary services, the value of lowering the flow of electricity on transmission lines increases as the violation amount grows, this should be reflected in energy prices, as it is in some other electricity markets (notably MISO). Given that congestion costs were over $1B in 2018, the IMM recommends that a more nuanced approach to how transmission security affects pricing be evaluated," the IMM said in the report

The IMM also included recommendations previously made in prior reports.

These include:

• Evaluate the need for a local reserve product.

• Price future ancillary services based on the shadow price of procuring the service

• Price congestion at all locations that affect a transmission constraint

• Modify the real-time market software to better commit load and generation resources that can be online within 30 minutes.

• Evaluate policies and programs that create incentives for loads to reduce consumption for reasons unrelated to real-time energy prices, including: (a) the Emergency Response Service (ERS) program and (b) the allocation of transmission costs.

• Reserve the inclusion of marginal losses in ERCOT locational marginal prices for post-implementation of real-time co-optimization in ERCOT.

Net Revenues

"Based on estimates of investment costs for new units, the net revenue required to satisfy the annual fixed costs (including capital carrying costs) of a new combustion turbine unit ranges from $80 to $95 per kW-year. Although higher overall in 2018 than any year since 2011, the ERCOT market continued to provide net revenues well below the level needed to support new investment, ranging from below $52 per kW-year in the North Zone to more than $56 per kW-year in Houston," the IMM said

"These results are consistent with a shrinking surplus of capacity, which contributed to more frequent shortages in 2018 compared to recent years. In an energy-only market, shortages play a key role in delivering the net revenues an investor needs to recover its investment. Such shortages will tend to be clustered in years with unusually high load or poor generator availability. The results in 2018 do not by themselves raise substantial concern regarding design or operation of ERCOT’s Operating Reserve Demand Curve (ORDC) mechanism for pricing shortages. Given the recent generation retirements and continued load growth, 2018 was in fact a year with significantly more occurrences of shortage pricing, with that trend expected to continue in 2019," the IMM said

"The generation-weighted price of all coal and lignite units in ERCOT during 2018 was $33.31 per MWh, an increase from $26.32 per MWh in 2017. Although specific unit costs may vary, index prices for Powder River Basin coal delivered to ERCOT were approximately $2.65 per MMBtu in 2018; remaining at 2017 (and 2015) levels after decreasing to $2.51 per MMBtu in 2016. At these average prices coal units in ERCOT are likely receiving just enough revenue to cover operating costs. It follows then that the decision by Luminant and CPS Energy to retire several coal units is financially justified," the IMM said

"Installed reserve margins for summer of 2018 were also historically low. What seem like very low reserves may just be the new normal. Given the overall size of the system and projected growth, a more robust reserve margin may no longer be required to cover load forecast errors and mitigate generator availability risks. Further, with smaller, more distributed generation technologies playing an increasingly important role in ERCOT, the risk associated with generator outages should decrease," the IMM said in the report

"Because the surplus has now disappeared and shortages are likely to be even more frequent in 2019, the economic signals could change rapidly. These short-term market outcomes and price signals, as well as investors’ response to these economic signals, will be monitored. This response could cause the planning reserve margins to exceed the forecast shown in the figure," the IMM said in the report

Shortage Prices (2018)

"Contrary to generally held expectations, market conditions were rarely tight, but prices did reach historic peaks. Real-time prices exceeded $3,000 per MWh for approximately 45 minutes, reaching $9,000 per MWh for the first time on January 23 for a duration of about ten minutes," the IMM said

Prices greater than $1,000 per MWh occurred in nearly 17 hours over the entire year.

The reliability adder was non-zero for 291 hours, or 3% of the time in 2018, most of which occurred in May. The reliability adder had very little overall effect on market outcomes in 2018 as its contribution to the annual average real-time energy price was $0.08 per MWh.

Other Observations

The total congestion costs experienced in the ERCOT real-time market in 2018 were $1.26 billion, an increase of 30% from 2017. "A costly, localized constraint in far west Texas was the primary cause of the increase," the IMM said

Link to report

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