This Colorado utility is building a VPP from scratch
Platte River Power Authority’s IRP calls for 32 megawatts of VPP capacity — but the utility currently doesn’t even have a DERMs.
Photo credit: Devonie McCamey / NREL / Department of Energy
Photo credit: Devonie McCamey / NREL / Department of Energy
A small utility in the Colorado front range has big plans for a virtual power plant.
The Platte River Power Authority is a non-profit, wholesale generation and transmission utility that serves 380,000 thousand customers across the Colorado cities of Estes Park, Fort Collins, Longmont, and Loveland. Its 2024 integrated resource plan includes a new, and ambitious, generation target: 32 megawatts of dispatchable capacity via a VPP by 2030.
The only problem? The utility currently has very few of the tools it needs to create a VPP at all.
While VPPs have the potential to benefit the power grid by integrating more renewables and providing ancillary services, Paul Davis, PRPA’s distributed energy resource manager, warned that operating a VPP to serve these functions could also stress the distribution system.
Avoiding that means building a VPP that is visible, measurable, predictable, and responsive in real time — a process that requires advanced communication and control technologies that PRPA currently does not have.
“Achieving the greatest benefits from a limited resource is another challenge,” said Davis in a public presentation in August. “We want to get as much as we can with these distributed energy resources, but some of these benefits are mutually exclusive.”
The utility will need a VPP configuration that allows them to optimize DERs within the market based on different conditions. And because it currently does not have a DER management system, or DERMS, it will need to purchase one, implement it, and create integrations with other critical systems: or, essentially build a VPP from scratch.
“And then there's the coordination among the various participants in this virtual power plant including the owner communities, Platte River customers, and really the whole VPP ecosystem,” said Davis. The ecosystem includes: customers, or DER owners; original equipment manufacturers, who make DERs and set flexibility parameters and capabilities; aggregators, who organize DERs as a unit and often across more than one DER type; and local service providers who make sure the DERs are available, being installed, and can be interconnected.
Breaking down the IRP
Like other utilities across the United States, PRPA is looking to clean up its generation mix by replacing dirty fossil fuels with cleaner options in the next few years. Specifically, the utility plans to expand their non-carbon generation mix from 24% today to 85% by 2030, which will entail retiring 431 MW of coal.
“Our key pillars are to provide energy and services while maintaining reliability, environmental responsibility, and financial sustainability,” said Davis, who helped craft the 2024 IRP, which includes 300 MW of new solar and 460 MW of new wind. “So [the planned-for new renewable capacity] replaces the energy that we would have received from coal, but we also need dispatchable capacity.”
PRPA wants to use that capacity for two primary use cases: meeting load in the early morning and evening hours when solar and wind generation ramp down, and during “dark calm” periods, which Davis characterized as those “without much sun, so it's dark, and without much wind, it's calm.” The dispatchable capacity is planned to come primarily from three sources: aeroderivative technology (i.e. gas turbines; 200 MW), battery storage (187 MW), and the virtual power plant.
Last year, PRPA conducted a study in support of its then-in-progress IRP, that forecasted DER adoption and potential customer enrollment in a VPP program. It found that by 2030, the utility would have 50,000 DERs capable of providing 32 MW of dispatchable capacity.
“The actual interconnected capacity would be much higher,” Davis noted, but that number only reflects resources capable of running for four hours on a peak summer day, and for multiple days in a row. “The reliable capacity that we could count on is 32 megawatts by 2030.”
The VPP strategy also assumes customer EV and storage adoption will reach almost 110 MW by 2043. And it incorporates distribution-scale storage as well, which was the subject of an RFP in late-2021; Davis said the utility is currently evaluating bids, with an eye toward putting one five-megawatt, four-hour battery in each owner community.
In pursuit of a DERMS
The crux of the VPP, though, is the advanced technology that will communicate with, monitor, and control all of the DERs involved.
While most utilities start with single programs — a smart thermostat program or an EV program, for instance — Davis said that way into a VPP is complicated by the fact that each of those programs run on their own system for dispatching resources.
“They operate differently. They're available at different times,” he said. “It's actually really hard.”
That coordination difficulty is precisely what PRPA is trying to avoid in building their VPP, he added: “We need to put into place a system to manage all these DERs across the various aggregators that we have.”
The utility currently has an RFP for an enterprise distributed resource management system for controlling all DERs and DER aggregators, which Davis describes as the “single pane of glass that allows us to collect the data, see how DERs are performing now, do a forecast of how they perform in the future, schedule them, dispatch them, perform to the market requirements, support measurement verification, and so on.”
Currently, PRPA is looking to find a DERMS — a challenge that another Colorado utility, Xcel Energy, is finding to be its biggest hurdle after the governor mandated the IOU to create a VPP program in May.
The enterprise DERMs will also be partitioned to the smaller distribution utilities that collectively own the power authority, systems that Davis calls “tenant DERMs.” The tenant DERMs will allow each distribution utility to access the DERs in their service territory on their own distribution systems.
“That's something that makes Platte River a little bit unique compared to a lot of utilities that are integrated where the system might be under the management of a single utility,” said Davis.
Brought to you by Uplight: Learn how virtual power plants differ from traditional demand response programs and how utilities can unlock grid flexibility.
Brought to you by Uplight: Learn how virtual power plants differ from traditional demand response programs and how utilities can unlock grid flexibility.
Brought to you by Uplight: Learn how virtual power plants differ from traditional demand response programs and how utilities can unlock grid flexibility.
Brought to you by Uplight: Learn how virtual power plants differ from traditional demand response programs and how utilities can unlock grid flexibility.
Beyond the DERMS
While the DERMs is the primary system for controlling resources, other systems are critical to the functioning of the VPP as well. Included in the same DERMS RFP is a request for a data management system to collect data and support analytics and forecasting capabilities.
The DERMs will also need to interact with a market management system to allow PRPA to submit VPP capacity bids into the wholesale market and receive instructions on when to dispatch capacity. One of those systems is an Automatic Generation Controller to send dispatch signals to a power plant, which then responds to the signal indicating it has performed as requested.
And an energy management system is needed for utilities to manage the transmission system. “We'd integrate [an energy management system] to make sure we are aware of how the VPP operates relative to transmission constraints, if any,” Davis said.
There are also customer and grid edge systems — customer information systems, advanced metering infrastructure, and meter data management systems, for instance — that support utilities in collecting customer energy usage data and billing.
“And then we get to Advanced Distribution Management Systems, which really is a new system that the owner communities don't yet have,” said Davis. An ADMS does a variety of things, he added, “but one of the things important to the VPP is to provide an as-operated network model.” An ADMS tracks the current configuration of a distribution system and tells utilities what portions are out of service.
These are among the technologies that the Department of Energy included in an April report on potentially transformative tools for utilities aiming to make better use of the existing grid.
“There [are] probably other systems that may be needed as we get into this further, but these are the ones that we're starting with as being important for the virtual power plant,” said Davis.
PRPA’s next steps for developing the VPP will be evaluating the RFP bids for a new DERMS and data management system, as well as bids for program design and implementation.
“It was one RFP with two scopes and we received our bids in early August,” said Davis. “We're working through those proposals now,” said Davis.
The utility hopes to award one or more contracts by the end of this year.
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