By Jeremy Klingel and Stuart McCafferty
Imagine customers, third parties and perhaps even utilities participating in a market in which their investments in renewable energy and other forms of DERs could be monetized. The uptake of clean energy would dramatically accelerate, creating new opportunities for innovation and an open, inclusive energy economy.
It’s the next evolutionary step to profoundly transform the energy industry into something where everyone can win and it’s happening now.
When asked if their utility anticipates the introduction of distribution markets for DERs, nearly four of every 10 respondents — 37 percent — to Black & Veatch’s 2019 Strategic Directions: Electric Report survey replied affirmatively. An additional 47 percent answered that they weren’t sure. Most likely, those in the “yes” camp come from areas where there is more DER penetration.
Today, we’re at a pivotal point. DERs exist in all markets and certainly will grow, meaning that some who replied “don’t know” to this year’s survey may say “yes” in a year or three. Those who don’t know also may be leaning toward “yes” today, but, in truth, no one yet knows how distribution markets will play out in places where they’re already being supported by regulators, such as New York and California. Until markets gel in those testing grounds, regulators in other parts of the country eagerly will watch and learn before forming their own opinions for distribution market models.
Why are markets emerging? Some 40 percent of survey respondents said the primary driver for distribution markets was that they’d serve as a “strategy for accelerating the transition to a more distributed grid model.” More than half — 55 percent — of survey respondents believed that DERs will dominate utility service offerings in the next 15 years.
What will those offerings be? They could well be the services of a market operator or, if a third-party operates the market, utilities could bid their resources into that market the same way they provide ancillary services for an independent system operator.
The market landscape has changed in such a way that the evolution of a distribution market seems natural and logical. After all, solar installations continue to expand. A recent U.S. Solar Market Insight Report from Wood Mackenzie and the Solar Energy Industries Association (SEIA) forecasts 25 percent growth in 2019 compared to 2018 and expects more than 13 GW of installations this year.
The lion’s share of that is coming from utilities. Sixty-one percent of the solar installed in this year’s first quarter was done by utilities. During that same period, the residential market saw 603 MW of residential solar installations, which represents a 6 percent increase. C&I deployments were down, but the report authors believe new community solar mandates in New York, Maryland, Illinois and New Jersey will help reinvigorate that segment starting in 2020.
Analysts at Reportlinker see an 18-percent compound annual growth rate for energy storage systems between now and 2023, and they believe the need for backup power will be a major driver.
Another development: We now have EVs finally starting to come online to a scale that makes them a potential dispatchable grid asset, particularly if you’re looking at a fleet perspective and thinking of tapping the light- to mid-duty vehicles used by players such as FedEx or a local Walmart delivery driver. They’ll use a lot of power and have significant demand response capacity.
Right now, EVs make up only about 1 percent of fleet vehicles, but Navigant Research expects the penetration to reach 12 percent by 2030.
In short, DERs are here to stay, and customers want to monetize their investments in them. As it turns out, there are plenty of aggregators to help them do it, as well as other third-party players who want to do things like invest in grid-scale solar or batteries and monetize those investments, too.
The generation mix is dramatically changing, and, as noted earlier, those who invest in energy resources want to optimize their investment returns. On the consumer side, California’s Demand Response Auction Mechanism (DRAM) helped residential consumers participate in a utility-based demand response program to support the reliability of the California Independent System Operator. Earlier this year, the California Public Utilities Commission (CPUC) issued its final report on the DRAM pilots. More than 52,000 customers were enrolled in DRAM in the 2017 delivery year, with 98 percent of them being residential customers, CPUC’s report noted.
For many California customers installing rooftop or on-site solar PV systems, payback occurs in about two years because of the high costs of electricity. Introducing distribution markets in other parts of the country could bring returns on investments that are typically in the seven-to-10-year range down to something similar to those being experienced in California.
On the utility side, market creation allows today’s power providers to earn against orchestration of all the energy resources connected to the grid and also to continue maintaining grid safety and reliability. Forty-four percent of survey respondents named aging infrastructure as one of the most challenging issues facing the electric industry today.
The way things work now, when utilities are faced with an infrastructure that needs upgrades or replacement, they spend money, then have regulators approve rates that allow for the utility investments plus a little for shareholders. The problem is that with today’s common rate-recovery approach, the infrastructure can only be replaced when there is an appropriate load growth curve to go against the costs. When customers put solar and storage on their household roofs or at business facility sites, it chips away at the way utilities traditionally monetize their technology and infrastructure investments.
A market play allows the utility to manage grid stability and reliability and might even generate revenue through a transaction-fee or fixed monthly fee model such in the as telecom and cable industries. Meanwhile, this approach adds plenty of other benefits for utilities and consumers alike.
Orchestrating DERs will give utilities a way to leverage non-wires alternatives to manage constrained circuits and substations on their systems. Using a distribution market approach, DER assets will compete and can be bid into the market, ultimately lowering the costs for electricity customers. DER asset bids will be valued compared to other market bids, and, as markets should, the distribution market operator will call on the least-cost resource at the time.
Distribution markets also could add a new layer of resilience to the system. Recently, one utility in south Texas estimated that there were more than 250,000 unregistered backup generation devices that neither the utility nor its independent system operator knew about. Consider how much value those resources could provide in the event of another superstorm. If the utility or system operator gains control over assets that can support reliability, customers with backup resources get to participate in markets, thereby gaining faster return on investment from their energy investments, while more people would be able to weather the storm with the lights on.
Unanswered Questions Linger
As for society as a whole, the market approach will allow us to bring more renewables online. There will be a greater incentive for customers to add renewable assets, and it will be easier for utilities to connect these assets to the grid without reliability or power quality impacts.
Given the benefits, why haven’t regulators outside of frontrunner states like California and New York started pushing utilities toward such a model? Because there still are too many unanswered questions.
For one thing, regulators need to see how distribution markets will provide value to a variety of interested parties, including customers and environmentalists as well as distribution operations and the utility. Second, marrying grid operations with distribution market operations requires organizational and technological changes that are continuing to mature. Third, regulators need to understand how the market could energize or balance the system with least-cost resources. Fourth, utilities and regulators alike must start talking about how markets will operate. How do we hone in on what we're going to do, and how do we tie that directly to the customer enablement?
Finally, this cannot be proprietary. There must be an overarching sense of interoperability with the adoption of Internet of Things DER messaging standards such as OpenFMB and the Institute of Electrical and Electronics Engineers 2030.5. That’s true from a technology standpoint, so that the maximum number of players can participate, as well as from a transparency point of view. In other words, customers will need to understand what it is they're signing up for.
Regulators and utilities will need to work together to answer these questions. Utilities also will need to leverage all their internal wisdom. This won’t be a problem that the utility is going to be able to solve with one portion of the business. The distribution operations staff will need to team up with system planning teams, generation, transmission operations, customer service and more to figure out what needs to happen and what regulators — who will empower the changes — need to know.
Still, in the end, this will be more of an evolution to the business of electricity than an end to it. We’ll be taking the economic value of power generation and storage — something everybody understands today — and broadening the aperture to make sure we're capturing not just those utility-owned assets but also everything available on the network. A market approach is a way to do that. This is the way to bring more into the fold and look at a more comprehensive picture of power provision today.
Jeremy Klingel is the global distributed energy business line leader for Black & Veatch’s power business. Klingel has more than 23 years of experience, including the past four years with Black & Veatch’s management consulting business. He has led more than two dozen smart grid development projects and has driven the operational roadmap behind advanced distribution management and end-user experience.
Stuart McCafferty is a managing director for the growth and performance offerings in Black & Veatch management consulting. McCafferty is a National Institute of Standards and Technology fellow for community resilience, an industry expert for Energy Central and vice chair for OpenFMB User’s Group. He previously served as vice president of EnergyIoT at Hitachi and was vice president of operations for the Smart Grid Interoperability Panel.