PJM differs from Cal-ISO and ERCOT in how renewables are treated in markets

The PJM Interconnection's "heavy handed" approach to maintaining sufficient capacity is likely to limit renewable development, but the California Independent System Operator and the Electric Reliability Council of Texas are likely to improve their reliability at reduced cost while maintaining renewable growth, according to participants in a recent webcast by the Enverus energy consultancy entitled, "2021 Outlook – What's Next for US Power Markets."

"Big picture, unlike CAISO and ERCOT, PJM has chosen to take the heavy-handed approach to regulation of renewable resources instead of allowing markets to dictate supply," Enverus said in its written Jan. 14 presentation.

However, Kieran Kemmerer, an S&P Global Platts Analytics power market analyst, said the effect of PJM's Minimum Offer Price Rule designed to negate the effect of state subsidies on new resources is unlikely to strengthen clearing prices in PJM capacity market auctions.

"While MOPR poses obstacles to new renewable resource entry, we anticipate a substantial amount of resource-specific exemptions to the default offer price proposed, particularly for solar resources," Kemmerer said in a Jan. 15 email.

Based on Dec. 18 data, Enverus estimates that the default MOPR for new solar resources in the regional transmission organization as a whole would be $390/MW-day – more than double the $140/MW-day clearing price for the 2021-22 capacity auction.

"Ultimately we expect MOPR to play a smaller role in the upcoming [Base Residual Auction] for the 2022/23 Deliverability Period, with a more substantial impact in auctions thereafter (provided limited changes to market rules)," Kemmerer said.

Combined-cycle gas turbines currently financed and under construction could suppress RTO clearing prices, Kemmerer said.

"We maintain that updates to the demand curve appear for the upcoming 2022/23 Base Residual Auction appear bearish for clearing prices, posing an estimated $30-$40/MW-day of downside to the last auction clearing price of $140/MW-day," Kemmerer said.

California volatility

In contrast with PJM's plentiful supply and stagnant demand, Cal-ISO had occasions in the summer of 2020 when it could not meet demand, as solar output declined without the capacity of sufficient gas-fired generation to fill the gap, which contributed to blackouts, Enverus said.

"Nameplate wind and solar generation are now nearly 17,000 MW," Enverus said in its written presentation. "The increase of wind and solar production has caused displacement of gas generators ... [which] has caused price volatility during the evening hours."

For example, the SP-15 day-ahead price for power surged near $1,000/MWh as solar output disappeared for the period between 7 pm and 9 pm on Aug. 14, 2020. However, Enverus presenter Rob Allerman, senior director of power analytics, said in a Jan. 15 email that Cal-ISO anticipates having 1.5 GW to 2 GW of battery storage across its footprint this summer.

Also, natural gas plant retirements are on hold, an additional 500 MW of wind generation is anticipated to be online, and changes in the Energy Imbalance Market reserve and scheduling calculations could add another 200 to 600 MW of capacity.

Assuming these revisions in a situation similar to Aug. 14, Enverus calculates scarcity pricing to stay below $500/MWh.

Morris Greenberg, Platts Analytics managing director of North American power said that while hydropower conditions have deteriorated over the past month, "overall supplies should be somewhat improved during the critical hours (between 6 pm and 8 pm)."

"The real question then is how likely is a repeat of the weather patterns observed last year," Greenberg said. "In our view this is unlikely so we will remain below forward market for SP15 and inland southwest."

The sun in Texas

While solar power contributed to price volatility in Cal-ISO in 2020, Enverus expects it to play a role in diminishing price volatility in ERCOT in 2021.

ERCOT reported in December that the current solar operating capacity was about 3.8 GW, expected to increase by 4.8 GW by August 2021.

"Unlike non-coastal wind which has a low Summer Peak Effective Load Carrying Capability (ELCC) of 19%, solar has an ELCC of 80%, which is much more coincident with summer demand peaks," Enverus said in its written presentation.

This is likely to "have a suppressive effect" on ERCOT's Operating Reserve Demand Curve adder, which is an administrative pricing mechanism applied systemwide to increase the price of power as operating reserves diminish to scarcity levels.

Applying Enverus' projected 3.9 GW of solar capacity to be online for August 2021 to the situation that occurred Aug. 13, 2019, when real-time prices averaged above $4,900/MWh for three hours, Enverus concluded that prices during those hours would range between $185/MWh and $227/MWh.

"The result brings the on-peak average from $1,534.88/MWh day down to $59.52/MWh," Enverus said.