Dozens of wind farms in Texas have been left reeling from billions of dollars of losses incurred during last month’s state-wide electrical grid failure, even though the industry played a minor role in the power generation shortages that crippled much of the state.

Those facilities either shut down, under-performed or were unable to fully export power during all or part of a week of historically cold winter weather because of blade icing, low wind resource, onsite electrical supply issues, and transmission congestion in the state’s main power grid, according to industry officials.

But the severe financial losses were not due to lost income from wind-power sales, but rather due to a knock-on effect from an inability to deliver power.

Many wind farm operators in Texas have so-called P99 hedging contracts, which commit projects to deliver a fixed amount of power every hour, regardless of actual levels of generation. This means that project owners had to buy electricity on the wholesale market at times when they could not generate enough power, and supply that to their offtakers at an earlier agreed set price.

But during the 90 hours of the recent crisis, the wholesale price was inflated to the ceiling price of $9,000 per MWh — more than 400 times the average $22/MWh price for bulk power in Texas in 2020 — as the local grid operator, the Electric Reliability Council of Texas (ERCOT), desperately sought power. Limited interconnection with neighbouring US electricity networks meant that ERCOT could only import small amounts of power from outside the state.

The sky-high wholesale price meant that project owners spent as much money in a few days as they would earn from several years of selling wind power, putting them in severe financial distress and unable to pay back counter-parties such as Wall Street banks or other financial institutions.

“Contract structures drove who was financially impacted by this event and who wasn’t,” said Lee Taylor, founder and CEO of REsurety, a leading clean energy analytics firm based in Boston.

The Texas Top 10

The ten largest owners of ERCOT market wind capacity (in alphabetical order):

Avangrid Renewables

Duke Energy Renewables

EDF Renewables

Engie North America


NextEra Energy Resources

Orsted Wind Power North America

Pattern Energy Group

RWE Renewables

Southern Power

“While there will certainly be exceptions, I expect the vast majority of projects with P99 hedges are in a very difficult situation right now.”

Analyst Bloomberg NEF modelled a hypothetical 200MW wind farm in Texas and found that it would have lost $40m from 15-19 February, “if it was operating at the ERCOT wind fleet average capacity factor”.

The full financial downside for the industry remains unclear, in part because privately held independent power producers and infrastructure funds are not required to disclose losses, while some publicly traded firms have not divulged their financial exposure.

A hint of what could be involved came in a 3 March filing by nine wind farm owners to the Public Utility Commission (PUC), the state’s grid regulator.

The owners including Canada’s Algonquin Power & Utilities, Denmark’s Copenhagen Infrastructure Partners (CIP) and Scout Clean Energy said “it appears that at least 46 mostly wind projects totalling 9GW would suffer severe financial losses” resulting from the $9,000/MWh prices during the power market crisis.

And two major European utilities, Engie and RWE, which are both among the largest wind-power operators in Texas (see panel), have said that the Texas freeze could result in negative impacts to their bottom lines.

Engie warned it could suffer a $147m hit to Q1 operating profits and RWE said its renewables unit will absorb a €400m ($478m) impact to pre-tax earnings.

“There are a lot of people who lost a lot of money. I don’t have a hard number,” said Jeff Clark, president of Advance Power Alliance, a regional renewable energy and natural gas industry group in the capital Austin.

Power market impacts

Perhaps the worst aspect of the debacle is that the PUC may not have needed to increase the wholesale power price to the maximum $9,000/MWh — and certainly not for as long as it did.

On Monday, 15 February, the grid neared collapse with system frequency having fallen from a normal 60 hertz to a perilously low 59.3 hertz, as scores of generators — mainly thermal power plants — tripped offline due to frozen equipment and shortages of fuel. Of the 680 generators in ERCOT, 356 were offline at some point during the event.

ERCOT imposed controlled rotating blackouts to balance power supply and soaring demand, leaving millions of Texans people in the dark without heat in sub-freezing temperatures. At least 57 people died.

“We could not stay there long [at 59.3Hz], we could not go lower, or we would have risked a blackout of entire system,” said ERCOT CEO Bill Magness, who was later fired. Load shed at peak reached 20GW.

Hours later, the PUC unilaterally issued an order that set power prices at the $9,000/MWh market cap, more than a seven-fold increase, in some cases, from those set in real-time in the deregulated market. The commission said it acted to encourage more supply from all electricity sources.

The move failed. By then, 50GW of system nameplate capacity of the 107.5GW available was offline and unable to respond. Critics said the intervention broke precedent and protocols and had unnecessary, unreasonable, and unforeseeable financial consequences for many sectors of the state’s electricity industry, including retail customers.

Potomac Economics, the independent market monitor, later said ERCOT and PUC left the $9,000/MWh price in place 32 hours longer than necessary, given load shed had stopped, resulting in as much as $16bn in electricity overcharges.

Municipal utilities, retail power suppliers, thermal generators and wind farms that lost money have joined consumer groups and some state leaders in calling on ERCOT and PUC to reverse the overcharges and change the way electricity was priced during the crisis.

“The circumstances are extraordinary. So must be the response,” Silvia Ortin, CEO of RWE Renewables Americas, wrote in a filing to the PUC. She said electricity prices should be resettled as of 15 February. “Absent resettlement, the ERCOT market faces a downward spiral of defaults and bankruptcies.”

As Taylor said: “The real takeaway that we get from this is that the power market impact was a lot bigger than the weather event.”

Bloomberg NEF estimates the cost of electricity sold over a five-day period from when blackouts were in effect was $50.6bn — versus $4.2bn the prior week.

This generated billions of dollars in windfall profits for generators able to operate and commodity trading desks with physical power to sell, as well as suppliers of natural gas taking advantage of the high scarcity prices.

Clark noted that some wind and solar farms “remarkably made money, clearly — we have members on both sides.” One reason is they took the necessary steps to successfully mitigate risk before and during the crisis, he said.

CPS Energy, the nation's largest municipal utility in San Antonio, is now suing ERCOT, accusing the grid operator of engaging in "one of the largest illegal wealth transfers in the history of Texas".

Governor Greg Abbott called upon state lawmakers to look into the matter, and the Texas Senate duly responded, passing a bill that would force the PUC to reverse the billions of dollars of overcharging. The bill will now be looked at by Texas’ House of Representatives.

Role of wind in supply shortages

There is 31.3GW of installed wind power capacity in the ERCOT market — more than all but four countries. This is second to natural gas (51.6GW), but ahead of coal (13.6GW), solar (6.1GW) and nuclear (5.2GW).

Some national and state Republican politicians were quick to blame wind outages for the electricity crisis. “Renewables were a contributor to the generation shortages during this period, but they were a rounding error compared to the thermal outages,” said Lee Taylor, founder and CEO of analytics firm REsurety.

He noted that ERCOT was expecting 2.5-3GW an hour from wind this winter in a low-generation scenario, and there were only three or four hours through the five-day event that the fleet fell short. “Overall, wind beat that and beat it by a lot.”

Even though some wind farms were inoperable, the fleet’s capacity factor was still 25% even with relatively low wind throughout the state, as is normal in winter. “There were a lot of turbines spinning,” Taylor said.

Going forward, Texas officials and regulators need to take a hard look at the relative vulnerability of fossil sources in cold weather events.

“The failure rate from gas as an example and even coal actually exceeded anything we’ve seen on wind,” said Jonathan Monken, a principal at Converge Strategies, which helps government and the private sector develop energy resilience strategies.