While the CPUC has parameters for what constitutes a "least-cost, best-fit" evaluation for new power supplies, San Diego Gas & Electric took exception to sharing with the California Energy Commission how it applies them when it selects renewable power contracts. SDG&E's refusal stood out at a July 1 workshop aimed at completing the 2005 Integrated Energy Policy Report because the other investor-owned utilities were happy to outline their methodologies. Under current CPUC requirements, investor-owned utilities must rank green power bidders on the basis of transmission costs, said Brian Schumacher, CPUC Energy Division supervisor. Those costs are included with generation and integration costs, along with information such as load forecasts, to determine the least-cost, best-fit ranking of the projects the utilities select for contracts. Southern California Edison and Pacific Gas & Electric generally require project developers to be able to deliver the power directly into their service territories, which further hampers the ability of many renewable power developers to enter into supply contracts, according to a recent report to the CEC (<i>Circuit<\/i>, June 24, 2005). Citing the report, Geesman called on the CPUC and utilities to "lighten up" on deliverability requirements for renewable power. The San Diego utility, however, maintains that it does not need to present its least-cost, best-fit methodology to the CEC because it is based on the uniform CPUC requirements, said Joe Cloverdan, company representative. To help utilities determine least-cost, best-fit for renewable power projects, the CEC teamed up with Davis Power Consultants to develop an alternative strategic value analysis method for determining which green power projects are economical in meeting the 20 percent renewables portfolio standard. Because transmission from outside the state is constrained, the CEC staff used the methodology solely to identify in-state renewable power projects that would be economical. A key aspect of the analysis was identifying where renewable power projects should be located to provide net benefits to the grid and minimize the need for transmission upgrades. "We can meet the 20 percent by using in-state resources, but not by 2010," said consultant Ron Davis. "By 2017, we don?t have any problem." The key hurdle in meeting the 20 percent goal in 2010 is the need to upgrade at least three transmission lines that already serve load centers with power imported from distant locations, including some outside the state. Short of those upgrades, CEC staff found that 1,485 MW of new geothermal power could be economically developed by 2010 and 2,638 MW by 2017. With some minimal transmission upgrades, CEC staff found that 2,473 MW of new wind power could become economical by 2010. An additional 3,742 MW—including 304 MW of low-speed wind power—could become economical by 2017, but only if major transmission projects are carried out. Residential solar installations could add 500 MW of new economical power by 2010 and 2,000 MW by 2017 if the pending Million Solar Roofs legislation is enacted. Because solar power is used locally, each megawatt of photovoltaic power produced on homes and local businesses provides the equivalent of 2 MW of net system reliability benefits when accounting for potential transmission problems, said George Simons, CEC Public Interest Energy Research renewables program manager. In addition, he said that strategic placement of 1,100 MW of central solar power projects in hot spots—areas where growth creates transmission bottlenecks—could eliminate the need for some transmission upgrades and provide a net system reliability benefit on the order of three-to-one. Biomass projects can contribute power too, but they are hampered by state air pollution control requirements, according to the CEC analysis. By 2017, the CEC study shows, the constrained lines would become unloaded as a result of development of distributed generation within utility service areas. However, overloads could occur on different lines, potentially requiring such steps as shutting down power plants in urban centers and changing the location of reliability-must-run units. Adjustments to power imports from out of state may be needed too. "We're bringing in more than we need," said Davis.