This summer, Texas grid operator ERCOT started working on ideas for opening the state’s energy markets to distributed energy resources, by allowing the grid-scale aggregation of rooftop customer-sited generators. It’s a move similar to those being taken in solar-rich states like California and Hawaii, only with Texas’ unique deregulated market flavor.
One interesting question is how to build distributed energy resource (DER) portfolios with enough flexibility to optimize their value to the grid and their owners, but not so much flexibility that companies can game the system. It’s a concern in the state that spawned Enron, and it’s part of the discussion around ERCOT’s new concept paper, released last week, that lays out a first official outline of what the state’s DER future might look like.
The white paper is for ERCOT’s Distributed Resource Energy & Ancillaries Market (DREAM) Task Force, or DREAMTF for acronym fans. The document largely hews to the three key classifications ERCOT is considering — DER Minimal, DER Light, and DER Heavy — and a description of just what will need to happen, and what future questions need to be answered, to make each version into a real-world grid product.
Roughly speaking, DER Minimal would set compensation like demand response today, at the regional market clearing price of one of Texas’ four grid zones. DER Light and Heavy, by contrast, would allow payment at prices set at the more than 11,000 nodes across the state, where prices can shift and spike more quickly to reflect local conditions, and are usually reserved to big generators. DER Heavy adds another layer: real-time dispatchability to meet fast-responding ancillary services markets.
That’s a truly novel opportunity for small-scale energy resources in the state, according to Chad Blevins, senior consultant with Austin, Texas-based law firm The Butler Firm and chairman of ERCOT’s Emerging Technologies Working Group. But it comes with a lot more responsibility to measure and report that data in real time, to make sure it’s doing what it’s being paid for, he noted.
DERs break many boundaries in how today’s grid markets are structured. For example, the Texas market maintains strict separation between generators, “wires” utilities, and the retail energy providers that do business with customers. But DERs cross over all three of these realms, which requires some fudging of the rules made for power plants.
At the same time, DERs represent both generation and load. In the case of energy storage, it can be both, in fact. Today’s energy market participants have to keep strict separation between those two realms. But well-managed DERs could flex their load curves alongside their generation curves, to add flexibility and efficiency to the profile they present the grid.
All of this creates potential points of contention between mainline power generators and the would-be pioneers of the distributed energy grid. One of the big emerging ones, Blevins said, is over how to allow combined generation and load resources to play into the markets. And unlike many of the other differences of opinion that have arisen in workshops addressing the topic, “This one will be something that will eventually have to come to a vote,” he said.
On the side of the DER proponents, “The idea that a component of a DER could be part of a market participatory distributed energy resource at some times, and at others the component, is providing service on-site, at the premise it’s located — that physical option is seen by some as a perfectly reasonable thing that should be allowed,” he said.
“Other market participants will strongly argue against that. They will say that is gaming at best, because it is not actually providing a better economic outcome to the market as a whole, and at worst, they’ll say that is an avenue for market manipulation.”
Here’s why, he said. Imagine an unscrupulous distributed energy aggregator with a lot of behind-the-meter energy storage and building energy management that can shift load up and down with precision. “Without the proper boundaries on its actions, that could use a whole lot of load, and the cost of that load is load-zone price, averaged out” — in other words, not as responsive to the sudden large increase in load at one particular node.
But this hypothetical operator does get paid that nodal price for the power it sends back to the grid — and by “driving up the congestion, and thus the locational price of the bus they happen to be behind, they can then turn around very quickly and inject energy at that higher price,” he said. (This real-time map of locational marginal prices across Texas indicates how they can shift over the course of the day.)
“That is the Enron scenario that people are painting and pointing to” as reasons to limit DERs to either acting wholly as a load resource or supply resource, not both.
However, many of these DER companies are focusing heavily on demand charge reduction — the task of shaving peak consumption to reduce the portion of the utility bill set by maximum power usage at certain times of the day or year. This is the main business model for behind-the-meter batteries from companies like Stem and Green Charge Networks in demand-charge-heavy states like California and New York.
Luckily, there are solutions to this problem, said Blevins. “As long as we write into the protocols just what a DER is allowed to do, we can still have that option in place, in a way that does not permit gaming,” he said.
One clear guideline in ERCOT’s white paper is the need for separate metering of storage systems.
Another idea is to ask DER Light and Heavy participants to follow a “current operating plan,” or COP, like today’s large-scale generators do, he said. COPs lay out their plans for the hours, days and weeks ahead, and require payment of penalties when providers don’t comply.
The white paper also “recommends that DER Light be required to communicate certain data in real time or near-real time to ERCOT,” to be able to include their effects on its own pricing scheme.
There’s good reason for ERCOT to seek out more data on what’s happening in the DER landscape, Blevins noted. “They recognize there are DERs being installed anyway — and they have no visibility into all that stuff out there right now. They know through interconnection data that it’s there, and they can use telemetry to know what it’s doing at any particular time, but they don’t know what it plans to do.”