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12-15-2003
Distributed Energy’s Promise
Tom Lord for Harts Energy Markets
The Blackout of 2003 has raised the clarion call for transmission system reinforcement. Electric utilities and transmission operators will propose and make billions in improvements, and the regulatory authorities will include these investments in rates. However, transmission is only one-half of the problems plaguing the electric infrastructure. The second half of the problem is the local distribution grid in America’s cities. Though less obvious, this may be an even larger challenge, because it requires the cooperation of local government and customers, as well as innovation in financing. Distributed energy resources, not more wires, may provide economical solutions; however the financial incentives may not readily reward customers and service providers who help address the problem. But there are those in the market seeking to connect emerging and alternative technologies with investors. The case must be made for why distributed energy will be a winner in the short to mid-term to attract investment.
A significant number of urban distribution networks will reach critical loading levels within the next 10 years. More than 10% of existing substation-level distribution grids in urban areas have been identified as reaching “critical” loading levels within the next 15 years. In most cases, some would reach those levels in less than five years. Critical loading means a greater than 50% likelihood that the individual area distribution network would not have sufficient capacity to meet the peak load demand for at least one day a year.
These problems are arising because central urban distribution grids are not static, and they continue to experience significant load growth. The American lifestyle and business practices are electricity intensive. Finding a location for new substations, adding lines to increase capacity, the costs of construction and dealing with the disruption of the surrounding area are all difficult problems. Moreover, distribution grids are being relied upon to do more and more, moving from a “dumb grid” to a “smart grid.” So what can be done?
NOT JUST GENERATION
The electric industry is looking to distributed energy– not just distributed generation, but also process control technology, efficiency and demand management technologies and other emerging energy technologies–to benefit both utilities and their customers. The utilities are looking to shed peak load demand in critical areas. They would definitely prefer not to lose the load completely–after all, their revenue comes from providing commodity and other services through their lines. If the load is satisfied completely by internal resources, they lose all their revenue.
If the business owner–industrial, commercial or residential property manager–can offer to avoid utility capital investment by placing DE resources on site while still assuring the utility of reduced peak and constant off-peak service needs, everyone wins.
The first place the utility wins is by being able to show utility regulators that it is seeking innovative solutions that allow all existing customers to share the benefits of managing system needs without massive capital investment. In addition, the utility can show customers and regulators that it is maintaining the reliability and affordability of urban power grids while encouraging existing large customers–frequently important employers in local economies–to retain their urban presence. Finally, the utility is able to retain a significant amount of its revenue from providing service–avoiding the negative impact of either complete load loss due to the customer providing all its power supply “behind the fence” or from a decision of the customer to relocate for power quality reasons.
Variable demand-side management technologies–such as remote equipment management controls–can allow the utility to manage demand within constraints negotiated with the customer. If the incentive offered by the utility is appropriate, then the customer saves, the utility saves and capital investment may be avoided. The solutions could include control technology, dispatchable distributed generation, energy efficiency technologies that address peak hour usage and other emerging technologies. An important part of the acceptance of these technologies and their financial success will be the ability of the DE provider to understand the needs of the utility marketplace and craft technologies that benefit all parties.
LEGITIMATE TECHNOLOGIES
One note of caution for the DE providers and the end-user community is that utilities seeking this type of solution are also seeking to insulate themselves from the common emerging technology “vaporware.” A manner in which they may do so is to set minimum performance standards for the behavior of the DE as observed by the utility. That means that the utility may monitor the peak load for the customer as compared to some predetermined “baseline” behavior. The establishment of a baseline and the application of rigorous evaluation criteria have become standard in the industry. If the DE does not perform as promised and the utility requires future capital investment, the DE provider or the end-use customer might be at risk for the capital investment. The need for DE providers to meet these requirements could have significant impacts on the future financial performance of DE providers.
The second benefit opportunity occurs simultaneously for the utility and the end-use customer. There is a reduction in the hedging risk for both. The regime of rapidly increasing prices at peak hours occurs when generators recognize that peak demand is increasing at a rate that makes high-cost, marginal plants certain to be used later in the day. At that time the generators can start offering premium prices on lower cost plants in the wholesale market because they are certain that demand will be such that end-users will be required to accept the offered prices. Distributed energy can help change that environment. Giving customers a new demand management tool ensures that prices become more elastic because their behavior is more flexible.
REDUCING PEAK DEMAND
Just as DE can reduce infrastructure investment needs, it also can reduce the amount of energy required at peak times. This translates into a reduced risk for the party that must purchase power–either the end-user, if it buys on the deregulated market, or the regulated utility if it is buying to serve tariff customers. This means the overall cost of energy for the purchasing party is reduced.
Therefore, if an end-use customer is a wholesale energy buyer, the total risk of its energy purchasing portfolio is diminished. Since the peak load is usually uncertain, the DE investment is reducing the amount of options that would potentially be required to manage the corporate energy risk. This amount of risk could be calculated and valued in comparison to the cost of the DE investment; this “savings” could be applied to the investment cost.
Even if the end-user is a wholesale energy buyer, the utility benefits again. The DE investment reduces the amount of energy the end-user is buying at the peak. In turn, the regulated utility now has less competition for potentially scarce resources during the peak hours. This should translate into marginally lower wholesale energy costs during peak times–thereby reducing the annual cost of energy for all customers.
In the case where the end user is a tariff customer, the regulated utility benefits even more. The end-use customer could provide access to the DE capabilities as a call option for the utility. In this manner, the utility can utilize the DE flexibility against the broader portfolio of the total utility customer base. It is possible that the utility might have instances where utilizing the DE resource would be economic for all customers at times when the end-use customer might not have an economic incentive to utilize the resource. As long as the utility makes the arrangement economically neutral for the end-use customer there can be mutual benefit.
For instance a facility operator wants to identify financing options for a small (>1 MW) generation and chiller set on the plant site. The customer for the facility wishes to avoid the risk of time-of-day pricing while assuring power quality. The potential for gain exists in a number of dimensions. While this is a fairly common project type, the analysis of the reduction in the price risk associated with load variability in peak hours is less common. The economics are not just the examination of the cost of output from the on-site plant versus the cost of grid power; they also include the reduction in price uncertainty by having the plant. The interesting point of DE cost examinations is the reduction in uncertainty can come from any number of DE technologies – on-site generation is only one selection from the spectrum of choices. In addition, the load reduction will occur in a transmission-constrained urban center, thereby reducing the potential need for the utility to make capital investment in transmission and distribution grids. It may be possible to negotiate with the utility to “capture” some of that value for the project.
One thing the end-use community and DE providers must recognize is that the “win-win” benefits occur for peaking needs. The use of DE to impact overall demand beyond the level of peak demand reduction necessary to avoid distribution grid investment has the potential to benefit the DE user while penalizing other utility customers. At this point, the “win-win” can become a contentious “win-lose” situation with the utility imposing stand-by and other service charges that can negatively impact the project economics.
POTENTIAL PITFALL
In the current regulatory regime, the utility spreads all costs over its regulated services. If the end-use customer reduces annual demand across a broad range, the utility will lose more revenues than money it will save from reduced capital investment and peaking costs. At that point, the utility has an incentive to obstruct the use of DE resources. It may be that load growth in certain areas may exceed the utility capability to serve with existing facilities across a broader time period. In this case more extensive DE investments may be beneficial to all. If regulators aligned the cost recovery incentives with reality, the utility would behave in an economically efficient manner, but under current practices it makes sense for the utility to obstruct some DE.
In the current economic environment of constrained capital budgets, utilities could be expected tightly control the use of investment dollars, stabilize earnings, and retain customers. The DE provider community is looking to create sufficient inroads into the energy market to attract new capital and broader investor interest. Utility commissions are seeking to further their goals of lowering costs, lowering volatility of energy bills and reducing environmental impacts from the energy system. The DE market has the ability, if fostered by all three groups plus the investor community, to further all those goals.
While DE is good for local distribution grids, its benefit can extend well into the transmission grid. The investment called for potentially exceeds $50 billion. Most of the need for grid reinforcement comes from peak-hour demand. The scenarios noted above all deal with reduction of peak-hour demand. There is the potential that DE, appropriately deployed, can help to reduce a significant amount of that capital investment requirement. That would reduce energy transmission costs and competition for capital. DE may not be the answer to every ill, but it does have the potential to help solve some significant economic issues facing the nation’s utilities, consumers and corporations.
The scenarios described above call for DE resources that can behave in specific operating ranges with a high assurance of results. The potential for economic success of the DE provider community is not tied to these scenarios. But investment success is likely to result from targeting services and products to the specific regulatory, technical and economic drivers in the wholesale and retail energy markets. |
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