The California Air Resources Board unveiled draft rules at an August 16 meeting that require both power generators and retailers to report greenhouse gas emissions to the agency annually. The proposal also calls for generators and retailers to hire third party verifiers to certify their data. On August 13, the Air Board also released a new inventory of greenhouse gas emissions in 1990. Once final, the inventory will become the de facto 2020 emissions limit under the state’s climate protection law, AB 32. The proposed reporting requirements are based largely on the California Climate Action Registry’s emissions reporting standards for the electricity sector, though they are “more rigorous,” said Doug Thompson, Air Board climate change section manager. The Air Board released the rules on the same day the California Public Utilities Commission released its own draft power industry reporting rules for greenhouse gases. The Air Board’s inventory revised upward the California Energy Commission’s estimate of emissions from the power industry in 1990. As the agency revealed the rules and inventory, power industry environmental managers had plenty of questions that revolved around consistency in the underlying methods. Two of the biggest concerns were how the Air Board ultimately will deal with carbon dioxide emissions from geothermal power plants and out-of-state coal plants that supply power to California. Both the emissions reporting and inventory calculation methods for geothermal plants overestimate actual emissions of CO2 by a factor of four to five times, said Barbara McBride, Calpine environmental safety and health director. The power company operates The Geysers geothermal plants along the Lake and Sonoma County line north of San Francisco. When it comes to other power plants, particularly those that burn coal, utility representatives pointed out that basing CO2 emissions on readings from continuous emissions monitors yields a higher output of greenhouse gases than calculating emissions based on fuel usage. The difference is significant, said Bud Beebe, Sacramento Municipal Utility District regulatory coordinator. Unless there is consistency, Beebe warned, it could open the door for some to achieve phantom emissions reductions by simply changing their reporting methodology. The draft rules would allow facility operators to pick which method to use in their reports. Air Board officials said they were aware of the concerns, but that AB 32 does not allow them enough time to sort through the complications. The law requires the Air Board to adopt both a final inventory and reporting rules by the end of the year, explained Thompson. Because of the short time, power industry representatives urged the Air Board to exclude emissions calculation methods from the actual reporting rule language itself. They also called for publishing them as guidance documents that could be updated by the agency’s executive officer instead of through the lengthy rulemaking process. “We’re less than happy with the methods,” said Pam Bermish, Air Board lead staff for the electric sector. However, the agency’s legal counsel advised that mandated methods be included in the reporting rule language. Consequently, the Air Board plans to begin working on rule amendments almost immediately after the requirements are adopted to address concerns on emissions calculation methods. The controversy over the inconsistency in CO2 emissions under various reporting methods was outlined last fall in a paper presented at a meeting of the American Geophysical Union in San Francisco. The paper by researchers at the U.S. Geological Survey office in Woods Hole--”Comparison of Two U.S. Power-Plant Carbon Dioxide Emissions Datasets”--showed differences in CO2 emissions as large as 12 percent when comparing fuel usage calculation estimates to data derived from continuous emissions monitors. In general, the researchers found that the monitors showed higher emissions levels. In the Air Board’s updated emissions inventory, staff relied on Energy Information Agency data for emissions of individual power plants. The data largely are based on fuel usage. In that inventory, the Air Board’s estimate for 1990 greenhouse gas emissions from the power sector in California is higher than the estimate outlined in the California Energy Commission’s inventory. It shows that the 1990 emissions totaled 103.07 million metric tons compared to the Energy Commission’s estimate of 89.22 million metric tons, as adjusted for inclusion of methane, nitrous oxide, and sulfur hexafluoride. The difference results mostly from two major changes in the inventory method, explained Larry Hunsaker, Air Board staff member. First, the Air Board included emissions attributable to gross imports of power instead of net imports. Second, it included more specific data from out-of-state coal plants instead of just using a power mix factor. Emissions of methane, nitrous oxide, and sulfur hexafluoride also were included. “We’re basically hitting California with the biggest of the two numbers,” said Hunsaker. The Air Board is taking comments on both the draft rules and inventory and plans to consider their formal adoption in December. Editors’ note: For a more detailed version of the California Air Resources Board emissions inventory and reporting story, please see our new sister publication: E=MC2 – Energy Meets Climate Challenge. You can find it at www.energymeetsclimate.com.
