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Copy and Paste This Permanent Link:http://www.distributedenergy.com/january-february-2009/the-gridwise-future.aspx

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©Stockphoto.com/Electricityplylon

Little-known and under-publicized at the time, a provision of the Energy Policy Act of 2005 has since made rapid strides towards advancing what would be a revolutionary goal: a complete revamping of our nation’s electrical grid system and ratepayer electricity markets. If this initiative, often called the “smart grid,” stays on the track that industry groups are now busily charting, it will not only change the grid, but fundamentally redefine how distributed energy (DE) generators do business—and perhaps even determine whether there is a DE industry, at least as it is now constructed.

Shepherding this far-reaching and massive undertaking is the US Department of Energy (DOE), working along with a public-private partnership called the GridWise Initiative. Members of the GridWise Alliance consortium include such major utilities and corporations (listed at www.gridwise.org) as: American Electric Power (AEP), AREVA T&D, Battell, Bonneville Power Administration (BPA), GE Energy, Nxegen LLC, IBM, PJM Interconnection, RockPort Capital Partners, SAIC, Schneider Electric, UAI, EnergyWeb, North America Power Partners, EnerNOC Inc., Site-Controls LLC, Powerit Solutions, RTP Controls Inc., and Ziphany LLC. The federal side of development is being spearheaded at DOE’s Pacific Northwest National Laboratory (PNNL) research facility in Richland, WA.

Positioned at the center of the new grid concept is probably just what you’d expect-a digital device. Introduced half a dozen years ago to the gas, electric, and water utilities, this one is known as the advanced or automated meter reader (AMR). In essence, AMRs replace the old mechanical electricity meters whose dials and gauges are read visually by walk-by inspection. Instead, AMRs log digitized data that can be transmitted—usually wirelessly—and, in new models, sent all the way to the utility business office.

Likewise, next-generation AMRs not only record and transmit, but also add two major enhancements. First, the ability to register a site’s energy usage at temporal increments, down to specific hours and even minutes of the day; and second, two-way communication, i.e., first sending data to the utility, and then allowing the utility to reach into the meter, and even into home appliances, remotely.

What this means is that, finally, the potential has suddenly emerged for utilities and customers to engage in a wholly different model of electricity usage and delivery—all thanks to these high-end AMRs. What’s envisioned primarily is a massive-scale, time-sensitive demand response (DR) energy market. If all goes as proponents envision, this will someday be operating throughout the US grid.

Here Is How It Might Work
Rather than ratepayers being charged basically flat, per-kilowatt-hour fees for power, day or night (as now), the new time-sensitive AMRs would provide the possibility of an energy user adjusting to the often-steep spikes in wholesale peaking power prices. Consumers will thus be able to use their appliances—turn them on or off—more intelligently, in response to power cost. For example, when doing the laundry, a person might first look at the daily rate fluctuations and determine the cheapest time for running that rather electricity-gobbling appliance. Or, a person might turn a thermostat up for “pre-cooling” at cheap rates, in order not to run a chiller later in mid-afternoon, during peaking times. Again, because AMRs can match usage to time, the utility can reward price-minded frugality.

Better still, from the utility benefit standpoint, comes a lowering of peak demand (achieved by all of these frugal customer decisions) and, with it, the ability to avoid buying costly peaking plant power. This electricity is, of course, often multiple-times higher in price.

From here, it’s a short step to what’s already emerging as the next phase. As just noted, digitally remote-controlled appliances will enable utilities to decide when and how to run air-conditioners, water heaters, space heaters, washer-driers, thermostats, HVAC, and such—always factoring in predetermined comfort levels, together with customer wishes and incentives. In fact, the compact circuit board for doing this task already exists, so too does a prototype of the whole market price–conscious smart grid itself, at least in a small-scale test version. In the state of Washington for 2006–07, all of the above described elements that were assembled and demonstrated using real utility customers—along with integrated onsite power generators in the mix. (More on this trial, below.)

Photo: Pacific Northwest National Library The Grid Friendly appliance controller is a sensor in an appliance that can detect when the electricity grid is under stress, and then turn it off.

Networked on this two-way grid, too, as just noted, will be present and future DE resources. They, like remote-controlled home appliances, will be complemented with greatly expanded DR. Using the new two-way technology, both will be made easily dispatchable in fine increments as needed, for grid stability or more efficient power management.

Exactly what this might mean for DE resource owners could include, among other things, a much easier way to use their backup diesel generators. As PNNL’s senior research engineer for the smart grid, Donald Hammerstrom, points out, these diesel generators—often located at hospitals and police stations—“Usually sit around having nothing to do.” But if an easy means existed, which could enable occasional peaking operation, these idle assets would find a whole new role for themselves. That is indeed a theoretical capability that has also recently proven out.

Industry Commitment Growing
In any event, during the few years since the Energy Policy Act empowered smart grid research, a number of related private initiatives have come to the fore. A few highlights:

• Major AMR implementations are now underway at Southern California Edison (5 million two-way meters—in 1999, Itron and Southern California Edison signed a contract creating the largest AMR Installation in California), Horizon Utilities (800,000 meters in Western Canada), CenterPoint Energy Houston Electric LLC (1.9 million—IBM was selected as the technology and implementation partner for the project), and Pacific Gas and Electric (9.3 million over the next six years under an agreement with Itron). Besides these, Duke Energy Corp., AEP, and BC Hydro have all announced huge smart meter projects, each to cost in the range of $1–5 billion, according to http://smartgridnews.com.
• In 2007 in metropolitan Washington DC, 1,200 customers began participating in a “PowerCentsDC” pilot with DR-capable, radio-controlled AMRs, under an agreement with Sensus Metering Systems. Price responsiveness is being tested at hourly, peak, and critical peak level rates. The Energy Independence and Security Act of 2007 added a provision for creating a Federal Smart Grid Task Force to coordinate smart grid activities for the federal government.
• A GridWise Architecture Board task group has been established to define generation and distribution protocols.
• IBM has launched the Intelligent Utility Network Coalition, which seems to be charting de facto standards.
• In December 2007, Xcel Energy established a private sector Smart Grid Consortium (consisting of Accenture, CURRENT Group, Schweitzer Engineering Laboratories Inc., and Ventyx) to develop data automation systems management.
• In January 2008, CURRENT Group announced the commissioning of the nation’s first high-speed utility Smart Grid home area network, for Oncor Electric Delivery Co. in Dallas, TX. Using programmable thermostats and load-control switches, the system communicates and verifies DR requests. Electricity retailers Direct Energy, Reliant Energy, and TXU Energy, as well as the Center for the Commercialization of Electric Technologies, are collaborating.
• After construction began in mid-2008, a $100-million (largely federally funded) Smart Grid City development at Boulder, CO, by Xcel Energy, was scheduled to be near completion by December 2008. Integrated at that time were four utility substations; 25 feeders; 50,000 residential smart meters; in-home Web portals with automation; and provision for plug-in hybrid electric vehicles (PHEVs) recharging solar, wind, and CHP. Xcel serves 3.3 million electricity customers and anticipates expanding the Smart Grid City to many.

Why Put in a “Smart DR Grid” Instead of More DER?
Massively expanded DR capability—going down to each home—goes far beyond anything done historically. Why launch such an enormous undertaking?

Supporters in the DOE and at the utilities argue this approach is simply the best solution for correcting a widely recognized, chronic market hardship that is increasingly exacerbated by grid congestion. Preston Michie, Executive Director of Northwest Hydrogen Alliance Inc. and a consultant to the Bonneville Power Administration (prominent in smart grid research for the DOE at PNNL), explains that, from an electrical standpoint, DR is “one of the better strategies for managing resource imbalance” caused by peak demand or a downed power line. “If you can trip the load off, you relieve stress on both the transmission [and distribution] systems,” he says. 

What about just adding more distributed energy resource (DER) to a feeder instead? Dispatching of this sort already occurs, Michie notes. “A fast-acting device at the load itself is a very good solution,” he says, “because it can detect [and solve] the problem at the load very quickly [by simply curtailing the load] at large numbers of residences or small businesses.”

DR load shedding is thus relatively instantaneous. This contrasts to the time lag that is encountered in waiting for DE resources to respond to dispatches. So from the utility standpoint, DR, rather than DE, “makes the [grid stability] problem much easier to solve, because the response occurs at the load itself,” says Michie. “What’s key, is that loads [unlike DE] are everywhere. You may need [to curtail] a couple of hundred megawatts of demand response—which is a very large number of homes. But if you had those sites already in place and automatically responding … the operator could send a signal that trips all of them simultaneously.” 

Photo: ECS Inc. High-efficiency fixtures replaced existing 300-watt incandescents in this school gym, to improve lighting and lower electricity and maintenance costs.

Thus, according to Michie, the “…ability to pinpoint the location and to control the magnitude with [DR] makes this the better solution.”

In purely commercial terms, having the ability to do pinpoint load management also means that utilities will avoid the often stiff, per-kilowatt-hour cost of buying from remote peaking plants. These charges in particular cut into profits, because they are not automatically or quickly passed on to ratepayers since regulators laboriously set rates.

Similarly, exorbitant costs are encountered by utilities in building transmission and distribution lines. Here again, the burden is borne by the utilities and ratepayers. As a Bonneville executive Mike Hoffman reports in another context, “It’s not unusual for construction of a transmission line to cost upwards of $100 million.”

However—despite the foregoing credible assertions—a curiously contrary finding, based on interviews with 22 utility managers for a recent Chartwell report, suggests that utilities may see the impending automated grid more as something to make their jobs easier, than as a solution to power-delivery problems. The report, titled, “Smart Grid: How Utilities View the Grid of the Future,” finds that utilities actually “see more value in operational benefits as opposed to load curtailment benefits.” One of the report’s contributors, Chartwell’s metering research analyst Mark Hall, calls this “surprising.”

A final reason for pushing smart grid development is that the services of electric utilities are rapidly expanding. Several have already announced plans to provide high-speed broadband over powerline. The smart grid will enable delivery and control of voice, video, and data transfer, over the same wire that brings in 120-V house current. A future grid with this added utility-end control and activity measurement built-in would become a tremendous enabling asset.

DR: Already a Big Competitor to DER
The utility-controlled home DR that the GridWise Alliance envisions would also come as an addition to the DR that is routinely taking place at larger-load sites now. In a way, these DR businesses—called “curtailment service providers” (CSP), a.k.a. energy brokers, DR aggregators, enterprise energy manager, etc.—are occasionally a thorn in the side for some onsite generation developers. Both offer customers similar peak load shaving benefits; but CSPs, et al. do it just by curtailing load, without installing power.

As an example: CSP firm Comverge reported helping the University of Maryland (UMB) at Baltimore cut back on more than 20 million kWh in power purchases from PJM Interconnection (the Pennsylvania-New Jersey-Maryland transmission organization) over the last two years. Comverge installed a market-pricing monitoring system and graphical tools, did load profiles, and established baselines—all of which, as UMB utility manager Michael Krone states in a news release, “have been invaluable to our success in the regional DR program.”

Among the strategies that Comverge implemented were: using an existing 20,000 ton-hour per 2,000-ton output thermal storage system to shift air-conditioning load from daytime peak to off-peak operation, remotely controlling campus lighting, and curtailing chilled water production.

As another example, DR firm Site Controls packages “intelligent load management technology” in a program called “Site-Command,” for doing long-distance, centralized load shedding at bank branches. An operator can monitor and control branch lighting, air-conditioning, signage, and equipment at hundreds or even thousands of sites. Peak load shedding is optimized, enabling energy reductions of least 15%, yet, “without interfering with customers’ experience,” says company sales materials.

DR and DER are not always competitors; occasionally they are complementary. As executive vice president of program development Paul Tyno, of Energy Curtailment Specialists Inc., points out: “Every DR provider has participants who have onsite generation to displace loads during an event call.” Thus, if the tariff incentives are large enough, sites will run their backup generators to displace peak loads, he says. However, there’s a strong public preference these days “to utilize reduction methodologies that are nonpolluting.”

Smart Grid: What’s It Going to Mean for DE?
If this futuristic grid becomes reality, it would effectively integrate many more energy competitors in the form of customers whose loads would participate in micro-scale DR. From a utility standpoint, as Michie noted, DR is sort of the flip side of DE: Both yield the result of enabling a grid to adjust to demand.

Although at first glance it seems DE resources would likely be at an increasing disadvantage, because of the possibility that the multi-kilowatt scale advantage—which onsite generators now enjoy—would be negated by the network of thousands of tiny 1-kW loads which could be automatically controlled, either individually or in aggregated multi-kilowatt blocks. PNNL’s Hammerstrom notes that an expanded role is conceivable, especially for backup generators. Also, operationally, whenever DE resources are dispatched, this will likely become more automated. Currently, if a utility needs DE, the phone rings. But in the future, the dispatch will probably come by an electrical signal. As Michie says, “We’ll be able to detect, say, a decline, and then automatically turn off demand or turn on generation; it can be done very quickly … in this instance, through a drop in frequency.”

Test Deployment: When the Price Was Right
Would electricity ratepayers really trade away control of appliances in exchange for lower bills? And in a bidding contest between DR and DE, how would DE come out? Possible answers—and an early real-world glimpse of this future—were supplied by a small pilot version in 2006–2007, on the Olympic Peninsula of Washington (the market area near PNNL and BPA). 

Major coparticipants included: Invensys Controls; IBM; Whirlpool Corp.; three utilities—BPA, Portland GE, and Clallam County planned unit development; power generator PacifiCorp; the City of Port Angeles, WA; and the US Department of Energy. In the experiment, the AMR meters, thermostats, and water heaters in 112 homes were outfitted with the above-described control boards. These were then set to turn appliances on or off in response to grid power demand—but also most importantly, doing so in response to pricing signals and customer choices. The whole array was then linked to the Internet, to enable owners to monitor things like fluctuations of kilowatt-hour prices and their own appliance’s costs and behavior, moment by moment—watching it in real time, via Web browsers, and setting parameters with the on-screen dashboard. Participants got actual market pricing information, and they were free to adjust devices, either for comfort or economizing.

Also in the competitive mix was a 30-kW microturbine running in grid parallel and two diesels generators (175 kW and 600 kW). Although the latter two were not grid-connected, they already had transfer switches to enable automated starts. Besides these three generators, a fourth “virtual” one was computer simulated, to see how it would respond to markets.  

Lastly, besides the DER and home-sized loads, several municipal and commercial loads were equipped: HVAC air handlers, water pumps, and such, could join in the competitive bidding. With these large DR loads, notes Hammerstrom, balance must also be maintained between building occupant comfort and load curtailment.

In this first-of-its-kind energy market, all participants were free to bid for the opportunity to curtail peaking loads (or, in the microturbine’s case, to make power directly) whenever grid conditions warranted. Winners, of course, received compensation.

“The real novelty was an extremely sophisticated price-point bidding system that every load and/or power-generating customer was able to participate in—not unlike market systems operating in the energy sector,” observes Hammerstrom.

The winning purchase decision was entirely automated and likewise market-driven, being determined by comparing energy prices measured at five-minute intervals. Thus, for example, whenever the wholesale power kilowatt-hour rates rose to a predetermined point, a DR resource (i.e., ratepayer) might decide to put off using the clothes drier or water heater a few hours, in order to win a nice, albeit brief, rate reduction.

Likewise with the microturbine or diesel generators: Finding that the rival peaking-plant power was priced much higher than their own costs (i.e., for fuel, labor, maintenance, and wear and tear) by a big enough margin to make it worth their while, the operators would fire-up turbines and sell power for some convenient time block (perhaps in minimal half-hour units, say, twice a day). For doing so, cash accrued to an account. Bids (i.e., wholesale market rates) and offers (DE/DR responses) occurred one or two days ahead, at specific price-points. Then—depending on which bids won—the resources (DR and/or DER) would be scheduled for the following day, allowing also some flexibility.

In its own “league” was the 30-kW microturbine: being grid-interconnected, it was able to set a constant output. It thus bid continually at about $377 per megawatt-hour.

Bids by the two diesel generators ranged greatly, Hammerstrom recalls, depending on the power quantity being produced—from as little as 30 kW, up to several hundred kilowatts—and bids to produce were accepted for as low as $180 per megawatt-hour, up to $680 per megawatt-hour. “The smaller generator usually bid lower than the 600 kilowatts,” he notes.

Photo: Pacific Northwest National Laboratory A 30-kW microturbine was interconnected to the local Washington state electrical grid and dispatched to provide peaking power from 2006-07.

So, at the end of the yearlong trial, what did the study reveal? All in all: a qualified success for DE.

Although DE bids were often too high, there were a few times when grids were so congested they could not bring more power in; Prices for DE soared, and bids were easily won. Successful DE bids peaked during a couple of weeks in early December when heating loads spiked; power rates leaped higher. The microturbine won many bids and ran a respectable 59 hours during this two-or-three-week period, while the other two generators worked 65 and 48 hours respectively. As days passed, though, feeder capacity revived, and DE resources were consistently outbid. On the shoulder months, activity fell by two-thirds in November and January, and then shrank down to a tiny fraction most of the year.

As for the home-based DR ratepayers, they too reportedly found that their participation paid off modestly, as they shaved an average of about 10% off monthly bills. Surveyed afterwards, most said they liked having a choice and would probably buy the necessary appliance modification to enable participating again. Few ever felt inconvenienced.

Michie—who worked on the experiment with Hammerstrom—recalls: “One of the things we looked for was, do people notice these things [i.e., the automated curtailing of home appliance loads]? And, the answer was, no.” 

The utilities received the greatest benefit: peak loads were cut as much as 50% for days at a time, notes Hammerstrom. If this could be duplicated nationwide for a couple of decades, it would likely translate into avoided costs of tens of billions of dollars, he adds.

Cost? Benefit?
On this latter score, however, actual long- or even short-term savings have proven extremely difficult to calculate, and the published estimates (of which there are many) vary considerably. For example, a 2006 DOE report to Congress (mentioned earlier) titled, “Benefits of Demand Response in Electricity Markets and Recommendations for Achieving Them,” found that in 10 DR industry studies to date, estimates were “wildly disparate,” and ranged from life cycle savings totaling as little as just $1 million, up to $52 billion. On only an annual basis, figures in two studies that DOE favored, came up with numbers varying by a factor of eight—$362 million versus $2.6 billion. Two estimates derived from PNNL pegged potential life cycle savings at either $70 billion or even $120 billion. And, a study in 2007 from the Brattle Group, covering real-time power savings during a one-week heat wave in PJM, found that curtailment of peaking plants resulted in an estimated $650 million in savings. So, take your pick.

Whatever the cost-avoidance benefit actually is, what will the smart grid set us back, and who will pay for it? AMR units—the enabling technology—are now priced over $100 each; and, beyond having one or more at each site, there will be thermostats and appliance circuit boards. Elsewhere on the system will be peak load and energy management controls, and a networking superstructure. Obviously, the total—perhaps coming to several hundred dollars per ratepayer site—won’t be cheap.

And as the GridWise Web site suggests, the tab will likely have to be recouped with increases in electricity tariffs and with taxpayer subsidies. The authoritative 2006 DOE report does not attempt to come up with a cost figure, but does note that expenses will be recurring, owing to periodic maintenance and upgrading. Also, the high first costs will likely pose an obstacle to gaining acceptance, especially for small- and medium-size customers.

Smart Grid Thus Faces Hurdles
Michie agrees that massive up-front cost will be needed, noting that implementation at just a single utility will necessitate retrofitting “tens of thousands of homes,” at a cost of many millions of dollars, just to yield DR “in the neighborhood of one kilowatt per locale, during peak loads.”

High initial cost is just one of a number of challenges to be surmounted. Michie—though he strongly supports the future grid—lists some of the other key considerations that will need to be addressed:

• “All-or-nothing” critical mass: There’s relatively little to gain from partial or incremental implementation. From a utility cost-benefit standpoint, “several hundred” megawatts are needed, he says; otherwise the impact “would be too small to be of much use.”
• Automation should be flexible. Although fully automated DR is probably desirable in many scenarios, it’s not in others, and manual operator oversight will be necessary.
• Superb reliability will be critical. “A failure rate of just 5%, for whatever reason,” might translate into millions of dollars in added expense or lost benefits, over the life of the system, says Michie. Similarly, the “rate of degradation is unknown”—a fact which would necessitate adding redundant systems initially, until system life is well understood. And any wide scale DR system would also be subject to failure whenever the Internet goes down, he adds.
• Human resources, administrative demands would be considerable. Operationally, servicing a future grid will require comprehensive staff re-training on technical, business, and marketing aspects. Likewise would come the need for acquisition of new materials, devising new distribution systems, and establishing new standard contracts approved by utility commissions.
• No mechanism to finance or insure the system exists. And there is likewise none yet for billing, handling complaints, or doing repairs.
• Public awareness of future grid benefits is negligible. Consumers will thus need to educated and “sold” on the concept, or their apathy/resistance will undermine it.

Despite these hurdles to be overcome, though, once the future electrical system is up and running, Michie says, “You’ve got a terrific resource—something very valuable to help manage emergency outages or peak demand.” Disruptive events like heat waves, ice storms, downed power lines, and peaking power shortages, will become far easier to cope with.

What Alternatives? DER, Energy Efficiency…
An expensive DR-based grid is not the only solution for peaking power, and, in fact, a number of options have been available for policy makers to weigh.

From the DER industry standpoint, the overwhelmingly obvious one is to continue making fairer grid interconnection rules. This would enable more customer-owned generation to be added and, thus, relieve congestion. This would also seem the preferable alternative for the public, as it would not only help solve peaking power issues, but do so without necessitating higher tariffs or public funding. Customers would invest in, own, and maintain their resource—whether it is rooftop solar photovoltaic (PV) or a cogeneration plant—which would provide broader public benefits gratis.

DER has long faced dubious interconnection barriers, and any would-be solar PV adopter also faces a number of obstacles—any of which could rather easily be removed if public policy were reformed. Regarding both, in fact, it is ironic that the same Energy Policy Act of 2005 that mandated doing studies of smart grids, also required that every public electric utility must offer net metering. In reality, however, it appears that this is not really happening very quickly. According to a report titled “Freeing the Grid” which was prepared by four consumer advocacy groups (the Network for New Energy Choices, the Interstate Renewable Energy Council, The Vote Solar Initiative, and The Solar Alliance), as of late 2007, 16 states still have no grid interconnection policy. Of those that do, eight are still deemed inadequate to facilitating connection. In other words, in total, about half of the US states still are not complying. Almost identical figures are reflected for net metering policies. At present, only five—California, Colorado, Maryland, New Jersey, and Pennsylvania—earned an “A” for interconnection and net-metering policies.

Simply correcting these two regulatory failings would arguably go a long way to solving peaking power problems. As has already been demonstrated in Germany, a public policy pushing solar-friendly, net-metering tariffs alone will likely spur enough investment and tech development that the result would solve grid congestion issues. Germany—which is now regarded as the world leader in solar PV—achieved this distinction primarily with PV-favorable net metering.

On the subject of adding DER to grids, Michie articulates the frequently cited utility response that, “There are infrastructure issues that need to be addressed first, so that utilities will have confidence that both distributed generation and demand response resources will respond as expected.”

A second alternative to the smart grid taking control of home appliances would be simply to promote investment in more energy-efficient ones, and let people use the “on” or “off” button as they wish. Another report (“Reducing US Greenhouse Gas Emissions: How Much at What Cost?”), issued in December 2007 by McKinsey & Company for The American Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE), reveals that “A huge potential for energy and dollar savings in the lighting, heating, and cooling of buildings” exists “...yet, substantial barriers to adoption of efficient technologies remain,” in the form of non-incentives for landlords and builders to invest in energy-efficient appliances.

The report also notes that consumers—although price conscious when asking about an appliance’s first cost—rarely pay attention to comparative life cycle energy cost. One easy solution might be to require appliance manufacturers to indicate their products’ relative energy efficiency in kilowatt-hours, right on the price tag, just as the MPG of new cars is on the showroom sticker. Another solution, suggested in the same report, is to rewrite utility regulations, so as to reward promotion of electricity conservation, rather than providing revenues solely for selling it.

Still another alternative to the smart grid (which, if it comes, will be almost wholly dependent on government mandates to make it happen, rather than on markets) might be, simply, to wait a year or two, as emerging competing technologies become better known. For example, newer inverter-based interconnections for DER and microgrids make DER relatively easier and safer to deploy. Another example is high-capacity battery storage (already widely used in Japan): Cells charge overnight and discharge at peak times. Another technology—announced in 2008 by PowerMand—is an entirely Web-based DR system, which lets any home engage in DR without other grid hardware or utility control. PowerMand’s DR would be managed by third-party energy aggregators and CSPs.

Based on its sales material, at least, PowerMand seems to have leapfrogged the national AMR grid. Given the high-powered push behind the smart grid undertaking—and the continuing rapid tech changes that surely lie ahead—it will be interesting to see what answers the GridWise folks can offer.