Acreage Needed in 2050 for Renewable Generation to Meet California s GHG Emission Reduction Goals California Energy Commission May 9, 2011

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1 Acreage Needed in 2050 for Renewable Generation to Meet California s GHG Emission Reduction Goals California Energy Commission May 9, 2011 The Energy Commission has developed a calculator to assist the DRECP in estimating the range of acreage that may be needed within the DRECP planning area to accommodate future renewable generation. The calculator estimates the acreage needed for renewable generation in 2050 to realize a specified percentage reduction from 1990 levels in electric sector greenhouse gases (GHG)... For an 80 percent reduction consistent with AB 32 it is easiest to think of a 23.2 million metric ton cap on carbon emissions being imposed on the electricity sector. Additional emissions would be allowed only to the extent that offsets can be purchased from other sectors of the economy in lieu of real reductions by electric generators. This cap on emissions limits fossil-fuel generation to a maximum number of GWh. Additional energy may be procured from that share of existing renewables and other zero-carbon resources both in- and out-of-state that are assumed to still be operating in 2050, new out-of-state renewables built during the next 40 years, and small-scale, in-state distributed generation that has a minimal impact on undisturbed land. The remainder must come from renewable resources. The description is divided into three sections: (1) Calculating Future Need for Renewable Energy, (2) Calculating Needed Acreage, and (3) High and Low Acreage Assumptions Section 1 includes the components that will cause electricity consumption to change and the assumptions for those changes in This section includes effects from key policies in energy efficiency, combined heat and power, customer-side and other distributed generation, and transportation electrification. The 2050 carbon cap is defined. Zero carbon resources that are likely to be existing in 2050 are enumerated. Allowable natural gas-fired generation under the cap is estimated. The new renewable energy needed is then calculated as a percentage of retail sales. Section 2 builds a renewable portfolio to meet the new renewable energy needed from Section 1. The reference case is based on current policies. Two additional cases with different potential build-outs of renewable resources, which will affect acreage needed, are added. Assumptions for the reference case are described in sections 1 and 2; assumptions for the high and low acreage cases are defined in section 3. (1) Calculating Future Need for Renewable Energy Energy Needed to Meet Demand Energy Needed in 2010 (Net Energy for Load or NEL): Net Energy for Load is the amount of energy that must be produced or purchased by load-serving entities (for example, utilities) to meet customer demand for electricity. The value used here is from the Energy Commission s 2009 demand forecast. Annual Economic/Demographic Demand Growth Rate: The annual rate at which electricity demand grows based on economic and demographic factors. The value used here (1.5 percent) is the annual average during

2 2 Annual Reductions from Energy Efficiency: The effect of energy efficiency programs on demand growth. The value used in the reference case (-0.81 percent) is the annual average during This reduces energy use by more than 145, 000 GWh, or 27.5 percent during The next three values incorporate additional demand from transportation electrification and demand reductions from combined heat and power (CHP) and customer-side distributed generation over the period. Each of these is assumptions discussed in greater detail below. Energy Increases in Outer Year from Electrification: The reference case assumes roughly a 10 percent (37, 186 GWh) increase in energy demand from electrifying transportation. 5.2 million alternative fuel vehicles yield an increase of 21,486 GWh, high-speed rail accounts for a majority of the remainder. New Combined Heat and Power (CHP) Reductions: The reference case assumes 6,500 MW of new CHP, consistent with the Clean Energy Jobs Plan. The share of generation consumed on site and avoided transmission losses are deducted from the amount of energy that is needed. New Customer Distributed Generation Reductions: This is primarily residential and commercial small rooftop solar PV. It includes only that share of additions not embedded in the demand forecast. Carbon Baseline 1990 Carbon Baseline: million metric tons (mmmt), per the California Air Resource Board s (CARB) Carbon Inventory. Desired GHG Percentage Reduction: A user-specified value; the percentage entered here (80%) is consistent with AB 32 s economy-wide target for Allowed Carbon Offsets: The share of sectoral reductions in GHG emissions that can be met by purchasing offsets from uncapped sectors of the economy. The value adopted by ARB in their regulations of December 2010 is 8 percent. Allowed Offsets: The additional GHG emissions from generation made possible by offset allowances. For an 80 percent reduction in emissions, an allowance percentage of 8 percent yields 7.4 million mmmt Carbon Cap with Offsets: The total amount of emissions allowed from generation. Zero-Carbon Generation Resources in 2050 This section enumerates the sources of zero-carbon energy available to California other than new in-state renewables. Existing Renewables Still Operating in 2050: Existing renewables still operating in 2050 will provide energy that does not require incremental land. The Energy Commission s Renewable Energy Office estimates that existing renewables and those under construction now provide 43,400 GWh; 9,100 GWh comes from out-of-state. This reference case assumes that 30,000 GWh (more than 85 percent) of existing in-state renewables are still operating in 2050, but that existing out-of-state renewables will be providing energy to outof-state entities. Note that, for an acreage assessment, this assumption does not require that aging renewables continue to operate, but merely that replacement/refurbishment occurs at the same (disturbed) sites. Large Hydro: Based on average; this value can move up and down by 15,000 GWh in wet and dry years.

3 3 Nuclear Energy: Based on expected output from Diablo Canyon, San Onofre (18,000 GWh each) and the California share of Palo Verde (6,000 GWh). Additional Out-of-State Non-Renewables: Recent and forecasted deliveries from Hoover Dam to California utilities are just under 4,000 GWh. While large hydro is generally available from the Northwest, it is usually marketed as energy from unspecified sources, which will have significant carbon content under existing regulations. Gas Performance and Emissions Assumed Average Operating Efficiency for Gas-Fired Generation: The average heat rate for gas-fired generation in GWH of Gas-Fired Generation Allowed Under the Cap: Based on allowed GHG emissions, minus the emissions from new CHP, and the assumed operating efficiency of gas-fired generation. New Renewable Energy Needed Renewable Energy Needed to Meet the Carbon Constraint: Total energy needed less that provided by gas-fired generation and CHP, minus that provided by zero-carbon nonrenewable resources. New Renewable Energy Needed (Renewable Net Short): Renewable energy needed to meet the carbon constraint minus existing renewables still operating in RPS Calculations Transmission and Distribution Losses: Losses must be deducted from Total Energy Needed to derive retail sales. Retail Sales: California s Renewables Portfolio Standard (RPS) is specified as a percentage of retail sales. RPS: Renewable energy needed as a percentage of retail sales. Detailed Assumptions about CHP, Customer DG, and Electrification New Combined Heat and Power (CHP) Assumptions MW (Nameplate Capacity): The 6,500 MW value reflects the target (for 2030) in the Clean Energy Jobs Plan. Annual Operating Level: The 92 percent capacity factor reflects the assumption made for CHP in CARB s AB 32 Scoping Plan. Share of Production Consumed On-site: The 50 percent value reflects the assumption made for CHP in CARB s AB 32 Scoping Plan. Energy Consumed On-site: This amount, increased to include avoided transmission and distribution losses, is subtracted from Net Energy for Load above. The GHG emissions associated with this generation are assumed to be credited to the industrial sector and are not counted against the electricity sector cap. Energy Exported to Grid: This reduces the amount of energy that needs to be provided by new, in-state renewable resources. Assumed Operating Efficiency for Exported Energy: The heat rate assumed for CHP exports determines the carbon content of the exports, and reduces the amount of GHG emissions that are available for other resources.

4 4 Carbon in Exported Energy: The GHG emissions (in mmmt) associated with CHP exports. The CHP sector consumes roughly 40 percent of GHG allowances available (before offsets) under the reference case assumptions. The CHP numbers above do not consider existing CHP. California has more than 9,000 MW of CHP in Roughly half of this capacity does not provide wholesale energy; the Energy Commission forecast assumes that these resources will continue solely to meet on-site demand. The remaining CHP resources divide their output between exports (70 percent) and on-site use (30 percent); the Energy Commission forecast assumes that the latter will continue to be self-provided. The future of existing CHP will be largely determined by the recent QF settlement. For illustrative purposes, assume that 1,900 MW of the most efficient, existing CHP continues to operate at a 60 percent capacity factor, selling 95 percent of its output to loadserving entities. Depending upon the heat rate assumed for this output (7,000 to 8,500 Btu/kWh); existing CHP would consume mmmt of the sector s GHG allowances. Assuming a heat rate of 7,400 Btu/kWh (the heat rate assumed for gas-fired generation), the 9,478 GWh of existing CHP sales to utilities would reduce the generation from gas-fired generation (53,177 GWh) by an equivalent amount. Customer Distributed Generation (Small Rooftop PV) Assumptions MW (Nameplate) Including the Original 3,000 MW CSI Target: The reference case assumes that there are 6,000 MW of small rooftop solar (< 1.5 MW) on the customer-sideof-the-meter. This is 3,000 MW more than assumed to be forthcoming from the California Solar Initiative. Annual Operating Level: The assumed capacity factor for small rooftop solar. Total Energy and Incremental Energy from Small Rooftop Solar: The total generation from small rooftop solar and the share that is not already embedded in the demand forecast. Assumptions regarding customer distributed generation appear in section 1 of the calculator because they affect the RPS calculation (unlike central station and utility-side DG assumptions, which appear in section 2). Total new renewable energy (procured) calculations in section 2 include the incremental energy value derived here. Electrification in 2050 Assumptions Meeting the state s 2050 GHG reduction goals will require significant electrification of the economy. The reference case includes 5.2 million full electric and hybrid vehicles, as well as values for public transportation, high-speed rail, and port electrification. This is not a forecast of likely penetration by 2050, but is presented to illustrate the potential impact of transportation electrification on electricity demand. The values presented are not those needed to reduce GHG emissions in the transportation sector by 80 percent; that would require a greater penetration of alternative fuel vehicles. Finally, the values for average vehicle efficiency and annual vehicle miles traveled may change substantially during the next 40 years. See the calculator for more details.

5 5 (2) Calculating Needed Acreage Acreage Calculation Assumptions This section provides estimates of acreage needed for five central station technologies: solar thermal, solar PV, wind, geothermal and biomass and utility-side distributed solar (up to 20 MW). It also measures the contribution of these technologies to meeting the renewable Net Short under user-entered values for nameplate capacity. MW Assumed: Total MW installed (nameplate). Annual Operating Level: The assumed Capacity Factor for the technology. The values presented in the reference case are staff estimates. o Central Station Thermal: 27%, 36% with storage o Central Station Photovoltaic: percent per 2010 LTPP depending on thin film versus crystal tracking, desert versus Central Valley location. o Wind: CPUC RPS calculator. o o Geothermal: CPUC RPS Calculator. Biomass: Staff queried the QFER data set for existing projects larger than 10 MW; median average capacity factor was 67% for 30 projects. Future biomass projects are expected to be higher, 80-90%. MW/Acre: Assumed MW/acre for the technology. The values provided are staff estimates based on information compiled from various sources, including applications for certification and third-party surveys. Where sufficient data was available, for example, wind, Californiaspecific values were used. o Central Station Solar Thermal: Power tower Parabolic trough estimates are from the Energy Commission s Siting Office AFC s. Additionally, California ISO Technical Appendices for Renewable Integration Studies, Version 1, p.27: MW/acre for thermal (average of trough and tower). o Central Station Solar Photovoltaic: 0.11 MW/acre - Federal Solar PEIS. o Wind: From NREL (Land Use Requirements of Modern Wind Plants, August 2009), California plants in database averaged MW/acre; entire U.S. averaged o Geothermal: Midpoint based on estimate of 5-7 acres at China Lake or MW/acre. o Biomass: Derived from Energy Commission s Siting Office data on operating California plants at Tracy Biomass Plant (Tracy), Colmac Energy Plant (Mecca) and Madera Energy Facility (Madera) = average 0.40 MW/acre. Output: The installed MW and Capacity Factor yield total output (GWh). Share of Net Short: The Output as a percentage share of the Net Short (incremental renewable energy needed to meet the RPS). Total Acres: The acreage needed for the MW specified, based on the MW/acre value for this technology. In-State Totals Total MW of Central-Station Technologies. Total MW of Distributed Generation: Utility-side distributed solar plus the share of customer-side distributed generation that is not already accounted for in the demand forecast. Total Output: For the six technologies (GWh); does not include the customer-side distributed generation (3,000 MW) that is already embedded in the demand forecast. Share of Net Short: The share of the net short met by the six technologies.

6 6 Total acreage: For the five central-station technologies. New Out-of-State Renewables Share of Renewable Energy Produced Out-of-State. The percentage value entered here may reflect maxima allowed by regulation or the user s estimate of the share of renewables serving California load in 2050 that will be located out of state. New Out-of-State Renewable Energy. The share of renewable energy allowed/assumed from out-of-state minus energy from existing out-of-state renewable resources. Share of Renewable Net Short. The share of the renewable net short met by new out-ofstate renewable resources. (3) High and Low Acreage Scenarios A set of user-defined renewable technology portfolios is hypothesized in each of these scenarios to meet the amount of new renewable energy needed. This table illustrates two bookend scenarios of around the reference case, which is based on the Governor s renewable policy goals. These two scenarios are designed to push toward lower and higher acreage amounts. Each is based on a version of the calculator with the same name. The assumptions used to construct these bookend scenarios and key impacts are examined in the next section. Technology (MW) Reference Case Low Acreage Case High Acreage Case Central Station Solar Thermal 9,000 3,500 15,000 Central Station PV 9,000 3,500 15,000 Wind 10,000 4,500 22,000 Geothermal 3,000 2,750 5,000 Biomass 3,000 2,750 5,000 Utility-Side Distributed Solar 9,000 9,000 18,000 Customer-Side Distributed Solar* 6,000 9,000 9,000 Total New Distributed Generation* 12,000 15,000 24,000 CHP 6,500 6,500 8,500 New Renewable Energy Needed (GWh) 200, , ,876 Share Obtained 99.2% 102.1% 99.2% Acreage 571, ,201 1,166,127 *3,000 MW of customer-side distributed solar is existing small rooftop solar from California Solar Initiative that is already embedded in Energy Commission demand forecast

7 7 Impacts of Assumptions on Scenarios These assumptions have the greatest impact on the need for in-state renewable energy in these scenarios: Load growth assumptions have the most significant impacts. o Electrification of the transportation sector in the high acreage scenario increases demand by 86,000 GWh compared to the reference case. o A 10 percent decrease in econ/demo-driven growth changes the demand for energy by 22,000 GWh in the low acreage case. o A 20 percent decrease in the impact of energy efficiency on annual demand growth increases the need for energy by 25,000 GWh in the high acreage case. Retirement of the nuclear facilities (Diablo Canyon, San Onofre, and Palo Verde) increases the need for renewable energy by 42,000 GWh. Changing the targeted GHG reductions from 1990 levels by 10 percentage points would shift the need for renewable energy by roughly 26,000 GWh. CHP development may have a substantial impact on the need for renewable energy, but this is caused by accounting conventions: emissions from on-site use of electricity generated by CHP and used on site are assigned to the industrial sector. If a large amount of electricity demand were met by on-site generation/consumption by CHP, the industrial sector would bear the emissions, and less demand would remain to be met by other resources, reducing the need for renewable generation. If all CHP generation is exported to utilities, both demand (retail sales) and sectoral emissions are largely unchanged, and CHP development has no little or no effect on the need for renewable energy. The portfolios created to meet the renewable energy requirements in each of the 3 cases are user-defined, but attempt to reflect constraints on the development of specific technologies (biomass and geothermal) given limited technical potential and fuel availability. The reference case portfolio assumes the development of 3,000 MW each of geothermal and biomass, technologies that produce a large amount of energy on a per MW basis. This is increased in the high acreage case as the amount of intermittent resources becomes implausible from an operations perspective. The retirement of the nuclear facilities, combined with assumed high off-peak loads from the electrification of the transportation sector, creates a need for dispatchable baseload energy. Thus geothermal and biomass resources are added in the high acreage case, despite the fact that they have a higher MWh energy/acre of land value than intermittent alternatives. Choosing these resources lowers the acreage, but without them you could not run the system.

8 8 Reference Case Assumptions Assumptions Leading to Low Acreage Assumptions Leading to High Acreage Load Growth and Electrification: Demand grows by 1.5%/year from econ/demo factors, but is reduced by 0.81% annual reduction from energy efficiency. 37,200GWh for electrification from 5.2 million EVs and hybrids, high speed rail and other transport Total energy needed is 385,600 GWh Offsets Allowed: 8% of total reductions, increasing allowed gas-fired generation by 17,900 GWh, from 32,500 GWh to 50,400 GWh. Econ/demo growth reduced to 1.35%/year means, 22,000 GWh less than reference case total 23,600 fewer GWh than reference case due to only 2.6 million EVs and hybrids, no high speed rail. Increase offsets to 10% of total reductions, 4,700 GWh of additional gas-fired generation compared to the reference case. Energy efficiency impacts reduced to 0.65%/ year ; 25,000 GWh more needed than reference case Additional 86,000 GWh needed beyond reference case for electrification; 26 million EVs and high speed rail are assumed. Reduce offsets to 5% of total reductions, 7,100 GWh less gas-fired generation compared to the reference case. Energy from Zero-Carbon Non- Renewables, Existing Renewables: 30,000 of 43,400 GWh of existing renewables (all in-state), still available; all 3 nuclear plants (42,000 GWh) still operating. Combined Heat and Power: 6,500 MW at 95% capacity factor; 50% of production used on-site. Customer Distributed Generation: 3,000 MW above ,000 CSI goal Gas Performance: 7,400 Btu/kWh assumed. Out-Of-State Renewables Allowed: 25% of total renewable energy, consistent with SBX12. Same as reference case. Same as reference case 6,000 MW above 2030 CSI goal, reducing renewable energy needed from other sources by 5,300 GWh compared to reference case. 7,000 Btu/kWh assumed, allowing 3,000 GWh more gas-fired generation compared to the reference case. Same as reference case. Nuclear facilities no longer in service, 42,000 additional GWh needed 8,500 MW, share of energy exported to grid increased to 70%; need for renewable energy increases by 3,900 GWh. Same as low acreage case. 7,800 Btu/kWh assumed, reducing gas-fired generation by 2,700 GWh compared to the reference case. Same as reference case.