NEW YORK — The Inflation Reduction Act and other policies have made the U.S. into one of the most attractive places to invest in clean energy, but completing the energy transition will require additional advances, panelists said Oct. 24 at the Aurora Energy Transition Forum.

Oliver Kerr, Aurora Energy Research’s managing director for North America, asked panelists whether they would pick the U.S. or Europe if they had $1 billion to invest.

“If I had a billion dollars, I would spend $100 million on the best development pipeline that required $2 billion of investment” in the U.S., RWE Clean Energy CEO Andrew Flanagan said. “And I’d invest that other $900 million into that portfolio, and then I’d claw back that additional billion, or $1.1 billion from our colleagues in Germany, or find some other equity source.”

Germany-based RWE is not alone, with Sandhya Ganapathy, CEO of EDP Renewables North America (a subsidiary of a Portuguese utility), saying the U.S. represents 45% of the parent firm’s investments, the largest share out of the 29 countries in which it is active.

“This is a great, great market to invest, and it’s also a great market where I truly believe that market fundamentals work really well,” Ganapathy said. “It’s not a lot of intervention; it’s really set by demand.”

There’s clearly still plenty of room to grow, as Europe is up to 35 to 40% renewable energy, while the U.S. is at just half of that. On top of federal policies spurring investments, 28 states have set some kind of mandate for renewables, and there is large and active demand from big corporate buyers, Ganapathy said.

Arguably the two leading states on the energy transition are California and Texas, which have deployed tens of thousands of megawatts using very different regulatory models.

“California, as we know, by state statute, has committed to decarbonizing the power sector by 2045,” CAISO CEO Elliot Mainzer said. “I think when you take the fifth-largest economy in the world and put it on that path, every major developer is going to want to have a piece of that, and so that’s why we have a 510-GW queue.”

Many developers come up against friction in the queue, but the issues around it can mask some realities like the fact that California has deployed 20,000 MW of new supply over the past four years, including 10,000 MW of batteries, he added.

California has a much more planning-based process with its various state agencies taking a bigger role in things than Texas, but part of the fix for that major backlog in the queue was borrowed from the Lone Star State. CAISO’s newest recently approved process involves studying which of those 510 GW actually are responding to demand and linking the transmission planning process to the queue, Mainzer said. (See FERC Approves CAISO Plan to Streamline Interconnection Process.)

CAISO borrowed “very shamelessly” Texas’ Competitive Renewable Energy Zone approach, which picked out the best areas for wind and built major transmission lines to connect them to cities, turning the state into the leader in wind capacity, Mainzer said.

“The way the ERCOT market has evolved, it has been very open and made it very easy for both supply and for load to come to the system,” CEO Pablo Vegas said. “We’ve got a light regulatory touch on virtually all facets of the interconnection process, and we’re very flexible in the way we manage those interconnection queues. And it’s been a benefit that has, I think, gotten us to where we are today, but the old adage of ‘what got you to where you are today won’t get you where you’re going to go’ applies very accurately in Texas, as we look forward.”

Projections for load growth in ERCOT call for as much as 150 GW to come online; it set its peak record of 85,508 MW in August 2023. It is far from clear that demand will grow that much, but like in other parts of the country, Texas is seeing demand growth on a scale that has not been witnessed since the years following World War II, Vegas said.

“In order to meet that challenge, we are going to have to think differently,” Vegas said. “In Texas, we have not historically planned where load or where supply gets sited. And when you’re trying to build transmission, which is going to become the linchpin to the success of this whole strategy, transmission has to know where load and supply is going to be. And so, we’re starting to take similar constructs and approaches to what Elliot just described.”

ERCOT is doing that less formally, making assumptions as to where demand is likely to show up on the grid based on where resources are and linking the two with transmission. None of that activity is required by rules, but the hope is that the market will follow suit and plan accordingly.

“It’ll be the fastest way to get there, and it will be the most efficient way to build the transmission infrastructure, but the market will respond to that,” Vegas said.

ISO-NE CEO Gordon van Welie said the transition involves four pillars, but one of them is much less discussed: ensuring the system has enough stored energy in fuel tanks or other long-term options to make it through times when renewable supply is low and demand is high, especially during winter.

“We’ve assumed that problem away,” van Welie said. “Actually, if you go back 25 years ago when we started the market construct, we just assumed that everyone was going to have a reliable fuel supply.”

The clean energy supply in New England is being driven by state mandates, while the issues around resource adequacy and reliability services is driven by the wholesale market. The states have said they do not want to take back authority for resource adequacy, van Welie said.

“They want the kudos from signing the contracts with the green stuff, and they want to leave the problem of how you pay for all that fossil stuff to the ISO and FERC, right?” he added. “So that’s the sort of political dynamic that’s going on there. But in this regard, I agree with [FERC] Commissioner [Mark] Christie, which is the states can’t just walk away from resource adequacy.”

The states have to get behind a market that can support resource adequacy over the long term, because otherwise it will be chaos, with the markets having to be redesigned every three or four years, van Welie said.

One of New England’s longstanding issues is ensuring reliability at the end of the pipeline network during harsh winter weather, which has bedeviled the market at the opposite end of many of those pipelines: Texas. Unlike the Northeast, Texas has plenty of natural gas supply, but it has had its worst reliability issues during the winters, Hunt Energy Network CEO Pat Wood said.

“Gas has two mistresses in the middle of a cold day, and it’s gas customers who keep their homes warm through natural gas and now 62% of Texans who keep their home warm through electric heat,” Wood said. “And that very tight period of time is where you’ve got the problem.”

Texas cannot count on its growing solar resources before the sun rises on a cold winter morning and when wind also is not producing at those times, and the market is not sending a strong price signal that resource adequacy is required in such times, Wood said. After Winter Storm Uri, the price cap was cut back from $9,000/MWh to $5,000/MWh.

The dispatchable reliability reserve service (DRRS), a proposal from the Texas Industrial Energy Consumers working its way through ERCOT’s processes, could help send the right kind of price signals to get needed generation built, Wood said.

While Texas and New England both face winter reliability issues, Calpine CEO Thad Hill, whose firm is active in both markets, noted they have very different causes.

“In the east, we’ve got a fundamental capacity shortage,” Hill said. “In ERCOT, we had a breakdown of preparation.”

Part of that breakdown ahead of Winter Storm Uri came from new oil and gas production capacity that had come online in the Permian Basin since ERCOT’s previous winter reliability problems in 2011, he added. Oil and gas production older than that performed better, while the new Permian capacity often was supplied by the grid and stopped producing when it lost power, exacerbating shortages in both gas and electricity.

While PJM had its hiccups in winters past, historically it has had very healthy reserve margins. But its recent capacity auction saw prices shoot up as those narrowed, which has sparked controversy. (See PJM Capacity Prices Spike 10-fold in 2025/2026 Auction.)

Hill noted that in the past when capacity prices have spiked, his firm and other suppliers have responded with new supply, and he expects that to happen again.