Making generalizations about how power sector reform will affect market prospects for renewables is complicated by the range of reforms, the characteristics of different power markets that renewables might enter, and the variation among countries' pre-reform conditions. Table 2 summarizes the key relationships between reforms and the different markets for renewables discussed in this paper.

Conclusions

Despite the difficulty in making generalizations, several conclusions can be drawn:

* The implications of power sector reform for renewables depend on assumptions about the pre-reform "base case." Other than large-scale hydropower, there are few cases where renewables have made major in-roads into the bulk or distributed power markets of developing countries. With some exceptions, this experience is unlikely to change under a continuation of state-owned monopoly utilities.

* Some power sector reforms enacted or contemplated in developing countries will improve market opportunities for renewable energy equipment suppliers and developers; others will not. At best, a better managed power sector will be in a position to weigh carefully new options for system expansion, especially using the distributed model. At worst, reforms that strengthen incentives to choose nonrenewable power sources represent not so much a retrenchment as a missed opportunity.

* In general, prospects for renewables penetrating distributed markets are improved when fuel and tariff subsidies are eliminated, when accounting for transmission and distribution costs is separated, and when the distribution provider chooses modes of service extension on the basis of the lowest system cost.

* Prospects for renewables in bulk power markets are less clear in the transition from public to private investment, since privatization's advantages (influx of new capital and breaking the state monopoly on power generation) are likely to be offset by its disadvantages (high discount rates and short time horizons leading to preference for thermal generation over more capital-intensive options).

* The introduction of wholesale and retail competition is likely to hurt the prospects of renewables in the absence of countervailing policy interventions. Without an explicit GHG policy in developing countries, such as carbon values imposed on fossil fuels, bulk renewable capacity may increase in absolute terms but is unlikely to increase market share dramatically. Investments in demand-side renewables are not likely to be made without appropriate regulatory incentives. This finding is particularly important for power sectors that are small or have other characteristics that make the economic benefits of introducing competition relatively modest.

* With respect to restructuring, the deployment of distributed resources will be determined by the ability of at least one player in an unbundled sector to capture system benefits.

* Renewables are likely to play a larger role if power sector reforms encourage consideration of the distributed rather than a central station model. In the near term, renewables will be most successful in competing for off-grid customers and other distributed applications where system costs for generation, transmission, and distribution are high.

* Power sector reforms have the greatest potential to improve the status quo in countries with large unelectrified populations. A privatized distribution company given exclusive access to an off-grid area can balance the returns of grid-connected and off-grid customers. It also can absorb market entry costs, achieve economies of scale in equipment and in operations and maintenance costs, exploit its existing network of local agents, and use its large cash flow to finance systems and absorb seasonal variations in customers' ability to pay.

Recommendations

The current period of power sector reform in developing countries will last for at least a decade. It offers both an opportunity and a danger for renewables. The opportunity is related to the sheer size of the various markets in which renewables can participate, and in some of which they enjoy a comparative advantage. The danger is that the rules governing reformed power sectors and markets will lock in conventional technologies. To realize the opportunity afforded by reform, stakeholders should consider the following recommendations.

Developing country governments should evaluate the implications of specific reforms on technology choices.

To avoid potentially adverse environmental effects of introducing competition to the power sector, reformers should reassess specific reform packages being considered to ensure that modest economic gains are not made at the expense of locking in nonrenewable power generation. Mitigating measures should be concurrently implemented -- such as initiating funding for sustainable energy options, drafting wholesale market rules that not biased against renewables, and advocating regulatory policies that give retail service providers incentives to offer demand-side services.

Bilateral and multilateral assistance organizations should help developing-country governments design indigenous models for power sector structure, operation, and regulation that are environmentally sustainable.

Due to the lack of indigenous alternatives, developing countries tend to adopt both electricity technologies and policy frameworks from industrial countries. Successful institutional models for the power sector that have been pioneered in one country have been widely observed among developing nations. International donors should provide technical assistance in developing indigenous structural models and institutional mechanisms for sustainable energy development that are geared to the power sector characteristics of specific client countries. For example, many developing countries might be better suited to a distributed model of power sector expansion. The distributed utility model might call for a completely different sectoral structure than reform trends in OECD countries would suggest.

Developing-country governments should enact laws and regulations that clarify and strengthen the responsibilities of privatized distribution service providers for rural electrification.

Key decisions in the privatization process include drafting the terms of sale of a utility, establishing criteria for awarding bids, creating the distribution concession contract, and determining the subsequent regulation of the concessionaire. The whole sequence of decisions has a potentially significant effect on the incentives for rural electrification based on renewable energy.

Because government retains greater leverage over rural electrification prior to the majority ownership sale of the utility, it should specify at least some fundamental rural electrification requirements in any privatization bidding document it issues. Then all bidders could assess the associated costs and risks and could factor them into the dollar value of their bids. Beyond minimum requirements, bid evaluation criteria could include business plans for serving off-grid areas in a least-cost manner. Once the contract is awarded, the state could allow a higher return if the concession meets specified performance objectives relating to rural electrification.

Developing-country governments should clarify sources of funding for rural electrification as they reform their power sectors.

Regardless of what technologies are used to electrify rural areas, associated costs are generally higher than in urban areas. Developing-country governments should consider allocating a portion of the proceeds from the sale of public distribution systems to a rural electrification account that would become available to the new owners or other entities responsible for electrifying rural areas. There are many claims on these proceeds; it may make sense to combine rural electrification with other rural development initiatives.

To increase the competitiveness of off-grid options with grid extension, all current forms of public support and customer class cross-subsidies should be equally available. Moreover, the primary distribution provider should be informed that lack of progress in extending service will force the government to solicit bids from other parties to provide this service.

Power sector reforms should ensure that distributed resource options can compete fully to provide electricity services.

The distributed resource model allows grid-support, off-grid, and demand-side renewables projects to be valued fully. Improved cost accounting would enhance utility incentives to weigh grid extension against distributed resource options. Regardless of whether the utility is functionally unbundled, power sector reforms should foster careful evaluation of the generation, transmission, and distribution costs that can be avoided by distributed resource investments.

The distribution company should be required to collect information on area- and time-specific marginal costs, which would allow more accurate analysis of the cost- effectiveness of distributed applications of renewables. Time-of-use and area rates would give appropriate price signals to end-users for consideration of demand-side renewable options. Time- and location-differentiated rates could be used first in bringing service to currently unelectrified regions and then phased in for grid-connected regions.

Least-cost resource acquisition at the distribution level would ensure a level playing field among grid extension and various off-grid options. At a minimum, regulators should require distribution concessions to estimate their location-differentiated cost of service, including generation, transmission, and distribution costs. Each area (one served by a substation, for example) would have to cover its costs. This gives distribution companies an incentive to acquire off-grid resources if they are cost-effective compared with grid extension. Regulators may need to develop least-cost analytic procedures and provide training to utilities.

Regulation of retail electricity suppliers should create economic incentives that promote full consideration of renewable energy technologies on both the supply side and the demand side.

Regulators should craft retail rate formulas that are at least neutral with respect to generation technology. For example, regulators can eliminate fuel cost pass-through and other practices that treat the risks associated with various generating options differently. However, rate-making could go further. Regulators can create regulatory alternatives to cap prices and reduce retail suppliers' incentive to maximize electricity sales. Furthermore, regulators can design performance-based rate making can be designed to explicitly encourage the acquisition of target levels of renewable resources. Retail suppliers could be encouraged to develop a diverse portfolio of resources based on rate bonuses or penalties. Performance-based regulation can also create incentives for retail service providers to invest in demand-side management by decoupling profits from sales.

Power purchase agreements need to be crafted in ways that avoid biasing decisions against renewable energy technologies competing in bulk power markets.

Developing-country governments might draft and adopt model standard PPAs that provide incentives for the selection and operation of renewable energy technologies. Provisions might include:

* premium rates for projects whose environmental performance exceeds national standards;

* payment terms (such as front-end loading) that do not discriminate against renewable energy options with comparable life-cycle costs to, but higher capital cost intensity than, thermal options; and

* explicit assignment of risks and liabilities associated with future environmental controls between power suppliers and purchasers.

As one example of the last provision, power purchase agreements could specify who will bear the risk of any climate policy, such as a carbon tax, that could increase a project's future operating costs. Although the timing and nature of such carbon restrictions are uncertain thus far, this risk is quite real, especially over the 40-year lifetime of thermal power projects. If carbon restrictions were imposed, both parties would have to agree to renegotiate the PPA.

Where transmission services become common carriers, all types of generation should have equal access to transmission capacity.

Transmission rate structures should not be biased against intermittent renewable capacity. Comparable transmission pricing would help overcome barriers to intermittent or low-capacity-factor renewables. Transmission cost structures should account for intermittency in a way that is fair to all types of generation. If the demand component of transmission charges is based on a generation facility's capacity equivalence (for example, an average level of coincident peak capacity output per month) rather than maximum rated capacity, then intermittent resources would pay more than their fair share of transmission costs. The energy component of transmission costs should be based on a significant fraction of total investment in the transmission grid.

Wholesale power markets should be required to consider the environmental characteristics of competing generators.

The calculus for determining generation dispatch priority should be based on social marginal costs -- that is, including fuel, variable operation and management, and external environmental costs. In short-term markets, the entity responsible for this would be the power pool manager. Social cost dispatch would strengthen incentives for merchant plant developers to choose technologies and fuels with low emission factors.

Realizing the Potential of Renewables

The future of renewable energy in a restructured and competitive electricity industry in the United States is currently subject to heated debate. While the interaction between power sector reform and renewables is rarely discussed in Asia, Latin America, and Africa, these regions are more likely to hold the key to the future of renewables because of burgeoning electricity demand and large populations unconnected to the grid. The massive investment in the power sector to be made in these regions holds the potential for enormous renewables markets. Whether this potential is realized depends on the path of power sector reform, which can either create new market opportunities for renewables or freeze them out. Timely interventions in the reform process by domestic policymakers, renewable energy trade groups, nongovernmental organizations, and other stakeholders would help to guide reforms in renewable-friendly directions.

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