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To: Rule 21 Working Group FourFrom: Julia Levin and Greg Stangl, BACDate: Revised Version, dated April 20, 2020Re: Anti-Islanding Proposal (Issue 18)BAC supports the proposals made by CALSSA in its April 10 memo to Working Group 4. In addition to the three proposals by CALSSA, BAC proposes several additional items related to anti-islanding to reduce unnecessary costs, increase transparency, and provide predictability for project developers.BAC cannot support PG&E’s current proposal at this time, as it does not appear to do anything to help reduce islanding risks or anti-islanding costs for small-scale bioenergy facilities that use synchronous generators. BAC urges PG&E to add specific data and steps to reduce the costs of anti-islanding measures for small-scale bioenergy projects required by SB 1122. BAC’s specific recommendations for PG&E’s proposal are below.BAC makes these recommendations based on recent experience with small-scale bioenergy projects required by SB 1122 (Rubio, 2012), the Governor’s Emergency Order on Tree Mortality, and numerous other laws requiring an increase in new small-scale bioenergy projects. California is relying heavily on bioenergy from organic waste to meet the state’s climate laws, in particular SB 32 (Pavley) and SB 1383 (Lara), to reduce the most damaging climate pollutants, known as Short-Lived Climate Pollutants (SLCPs). The state’s climate plan is relying on SLCP reduction for more than one-third of all the carbon reductions needed to meet the requirements of SB 32. More than 90% of SLCP emissions come from organic waste that is burned, either in wildfires or controlled burns, disposed of in landfills, piled and left to decay, or generated at wastewater treatment facilities. CalRecycle’s regulations to implement SB 1383 rely heavily on bioenergy production, as does the state’s Short-Lived Climate Pollutant Reduction Strategy.The Short-Lived Climate Pollutant Reduction Strategy states repeatedly that California must remove barriers to bioenergy interconnection to meet the state’s climate goals. For example, the Strategy points out that:“Practical solutions must be developed and implemented to overcome barriers to waste gas utilization for pipeline injection and grid interconnection. . . Stubborn barriers remain, including connecting distributed electricity and biogas projects, which have slowed previous efforts to reduce emissions of SLCPs and capture a wide array of benefits. These barriers are not insurmountable, and now is the time to solve them. State agencies, utilities, and other stakeholders need to work immediately to identify and resolve remaining obstacles to connecting distributed electricity with the grid . . . . Interconnecting distributed sources of renewable energy onto the electricity grid . . . remains an unnecessarily long and costly process in many cases.”California is also relying on new, small-scale forest biomass projects to help address California’s wildfire and tree mortality crises, which are ongoing. Governor Brown’s Emergency Order on Tree Mortality and the California Forest Carbon Plan call on the CPUC to accelerate interconnection for new forest BioMAT projects required by SB 1122. As part of the Governor’s Tree Mortality Task Force, the Governor’s Office, CPUC, PG&E, and BioMAT project developers reviewed the interconnection project costs for six projects and found that PG&E had added unnecessary interconnection requirements to five of the six projects reviewed. The average unnecessary interconnection costs across the six projects was $1 million per project. PG&E’s senior engineer acknowledged that its own interconnection staff had added a total of $5.6 million in unnecessary interconnection costs to the six projects. The breakdown – agreed up by PG&E, the CPUC, and project developers is in the table below:Project NameInterconnection CostsRevised Costs Net Savings Identified Blue Mountain $ 2,045,000.00 $1,315,000 $ (730,000.00)North Fork $ 1,257,000.00 $877,000 $ (380,000.00)Collins $ 3,305,000.00 $1,910,000 $ (1,395,000.00)Burney Hat Creek $ 4,657,000.00 $2,037,000 $ (2,620,000.00)Indian Valley $ 2,860,000.00 $2,860,000 0.00 Celestial Valley $ 5,560,500.00 $5,010,500 $ (550,000.00)TOTAL $ 19,684,500.00 $ 14,009,500.00 $ (5,675,000.00)Given the urgency of connecting new bioenergy projects and other distributed generation, BAC supports CALSSA’s proposals to:Require utilities to base anti-islanding screening on the Sandia studies to include assessment of the possibility of matching reactive power on a circuit;Revise the way the generation-to-load ratio is calculated; andAllow the project developer to hire an independent analyst to perform an islanding risk assessment.While BAC agrees with CALSSA’s proposals, we would like to note that DTT often greatly exceeds $800,000. This is particularly relevant in more rural areas of the State where the gird is radial and DTT is applied to numerous substations. Furthermore, none of these reported costs include the leased line communications infrastructure, which can be particularly expensive in less urban areas.In addition to the three CALSSA proposals, BAC proposes the following to avoid islanding while accelerating interconnection, avoiding unnecessary costs, and reducing uncertainty: The CPUC – not individual utilities - should develop a guide to anti-islanding options that clearly identifies the cost of each option and when it will be required. Costs should be all-inclusive. This “Interconnection Guidebook” should provide clear guidance to project developers so that they know exactly what circumstances will trigger a requirement for DTT and what circumstances or steps can be taken to avoid DTT. There should be clear metrics and examples provided so that developers do not have to guess about potential requirements.SDG&E Comments: We oppose this entire section, as it recommends a significant overreach of the responsibility of the CPUC to dictate the implementation of what the utility sees as prudent to ensure the safe and reliable operation of its system. Utilities should not be allowed to require more than what is in the Interconnection Guidebook unless they demonstrate the need to the CPUC in a timely manner. For instance, if the Guidebook says that DTT is not required if an end of line fault (EOL) can be seen and the generator tripped in 120 cycles (2 seconds), then the utility should not be able to deviate from that without prior – and timely – approval by the CPUC. Utilities should be required to offer least cost / best fit solutions to meet anti-islanding requirements. Most transfer trips could be achieved with a $50,000 SCADA system and a phone line or appropriate protective relays. A T1 with a $1,000,000 DTT transmitter/receiver setup is often not necessary nor preferred.SDG&E Comments: From our experience, this cost is vastly underestimated. Most overhead switches with capable relays cost $25,000 from the vendor. That does not include the cost of installation, commissioning, and communication services back to the control center. It may not be the same as DTT, but let’s not understate the cost for a SCADA switch, and pad-mounted UG solutions would cost even more.Utilities should have to justify why they are not using SCADA or protection relays such as the Schweitzer 651-R, or other options that are less expensive and require less upkeep than DTT and the basis for deciding when less expensive options are sufficient should be very clear and not up to utilities’ discretion.The CPUC should adopt an enforceable interconnection timeline so that projects do not have to wait for extended periods of time after completion to connect to the grid.BAC does not support PG&E’s current proposal as it does not seem to address projects that use synchronous generators and does not explain or provide sufficient detail for several of the items in the flowchart. BAC urges PG&E to add or clarify the following:PG&E should add an option that works for bioenergy (machine generation) to its proposal and graphic. As presented in PG&E’s April 16 draft, nothing in the flowchart that PG&E presented will help address anti-islanding for small-scale bioenergy projects.Can PG&E please explain, in writing, what the three percentage threshholds in the flowchart are based on, where they come from, or why PG&E chose those percentages. There is no explanation for the policy or technical bases of these percentage requirements.Can PG&E please describe, in writing, what an ROI study would include, any threshold requirements, other considerations, level of detail required, who would prepare, etc. Depending on what the content will be and the process for developing the ROI, it may be more helpful to move up in the flowchart, but without knowing more about it, it is hard to assess how or whether it will be helpful and, if it will, how early in the process it should be developed.Could it be considered that PGE could provide a historical example where this new methodology might be applied to a historical interconnection to see if it actually would accomplish a reduction in incidence of DTT or a reduction in the cost of the chosen anti-islanding protection scheme? ................
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