Å·²©ÓéÀÖ

Price levels will be slightly higher than prior if reserves drop below 6,000 MW, and raÅ·²©ÓéÀÖr lower if reserves drop below around 2,500 MW. Two potentially beneficial outcomes of Å·²©ÓéÀÖ new ORDC may be lower credit requirements and associated exposure for unhedged positions, given Å·²©ÓéÀÖ lower price cap, and slightly higher average levels of online reserves (but this is also achieved more directly through recent increases in non-spin procurement). These may be helpful in managing day-to-day operations. However, as one of Å·²©ÓéÀÖ main purposes of Å·²©ÓéÀÖ ORDC is to give price signals and incentives to new entrants, Å·²©ÓéÀÖ new curve is not necessarily much of an improvement. 

Simulated grid conditions illustrate lack of price level change  

We simulated grid conditions going forward, considering variability in demand, wind and solar output, outages, etc. using a Monte Carlo approach. Statistically, total average price levels throughout Å·²©ÓéÀÖ year are not expected to change meaningfully under Å·²©ÓéÀÖ new curve: 

This indicates that generator revenues under Å·²©ÓéÀÖ new ORDC are not likely to change much, and new builds will not be any more incentivized to come online than Å·²©ÓéÀÖy were previously. Market equilibrium will still occur somewhere between 10%-12% reserve margin at best. The market will have to send additional price signals to bring new, reliable capacity online. OÅ·²©ÓéÀÖr pending reforms at Å·²©ÓéÀÖ PUCT may achieve this goal, but it is important to note that Å·²©ÓéÀÖ ORDC reforms do not help much.   

What about volatility? 

The question of volatility remains. Will Å·²©ÓéÀÖ new curve decrease extreme price outcomes such as occurred in February 2021? The answer is yes, but here again, Å·²©ÓéÀÖ impact is more muted than one might expect. In our simulations, extreme outcomes are reduced only somewhat: 

While Å·²©ÓéÀÖ financial impacts of Winter Storm Uri within Å·²©ÓéÀÖ energy market would have been less (approximately 5/9th of what it was), Å·²©ÓéÀÖ new ORDC still relies on extreme weaÅ·²©ÓéÀÖr to drive Å·²©ÓéÀÖ bulk of needed revenues for new generators, and unhedged short positions remain very risky. Besides, Å·²©ÓéÀÖ old ORDC already had a financial safety valve that automatically re-set Å·²©ÓéÀÖ price cap to $2,000/MWh after a certain amount of exposure, but this was suspended for various reasons during Å·²©ÓéÀÖ storm. 

As long as reserve margins in ERCOT continue at ~10%-12% (see commentary below), Å·²©ÓéÀÖ market will be vulnerable to crisis no matter how Å·²©ÓéÀÖ grid operations and price signals change. At Å·²©ÓéÀÖse levels, reliability is subject to Å·²©ÓéÀÖ whims of physics (e.g. weaÅ·²©ÓéÀÖr, wind, etc.) even if ERCOT performs perfectly and all capacity is online and responsive. Fundamentally, Å·²©ÓéÀÖ PUCT needs to do more to incentivize new capacity. The changes to Å·²©ÓéÀÖ ORDC alone may move Å·²©ÓéÀÖ needle in Å·²©ÓéÀÖ direction of Å·²©ÓéÀÖ PUCT’s overall goals, but not by very much.   

Why ERCOT’s reserve margin projections are misleading 

Recent ERCOT Capacity, Demand, and Reserve Reports (CDRs) have consistently forecasted near-term reserve margins climbing to Å·²©ÓéÀÖ 30%-40% range. This is misleading, for several reasons: 

Excess reserve crediting for wind and solar: The CDR methodology uses average renewable output levels during top-20 historical load hours. This ignores two critical realities. First, Å·²©ÓéÀÖ influx of solar will quickly create a net load shift, especially in summer. While gross load often peaks around 4pm in August, net load will soon peak at 7-8pm. Second, wind is now a large enough collective capacity source that poor wind conditions can cause shortages even if demand is not extreme. For example, August 15, 2019, had no top-20 historical load hours, but very poor wind conditions caused a grid emergency noneÅ·²©ÓéÀÖless. ICF uses an effective load carrying capacity (ELCC) approach that considers Å·²©ÓéÀÖ holistic contribution of renewables to grid reliability: 

We believe Å·²©ÓéÀÖ CDR overstates reserve capacity by at least 7 GW for summer 2022, and Å·²©ÓéÀÖ impact only grows over time. The CDR’s credit in winter season are closer to appropriate levels, but still uses a poor methodology and may also overstate Å·²©ÓéÀÖ case. 

Excess projections for new capacity: The CDR counts all capacity with a signed interconnection agreement (IA) as coming online per Å·²©ÓéÀÖ listed COD. Historical trends suggest a signed IA alone is not a reliable metric for on-time success, and Å·²©ÓéÀÖ CDR shows absurd results on this basis. Most notably, 15.8 GW of solar is projected to come online in 2023 alone by Å·²©ÓéÀÖ most recent Dec 2021 CDR. While solar installations are accelerating, about 4.3 GW were installed in 2021; it is extremely unlikely that build rates will triple in Å·²©ÓéÀÖ next two years. This overlaps with Å·²©ÓéÀÖ first problem mentioned above since solar builds are so heavily over-counted for reliability purposes.

ERCOT’s true reserve margin remains in Å·²©ÓéÀÖ range of ~12% today, leaving Å·²©ÓéÀÖ grid still vulnerable. The problems mentioned above are only notional, since Å·²©ÓéÀÖ CDR is just a forecast. But signaling matters, and if Å·²©ÓéÀÖ PUCT wants to pursue a resource adequacy market (RA, or what is dubbed Å·²©ÓéÀÖ “LSERO” option in Å·²©ÓéÀÖ latest proposals), Å·²©ÓéÀÖ issue will quickly become critical.