Virtual power plants (VPPs), distributed energy resources (DERs), and demand response (DR) schemes are intriguing topics and “Charging Ahead” has regularly featured them, but rarely together. Today, however, everything is changing and it’s being driven by the behind-the-meter (BTM) segment that’s become a jam-packed source of electricity. BTM customers are generating, storing, and managing their power resources as never before. The experts are talking about unified flexibility platforms, sophisticated distribution energy resource management systems (DERMS), and innovative demand response management systems (DRMS). Specialists suggest these and other developments have enhanced VPP applications to the extent that energy-as-a-service is a key element for meeting growing power demand, but that’s not happening. 

To pull it off, VPPs need to be speedily interconnected to the power grid, but that’s proving challenging as acceptance of VPPs is encountering strong headwinds. DOE’s (Department of Energy) latest revision of its VPP Liftoff Report states that “VPPs are at an inflection point due to market and technical factors.” DOE’s narrative said, “Despite their benefits for American consumers and for advancing the nation’s climate goals, VPPs are often undervalued by grid operators and have yet to scale.” DOE continued saying, “Although the innovations across the VPP industry have been valuable, the complexity and fragmentation around how VPPs are implemented has inhibited the growth of VPPs to date.”

Systemic Bottlenecks

Other studies support the DOE’s findings and they’re examinations are finding it’s not only the physical component, but there are administrative delays as well. Their findings identify key elements that are counterproductive when it comes to employing VPPs on today’s power grid. At the top of the list is the dilemma of integrating thousands of DERs from a variety of suppliers without the benefit of interoperability and open standards. Running a close second is disjointed electricity policies across jurisdictions such as the “slow, uneven compliance” to FERC Order No. 2222.

Oddly enough, there are legislative efforts to stall VPPs in some states while others have regulatory policies that are not in compliance with Order 2222. According to FERC, “compliance and rollout timelines vary significantly by grid operator.” In simple terms, there’s a disconnect between wholesale market rules and retail distribution utility policies. Additionally, VPPs face structural barriers to market participation and can be shut out of capacity markets or face minimum-bid size requirements. In addition, utility models often fall short when measuring all the ways VPPs support the power grid.

Plus, DOE suggested that legacy utility rules and lack of formalized market participation structures are preventing VPPs from being fully compensated for grid services. With the grid-edge digital ecosystem expanding, the technology has undergone considerable evolution moving from small pilot projects to utility-scale applications, but there are concerns about that growth. Market researchers are disturbed that VPP marketplace has broadened rather than deepening. In plan terms, there are a lot of VPPs on the power grid, but their “capacity growth remains modest.” With that in mind, it’s time to talk with an expert on VPPs’ broad and general issues.

Technological Assessment 

“Charging Ahead” contacted a colleague, Shikhar Pandey, who is a member of the Institute of Electrical and Electronics Engineers and its Power & Energy Society (PES). Pandey is the current secretary of PES’s Industry Technical Support Leadership Committee (ITSLC). He is also the Managing Partner of Grid CoGroup. The ITSLC Task Force on Grid Flexibility recently published technical report, “PES-TR139 - Virtual Power Plants: A Critical Assessment of Their Role in the Energy Security.” Pandey was the co-chairman of that task force and has offered to provide some unique insights on VPPs and the work of the task force.

Pandey began the discussion saying, “VPP performance has been evolving since its beginning, but research conducted during the mid-2000s improved its practical operation. The speed of this digital environmental evolution will be increasing once FERC Order 2222 is completely implemented. VPPs possessed the ability to act like power plants by grouping DERs together to inject active power into the grid. They can also be dispatched similarly as traditional electric generators in some respects. That allows them to economically deliver grid services that provide grid stability, that DR can’t explicitly do.”

Pandey continued, “Usually, DR is included with VPPs, but the taskforce found that VPPs should only include current injection technologies and there needs to be a clearer distinction between VPPs and DR programs. Typically, VPPs make money through active market bidding, perform broader services including local grid services, and faster dispatch than DR applications. DR can only reduce load in response to market signals or pre-scheduled dispatches and that’s an important difference. As loads build, the DR’s limitations become clearer. Curtailing a load reduces consumption in that segment for a defined time. The curtailment is either shifted, or the grid operator has to procure power from another resource. DR only address the symptom of too much load. They don’t solve the problem of adding more electrical power. That’s where the VPP proves economic value.”

Pandey explained, “An application made up of only controllable loads is a DR aggregation, which as we said only moves the problem around the grid. The modern power grid requires VPP’s as a supply-side resource that provides watts where they are needed to keep the supply and load in balance. And most importantly, the grid needs the VPP’s ability to provide essential grid support functions like voltage and frequency support which maintain grid reliability and prevent blackouts. Of course, there are VPPs with DR features, but that’s another subject and our focus is on the quintessential VPP.”

Pandey said, “The rise of VPPs are undeniable, fueled by an urgent need to prevent imminent capacity shortages. The task force found there are two fundamental economic challenges stimulating VPP deployment. The “Fire-Fighter” reality is the dominant economic model for VPP applications, and it’s based on scarcity and emergency. VPPs are utilized during brief high-impact dispatches during volatile marker events rather than a steady market participation.”

Pandey added,” The second model is the “Grid Bottleneck.” Essentially, it amounts to the fact that the most advanced VPP is limited by the grid infrastructure it’s connected to. A legacy grid lacking smart meters and real-time controls prevents VPPs from being regarded as a reliable, system-wide asset. Their abilities can’t overcome the limitations of the existing grid’s constraints that limits their proliferation or usability and that impacts the technology’s true potential. VPPs are one of the fastest, emissions-free answer to the capacity gap caused by the industry’s transition to clean energy. They are an agile near-term solution for upgrading our distribution grid from passive systems to smart, dynamic networks needed for a decentralization clean energy power grid. They are not a permanent replacement of the grid buildout but can provide extra time to build the grid right in an affordable way.”

Shaping the Future 

In April, the Minnesota Public Utilities Commission approved Xcel Energy's plan to build and operate its own VPP, and it’s been generating a great deal of interest. Summarizing all the news releases, this is the first utility-owned and operated of its kind to be approved. According to Xcel, their Capacity*Connect program will install up to 200 megawatts of small-scale batteries in 1-to-3-megawatt steps. They will be located across Xcel’s Minnesota territory. The goal is to manage demand without adding expensive new infrastructure. Xcel is also working toward establishing a metric to measure the value that DERs bring to the grid. Xcel is looking to create a template that will removed this major hurdle for broad adoption of VPPs.

All things considered, it’s a volatile period for VPPs. Technologically, AI is optimizing grid-response application and enhancing energy management platforms and improving interconnected energy systems, but AI is controversial. And that’s not the only controversial factor when it comes to VPPs. It’s estimated that only about 20% of distributed energy capacity is enrolled in VPP programs, which has been referred to as the capacity gap. One analyst indicated that about 217 gigawatts of DER capacity would be added to the power grid between 2024 and 2028.

If only 20% is used, that equates to about 80% of the DER capacity not being available to utilities and grid operators. That’s an outrageous amount to miss out on because customers-owners find enrollment too complicated or not user friendly, and aggregators find outdated regulatory frameworks and policy barriers, but it’s changing. Strategists in 35 states have been busy moving advanced VPP and DER aggregation policies and regulations forward.

The National Energy Assistance Directors Association estimates we will see the average cost of electricity go up 10.5% this summer over last summer. Exactly how high the cost will go depends on where the customer lives and whether their electricity is generated by unaffordable coal-fired generation or cost-effective renewables. With VPPs and dispatchable DER aggregations becoming available across the country, it’s going to be interesting watching these trending technologies playout!