Desert Renewable Energy Conservation Plan

Transcription

1 **THIS IS A CONSULTANT WORK PRODUCT AND HAS NOT BEEN REVIEWED BY THE REAT AGENCIES** 3.5 Renewable Energy Goals The State of California has a long-term goal of reducing statewide greenhouse gas (GHG) emissions by 80% below 1990 levels by For the state to reach these goals and avoid the worst impacts of climate, change a wholesale reshaping of the energy system will be needed. It is likely that electricity generation will have to shift from carbon intensive fuels sources, and accommodate the electrification of the vehicle fleet, as well as a growing population 3. Consequently, the renewable resources in the desert necessary for meeting the state s future energy needs. The purpose of the DRECP is to conserve Covered Species while streamlining permitting for renewable energy development related to state and federal policy Federal/BLM Renewable Electricity Goals As discussed in Section 1, a number of Executive Orders (E.O.s), Congressional mandates, and federal agency orders are designed to promote the development of domestic renewable energy resources. The BLM, as the predominant federal land management agency in the desert, is charged with the successful development of solar energy that is consistent with protection of other important resources and values, including units of the National Park System; national wildlife refuges; other specially designated areas; wildlife; and cultural, historic, and paleontological values. At the same time BLM, is seeking to facilitate renewable energy development under Secretarial Order 3285A California s Renewable Electricity Goals Since 2002 California has had, a state mandated Renewable Portfolio Standard (RPS), that requires a minimum percentage of the retail customers electricity sales to be from renewable sources. Initially the RPS was designed to diversify the state s electricity generation and reduce dependence on natural gas. Subsequently, the RPS has become a fundamental component of the state s efforts to reduce greenhouse gas emissions and switch to a low carbon economy 4. 1 Executive Order S Signed June 1, Executive Order B Signed March 23, Staff Draft Report on Renewable Power in California: Status and Issues. California Energy Commission, August 2011, Publication No. CEC Senate Bill X1-2 (Simitian), California Renewable Energy Act. Signed April 12,

2 In its Climate Change Scoping Plan report, the ARB (Air Resources Board) identified the percent RPS target as a foundational policy for meeting the 2020 GHG emission reduction goal. And a necessary precursor to the overall state objective of reducing GHG emission to 80% of 1990 levels by Preliminary estimates of the amount of renewable energy needed to achieve the 2050 GHG emission reduction goal suggest that California s renewable electricity percentage may need to increase to more than 70 percent, depending on the pace and policies affecting electrification of the transportation sector, retiring coal generation, and whether existing nuclear plants are relicensed Overview of the DRECP Renewable Energy Planning Process In support of the state and federal renewable energy goals the Plan aims to provide a streamlined permitting process and identify desert locations that are compatible with renewable energy development. The following sections summarize the underlying assumptions and range of parameters used during the development of renewable energy goals for the DRECP. REAT agencies and stakeholders identified three principles to guide the identification of areas compatible with renewable development. Where feasible, generation should be developed either on already disturbed land or in areas of lower biological value, the biological value to be determined by the full conservation and reserve design process. Generation should, where possible, be aggregated to avoid transmission sprawl; reduce cost; and reduce disturbance across the Plan Area. Again, this principal facilitates the least disturbance to biologically valuable areas. Finally, the plan should be sufficiently flexible to maintain a market neutral approach and avoid any artificial constraints evolving because of the Plan. Identifying the best locations for renewable energy is a multi-stage process anchored in assumptions about current and future California energy policy. To plan for future energy development the REAT agencies took the following steps to estimate the contribution of the desert to California energy goals. 1) Estimate the possible future contribution of desert based generation to California s energy generation portfolio, based on future policy trends, using the CEC Renewable Energy Portfolio Acreage Calculator Staff Draft Report on Renewable Power in California: Status and Issues. California Energy Commission, August 2011, Publication No. CEC

3 2) Estimate the minimum acreage for the footprint of renewable energy development accounting for difference in technology, siting, permitting mitigation issues encountered when developing projects. 3) Use agency and stakeholder input to identify and characterize areas suitable for renewable energy development based on the principles laid out above. 4) Develop an overarching transmission plan that serves the predicted generation capacity and distribution. The following sections contain the assumptions and parameters underlying the estimated generation capacity and associated acreage requirements expected from desert based generation. Acreages are estimated for the entire Plan Area, and more detailed breakdowns are given in later chapters. Specific geographical layout of different technologies and the description of Development Focus Areas (DFAs) are included in Chapter 6. Finally, transmission planning goals and assumptions are described in this section but, again, the specific details are described in Chapter Estimating Future Generation Capacity Requirement from the Plan Area The lifespan of the DRECP permit is for up to 27 years (i.e., out to 2040). Given the longevity of the Plan, it is necessary to estimate the energy needs of California out at least to Energy Commission staff formulated renewable development scenarios for 2040 under the assumption that the state s electricity sector will achieve its GHG emission reduction target of 80% below 1990 levels by The amount of incremental renewable energy required in 2050 may be in excess of 400,000 GWh, roughly ten times what is currently in place to serve California loads. The 2040 scenario, that approximates the expected lifespan of the DRECP, posited an incremental need for 194,000 GWh of renewable energy; enough energy to meet a 58% reduction in GHG emissions from 1990 levels. Achieving these goals requires a dramatic reduction in electricity generation using fossil fuels, and is further complicated by many different factors, including the expected increase in the electrification of the transportation sector and possible retirement of the current nuclear generation fleet. Many technological or policy changes may result in different generation portfolios over the next twenty-five years. It is necessary to consider the direction and magnitude of many of these energy policies in California in order to develop a robust plan for renewable energy development in the desert. 6 The following section is taken directly from and 2050 Acreage Needs for Renewable Generation memo sent to Covered Activities and Resource Mapping working groups on Oct. 21,

4 The following scenarios, assume that out-of-state resources will meet one-quarter of renewable energy generation. The remaining need would be met from in-state generation. It is estimated that by 2040 the state will require 22,000 to 33,000 MW of central station solar, most of which is assumed to be in the Plan area. In addition, 19,000 MW 28,000MW of wind is required. This conclusion is despite assuming that baseload renewable resources (geothermal, biomass) will be at levels that exceed their current economic/technical potential, and that distributed generation will far exceed current targets. It should be noted that the renewable resource portfolios developed by CEC staff were not constrained by the need to meet demand as represented by an assumed load shape. For example, most representations of futures in which the transportation sector is substantially electrified assume a substantial increase in off-peak loads, and thus the need for generation, both renewable and otherwise, that is available during off-peak hours. Here staff assumed that the scenarios developed are plausible given the potential for technological advance, (e.g., improvements that allow for large amounts of distributed generation, advances in storage technologies), combined with the availability of hydroelectricity and wind during off-peak hours and the potential for load-shifting. Further, the potential impact of climate change on the amount of hydroelectric energy available was not considered. Reductions in hydroelectric energy would require additional energy from zero-carbon resources in order to leave GHG emissions unchanged. More specific policy and growth assumptions, that will affect energy demand in the 2040 scenario are as follows: Demand Growth of 1.5% per year was assumed in line with recent economic/demographic projections used by the Energy Commission s Demand Analysis Office. Demand Reduction due to Energy Efficiency programs was assumed to be % per year which is slightly better average of % per year The two in state nuclear facilities (Diablo Canyon and San Onofre) were assumed to be retired, although the Palo Verde facility in Arizona was still assumed to be operating. 18 million hybrid and full electric vehicles were assumed to be in use in ,000 GWh of renewable energy was assumed to be provided by existing in-state renewable resources that would still be operating or replacement resources located at the same sites. No fossil generation with sequestration was assumed operational. 3-4

5 The efficiency of natural gas-fired generation was assumed to be 7,400 Btu/kWh. The percentage of total energy (net energy for load) needed to be stored was assumed to be 10%. No renewable resources were assumed to be built in California to serve out-ofstate loads. High-speed rail was assumed to be developed during the 2040 s, requiring 13,000 GWh of energy in the 2050 scenario. Renewable energy from out-of-state was assumed to provide 25% of the renewable energy required to meet the GHG reduction target in each scenario. While many permutations of these assumptions are possible it is perspective of CEC staff that the above set of assumptions provide the best scenario to analyze when making conservative planning projections for desert based generation Estimating the Plan Area Contribution to State-Wide 2040 Renewable Energy Goals A range of MW estimates for likely statewide generation portfolios were calculated and then scaled to the DRECP. The following assumptions concerning the relative proportion of each technology occurring in the DRECP were made: 100% of all California s central station solar thermal would be located in the DRECP; 70% of all California s central station solar PV would be in the DRECP; 50% of all California s the wind would be in the DRECP; 3,000 MW of the geothermal would be in the DRECP; and 27.5 % of the utility-side DG would be located in the DRECP. Table illustrates the relative contribution of the DRECP for example portfolios of 40% wind to 60% Solar, and 60% wind to 40% solar. in the statewide energy portfolio. In light of the above assumptions, an expected reasonable range of generation capacity required from the Plan Area was in the region of 20,000 to 22,000 MWs. Table Relative Generation Contribution of the DRECP Under Different Solar to Wind Ratios 2040 Solar/Wind 60/40 Solar/Wind 40/60 CS Solar Thermal 4,900 3,

6 CS Solar PV 6,860 4,550 Wind 4,175 6,250 Geothermal 3,000 3,000 Utility Scale - DG 3,025 3,025 Total 21,960 20,075 Accounting for Operational Projects or Projects Under Construction The CEC acreage calculator accounts for all projects that were operational as of December 2010 when deriving the target MWs requirement. Numerous projects are currently under construction and will become operational between then and the date that the DRECP goes into effect. All projects known to be in permitting were tracked by the CEC and only those that were either operational or under construction as of were subtracted from the target generation capacity requirement to reduce the target DRECP contribution Estimating Acreage Requirements for Generation within the Plan Area Conversion of the generation capacity requirements (MWs) to an expected acreage requirements is reliant on an estimate of the average energy yield per acre, which is quoted as acres required per MW (Table 3.5-2). In addition to the yield estimates micro-siting and mitigation land further increase the acreage needed for each development (Table 3.2-4). Estimating Yield per Acre Energy yield per acre is technology dependent, consequently the minimum acreage requirements to accommodate the expected generation is dependent upon the assumptions made about technology mix. The yield represents the minimum acreage requires to generate a megawatt of energy. The specific assumptions made concerning the average acres per MW of generation capacity for each technology are given in Table

7 Table Acreage Requirements per MW of Generation Capacity Technology Central station solar thermal 7.1 Central station solar PV 7.1 Wind 40 Geothermal 5.0 Utility Scale DG 7.1 Acres / MW For all portfolio scenarios acreage requirements (per MW) associated with each technology were held constant. It was not realistic to assume that changes in the acreage requirements associated with a given technology can be projected with accuracy or that an aggregate change in these requirements due to across-the-board technological change can be posited with any confidence 7. Given the acreage generation portfolios in Table and minimum acreage requirements described in Table a range of between 314,891 and 360,981 acres is reasonably required to accommodate (Table 3.5-3) example generation portfolios. Table Estimated Acreage Required to Accommodate Renewable Generation Solar/Wind 60/40 Solar/Wind 40/ Acres Acres CS Solar Thermal 34,790 23,075 CS Solar PV 48,706 32,305 Wind 167, ,000 Geothermal 15,000 15,000 Utility Scale - DG 21,478 21,478 Total Minimum Development Acreage Required 286, ,858 The overall range of acreages is strongly sensitive to the proportion of wind generation in the portfolio. This is driven by the need for 40 acres per MW of wind generation. For example, the extreme scenarios of 0% wind (Maximum Solar) and 0% solar (Maximum and 2050 Acreage Needs for Renewable Generation memo sent to Covered Activities and Resource Mapping working groups on Oct. 21,

8 Wind) generation give affected acreages of 149,616 acres and 673,878 acres respectively. These extreme scenarios illustrate the range of possible variability. It should be noted that the above portfolios are working examples. Resource constraints may limit the acreage available to a specific technology e.g. wind. As a consequence, the resource portfolios analyzed in the plan may look substantially different to those presented in table Estimating Acreage Required for Developing, Siting and Mitigating a Project The process of siting, permitting and constructing a facility requires more land than the minimum acreage assumed necessary for energy generation. To account for the many factors that may affect the location and configuration of a project a multiplication factor was developed. The multiplication factor s intent is to integrate a variety of different factors that affect siting, including ownership, and land parcelization issues, as well as permitting conditions such as mitigation measures and resource avoidance. For example, areas of the plan that are highly parcelized require more initial acreage for siting than areas of the plan with larger parcel sizes. Similarly public lands that have been studied within the Solar PEIS are viewed as requiring a lower multiplication factor. In addition, avoidance of significant local resources e.g. wetlands, may requires additional land for avoidance, or where avoidance is infeasible, the developer may be obligated to mitigate the impact by the provision of long-term easements that preclude further development. These multiplication factors are a rule of thumb, estimator that is geographically specific, and influenced by factors given above.. The multiplication factor ranges between 3 and 5, the typical characteristics for each factor are given in Table Inclusion of a multiplication factor gives a global indicator of the acreage required within the plan area to achieve generation goals. Table gives the range of expected land requirements for the example Solar/Wind Portfolios with different multiplication factors. More detailed description of the range and geographical distribution of multiplication factors are given in chapter 6. Table Siting and mitigation multiplication factor Range and Description. Description Public land or Low degree of Parcelization; minimal mitigation land requirements Private land and/or highly Parcelized ; greater mitigation requirement Value

9 Table The range of acreage required for each technology given the effects multiplication factor 2040 Solar/Wind 60/40* Solar/Wind 40/60** Acres Acres CS Solar Thermal 104, ,375 CS Solar PV 146, ,525 Wind 501,000 1,250,000 Geothermal 45,000 75,000 Utility Scale - DG 64, ,388 Total 860,921 1,709,288 * Multiplication factor = 3 for all technologies **Multiplication factor = 5 for all technologies Renewable Energy Resource Distribution and Development Potential Most of the DRECP is recognized as world-class renewable energy resource. There is potentially 10 million acres of solar, 11.5 million acres of wind resource within the DRECP boundary. The following section describes the information used to characterize renewable energy potential, and describes the development assumptions used to refine that potential within the Plan Area. Resource Data Not Refined by Development Potential The following is an assessment of the potential areas suitable for renewable energy development in the Plan Area, using unconstrained resource data (i.e., resource data not refined by development potential). Tables through provide the acreage of solar, wind, and geothermal resources within the Plan Area. Figures through show the distribution of each of these resources within the Plan Area. Solar Based on NREL 2009 data for solar resources (measured by direct normal solar insolation; see Table 3.5-6), approximately 10 million acres within the Plan Area have potential for the development of solar resources (areas with insolation greater than 6.5 kilowatt-hours per square meter per day). Figure displays the various levels of solar insolation measured in kilowatt-hours per square meter per day in the Plan Area. Geographically, the highest insolation values and greatest concentration of solar resources based on these data are located in the west and central Mojave regions (Figure 3.5-1). 3-9

10 Table Solar Resources within the Plan Area 1 Solar Resource 1 Plan Area Acreage , , ,294, ,299, ,299, ,457 >8.0 29,683 Other 12,957,441 Total 22,586,912 Direct normal solar insolation measured in kilowatt-hours per square meter per day (NREL 2009). Wind Based on NREL 2009 data for wind resources (measured by meters per second at 50 meters (164 feet) above ground level), approximately 1.5 million acres within the Plan Area have potential for the development of wind resources (wind speeds greater than 5.6 meters (18 feet) per second are considered suitable based on the categories used in this dataset; see Table 3.5-7). The highest wind speed values and greatest concentration of wind resources based on these data are located in the Tehachapi region and various mountain ranges in the central and eastern Mojave regions (Figure 3.5-2). Table Wind Resources in the Plan Area 1 2 Wind Resource 1 Plan Area Acreage ,979, ,759, ,557, , , ,013 > ,312 Total 22,582,761 2 Wind speed measured in meters per second (NREL 2009). Approximately 4,200 acres of the Plan Area had no wind resource data. 3-10

11 Geothermal Based on California Energy Commission (CEC) 2010 data for geothermal resource areas, approximately 350,000 acres within the Plan Area have been identified as known geothermal resource areas (KGRAs), as summarized in Table The geothermal resource areas are concentrated in the Salton Sea and Imperial Valley areas, south of Owens Valley in Inyo County, and the north central Mojave area (Figure 3.5-3). Table Known Geothermal Resource Areas in the Plan Area Known Geothermal Resource Area Total Coso Hot Springs 17,844 Dunes 7,723 East Brawley 70,536 East Mesa 37,798 Glamis 25,986 Heber 58,995 Randsburg 12,948 Salton Sea 103,190 South Brawley 12,779 Non-Geothermal 22,239,113 Source: CEC 2010a. Total 22,586,912 Geothermal resource data reveal specific areas where the resource occurs. There is also additional geothermal resource information in the following sources: Southern Methodist University (SMU) Geothermal Laboratory: The Surface Heat Flow Map developed by SMU (SMU 2004). NREL: USGS Assessment of Moderate- and High-Temperature Geothermal Resources of the United States (USGS 2008). International Heat Flow Commission: The Global Heat Flow Map BLM Division of Energy: The BLM has the authority for leasing on more than 245 million acres of public lands (including 104 million acres of National Forest managed by the U.S. Forest Service) with geothermal potential in 11 western states and Alaska. Relevant analyses conducted by the BLM in consideration of leasing applications within the Plan Area include the following: 3-11

12 o BLM Western United States PEIS: The BLM completed a geothermal PEIS in May o BLM Truckhaven PEIS. o BLM West Chocolate Mountain PEIS - Published June o o o BLM Haiwee PEIS - The Notice of Intent for the HGLA planning effort was published in 2009, and the PEIS has not been distributed for public review to date. Imperial Sand Dunes Recreation Area (ISDRA) - The draft Recreation Area Management Plan PEIS was published in March Superstition Mountains - U.S. Navy recently completed a geophysical study Imperial Irrigation District Geothermal Resource Assessment: The Imperial Irrigation District prepared a Geothermal Resource Assessment in January 2011, to support its goal to become a better steward for resources in its control area. In general, the areas identified as potentially suitable for geothermal development are consistent with those areas identified in the Department of Conservation Map. California State Lands Commission - Mineral Resources Management Division (MRMD): The MRMD manages geothermal resources on state-owned lands by issuing permits and leases for exploration and development. State lands are defined as all lands owned by the state, including school lands, lieu lands, proprietary lands, tidelands, submerged lands, swamp and overflowed lands, and beds of navigable rivers and lakes, and lands in which geothermal resources have been reserved to the state. The MRMD also manages geothermal permitting and leasing on proprietary lands owned by other State agencies; for example, lands owned by the CDFG or the CDPR near the Salton Sea in Imperial County. o The State s primary authority is provided in the Public Resources Code within Division 6 (Public Lands), Part 2 (Leasing of Public Lands), Chapter 2 (Oil and Gas and Mineral Leases), Article 5.5 (Geothermal Resources), 6901 through Article 5.5 was added to the code through the Geothermal Resources Act of o Additional geothermal-related provisions are in the California Code of Regulations (CCR) within Title 2 (Administration), Division 3 (State Property Operations), Chapter 1 (State Lands Commission), Article 4.1 (Leases for Exploration and Development of Geothermal Resources), 2249 through

13 Resource Development Potential The Identification of Renewable Energy Study Areas Initial analysis to develop the Preliminary Conservation Strategy identified the Renewable Energy Study Areas (RESAs). The RESAs are generalized areas within the DRECP that avoided conflicting major land uses (CEC 2011). RESAs focused on areas with lower potential for conflict between renewable energy development and conservation goals. Five loosely defined RESAs were identified based upon Renewable Energy Action Team (REAT) criteria, the criteria for each resource are described below. Areas in the West Mojave, around Barstow, in east Riverside County near Blythe, Imperial Valley, and parts of the Owens Valley all show potential for renewable development and have a mix of biological values that required further and more detailed study (see Figure 3.5-4, RESAs in DRECP). Solar For solar development siting, several factors were considered in the delineation of the RESAs. Solar insolation data from NREL (2009) was mapped across the desert to show relative areas of higher and lower annual solar insolation. These data were used to ensure that identified RESAs met the minimum requirement of 6.5 kilowatt-hours per square meter per day to support viable solar energy generation from current technologies, as identified by input from solar industry stakeholders. Areas of relative higher solar insolation (ranging from 7.6 to more than 8 kilowatt-hours per square meter per day) were identified, primarily in the west Mojave portion of the Plan Area. Slope was also considered relative to the development of RESAs for solar development siting. The initial evaluation of slope within the potential RESAs was cursory and these areas may encompass lands exceeding 5% slope. Slope constraints are to be evaluated in accordance with constraint limitations provided by industry representatives and include preferred slope value of less than 5% for solar photovoltaic (PV) technologies and less than 3% for solar thermal technologies. Wind For wind development siting, several factors were considered in the delineation of the RESAs. Evaluation of potential wind focus areas includes the mapping of areas with a wind speed of 6 meters per second and greater, using data provided by NREL (2009). These areas focus on conditions that are preferred for the deployment of current wind turbine technology. Areas were removed if they conflicted with legislative and legally protected areas, BLM or military land, even if they mapped with preferred wind speeds. 3-13

14 Geothermal For geothermal development siting, several factors were considered in the delineation of the RESAs. Potential geothermal development areas were identified by directly mapping the KGRAs (California Department of Conservation 2001), in conjunction with the current existing BLM geothermal lease areas. Additional potential geothermal lease areas under consideration in the Chocolate Mountains (Imperial County) are also included as potential geothermal development areas. As mapped, these areas represent the extent of the known and commercially operating geothermal resources in the Plan Area. Additional information and discussions with industry, CSLC, BLM, and DOD are needed to determine approaches to help identify additional potential geothermal resource areas that may be needed within the lifetime of the DRECP. Other information used in Developing RESAs The extent of disturbed lands that exist in the Plan Area were mapped using the best available information as these lands were viewed as presenting areas of lower conflict with renewable energy development and were considered in the development of the RESAs. In developing the RESAs, known military, legally & legislatively protected areas as well as other lands known to be managed or designated with incompatible uses were avoided e.g. DWMAs and ACECs. Qualitative assessments of the RESA boundaries by agency field staff was undertaken to establish and modify RESA boundaries based on field staffs local knowledge and experience throughout the fourth quarter of

15 Figure Solar Resources in the Plan Area 3-15

16 INTENTIONALLY LEFT BLANK 3-16

17 Figure Wind Resources in the Plan Area 3-17

18 INTENTIONALLY LEFT BLANK 3-18

19 Figure Geothermal Resources in the Plan 3-19

20 INTENTIONALLY LEFT BLANK 3-20

21 Figure Renewable Energy Study Areas 3-21

22 INTENTIONALLY LEFT BLANK 3-22

23 Stakeholder Defined Development Potential The Center for Energy Efficiency and Renewable Technologies (CEERT) and the Large Scale Solar Association (LSA) submitted proposed areas for the development of solar energy in the Plan Area. CEERT and LSA s analysis identifies the chief characteristics of desirable solar resource lands, including (1) above average insolation, (2) level topography (under 5 degrees of slope), and (3) proximity to transmission (existing or planned high-voltage lines and substations) 8. CEERT and LSA sought to identify up to 2 million acres within the DRECP boundary that should be analyzed for conflict with the conservation goals (see Figure 3.5-5). Additional MARXAN based analysis was undertaken utilizing CEERT defined development criteria that include insolation values, parcel size and slope as factors (Appendix B, Section 5). In November 2010, CalWEA presented Wind Resource Considerations for the DRECP Process, to the Resource Mapping Working Group. The presentation, included mapping and acreage calculations for areas of potentially viable wind resource development areas within the Plan Area. Subsequently, CalWEA updated their plan and identified Wind-Development Focus Areas that include the highest quality wind resources that are within 10 miles of an existing transmission corridors and do not overlap with lands that have been classified as having special environmental concerns (ACECs and DWMAs). 9 See Figure CEERT Transmittal Letter March Docket No. 09-Renew EO-0 1, Center for Energy Efficiency and Renewable Technologies and Large-scale Solar Association s Proposed Development Focus Areas 9 CalWEA letter April , Proposed DRECP Scenario for Wind Energy Resources 3-23

24 Figure Land areas comprising CEERT identified areas for Solar Resources 3-24

25 Figure 3.6 Land Areas Comprising CalWEA Scenario for Wind Resources 3-25

26 3.5.8 Transmission Planning Goals and Assumptions In California, multiple groups have engaged in transmission planning, including the Renewable Energy Transmission Initiative (RETI), the California Transmission Planning Group (CTPG), and the utilities themselves. Planning for transmission within and through the DRECP boundary requires building upon those efforts and developing new methods to optimize land use within the Plan Area. Transmission planning for the DRECP aimed to be utility neutral, and assure access and certainty for renewable energy developers and utilities alike. The previous sections have focused on generation development and the underlying goals assumptions and parameters. Transmission planning requires its own set of assumptions in order to identify the likely magnitude and location of transmission needed to deliver the Plan Area generation to the load centers. The transmission conceptual plan for the DRECP is assumed to serve Plan Area generation growth only and was dependent upon the location and extent of the generation as well as the load center. All transmission planning within California adheres to its own set of general principles known as the Garamendi Principles 10. The Garamendi Principles are expressed as: 1) Encourage the use of existing rights-of-way by upgrading existing transmission facilities where technically and economically justifiable; 2) When construction of new transmission lines is required, encourage expansion of existing rights-of-way, when technically and economically feasible; 3) Provide for the creation of new rights-of-way when justified by environmental, technical, or economic reasons, as determined by the appropriate licensing agency; 4) Where there is a need to construct additional transmission, seek agreement among all interested utilities on the efficient use of that capacity. Early in the process the scope of transmission covered by the DRECP was explicitly restricted to that transmission which was required to serve the generation based in the DRECP, any transmission upgrades required as a consequence of out-of-state or out of DRECP renewable energy resource were excluded from consideration. 10 Senate Bill 2431 (Garamendi, Chapter 1457, Statutes of 1988) 3-26

27 Initially a conceptual transmission plan was developed to estimate the overall transmission requirements necessary to deliver energy from generation located in the RESAs to load centers 11. Underlying the conceptual transmission plan are nine key assumptions: 1. Generation is located within RESAs in quantities proportionate to the RESAs relative size and technology mix. 2. The Conceptual Plan is an evaluation to determine land impacts. It is not a siting evaluation. None of the typical power systems analysis activities, such as power flow studies or stability studies, were conducted. The conceptual transmission plans and associated impacts are the result of the judgments of the experienced transmission planners representing the major utilities from across the state. 3. Guiding principles for the work include planning of rational, orderly, costeffective transmission additions that would allow for phased development. Examples of how these guiding principles were invoked include the following: a. It is rational to assume that conservation goals would strive to both minimize the total footprint of grid facilities and to utilize land of lower biological value. b. The conceptual transmission plan should strive to identify an ultimate plan to meet the requirements of 2050, and then utilize a subset of the components to meet the requirements of 2040 to avoid teardown and rebuild and to reflect the phasing in of facilities over time. c. It is orderly to plan for slightly larger substation footprints to manage the land congestion that can arise when many lines converge on a collector substation and physical space is quickly used up. d. It is cost effective to utilize fewer components that are of sufficient size to collect and deliver most of the renewable generation from the RESA, but also recognize and provide for smaller facilities. 4. The conceptual transmission plan components are assumed to have no preferred developer or owner. 11 DRECP Transmission Conceptual Plan April

28 5. The generation in each RESA is assumed to have no preferred developer or owner. 6. The generation analysis assessed existing generation with operational dates before January Any generation in a RESA and also in the California Independent System Operator (CAISO) interconnection queue, for which utility side transmission is under construction (having already secured a CPCN) has been removed from the RESA generation estimates. All other generation in the CAISO queue within the RESA boundaries was assumed to be included in the RESA generation amount estimates for which conceptual transmission plans would be developed. 7. The RESA output was assumed to be transferred to the following delivery point destinations: a. 25% would be delivered to load centers in Southern California; b. 25% would be delivered to load centers in Northern California; c. 25% would be delivered to load centers in the Pacific Northwest (PNW); and d. 25% would be delivered to load centers in states of the Southwest (SW), including Arizona, Nevada, and New Mexico. 8. The following two assumptions are considered regarding the availability of transmission capacity in the existing transmission network in calculating the transmission requirements for the delivery of 2040 and 2050 RESA renewable power: a. The first assumes that there is little-to-no available capacity in the existing transmission network for the delivery of 2040 and 2050 RESA renewable power. This assumption is used to determine the transmission needed to interconnect the RESAs to the network and provides an upper bound for transmission potentially required to deliver the RESA output to the four destinations listed previously. b. The second assumes that available capacity as indicated by the 2020 prerenewable cases prepared by the California Transmission Planning Group (CTPG) would be used to deliver a portion of the RESA output with the remainder of the RESA output delivered on new transmission. This assumption was used to provide a lower bound for transmission 3-28

29 potentially required to deliver the RESA output to the four delivery destinations listed previously. 9. CTPG pre-renewable cases ( 0 cases) were used as proxies for 2040 planning purposes. Transmission to Southern California is most limited in the Spring, and transmission to Northern California and PNW is most limited in Fall. Consequently, transmission impacts in both Spring and Fall cases were used to develop the Conceptual Transmission Plan 12. The transmission plan was based on the same 20-22,000MW requirement estimated by CEC s Renewable Portfolio Standard and Acreage Calculator as described in Table The planning process identified the necessary transmission system facility additions to accommodate the 20-22,000 MWs of renewable generation that could be developed in the 2040 timeframe. The generation scenario estimates were then adjusted downward for generation projects that have reached a stage of development where the generation operating date is after December 31, 2011 and there is an associated transmission plan for interconnection or where the transmission is under construction. Each new element of the required transmission system (e.g., substation, transmission line, etc.) has an assumed MW capacity to accommodate generation and an associated amount of land that would be impacted by its construction and operation. The Transmission conceptual plan compiled the likely transmission system additions by matching the transmission component capacity to the renewable generation capacity in each RESA for Then using the associated acreages affected for each new component, a tally of the total affected acreage was developed Table gives the total miles and acreages effected by bulk transmission upgrades necessary to deliver power from the DRECP to load center. Table gives the estimated generation interconnection (gen-tie), substation and collection line effected miles and acreages. Subsequently, the transmission plan was modified to reflect changes in assumed 12 To establish the delivery transmission impacts associated with RESA deliveries to all four delivery point destinations described in Item 6, CTPG pre-renewable cases ( 0 cases), which were developed in 2011, were reviewed. These cases model 2020 spring, 2020 summer, and 2020 fall conditions and establish the flows that would be assumed for 2040 and 2050 prior to dispatching the RESA generation. This review showed that the CTPG 2020 Spring Case 0 is the limiting case as it has the highest west-bound flows from five RESAs in Southern California and would result in the most transmission impacts on the Southern California transmission system associated with deliveries of RESA output to Southern California, Northern California, and PNW. As such, the CTPG 2020 Spring Case 0 Flows would be used to help establish the conceptual new delivery lines in Southern California to deliver RESA power to Southern California delivery point destinations. Similarly, the review also showed that the CTPG 2020 Fall Case 0 is the limiting case as it has the highest north-bound flows and would result in the most transmission impacts associated with deliveries of RESA output to Northern California and PNW. As such, the 2020 Fall Case 0 would be used to help establish the conceptual new delivery lines from Southern California to Northern California and PNW. 3-29

30 generation distribution resulting from differences between the distribution of RESAs and the proposed development distribution described in in Chapter 6. Table Estimated Bulk (220kV-500kV) Transmission Required for the 2040 Scenario Given 21,500MW of Generation Distributed Across RESA. Bulk Transmission to load centers Total Miles Required Miles Outside DRECP Miles Inside DRECP Total Acres affected in DRECP Imperial Valley Substation to San Diego Imperial Valley IID System to the North and South Imperial Valley North to send renewables to Northern CA Barstow and West Mojave to LA Basin (incl. Owens) Mojave to Northern California and to Pacific North West Total Table Estimated Effected Miles and Acreages for Generation Interconnection and Substations and Collection/Delivery Lines for the 2040 Scenario Given 21,500 MW of Generation Distributed Across RESA. Linear Miles Acres Gen-Tie 419 3,217 Substation 2,056 Collection and Delivery Lines 812* 18,984 Note: *Bulk delivery lines plus 113 miles of high voltage collection lines 3-30