Why Is the Texas Market So Tough for Energy Storage?

Let me count the ways…

The booming renewables industry in Texas should, in theory, create a role for energy storage plants to manage its variability.

Years into the Lone Star State’s wind and solar deployment, though, little grid storage has arrived, and future prospects look bleak.

Early projects have delivered some 89 megawatts of storage into ERCOT’s grid, said Cheryl Mele, chief operating officer of the Electric Reliability Council of Texas, the grid operator. Another 1,800 megawatts have entered the interconnection queue, which by no means guarantees they will ever be built.

Lack of a winning business model makes it unlikely mass deployments will begin anytime soon. That could leave significant value on the table for Texas ratepayers.

“When you look at the amount of renewables we do have, certainly storage would have some value in being able to respond quickly,” said Mele, speaking at Wood Mackenzie’s Power & Renewables Summit in Austin Wednesday.

“If we start to see a gap between our forecasted load and our forecasted intermittent renewables, the batteries can respond very quickly,” Mele added. “They can cover a bit of that gap while you’re waiting for other resources to ramp up.”

Here are the major obstacles facing the young energy storage market in Texas, with some provisional solutions to get this technology into play.

Utilities can’t own it

Texas power market deregulation separated competitive generation from regulated wires utilities.

That implicates storage because it qualifies as generation in this market; that means it has to compete with gas generators, and wires utilities are not allowed to own it, lest their ownership undermine the bedrock of competitive markets.

That said, batteries don’t actually generate; they store electricity generated elsewhere and release it at useful times. The discharge of power resembles generation, but batteries can readily function as transmission or distribution assets.

The classic case would be when load growth in a certain area strains the substation or transmission lines serving customers there. The traditional solution is to upgrade the substation or build new wires, at great expense to ratepayers. Sometimes the additional power required on a rare peak event can be served with the addition of a battery system nearby, at much less expense.

This doesn’t work just anywhere. Indeed, the deferral projects are rare enough to remain nameable: Arizona Public Service’s Punkin Center; Duke Energy’s Smoky Mountains outpost; and an American Electric Power subsidiary’s Presidio project, before Texas decided to call storage generation.

These projects made storage pay for itself on economic grounds in states with no policy incentives to support deployment. That says something. But that won’t be happening in Texas under the current rules.

It’s hard to gauge just how big a market this could be for storage. One rough indicator: American Electric Power pledged this week to invest $25 billion in transmission and distribution infrastructure across the U.S. If a fraction of that ends up in Texas, it would represent a billion-dollar opportunity for storage to get involved in.

It’s hard enough out here for a generator

This argument is more about feasibility.

In the rough-and-tumble Texas energy market, nobody is guaranteed anything. Participants look at market signals and choose whether to invest. If they do, they have to decide when prices justify firing up their generators. To stay afloat, they need to hit enough good scarcity events in a year to make up for the stretches of low prices.

That’s getting harder and harder to do, especially as wind resources start pushing down regular wholesale prices.

It’s tough actually making money in this game, and that’s for established companies with existing assets using tried-and-true technology. The idea of competing by building a new asset using relatively new technology, which doesn’t make electricity but obtains it from elsewhere and then returns it to the grid with some losses, seems highly improbable.

Add to that the lack of available financing for storage projects without long-term contracts and it becomes quite clear why no storage developers are looking to prove themselves in the Texas market.

No capacity contracts
This bears repeating: Texas has no capacity market. It does not contract with plants to come online in a pinch. That removes a financing tool that has launched hundreds of megawatts in California and the U.K.

Storage projects have worked without long-term contracts. The whole PJM frequency regulation market, which launched the U.S. grid battery era, rested on merchant investment to grab quick returns. But that market tanked after some rule adjustments, and since then, merchant storage hasn’t had any luck in the U.S.

“People are much more cautious based on what happened in PJM,” said Daniel Finn-Foley, senior analyst covering energy storage at WoodMac Power & Renewables.

Frequency market is a dead end
Texas does have a market for frequency regulation, and some storage projects are participating. But this is all merchant too, and the returns are nowhere near as solid as in the early days of PJM’s battery boom.

The small market is already getting saturated, Finn-Foley noted. That pattern has repeated everywhere else storage rushes in to perform this fast-response grid service. It won’t form the basis of an enduring market.

Arbitrage is not enough — yet
If storage can bridge the gaps between electrical feast and famine, there should be money in that. After all, prices can spike up to a cap of $9,000 per megawatt-hour, although that’s only happened once so far.

Lucrative price spikes, though, don’t come regularly enough to make a living on. A battery would have to load up on cheap or free wind power —and wait.

“If you’re sitting around doing nothing, ideally you want to be paid to sit around and do nothing, but there isn’t a mechanism for that in ERCOT,” Finn-Foley said.

All the existing gas plants are also waiting hungrily for price spikes. When they see one, they pounce, and that can limit the windfall to an hour or less.

If storage developers really believed in their technology, they absolutely could go into this market today without regulatory barriers to worry about. The case may improve as more wind and solar comes online, bringing more negative price events and transmission constraints.

FERC can’t help
Storage professionals are salivating in anticipation of the Federal Energy Regulatory Commission’s Order 841 results, which will clarify the ability of storage technology to participate wholesale markets.

“Markets are designed to favor conventional generation — that’s why FERC is ordering these markets to be redesigned so that storage is eligible,” Finn-Foley said. “There needs to be some recognition of the fact that storage is different.”

That won’t help developers in ERCOT, because that territory, within a single state, does not fall under federal regulatory jurisdiction. They’ll have to go it alone.

Near-term solutions
This all sounds pretty dire for Texan storage development. ERCOT is careening toward a state of renewables overload, while the snappiest tool to manage that intermittency lacks a viable path to market.

All is not lost yet, however. Some projects have still managed to appear, despite these obstacles. The near-term pathways for this break down into three categories.

Third-party service: A proceeding has begun before the Texas utility regulator to clarify a workaround for the “utilities can’t own storage” problem. One idea floated at the Power & Renewables Summit: The wires utility would contract the services of energy storage from a third party, and earn a regulated rate of return on the expenditure as an alternative to more expensive capital upgrades.

In theory, this saves ratepayers money compared to the old approach; it gives utilities a new way to earn profits, which they like; and it creates an opening for storage developers to hawk their services.

Merchant experimentation: A few companies have gone ahead and built battery plants already, treating it as an R&D expense to help them develop new business models.

Duke Energy did that at its Notrees, Texas wind farm. More recently, Vistra built the business case for the biggest battery in Texas by capturing solar generation that was getting clipped at an existing plant.

This category does not qualify as a proper market, but the more practice companies have with storage deployment, the more likely they are to try it if a better path to market comes along.

Customer-sited resilience for small-scale storage: After storms and floods, resilience is on the mind of many Texas businesses and homeowners. This customer-sited use case doesn’t require tricky regulatory overhauls, but projects will be smaller than grid-scale would provide.

Source: greentechmedia