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Editor's note: This is the first installment in a three-part series. Part II, on energy storage, will be published June 19.

Three main drivers move the needle on distributed generation (DG) implementations: policy, power reliability and the business case, roughly in that order. Let's examine these drivers in light of a recent survey of smart grid executives sponsored by IEEE Smart Grid and conducted by market research firm Zpryme, because those executives' expectations for market growth are undoubtedly motivated by the same drivers.

As shown in the figure below, the three benefits of distributed generation most valued by smart grid executives include adding power where needed, reducing infrastructure costs and improving power reliability.


The top sources of DG that respondents expect to see accomplish these outcomes are solar photovoltaics (PV) and wind power.


The aforementioned benefits of DG are very attractive, but will solar and wind power really deliver these results? A closer examination of DG may determine whether smart grid executives’ expectations line up with relevant drivers and constraints.

What is DG?

First, let’s define “distributed generation,” or DG. Most of us use the term to refer to generation resources on the distribution system. The relevant utility may or may not have immediate control over the resource, other than requiring it to go offline when grid power is down.

DG tends to take the form of solar PV panels on customers’ rooftops and diesel generators at facilities where uninterruptible power is needed. Wind power is most common at utility scale, and because it is typically tied into the transmission system, it isn’t considered DG. Currently, most DG consists of backup, internal combustion generators running diesel or natural gas fuel. Thus, DG and renewable energy, or RE, are not synonymous, but there is overlap.

DG on the distribution system can contribute to system capacity when it is dispatchable and reasonably available. Utility-owned DG can supplement capacity at peak periods for feeders and substations where load growth has exceeded installed power delivery capacity, but is not sufficient to justify the next increment of power delivery asset expansion - e.g., an additional substation power transformer. Therefore, utilities may see DG as a contributor to “deferral opportunities,” where the cost of adding capacity is greater than the cost of coordinating DG to lower system loads. 

At industrial sites, combined heat and power (CHP) configurations often make a reliable contribution to capacity. At commercial and institutional sites, the contribution to capacity is not as clear-cut, because it relies on the statistical probability that the CHP is generating at the time of peak electrical demand. In some instances, that correlation is good and results in a contribution to system capacity; in other cases, the correlation is poor and the capacity contribution is limited.

Drivers of DG for customers

Policy is a strong driver, particularly in Europe, where policies encouraging distributed renewable energy have been adopted since the early 1990s. The homogeneity of policy under the European Union has accentuated the policy driver.

In contrast, in the U.S., policy regarding the distribution system falls under the purview of each of the 50 states’ public utility commissions. Utility-based incentives for customers to adopt DG in the form of solar PV vary widely and are anything but uniform. The adoption of internal combustion generators for uninterrupted power is largely based on the individual customer’s business case for power reliability.

The strongest case for power reliability in the form of DG typically comes when “energy surety” is mission-critical. Thus, we see military bases adopting DG, as well as energy storage and microgrids, because the ability to maintain our defenses needs to be decoupled from the widely dispersed  - and, therefore, vulnerable – grid, and the decoupling from both the vulnerable grid and the ordinary sources of fuel supply might be needed for an extended period.

In the case of hospitals, patients’ lives, blood supplies, pharmaceuticals and the like cannot be risked by an ordinary power outage. Universities have similar needs for their research labs and perishable collections. In these cases, the imperative of energy surety trumps a formal business case based on return on investment. Preventing the loss of life and/or assets is difficult to value as a business case variable, but makes sense on its face.

That leaves the business case. Corporate campuses, increasingly, are turning to DG - as well as short-term storage and microgrids - based on preventing the measurable loss of productivity wrought by the known frequency and duration of local outages. (Storage in this scenario merely bridges the gap between an outage and the startup of backup generation.)

Policy also can drive non-renewable distributed generation. If commercial power is relatively expensive and the demand charge set by peak use at an industrial facility, for instance, is high enough, the installation of turbines or reciprocating-engine, natural-gas-fired generators designed to lower peak demand may be affordable and advisable. Micro-turbines often are used at smaller facilities.

Utility concerns and circumstances

Finally - and this is crucial to the uptake of DG - there is the business case for the utility itself. A scenario is possible in which DG serves to reduce load where, otherwise, meeting the peak would require a more expensive peaker plant. However, this possible solution comes with unintended consequences.


At a well-known utility in Southern California, the penetration of solar PV among customers is so high that substation-based load tap changers and feeder voltage regulators, attempting to maintain distribution voltage constant with a widely varying net-load level, operate perhaps 80 times per day - and tap changers are designed and built to operate perhaps a half-dozen times per day. Therefore, simply accommodating DG comes with an operations and maintenance cost to the utility.

The potential ambivalence of utilities to DG can be understood when you consider that they need (costly) controls and protection in place to accommodate the DG, yet that DG typically undercuts the electrons they sell via a centralized grid system. This is particularly true when residential tariffs are volumetric (i.e., per kilowatt-hour) and the demand cost is rolled into the energy consumption charge. “Net zero energy,” under such a tariff, removes all utility revenue, but leaves the substantial cost of providing that customer with grid demand capacity.

Meanwhile, the technical demands of accommodating renewable portfolio standards - typically through utility-scale renewable resources - also are hitting utilities. And policymakers rarely consult with a utility’s technologists to understand what is feasible in terms of the electrical infrastructure required to support RE penetration.

‘Kick the tires’

On the other side of the meter, however, one can readily see why customers - whether for energy surety, the bottom line or green “bragging rights” - are being moved to adopt DG. Perhaps that explains expectations of survey respondents, which are seemingly surrounded by drivers for greater DG uptake.


My colleague, Reigh Walling, principal at Walling Energy Systems Consulting LLC, captured much of the foregoing discussion when we talked over the topic recently.

“I think there's a wide divide between the policy view of distributed generation and some of the rather superficial analyses done on DG in reality,” Walling told me. “I’m a bit of a tire-kicker on this subject. A better understanding of how the grid operates - and the benefits and costs of diversity - have to be taken into account to arrive at a good understanding of how and where DG really plays in the system. Integrating a lot of variable, distributed generation has a lot of challenges.”

Relevant standards

IEEE 1547 Standard for Interconnecting Distributed Resources with Electric Power Systems was published in 2003 and is being updated periodically. The standard did not mandate interconnections, but state public utility commissions typically use it to require utilities under their jurisdiction to have a set of uniform criteria and procedures for interconnecting DG to the grid. But as policies change, as technology advances and circumstances evolve, continued standards work clearly is needed. Walling, who was involved in writing IEEE 1547, explains a few of the nuances.

“During the development of IEEE 1547 ten years ago, most of us did not anticipate the level of growth in distributed generation,” Walling said. “Some of the decisions we made and some of the requirements in the original standard are counterproductive when it comes to accommodating larger and larger levels of integration.

“One amendment to the standard, 1547-A, will address DG’s impact on the reliability and security of the bulk grid,” Walling continued. “Right now, under the original standard, DG is required to get off the grid at the slightest disturbance. But let's say you had a transmission fault on a 500 kV substation coming in to a metropolitan area, causing the voltage over the whole metro area to dip. That could result in hundreds of megawatts, even gigawatts, of distributed generation dropping off simultaneously, which then exacerbates a real problem.

“Also, the original IEEE 1547 barred distributed generation from performing voltage regulation to help smooth associated issues at the distribution level, even if the utility wanted to allow it,” Walling added. “Allowing DG to do voltage regulation where possible could improve the business case for the developer and help the utility as well. So, that’s being modified. And there’s another standard, IEEE 1547.8, which is a new recommended practice for dealing with high penetration of DG, but completion of this standard will take longer than the more immediate changes in the 1547-A amendment.” 

The gap: expectations and projections

As noted, many drivers are at work here, pushing greater interest in and expectations for distributed generation. Yet a quick review reveals that a unified policy environment in Europe - separate from the business case - could indeed spur greater adoption there than in the U.S., with its state-level regulatory bodies. Here in the U.S., the need for energy surety and/or the business case may well propel customer interest in DG, while for utilities, the breadth of implications is decidedly mixed. Finally, applicable standards continue to evolve to accommodate the interconnection policies and procedures for interconnecting customer-driven DG to the utility’s central grid.

All these factors are more likely to turn a straight line between expectations and market projections into more of a scenic route. We’ll undoubtedly reach our destination, but the timeframe is far from certain and we can expect a few interesting curves along the way. 

John D. McDonald is an IEEE Smart Grid technical expert, as well as director of technical strategy and policy development at GE Digital Energy. He is also past president of the IEEE Power & Energy Society (PES), an IEEE PES distinguished lecturer, board chair of the Smart Grid Consumer Collaborative and board chair of the Smart Grid Interoperability Panel 2.0 Inc., among other affiliations.

McDonald wrote this series to further analyze the results of a recent survey sponsored by IEEE Smart Grid and performed by market research firm Zpryme. The report, titled “Power Systems of the Future: The Case for Energy Storage, Distributed Generation and Microgrids,” can be found HERE.

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