Energy storage in ERCOT
Who ought to own standalone energy storage in ERCOT?
The implications for generators, transmission and distribution utilities, developers and ratepayers are big.
Since utility services within ERCOT were unbundled in 1999, resource participation has been categorized essentially as either generation or transmission.
Storage has attributes of both. Storage can enhance generation by making intermittent resources dispatchable, for example. Storage can also enhance the wires and the poles, in much the same way that line packing natural gas into an existing pipeline can increase system reliability.
Texas legislators and regulators have struggled with how to handle the multifaceted storage asset within the existing binary framework.
They are expected to weigh in on the issue in the near to medium term. There seems to be momentum behind an approach that would keep storage ownership primarily out of the hands of the transmission and distribution utilities, but utilities would be allowed to buy reliability services from independently-owned storage facilities by contract, pass the costs on to ratepayers, and potentially own small amounts of storage under limited circumstances.
Current market structure
Approximately 90% of Texas load is served through the ERCOT market, which set a new record for peak demand of 74,679 megawatts on August 12, 2019. More than 25% of generating capacity in ERCOT as of January 2019 came from intermittent resources: 23.4% from wind and 2.1% from solar. Judging from the current interconnection queue, ERCOT’s generation mix will become even more intermittent, with 59,000 megawatts of solar accounting for 54% of the queue, 36,000 of wind accounting for 33% of the queue, 10,000 megawatts of gas representing 9% of the queue, and 4,000 megawatts of battery storage representing 4% of the queue.
Superficially, with so much intermittent generation, ERCOT would seem like a ripe market for storage.
Energy storage, and battery technology in particular, are often described as a Swiss Army knife, capable of providing a wide variety of services to the grid in a single compact package. Storage deployment is still in the early stages relative to wind and solar. The tendency among developers thus far has been to pull all the blades out of the Swiss Army knife at once, to stack as many storage revenues as possible. However, recently as global energy storage markets have gained traction and matured at least somewhat, three distinct revenue streams have come into focus: capacity, energy and ancillary services. Capacity payments tend to be predictable and therefore the easiest part of the storage revenue stack to project finance. To date, energy storage has flourished in markets with meaningful capacity payments.
ERCOT, however, is an energy-only market. There are no pure capacity payments in ERCOT. To survive in ERCOT, grid-scale energy storage systems must either buy energy low and sell energy high or provide ancillary services, which are essentially operating reserves that respond to variability in load or in generation output, often for purposes of voltage and frequency control.
To date, the energy arbitrage and ancillary services use cases have not been attractive enough for storage truly to flourish in ERCOT. Currently there are just 10 operational standalone storage projects in ERCOT with a total capacity of 101 megawatts, of which 64 megawatts are from two projects. According to ERCOT, these existing storage projects are primarily used for ancillary services.
Beyond energy and ancillary services, a hypothetical third option for new grid-scale storage in ERCOT would be for transmission and distribution utilities to own storage and put the capital expenditures into rate base. To date, there has been only one transmission-level storage project owned by a utility in ERCOT — a very small facility in a very remote part of Texas.
The question of utility ownership came to the fore when AEP Texas, a utility, asked the Public Utility Commission of Texas (PUCT) for permission to own storage to address reliability issues in remote parts of its distribution system. The Texas utilities code says that storage that is intended to be used to sell energy or ancillary services is a generation asset that cannot be owned by a transmission and distribution utility. But the Texas utilities code also says that transmission and distribution utilities may not sell electricity or participate in the market for electricity except for the purpose of buying electricity to serve their own needs.
Did AEP Texas intend to own storage to participate in power markets or support reliability?
The issue divided the power community along generator and utility lines. The utilities said the law is clear, and utilities can own storage if the goal is reliability. Generators said the law is not clear and, even assuming clarity, the impact would be altered wholesale prices. Storage developers and manufacturers mostly aligned themselves with the utilities.
The PUCT dismissed AEP Texas’s application and requested legislative direction. The Texas legislature only meets every other year. During the 2019 legislative session, a bill passed both chambers and was signed into law that clarified that municipal utilities and electric cooperatives may own storage without registering as a generator. However, the question of utility ownership of storage remains unsettled.
As a result, the current state of play is that transmission and distribution utilities may not own storage in ERCOT.
Possible paths forward
In January 2019, before the most recent Texas state legislative session, the PUCT presented legislators with four distinct options relating to ownership of storage:
 prohibiting a [transmission and distribution utility’s (TDU)] involvement with an energy storage device other than to provide transmission and distribution service to it;  allowing a TDU to contract with a power generation company for reliability service from an energy storage device;  limiting a TDU’s ownership and operation of an energy storage device only to limited, specified circumstances such as to address a reliability issue in a sparsely populated area in its distribution system; and  allowing a TDU to own and operate an energy storage device in circumstances where the TDU’s ownership and operation of the device would provide the lowest cost transmission and distribution service.
With the AEP Texas request to own storage effectively paused pending legislative direction, transmission and distribution utilities are not currently allowed to own storage.
As a result, option 1 would operate as an effective extension of the status quo.
Although a number of developers see great opportunities in the ancillary services markets, deployment numbers to date suggest that for storage to see greater deployment under existing market conditions, storage should also be cost-competitive in the energy markets. This is a function of the storage owner or operator knowing when and how quickly to charge and discharge, and knowing how efficiently the storage system’s technology can hold the charge.
There are many storage technologies, each with unique strengths and weaknesses. The inability to hold a charge efficiently for more than a few hours at a time limits a storage system’s ability to capture the full arbitrage opportunity, as does the inability to predict accurately and respond quickly to arbitrage opportunities.
Texas summers are hot and prices tend to spike in late afternoons. August 2019 was no exception: 27 of 31 days were above 100 degrees in Austin.
August 12, 13 and 15, 2019 provide an excellent case study in how peak temperatures and peak loads alone do not predict ERCOT wholesale prices. The new ERCOT peak demand of 74,679 megawatts was set on August 12, 2019. August 13 and 15 each had slightly lower demand, at 74,428 megawatts and 74,558 megawatts, respectively. And yet, new record peak day August 12 saw only two momentary spikes, first to $7,000 a megawatt hour at 2:25 pm and then to $8,000 a megawatt hour at 3:00 pm. In contrast, August 13 and 15 each saw prices reaching the ERCOT maximum price of $9,000 a megawatt hour for nearly two hours, between 3:05 and 4:45 pm on the 13th and between 3:10 and 4:55 pm on the 15th.
Why? At the time of instantaneous peak demand on the 12th, there were a relatively abundant 7,468 megawatts of wind and only 3,765 megawatts of generation outages, as compared to just 4,507 megawatts of wind and 3,282 megawatts of outages on the 13th and only 2,789 megawatts of wind compounded by 4,916 megawatts of outages on the 15th.
To reap the potential profits that energy prices promise at $9,000 a megawatt hour, energy storage systems need either to wait patiently at the ready, efficiently holding their energy charges for the precise moment to pounce, or be able to predict wind generation and other generator outages accurately. A sponsor hoping to finance such a revenue stream would also need to convince a financier that the price surges of $9,000 a megawatt hour will continue to occur several years from now after presumably much more solar has been built on the ERCOT grid and is generating on-peak.
Option 2 would allow transmission and distribution utilities to contract with storage owners for reliability services, but not own storage.
This would shift the burden of the initial capital outlay from ratepayers to storage developers. In that sense, it is a pro-competitive market option.
If this path is pursued, there are several key issues to be resolved.
One issue is whether the payments made by the utility to the storage facility in exchange for the reliability services under the contract could be capitalized and therefore passed on to the ratepayers (and, therefore, not be as pro-competition as Option 1).
Another issue is whether the storage owner would be permitted to use any storage capacity in excess of the capacity required to satisfy the reliability requirements of the utility for offers and sales of energy and ancillary services.
There is also the issue of what happens if the storage facility fails to meet the reliability requirements or impermissibly participates in energy and ancillary services markets and whether any associated administrative penalties would be the responsibility of the storage owner or the utility.
Option 3 would allow transmission and distribution utilities to own storage only under certain narrowly specified conditions.
The PUCT’s January 2019 report to the Texas state legislature provided one lone example of such a condition: sparsely populated areas in order to support grid reliability on a utility’s distribution system.
There are many open questions to be resolved if this path is pursued, including just how sparse a “sparsely populated area” would have to be, whether there are any other conditions beyond just distribution system reliability that would qualify, whether there might be any circumstances under which the utility could own storage on the transmission grid and participate in energy and ancillary services markets, and whether there would be an overall cap on the number of megawatts of storage a utility could own.
Option 4 would allow utilities to own and operate energy storage when such ownership provides the lowest cost of transmission and distribution service.
In one sense, this can be considered a limited, specified condition and, therefore, a subset of option 3. In another sense, one could argue that providing the lowest cost of service ought to be a prerequisite to utility ownership of storage in all circumstances and, therefore, Option 3 ought to be a subset of Option 4. One could also argue that contracting for services from an independent storage owner will always be cheaper than utility ownership and, therefore, Option 4 is the functional equivalent of Option 2.
Regardless of how it is characterized relative to the other options, many of the same issues still need to be resolved, such as whether there might be any circumstances under which the utility could own storage on the transmission grid and participate in energy and ancillary services markets, and whether there would be an overall cap on the number of megawatts of storage a utility could own.
A possible outcome
Preserving competitive markets to keep ratepayer costs as low as possible is likely to be the guiding principle for the Texas legislature and the PUCT.
Consequently, the ultimate path forward will probably involve as little intrusion on the energy and ancillary markets as possible, while recognizing that energy storage resources can be valuable for purposes of generation and transmission as well as overall grid reliability.
A potentially likely outcome is a combination of Options 2 through 4, which is essentially what was proposed as SB 1941 by Texas Senator Kelly Hancock during the 2019 legislative session.
SB 1941 would have allowed or permitted five things. It would have allowed transmission and distribution utilities to contract with a third-party storage facility for reliability services with payments included in the utility’s rate base. It would have permitted the storage owner to use any storage capacity above the capacity required to satisfy the reliability requirements of the utility for offers and sales of energy and ancillary services. It would have allowed the utility to make the third-party storage owner responsible for any associated administrative penalties. It would have required the utility to issue a request for proposals before entering into any reliability services contracts. Finally, it would have allowed utilities to own no more than 10 megawatts of storage with the prior approval of the PUCT if the utility issues a request for proposals and receives no offers meeting the requirements.
SB 1941 passed the Senate and then the House State Affairs Committee before time ultimately expired on the 2019 legislative session.
A bill similar to SB 1941 may be proposed during the 2021 Texas legislative session. The PUCT also might pick the matter back up in the meantime. Legislators and regulators may be hesitant until there is more data about the likely impacts such a law might have on wholesale energy prices, storage deployment, consumer rates and grid reliability.
Legislators and regulators may be waiting for ERCOT to assemble a larger data set for existing storage. Of the 10 existing operational standalone storage projects in ERCOT, the oldest was placed in service in 2013, and seven of the 10 projects representing 65 megawatts of the 101-megawatt total installed capacity became operational in 2017 or later, so the sample size is small.
As a practical matter, ERCOT does not currently have much visibility into storage resources. In essence, the grid operator can see storage as load when charging and as generation when discharging. But in order to understand the extent to which a storage facility could be a reliability resource, ERCOT must be able to model how storage will act, so ERCOT will eventually need to see state of charge and have an understanding of potential rate of charge and discharge.
Although ERCOT is entirely within the state of Texas and, therefore, not subject to federal regulatory jurisdiction, ERCOT is monitoring the changes other independent system operators are undertaking in compliance with FERC Order No. 841. Multiple ERCOT stakeholder task forces, working groups and nodal protocol revision requests continue to tackle some of the finer questions posed by grid-scale storage, such as telemetry requirements, data reporting obligations, hub-versus-node pricing when charging and discharging and responsibility for transmission charges through ERCOT’s four coincident peak calculations. Meanwhile, the Texas legislature and PUCT work through the big question of storage ownership.
Even as stand-alone storage waits for the Texas legislature and the PUCT, developers are announcing pure merchant storage facilities.
Whether these projects will be built will depend on the risk tolerance of investors and lenders for the energy and ancillary services markets and whether a federal investment tax credit is forthcoming for standalone storage. In addition to standalone storage, co-locating storage with solar, primarily to capture the existing solar investment tax credit on the storage components, but potentially also to firm up hedging-related volume commitments will continue apace. And while “energy alerts” such as those issued on August 13 and 15 sound alarming, in many ways the energy-only market stucture in ERCOT achieves its desired purpose: the lights did not go off and prices went up, incentivizing development.
We can expect more storage on the ERCOT grid, that much is clear, but the questions of who owns, who pays and who profits will depend in part upon the Texas legislature and the PUCT. ∞
A special thanks to Suzanne Bertin at the Texas Advanced Energy Business Alliance and Charlie Hemmeline at the Texas Solar Power Association.