DER Operational and Grid Benefits

by Eugene Shlatz, Navigant Consulting Inc.

Proponents of distributed energy resources (DER) often cite benefits that larger, conventional generating sources typically cannot provide. The number of people who support DER as a viable alternative to traditional generation is growing and impressive. Supporters include regulators, technology advocates, environmentalists and, increasingly, electric utilities and major equipment suppliers. Some tout green benefits and operational advantages of DER as clear evidence that DER is preferable to central generation, particularly fossil sources that create a large carbon footprint.

Figure 1: Upon completion, E.ON Climate and Renewables’ Roscoe (Texas) Wind Farm will be the world’s largest wind farm, spanning 100,000 acres and producing 780 MW.
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Increased attention on nonconventional technologies has spawned a vibrant industry composed of small and large developers, manufacturers and independent owners. Given recent advances in wind and solar technologies (see Figure 1), it appears inevitable that DER will assume an increasingly critical role in meeting the nation’s electricity demand. Notably, DER may be the catalyst to develop and employ grid technology as a preferred solution to meeting carbon-reduction goals.

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This article examines perceived advantages of DER; specifically, whether DER can provide quantifiable grid benefits (T&D economic value). Enabling technologies needed to realize these benefits are presented, highlighting key challenges to achieving goals that may be more daunting than many realize. A case study of DER in a high-cost, high-growth area is presented to highlight potential benefits.

Grid Benefits

Figure 2 highlights the range of benefits DER could provide. It includes deferred generation capacity and energy-delivery savings, grid benefits and reduced emissions. Stakeholder beneficiaries include retail customers (C), electric utilities (U) and society at large (S).

DER benefits accrue not only to utilities, but also to customers who see better reliability and society at large in the form of reduced fossil emissions. Utilities in states that have sold their generating units (and now provide energy-delivery services) no longer are the beneficiaries of deferred generating capacity and reduced energy costs. Here, third-party owners or retail customers are the direct beneficiaries. In these markets, the absence of straightforward mechanisms to purchase and sell the electricity, such as feed-in tariffs commonly applied in Europe, could thwart development of alternative sources.

Can DER Improve Reliability? A commonly cited benefit of distributed generation is enhanced reliability, created by the diversity offered by small, distributed resources. In sufficient quantities, and with the appropriate control and protection systems, DER could serve isolated pockets of load during major outages—that is, as an independent microgrid. Reliability benefits might better be described, however, as enhanced capacity, as firm DER essentially displaces central generation.

Distribution system reliability benefits are surprising low, as most outages are caused by storms, equipment failure or fallen trees—DER offers little, if any, capability to reduce the type of failures that cause outages. The primary distribution reliability benefit—outside of capacity deferral—is reduced restoration time, accomplished by using DER to expedite load transfer and minimize time and steps needed for load transfer. Case study results confirm reliability benefits are nominal, at best.

Figure 3: Typical distribution load profiles suggest that DER needs to operate or be available only for a relatively small number of hours—usually less than 15 percent of the year—to reduce peak load by up to 20 or 30 percent. Beyond 15 percent of total hours, the load curve flattens and additional capacity deferral opportunities are limited.
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Although reliability benefits are limited, inverter-based distributed generation (DG) can improve power quality and voltage stability by using the inverter to produce or absorb reactive power. Current practices, however, will need to change to enable inverters to operate over a range of power factors. Further, smart grid technologies need to be employed as utilities likely would monitor and control these devices.

Figure 4: The time of day of the feeder peak often varies dramatically. For this system, the feeder peak occurs when photovoltaic output is low.
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How Firm Are DER Capacity Benefits? Typical distribution load profiles suggest that DER needs to operate or be available only for a relatively small number of hours—usually less than 15 percent of the year—to reduce peak load by up to 20 or 30 percent (see Figure 3). Beyond 15 percent of total hours, the load curve flattens and additional capacity deferral opportunities are limited.

The notion that DER can displace traditional central generation—assuming equivalent availability—relies on meeting several important criteria. No doubt, smaller distribution resources can reduce system reserve margins, but only if the capacity is firm.

Many DER technologies do not provide firm capacity equal to conventional technologies, and adjustments are needed to avoid overstating value. The level of firm capacity assigned to DER must recognize:

  • Renewable technologies such as photovoltaic and wind typically have low capacity and coincidence factors; the latter often less than 10 percent for systems with late-day peaks (see Figure 4), and
  • Customer-owned generation—no matter how reliable—cannot be deemed to have the same availability as generation that the grid operator monitors and controls.

To address the uncertainty associated with customer DG ownership, some utilities have offered incentives for customers willing to provide physical assurance—defined as allowing the utility to interrupt customer load if the DG unit is unavailable when called upon—usually during peak or contingency conditions. Physical assurance, when tried, has seen minimal acceptance, as few customers appear willing to unilaterally allow utilities to interrupt load. Energy storage also is expected to improve firm capacity for renewable energy (RE) technologies, particularly if costs for both RE and storage continue to decline.

Can DER Support the Energy-Delivery Grid? If DER can defer distribution capacity, it would produce benefits beyond those typically associated with larger, central generation—benefits not available for resources interconnecting with the higher-voltage transmission network. Several pitfalls are encountered, however, when DER is used to displace distribution line or substation capacity:

  • DER may not be available following a reclosing of the substation circuit breaker. The Institute of Electrical and Electronics Engineers Inc. (IEEE) guidelines and utility-interconnection standards require a minimum five-minute interval before DG restart to avoid operating during reclosing intervals and attendant equipment damage. This potentially precludes relying on DER for firm feeder capacity, as line and equipment overloads could occur if a reclosing circuit breaker were to operate and trip DER off-line during peak-load periods.
  • Enabling technologies—i.e., smart grid—are essential to monitor, operate and control distributed devices to derive most benefits at the distribution level.
  • Renewable technologies may have low coincidence with feeder peaks, which invariably limit grid capacity benefits.

Case Study Results

A case study of DER installations was performed for a high-growth, several-hundred-MW planning area—the location was selected to maximize potential grid benefits. Case study DER technologies include:

  • Photovoltaic DG
  • Synchronous and induction DG
  • Energy storage
  • Demand response (DR)

Results of the case study demonstrate that displaced central generation capacity and energy dominate the amount of benefits provided by DER (see Figure 5). Targeting DER additions to areas that have T&D constraints (and where maximum output aligns with the feeder peak), however, can produce significant local benefits. Some urban utilities where grid capacity is expensive have used DER to defer new substations and feeders at significant savings.

Figure 5: Case study results demonstrate that displaced central generation capacity and energy dominate the amount of benefits provided by DER.
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Not surprisingly, benefits often are long-term. Figure 6 illustrates that positive net present value is achieved only when long-term benefits are considered. This increases the risk that the economic value of some DER technologies may not be sustainable, particularly those purchased by retail customers who may experience business closures, technology fatigue or costly equipment failure.

Figure 6: Positive net present value is achieved only when long-term benefits are considered.
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What Changes Are Needed? Proponents insist that fundamental changes are needed to foster a robust market for DER. Some suggest customers should effectively partner with utilities to help supply growing electrical demand. Such partnerships presumably would encourage a mix of conventional and nonconventional power resources at lowest cost and with the least environmental impact.

Beyond meeting technology challenges, fundamental changes in rules and regulations are needed to maximize the benefits DER potentially can provide. To eliminate or mitigate these barriers, market participants, regulators and policymakers should strive to:

  • Establish flexible rate and revenue-recovery mechanisms for DER grid benefits defined, particularly for difficult-to-quantify benefits such as power quality,
  • Promote changes in interconnection policies (such as IEEE 1547) to enable advanced inverter technology applications (such as operation over a range of power factors),
  • Offer alternative pricing—both wholesale and retail—that capture values unavailable in existing tariffs. These include:

  1. Rules that allow for provision of ancillary services by non-ISO participants,
  2. Markets for energy-delivery system benefits for demonstrable firm DER, including mechanisms to promote customer-utility partnerships, i.e., shared risk and benefits,
  3. Performance-based rates that encourage customers to use DER to improve reliability, power quality or both,

  • Extend or offer new state and federal rebates and investment tax benefits (ITC) for integrated renewable systems, and
  • Enable retail customers to earn emission-offset credits—that is, at the interstate level, regional level or both.


If technological, regulatory and institutional barriers and challenges are addressed to the satisfaction of all stakeholders, DER can be an important resource to the utility grid. Findings from recent case studies demonstrate that:

  • Under most conditions, the primary DER benefits are deferred central generation capacity and energy displacement,
  • DER, however, is more competitive with traditional system investments when operational and grid benefits are considered,
  • Enabling technologies are essential to achieve and maximize gird benefits,
  • Integration of energy storage and intermittent RE systems provide an opportunity to enhance the value of renewable generation,
  • New regulatory models and market mechanisms are needed to ensure DER owners are fully compensated—but not overcompensated—for benefits they provide, and
  • There needs to be a reasonable sharing of risks and benefits among stakeholders.


Eugene Shlatz is director of Navigant Consulting Inc. E-mail him at

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