Next week might well be termed “transmission corridor week” in California as federal and state agencies hold public sessions on the topic. On May 14, the California Energy Commission is set to host a workshop on transmission matters that performs a double duty. It kluges the biannual “Strategic Transmission Investment Plan,” and seeks to streamline the somewhat confusing siting process for transmission lines in an attempt to improve system reliability and access to potential renewable resources – the latter in response to last year’s SB 1059. State regulators are investigating the designation of in-state transmission corridors – separate from, but complementary to, the Department of Energy process. On May 17 in San Diego, the Department of Energy will have its only scheduled Western meeting to vet the pending “national interest electric transmission corridor” designation proposal. As described by the Energy Commission, the state process is most concerned with identifying potential corridors that would be beneficial to the development of renewable energy resources in California. Regulators also intend to help the state meet the requirements of its renewables portfolio standard while increasing the reliability of the state’s energy systems and improving fuel diversity. Corridors are just one aspect of the workshop, as the CEC delves into all manner of issues related to anticipated utility loads, planning alternatives, estimated costs and benefits, and a review of the current status of projects. Transmission planning is a long-term process. Even though utilities, the California Public Utilities Commission, and the California Independent System Operator last year finally extended their grid planning horizons from 5 to 10 years, the CEC wants to go farther. Staff have proposed expanding the planning horizon to 10 years for specific projects to be included in the strategic plan and make 20 years the event horizon for transmission corridors. In data responses to staff inquiries for the workshop, municipal and investor-owned utilities provided something of a wish list for new transmission projects that may or may not ever be built. These include simple substation upgrades, bolstering of existing paths, and, in a couple of cases, ambitious new pathways. We already know about the big projects that would fall within the Western DOE corridor (if that process doesn’t get scuttled by opponents in Congress). Sunrise Powerlink, Tehachapi, Green Path, and the Western Frontier lines all have been in the public eye. In fact, they probably won’t be affected much by the DOE process because they are already far along the path toward certification (Circuit, May 4, 2007). More interesting are nascent high-voltage proposals planned within the region. Lying outside of the DOE proposed corridor in Southern California, they come mainly from Pacific Gas & Electric or munis. By my count, they collectively would exceed $4 billion in investment (based on incomplete information) and potentially could open up whole new areas to power development – undoubtedly raising anew issues of environmental impact and NIMBY opposition. Whether they deserve to be incorporated into a special state corridor designation remains a decision for regulators. Those who crave specifics should, of course, attend the CEC workshop in person or electronically. Here I’m going to note a couple of the significant proposals and offer thoughts as to what we might expect. The most ambitious project appears to be PG&E’s Midway-Gregg line, a 150-mile, 500 kV line costing between $800 million and $1 billion. The route is essentially a 1,200 MW expansion of Path 15 capacity – akin to adding a fourth lane on this crucial electric superhighway down the Central Valley. What is interesting about this plan is that it would be geared to improving south-to-north flows, signaling PG&E’s eagerness to access the same renewable energy sources that Southern California utilities are hoping to tap with the Sunrise, Tehachapi, and Green Path lines. A more limited project, the $200 million Gates-Gregg 230 kV project, is something of a backstop plan, in case PG&E once again runs into regulatory or local roadblocks to Path 15 expansion. The 60-mile line would not really be needed until 2016 – mainly to improve Fresno-area reliability and increase use of the Helms pumped-storage plant – but if Midway-Gregg were built, it wouldn’t be needed at all, PG&E says. The Transmission Agency of Northern California (TANC) has identified six potential projects, ranging from attempts to improve interconnection among the muni consortium’s members to a possible 300 MW expansion of transport capacity on the California-Oregon Intertie through installation of new capacitors at key substations at Captain Jack, Olinda, and Tracy. This project appears remarkably cost-effective, as it would cost only $34 million and entail no new permitting. Of TANC’s other long-term plans, one that is known currently as Zeta would also attempt to increase access to the Pacific Northwest, where new wind and the seasonal hydro power is always of interest to California consumers. The Zeta project would include 173 miles of new 500 kV transmission and two new substations, at a cost of about $560 million. Though most of the planned route follows existing rights-of-way, it could represent a major new interconnection to the Northwest, TANC says. So far, these ambitious projects seem to make economic sense, and because they largely parallel existing grid paths, they might not encounter much resistance (so to speak). In contrast, the Los Angeles Department of Water & Power is fast-tracking a 480 MW expansion of the existing DC Intertie with the Intermountain Power Plant in Utah, which would raise import capacity to 2,400 MW. That’s 2,400 MW of old, coal-fired power. While LADWP says it could have the $100 million project operational by December 2008, I’m not sure it will ever happen. Come this summer, the CEC will have adopted its rules for a “generation performance standard” for munis that will discourage any new long-term investment in coal power that does not match or beat the emissions profile of a state-of-the-art natural gas power plant. If the new greenhouse gas emission limits are anything like those adopted by the CPUC for investor-owned utilities, we could see our first test case of litigation over how far the Energy Commission can go in regulating business decisions by public power entities.