To date, few publicly owned and managed utilities have constructed bulk renewable generation facilities other than large hydro. They have not had strong capabilities for adopting emerging technologies and have tended to use more familiar and conventional generation equipment.

Commercialization

By itself, commercializing public utilities has little effect on renewables in bulk power markets. Still, the ability to adopt new technologies may be improved. Renewables may be considered more seriously to the extent that improved management, cost accounting, and cost recovery increase the utility's interest in choosing the least-cost approach to expanding service on a life-cycle basis.

Privatization

Similarly, privatization is unlikely by itself to increase the market share of renewables. Technology preferences for investments in new generation result partly from differences in project financing available to public utilities, private utilities, and independent power developers. When new generation is privatized and unbundled, independent power producers must generally finance projects on the basis of the expected returns from the specific project and the need to recover investment over the loan repayment period. In contrast, public utilities, backed by sovereign guarantees, often face lower costs of capital. Because even well-capitalized private developers do not have the credit capacity to underwrite the debt on a portfolio of projects whose total capital costs may be hundreds of millions of dollars, obtaining third-party debt is essential. Consequently, independent power developers face a higher cost of capital and a shorter repayment period than vertically integrated utilities. They must recover their investment over the period of their loan repayment. All things being equal, the cost of energy from a capital-intensive renewable project to either a private utility or an independent power producer is higher than to a public utility. (See, for example, Box 6.)

Because of these financial considerations, private developers prefer generation options that have relatively low capital costs per megawatt, a short construction time in order to yield revenue quickly, high efficiency, and the ability to be operated most of the time. Based on recent trends, private developers appear to favor natural gas generation (sometimes even where liquefied natural gas must be imported) due to its cost structure and short construction time. Generation options that are not favored are coal, nuclear, hydro, and other renewables. In developing countries where public power systems have relied heavily on hydro, for example, the transition to private financing has resulted in increased use of thermal generation at the expense of hydro. Hydropower is unattractive to independent power developers because of its capital intensity and relatively long lead time (for large projects).¹² In Latin America, natural gas has often displaced hydro for new generation. In Asian countries where natural gas is not available for power generation, coal often displaces hydro for new capacity.

Power purchase agreements can also affect financing for renewables, depending on the extent to which provisions in these agreements are geared to the characteristics of renewable generation options. Since most independent power projects have been thermal to date, the terms of standard PPAs are often geared to such projects. Payment schedules and other terms in PPAs may create incentives for independent power producers to choose relatively low capital-cost-per-megawatt generation technologies over options with comparable life-cycle costs but higher capital costs. PPAs often guarantee fixed price payments to developers over a limited period of time. Adequate payment schedules are particularly critical for capital-intensive power generation options, a characteristic of geothermal, wind, hydro, solar, and thermal options. Independent power developers must attract private debt financing on the strength of PPAs. They must often recover their capital investments over the fixed price contract period (generally less than the facility's life span). This is harder to do for developers of capital-intensive generation options, putting them at a competitive disadvantage relative to developers of fuel-cost-intensive options.

Renewables face other barriers in obtaining long-term power contracts. Transaction costs incurred to participate in the bidding process may favor certain technologies. Per megawatt, the costs of preparing a bid for a thermal project are less than for a renewable project. Thermal projects can be readily determined and are not particularly site-specific, allowing bids to be prepared more quickly and cheaply. Developers of small-scale renewable power sources may find the transaction costs of negotiating PPAs prohibitive.

The treatment and allocation of risks in PPAs can also be biased toward some technologies. PPAs ideally specify which party will assume different risks. Otherwise, equity owners of the project are typically assumed to bear them. For example, PPAs may include fuel cost indexing provisions that protect developers of thermal projects against the risk of future fuel price volatility.

In some countries, many of these issues have been addressed through the development of standardized power purchase agreements that include provisions on how much the utility will pay for the power over a specified period of time. Where private power projects that use renewable resources have fared relatively well (such as India, Indonesia, and the Philippines), the terms of power purchases and other policies have been explicitly geared to the characteristics that distinguish renewables from conventional power sources. (See, for example, Box 7.)

Restructuring

The conditions and rates under which independent power producers can gain access to the transmission system and use it to "wheel" power for sale directly to electricity users affect the independent power producer's choice of technologies in grid-connected applications. Transmission access has the potential to stimulate development of new renewable power generation. Because renewable resources are location-specific, developers of renewable power generation depend on access to transmission lines to sell power to the grid. Moreover, transmission access gives renewable power developers the ability to sell power to locations where, and at times when, it is more highly valued than by the local utility.

Despite legal and physical access to transmission lines, however, renewable developers may not have equal access to transmission capacity because of unfavorable contract terms. Developers of intermittent generation may be charged more per kilowatt-hour to transmit power than their dispatchable competitors. Transmission access charges may be based on a generator's maximum rated capacity or what it actually generates during peak periods. Moreover, the site-specific nature of renewables may be a drawback under some transmission pricing schemes. Rates may be based on distance or contract paths regardless of actual transmission costs or the flow of electrons. To facilitate wind power development, several states in India charge 2% of the power transmitted for wind generators to gain transmission access. (Unfortunately, transmission system bottlenecks reduce the effectiveness of this policy in some states.)

Competition

Wholesale competition is not likely to favor renewables in bulk power markets. Compared with long-term bilateral power purchase agreements, short-term or spot markets make it more difficult to finance and develop renewable generation options. For one thing, renewable projects bidding into spot markets are harder to finance than generation projects with low capital costs. Lenders are reluctant to provide debt capital for renewable energy merchant plant projects, especially in countries where spot markets have yet to establish a track record. Since lenders require that power projects demonstrate steady, predictable cash flows to meet debt service requirements over several years, the revenue risk created by unpredictable spot markets effectively precludes financing.

Spot markets are particularly unfriendly to the development of "intermittent" renewable resources that generate power when the sun shines and the wind blows. Their prices may be high for a limited number of hours in a year and not necessarily when these intermittent renewable resources are available. The inability to generate power on demand is more of a drawback in spot markets, which place a high premium on generators that can assure power availability during peak periods. Because these resources cannot be dispatched on demand, the rules governing dispatch and payment in competitive wholesale markets are particularly important in determining their value. In contrast, developers of thermal plants can secure financing because they have greater control over when they sell to the spot market and because their lower debt load gives them less exposure to a prolonged slump in market prices.¹³

Retail competition is also likely to affect the ability of renewables to compete in bulk power markets in developing countries. The incentive to retain and attract customers that is created by retail competition makes electricity suppliers seek opportunities to minimize rates and to differentiate themselves from competitors. In the United States and parts of Europe, some retail suppliers are trying to differentiate themselves by marketing "green" (environmentally friendly) electricity generation. This market niche is, however, likely to be much smaller in developing countries because environmental consciousness is generally lower and electricity costs tend to loom larger in household or business budgets.

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