SnapshotWhat is DG and Why Should We Care?
By: Michael Bobker
June 30, 2006
We are all connected to the electric grid. It is an essential part of the life we take for granted in our advanced societies. So it would seem that our "connectivity" is high. But this connection, unlike what we have with the Internet, is one-way only. Electrons flow from sources of high voltage, such as power plants, to low voltage consumers like office computers, lighting and household appliances. Unlike the interactive packets of telephone or Internet, the electrons have no particular destination or address on the grid; they flow wherever there are voltage differences. When sudden events interrupt the gentle, balanced flow, surges occur causing breakers to trip (to isolate and protect the wider system) and the system can become unstable. Grid operators seek to control their systems and protect them from "faults", from the top down, in order to assure that we have reliable power.
Over the last two decades, changes in technology and regulation have begun to enable a different model of the electric grid with more varied generating sources. Decentralized, distributed generators (DG) are connecting to the grid from what were previously just consuming sites (or "loads"). Distributed generators can be solar or wind installations, fuel cells, or, most commonly, reciprocating engine or turbine-driven co-generators, where the waste heat from electrical generation is recovered for use on-site. For an engine-driven distributed generator there is no efficiency gain compared to the fleet of central plants unless the waste heat is being recovered for useful purpose and small, localized engine exhausts can be more polluting than the newest gas-fired central plants.
Distributed generators would like to be connected to the grid, rather than "standing alone", for several reasons:
- The grid provides back-up and reliability. Without a connection, systems would have to be fully redundant, which of course costs money.
- The grid allows more economic sizing so that the DG unit would not have to meet the site's peak demands, which are usually limited in occurrence, e.g., hot summer days, and duration.
- For solar or wind installations, because of the intermittent nature of the resource, an isolated installation would require expensive battery banks.
It has not always been easy for private entities to connect their generators to the grid. In an era of vertically integrated utility monopolies, local utilities were unsupportive of private generators. In this period co-generating sites, such as Starrett City in Brooklyn, had to be stand-alone plants without grid connection. This changed when the Public Utilities Regulatory Act (PURPA) of 1977 required utilities to connect "qualified facilities" that were efficient co-generators or used renewable energy sources.
Notice that so far we have only discussed distributed generator drawing electricity from the grid, "in parallel" with the on-site generating source. Why not produce more electricity than the site requires, at least some of the time, especially if there is enough wind, sun or on-site thermal load? Answering this question takes us into the mysteries of utility "grid protection." Sources that are small, in comparison to the power handled by the local sub-station, will have little impact on the grid's stability. But larger sources, engine-driven co-generators suitable for stand-alone power ("synchronous", as opposed to "induction" generators) do have the potential to introduce significant faults into the system that, by causing circuit breaker trips at the sub-station, could cause local grid shut-downs (i.e.- black-outs). Under PURPA, utilities actually did have to go beyond one-way connection, to actually buy-back power from qualified facilities. But this additional mandate was limited by specific utility needs to protect their local grids.
New York City's Con Edison has a particularly vexatious situation as its "network" grid has multiple pathways into (and hence, potentially out of) many buildings. In much of NYC, the transformers that reduce voltage from the distribution system so that the electricity can be used in buildings for lights, computers and so many other needs, have more than one electrical feeder. This improves reliability, as many alternate pathways are available for the flow of electricity. But the fact of multiple electrical feeders also makes it much more difficult to monitor, track and isolate faults which might occur on the system, so Con Edison has one of the most rigorous procedures in the country for inter-connecting DG. And only the smallest installations such as a residential photovoltaic installation — no more than a few kilowatts in size — are allowed to sell power back into the grid. The level of detail and systematic interconnection application and design process can be gleaned from a visit to their website, www.coned.com/dg.
In recent years, many states including New York have passed "net metering laws" that require local utilities to accept electrons from renewable energy sources, such as solar photovoltaic (PV) and wind, making the meter turn backward when more power is generated on site than is consumed. This mandate applies to farms and residential sites, the latter meaning single family homes, as most of the regulations set a 10 kilowatt (kw) maximum; a typical NYC apartment will draw 2-3 kw at summer peak. Such small-scale installations of direct-current "inverted" power (to convert the direct current into alternating current) do not pose a grid-protection issue and are easily accepted onto the system. To accept much larger electron flows from DG will require major grid upgrades for improved fault protection. But keep in mind that the quantity of electrons that can be cost-effectively generated on a site is a function of the thermal loads that exist on that site — for a gas-fired engine (or turbine) driven distributed generator, no heat recovery equals no cost-advantage.
More contentious is the allocation of costs for back-up service. Con Edison, not alone among utilities, has long sought to charge co-generators fully allocated costs for the site's full potential load. Such a charge would be a major economic disincentive for distributed generation, at a time when the city as a whole and many local distribution networks could use the additional power. Recognizing this, in recent rate cases the Public Service Commission have denied Con Ed the authority to impose such charges. Other locales have gone further. Chicago, for example, has experimented with having its local utility acquire — that is, actually participate in the development of — distributed generation to reinforce the local distribution system. Con Edison has accepted this principle for demand-management measures but so far has not included distributed generation resources in the mix. The step from demand-management to participation in the ownership and management of distributed resources is not large and harks back to the early days of the first generating plants, often on-site, in the early part of the 20th century. Thomas Edison might be smiling.
Michael Bobker is a senior fellow at the CUNY Institute for Urban Systems and leads the new CUNY Building Performance Lab. He has worked for engineering firms, energy service companies, and not-for-profits, most recently the Association for Energy Affordability, over his thirty-year career in NYC buildings. He is a board member of the NYC chapter of the Association of Energy Engineers and chairs the Environmental Science Section at the New York Academy of Sciences.
