Review of the Boston Consulting Group Understanding the Impact of AB32 Report. Final Report

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1 Review of the Boston Consulting Group Understanding the Impact of AB32 Report Final Report Prepared for California Business Alliance for a Green Economy Date: October 5, 2012 Prepared by TIAX LLC Stevens Creek Blvd., Suite 250 Cupertino, California Tel Fax TIAX Case No. D0642

2 Executive Summary In the report entitled Understanding the Impact of AB32, Boston Consulting Group (BCG), funded by the Western States Petroleum Association, modeled the impacts of the Low Carbon Fuel Standard (LCFS) and the AB32 cap-and-trade program on the California refinery sector. BCG drew stark conclusions for the refinery sector and the California economy with the implementation of these programs. Upon review of the BCG report, TIAX has identified significant inaccuracies and faulty assumptions that led to the results concluded by BCG. BCG assumed that imported sugarcane ethanol is the only alternative fuel used for compliance with the LCFS to generate credits, that the cost of AB32 cap-and-trade and LCFS allowances will cause the displacement of hydrocarbon (HC) gasoline by imported corn ethanol, and that advanced technology vehicles (ATVs), including electricity, natural gas, and hydrogen, do not generate LCFS credits. The combination of these assumptions created a worst-case scenario for California where no business, economic activity, or jobs from LCFS fuel production are generated in the state since all compliance fuels are imported. BCG, based on its modeled added fuel cost of $0.33 to $1.06 per gallon due to the LCFS, implicitly stated that the LCFS allowance price is $275 to $883 per ton in This is significantly more expensive than the estimated cost of $25 per ton for LCFS allowances, or $0.03 per gallon. BCG discussed the costs to only one segment of the transportation fuel market and omitted the benefits to other segments and to California as a whole from the LCFS and AB32 cap-and-trade. It ignored the jobs and economic benefits to California from new infrastructure and new cars (including California-based car companies such as Tesla and statewide dealers selling electrified and natural gas vehicles) for electricity and natural gas that are produced, transported, and dispensed by California utilities and companies. BCG s scenario also ignored the benefits from in-state investment for E85 infrastructure. Assuming necessary upgrades to terminals and all gasoline stations in California, $2.8 billion would need to be invested by 2020, based on the BCG E85 scenario estimate. Over 44,000 fulltime equivalent (FTE) jobs would be created by the build-out of the E85 refueling infrastructure. In addition, the $1.26 billion invested in terminal upgrades would create between 4,200 and 6,300 direct new jobs and 21,000 to 44,100 new jobs on account of indirect impacts. This number is comparable to BCG s estimated number of jobs lost in the refinery sector. This required investment will not only create jobs but also business income in California. BCG s major assumption that only imported sugarcane ethanol generates LCFS credits excludes any economic impact from biofuels or alternative fuels produced in California. The assumption zeroed out any potential economic development from AB 118, the Alternative and Renewable Fuel and Vehicle Technology Program. The California Energy Commission (CEC), through AB118, has proposed, funded, or allocated $108.7 million for biomethane, gasoline substitute (mainly ethanol), and diesel substitute (mainly biodiesel) production within California. In previous, upcoming, and proposed funding, CEC has set aside over $255 million for light-, medium-, and heavy-duty alternative fuel infrastructure and vehicles, including electricity hydrogen, natural gas, and E85. BCG also overstated the cost and cost range of carbon credits and ignored the effect carbon offsets would have on the average credit/allowance price. BCG assumed that carbon prices ES-1

3 could be four to five times higher than the Reuters-forecasted carbon price of $30 to $35 per ton, thereby considering scenarios of up to $150 per ton. This assumption acts as a multiplier for BCG s modeled effects of AB32 cap-and-trade and overstates the potential costs of purchasing carbon credits. BCG also ignored emission reduction opportunities at refineries (e.g., energy efficiency) that would be much cheaper compliance options than purchasing allowances at $60 to $70 per ton and would put downward pressure on allowance prices in the market. The BCG report and model did not include a baseline scenario. This baseline is imperative for determining the future costs and benefits of a regulation. Without a baseline, or business-asusual (BAU) case, the impacts of the regulation and what would otherwise happen in the absence of the regulation cannot be separated; thus, effects cannot logically be attributed to the regulation. The report compared the actual 2011 HC gasoline production in California to the modeled 2017 and 2020 HC gasoline production volumes to determine refinery closures and associated job losses and subsequently attributed all job losses to AB32. A representative baseline scenario would model transportation fuel demand in a way that accounts for the California ZEV standards, California Light-Duty Vehicle Greenhouse Gas (GHG) or Clean Cars Standards Phase I (2011 to 2016) and Phase II (2017 to 2025). The lack of a baseline in the BCG analysis undermines the findings attributing refinery closures to AB32 cap-and-trade and the LCFS. Furthermore, BCG utilized a CEC petroleum demand forecast that did not take into account the LCFS or AB32 when it was modeled, making it difficult to assess the impacts of the regulation. The CEC demand forecast estimates 856 Mbpd of petroleum fuel demand in 2020; assuming an E10 blend, it would contain Mbpd of HC motor gasoline, a reduction of 63.6 Mbpd from the 2011 HC motor gasoline production in the BCG report. This reduction in the absence of AB32 and the LCFS is equivalent to over 27% of the BCG-modeled refinery shutdowns that were attributed to these regulations. The BCG scenario ignored the potential credits produced by ATVs in the CEC demand forecast. The CEC Low Petroleum demand scenario used by BCG also included over 665 million kwh of electricity and over 200 million gge of CNG. This forecasted electricity and natural gas consumption would have produced enough LCFS credits to offset 25 Mbpd and 14.1 Mbpd, respectively, of HC gasoline. These offsets would reduce the need for imported sugarcane ethanol. The illustrative pathways of the Air Resources Board (ARB) project that electrified vehicles could produce enough LCFS credits to offset 70 Mbpd of HC gasoline, almost one-third of BCG s modeled scenario of 234 Mbpd of refinery closures in With the inclusion of offroad electrified transportation, there is the potential to double ARB s projections of LCFS credits from electricity in BCG s model was a black box where most of the important assumptions, costs projections, and equilibrium equations were unavailable and could not be analyzed. None of the inputs identified in its Exhibit 22 were presented, making the BCG model a complete black box. In addition, the BCG model did not use historical data and instead used BCG equilibrium pricing. TIAX disagrees with this decision because refinery production historically does vary seasonally and should be accounted for in the model. To ensure the model s validity, it needs to be calibrated against historical data. Lastly, BCG used a model that did not include price elasticity of supply and demand of petroleum and did not include fuel choice or fuel switching. The model assumed a static petroleum blend transportation fuel demand while prices varied. ES-2

4 Introduction In the report entitled Understanding the Impact of AB32, Boston Consulting Group (BCG), funded by the Western States Petroleum Association, modeled the impacts of the Low Carbon Fuel Standard (LCFS) and the AB32 cap-and-trade program on the California refinery sector and the California economy. BCG drew stark conclusions for the refinery sector and the California economy with the implementation of these programs. Upon review of the BCG report, TIAX has identified significant inaccuracies and faulty assumptions that led to the results concluded by BCG. TIAX has categorized these inaccuracies and assumptions into three categories: General, Alternative Fuel, and Economic. At a high level, the BCG report and model did not include a baseline scenario. This baseline is imperative for determining the future costs and benefits of a regulation or policy. Without a baseline, or business-as-usual (BAU) case, the impacts of the regulation and what would otherwise happen in the absence of the regulation cannot be separated; thus, effects cannot logically be attributed to the regulation. Furthermore, BCG utilized a California Energy Commission (CEC) petroleum demand forecast that did not take into account the LCFS or AB32 cap-and-trade when it was modeled, making it difficult to assess the impacts of the regulation. Lastly, BCG s model was a black box where most of important assumptions, costs projections, and equilibrium equations were unavailable and could not be analyzed. In addition, BCG assumed that imported sugarcane ethanol is the only alternative fuel used for compliance with the LCFS to generate credits, that the cost of AB32 cap-and-trade and LCFS allowances will cause the displacement of hydrocarbon (HC) gasoline by imported corn ethanol, and that advanced technology vehicles (ATVs), including electricity, natural gas, and hydrogen, do not generate LCFS credits. The combination of these assumptions created a worst-case scenario for California where no business, economic activity, or jobs from LCFS fuel production are generated in the state since all compliance fuels are imported. Lastly, BCG used a model that did not include price elasticity of supply and demand of petroleum and did not include fuel choice or fuel switching. The model assumed a static petroleum blend transportation fuel demand while prices varied. BCG discussed the costs to only one segment of the transportation fuel market and omitted the benefits to other segments and to California as a whole from the LCFS and AB32 cap-and-trade. BCG also overstated the cost and cost range of carbon credits and ignored the effect carbon offsets would have on the average credit/allowance price. 1

5 General Inaccuracies and Assumptions The major general inaccuracies and assumptions identified by TIAX are: No baseline scenario for 2017 and 2020 in the absence of AB32 to compare to the AB32 scenario Effects of AB32 and the LCFS not included in the CEC petroleum demand forecast used in BCG s model BCG s black box refinery model does not allow the review of important assumptions, costs projections, and equilibrium equations No Baseline 2017 and 2020 Scenarios When modeling the impacts of a proposed policy, it is necessary to first develop a baseline or BAU scenario for future analysis years in the absence of the policy. This allows for a representative comparison of the future conditions with and without the policy to determine its impact. Without producing a BAU scenario and comparing to current conditions, there is no indication of which impacts are due to the policy and what would have happened otherwise. BCG s analysis did not create a BAU scenario to compare to its modeled AB32 scenario. The report compared the actual 2011 HC motor gasoline production in California to the modeled 2017 and 2020 HC production volumes to determine refinery closures and associated job losses and subsequently attributed all job losses to AB32. A representative baseline scenario would model transportation fuel demand in a way that accounts for the California ZEV standards, California Light-Duty Vehicle Greenhouse Gas (GHG) Standards Phase I (2011 to 2016) and Phase II (2017 to 2025). These light-duty standards have been harmonized with the federal CAFE Standards. The lack of a baseline in the BCG analysis undermines the findings attributing refinery closures to AB32 and the LCFS. Additionally, BCG analyzed a single worst-case scenario and did not analyze any compliance scenarios that include cellulosic ethanol or ATVs. CEC Petroleum Demand Forecast BCG utilized a CEC petroleum demand forecast 1 to analyze the effects of AB32 cap-andtrade and the LCFS even though this demand forecast includes neither of these policies nor Phase II of California s vehicle GHG standards. For the CEC petroleum demand forecast to be used as the demand forecast for analyzing AB32 and the LCFS, it would need to include these policies. The CEC demand forecast estimates 856 Mbpd of petroleum fuel demand in 2020; assuming this is an E10 blend, it would contain Mbpd of HC motor gasoline, a reduction of 63.6 Mbpd from the 2011 HC motor gasoline production in the BCG report. This reduction in the absence of AB32 cap-and-trade and the LCFS is equivalent to over 27% of the BCG-modeled refinery shutdowns that were attributed to these regulations. In addition, BCG conservatively assumed the Low Petroleum demand scenario (as seen in a comparison of Exhibits 41 and 44 in the BCG report with Table 3-5 on page 77 of 1 California Energy Commissions, Transportation Energy Forecasts and Analyses for the 2011 Integrated Energy Policy Report, Draft Staff Report, August 2011, CEC SD. 2

6 the CEC report), which starts the analysis on the low end of HC gasoline production compared to 2011 production volumes. BCG ignored the rest of the Low Petroleum transportation demand scenario, which includes over 25 Mbpd of CARBOB-equivalent LCFS credits from electricity and over 14 Mbpd from natural gas. These ignored portions of the scenario would reduce the need to import sugarcane ethanol for compliance and the cost associated with the LCFS as E85 sugarcane is assumed to more expensive than HC gasoline by BCG (BCG report Key Exhibit 7). BCG Black Box Model Many of BCG s main assumptions about fuel prices (alternative and conventional) and international and domestic trade patterns were embedded within a proprietary model that cannot be reviewed. The details and assumptions of BCG s equilibrium pricing model and the interaction of gasoline, corn ethanol, and sugarcane ethanol prices were not discussed. This is important because BCG s pricing model determined a crossover point where it is more economical for refiners to purchase and sell corn ethanol than to produce and sell HC gasoline (BCG Key Exhibit 1). None of the inputs identified in Exhibit 22 were presented, making the BCG model a complete black box. In addition, the BCG model did not use historical data and instead used BCG equilibrium pricing. TIAX disagrees with this decision because refinery production historically does vary seasonally and should be accounted for in the model. To ensure the model s validity, it needs to be calibrated against historical data. In addition, BCG s model used a simplifying assumption that the supply of gasoline is equivalent to demand and so imports and exports are minimal. BCG used Energy Information Administration (EIA) data from 2011 for PADD5 to support its assumption, but these data wash out intrastate exports of motor gasoline to Oregon, Nevada, and Arizona. In 2011, California exported 10% of its refined motor gasoline to other states or overseas. 2 Alternative Fuel Inaccuracies and Assumptions The major alternative fuel inaccuracies and assumptions identified by TIAX are: Assuming that only sugarcane ethanol is used to comply with the LCFS and that corn ethanol imports displace HC gasoline Not including ATVs for electricity and natural gas consumption Ethanol Assumptions The BCG report assumed that only sugarcane ethanol will be available as a compliance pathway under the LCFS. The rationale for excluding cellulosic ethanol was the EIA s cellulosic ethanol projections in the 2012 Annual Energy Outlook (AEO), which shows very small volumes of cellulosic ethanol in This is not an accurate projection of the availability of cellulosic ethanol with the implementation of the LCFS and AB32. AEO 2012 explicitly states in the passages below that energy projections do not include

7 the LCFS or AB32 due to ongoing litigation at the time of publishing (for the LCFS) and modeling limitations (for AB32). LCFS (page 14 of AEO 2012): The future of the LCFS program remains uncertain. After the initial ruling, a request for a stay of the injunction was quickly filed by CARB, which would have allowed the LCFS to remain in place during the appeal process; however, that request was denied by the same judge who initially blocked enforcement of the LCFS. A new request for a stay of injunction while CARB appeals the original ruling was filed with the U.S. Ninth District Court of Appeals and was granted as of April 23, 2012 [39]. A decision on the appeal filed by CARB is yet to be made. As a result of the initial ruling s timing, along with EIA s prior completion of modeling efforts, the LCFS is not included in the AEO2012 Reference case. AB32 (page 10 of AEO 2012): The cap-and-trade program applies to multiple economic sectors throughout the State s economy, but for AEO2012, due to modeling limitations, it is assumed to be implemented only in the electric power sector. BCG s analysis was based on fuel supply projections from the EIA that are extremely low estimates that assume no LCFS. To make a valid assessment of AB32 cap-and-trade and the LCFS, it is necessary to utilize a biofuel forecast that takes into account the effects of these regulations. These regulations and the cost of carbon allowances act as incentives for increased production volumes. Between now and 2020, cellulosic biofuel production technology and methods are likely to improve. BCG assumed increased costs of sugarcane E85 relative to HC gasoline that include full reinvestment economics for infrastructure to produce, transport, store, and distribute ethanol. Based on this assumption and the costs of natural gas and electricity (including the increased efficiency of electric vehicles over gasoline vehicles) for transportation, it would be much cheaper for refineries to use LCFS credits from natural gas and electricity than sugarcane ethanol using E85 infrastructure. BCG modeled a cost of $0.33 to $1.06 per gallon of HC gasoline using sugarcane ethanol to comply with the LCFS, which implies costs of $275 to $883 per ton for LCFS allowances in The estimated cost of LCFS allowances of $25 per ton equal only $0.03 per gallon in In addition, based on USDA-projected sugar prices 3 and lower cost estimates for producing sugarcane ethanol than corn ethanol, 4 the costs of the LCFS estimated by BCG are overstated. 3 4 USDA Agricultural Projections to 2020, Long-Term Projections Report, Interagency Agricultural Projections Committee, February 2011, OCE Valdes, Constanza, Brazil s Ethanol Industry: Looking Forward, USDA Economic Research Service, June 2011, 4

8 BCG stated that not enough sugarcane ethanol would be available in 2020 for compliance with the LCFS. However, in making this statement, BCG assumed that 2020 production volumes would equal 2011 volumes (360 Mbpd). The production volumes in 2011 were considerably lower than in 2010 when Brazil produced over 525 Mbpd 5, which is only 5% less than what BCG estimated California would need. The production of sugarcane ethanol is currently dependent on the commodity price of sugar. When the price of sugar is high, it is more economical to produce sugar than sugarcane ethanol. BCG assumed that even with the projected demand from California, the United States, and Europe, Brazil would not invest in additional production capacity to support this higher demand. The USDA suggests that Brazil has the potential to export over 1,100 Mpbd of sugarcane ethanol as early as 2018, or twice the amount BCG estimated California would need for LCFS compliance. 6 This is a recurring theme of the BCG report: it fails to consider price elasticity of supply and demand. In reality, increased demand would likely increase prices and potentially increase future supply. A major assumption that greatly impacts BCG s conclusions is that imported corn ethanol will displace HC gasoline. The report assumes that refiners would find it more economical to purchase ethanol than to sell HC gasoline in California due to the cost of compliance with AB32 cap-and-trade, which would require refiners to purchase allowances, making HC gasoline prices higher than ethanol. Because BCG did not explicitly state its assumptions of HC gasoline price, ethanol price, and when substitution occurs, TIAX can only assume that this displacement occurs. BCG incorrectly assumed that the CEC demand forecast would remain the same (no price elasticity of supply and demand) while increasing fuel prices based on the costs of AB32 cap-and-trade and the LCFS, when the CEC demand forecast incorporated specific fuel price forecasts not utilized by BCG. The assumption that imported corn ethanol will displace HC gasoline does not follow the historical trends of gasoline and ethanol price. Since HC gasoline and ethanol are blended in both E12 and E85 in the BCG scenario, it is unlikely the prices of HC gasoline and ethanol will decouple. While on a per-gallon basis HC gasoline could be more expensive than ethanol, historically the cost of ethanol on a per gasoline gallon equivalent (gge) energy basis is consistently higher than the price of HC gasoline. HC gasoline is dependent on the trading price of crude oil, and ethanol prices are dependent on the price of HC gasoline. Figures 1 and 2 below show gasoline and E85 prices from the Clean Cities Alternative Fuel Price Reports and F.O.B. HC gasoline and ethanol prices in Nebraska. 5 6 Valdes, Constanza, Brazil s Ethanol Industry: Looking Forward, USDA Economic Research Service, June 2011, Valdes, Constanza, Brazil s Ethanol Industry: Looking Forward, USDA Economic Research Service, June 2011, 5

9 $5.00 U.S. Average Retail Fuel Prices $4.50 $4.00 $3.50 Cost per GGE $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 E85 Gasoline Diesel CNG $0.00 Mar-00 Mar-01 Mar-02 Mar-03 Mar-04 Mar-05 Mar-06 Mar-07 Mar-08 Mar-09 Mar-10 Mar-11 Mar-12 Figure 1. U.S. Average Retail Fuel Prices 7 Cost Per Gallon $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 Ethanol Ethanol (gge) $0.50 Gasoline $ Figure 2. Annual Average Nebraska F.O.B Rack Price 8 Figure 1 shows that gasoline and E85 prices track with each other on a gge basis. Since the removal of the ethanol blender s credit at the end of 2011, the cost of E85 has increased over the cost of gasoline by over $1/gge. Figure 2 shows the cost of HC gasoline and unblended ethanol tracking with a differential of over $0.90/gge in 2011 before the blender s credit expired. Based on the historical trends of gasoline and ethanol prices, and as E12 and E85 are HC gasoline and ethanol blends, the prices of HC gasoline

10 and ethanol are unlikely to decouple or make ethanol significantly cheaper than HC gasoline on a gge basis. It is improbable that refiners would purchase and substitute corn ethanol for HC gasoline as BCG has predicted, even when including the AB32 cap-and-trade allowance costs. In the BCG scenario, E85 has infrastructure costs on top of the historical trend of ethanol being more expensive on an energy basis than HC gasoline. In addition, corn ethanol has no benefits for complying with the LCFS since it has a carbon intensity similar to that of HC gasoline. If HC gasoline were used in the BCG scenario instead of corn ethanol, the resulting refining increase of 222 Mbpd of HC gasoline would almost equal the capacity of the BCG-modeled refinery closures. The BCG report also ignored the potential for technological improvements in corn ethanol production. As part of the LCFS, ethanol producers need to register their fuel production pathways and those pathways representative carbon intensity values. Because the goal of the LCFS is to reduce fuel carbon intensity, and one way to do so is to cut energy consumption in the production process, corn ethanol producers will likely find a competitive advantage and economic benefit in reducing their energy consumption through technological improvements. A review of the Method 2B applications already approved pursuant to the most recent regulatory order of the LCFS 9 shows that ethanol manufacturers are producing ethanol with lower carbon intensities than the 2020 compliance standard and are therefore generating LCFS credits. ATV Assumptions BCG s flawed assumptions about ATVs have significant effects on the analysis. The report dismissed ATVs and their potential for compliance with the LCFS, ignoring ATVs in its demand scenario. BCG did not take into account ATV credits, including electricity, natural gas, and hydrogen, in its scenario. The argument for excluding these technologies was based on the incremental cost of ATVs and the assumption that in 2020, there will not be a large enough population. In Exhibit 11 of the report, BCG predicted that California cannot reach the ARB-projected populations of ATVs and cited U.S. hybrid electric vehicle penetrations as evidence. The error in using those projections is that the penetration of hybrid electric vehicles in California is twice the average U.S. penetration rate (5.3% of sales in California compared to 2.8% in the U.S. and over 350,000 hybrids in the California fleet in 2009). In addition, there were already over 400,000 flex-fuel vehicles (FFVs) in California in 2009, 10 and U.S. automakers pledged in 2008 that if E85 infrastructure were available, 50% of automobiles manufactured in the U.S. would be FFVs in model year Given current populations and projected sales based on the automakers pledge, there will be sufficient FFVs in 2020 for the volumes of E85. BCG also ignored the potential of natural gas vehicles to displace HC gasoline and diesel and the associated LCFS credits that could be generated. The relatively low natural gas communication and data request from the California Energy Commission. 7

11 prices relative to gasoline and diesel will encourage greater acceptance by business and commercial fleets. Historically, prices for natural gas as a transportation fuel tracked with diesel prices since natural gas displaced diesel fuel and was considered to be a supply-limited resource. Figure 1 above shows that, with recent use of hydraulic fracturing and the resulting glut of domestic natural gas and corresponding low natural gas prices, compressed natural gas prices have decoupled from diesel prices, creating sufficient price differentials to entice the purchase of natural gas vehicles with shorter payback periods. In addition, automakers have pledged to produce 50,000 fuel cell vehicles (FCVs) in the 2015 timeframe. While this number is small, it lays the foundation for future FCVs. The BCG report failed to account for the potential of FCVs. As part of the LCFS, electricity used for electric transportation, including light-duty vehicles, transit, forklifts and industrial vehicles, can be counted toward LCFS obligations. BCG completely overlooked this compliance option. BCG incorrectly stated that LEV/ZEV standards will not have an impact on the LCFS (page 33 of the BCG report). The LEV/ZEV regulations will decrease demand for petroleum because the vehicles will be more efficient or will use no petroleum at all and will increase electricity and hydrogen consumption. The result will be a decrease in the demand for LCFS credits and an increase in LCFS credit generation. It appears that BCG s assumption that LEV/ZEV regulations will not have an impact was based on its premise of fixing the carbon price before determining the demand for credits or how the LCFS will change the demand for credits. This is another example of how the BCG model did not take into account the price elasticity of supply and demand. The BCG scenario ignored the potential credits produced by ATVs in the CEC gasoline demand forecast. The CEC Low Petroleum demand scenario used by BCG also included over 665 million kwh of electricity and over 200 million gge of CNG. This forecasted electricity and natural gas consumption was omitted from BCG s demand scenario but would have offset over 25 Mbpd and 14.1 Mbpd, respectively, of HC gasoline. These offsets would reduce the need for imported sugarcane ethanol, which was assumed by BCG to be more costly than gasoline (BCG report Key Exhibit 7). ARB s illustrative pathways project that electrified vehicles could produce enough LCFS credits to offset 70 Mbpd of HC gasoline, almost one-third of BCG s modeled scenario of 234 Mbpd of refinery closures in With the inclusion of off-road electrified transportation as mentioned above, there is the potential to double ARB s projections of LCFS credits from electricity in

12 BCG s Economic Assumptions The main economic inaccuracies and assumptions identified by TIAX are: Discussing the costs of only one segment of the transportation fuel market and ignoring benefits to other segments and California as a whole Using a model that does not include price elasticity of supply and demand of petroleum, fuel choice, or fuel switching Overstating the cost and cost range of carbon credits and ignoring the effect carbon offsets would have on the average credit/allowance price No Discussion of Benefits, Only Costs to Refiners In the BCG report, there was no discussion of benefits to the State of California in jobs or economic activity related to the transportation sector, including increased usage of electric, natural gas, and hydrogen vehicles and in-state biofuel production. This is a result of BCG s assumption that LCFS compliance only occurs through the purchase of imported sugarcane ethanol from Brazil. The report ignored the increased consumption of electricity and natural gas for transportation. It also ignored the jobs and economic benefits to California from new infrastructure and new cars (including California-based car companies such as Tesla and statewide dealers selling electrified and natural gas vehicles) for electricity and natural gas that are produced, transported, and dispensed by California utilities and companies. BCG s scenario also ignored the benefits from in-state investment for E85 infrastructure. There are approximately 10,000 gas stations in California, and all of them would need to be converted to have E85 pumps and storage tanks for distribution of the volumes modeled by BCG. At an estimated cost of $154,000 per station upgrade 11 and $0.113 per gallon per year 12 for petroleum terminal upgrades, $2.8 billion would need to be invested by 2020, based on the BCG scenario estimate of billion gge of E85. Also, $169 million would be invested in new distribution trucks, purchased potentially from California-based dealerships, based on $0.18 million per truck to distribute E85 and 11.9 million gge per year per truck. 13 These costs for E85 transport, storage, and infrastructure are already included in BCG s price of ethanol, as stated on page 27 of the report. Utilizing the IMPLAN Input-Output Model construction sector employment multiplier of full-time equivalent (FTE) units of employment for every $1 million of spending in the construction sector, over 44,000 FTEs would be created by the build-out of the E85 refueling infrastructure. The use of FTEs as a measure does not imply that the employees are full-time employees; two or more employees may be employed on a part-time basis, and their total employment may comprise a single FTE. In addition, assuming that petroleum terminal upgrades are comparable to energy efficiency investments in terms of job impacts and using the methodology in Exhibits 51 and 52 for jobs per investment and job multipliers, $1.26 billion invested in terminal upgrades would create between 4,200 and 6,300 new jobs. When including BCG s assumed jobs multiplier of 5 to 7 (Exhibit 11 EPA RFS2 RIA Chapter page Ibid. 13 Ibid. 9

13 52), 21,000 to 44,100 new jobs would be created by the terminal upgrades on account of indirect impacts. This number is comparable to BCG s estimated jobs lost in the refinery sector. This required investment will not only create jobs but also business income in California. BCG s major assumption that only imported sugarcane ethanol generates LCFS credits and that additional corn ethanol imports to California displace HC gasoline excluded any economic impact from biofuels or alternative fuels produced in California. BCG s assumptions zeroed out any economic development from biofuel production in-state, including ethanol, biogas, and biodiesel, and ignored any potential impacts from AB 118, the Alternative and Renewable Fuel and Vehicle Technology Program. CEC, through AB118, is providing funding of up to $100 million annually, leveraging public and private investment to develop and deploy clean, efficient, and low-carbon alternative fuels and technologies. CEC has funded and allocated $48.6 million, $23.9 million, and $16.2 million for biomethane, gasoline substitute (mainly ethanol), and diesel substitute (mainly biodiesel) production within California, respectively. 14 There is an additional $20 million proposed in the Investment Plan for alternative fuel production in California. In previous, upcoming, and proposed funding, CEC has set aside over $120 million for alternative fuel infrastructure and $135 million for alternative fuel vehicles, including electricity (light-, medium- and heavy-duty), hydrogen, natural gas, and E Using an Insufficient Model For BCG to model the effect of AB32 and the LCFS, including the alleged increased price of HC gasoline that would result from refiners needing to purchase allowances, the model needs to include a price elasticity of transportation fuel supply and demand and any HC gasoline price elasticities of other alternative fuel prices. Short-term transportation fuel demand should be almost inelastic, as historical fuel demand has been relatively inelastic with brief price fluctuations, but long-term price increases should see changes in fuel demand through the purchase of more fuel-efficient vehicles and fuel switching from petroleum. In addition, the BCG model lacked price elasticities of supply and demand for alternative fuels and compliance fuels such as sugarcane ethanol. BCG assumed that Brazilian sugarcane ethanol production is static, but if demand increases, then acreage and production will likely increase as well. The USDA suggests that Brazil has the potential to export over 1,100 Mpbd as early as 2018, or twice the amount BCG estimated California would need for LCFS compliance. 16 With the blender s credit and the tariff on sugarcane ethanol factored out, sugarcane ethanol is now cost competitive with corn ethanol Valdes, Constanza, Brazil s Ethanol Industry: Looking Forward, USDA Economic Research Service, June 2011, 10

14 In order to understand the relationship of the transportation fuels and when one fuel is selected over another within the BCG model, it is necessary to know the fuel prices. It is unclear what fuel price assumptions were used by BCG for HC gasoline and ethanol (the effect of all other alternative fuels were neglected). BCG utilized the CEC Low Petroleum demand scenario. If this scenario had included phase II of California s vehicle GHG standards, it would suffice as a baseline scenario for HC gasoline consumption, but since it does not include AB32 cap-and-trade and the LCFS, it is not a sufficient scenario for these modeling purposes. In addition, it utilizes the CEC High Petroleum price scenario, which includes E85 prices equal to that of gasoline ($4.93 per gge in 2010 dollars). The CEC scenario is based on the following assumption: This assumption was made since flex fuel vehicles can also use gasoline and thus E85 is a substitute for gasoline for these consumers. Since E85 is directly competing with gasoline, consumers will eventually base their purchasing decisions on the fuel economy realized per gallon, driving the price to this energy content equivalency. 17 In addition, the CEC Low Petroleum demand scenario estimates crude prices in 2020 at $143 per barrel in 2010 dollars, or $33 per barrel higher than BCG s $110 per barrel. Moreover, the BCG model did not take into account future conditions (the current trading price of Brent Crude is over $110 per barrel), market fluctuations, or oil forecasts from the EIA or CEC, where the petroleum demand scenario came from. Overstating the Cost and Range of Carbon Prices The BCG analysis and scenario assumed that shocks in carbon prices will be similar to the spikes seen in electricity prices in This is an invalid assumption for carbon price shocks, as the electricity price volatility in 2000 was due to deliberate market manipulation. Because of this assumption, BCG assumed that carbon prices could be four to five times higher than the Reuters-forecasted carbon price of $30 to $35 per ton, thereby considering scenarios of up to $150 per ton. This overstates the potential costs of carbon credits, AB32, and the LCFS. As a stop-gap measure, ARB does have an Allowance Price Containment Reserve where additional allowances can be auctioned when the price of carbon reaches a certain threshold. BCG used a carbon price range of $14.1 to $70.4 per ton in its main analysis. These prices, especially when considered as average prices and not the most expensive marginal prices and not including offsets, appear high. BCG ignored emission reduction opportunities at refineries (e.g., energy efficiency) that would be much cheaper compliance options than purchasing allowances at $60 to $70 per ton and would put downward pressure on allowance prices in the market. Page 27 of the BCG report states: A second effect of the cap and trade program is that investments in energy efficiency that were previously not profitable or had an unacceptably long payback period could become more attractive. Some of 17 California Energy Commission, Transportation Energy Forecasts and Analyses for the 2011 Integrated Energy Policy Report, Draft Staff Report, August 2011, CEC SD, page B-7. 11

15 these projects, their costs, and their effects on emissions are discussed in Section 4.3. Section 4.3 is silent on these issues, and the model assumed refinery emissions are constant from 2009 to 2020 (i.e., zero energy efficiency improvements). In addition, ARB allows 8% of a company s AB32 cap-and-trade compliance obligation to come from carbon offsets. BCG did not consider the purchase of offsets for companies to meet their compliance obligations and assumed that compliance occurs only through the purchase of auctioned allowances. Current and projected prices of carbon offsets that can be used for compliance with AB32 cap-and-trade are at the low end of BCG s range for carbon allowances; i.e., $11 to $13 per ton. 18 These low-cost carbon offsets will drive down the average cost of compliance when compared to auctioned allowances. 18 Evolution Markets, Monthly Market Update (August 2012). 12

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