EnergyTexas Electricity Prices Up After Post-Blackout Directives, State Increasing Capacity and Caution

In front of the Texas House State Affairs Committee, Potomac Economics’ ERCOT Director Carrie Bivens testified that Texas electricity prices are increasing substantially as the state changes the way it runs its power grid.

Last year, electricity prices per megawatt-hour (MWh) on the ERCOT grid increased 550 percent — reaching $167.88 per MWh. That includes the soaring costs during the February blackouts when the price of electricity jumped into the thousands, up to $9,000 per MWh, where it remained for several days.

Taking out the blackout’s extremity, that price drops to $40.73 per MWh, still a 65 percent increase from 2020 to 2021. Part of the blackout’s cost is the securitization loans companies are now beginning to pay off, the result of a 32-hour period during which the price of electricity was held at its $9,000 cap after emergency conditions had ceased.

Customers are seeing surcharges appear on their monthly utility bills, but those are lower than they would have been without the loans that allow the companies to defray the cost of their blackout-incurred debt over decades rather than months.

In addition to the blackouts, an external driver of that cost increase is the rising price of natural gas — the fuel that powers over half of the grid’s installed generation capacity. That price is rising for a variety of reasons, including the European market turmoil spurred by the Russia-Ukraine conflict, since the gas market is international, and the bleak outlook among domestic producers caused by inflation and the White House’s energy policy.

But the biggest and most immediate cause of the rising electricity costs is the state’s operational response to the blackouts.

In its Phase I reforms, ERCOT and the Public Utility Commission (PUC) decided to inject more caution into its daily operations. This entails increasing its number of available peaker plants — “break in case of emergency” generation — by 15 percent throughout the year, not just during the height of the summer heat during which they typically operate. Keeping those generators online more often than they otherwise would costs more money.

Peaker plants normally operate on the ancillary services market — a secondary market in which the price of generation rises to an even higher premium than the wholesale market.

Bivens voiced concerns about this operational change on Wednesday, saying that it unnecessarily increases cost and could inhibit the generators’ ability to stay online at later points in the summer.

Price signals are paramount to the grid because ERCOT is as close to a free market as exists across the nation’s power grids. When demand for electricity increases, so does its price to match. When price increases, that sends a signal to generators to bring more capacity online, presenting an opportunity to make money.

And that price is constantly fluctuating.

The other part of the rising cost is a tweak to the Operating Reserve Demand Curve (ORDC), a regulator that increases prices as scarcity rises. When grid conditions tighten and reserve margins are dipped into, the ORDC triggers a price increase. This is what caused the price to jump to the cap during the blackouts. After the blackouts, the ORDC’s price signals now kick in sooner than before to try and prevent reserve margins from being used.

But that comes at a steep financial cost.

Bivens estimates that these two operational changes could cost up to $1.3 billion through May this year.

The PUC is now considering its Phase II market reforms, a blueprint laying out a substantial overhaul of the ERCOT electricity market.

Texas is facing a rapidly growing footprint of renewable generation at the expense of thermal development. A declining thermal footprint means the grid’s resilience is more dependent on renewables and the continuously changing winds and disappearing sunshine.

Renewables can produce at relatively high levels for their installed capacity, just as they did when Texas set an all-time peak demand last month, but they also can disappear at inconvenient times.

At lengthy periods during the 2021 winter storm, wind generation produced less than a fifth of its installed capacity — occasionally dipping even lower than that.

Because of the influx of renewable energy into the ERCOT market — and their ability to break even producing power at negative prices because of federal tax credits — Bivens said she sees only two possibilities to fix the grid’s issues.

She said that either the PUC tweaks the market signals enough to remedy that “distortion” of the ERCOT market, or the state needs to adopt a capacity model — the likes of which exists in most of the rest of the country.

A change in the latter direction would entail a far more cumbersome process of reform, and legislators do not appear keen on that path — especially only a year after their directives were passed and before the PUC has finished implementing them.

That kind of change too would come at a cost. Electricity in capacity markets is generally pricier because constantly guaranteed generation negotiated up-front costs more than the fluctuating decisions to turn on and off that the ERCOT market uses. But the 2021 winter storm shows the trade-off: in times of extreme scarcity, prices in a fluctuating market spike.

And at the end of the day, the costs in almost all cases will be shouldered by the ratepayers, the customers.

In the wake of the 2021 blackouts, Texas officials were urged to never let it happen again and inject more dependability into the power grid. But that comes with a price. All decisions come with trade-offs, especially those concerning Texas’ power grid.