Demand response, pricing and microgrids provide emissions-free renewables backup.
by Guerry Waters, Oracle Utilities
Around the world, citizens concerned about the environment voice enthusiasm for electricity generated from carbon-free renewables such as wind and solar.
Behind the scenes, however, utility experts have winced when the conversation turns to questions of exactly how much carbon those sources save.
Reliability requirements frequently force utilities to back up intermittent renewables with spinning generation—often fueled by natural gas—so when wind drops or clouds pass between the sun and the collector, the grid remains operable.
Exactly how much backup generation utilities should require is a matter for debate; 85 percent is not uncommon.
Renewables advocates argue that utilities need far less if renewables are geographically dispersed and of different types because it is unlikely that the wind would drop and clouds would roll in simultaneously everywhere in a large generating region.
Others point out that the facilities and transmission corridors to create such regions do not exist.
A resolution will emerge, but it still will require backup for intermittent renewables.
No one wants to use backup that erodes renewables’ environmental benefits.
Utilities and renewables generators are exploring alternatives to backup generation such as advanced batteries, pumped storage, air compression and other physical devices. But alternatives do not need to be physical. Utilities can begin to implement programs that serve as a virtual backup for renewables using tools already in place: billing, customer, metering and network management applications.
In the past, utilities have found demand response effective in managing unpredictable events.
By soliciting load reductions from generally large industrial and commercial customers, utilities could mitigate the potentially devastating effects of a sudden loss of supply or demand increase.
During the past several years in conjunction with growing interest in the smart grid, utility analysts have touted an additional demand response application: peak demand reduction (see Figure 1).
Lower peaks and a smoother demand reduce utilities’ need to overbuild the grid with wires, peaking plants and associated equipment that they use for relatively few hours per year.
Lower peaks also can reduce costs associated with buying electricity at frequently high spot market prices.
Utilities’ interest in reducing peaks dropped substantially with the global recession.
As overall demand dropped—frequently by 5 or 6 percent—peaking problems began to evaporate. So did some previously projected savings on capital and supply costs that utilities had been using to justify investments in the smart grid and associated demand response programs.
The peaking problem will return. In the meantime, however, utilities might want to consider the value of demand response as a renewables backup.
The Demand Response Smart Grid Coalition is one of many organizations advocating this potential:
- From the coalition’s 2008 Policy Recommendations: Demand response has been demonstrated to be a resource that can be quickly dispatched to replace renewable energy generation when the latter becomes unavailable, ensuring that there are no interruptions or outages. Demand response, when coupled with renewable energy generation, can make the combined domestic resource mix more reliable and viable and lead to its accelerated adoption.
- From a coalition fact sheet: Demand response can serve to meet unexpected needs on the grid when renewable resources that are normally available suddenly become unavailable. For example, in March 2008 Texas experienced a sudden drop in wind”energy production from 1,700 MW to 300 MW. Within 10 minutes, however, Texas grid operators deployed 1,100 MW of demand response from electricity customers—thereby preventing a statewide blackout.
Capgemini cites in its 2005 report “Smart Metering: The holy grail of demand-side energy management?” the example of a U.S.-based investor-owned utility in which customers received incentive payments to put their appliances on call. The utility could cycle specific appliances on and off for 15 minutes every half hour for three hours per day or shut them off completely for three to four hours. The program has proved popular. Although its marketing program consists almost entirely of word of mouth, more than 500 customers per month inquire about it, and 80 to 85 percent of those sign up. As a result, the utility can shed 2,000 to 3,000 MW in just 60 seconds.
In the Texas case, demand response served its traditional function as an event-management tool; grid operators prevented a blackout by activating load reduction commitments.
But the 10-minute delay could be far shorter when utility demand response programs include direct load control. Utility direct control over air conditioners is not new. Such programs, based on radio signals, were popular in the 1980s and ’90s for peak shaving. Many customers welcomed the associated incentive payments. Still, many utilities avoid radio-based direct load control because of signaling problems and the inability to determine over time which units remain operable.
Smart grid-based direct load control avoids those problems with far more sophisticated signaling and measurement devices.
But direct load control has played only a secondary role in most current discussions of the smart grid because many think customers will be reluctant to accept them.
They cite, for instance, the storm of negativity surrounding a quickly abandoned 2008 California proposal that would have allowed utilities to control home temperatures during emergencies.
Others think a big difference exists between the California proposal, which would have been applied universally without allowing customers to override the system, and direct load control for incentivized volunteers.
Some see volunteers as even more plentiful if direct control programs reduced renewables’ costs and increased their use.
And even assuming some customers might quickly hit the override button, tests and experience will give grid operators the data to understand, based on the length of the projected renewables’ shortfall, how much power they need to call up from other sources.
A second issue blocking increased use of renewables is that peak renewables generation and peak demand do not always coincide. Time-of-use pricing can ease—though not eliminate—this inhibitor to renewables’ use.
To see how, let’s posit a simplified case intended to be illustrative, not particularly realistic.
- A grid able to accommodate 25 percent intermittent renewables has demand of 1,000 MW during the night and 2,000 MW during the day—a demand that uses grid capacity to its fullest.
- Base generation from coal provides 750 MW.
- During the day, base generation plus 1,250 MW of gas-fired generation meet demand.
- At night, the utility meets demand with base generation plus 250 MW of wind (half of the renewables’ capacity).
- If, encouraged by pricing, customers shifted an eighth of their daytime use to night, the utility could reduce gas generation to 1,000 MW, lowering emissions.
- The utility could use wind to its full capacity—500 MW—at night to meet the new 1,250-MW demand level, maintaining the overall emissions reduction.
- The pricing tool is less effective for solar because peak prices and solar generation frequently coincide.
Powering storage with weekend solar, however, in some cases might prove a cost-effective way to meet renewables mandates.
A microgrid is an autonomous electricity environment that operates within the larger electric utility.
It coordinates with other utilities operations, but it can run in part or in total on local distributed energy resources.
Microgrids promote renewables use because they can match up intermittent supply with potentially intermittent demand.
Microgrids are more adept than are regional grids at, for instance, directing power from solar rooftops at an appliance load such as basement dehumidifiers, which can operate effectively without constant access to power.
Microgrids may be particularly useful in handling demand created by plug-in electric vehicles (PEVs) by directing overnight wind generation to vehicle charging stations.
Using renewables close to the source of generation has efficiency benefits: Power is no longer subject to the 5 to 8 percent loss typical when it is transmitted long distances.
Microgrids also can save some capital costs associated with increased renewables. The more effective use of local resources can delay or eliminate the need for additional distribution infrastructure such as lines and transformers, as well as the need to obtain new corridors with the associated citing complications.
Direct load control, pricing and microgrids are not the only paths to increasing use of renewables.
As parts of the equation, they can boost renewables’ use and accelerate delivery of their environmental and energy-security benefits.
Guerry Waters is vice president of industry strategy at Oracle Utilities. Reach him at firstname.lastname@example.org.