The ERCOT Independent Market Monitor has filed a 2016 state of the market report, including 7 recommendations.

Four of the recommendations were contained in prior reports, including the IMM's recommendation for an evaluation of 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 (namely, the use of 4CP).

New recommendations from the IMM include:

• Ensure that the price of any energy deployed from a reliability must run (RMR) unit reflects the shortage conditions that exist by the fact that there is an RMR unit

• Evaluate the need for a local reserve product

• Consider including marginal losses in ERCOT locational marginal prices

Concerning a local reserve product, the IMM said, "we recommend that ERCOT align its planning requirements and real-time operating requirements and begin evaluating the need for a local reserve product. Changes to the process for determining whether an RMR unit is needed, implemented in NPRR788, were important clarifications. However, if there is a local reliability concern that is best addressed by maintaining additional operating reserves in a specific area, we suggest that ERCOT develop and implement a new local reserve product."

Concerning marginal losses, the IMM said, "we are now recommending that the ERCOT real-time market be upgraded to recognize marginal losses in its dispatch and prices. Accompanying this change, a revenue allocation methodology will need to be developed because marginal loss pricing results in the collection of more payments for losses than the aggregate cost of losses. This occurs because the marginal losses are always larger than the average losses (i.e., losses increase as more power flows over the transmission system). Most other RTOs in the U.S. recognize marginal losses and may provide examples of allocation approaches that could be used in ERCOT."

The IMM also included a discussion of net revenue in the market

"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 gas turbine unit ranges from $80 to $95 per kW-year. These estimates reflect Texas-specific construction costs. The net revenue in 2016 for a new gas turbine was calculated to be approximately $23 to 29 per kW-year," the IMM said

"These results are consistent with the current surplus capacity, which contributed to infrequent shortages in 2015 and 2016. In an energy-only market, shortages play a key role in delivering the net revenues an investor would need to recover its investment. Such shortages will tend to be clustered in years with unusually high load and/or poor generator availability. Hence, these results alone do not raise substantial concerns regarding design or operation of ERCOT’s ORDC mechanism for pricing shortages," the IMM said

The IMM also addresses nuclear and coal revenues

"Given the very low energy prices during 2016 in non-shortage hours, 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 $21.46 per MWh in 2016, down from $24.56 per MWh in 2015. According to the Nuclear Energy Institute (NEI), total operating costs for all nuclear units across the U.S. averaged $27.17 per MWh in 2016. Assuming that operating costs in ERCOT are similar to the U.S. average, it is likely that these units were not profitable in 2016, based on the fuel and operating and maintenance costs alone. To the extent nuclear units in ERCOT had any associated capital costs, it is likely those costs were not recovered. Compared to other regions with larger 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 does potentially raise a resource adequacy issue that will need to be monitored," the IMM said

"The generation-weighted price of all coal and lignite units in ERCOT during 2016 was $23.98 per MWh. Although specific unit costs may vary, index prices for Powder River Basin coal delivered to ERCOT were approximately $2.50 per MMBtu in 2016, a decrease from approximately $2.60 per MMBtu in 2015. For the past two years, delivered coal costs in ERCOT have been about $0.03 to $0.05 per MMBtu higher than natural gas prices at the Houston Ship Channel. Given that the coal units generally have higher heat rates and more expensive non-fuel operations and maintenance costs, they have been losing market share to natural gas. As with nuclear units, it appears that coal units were likely not profitable in ERCOT during 2016. With the bulk of the coal fleet in ERCOT being more than 30 years old, the retirement or suspended operation of some of these units could cause ERCOT’s capacity margin to fall to unreliable levels more quickly than anticipated. While both nuclear and coal are feeling the pressure of an increased reliance on lower-priced natural gas units, coal units appear to be at greater risk of retirement than the nuclear units in ERCOT due to their relative age and inefficiency," the IMM said

The IMM noted that ERCOT’s current projection of planning reserve margins indicates that the region will have a 16.9 percent reserve margin heading into the summer of 2017. "While these projections are slightly lower than those developed last year, the current outlook is very different than in 2013, when planning reserve margins were expected to be below the then-existing target level of 13.75 percent for the foreseeable future," the IMM said

"This current projection of planning reserve margins combined with relatively infrequent shortage pricing may raise doubts regarding the likelihood of announced generation coming on line as planned. Given the projections of continued low prices, investors of some of the new generation included in the Report on the Capacity, Demand, and Reserves in the ERCOT Region (CDR) may choose to delay or even cancel their project. Additionally, the profitability analysis of existing baseload resources casts doubt on the assumption embedded in the CDR that all existing generation will continue to operate. Hence, it is likely that the planning reserve margins will be lower than forecasted in the figure above," the IMM said

Addressing market power, the IMM said an analysis of the incremental output gap, "show that potential economic withholding levels were extremely low for the largest suppliers and small suppliers alike in 2016. Output gaps for the largest suppliers are routinely monitored individually and were found to be consistently low across all load levels. These results, together with our evaluation of the market outcomes presented in this report, allow us to conclude that the ERCOT market performed competitively in 2016."

The IMM noted that, "at loads greater than 65 GW, there was a pivotal supplier 99 percent of the time. This is expected because at high load levels, larger suppliers are more likely to be pivotal because other suppliers’ resources are more fully utilized serving the load. The frequency of relatively high loads increased in 2016. This led to an increase in the pivotal supplier frequency to 28.5 percent of all hours in 2016, up from 26 and 23 percent of all hours in 2015 and 2014, respectively. This indicates that market power continues to be a potential concern in ERCOT and underscores the need for effective mitigation measures to address it."

Link to SOM Report