U.S. Energy Information Administration - EIA - Independent Statistics and Analysis
Annual Energy Outlook 2013
Legislation and regulations
The Annual Energy Outlook 2013 (AEO2013) generally represents current federal and state legislation and final implementation regulations as of the end of September 2012. The AEO2013 Reference case assumes that current laws and regulations affecting the energy sector are largely unchanged throughout the projection period (including the implication that laws that include sunset dates are no longer in effect at the time of those sunset dates) . The potential impacts of proposed legislation, regulations, or standards—or of sections of authorizing legislation that have been enacted but are not funded or where parameters will be set in a future regulatory process—are not reflected in the AEO2013 Reference case, but some are considered in alternative cases. The AEO2013 Reference case does not reflect the provisions of the American Taxpayer Relief Act of 2012 (P.L. 112-240) enacted on January 1, 2013 . Key energy-related provisions of that legislation—including extension of the production tax credit for renewable generation, tax credits for energy—efficient appliances, and tax credits for selected biofuels—are reflected in an alternative case completed as part of AEO2013. This section summarizes federal and state legislation and regulations newly incorporated or updated in AEO2013 since the completion of the Annual Energy Outlook 2012 (AEO2012).
Examples of federal and state legislation and regulations incorporated in the AEO2013 Reference case or whose handling has been modified include:
- Incorporation of new light-duty vehicle greenhouse gas emissions (GHG) and corporate average fuel economy (CAFE) standards for model years 2017 to 2025 
- Continuation of the Clean Air Interstate Rule (CAIR)  after the court's announcement of intent to vacate the Cross—State Air Pollution Rule (CSAPR) .
- Updated handling of the U.S. Environmental Protection Agency's (EPA) National Emissions Standards for Hazardous Air Pollutants (NESHAP) for industrial boilers and process heaters 
- Modeling of California's Assembly Bill 32, the Global Warming Solutions Act (AB 32) , that allows for representation of a cap-and-trade program developed as part of California's GHG reduction goals for 2020
- Incorporation of the California Low Carbon Fuel Standard (LCFS) , which requires fuel producers and importers who sell motor gasoline or diesel fuel in California to reduce the carbon intensity of those fuels by an average of 10 percent between 2012 and 2020 through the mixing and increased sale of alternative low-carbon fuels.
There are many other pieces of legislation and regulation that appear to have some probability of being enacted in the not-too-distant future, and some laws include sunset provisions that may be extended. However, it is difficult to discern the exact forms that the final provisions of pending legislation or regulations will take, and sunset provisions may or may not be extended. Even in situations where existing legislation contains provisions to allow revision of implementing regulations, those provisions may not be exercised consistently. Many pending provisions are examined in alternative cases included in AEO2013 or in other analyses completed by the U.S. Energy Information Administration (EIA). In addition, at the request of the Administration and Congress, EIA has regularly examined the potential implications of other possible energy options in Service Reports. Those reports can be found on the EIA website at eia.gov/oiaf/service_rpts.htm.
1. Greenhouse gas emissions and corporate average fuel economy standards for 2017 and later model year light-duty vehicles
On October 15, 2012, EPA and the National Highway Traffic Safety Administration (NHTSA) jointly issued a final rule for tailpipe emissions of carbon dioxide (CO2) and CAFE standards for light-duty vehicles, model years 2017 and beyond . EPA, operating under powers granted by the Clean Air Act (CAA), issued final CO2 emissions standards for model years 2017 through 2025 for passenger cars and light-duty trucks, including medium-duty passenger vehicles. NHTSA, under powers granted by the Energy Policy and Conservation Act, as amended by the Energy Independence and Security Act, issued CAFE standards for passenger cars and light-duty trucks, including medium-duty passenger vehicles, for model years 2017 through 2025.
The new CO2 emissions and CAFE standards will first affect model year 2017 vehicles, with compliance requirements increasing in stringency each year thereafter through model year 2025. EPA has established standards that are expected to require a fleet-wide average of 163 grams CO2 per mile for light-duty vehicles in model year 2025, which is equivalent to a fleet-wide average of 54.5 miles per gallon (mpg) if reached only through fuel economy. However, the CO2 emissions standards can be met in part through reductions in air-conditioning leakage and the use of alternative refrigerants, which reduce CO2-equivalent GHG emissions but do not affect the estimation of fuel economy compliance in the test procedure.
NHTSA has established two phases of CAFE standards for passenger cars and light-duty trucks (Table 1). The first phase, covering model years 2017 through 2021, includes final standards that NHTSA estimates will result in a fleet-wide average of 40.3 mpg for light-duty vehicles in model year 2021 . The second phase, covering model years 2022 through 2025, requires additional improvements leading to a fleet-wide average of 48.7 mpg for light-duty vehicles in model year 2025. Compliance with CO2 emission and CAFE standards is calculated only after final model year vehicle production, with fleet-wide light-duty vehicle standards representing averages based on the sales volume of passenger cars and light-duty trucks for a given year. Because sales volumes are not known until after the end of the model year, EPA and NHTSA estimate future fuel economy based on the projected sales volumes of passenger cars and light-duty trucks.
The new CO2 emissions and CAFE standards for passenger cars and light-duty trucks use an attribute-based standard that is determined by vehicle footprint—the same methodology that was used in setting the final rule for model year 2012 to 2016 light-duty vehicles. Footprint is defined as wheelbase size (the distance from the center of the front axle to the center of the rear axle), multiplied by average track width (the distance between the center lines of the tires) in square feet. The minimum requirements for CO2 emissions and CAFE are production-weighted averages based on unique vehicle footprints in a manufacturer's fleet and are calculated separately for passenger cars and light-duty trucks (Figures 9 and 10), reflecting their different design capabilities. In general, as vehicle footprint increases, compliance requirements decline to account for increased vehicle size and load-carrying capability. Each manufacturer faces a unique combination of CO2 emission and CAFE standards, depending on the number of vehicles produced and the footprints of those vehicles, separately for passenger cars and light-duty trucks.
For passenger cars, average fleet-wide compliance levels increase in stringency by 3.9 percent annually between model years 2017 and 2021 and by 4.7 percent annually between 2022 and 2025, based on the model year 2010 baseline fleet. In recognition of the challenge of improving the fuel economy and reducing CO2 emissions of full-size pickup trucks while maintaining towing and payload capabilities, the average annual rate of increase in the stringency of light-duty truck standards is 2.9 percent from 2017 to 2021, with smaller light-duty trucks facing higher increases and larger light-duty trucks lower increases in compliance stringency. From 2022 to 2025, the average annual increase in compliance stringency for all light-duty trucks is 4.7 percent.
The CO2 emissions and CAFE standards also include flexibility provisions for compliance by individual manufacturers, such as: (1) credit averaging, which allows credit transfers between a manufacturer's passenger car and light-duty truck fleets; (2) credit banking, which allows manufacturers to "carry forward" credits earned from exceeding the standards in earlier model years and to "carry back" credits earned in later model years to offset shortfalls in earlier model years; (3) credit trading between manufacturers who exceed their standards and those who do not; (4) air conditioning improvement credits that can be applied toward CO2 emissions standards; (5) off-cycle credits for measurable improvements in CO2 emissions and fuel economy that are not captured by the two-cycle test procedure used to measure emissions and fuel consumption; (6) CO2 emissions "compliance multipliers" for electric, plug-in hybrid electric, compressed natural gas, and fuel cell vehicles through model year 2021; and (7) incentives for the use of hybrid electric and other advanced technologies in full-size pickup trucks.
Finally, flexibility provisions do not allow domestic passenger cars to deviate significantly from annual fuel economy targets. NHTSA retains a required minimum fuel economy level for domestically produced passenger cars by manufacturer that is the higher of 27.5 miles per gallon or 92 percent of the average fuel economy projected for the combined fleet of domestic and foreign passenger cars for sale in the United States. For example, the minimum standard for passenger cars sold by a manufacturer in 2025 would be 50.9 miles per gallon, based on the estimated fleet average passenger car fuel economy for that year.The AEO2013 Reference case includes the final CAFE standards for model years 2012 through 2016 (promulgated in March 2010)  and the standards for model years 2017 through 2025, with subsequent CAFE standards for years 2026-2040 vehicles calculated using 2025 levels of stringency. The AEO2013 Reference case projects fuel economy values for passenger cars, light-duty trucks, and combined light-duty vehicles that differ from NHTSA projections. This variance is the result of a different distribution of the production of passenger cars and light-duty trucks by footprint as well as a different mix between passenger cars and light-duty trucks (Table 2). CAFE standards are included by using the equations and coefficients employed by NHTSA to determine unique fuel economy requirements based on footprint, along with the ability of manufacturers to earn flexibility credits toward compliance. The AEO2013 Reference case projects sales of passenger cars and light-duty trucks by vehicle footprint with the key assumption that vehicle footprints are held constant by manufacturer in each light-duty vehicle size class.
On August 21, 2012, the United States Court of Appeals for the District of Columbia Circuit announced its intent to vacate CSAPR, which it had stayed from going into effect earlier in 2012. CSAPR was to replace CAIR, which was in effect, by establishing emissions caps (levels) for sulfur dioxide (SO2) and nitrogen oxides (NOX) emissions from power plants in the eastern half of the United States. As a result of the court's action, the regulation of SO2 and NOX emissions will continue to be administered under CAIR pending the promulgation of a valid replacement. AEO2013 assumes that CAIR remains a binding regulation through 2040.
CAIR covers all fossil-fueled power plant units with nameplate capacity greater than 25 megawatts in 27 eastern states and the District of Columbia (Figure 11). Twenty-two states and the District of Columbia fall under the caps for both annual emissions of SO2 and NOX and ozone season NOX. Three states are controlled for only ozone season NOX , and two states are controlled for only annual SO2 and NOX emissions. The caps went into effect for NOX in 2009 and for SO2 in 2010. Both caps are scheduled to be tightened again in 2015. AEO2013 considered how the power sector would use the emissions allowance trading that EPA set up to lower compliance costs, including capturing the interplay of the SO2 program for acid rain under the Clean Air Act Amendments Title IV and the CAIR program that uses the same allowances.
Although CSAPR shared some basic similarities with CAIR, there are key differences between the two programs. Generally, CSAPR had greater limitations on trading to ensure that emissions reductions would occur in all states; lower emissions caps; and more rapid phasing in of tighter emissions caps. CSAPR also did not allow carryover of banked allowances from the Acid Rain SO2 and NOX Budget programs. Each program was aimed at substantial reductions of power sector SO2 and NOX emissions.
AEO2013 represents the limits on SO2 and NOX emissions trading as specified by CAIR. The National Energy Modeling System (NEMS) includes the representation of emissions for both the CAIR and non-CAIR regions. In NEMS, power plants in both regions are required to submit allowances to account for their emissions as if covered by the rule. NEMS allows for power plants in the CAIR regions to trade SO2 allowances with those plants in the non-CAIR region, but the SO2 allowances are valued differently for each region. NEMS also allows for the banking of SO2 and NOX allowances consistent with CAIR's provisions.
Waste confidence is defined by the U.S. Nuclear Regulatory Commission (NRC) as a finding that spent nuclear fuel can be safely stored for decades beyond the licensed operating life of a reactor without significant environmental effects . It enables the NRC to license reactors or renew their licenses without examining the effects of extended waste storage for each individual site pending ultimate disposal.
NRC's Waste Confidence Rule issued in August 1984  included five findings:
- Spent nuclear fuel can be disposed of safely in a mined geologic repository.
- A mined geologic repository will be available when needed for disposal of spent nuclear fuel.
- Until a mined geologic repository is available, spent nuclear fuel can be safely managed.
- Spent nuclear fuel can be safely stored at reactors for 30 years without significant environmental impacts.
- Storage will be made available for spent nuclear fuel onsite or offsite, if required.
The NRC issued an order in August 2012 that suspended actions related to issuance of operating licenses and license renewals . Currently, the NRC is analyzing the potential impacts on licensing reviews and developing a proposed path forward to meet the court's requirements. Until the NRC revises the Waste Confidence Rule, it will not issue reactor operating licenses or operating license renewals. Licensing reviews and proceedings will continue, but Atomic Safety and Licensing Board hearings will be suspended pending further NRC guidance. NRC expects to issue a revised Waste Confidence Rule within 2 years .
Reactors with license renewal applications under review by the NRC may continue to operate, even if their existing licenses expire, until the NRC can resolve the waste confidence issue and promulgate a revised rule. The regulation states: "If the licensee of a nuclear power plant licensed under 10 CFR 50.21(b) or 50.22 files a sufficient application for renewal of either an operating license or a combined license at least 5 years before the expiration of the existing license, the existing license will not be deemed to have expired until the application has been finally determined" . There are currently 15 reactors with license renewal applications in various stages of review by the NRC that are subject to the August 2012 order that suspends licensing decisions.
For those reactors that have not submitted applications for license renewal, the first license expiration date would occur in 2020. Because it is anticipated by the NRC that the issues with the Waste Confidence Rule will be resolved within 2 years, well before 2020, the continued operation of those reactors should not be affected. The AEO2013 Reference case assumes plants that have not submitted applications for license renewal will be unaffected.
Currently, utilities have the option to license reactors under either of two NRC rules. The NRC's Domestic Licensing of Production and Utilization Facilities rule defines a two-step process for obtaining an operating license . First, a construction permit is issued, and then an operating license is issued. There are two U.S. reactors with current construction permits: Bellefonte Unit 1 and Watts Bar Unit 2. Both plants are owned by the Tennessee Valley Authority (TVA), which has announced that construction of Bellefonte Unit 1 will not proceed until fuel loading at Watts Bar Unit 2 is completed . Neither reactor will be able to receive an operating license until the waste confidence issue is resolved, but construction may continue. TVA has not provided a projected date for commencement of operations at Bellefonte Unit 1, but it is unlikely that resolution of the issues associated with the Waste Confidence Rule will affect the operational date of Bellefonte Unit 1. Watts Bar Unit 2 was originally scheduled to go online in 2012, but delays in construction make it unlikely that it will be ready to begin operation before the issues with the Waste Confidence Rule can be resolved. AEO2013 assumes that Watts Bar Unit 2 will come online in December 2015.
The NRC's "Licenses, Certifications, and Approvals for Nuclear Power Plants" rule defines a one-step process, whereby the construction permit and operating license are issued as a combined license (COL) . Once an application for a COL is submitted, the utility may engage in certain pre-construction activities. To date, two plants, each with two reactors, have received COLs in 2012. Vogtle Units 3 and 4 and Summer Units 2 and 3 will both be unaffected by the issues with the Waste Confidence Rule. Once construction and all inspections are complete, the Vogtle and Summer plants may commence operations. For utilities that have submitted applications but have not received COLs, issuance of those licenses may be delayed. For COL applications currently under active review, it is possible that two—Levy County Units 1 and 2 and William States Lee III Units 1 and 2—may be delayed, based on their review status and the NRC's schedule for application reviews. The online dates for the units should be unaffected if issues with the Waste Confidence Rule are resolved within the next 2 years.
Based on EIA's analysis of the Waste Confidence Rule and ongoing proceedings, the AEO2013 Reference case assumes that the issuance of new operating licenses will not be affected. AEO2013 also assumes that the Waste Confidence Rule will not affect power uprates, because uprates do not increase the amount of spent nuclear fuel requiring storage, as confirmed in a public policy statement issued by the NRC .
Section 112 of the CAA requires the regulation of air toxics through implementation of NESHAP for industrial, commercial, and institutional boilers . The final regulations are also known as "Boiler MACT," where MACT is the Maximum Achievable Control Technology. Pollutants covered by the Boiler MACT regulations include control of hazardous air pollutants (HAPs), such as hydrogen chloride, mercury (Hg), and dioxin/furan, as well as carbon monoxide (CO), and particulate matter (PM) as surrogates for other HAPs. Boilers used for generating electricity are explicitly covered by the Mercury and Air Toxics Standards, also under Section 112 of the CAA, and are specifically excluded from Boiler MACT regulations.
The Final Rule for Boiler MACT was issued in March 2011; a partial Reconsideration Rule concerning limited technical corrections to the Final Rule was issued in December 2011, but it did not replace the Final Rule. The AEO2013 Reference case assumes that the Final Rule and the partial Reconsideration Rules are in force. The finalized Boiler MACT rule was announced in December 2012, after the modeling work for AEO2013 was completed. The provisions of the finalized Boiler MACT rule are less stringent than the provisions of the Final Rule and the partial Reconsideration Rule assumed in the Reference case. For AEO2013, the upgrade costs of Boiler MACT were implemented in the Macroeconomic Activity Module (MAM). Upgrade costs used are the "nonproductive costs," which are not associated with efficiency improvements. The upgrade costs are applied as an aggregated cost across all industries. Because of this aggregation of cost and the need for consistency across industries, the cost in the MAM is manifested as a reduction in shipments in the Industrial Demand Module. There is little difference in the cost of compliance for major sources between the March 2011 Final Rule and the December 2011 Reconsideration Rule, and there is no difference for area sources.
Boiler MACT has two compliance groups with different obligations: major source , and area source. A site that contains one or more boilers or process heaters that have the potential to emit 10 or more tons of any one HAP per year, or 25 tons or more of a combination of HAP per year, is a major source . An emissions site that is not a major source is classified as an area source. The characteristics of the site determine the compliance group of the boiler. Generally, compliance measures include regular maintenance and tuneups for smaller facilities and emission limits and performance tests for larger facilities. In the Reconsideration Rule, EIA calculations based on EPA estimates revealed that there were 14,111 existing major source boilers in 2011 . Of those, calculations based on EPA estimates revealed that 16 percent burn fuels that potentially may subject them to specific emissions limits and annual performance tests. The existing number of affected area source boilers in 2011 was estimated at 189,450 by EIA, using data from EPA .
To comply with Boiler MACT, major source boilers and process heaters whose heat input is less than 10 million Btu per hour must receive tuneups every 2 years . Most existing and new major source boilers or process heaters with heat inputs 10 million Btu per hour or greater that burn coal, biomass, liquid, or "other" gas are subject to emission limits on all five of the HAP listed above . Larger major source boilers with heat input of 25 million Btu per hour or greater that burn coal, biomass, or residual oil must use a continuous emission monitoring system for PM . Major source boilers with heat inputs of 10 million Btu per hour or more that burn natural gas or refinery gas, as well as metal process furnaces, are not subject to specific emissions limits or performance tests . Existing major source boilers must comply with the Final Rule by March 21, 2014; new major source boilers must comply by May 20, 2011, or upon startup, whichever is later .
Area source natural gas-fired boilers are not subject to Boiler MACT. Area source coal-fired boilers whose heat input is less than 10 million Btu per hour and biomass-fired and liquid fuel-fired boilers of any size must receive a tuneup every 2 years. Existing area source boilers with heat input of 10 million Btu per hour or greater are subject to emissions limits, must receive an initial energy assessment, and must undergo performance tests every 3 years . Existing and new coal-fired boilers must meet Hg and CO limits; new coal-fired boilers must also meet limits for PM. New oil-fired and biomass-fired boilers must meet emissions limits only for PM . Existing area source boilers subject to an energy assessment and emissions limits must comply by March 21, 2014.
To the extent possible, AEO2013 incorporates the impacts of state laws requiring the addition of renewable generation or capacity by utilities doing business in the states. Currently, 30 states and the District of Columbia have an enforceable renewable portfolio standard (RPS) or similar law (Table 3). Under such standards, each state determines its own levels of renewable generation, eligible technologies , and noncompliance penalties. AEO2013 includes the impacts of all RPS laws in effect at the end of 2012 (with the exception of Alaska and Hawaii, because NEMS provides electricity market projections for the contiguous lower 48 states only). However, the projections do not include policies with either voluntary goals or targets that can be substantially satisfied with nonrenewable resources. In addition, NEMS does not treat fuel-specific provisions—such as those for solar and offshore wind energy—as distinct targets. Where applicable, such distinct targets (sometimes referred to as "tiers," "set-asides," or "carve-outs") may be subsumed into the broader targets, or they may not be included in the modeling because they could be met with existing capacity and/or projected growth based on modeled economic and policy factors.
In the AEO2013 Reference case, states generally are projected to meet their ultimate RPS targets. The RPS compliance constraints in most regions are approximated, because NEMS is not a state-level model, and each state generally represents only a portion of one of the NEMS electricity regions. Compliance costs in each region are tracked, and the projection for total renewable generation is checked for consistency with any state-level cost-control provisions, such as caps on renewable credit prices, limits on state compliance funding, or impacts on consumer electricity prices. In general, EIA has confirmed the states' requirements through original documentation, although the Database of State Incentives for Renewables & Efficiency was also used to support those efforts .
No new RPS programs were enacted over the past year; however, some states with existing RPS programs made modifications in 2012, as discussed below. The aggregate RPS requirement for the various state programs, as modeled in AEO2013, is shown in Figure 12. In 2025 the targets account for about 10 percent of U.S. electricity sales. The requirement is derived from the legal targets and projected sales and does not account for any of the discretionary or nondiscretionary waivers or limits on compliance found in most state RPS programs.
At present, most states are meeting or exceeding their required levels of renewable generation based on qualified generation . A number of factors have helped to create an environment favorable for RPS compliance, including a surge of new RPS-qualified generation capacity timed to take advantage of federal incentives that either have expired or were scheduled to expire; significant reductions in the cost of renewable technologies like wind and solar; and generally reduced growth (or, in some cases, even contraction) of electricity sales. In addition to the availability of federal tax credits, which historically have gone through a cycle of expiration and renewal, renewable energy projects were given access to other options for federal support, including cash grants (also known as Section 1603 grants) and loan guarantees. The short-term availability of federal incentives has helped to make renewable capacity attractive to investors and helped utilities meet state requirements or potential future load growth in advance (that is, build ahead of time to take advantage of the federal incentives). The attractiveness of renewable projects to investors has also been supported by declining equipment costs for wind turbines and solar photovoltaic systems, as well as by improvements in the performance of those technologies. The declines in technology cost are, in themselves, the result of a complex set of interactions of policy, market, and engineering factors. Finally, most state RPS programs have targets that are tied to retail electricity sales; and with relatively slow growth in electricity sales in most parts of the country, the renewable generation that has entered service recently has gone further toward meeting the proportionally lower targets for absolute amounts of energy (that is, for kilowatthours of energy, as opposed to energy as a percent of sales).
EIA projects that, overall, RPS-qualified generation will continue to meet or exceed aggregate targets for state RPS programs through 2040, as shown in Figure 12. Through the next decade, the surplus qualifying generation will decline gradually, as little additional qualifying capacity is added, allowing the targets to catch up with supply. By the end of the projection horizon, however, the surplus widens substantially as renewable generation technologies become increasingly competitive with conventional generation sources. It should be noted that the aggregate targets and qualifying generation shown in Figure 12 may mask significant regional variation, with some regions producing excess qualifying generation and others producing just enough to meet the requirement or even needing to import generation from adjoining regions to meet state targets. Furthermore, just because there is, in aggregate, more qualifying generation than is needed to meet the targets, this does not necessarily imply that projected generation would be the same without state RPS policies. State RPS policies may encourage investment in places where it otherwise would not occur, or would not occur in the amounts projected, even as other parts of the country see substantial growth above state targets, or even in their absence. It does, however, suggest that state RPS programs will not be the sole reason for future growth in renewable generation.
Recent RPS modifications
A number of states modified their RPS programs in 2012, either through regulatory proceedings or through legislative action. These changes are reflected in Table 3. The changes affect some aspects of the laws and implementing regulations, but they do not have substantive effects on the representation of the RPS programs in AEO2013. Key changes include:
California Assembly Bill 2196, which establishes requirements for certain biomass-based generation resources, requires that biomass-derived gas be produced on site or sourced from a common carrier pipeline that operates within the state. It also sets additional requirements related to the in-service date of a common carrier source and the ability to claim certain environmental benefits from the use of such sources.
The state enacted a series of bills that accelerate the solar-specific compliance schedule (while leaving the aggregate RPS target unchanged) and expand the tier 1 requirement category to include thermal output from certain animal waste and ground-source heat pumps.
The Department of Energy Resources issued final rules regarding the use of certain biomass resources to meet the RPS standard. Biomass facilities must meet certain conditions with regard to conversion technology and feedstock sourcing to be eligible for use in meeting the standard.
Senate Bill 218 allows certain thermal resources, including heat derived from qualified solar, geothermal, and biomass sources, to meet renewable energy targets. It also allows electricity produced from the cofiring of biomass in certain existing coal plants to meet the requirements. The bill also adjusts the total renewable energy target upward by 1 percentage point, to 24.8 percent by 2025.
Senate Bill 1925 changed the compliance schedule for the solar component of the RPS. The revised law is implemented with a solar target of 3.47 percent of sales by 2021.
The legislature passed a set of laws that allow certain types of cogeneration facilities to qualify in meeting the RPS.
6. California Assembly Bill 32: Emissions cap-and-trade as part of the Global Warming Solutions Act of 2006
California's AB 32, the Global Warming Solutions Act of 2006, authorized the California Air Resources Board (CARB) to set California's overall GHG emissions reduction goal to its 1990 level by 2020 and establish a comprehensive, multi-year program to reduce GHG emissions in California, including a cap-and-trade program .In addition to the cap-and-trade program, other authorized measures include the LCFS; energy efficiency goals and programs in transportation, buildings, and industry; combined heat and power goals; and RPS .
The cap-and-trade program features an enforceable cap on GHG emissions that will decline over time. CARB will distribute tradable allowances equal to the emissions allowed under the cap. Enforceable compliance obligations begin in 2013 for the electric power sector, including electricity imports, and for industrial facilities. Fuel providers must comply starting in 2015. All facilities that emit 25,000 metric tons carbon dioxide equivalent (CO2e) or more are subject to cap-and-trade regulations. The only exception is that, starting in 2015, all importers of electricity from electric facilities outside of California will be subject to cap-and-trade regulations, even from facilities that emit less than 25,000 metric tons CO2e.
The most significant GHG covered under the program is CO2, but the cap-and-trade program covers several other GHGs , including methane, nitrous oxide, perfluorocarbons, chlorofluorocarbons, nitrogen trifluoride, and sulfur hexafluoride . In 2007, CARB determined that 427 million metric tons carbon dioxide equivalent (MMTCO2e) was the total state-wide GHG emissions level in 1990 and, therefore, would be the 2020 emissions goal. CARB estimates that the implementation of the cap-and-trade program will reduce GHG emissions by between 18 and 27 MMTCO2e in 2020 .
The enforceable cap goes into effect in 2013, and there are three multi-year compliance periods:
- Compliance period 1 (2013-2014) includes sources of GHG emissions responsible for more than one-third of state-wide emissions.
- Compliance period 2 (2015-2017) covers sources of GHG emissions responsible for about 85 percent of state-wide emissions.
- Compliance period 3 (2018-2020) covers the same sources as Compliance Period 2 .
The electric power and industrial sectors are required to comply with the cap starting in 2013. Providers of natural gas, propane, and transportation fuels are required to comply starting in 2015, when the second compliance period begins. For the first compliance period, covered entities are required to submit allowances for up to 30 percent of their annual emissions in each year; however, at the end of 2014 they are required to account for all the emissions for which they were responsible during the 2-year period. Each covered entity can also use offsets to meet up to 8 percent of its compliance obligation. Offsets used as part of the program must be approved by CARB and can be canceled later by CARB for certain reasons (a provision known as "buyer liability").
A majority (51 percent) of the allowances  allocated over the initial 8 years of the program will be distributed through price containment reserves and auctions, which will be held quarterly when the program commences. CARB's first allowance auction was held in November 2012 . Future auctions may be linked to Québec's cap-and-trade program . Twenty-five percent of the allowances are allocated directly to electric utilities that sell electricity to consumers in the state. Seventeen percent of the allowances are allocated directly to affected industrial facilities in order to mitigate the economic impact of the cap on the industrial sector . Allowance allocations for the industrial sector are based on output. Starting in 2013, the number of allowances allocated annually to the industrial sector declines linearly to 50 percent of the original total in 2020. The remaining 7 percent of the allowances issued in a given year go into a price containment reserve, to be used only if allowance prices rise above a set amount in quarterly auctions.
The AB 32 cap-and-trade provisions, which were incorporated only for the electric power sector in AEO2012, are more fully implemented in AEO2013, adding industrial facilities, refineries, fuel providers, and non-CO2 GHG emissions. The allowance price, representing the incremental cost of complying with AB 32 cap-and-trade, is modeled in the NEMS Electricity Market Module via a region-specific emissions constraint. This allowance price, when added to the market fuel prices, results in higher effective fuel prices  in the demand sectors. Limited banking and borrowing, as well as a price containment reserve  and offsets, also have been modeled, providing some compliance flexibility and cost containment. NEMS macroeconomic effects are based on an energy-economy equilibrium that reacts to changes in energy prices and energy consumption; however, no macroeconomic effects are assumed explicitly from the AB 32 cap-and-trade provisions.
The LCFS, administered by CARB , is designed to reduce by 10 percent the average carbon intensity of motor gasoline and diesel fuels sold in California from 2012 to 2020 through the increased sale of alternative "low-carbon" fuels. Regulated parties generally are the fuel producers and importers who sell motor gasoline or diesel fuel in California. The program is assumed to remain in place at 2020 levels from 2021 to 2040 in AEO2013. The carbon intensity of each alternative low-carbon fuel, based on life-cycle analyses conducted under the guidance of CARB for a number of approved fuel pathways, is calculated on an energy-equivalent basis, measured in grams of CO2-equivalent emissions per megajoule.
AEO2013 incorporates the LCFS by requiring that the average carbon intensity of motor fuels sold for use in California meets the carbon intensity targets. For the AEO2013 Reference case, carbon intensity targets and the carbon intensities of alternative fuels were adapted from the "Third Notice of Public Availability of Modified Text and Availability of Additional Documents and Information" . Key uncertainties in the modeling of the LCFS are the availability of low-carbon fuels in California and what actions CARB may take if the LCFS is not met. In AEO2013, these uncertainties are addressed by assuming that fuel providers can purchase low-carbon credits if low-carbon fuels cannot be produced and sold at reasonable prices.
In December 2011, the U.S. District Court for the Eastern Division of California ruled in favor of several trade groups that claimed the LCFS violated the interstate commerce clause of the U.S. Constitution by seeking to regulate farming and ethanol production practices in other states. The court granted an injunction blocking enforcement of the LCFS by CARB . In April 2012, the U.S. Ninth District Court of Appeals granted a stay of injunction while CARB appeals the original ruling . Although the future of the LCFS program remains uncertain, the stay of the injunction requires that the program be enforced.
Endnotes for Legislation and regulation
8. A complete list of the laws and regulations included in AEO2013 is provided in Assumptions to the Annual Energy Outlook 2013, Appendix A, http://www.eia.gov/forecasts/aeo/assumptions/pdf/0554(2013).pdf.
9. U.S. Government Printing Office, "American Taxpayer Relief Act of 2012, Public Law 112-240" (Washington, DC: January 1, 2013), http://www.gpo.gov/fdsys/pkg/PLAW-112publ240/pdf/PLAW-112publ240.pdf.
10. U.S. Environmental Protection Agency and National Highway Traffic Safety Administration, "2017 and Later Model Year Light-Duty Vehicle Greenhouse Gas Emissions and Corporate Average Fuel Economy Standards; Final Rule," Federal Register, Vol. 77, No. 199 (Washington, DC: October 15, 2012), https://www.federalregister.gov/articles/2012/10/15/2012-21972/2017-and-later-model-year-light-duty-vehicle-greenhouse-gas-emissions-and-corporate-average-fuel.
11.U.S. Environmental Protection Agency, "Clean Air Interstate Rule (CAIR)" (Washington, DC: December 19, 2012), http://www.epa.gov/cair/index.html#older.
12. U.S. Environmental Protection Agency, "Fact Sheet: The Cross-State Air Pollution Rule: Reducing the Interstate Transport of Fine Particulate MaItter and Ozone" (Washington, DC: July 2011), http://www.epa.gov/airtransport/pdfs/CSAPRFactsheet.pdf.
13. Clean Air Act, 42 U.S.C. 7412 (2011), http://www.gpo.gov/fdsys/pkg/USCODE-2011-title42/pdf/USCODE-2011-title42-chap85-subchapI-partA.pdf.
14. State of California, Assembly Bill No. 32, Chapter 488, "California Global Warming Solutions Act of 2006" (Sacramento, CA: September 27, 2006), http://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=200520060AB32&search_keywords.
15. California Code of Regulations, "Final Regulation Order: Subchapter 10. Climate Change, Article 4. Regulations to Achieve Greenhouse Gas Emission Reductions, Subarticle 7, Low Carbon Fuel Standard," Sections 95480 to 95490 (Sacramento, CA: July 2011), https://www.arb.ca.gov/regact/2009/lcfs09/finalfro.pdf.
16. U.S. Environmental Protection Agency and National Highway Traffic Safety Administration, "2017 and Later Model Year Light-Duty Vehicle Greenhouse Gas Emissions and Corporate Average Fuel Economy Standards; Final Rule," Federal Register, Vol. 77, No. 199 (Washington, DC: October 15, 2012), https://www.federalregister.gov/articles/2012/10/15/2012-21972/2017-and-later-model-year-light-duty-vehicle-greenhouse-gas-emissions-and-corporate-average-fuel.
17. Fuel economy projection averages based on a 2010 baseline fleet. NHTSA alternatively lists projected compliance fuel economy averages based on the 2008 baseline fleet. EPA lists compliance-level average CO2 tailpipe emissions based solely on the 2008 baseline fleet.
18. U.S. Environmental Protection Agency and National Highway Traffic Safety Administration, "Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards; Final Rule," Federal Register, Vol. 75, No. 88 (Washington, DC: May 7, 2010), https://www.federalregister.gov/articles/2010/05/07/2010-8159/light-duty-vehicle-greenhouse-gas-emission-standards-and-corporate-average-fuel-economy-standards.
19. U.S. Nuclear Regulatory Commission, "Temporary storage of spent nuclear fuel after cessation of reactor operation—generic determination of no significant environmental impact," (Washington, DC: December 18, 2012), http://www.nrc.gov/reading-rm/doc-collections/cfr/part051/part051-0023.html.
20. U.S. Nuclear Regulatory Commission, "Waste Confidence Decision," Federal Register, Vol. 49, No. 171 (Washington, DC: August 31, 1984), http://pbadupws.nrc.gov/docs/ML1233/ML12335A680.pdf.
21. U.S. Nuclear Regulatory Commission, "Waste Confidence Decision Review," Federal Register, Vol. 55, No. 181 (Washington, DC: September 18, 1990), http://pbadupws.nrc.gov/docs/ML1209/ML120960684.pdf.
22. U.S. Nuclear Regulatory Commission, "Waste Confidence Decision Update," Federal Register, Vol. 75, No. 246 (Washington, DC: December 23, 2010), pp. 81037-81076, https://www.federalregister.gov/articles/2010/12/23/2010-31637/waste-confidence-decision-update.
23. U.S. Court of Appeals for the District of Columbia Circuit, "State of New York v. Nuclear Regulatory Commission and United States of America" (Washington, DC: June 8, 2012), http://www.cadc.uscourts.gov/internet/opinions.nsf/57ACA94A8FFAD8AF85257A1700502AA4/$file/11-1045-1377720.pdf.
24. U.S. Nuclear Regulatory Commission, "CLI-12-16, Memorandum and Order" (Washington, DC: August 7, 2012), http://www.nrc.gov/reading-rm/doc-collections/commission/orders/2012/2012-16cli.pdf.
25. U.S. Nuclear Regulatory Commission, "NRC Directs Staff to Conduct Two-Year Environmental Study and Revision to Waste Confidence Rule" (Washington, DC: September 6, 2012), http://www.nrc.gov/reading-rm/doc-collections/news/2012/12-098.pdf.
26. U.S. Nuclear Regulatory Commission, "Effect of timely renewal application" (Washington, DC: December 18, 2012), http://www.nrc.gov/reading-rm/doc-collections/cfr/part002/part002-0109.html.
27. U.S. Nuclear Regulatory Commission, "Domestic Licensing of Production and Utilization Facilities" (Washington, DC: December 18, 2012), http://www.nrc.gov/reading-rm/doc-collections/cfr/part050/.
28. Tennessee Valley Authority, "TVA's Bellefonte Resets Work Priorities" (Hollywood, AL: March 15, 2012), http://www.tva.gov/news/releases/janmar12/bln.htm.
29. U.S. Nuclear Regulatory Commission, "Licenses, Certifications, and Approvals for Domestic Nuclear Power Plants" (Washington, DC: December 18, 2012), http://www.nrc.gov/reading-rm/doc-collections/cfr/part052/.
30. U.S. Nuclear Regulatory Commission, "Deciphering the Waste Confidence Order" (Washington, DC: August 9, 2012), http://public-blog.nrc-gateway.gov/2012/08/09/deciphering-the-waste-confidence-order/.
31. Clean Air Act, 42 U.S.C. 7412 (2011), http://www.gpo.gov/fdsys/pkg/USCODE-2011-title42/pdf/USCODE-2011-title42-chap85-subchapI-partA.pdf.
32. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011) pp. 15,608-15,702, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4494.pdf.
33. U.S. Environmental Protection Agency, "Definitions," Code of Federal Regulations, 40 CFR §63.2 (July 1, 2012), http://www.gpo.gov/fdsys/pkg/CFR-2012-title40-vol10/pdf/CFR-2012-title40-vol10-part63-subpartA.pdf, p. 16.
34. U.S. Environmental Protection Agency, "Definitions," Code of Federal Regulations, 40 CFR §63.2 (July 1, 2012), http://www.gpo.gov/fdsys/pkg/CFR-2012-title40-vol10/pdf/CFR-2012-title40-vol10-part63-subpartA.pdf, pp. 13-14.
35. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters; Proposed Rule," Federal Register, Vol. 76, No. 247 (Washington, DC: December 23, 2011), p. 80,622, http://www.gpo.gov/fdsys/pkg/FR-2011-12-23/pdf/2011-31667.pdf.
36. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), p. 15,579, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4493.pdf.
37. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), p. 15,695, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4494.pdf.
38. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), pp. 15,689-15,691, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4494.pdf.
39. CU.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), p. 15,615, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4494.pdf.
40. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), p. 15,696, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4494.pdf.
41. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), p. 15,665, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4494.pdf.
42. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers; Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), p. 15,594, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4493.pdf.
43. U.S. Environmental Protection Agency, "National Emission Standards for Hazardous Air Pollutants for Area Sources: Industrial, Commercial, and Institutional Boilers, Final Rule," Federal Register, Vol. 76, No. 54 (Washington, DC: March 21, 2011), pp. 15,601-15,602, http://www.gpo.gov/fdsys/pkg/FR-2011-03-21/pdf/2011-4493.pdf.
44. The eligible technology, and even the definition of the technology or fuel category, will vary by state. For example, one state's definition of renewables may include hydroelectric power generation, while another's definition may not. Table 3 provides more detail on how the technology or fuel category is defined by each state.
45. More information about the Database of State Incentives for Renewables & Efficiency can be found at http://www.dsireusa.org/incentives.
46. Database of State Incentives for Renewables & Efficiency, http://www.dsireusa.org/rpsdata/index.cfm.
47. Pyrolysis is defined as the thermal decomposition of biomass at high temperatures (greater than 400 °F, or 200 °C) in the absence of air.
48. California Legislative Information, "Assembly Bill No. 32: California Global Warming Solutions Act of 2006" (Sacramento, CA: September 27, 2006), http://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=200520060AB32.
49. California Air Resources Board, "AB 32 Scoping Plan Functional Equivalent Document (FED)" (Sacramento, CA: May 16, 2012), http://www.arb.ca.gov/cc/scopingplan/fed.htm.
50. State of California, "Final Regulation Order, Subchapter 10 Climate Change, Article 5, Sections 95800 to 96023, Title 17, Article 5: California Cap on Greenhouse Gas Emissions and Market-Based Compliance Mechanisms" (Sacramento, CA: December 22, 2011), pp. 47-49, http://www.arb.ca.gov/regact/2010/capandtrade10/finalrevfro.pdf.
51. State of California, "Final Regulation Order, Subchapter 10 Climate Change, Article 5, Sections 95800 to 96023, Title 17, Article 5: California Cap on Greenhouse Gas Emissions and Market-Based Compliance Mechanisms" (Sacramento, CA: December 22, 2011), http://www.arb.ca.gov/regact/2010/capandtrade10/finalrevfro.pdf.
52. California Air Resources Board, "California Greenhouse Gas Emissions Inventory: 2000-2009" (Sacramento, CA: December 2011), p. 10, http://www.arb.ca.gov/cc/inventory/pubs/reports/ghg_inventory_00-09_report.pdf.
53. California Air Resources Board, "Updated Information Digest, Regulation to Implement the California Cap-and-Trade Program" (Sacramento, CA: December 14, 2011), p. 6, http://www.arb.ca.gov/regact/2010/capandtrade10/finuid.pdf.
54. For years 2021-2040 held constant in AEO2013 at 2020 levels.
55. California Air Resources Board, "Appendix J, Allowance Allocation" (Sacramento, CA: October 18, 2010), p. J-12, http://www.arb.ca.gov/regact/2010/capandtrade10/capv4appj.pdf.
56. California Air Resources Board, "California Air Resources Board Quarterly Auction 1" (Sacramento, CA: November 19, 2012), http://www.arb.ca.gov/cc/capandtrade/auction/november_2012/auction1_results_2012q4nov.pdf.
57. California Environmental Protection Agency, "Press Release: California Applauds Québec on Adoption of Amended Cap-and-Trade Program" (Sacramento, CA: December 13, 2012), http://www.calepa.ca.gov/PressRoom/Releases/2012/Quebec.pdf.
58. See Assembly Bill 32, Section 38562(B)(8), http://www.leginfo.ca.gov/pub/05-06/bill/asm/ab_0001-0050/ab_32_bill_20060927_chaptered.pdf. The evaluation of "leakage risk" and the amount allocated to prevent leakage will be revisited by CARB during each of the periodic reviews of the cap-and-trade program, which will occur at least once every three-year compliance cycle.
59. CA price that has been adjusted for allowance costs.
60. State of California, "Final Regulation Order, Subchapter 10 Climate Change, Article 5, Sections 95800 to 96023, Title 17, California Code of Regulations: California Cap on Greenhouse Gas Emissions and Market-Based Compliance Mechanisms" (Sacramento, CA: December 22, 2011), http://www.arb.ca.gov/regact/2010/capandtrade10/finalrevfro.pdf. Note: The final regulation states that reserves are held at 1 percent in compliance period 1, 4 percent in compliance period 2, and 7 percent in compliance period 3. For modeling purposes, post-2020 reserves are set to 0 percent.
61. State of California, "Final Regulation Order, Subchapter 10. Climate Change, Article 4. Regulations to Achieve Greenhouse Gas Reductions, Subarticle 7. Low Carbon Fuel Standard" (Sacramento, CA: January 13, 2010), http://www.arb.ca.gov/regact/2009/lcfs09/finalfro.pdf.
62. California Air Resources Board, "Third Notice of Public Availability of Modified Text and Availability of Additional Documents and Information" (Sacramento, CA: September 17, 2012), http://www.arb.ca.gov/regact/2011/lcfs2011/lcfs3rdnot.pdf.
63. State of California, "Low Carbon Fuel Standard (LCFS) Supplemental Regulatory Advisory 10-04B" (Sacramento, CA: January 1, 2012), http://www.arb.ca.gov/fuels/lcfs/123111lcfs-rep-adv.pdf.
64. California Air Resources Board, "LCFS Enforcement Injunction is Lifted, All Outstanding Reports Now Due April 30, 2012" (Sacramento, CA: April 24, 2012), http://www.arb.ca.gov/fuels/lcfs/LCFS_Stay_Granted.pdf.
Sections in this chapter :
- Greenhouse gas emissions and corporate average fuel economy standards for 2017 and later model year light-duty vehicles
- Recent rulings on the Cross-State Air Pollution Rule and the Clean Air Interstate Rule
- Nuclear waste disposal and the Waste Confidence Rule
- Maximum Achievable Control Technology for industrial boilers
- State renewable energy requirements and goals: Update through 2012
- California Assembly Bill 32: Emissions cap-and-trade as part of the Global Warming Solutions Act of 2006
- California low carbon fuel standard