What locational value do DERs provide to the grid?

By Josh Bode

The electricity industry is abuzz with the question of how to integrate and value distributed energy resources (DERs). We used to have separate dialogues about solar, demand response, batteries, distributed generation, electric vehicles, microgrids and energy efficiency. Today the term distributed energy resource captures all small, geographically disseminate resources that directly connect to the distribution grid. These resources are expected to grow and, according to many, fundamentally change how the electric grid is planned and operated.

At the core of the discussion regarding DERs is a debate about the value these resources provide to the grid; notably, how do we monetize the locational value? Are DERs increasing the cost of distribution grids? Are these resources delivering grid value without corresponding payments? Are they being cross-subsidized by other ratepayers? Will DERs be allowed to compete side-by-side with large-scale generators and traditional distribution grid equipment?

Distributed but not limited to distribution

One of the most unique attributes of DERs is that they affect all aspects of the electric grid’s infrastructure including the need for bulk transmission and generators. While a significant amount of DER value is tied to energy production, an equally significant impact is tied to power infrastructure. Many DERs produce energy, and all of them eliminate the need to transmit power across long distances and thereby avoid line losses. Both generation and distribution infrastructure are sized to meet the aggregate energy demand of customers when it is at its highest --- peak demand. The key difference is that generation and transmission infrastructure is sized to cover broad areas while distribution infrastructure is sized based on a local distribution area’s coincident demand, which can be quite diverse. If distributed resources deliver when the system peaks, they can help avoid having to build peaking generators that mostly sit idle throughout the year. If DERs deliver when the distribution grid is strained --- often based on local, coincident peaks --- they may help avoid or defer growth-related distribution and transmission investments. 

The discussion around valuation of DERs is taking place in three strands: grid modernization, the value of solar, and the development of new competitive procurement models that integrate distributed resources.

Grid modernization

There is an active discussion regarding how to modernize distribution grids in preparation for deeper penetration of solar, electric vehicles, batteries and loads that automatically respond to market prices. This debate is largely taking place among distribution planners and operators. It is fundamentally about designing a distribution system that can accommodate two-way power flows. 

The value of solar

There is also a wide-ranging policy debate taking place on a state-by-state level, focused on the value of solar. In preparing for a workshop we hosted on How to Align Distributed Energy Resources with Grid Value, we put together a graphic (see map below) showing the level of solar value discussion activity. With two federal bills being introduced in the past few months, we’ve now officially moved from local, state-by-state efforts to a nationwide push.

The push to integrate DERs into planning, operations and markets

The third discussion is about creating side-by-side competition between DERs and traditional utility and bulk power system investments. The New York REV (Reforming the Energy Vision) and California’s DRP (Distribution Resource Plan) are leading state efforts to drive policy to facilitate large amounts of DER coming on to the grid. The policy debate includes the breadth of DERs. In both of these states, efforts to integrate DERs are well underway. In California, they started with SCE’s procurement of over 600 MWs of distributed resources --- including batteries, energy efficiency, demand response, solar and thermal storage --- and have culminated in a proceeding regarding how to integrate DERs into distribution planning. In New York, the debate was triggered in part by projections of over $30 billion of distribution upgrades over the next decade. In both these states, demonstration projects regarding the ability to manage distribution grids by using DERs instead of distribution upgrades are already underway or will begin soon.

The central question here is: What should the competitive process or market look like? Are distribution-level markets needed? Are real time markets or forward markets necessary to ensure long term reliability? Or, are there less complex competitive processes that can be implemented to meet the goal of integrating and valuing DERs? 

Assessing the locational value of DERs to achieve both competitive markets and grid reliability

In all of these discussions, the question of locational value arises. Properly valuing DERs is not as simple as enumerating the benefits and cost categories, however. Four key concepts need to be incorporated into valuation frameworks.

The main locational value is the ability to defer or avoid distribution equipment costs driven by growth in peak demand. The product is not energy per se but rather the ability to ensure local demand does not exceed the distribution equipment capability. When demand exceeds local distribution capacity, equipment is overloaded, it degrades more quickly, and the risk of the grid collapsing grows exponentially. Not all distribution investments are driven by peak demand, however, and many local areas will have plenty of hedge room to operate. 

Local coincident peak demand patterns determine when, how, how much, and what type of DERs are needed. The figure below illustrates how important it is for DER characteristics to align with peaking risk. It shows various types of DERs that either follow a specific production pattern or are based on loads which vary by hour (note: it does not include resources that are not time dependent). Those load shapes were normalized (as the percent of the annual peak) so they can be directly compared and juxtaposed against the local peaking risk (the area graph). Some resources --- commercial and residential air conditioner loads --- align well with the local peaking risk. Other resources --- residential lighting, solar --- do not align as well. The concentration of local peaking risk and the alignment with specific DERs will vary for local areas. We need the right mix of resources at the right location. 

The specific operational characteristics of different DERs influence their value at each location. DERs are not a single type of resource that can be easily defined. It includes a wide range of technologies with diverse operating characteristics. For each resource type there is a battery of questions that can affect value. Is the DER flexible? Does it follow a specific production (or reduction) pattern? Does it have limits on how quickly it can start, how long it can produce or how often it can operate? Does it need to recharge? How well do production patterns coincide with local coincident peaks (which drive incremental distribution costs)? How well do they coincide with system peaks (with drive the need for new generators)? To provide value, the specific production (or reduction) characteristics of distributed resource must align with the local peaking pattern.

The whole is more important than the parts. Many DERs deliver incomplete solutions for local distribution capacity relief needs when deployed individually but have characteristics that can provide complementary value when deployed as a combined solution. In the right combination, DERs deliver more value as a whole solution than as stand-alone components. Because of this, distribution capacity relief using DERs is not a simple commodity but a complex problem that may require optimizing the portfolio procured based on cost, DER attributes and local peaking patterns. The diversity of DERs and local needs are the main challenges for integrating these resources. This same diversity is also DERs key strength. When bundled together in the right combination, DERs deliver more value than as stand-alone components. The overall value of each individual part depends on the other DERs available for bundling. To use an analogy, if one is building a single car, one needs the right type and quantity of parts that can be combined into a whole car. A car without wheels is not useful, nor is having two engines. Ideally, there are multiple sellers able to produce the different components and they compete with each other, transparently, in pricing the parts. In the same way, with DERs, there are multiple ways to bundle a solution. The best bundle is not always made up of the cheapest parts but rather the best overall bundle with which the electric distribution grid can be operated reliably.

Grid optimization for DER is possible today

From a planning standpoint, the best bundle is inherently an optimization problem. The right data analysis of substation or feeder level data can generate actual insights about where and when different types of DER provide locational value and perform these optimizations. Utilities with AMI data are better poised because it is possible to analyze DER potential and value down at a micro-level.

Even with limited or no AMI data, we’ve has been able to use big data analytics to accurately reveal the behavior of grid assets and distributed resources, producing valuation frameworks that account for these four important considerations:

• Ability to ensure that local demand does not exceed the distribution equipment capability
• Actual mix of resources at a specified location
• Specific production or reduction characteristics of each DER matched with the local peaking patterns
• Various scenarios for distribution capacity relief with dynamic inputs for cost, DER attributes and local peaking patterns

While integration and valuation of DERs may seem difficult, once defined properly, the challenge can be solved. 

Josh Bode is principal consultant at Nexant.