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Based on results from EIA's Annual Energy Outlook 2016 (AEO2016) Reference case and International Energy Outlook 2016, EIA projects that the North American share of energy generation from renewable and nuclear energy sources will grow from 38% in 2015 to 45% in 2025. This projection assumes the Clean Power Plan (CPP) is upheld and takes effect in the United States. A recent agreement among Canada, Mexico, and the United States established a goal of 50% of electricity generation from clean energy sources by 2025. The trilateral agreement goal includes nuclear, renewables, and energy efficiency as eligible sources of clean energy, but it does not specify a baseline for assessing energy efficiency, which has been improving over time. The EIA projections discussed here focus solely on electricity generation from nuclear and renewable sources as a share of total generation. Substantial increases in demand-side energy efficiency are included in EIA's projection for overall electricity demand, but explicit accounting of energy efficiency contributions are not projected. Moreover, these values reflect the Reference case projections; other assumptions for fuel prices, technology costs, and policies could affect the electricity generation mix. Electricity generation in the United States currently represents more than 80% of total generation in North America. EIA's AEO2016 Reference case assumes that implentation of the CPP will begin in 2022. The extension of certain tax credits, significant cost reductions, and recognition of future CPP requirements result in a large increase in renewable generation between 2015 and 2025. U.S. coal-fired generation is expected to decline by 13% between 2015 and 2025 in the AEO Reference case, while natural gas-fired generation increases by 4%. Canada's power generation was already met by 80% clean energy in 2015, mainly because of Canada's extensive hydroelectric capacity. Canada plans to further increase its hydroelectric capability by 2025, in addition to increasing wind and solar capacity by 2025. EIA's International Energy Outlook 2016 (IEO2016) projects reduced coal use in Canada between 2015 and 2025, consistent with Canadian government plans to gradually phase out the use of existing coal plants. However, the combined share of renewables and nuclear in Canada's total generation is expected to fall to 75% by 2025 because of increases in natural gas use and projected retirements of existing nuclear capacity. Overall, Canada's generation currently represents about 13% of the North American total generation. Mexico accounted for about 6% of total North American electricity generation in 2015. The country has announced national energy goals and is undergoing electricity market reform to help encourage the development of new, low-carbon capacity expansion. Mexico is projected to increase generation from hydroelectric, wind, and other renewables and to reduce generation from fossil fuels. By 2025, Mexico's combined nuclear and renewables share of total electricity generation is expected to be 29%.

U.S. coal production is projected to decline by about 26%, or 230 million tons, between 2015 and 2040 in EIA's Annual Energy Outlook 2016 (AEO2016) Reference case, which assumes the implementation of the Clean Power Plan (CPP). In a scenario that assumes the CPP is never implemented (No CPP case), U.S. coal production remains close to 2015 levels through 2040. Although production in each major U.S. coal supply region is expected to decline when the CPP is implemented, the magnitude of the effects differs because of differences in coal quality, pricing, and the markets served by each region. In 2015, the coal production shares of the West, Interior, and Appalachian regions were 55%, 19%, and 26%, respectively. In the scenario without the Clean Power Plan, these shares were expected to shift to 52%, 29%, and 20% by 2040, respectively, as coal production from the Interior region increases while coal production in the West and Appalachian regions decreases. In the Reference case, the decline in coal demand impedes growth for the Interior region and leads to even larger declines in the West and Appalachian regions. By 2040, market shares for the West, Interior, and Appalachian regions are 51%, 26%, 22%, respectively. West. Coal production in the West region falls by 155 million tons between 2015 and 2040 in the Reference case, compared to a reduction of 31 million tons in the No CPP case. Approximately two-thirds of Western coal production occurs in the Powder River Basin, where relatively low mining costs and low-sulfur coal have offset higher transportation costs and allowed western coal to remain economic in distant markets. However, the addition of sulfur control equipment at existing coal-fired power plants to accommodate the Mercury and Air Toxics Standards (MATS) early in the projection period makes higher sulfur coals more competitive at units that had previously used low-sulfur coal to comply with prior limitations on sulfur dioxide emissions. In the Reference case, competition from natural gas and renewables combined with coal-fired power plant retirements also lowers coal demand in the states that are currently large consumers of Western coal. Interior. Coal production in the Interior region increases by 86 million tons by 2040 in the No CPP case. In the Reference case, this increase is smaller, totaling 5 million tons by 2040. Over the projection period, coal producers in the region are projected to control costs using longwall mining, a technique that is well-suited for the region's coal reserves. Additionally, the installation of sulfur control equipment at existing coal-fired power plants will enable Interior coal to displace some use of lower-sulfur Western and Appalachian coals. Appalachian. Coal production in the Appalachian region, which has declined steeply over 2000-2015, is projected to see the smallest reduction in production attributable to the CPP. In the No CPP case, Appalachian coal declines 50 million tons by 2040. In the Reference case, Appalachian coal declines 79 million tons. Appalachian steam coal production is relatively expensive relative to other coals, and it is expected to experience decreasing labor productivity. This lower productivity further decreases its competitiveness with coal from other regions, as well as with other fuels used to generate electricity, such as natural gas. However, production of metallurgical coal, which is used in the steelmaking process, represented about 28% of the region's total coal production in 2014 and is not affected directly by the CPP. However, slower growth in international metallurgical coal demand and falling international steam coal trade also limit projected export growth for Appalachian coal.

Proposed fuel economy and greenhouse gas emissions standards would increase fuel economy and reduce diesel consumption in medium- and heavy-duty vehicles. Unlike light-duty vehicles, which have been subject to fuel economy standards since the 1970s, the first phase of medium- and heavy-duty vehicle standards was recently implemented, starting with model year 2014. The proposed Phase 2 standards—issued jointly by the U.S. Environmental Protection Agency and the National Highway Traffic Safety Administration—would take effect in model year 2021 for most medium- and heavy-duty vehicle classes and increase in stringency through model year 2027. These standards are projected to reduce diesel consumption by 0.5 million barrels of oil equivalent per day (boe/d) by 2040. As described in an Issues in Focus analysis as part of EIA's Annual Energy Outlook 2016 (AEO2016), the proposed Phase 2 standards address specific vehicle categories, including combination tractors, heavy-duty pickup trucks and vans, vocational vehicles, and, for the first time, trailers. Vehicles are divided into different classes based on their gross vehicle weight rating (GVWR). Light-duty cars and trucks (typical passenger vehicles) weighing 8,500 pounds or less make up classes 1 and 2a (Class 2 is divided into 2a and 2b), and are not regulated by the proposed Phase 2 standards. These light-duty vehicles make up most of the vehicles on the road and accounted for 59% of 2015 transportation energy consumption in the United States. The Phase 2 standards affect classes 2b through 8, covering the medium- and heavy-duty vehicles that accounted for about 20% of U.S. transportation energy consumption in 2015. Heavy-duty pickups and vans, such as 3/4- and 1-ton pickup trucks used on construction sites, include class 2b and 3 vehicles with a GVWR between 8,501 and 14,000 pounds. They would be required to meet an annual 2.5% per year reduction in allowable emissions from model years 2021 to 2027. Vocational vehicles include a wide range of truck styles, such as delivery, refuse, utility, dump, and cement trucks, as well as school buses, ambulances, and tow trucks. This category includes class 2b through 8 vehicles with a GVWR of 8,501 pounds and above. A 16% reduction in carbon dioxide (CO2) emissions for diesel-powered vehicles would be required, with lower reductions in emissions for gasoline-powered vehicles and exceptions for certain vehicle types. Combination tractors—semitrucks that typically pull trailers—are class 7 and 8 vehicles with a GVWR of 26,001 pounds and above. They would be required to reduce CO2 emissions by up to 24% compared to the model year 2017 baseline. Trailers were not regulated in Phase 1, but they would need to improve aerodynamics and rolling resistance with different stringency depending on the type. By 2040 the average fuel economy of new medium- and heavy-duty vehicles across all regulated classes would reach 10.6 miles per gallon gasoline equivalent, representing a 33% improvement compared to the Reference case. Because vehicles can last for decades, the turnover of the vehicle fleet is relatively slow, although newer vehicles are often driven more intensively than older ones. Consequently, the average fuel economy of the entire fleet increases more gradually. In the Reference case, total fleet medium- and heavy-duty vehicle fuel economy only increases slightly as vehicles manufactured under Phase 1 standards become fully adopted. Small changes in fuel economy measured in terms of miles per gallon (mpg) at the lower end of the range can have outsized effects. For instance, switching from an 8-mpg vehicle to a 10-mpg vehicle provides a fuel consumption savings of 0.025 gallons per mile of travel—the difference between 0.125 gallons used to travel a mile in the 8-mpg vehicle and 0.1 gallons used by the 10-mpg vehicle to travel the same distance. In contrast, starting with a 20-mpg vehicle, fuel economy must increase to 40 mpg to produce the same savings per mile—the difference between 0.05 gallons per mile used by the 20-mpg vehicle and 0.025 gallons per mile used by the 40-mpg vehicle. This illustrates how seemingly small changes in fuel economy for large trucks can save a significant amount of fuel. For medium- and heavy-duty vehicles, the amount of vehicle travel is not expected to change significantly compared with the Reference case, so changes in fuel economy tend to be directly reflected in fuel consumption. Unlike light-duty fuel economy standards, which mainly affect gasoline consumption, standards for medium- and heavy-duty vehicles will primarily affect diesel fuel consumption. As such, diesel consumption by medium- and heavy-duty vehicles in the Phase 2 Standards case is 18% lower (0.5 million boe/d) in 2040 compared to the Reference case. Gasoline and alternative fuel consumption is also reduced, but to a lesser extent, because fuels other than diesel account for only about 10% of consumption from medium- and heavy-duty vehicles.

The U.S. Environmental Protection Agency's (EPA) Clean Power Plan (CPP) regulates carbon dioxide (CO2) emissions at existing fossil-fueled electric power plants, but the ultimate energy-related emissions effect depends to an important extent on how the rule will be implemented by states. Because the CPP provides the flexibility to choose different compliance options for reducing CO2 emissions, EIA has produced an Issues in Focus analysis that considers several compliance paths. One of the most significant options is the compliance metric itself. States may choose between mass-based standards, which impose an absolute cap on the amount of CO2 allowances, or rate-based standards, which limit the amount of CO2 per unit of electricity generated. Each state's choice may have implications for other states, as the CPP provides the flexibility for states choosing the same compliance option to cooperate. For example, for two states complying with mass-based standards, a state with relatively low compliance costs could reduce CO2 emissions below its target level and sell the excess allowances to another state with comparatively high compliance costs. Instead of modeling each state individually, EIA's analysis considers 22 electricity market regions, which reflect electricity markets better than state borders. In terms of CPP compliance, the AEO2016 Reference case assumes that the CPP is implemented according to schedule and that states comply with a mass-based standard. The CPP Rate case assumes all regions choose rate-based standards instead of mass-based standards. The CPP Interregional Trading case uses mass-based standards as in the Reference case but allows allowance trading within the Eastern Interconnection and within the Western Interconnection, the two largest interconnections of the North American electric grid, covering essentially all of the United States except much of Texas. The CPP Allocation to Generators case assumes that the mass-based allowances are allocated to the generators that produce the power instead of to load-serving entities that sell the power to the end-use customers. The Reference case assumes that the allowances are allocated to the load-serving entities, and these revenues provide a rebate on consumers' bills. Allowances allocated to generators may result in the cost of the allowance flowing through to consumer prices. The CPP Extended case further reduces mass-based targets after 2030 instead of maintaining a constant level as specified in the CPP. In this case, power-sector CO2 emissions are required to be 45% below 2005 levels in 2040, compared to 35% in 2030. The No CPP case assumes the CPP, which is currently on hold pending judicial review, is permanently voided. In general, power-sector CO2 emissions are highest in the No CPP case and lowest in the CPP Extended case, at 19% and 45% below 2005 emissions levels in 2040, respectively. From an emissions savings perspective, all other scenarios are similar to the Reference case through 2030, where power-sector CO2 emissions are about 35% below 2005 levels. In the CPP rate case, CO2 emissions begin to rise after 2030 as both electricity generation and resulting emissions increase. In the CPP Interregional Trading case, CO2 emissions are slightly higher than in the Reference case as a few regions have more stringent existing programs resulting in excess CPP allowances that can be sold to other markets. Because the compliance paths have implications for compliance costs, the various CPP cases result in slightly different retail electricity prices. EIA projects higher retail electricity prices in the CPP cases primarily because of increases in fuel costs associated with shifting to natural gas-fired generation and capital costs associated with renewable capacity additions. Price effects are similar in the Reference and CPP rate cases where the average electricity price from 2022 through 2030 in both cases is 2% higher than in the No CPP case, and 3% higher on average from 2030 through 2040. In the CPP Extended case, further reductions in CO2 emissions after 2030 beyond the levels specified by the CPP require more renewable and natural gas-fired generation. The resulting electricity price in this case in 2040 is 3% higher than in the Reference case and 6% higher than in the No CPP case. In the CPP Allocation to Generators case, the allowances are distributed to generators instead of to load-serving entities and the cost of allowances is included in marginal production costs instead of rebated to consumers. As a result, the average electricity price from 2022 through 2040 in the CPP Allocation to Generators case is 1% higher than in the Reference case and 4% higher than in the No CPP case. The residential sector currently is the largest electricity-consuming sector, with 1.4 trillion kWh sold in 2015. Electricity sales in the residential sector are projected to grow by 0.3% per year in the Reference case from 2015 through 2040 as the number of households increases by 0.8% per year. Residential energy intensity is expected to decline, with the average purchased electricity per household falling 11.3% from 2015 to 2040. Federal efficiency standards for most major end uses, including lighting, space cooling and heating, and water heating, as well as state and local building energy codes, are the main reasons for the electricity intensity decline. Electricity sales to commercial consumers are projected to increase at an average annual rate of 0.8% from 2015 to 2040. Commercial sector electricity intensity (electricity sales per square foot of floorspace) is projected to decline 0.3% per year as total commercial sector floorspace increases 1.1% per year. Federal energy efficiency standards, as well as technological improvements in lighting, refrigeration, space heating, and space cooling, contribute to the decline in electricity intensity. Electricity sales to industrial consumers are projected to rise 1.1% per year on average, from 1.0 trillion kWh in 2015 to 1.2 trillion kWh in 2040. With the value of industrial shipments projected to grow 1.9% per year in the Reference case, industrial sector electricity intensity, or electricity sales per dollar of industrial shipments, declines at an average annual rate of 0.8% from 2015 to 2040. The decline in projected electricity intensity results from the adoption of more energy-efficient technologies and structural changes in the economy toward less electricity-intensive industries. A recent extension of federal tax credits for residential and commercial solar photovoltaic (PV) systems, combined with the expected continuation of declining PV prices, spurs increased adoption of residential and commercial PV in the AEO2016 Reference case projection. Total building PV capacity grows at 8.6% annually in the AEO2016 Reference case. Generation from residential PV systems reaches 90 billion kWh, and commercial system generation reaches 36 billion kWh by 2040. Residential and commercial electricity sales would be 5.0% and 1.7% higher, respectively, in 2040 without the electricity generated by rooftop PV systems.