Since the blackouts last February, state officials and industry stakeholders have tried frantically to map out reforms to the Electric Reliability Council of Texas (ERCOT) market on which electricity is bought and sold. Texas has an energy only market format, in which generators are paid for how much electricity they supply rather than negotiated up front like in a capacity market.
Being an actual marketplace, fluid and constantly changing, financial incentives play a massive role in ensuring electricity supply is available and in driving it to the end-user — the customer.
And so, while the legislature passed more tangible reforms, like a “weatherization” mandate, the orders to tweak the market are not so easily comprehensible.
The old economic principle holding that high demand and low supply yields a premium price was exhibited during the winter storm. Prices for electricity jumped to $9,000 per megawatt-hour (MWh) and remained there for days on end. In normal conditions, electricity trades on the ERCOT market between $20 and $50.
But that is dependent on enough supply to meet demand. During the hot summers when Texans blast their air conditioning units, the margin between the level of consumer demand and available supply tightens — and price rises.
This also occurred in February, but due to various issues, many weather-related, a large portion of the available supply dropped off the proverbial cliff. And as such, the wholesale price soared to its cap and grid regulators instituted rolling brownouts that turned into prolonged blackouts.
Companies that needed to purchase electricity on the wholesale market saw their bills rise nearly 30,000 percent, resulting in crippling debt for some. The legislature aims to alleviate this through securitization, government loans that allow the debtors to defray the cost of repayment over decades rather than months.
With that in mind going forward, the first market reform suggested by the PUC is to reduce the Operating Reserve Demand Curve (ORDC), a price adjustment tool that operates based on the scarcity of electricity. The PUC increased the point at which reserve capacity triggers emergency conditions and scarcity pricing, enlarging the cushion between normal conditions and running out of reserves.
It also dropped the scarcity pricing cap from $9,000 MWh to $5,000 MWh. There are two sides of this equation. The first is the generator on the front end supplying the power and hoping to capitalize on the premium prices, providing an incentive for them to ensure their generation is available. The second is the Retail Electric Provider (REP) on the other end of the transaction, purchasing the electricity and having to pay those premiums.
These companies on each side of the transaction often negotiate prices and supply with each other in day-ahead trading, but REPs whose negotiated generators were unable to fulfill their obligation due to outages had to then purchase electricity on the wholesale market. This led to massive costs and entities finding themselves underwater in cumbersome debt.
The effectiveness of this reform, its intended and unintended consequences, will not become clear in the near future.
When reserve margins tighten and emergency conditions are triggered, one of the first protocols initiated is to coordinate with large facilities that use massive amounts of electricity to take their load off the grid. This is done to free up capacity for residential customers.
Many of these facilities have backup generation on-site from which to pull in a pinch. While removing themselves from the ERCOT grid, they can still operate with those backups.
That protocol was triggered during the blackouts, but it wasn’t enough to prevent residential blackouts once the outages piled up. This blueprint proposes to streamline the process for removing those large consumers from the grid at large before emergency conditions are triggered to prevent them in the first place.
Another deals with regulation of the grid’s frequency. During the February blackouts, the ERCOT grid was 4 minutes and 37 seconds from a statewide blackout that could have lasted weeks or even months — known as a “black start” event. This occurred because large-scale outages caused the 60 Hertz (Hz) frequency to drop below 59.4 Hz for nearly 5 minutes.
The frequency must remain steady to prevent circuits from breaking and other electrical wiring from frying. Had the black start event occurred, those circuits across the 268,597-square-mile state would have needed to be manually fixed. The whole winter storm event was terrible, but this would’ve made it catastrophic.
The blueprint provides few details on this item, but it says the agencies are “currently developing Fast Frequency Response Service to help stabilize grid frequency in the future.”
Another contingency is a backstop of dispatchable generators lying in wait to fill any holes the Texas wholesale market and ancillary services miss. Ancillary services denote the fleet of generators that serves as a “break in case of emergency” option when reserve margins shrink. Made up largely of “peaker plants,” power plants only used during times of stressed supply which usually comes in the summer heat, ancillary service generation trades at an even higher premium price than the ERCOT market cap.
The state added additional ancillary service capacity ahead of this winter to provide more cushion. It did this by taking peaker plants that normally just operate during the summer and ensuring their availability this winter. It added 15 percent capacity to the winter fleet.
But someone has to pay for the additional standby generation and its effect on utility bills remains to be seen.
Incentivizing New Dispatchable Generation
Over the last few years and into the next few, Texas has added and will add over 30,000 MW in renewable energy generation in the form of wind and solar power. During the same period, it has lost or will lose over 20,000 MW in coal and natural gas generation due to plant retirements.
Natural gas generation in Texas and across much of the country has gradually supplanted coal plants because it is a generally more efficient resource and produces less emissions. But during the storm, coal may have helped provide more generation because its supply is generally stored on-site rather than shipped consistently through pipelines like natural gas. But that source, like all the others, was susceptible to severe cold weather issues too.
When regulators and politicians talk about dispatchable power, they mean any source of energy that is not reliant on the weather for its generation. Governor Greg Abbott, the state legislature, and the regulatory agencies have all stressed the need to add more dispatchable power capacity that is inherently more reliable because it is not intermittent like wind and solar.
The proposed Load-Side Reliability Mechanism aims to “[o]ffer economic rewards and provide robust penalties or alternative compliance payments based on a resource’s ability to meet established standards.”
This mechanism will be “self-correcting,” the blueprint reads, meaning that the incentive of higher prices begets more generation which in turn drives prices downward. The end goal is that the state ends up with more dispatchable power on the books for its rapidly growing population.
Markets of any kind are fickle contraptions because they are formed by thousands, millions, and billions of individual transactions between persons and entities. The ERCOT market is no different.
There has been little incentive, financial or otherwise, for generators to invest in more dispatchable sources of generation. Because of subsidies, renewable sources of energy have been the easy way to make a buck because they can sell electricity for negative prices and still break even. Perhaps the largest contributor to this is the federal Production Tax Credit that provides financial grants to renewable generators per kilowatt-hour of electricity they produce.
That provides a strong disincentive toward spurning thermal generation development. And the PUC hopes these tweaks provide a counter incentive.
The market redesign, dubbed Phase II of the PUC’s winter storm response, has not been finalized and industry stakeholders are currently filing comments on this blueprint. Feedback will be considered before the commission approves Phase II’s reforms.
Texas and its power grid regulators are in the process of implementing reforms, both physical and economic, to the state’s energy industry. And while the reforms’ return may not be fully realized in the short term, the rubber will meet the road as the state enters its first winter after its lights were knocked out.
Disclosure: Unlike almost every other media outlet, The Texan is not beholden to any special interests, does not apply for any type of state or federal funding, and relies exclusively on its readers for financial support. If you’d like to become one of the people we’re financially accountable to, click here to subscribe.
Brad Johnson is a senior reporter for The Texan and an Ohio native who graduated from the University of Cincinnati in 2017. He is an avid sports fan who most enjoys watching his favorite teams continue their title drought throughout his cognizant lifetime. In his free time, you may find Brad quoting Monty Python productions and trying to calculate the airspeed velocity of an unladen swallow.