EnergyStatewide NewsTaxes & SpendingTexas Nears ERCOT Market Redesign After Third Party Delivers Recommendation

As part of the fallout from the collapse, the Legislature directed the Public Utilities Commission (PUC) to re-evaluate the way electricity is bought and sold on Texas’ largest power grid. An initial Phase II blueprint was released 11 months ago, and since then the agency and industry have been enveloped in discussions and considerations on a path forward.

PUC contracted with Energy and Environmental Economics, Inc. (E3) to evaluate the Electric Reliability Council of Texas’ (ERCOT) electricity market and potential paths of reform. E3 released its analysis and recommendation last week.

The whole endeavor has two main purposes: to adjust the status quo to cope with the massive influx of renewable generation, a dynamic that didn’t exist when the state set up the current energy-only system, and to find a way to incentivize development of more dispatchable — thermal — generation.

Both purposes are aimed at one objective: increased reliability.

Texas’ current structure is an “energy-only” market, in that the electricity is supplied in real-time and not negotiated up front — which means the price fluctuates depending on the demand for and supply of electricity on the market at a given time. This structure uses price signals to incentivize generators to come online and go offline depending on the severity of need.

An even steeper price signal is applied in the ancillary services market — a set of break-in-case-of-emergency power plants that typically only supply power for short periods during times of peak demand, for substantially higher prices than is available on the ERCOT wholesale market.

The higher that demand rises relative to supply, the more money generators can make selling their electricity, which in turn brings on more supply and then places downward pressure on price. Ideally, it creates a constantly fluctuating price equilibrium.

But since the influx of renewable generation in Texas goaded by tax credits — primarily from the federal government, but also local ones — a windmill-sized wrench has been thrown into the delicate equation. Wind and solar cost less to break even on selling electricity due to the disproportional tax breaks and lack of fuel costs, which makes it an attractive investment.

Due to their intermittency, the growing proportion of the grid portfolio, and pricing advantage, the influx of renewable generation has brought with it a decline in natural gas and coal development. During times of peak demand — the time of highest grid stress, which comes during the afternoons and early evenings of hot summer days — wind production varies substantially, sometimes falling off almost entirely.

Solar performs far better and more consistently than its renewable counterpart during those periods. Its weakness, unsurprisingly, is when the sun goes down — which often, but not always, coincides with wind’s best performance period overnight.

Through 2026, E3 projects a 230 percent increase of installed solar capacity in the works, along with a 15 percent increase of installed wind capacity; that would put both sources around 40,000 megawatts of installed capacity each.

The projected trend for natural gas and thermal development varies entirely on the path chosen by state officials. Natural gas generation currently accounts for 56 percent of the installed capacity available this past summer.

There are many competing interests in the deliberations over the market redesign. Naturally, renewable generators and advocates like the status quo insofar as it favors them economically. But they also point toward other economic tweaks such as demand response services — a system that allows the state or local power company to reduce customers’ electricity use centrally rather than relying entirely on users to reduce usage of their own volition.

Meanwhile, thermal generators see little to no incentive for new development so long as that economic imbalance dynamic exists.

The thing everyone agrees on — renewables, thermal, bureaucrats, politicians, etc. — is that nobody is entirely happy with the status quo, which is using a patchwork of costly half-measures to bridge the gap between now and the time at which the redesign is implemented.

According to ERCOT’s Independent Market Monitor, the operational changes applied in the wake of the blackouts cost $1.3 billion through May 2021.

Generally, those precautions — the additional caution applied to the grid that is costing so much more — have continued.

And they’ve accomplished their purpose, getting the state through a cold snap in February and a prolonged scorching summer this year. But those adjustments are not self-sustaining, hence the redesign.

Under the current state of the energy-only market, E3 estimates that in 2026, customers would see $22.3 billion in costs per year as 11,260 MW of natural gas and coal capacity would exit the system — plants retiring from use without replacements. Under that scenario, the consultant also projects 1.25 days per year in which load-shedding, rotating or forced blackouts, might be necessary.

That’s the baseline of E3’s analysis.

The firm then analyzed six other paths forward for the redesign and recommended the PUC adopt a “Forward Reliability Market” (FRM) approach.

The FRM would create a system in which “reliability credits” — monetary awards divvied out to generators by ERCOT — are distributed to generators based on their performance during times of high stress on the grid.

This does not mirror one of the items Gov. Greg Abbott tasked the PUC with pursuing in July 2021: sticking renewable generators with costs incurred by the state or other generators when the intermittent sources fail to show up. It appears instead to try and accomplish a similar goal through another route — rewarding those who do produce monetarily.

E3 estimates the cost of this measure to ratepayers to be $460 million with a 0.1-day-per-year loss of load potential, which is in line with industry standards, according to the report. It also estimates a 5,630 MW growth in natural gas capacity under that scenario.

The other option E3 favored close to the FRM is a Load Serving Entity Reliability Obligation. This plan is similar in structure, but its reliability credits would instead be traded between generators rather than divvied out by the central authority.

The idea is similar to the internationally discussed “Cap and Trade” system in which a cap on emissions is set and then emitters, whether power plants or other miscellaneous businesses, can trade emissions credits between one another.

That system comes with roughly the same cost, load-loss, and capacity growth estimates as the FRM scenario.

A complication within the report is that while E3 stops its analysis after 2026, ERCOT projects capacity developments through 2033. Pair that with the fact that many Retail Electric Providers — more accurately, their ratepayers — are paying off billions of dollars in debt associated with the costs from the blackouts through securitization loans for decades to come.

E3 says the reason it chose the 2026 timeline is that it’s “near-term enough that there is relative certainty about expected loads and resources … but long-term enough that any potential market design reform could be implemented.”

While this is the official third-party recommendation, it’s not necessarily what the PUC will ultimately adopt — nor perhaps the only thing.

At an October press conference introducing new ERCOT CEO Pablo Vegas, PUC Chair Peter Lake said the final market redesign will be approved before the end of the year.

Correction: A previous version of this story incorrectly stated that ERCOT partnered with E3 Energy Solutions, not Energy and Environmental Economics, Inc. We regret the error.

A copy of E3’s report can be found below.