ERCOT IMM Includes New Congestion Pricing Recommendation In State of The Market Report
ERCOT's Independent Market Monitor has filed its 2017 state of the market report for ERCOT that includes a new recommendation concerning pricing congestion at all generator locations that affect a transmission constraint (and no longer pricing small generators on zonal rather than nodal pricing if they affect a constraint).
The IMM found that in 2017 market conditions were rarely tight -- real-time prices did not exceed $3,000 per MWh in 2017 and exceeded $1,000 per MWh for only 3.5 hours cumulatively for the year.
The ERCOT-wide load-weighted average real-time energy price was $28.25 per MWh in 2017, a 14.7% increase from 2016.
The all-in price in 2017 included small contributions from ERCOT’s energy price adders -- $0.24 per MWh from the operating reserve adder and $0.16 per MWh from the reliability adder.
When averaged across only the active hours, the largest price impacts of the reliability adder occurred in January. The reliability adder was non-zero for fewer than 250 hours, or less than 3% of the time in 2017, most of which occurred in August. The contribution from the reliability adder to the annual average real-time energy price was $0.16 per MWh. Like the operating reserve adder, it had very little overall effect on the market outcomes in 2017 because the supply conditions were rarely tight and ERCOT took fewer reliability actions in 2017.
The IMM said that, "Net revenues provided by the market during 2017 were less than the estimated amount necessary to support new greenfield generation investment, which is not a surprise given that planning reserves were above the minimum target and shortages were again rare in 2017. The Operating Reserve Demand Curve (ORDC), combined with a relatively high offer cap, should increase net revenues when shortages become more frequent."
The IMM said that, "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. The ERCOT market continued to provide net revenues well below the level needed to support new investment, ranging from less than $20 per kW-year in the North Zone to almost $48 per kW-year in Houston."
The IMM said that, "These results are consistent with continued surplus of capacity, which contributed to infrequent shortages over the past three years. In an energy-only market, shortages play a key role in delivering the net revenues needed to support new investment. Such shortages will tend to be clustered in years with little surplus capacity, unusually high load, or poor generator availability. Therefore, these results alone do not raise concerns regarding design or operation of ERCOT’s ORDC mechanism for pricing shortages. Given the recent generation retirements and load growth, 2018 may well produce significantly more shortage pricing."
The IMM said that, "Given the low natural gas and resulting energy prices in 2017, the economic viability of existing coal and nuclear units was evaluated. Non-shortage prices, which have been substantially affected by the prevailing natural gas prices, determine the vast majority of net revenues received by these base load units. The generation-weighted average price for the four nuclear units in ERCOT (approximately 5 GW of capacity) was only $24.73 per MWh in 2017. This is similar to nuclear prices in 2016 and 2015, which were also lower than the ERCOT-wide prices in those years. Nuclear prices were $21.46 per MWh in 2016, down from $24.56 per MWh in 2015."
The IMM said that, "Assuming that operating costs of the nuclear units in ERCOT are similar to the U.S. average, it is likely that these units were not profitable in 2017, based on the fuel and operating and maintenance costs alone. Hence, it is unlikely that these nuclear units covered any capital costs that may have been incurred. However, unlike other regions with large amounts of nuclear generation, the four nuclear units in ERCOT are relatively new and owned by four entities with sizable load obligations. Although not profitable on a stand-alone basis, the nuclear units have substantial option value for the owners because they ensure that the cost of serving their load will not rise substantially if natural gas prices increase. Nonetheless, the economic pressure on these units raises resource adequacy issues that will need to be monitored."
The IMM listed ERCOT’s current projection of planning reserve margins which indicates that the region will have a 9.3% reserve margin heading into the summer of 2018
"This current projection of planning reserve margins is consistent with the economic signals produced by the market in recent years, which are themselves the product of the sustained capacity surpluses that have existed in ERCOT. Hence, these results demonstrate that the market is functioning properly," the IMM said
"However, because the surplus has now disappeared and shortages are likely to be more frequent in 2018, 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 closely. This response could cause planning reserve margins to exceed the forecast shown in the figure," the IMM said
The number of RUC instructions in 2017 fell by 63% from 2016, despite the increase in congestion that occurred in 2017.
The IMM proffered several recommendations, most of which were previously made in prior reports (including changing transmission cost allocation)
A new recommendation is to price congestion at all generator locations that affect a transmission constraint.
The IMM said that since the start of the nodal market, generators greater than 10 MW were considered part of the wholesale market with associated obligations and privileges. Generators less than 10MW and connected to the transmission system are not subject to many of the obligations borne by larger generators. Further, these small facilities are settled at the Load Zone price, not a location-specific nodal price.
"This practice may have been adequate for the few number of small generators that existed at the time of nodal market implementation. Currently however, the output of some small generators can significantly affect transmission congestion. When they can relieve a constraint, they would be paid a much higher price than they are currently. When they aggravate a constraint, they would generally settle at a lower price. Hence, settling with this generator as a zonal prices fails to provide efficient incentive for it to operate in a manner consistent with the reliability needs of the system," the IMM said
"All generators with output that affects a transmission constraint should receive a locational price. Small generators may not have to bear all the obligations of large generation resources, but they should settle in a manner consistent with the effect they have on the system," the IMM said
Other recommendations are:
• Implement real-time co-optimization of energy and ancillary services.
• 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.
• Modify the real-time market software to better commit load and generation resources that can be online within 30 minutes.
• Consider including marginal losses in ERCOT locational marginal prices.
• Price future ancillary services based on the shadow price of procuring the service.