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U.S. carbon dioxide (CO2) emissions from the transportation sector reached 1,893 million metric tons (MMmt) from October 2015 through September 2016, exceeding electric power sector CO2 emissions of 1,803 MMmt over the same time period. On a 12-month rolling total basis, electric power sector CO2 emissions are now regularly below transportation sector CO2 emissions for the first time since the late 1970s. CO2 emissions from electric power have been trending lower since 2007. Comparing emissions over a 12-month period reduces the effects of seasonal fluctuations. Both sectors tend to have higher consumption and emissions in the summer months when electricity demand and vehicle travel are relatively high. Emissions levels through September 2016 represent the latest available data in EIA’s Monthly Energy Review. The electric power sector makes up a larger share of total U.S. energy consumption than the transportation sector. However, CO2 emissions from the electric power sector are now lower than those from transportation because the carbon intensity of the power sector has fallen much faster than the carbon intensity of the transportation sector. Emissions from the electric power sector are primarily from coal-fired and natural gas-fired electric generators. On average, emissions associated with combusting coal are higher than those associated with combusting natural gas. The average rate of CO2 emitted from combusting coal ranges from 206 to 229 pounds per million British thermal units (lbs CO2/MMBtu), depending on the type of coal consumed. The combustion of natural gas emits on average 117 lbs CO2/MMBtu. Natural gas electric generators also tend to be more efficient than coal generators, because they require less fuel to generate electricity. In the 12 months from October 2015 through September 2016, coal and natural gas had nearly equal shares of electric power generation in the United States: 31% and 34%, respectively. However, their shares of electric power sector emissions were 61% and 31%, respectively, as coal is much more carbon-intensive. Overall electric power carbon intensity has also decreased as generation share of non-carbon-emitting fuels such as nuclear, hydropower, wind, and solar has grown. Emissions from the transportation sector are primarily from motor gasoline, distillate fuel oil, and jet fuel, which have carbon intensities lower than coal but higher than natural gas. For example, gasoline emits an average of 157 lbs of CO2/MMBtu. In the 12 months from October 2015 through September 2016, motor gasoline represented 60% of the total emissions from the transportation sector, while 23% was from distillate fuel oil and 12% was from jet fuel. Very little electricity is used in the transportation sector. Attributing transportation’s share of electric power sector emissions to the transportation sector would only add 4 MMmt CO2 to the transportation sector’s total of 1,893 from October 2015 through September 2016. Capital costs for large-scale battery storage systems installed across the United States differ depending on technical characteristics. Systems are generally designed to provide either greater power capacity (a battery’s maximum instantaneous power output) or greater energy capacity (the total amount of electricity that can be stored or discharged by a battery system). The cost of a battery system can be expressed in terms of power capacity costs (dollars spent per unit of maximum instantaneous power output as expressed in dollars per kilowatt) or energy capacity costs (dollars spent per unit of total energy stored as expressed in dollars per kilowatthour), depending on which attribute is prioritized. Power-oriented systems are shorter duration systems, meaning they are typically designed to generate large amounts of instantaneous power output but cannot sustain that output for very long. These systems have lower costs per kilowatt and higher costs per kilowatthour. For example, a $12 million battery system with a nameplate power capacity of 10 megawatts and nameplate energy capacity of 4 megawatthours would have relatively low power costs ($1,200 per kilowatt) and relatively high energy costs ($3,000 per kilowatthour). Power-oriented systems are designed to provide grid reliability services such as frequency regulation, which requires large shifts in the power capacity in quick, sub-hourly intervals. Power-oriented battery systems are more prevalent in the PJM Interconnection than other regions and actively participate in PJM’s ancillary services market. Energy-oriented systems are designed for use for longer durations, meaning they have more energy capacity relative to their power capacity. As a result, these systems have higher average costs per kilowatt and lower costs per kilowatthour. For example, an $8 million battery system with a nameplate power capacity of 4 megawatts and nameplate energy capacity of 10 megawatthours would have relatively high power costs ($2,000 per kilowatt) and relatively low energy costs ($800 per kilowatthour). Energy-oriented battery systems are used to provide services such as peak load shaving, which is the act of delivering power during periods of the highest electricity demand, typically over the course of one or more hours. Energy-oriented battery systems are relatively more popular in the California Independent System Operator (CAISO) area. The nameplate duration of the battery storage system is the ratio of nameplate energy capacity to nameplate power capacity. For example, a system with a 6-megawatt power capacity and a 24-megawatthour energy capacity has a nameplate duration of 4 hours. Short-duration batteries—which are power oriented—have durations of less than 30 minutes. Medium-duration battery storage systems have nameplate durations ranging between 30 minutes and 2 hours. Long-duration battery storage systems—which are energy oriented—have more than 2 hours of nameplate duration. EIA’s recently released U.S. Battery Storage Market Trends report explores trends in U.S. battery storage capacity additions and describes the current state of the market, including information on applications and cost, as well as market and policy drivers.

Canada is the largest energy trading partner of the United States, based on the combined value of energy exports and imports. Although the value of bilateral energy trade with Canada has varied over the past decade, driven primarily by changes in the prices of oil and natural gas, the overall structure of bilateral energy trade flows has changed relatively little, with the value of U.S. energy imports from Canada consistently exceeding the value of U.S. energy exports to Canada by a large margin. Increasing energy commodity prices in 2017 led to growth in the value of both exports to and imports from Canada. Based on the latest annual data from the U.S. Census Bureau, energy accounted for $18 billion, or about 6%, of the value of all U.S. exports to Canada. Energy accounted for $73 billion, or about 24%, of the value of all U.S. imports from Canada in 2017, up from 19% in 2016. Canada is the main source of U.S. energy imports and the second-largest destination for U.S. energy exports behind only Mexico. Crude oil accounts for most U.S. energy imports from Canada, averaging 3.4 million barrels per day (b/d) in 2017. Canada is the largest source of U.S. crude oil imports, providing 43% of total U.S. crude oil imports in 2017. The value of U.S. crude oil imports depends on both volume and price. In 2017, the value of U.S. imports of Canadian crude oil increased, reaching $50 billion, as a result of both an increase in oil prices and an increase in volume. Canadian crude oil imported by the United States is largely produced in Alberta and consists mainly of heavy grades shipped primarily to the Midwest and Gulf Coast regions. Until the removal of restrictions on exporting U.S. crude oil in December 2015, virtually all U.S. crude oil exports went to Canada. Since the United States began exporting more crude oil to other countries, Canada’s share of U.S. crude oil exports has fallen, although Canada still remains the largest destination for U.S. crude oil exports. In 2017, for the first time, the United States exported more crude oil, in total, to other countries (794,000 b/d) than it exported to Canada (324,000 b/d). U.S. crude oil exports to Canada are typically light sweet grades that are shipped to the eastern part of the country. Bilateral petroleum products trade with Canada is relatively balanced in both volumetric and value terms. In 2017, Canada was the destination for 516,000 b/d of petroleum products, or 10% of all petroleum products exported from the United States. These exports were valued at more than $9 billion in 2017. However, the mix of petroleum product flows between the United States and Canada varies by product and region. For example, the United States is a net importer of gasoline from Canada, with significant volumes flowing from refineries in Eastern Canada to serve markets in the Northeast United States. In contrast, very little of the petroleum products exported from the United States to Canada are finished transportation fuels. Pentanes plus, liquefied petroleum gases, and other oils constitute most U.S. product exports to Canada. Some of these products are used as a diluent to enable pipeline movement of heavy crude oils produced in Canada. Overall, U.S. petroleum product exports to Canada and other destinations have increased over the past decade. Bilateral natural gas trade between Canada and the United States is dominated by pipeline shipments. Natural gas imports from Canada increased to 8.1 billion cubic feet per day (Bcf/d) in 2017, accounting for 97% of all U.S. natural gas imports. Total natural gas imports from Canada were valued at $7.3 billion in 2017. Most of Canada’s natural gas exports to the United States originate in Western Canada and are shipped to U.S. markets in the West and Midwest. U.S. natural gas exports to Canada, which increased to 2.5 Bcf/d in 2017, mainly go from New York into the eastern provinces. Increases in pipeline capacity to carry natural gas out of the Marcellus and Utica shale formations increased flows of U.S. natural gas into Canada, reducing pipeline imports from Canada and increasing U.S. pipeline exports to Canada. Electricity accounts for a small but locally important share of bilateral trade. In 2017, the value of U.S. imports of electricity from Canada increased for the second straight year, reaching $2.3 billion. The United States imported 72 million megawatthours of electricity from Canada in 2017 and exported 9.9 million megawatthours, based on data from Canada’s National Energy Board.

Electrified vehicles (hybrid electric, plug-in hybrid electric, and battery electric) have been sold as high fuel economy alternatives to conventional gasoline vehicles for a number of years but collectively have been slow to gain market share in the United States. From 2012 through 2017, electrified vehicles consistently accounted for between 2.5% and 4.0% of total light-duty vehicle sales, even as the number of available models increased from 58 to 95. Hybrid electric vehicles accounted for the largest share of electrified vehicles, but their share of sales has fallen as plug-in hybrid electric (PHEVs) and battery electric vehicle (BEVs) shares have slightly increased. The BEV share of total light-duty vehicle sales has grown the most since 2012 but only accounted for 0.6% of 2017 sales. The PHEV share grew from 0.1% to 0.5% and non-plug-in hybrid electrics declined from 3.0% to 1.9% of total light-duty vehicle sales between 2012 and 2017, based on Wards Automotive sales data. Several factors may account for the limited growth in these vehicles. Gasoline prices have remained relatively low in recent years, and the fuel economy of conventional vehicles has increased—factors that diminished the potential fuel savings of switching to electrified vehicles. Initial purchase prices for many electrified vehicles remain relatively high, especially for several PHEV and BEV models, despite federal and state incentives. Also, in most locations, limited charging infrastructure for plug-in vehicles has hindered wider adoption. Data from the 2017 National Household Travel Survey conducted by the U.S. Department of Transportation offers insight into the use and ownership of electrified vehicles. Households that own BEVs and PHEVs tend to have more vehicles per household, owning 2.7 vehicles compared with the household average of 2.1 vehicles. BEVs and PHEVs also tend to be used about 12% less than other vehicles in terms of annual mileage per vehicle. About one-third of all households have annual incomes higher than $100,000. However, about two-thirds of households with BEVs or PHEVs have incomes higher than $100,000. Households with annual incomes lower than $25,000 account for about 16% of all households but about 3% of BEV- and PHEV-owning households. Crude oil accounts for most U.S. energy imports from Canada, averaging 3.4 million barrels per day (b/d) in 2017. Canada is the largest source of U.S. crude oil imports, providing 43% of total U.S. crude oil imports in 2017. The value of U.S. crude oil imports depends on both volume and price. In 2017, the value of U.S. imports of Canadian crude oil increased, reaching $50 billion, as a result of both an increase in oil prices and an increase in volume. Canadian crude oil imported by the United States is largely produced in Alberta and consists mainly of heavy grades shipped primarily to the Midwest and Gulf Coast regions. Until the removal of restrictions on exporting U.S. crude oil in December 2015, virtually all U.S. crude oil exports went to Canada. Since the United States began exporting more crude oil to other countries, Canada’s share of U.S. crude oil exports has fallen, although Canada still remains the largest destination for U.S. crude oil exports. In 2017, for the first time, the United States exported more crude oil, in total, to other countries (794,000 b/d) than it exported to Canada (324,000 b/d). U.S. crude oil exports to Canada are typically light sweet grades that are shipped to the eastern part of the country. Bilateral petroleum products trade with Canada is relatively balanced in both volumetric and value terms. In 2017, Canada was the destination for 516,000 b/d of petroleum products, or 10% of all petroleum products exported from the United States. These exports were valued at more than $9 billion in 2017. However, the mix of petroleum product flows between the United States and Canada varies by product and region. For example, the United States is a net importer of gasoline from Canada, with significant volumes flowing from refineries in Eastern Canada to serve markets in the Northeast United States. In contrast, very little of the petroleum products exported from the United States to Canada are finished transportation fuels. Pentanes plus, liquefied petroleum gases, and other oils constitute most U.S. product exports to Canada. Some of these products are used as a diluent to enable pipeline movement of heavy crude oils produced in Canada. Overall, U.S. petroleum product exports to Canada and other destinations have increased over the past decade. Bilateral natural gas trade between Canada and the United States is dominated by pipeline shipments. Natural gas imports from Canada increased to 8.1 billion cubic feet per day (Bcf/d) in 2017, accounting for 97% of all U.S. natural gas imports. Total natural gas imports from Canada were valued at $7.3 billion in 2017. Most of Canada’s natural gas exports to the United States originate in Western Canada and are shipped to U.S. markets in the West and Midwest. U.S. natural gas exports to Canada, which increased to 2.5 Bcf/d in 2017, mainly go from New York into the eastern provinces. Increases in pipeline capacity to carry natural gas out of the Marcellus and Utica shale formations increased flows of U.S. natural gas into Canada, reducing pipeline imports from Canada and increasing U.S. pipeline exports to Canada.

EIA’s Short-Term Energy Outlook forecasts the typical U.S. household will spend an average of $426 for electricity this summer (June–August), an increase of about 3% from the average summer expenditures in 2017. The expected increase in electricity bills is a result of forecast higher retail electricity prices and slightly higher projected electricity use to meet increased cooling demand. The amount of money that customers spend on their electric bills is based on the quantity of electricity they used during the period, measured in kilowatthours (kWh), and the price charged for that electricity (dollars per kWh). Fluctuations in electricity bills are usually the result of differences in outside temperatures, so electric bills are usually lowest during the milder spring and fall months. In most parts of the country, residential electricity usage peaks during the summer months of June, July, and August, when households are using air conditioning to cool their homes. Based on projections from the National Oceanic and Atmospheric Administration (NOAA), EIA expects cooling degree days—an indicator of cooling demand—during the months of June through August 2018 to total about 2% more than during the relatively mild summer of 2017. NOAA expects cooling degree days in summer 2018 to be about 1% fewer than the average of the previous 10 summers. The projected increase in summer temperatures compared with last year contributes to EIA’s forecast that the average U.S. residential electricity customer will use about 1% more electricity this summer. NOAA forecasts summer temperatures to be warmer throughout the eastern area of the country, while the western states are expected to experience milder summer weather than last year. Summer-over-summer changes in average household electricity usage range from 6% less electricity use in the Pacific states to 5% more electricity use in the New England states. EIA expects U.S. residential retail electricity prices to average 13.5 cents per kWh between June and August 2018, about 2% higher than last summer. Electricity prices are rising primarily in response to higher generation fuel costs, especially for natural gas. Retail electricity rates are also rising as utilities increase their investments in transmission infrastructure. Electricity prices are expected to be higher this summer in all regions of the country. EIA expects natural gas to be the primary fuel for summer electricity generation, providing 37% of total U.S. electricity generation compared with 35% during the summer of 2017. The share of forecasted generation fueled by coal averages 29%, down from 31% last summer. This change in the projected relative generation mix of coal and natural gas is primarily a result of recent natural gas capacity additions and coal plant retirements.

Relative profits for some natural gas- and coal-fired generators in several Midwestern and Mid-Atlantic states may have decreased since 2016 because of higher natural gas and coal prices and lower wholesale electricity prices. A common measure of profitability for power plants within a region is the difference between their input fuel costs, such as the cost of coal or natural gas, and their wholesale power price. For electric power generation fueled by natural gas, this difference is called the spark spread; for coal, the difference is called the dark spread. Spark spreads and dark spreads in the first part of 2017 were lower than the 2016 averages in the PJM Western hub, which covers electricity generation in parts of several Midwestern and Mid-Atlantic states. Changes in spark spreads and dark spreads for a given electricity power market indicate the general operational competitiveness of coal-fired or natural gas-fired electric generators in meeting the market’s electricity demand. These spreads are calculated by comparing the day-ahead, wholesale power market price with the delivered input price of the fuel, and are adjusted for the energy content of the fuel and the relative conversion efficiency of power plants. These values can then be compared with wholesale power prices, which, in this example, are the average day-ahead prices at the PJM Western hub. Delivered coal prices vary among coal supply regions based on the quality of coal, the transportation costs of shipping the coal, and other contract terms. Natural gas prices vary regionally and are calculated using spot market prices, which can be volatile on a day-to-day basis. Coal and natural gas have different energy contents, and the power plants using these fuels have different heat rates, or energy conversion efficiencies. For this reason, spark and dark spreads are location-specific and reflect the characteristics of the fuels and the technical specifications of power plants in a given market. For example, natural gas consumed in the electric power sector in the PJM region has an estimated heat content of 1,033 British thermal units (Btu) per cubic foot of natural gas. So far in 2017, the average price for natural gas in this area has averaged $2.54/million Btu, based on prices at the Texas Eastern Transmission Market Zone 3 (Tetco M3) trading hub, which generally reflects natural gas prices in Pennsylvania, New Jersey, and New York. Spot prices within PJM vary widely because of pipeline constraints transporting natural gas from production areas in the Appalachian region to different markets. Natural gas combined-cycle plants in the PJM region are generally expected to produce one kilowatthour of electricity for every 7,300 Btu of natural gas. In the PJM region, combined-cycle plants are more commonly operated in direct competition with coal-fired generators. At the national level, average heat rates for all natural gas-fired generators have decreased over time (i.e., become more efficient) as more efficient natural gas power plants such as combined-cycle units have been installed and as older and less efficient units have been retired or converted to more efficient units. Coal consumed in the PJM region has an estimated heat content of 22.5 million Btu/short ton, representing the consumption-weighted average heat content of various coal types. Coal prices in the region have averaged about $55/short ton so far this year. Adding in an assumed coal transportation cost of $17/short ton, the estimated delivered coal costs translate to about $3.20/million Btu, or about 34% higher than delivered natural gas costs. PJM-region coal plants are, on average, less efficient than natural gas combined-cycle units, requiring about 10,500 Btu of coal to produce one kilowatthour of electricity. Although PJM-region spark and dark spreads appear to indicate that natural gas-fired units have been more profitable than coal-fired units recently, many factors affect these calculations, including the selection of representative fuel prices, generator heat rates, fuel delivery costs, and time of year considered.