Independent system operators such as CAISO and PJM have empowered aggregators of distributed energy resources to sell services into the transmission grid through market mechanisms. But since the flow of electrons between distributed energy resources (DERs) and the transmission grid is mediated by distribution utilities, simply opening the door for DERs to join the party only goes so far -- we still must identify and overcome challenges impeding progress at the interface between meters and transmission towers.

ISO efforts stem from a recognition of the potential for distributed resources (including energy efficiency, rooftop PV, distributed storage and fuel cells, and responsive loads like electric vehicles or automated demand response) to provide a wide range of services to bulk systems such as peaking capacity, ramping, voltage support, and improved system efficiency.  The extensive range of cheap and flexible distributed resources available to provide grid benefits means we must examine the distribution system’s role in enabling them to support the transmission grid through three different lenses:

  • A physical lens acknowledging constraints of reliably managing the grid, taking into account the physical properties and locations of distributed resources.
  • An economic lens considering economic realities driving utility decisions and distributed energy vendor behavior.
  • An information and control lens allowing proper physical system management, along with value discovery and validation for utilities and DER providers.

The physical lens

Distribution utilities must overcome considerable physical challenges to enable the participation of distributed resources in the transmission grid, as transmission grid needs and constraints are not always aligned with those of distribution grid.  For example, if an aggregated demand response resource lowers electricity demand by an agreed amount in a given location, the transmission grid doesn’t care which underlying devices reduce consumption. 

On distribution circuits, though, if a whole block of houses on one single feeder suddenly stops drawing current from their water heaters simultaneously, the current change can create nasty voltage spikes for neighbors or even destabilize that circuit. In response, the distribution utility may need to reinforce the circuit or require demand-response participants to stagger responses to the transmission grid’s signal.

Similarly, when commuters come home from work and start flicking on lights and appliances, the transmission grid operator could either increase output from centralized power plants or call on distributed energy resources, depending on which is cheaper. But the distribution utility must know whether the power is in the right place on the distribution system to serve the homes with increased demand. Depending on the location, distributed resources may make it easier for the utility to manage local variations in demand, or they might cause a problem for an ill-equipped substation.

Modeling physical consequences of distributed resource participation is thus much more complicated for distribution utilities, especially when grids are managed in different jurisdictions that may not be effectively coordinated. Wider participation to solve transmission grid issues requires new interconnection rules so utilities have access to necessary information about where distributed resources are installed and how they will most likely behave. 

The economic lens

Assuming compensation accommodates physical realities, considering distributed resources through the economic lens means they should respond to economic signals from the transmission grid while maximizing their distribution grid benefits. Rates should reflect wholesale market value and avoided-cost impacts of distributed resource participation on both distribution and transmission plans, as well as high-level integrated resource plans including deferred investment in substations, new power plants, or transmission lines. 

Customers and project developers also need clear, stable and predictable rates to provide transparency on investment recovery. The rate structure also must mesh with regulatory incentives to align distribution utilities’ financial interests with efficient use of distributed resources. 

Paying utilities based on their ability to achieve outcomes that maximize customer value instead of allowing a fixed return on capital invested can optimize economic signals. Performance-based regulation offers an excellent approach by linking utility shareholder value to outcomes like environmental performance, reliability, affordability, convenience and customer choice. 

Alternatively, regulators may take an interim step by providing distribution utilities an extra rate of return on payments to a third party for services obviating capital investments, as in the Brooklyn-Queens Demand Management Program. Utilities could be allowed to make money not only on services from distributed resources that act as an alternative for distribution capital investments, but also on those that facilitate the connection between those resources and the transmission grid. This approach is sometimes referred to as “infrastructure-as-a-service,” as detailed in a recent white paper from SolarCity, and it also serves as a central value proposition for some DER providers, such as with the concept of the “Energy Cloud."

Listen to a recent episode of the Interchange detailing how infrastructure-as-a-service would work:

The information and control lens

New rules, rates and economic incentives must also be viewed through an information and control lens. Market participants including distributed resource aggregators need accurate data from utilities about where newly installed systems might provide the most value (see California’s Distributed Resource Plans), while utilities need a framework for dispatching distributed resources and verifying performance against contracts or rates. To collect reliable data, the utility must rely on its own smart devices in combination with data collected from third parties. 

In order to operate and balance the distribution grid safely and reliably, utilities want enough control over assets to effectively manage reliability. Historically, this meant knowing exactly where resources were located and how they reacted to control signals or grid conditions. As a result, utilities may prefer to connect new equipment directly to their control systems and install revenue-grade meters at each point, which could require costly new infrastructure investments.

But instead of building up their own separate and expensive custom information-gathering and control network, utilities could use existing telecom assets like cell phone towers or the internet to more efficiently collect real-time data on actual grid conditions and distributed resource performance. Before risking over-investment, utilities and regulators should explore whether a “trust-but-verify” approach relying on third-party data would be more cost-effective than utility-led investment in sensors and telemetry. 

With aggregated distributed resources, performance on obligations to the transmission grid will tend to have a statistical, probabilistic nature. A fleet of EVs, for example, might provide service to the grid by collectively managing charging, but that doesn’t mean every EV must or will participate on a given day or in a given location. A paradigm centered on fixed distribution assets and meters is insufficient to take advantage of this dynamic fleet. 

The trust-but-verify approach can create higher value at lower cost when a third-party aggregator uses its own communication network to control charging or dispatch in real time, identify exactly which resources are responding, adjust for signals from the transmission grid and conditions on the distribution grid, and relay back the necessary information.

We’re in the very early days of distributed resource participation in grid management, but these factors suggest four considerations for regulators and the stakeholders advising them:

  1. Create economic incentives or rate structures so distributed resources don’t respond to transmission needs without considering the physical needs of the distribution system. For example, take advantage of approaches that stagger dispatching to avoid voltage spikes.
  2. Recognize physical constraints and the need to upgrade certain aspects of the distribution system, but don’t let this become an excuse for foot-dragging and gold-plating. Don’t let the solution define the need; instead, identify physical grid needs through processes like integrated distribution system planning, and then fulfill these needs through a competitive, unbiased procurement process.
  3. Align financial incentives so utilities support economic solutions while capturing some upside even if they don’t own the equipment. This might first mean revenue-sharing or infrastructure-as-a-service, but over time, regulators will need to better define future utility roles and encourage them by creating an incentive framework like performance-based regulation.
  4. Enable utilities and third parties to leverage existing telecom networks for command-and-control, as well as financial settlements using a trust-but-verify approach. 

Today’s distribution system resembles an information desert governed by occasional transformer tap adjustments and monthly meter-reads, but with these changes, it could become a rich ecosystem providing improved distribution system performance, wiser and more efficient use of assets, and more value for customers and market participants.


Eric Gimon represents America's Power Plan.

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