Distributed applications constitute the largest near-term market for several renewable energy technologies. The reforms under way in numerous developing countries affect the extent to which the distributed resource model, particularly regarding renewables, is used when expanding the sector's infrastructure.

Commercialization

Commercialization generally favors renewables, at least compared with a situation in which there is no reform. When utilities commercialize, they are forced to attend to cost recovery. This means that they may reduce subsidies to rural customers, sending more accurate price signals. Better management is likely to mean better information on cost of service and more attention to the environmental implications of investment choices. A commercialized utility is more likely to identify the least costly manner of extending service to rural areas.

Commercializing a public utility may improve its incentives to implement DSM and grid support applications of renewables. To the extent that a commercialized utility has an incentive to reduce sales to where the cost of supplying the next kilowatt-hour is greater than the revenue received, it should be willing to pay up to the difference (the cost subsidy) not to have to supply that kilowatt-hour. For example, a utility could invest in photovoltaic-powered water pumps in lieu of extending the grid to farmers who would receive heavily subsidized power. Grid power could be reserved for urban customers who pay the full cost of service. In a country with unmet demand for power, this policy would not necessarily result in "lost revenues."

Privatization

Privatization has mixed effects on distributed applications of renewables. It strengthens the managerial improvements and cost recovery changes begun under commercialization. At the same time, when ownership is transferred to the private sector, the cost of capital used in making investment decisions is likely to increase. As a result, demand-side investments yield a lower rate of return than they would under public ownership because the investment is made right away while the benefits, accruing over a period of years, are discounted.¹⁰ For this reason, fewer DSM measures are attractive to a private utility than to a public one.

Second, privatization is likely to dampen interest in serving rural markets, where renewables have a comparative advantage. In some countries, the government regulator grants the new private owner a long-term concession for the right to distribute electricity to a defined geographic area that includes both urban and rural customers. Unless required by regulation, the privatized utility is reluctant to extend service where doing so does not meet its profitability criteria. The ability to cross-subsidize rural customers is limited. Shareholders may require higher rates of return to justify investments in rural markets, which are viewed as being relatively risky. In addition, the utility may or may not have the authority, interest, or expertise to pursue other means of providing electricity services to rural areas. To address these issues, the Government of Argentina is implementing a "rural concessions program" (see Box 5), and Brazil is considering a similar initiative.

Third, public utilities have often pursued other social objectives in addition to universal electrification that may have involved deployment of renewables, such as economic development and technology commercialization. When a utility is privatized, its pursuit of social objectives in response to national policy or political mandates wanes. The responsibility for implementing such objectives transfers to regulators, who seek to balance these goals with the utility's economic well-being.

Fourth, the form of regulation that accompanies privatized retail services affects the incentives for end-use customers to invest in on-site renewables. Under some tariff structures, customers could see fully itemized rates based on area- and time-specific energy, transmission system capacity, and distribution capacity costs. Depending on the previous structure, such rates could improve ratepayers' economic incentives for managing their demand and reducing consumption. Key factors include how costly it is to install meters that charge according to time-of-use, whether location-specific costs can be differentiated, whether hook-up fees reflect the customer's load, and whether meters are allowed to "run backwards" to credit on-site generation. Regulators might also adopt policies to improve incentives for electricity suppliers to make demand-side investments that reduce system-wide costs.¹¹

Restructuring

The implications of separating a utility into independent firms that individually provide generation, transmission, distribution, and retail services for distributed applications of renewables depend on how the allocation of costs changes. Before unbundling, a utility can calculate the value of distributed generation by adding up the costs associated with central station generation, transmission, and distribution that are avoided. After unbundling, the entity most likely to be considering distributed generation investments (the distribution company) may not be able to fully identify, value, and capture upstream generation and transmission costs that would be avoided by such investments. At best, the way that upstream costs are passed through in an unbundled power sector would not diminish the cost-effectiveness of distributed generation to a distribution company. At worst, unbundling causes the set of attractive distributed generation investments to shrink. Still, distribution companies might find some such investments to be cost-effective in locations where:

* the marginal costs of service are particularly high due to network constraints;

* service must be extended to customers with low loads who are far from the grid; and

* sharp local peak demand results in inefficient use of distribution assets.

Competition

Competition affects the attractiveness of investments in distributed renewables in several ways. First, a thriving competitive wholesale market should drive down generation expenses, thus reducing the costs that can be avoided by distributed renewable installations. Spot markets, for example, often operate on the basis of competing generators' short-term operating costs. Compared with long-term power purchase agreements based on full costs incurred over a project's life, spot generation markets weaken the incentive to invest in distributed renewables whose costs must be recovered over a period of several years.

Second, competition among electricity suppliers for retail customers creates an incentive to minimize capital investments that would put upward pressure on rates in the near term, even if they would hold down rates in the long term. Over time, the focus of retail competition may shift from low cost to customer value. If so, retail suppliers may offer packages incorporating distributed renewables, including demand-side applications, to differentiate themselves from competitors.

Third, competition at the wholesale and retail levels is likely to make retail rates more variable and less predictable. End-users investing in demand-reducing measures face the risk that the dollar savings over the life of the measure may be less than expected. This risk is exacerbated when future electricity costs are less certain.

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