Renewable portfolio standards (RPSs) of various forms have been adopted by 28 states and the District of Columbia (Figure 1). Some set voluntary goals with long implementation schedules; others—like those of Texas, which call for 5,880 MW of renewable power sales by 2015—mandate both an absolute value and a near-term deadline. Several RPSs (like those of Illinois, Minnesota, and Oregon) aggressively target a penetration goal as high as 25% but allow plenty of time to meet it (2025, in all three cases).
California’s scramble for renewable energy resources has been, for the most part, legislatively driven. In 2002, California passed Senate Bill (SB) 1078, which created an RPS for California’s three investor-owned utilities (IOUs): Southern California Edison, Pacific Gas and Electric Co., and San Diego Gas & Electric Co. The goals of this RPS included increasing total annual retail power sales from eligible renewable resources by at least 1% per year, and attaining 20% aggregate annual retail sales by 2017. Although municipal utilities were exempted from the specific provisions of SB 1078, the legislation did require them to develop their own renewables programs with the same objective as SB 1078.
n 2005, California’s Energy Action Plan and the California Energy Commission’s Integrated Energy Policy Report revised the 20% penetration level goal by calling for it to be met seven years earlier, in 2010. The acceleration made California’s RPS one of the nation’s more aggressive standards. Many expect it to become even more aggressive within a year or two, because Governor Schwarzenegger is pushing to make the minimum penetration level 33% by 2020.
State RPSs have proven to be necessary, but hardly sufficient, for renewables project development. For example, California IOUs have seen about 60% of the renewables projects proposed to them fail to evolve into viable power plants. Historically, the fatal blow has usually been an inability to secure financing, a site, or a grid interconnection for a project. Recently, however, a new obstacle has arisen in one segment of the renewable generation market: a shortage of wind turbines that has made both IOUs and municipal utilities less confident in the ability of otherwise suitable projects to help them meet their RPS goals on time.
Major wind turbine manufacturers are currently so inundated with orders that 18 months may elapse between the signing of a contract for multiple units and their delivery to a developer. Naturally, vendors are more likely to fast-track larger orders for at least 100 MW worth of total installed capacity. But that practice increases backlog times for smaller orders from the same manufacturer and limits utilities’ choice of suppliers to second-tier players with fewer commitments to multiyear orders. Inevitably, the gap between supply and demand will take its toll on wind turbine prices, which are currently running at about $2,500 per kilowatt of installed capacity.
Transmission trouble
For political and economic reasons, utilities prefer to acquire renewable generation locally. Unfortunately, because average wind speeds typically are higher (and land prices lower) far from load and population centers, most wind farms are built in remote areas. Such sites usually require the upgrading of weak transmission lines or the building of new ones to bring the farms’ production to utility grids.
Indeed, transmission remains the biggest constraint on long-term wind power development. It might take a year to build a wind farm but five or six years to interconnect it. For example, Southern California Edison (SCE) is awaiting regulatory approval of the final legs of a high-voltage transmission project designed to bring up to 4,500 MW of wind generation from several wind farms in eastern Kern County to the Los Angeles basin via the city of Ontario. Some 1,500 MW of the total would come from wind farms being developed near Tehachapi by Alta Windpower Development LLC. In December 2006, SCE agreed to purchase their output for 20 years—the biggest wind power contract in U.S. history.
Government-imposed RPSs may even have unintended negative consequences on the development of wind farms and supporting transmission lines. This August, the U.S. House of Representatives passed a comprehensive energy bill that would require all states to get at least 15% of their electricity from renewable resources, including wind, by 2020. However, the energy bill passed by the Senate two months earlier says nothing about RPSs. Reconciling the two bills has proved problematic, and the attendant uncertainty about a national RPS may have an effect on developers and lenders as chilling as the three expirations between 1999 and 2004 of the federal production tax credit (PTC) for renewable energy facilities. (More on the current PTC later.)
“You can build all the solar arrays or wind turbines in the world, but if you don’t have the transmission lines [to support them they] do you no good,” said Dan Riedinger, a spokesman for Edison Electric Institute, the trade association of U.S. IOUs. Riedinger noted that a national RPS would only exacerbate the financial challenges facing utilities by requiring them to spend more to upgrade and add lines. Investment in U.S. grids has steadily dropped over the past 30 years, while electricity demand has risen by an average 2% annually for the past few decades.
Another drag on wind power transmission development is the intermittent nature of wind. Because wind farm capacity factors rarely exceed 40%, much of the transmission capacity built to serve them is underused, limiting its installed economies of scale. For this reason, it typically costs three times more to transmit a kilowatt-hour of wind power than a kilowatt-hour from a fossil-fueled baseload plant.
Ideally, a new wind farm would be sited near an existing transmission system with sufficient excess capacity to handle its output (see Cover Story, Steel Winds). It’s more likely, however, that the farm is near a line that needs upgrading. “Reconductoring” existing lines with thicker wires is a common, cost-effective solution to the problem, even if doing so requires strengthening transmission towers to accommodate the added mechanical load. Another effective way to add transmission capacity to a grid is to erect a new set of towers and lines within an existing right-of-way.
The least cost-effective and practical approach would be seeking to build a new transmission line within a new right-of-way. Although the federal government has been pressuring its agencies to streamline the processes for approving new transmission, resistance to change has been stiff. Moreover, it may be too time-consuming for a developer to ask the Federal Energy Regulatory Commission (FERC) to overrule a state’s denial of a permit for a proposed project, even one within a congested National Interest Transmission Corridor (see POWER, November 2007, Legal & Regulatory). Odds are, whether you’re a developer or utility, you’ll have to build a substation and at least 10 miles of new, above-ground transmission to get the output of your farm to the existing grid, at a cost of $2 million per mile.
If you’re a utility resource planner, you have the usual two options—build or buy—for acquiring the wind capacity needed to help satisfy your RPS mandate. Each approach has pros and cons. Let’s start with the option of building your own wind farm.
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