ENERGY is a key ingredient in U.S. economic growth. Ensuring a reliable supply of electricity and other sources of energy is critical to the financial security of American businesses and households and to the national security of the country as a whole. While dynamic enough to respond to the climate conditions of the past, our energy system, as currently designed, is poorly prepared for future climatic changes. Rising temperatures, increased competition for water supply, and elevated storm-surge risk will affect the cost and reliability of the U.S. energy supply. Climate change will also shape the amount and type of energy consumed. In this chapter, we quantify the demand-side impacts of the projected changes in temperature described in chapter 4 and discuss the range of supply-side risks the U.S. energy sector faces as well.
BACKGROUND
Energy demand is highly climate-sensitive in some sectors, and temperature in particular is a significant determinant of both the quantity and type of energy consumed. Demand for heating and cooling, which accounts for roughly half of residential and commercial energy use, fluctuates hourly, daily, and seasonally in response to outdoor ambient temperatures. Warmer winter temperatures as a result of climate change will reduce heating demand, particularly in northern states, which is currently met largely through the combustion of natural gas and fuel oil in boilers, furnaces, and water heaters. At the same time, hotter summer temperatures will increase demand for residential and commercial air-conditioning run on electricity. Climate-driven changes in air-conditioning can have an outsized impact on the electric-power sector, forcing utilities to build additional capacity to meet even higher peak temperatures.
OUR APPROACH
To assess the effect of the projected temperature changes discussed in chapter 4 on U.S. energy consumption, we turned first to the econometric literature. Because there are strong cross-location patterns in energy demand, as well as strong trends over time (that may differ by location) and over seasons, we focused on studies that account for these patterns when measuring the effect of climate variables on energy demand. Two studies provide estimates that satisfy these criteria, although only one is nationally representative. Deschênes and Greenstone (2011) examine state-level annual electricity demand for the country from 1968 to 2002 using data from the U.S. Energy Information Administration (EIA), and Auffhammer and Aroonruengsawat (2011) study building-level electricity consumption for each billing cycle (roughly a month) for California households served by investor-owned utilities (Pacific Gas and Electric, San Diego Gas and Electric, and Southern California Edison). Both studies identify the incremental change in electricity consumed for each additional day at a specified temperature level. Deschênes and Greenstone provide national coverage, while Auffhammer and Aroonruengsawat provide greater temporal and spatial resolution across the full range of climate zones in California; thus, the studies may be complementary.
Both studies find that electricity consumption increases during both hot days that exceed roughly 65°F and cold days that fall below roughly 50°F (figure 10.1). Incremental increases in daily temperature cause electricity consumption to rise more rapidly than incremental decreases in temperature, although both changes have substantial impacts on overall demand. Auffhammer and Aroonruengsawat further examine how the shape of this dose-response function changes with the climate zone that each household inhabits, finding that in hotter locations that are more likely to have air-conditioning widely installed, electricity demand increases more rapidly with temperature. This suggests that as populations adapt to hotter climates, they install more air-conditioning infrastructure and use air-conditioning more heavily for hot days at a fixed temperature.
FIGURE 10.1. Temperature and Electricity Demand
Observed change in electricity demand (percent) vs. daily temperature (degrees Fahrenheit)
Widening the Lens
Unfortunately, the available econometric studies only capture part of the energy-demand story. While residential and commercial electricity demand rises alongside temperature, as households and businesses increase their use of air-conditioning, natural gas and oil demand in those two sectors falls. Many households and businesses use natural gas or oil-fired boilers and furnaces for heating, rather than electricity. The econometric studies mentioned earlier only cover changes in demand, not changes in price. To capture these fuel substitution and price effects, we use RHG-NEMS, a version of the EIA’s National Energy Modeling System (NEMS; more information on NEMS is available at www.eia.gov/oiaf/aeo/overview) maintained by the Rhodium Group.
NEMS is the model used by the EIA to produce its Annual Energy Outlook, the most widely used projection of future U.S. energy supply and demand. NEMS is the most detailed publicly available model of the U.S. energy system, as it includes every power plant, coal mine, and oil and gas field in the country. Individual consumer decisions regarding how much to heat or cool one’s home, which appliance to buy, and what car to drive are explicitly modeled, as are producer decisions regarding new electricity, oil, gas, and coal production. Temperature is an input into NEMS and affects heating and cooling demand in the residential and commercial sectors. The appliances and equipment used to meet this demand influences the quantity of electricity, natural gas, and oil supplied to household and business consumers.
We began by comparing the modeled impact of a given change in temperature on electricity demand in NEMS with the empirically derived dose-response function described earlier and found very similar results. We then modeled the impact of a range of regional temperature projections from chapter 4 to capture the change in total energy demand, energy prices, and delivered energy costs. NEMS only runs to 2040 but is still useful in modeling the impact of longer-term temperature changes relative to the energy system we have today. As we are measuring the impact of climate-driven changes in energy demand relative to a baseline, the baseline itself matters less. Modeling long-term temperature changes in NEMS provides a reasonable estimate of the relative change in demand, price, and costs given current economic and energy-system structures.
RESULTS
Energy Demand
Consistent with the econometric estimates, we find meaningful climate-driven increases in residential and commercial electricity demand. Under RCP 8.5, average nationwide electricity demand in the residential and commercial sectors likely increases by 0.7 to 2.2 percent by 2020–2039, 2.3 to 4.9 percent by 2040–2059, and 6.2 to 14 percent by 2080–2099 (figure 10.2). The largest increases occur in the Southwest, the Southeast, and southern Great Plains states (figure 10.3). Texas, Arizona, and Florida see late-century likely increases of 9.6 to 21 percent, 8.5 to 21 percent, and 9.6 to 22 percent, respectively. At the other end of the spectrum, most New England states and those in the Pacific Northwest see low single-digit likely increases, with declines possible in certain counties.
FIGURE 10.2. National Change in Electricity Demand
FIGURE 10.3. Local Changes in Electricity Demand
Median change in electricity demand from 2012 levels, RCP 8.5
In RCP 4.5, we find a likely increase in average electricity demand of 0.2 to 1.9 percent by 2020–2039, 1.2 to 4.1 percent by 2040–2059, and 1.7 to 6.6 percent by 2080–2099. In RCP 2.6, we find a likely increase of 0.8 to 2.1 percent by 2020–2039, 1.1 to 2.7 percent by 2040–2059, and 0.7 to 2.7 percent by 2080–2099.
Offsetting this increase in cooling-driven electricity demand, we find a significant decline in heating-driven natural gas and fuel oil demand in the residential and commercial sectors under RCP 8.5. This decline is concentrated in the Northeast, upper Midwest, northern Great Plains, and Northwest, areas with the greatest heating needs today. Total natural gas demand does not fall because demand from the power sector increases, but the net effect of changes in heating and cooling demand is a very modest change in energy consumption overall.
Energy Costs
While we find little climate-driven change in total energy demand, the switch from heating demand to cooling demand raises total energy costs. Climate-driven increases in cooling demand increase electricity consumption during the hottest times of the day and hottest periods of the year, when electricity demand is already at its peak. Higher peak demand requires the construction of additional power-generation capacity to ensure reliable electricity supply. Under RCP 8.5, we find a likely increase in installed power-generation capacity due to climate-driven changes in electricity demand of 8 to 95 gigawatts (GW) by 2020–2030, 73 to 212 GW by 2040–2059, and 223 to 532 GW by 2080–2099.
While most of this capacity would only operate part of the time (during peak demand periods), the capital costs as well as operating costs are passed on to electricity consumers. The resulting electricity price increases lead to a likely 0.1 to 2.9 percent increase in total annual residential and commercial energy costs on average by 2020–2039, 2.1 to 7.3 percent by 2040–2059, and 8 to 22 percent by 2080–2099 (figure 10.4). The greatest likely increases occur in the Southeast (12 to 28 percent), Great Plains (9 to 30 percent), and Southwest (11 to 25 percent) in 2080–2099. At the other end of the spectrum, the Northwest sees a likely change in energy expenditures of –4.5 to +3.7 percent late-century, while the Northeast sees a 4.1 to 13.6 percent likely increase. In RCP 4.5 and RCP 2.6, smaller increases in demand lead to less generation capacity construction and thus lower energy cost increases, though the RCP 4.5 and RCP 2.6 cost estimates do not include any increase in energy costs resulting from a change in U.S. energy supply necessary to reduce greenhouse-gas emissions consistent with either climate pathway. The cost estimates described above also exclude the supply-side climate impacts discussed later.
FIGURE 10.4. Change in Annual Residential and Commercial Energy Expenditures
OTHER EFFECTS
Climate change will impact energy supply as well as energy demand. The energy supply chain is long and complex. There are a number of points in that supply chain where climate-related disruptions could interrupt delivery of electricity and heating or transport fuels.
Climate change will also have negative impacts on some sources of energy supply. For example, rising average temperatures and more frequent temperature extremes will reduce the efficiency of thermoelectric generation and transmission, while reduced sea ice in the Arctic will enable greater offshore oil and gas exploration. We describe some of the most significant supply-side climate impacts in the subsections that follow.
Thermal Generation Efficiency
Coal, natural gas, oil, nuclear, and biomass power plants all produce electricity by boiling water and using steam to spin a turbine. This steam is then recycled by cooling it back into water. Higher ambient air temperatures as a result of climate change reduce the efficiency of this process. The magnitude of the impact depends on a number of plant- and site-specific factors. For most combined-cycle plants, every 1.8°F (1°C) increase in air temperature will likely reduce electricity output by 0.3 to 0.5 percent (Maulbetsch & Difilippo 2006). For combined-cycle plants with dry cooling, often more sensitive to warmer ambient temperatures, the reduction can be as large as 0.7 percent (Davcock, DesJardins, & Fennel 2004). For natural gas–fired combustion turbines, which are often used for peak demand times, each 1.8°F increase in temperature will likely result in an 0.6 to 0.7 percent decline in electricity output, and for nuclear power, output losses are estimated at approximately 0.5 percent (Linnerud, Mideksa, & Eskeland 2011). Combining these reductions with the projected increase in average summer temperatures under RCP 8.5 described in chapter 4 suggests thermal efficiency declines could reduce total electricity generation by 2 to 3 percent by midcentury and 4 to 5 percent by late century, depending on the energy technology mix.
Nearly all the electric-power plants in the United States use water for cooling, and the power sector accounts for nearly half of total U.S. water withdrawals (Energy Information Administration 2011). Ambient temperatures affect surface-water temperatures. Surface-water temperatures in many U.S. rivers have risen in recent years (Kaushal et al. 2010) and are projected to continue to warm due to climate change in the decades ahead (Cloern et al. 2011; Van Vliet et al. 2012; Georgakakos et al. 2014). Warmer water temperatures can degrade the efficiency of cooling processes and reduce electricity production as well (Van Vliet et al. 2012). In August 2012, record water temperatures in Long Island Sound shut down one reactor at Dominion Resources’ Millstone Nuclear Power Station in Connecticut because the temperature of the intake cooling water exceeded the technical specifications of the reactor. While no power outages were reported, the 2-week shutdown resulted in the loss of 255,000 megawatt-hours of power, worth several million dollars (U.S. Nuclear Regulatory Commission 2012).
The majority of U.S. thermal power plants currently use once-through cooling systems, which use water from a nearby lake, river, aquifer, or ocean to cool steam and then return it to the body of water from which it was withdrawn. Because of the elevated temperatures of discharged water, thermal discharge limits have been established to protect aquatic ecosystems. Increasing water temperatures put power plants at risk of exceeding these limits, with the potential for financial penalties or forced curtailments (Skaggs et al. 2012). Indeed, large coal and nuclear plants have, in several cases in recent history, been forced to restrict operations because of higher water temperatures (Averyt et al. 2011). A recent study projected a decrease in average summer capacity of thermoelectric plants with once-through cooling of 12 to 16 percent and of those with recirculation cooling systems of 4.4 to 5.9 percent by midcentury, depending on the emissions scenario (Van Vliet et al. 2012). The study also found that the probability of extreme (greater than 90 percent) reductions in power production will on average increase by a factor of 3.
Electricity Transmission
Approximately 7 percent of generated electricity is lost during transmission and distribution (known as “line losses”), with the greatest losses occurring on hot days (Energy Information Administration 2012a). Increased average temperatures, as well as more frequent temperature extremes, will likely exacerbate these transmission and distribution losses (U.S. Global Change Research Program 2009; Sathaye et al. 2012; Wilbanks et al. 2012b). Warmer temperatures are also linked to diminished substation efficiency and life span (Sathaye et al. 2012). Current line losses are valued at nearly $26 billion (Energy Information Administration 2012b), so even small increases in loss rates can have a significant impact on electricity producers and consumers. A recent study found that a 9°F increase in average summer temperatures in the Southwest (within our projected end-of-century range under RCP 8.5) would result in a 7 to 8 percent reduction in transmission carrying capacity (Sathaye et al. 2013). Extreme heat events could result in even higher losses. Depending on the duration and intensity of the event, extreme temperatures can lead to power outages, as happened in 2006 when power transformers failed in Missouri and New York during a heat wave, causing widespread electricity supply interruptions (U.S. Global Change Research Program 2009).
Arctic Oil and Gas Production
Climate change is already shaping the energy landscape in Arctic Alaska, which has warmed faster than any other region of the United States to date, with both positive and negative impacts for the U.S. energy supply. Alaska currently accounts for more than 10 percent of U.S. crude oil production and is home to a large share of the national oil and gas resource base (U.S. Energy Information Administration 2013). Warming temperatures have already resulted in permafrost thaw, which is beginning to threaten onshore infrastructure on which oil and gas exploration and production depends. Energy pipelines built on permafrost are at increasing risk of rupture and leakage, and warmer temperatures are already resulting in shorter winter road seasons. The number of days of allowable travel on Alaskan tundra have been cut in half over the past 30 years, limiting the time during which onshore oil and gas exploration and production equipment can be used (Alaska State Legislature 2008). In a changing and unstable Arctic, the cost of maintaining existing infrastructure will likely increase, as will design and construction costs for new onshore infrastructure. Climate change is opening up new sources of oil and gas development as well. Higher temperatures are reducing sea-ice cover, which is improving access to substantial offshore oil and natural gas deposits in the Beaufort and Chukchi seas.
Water Availability
Current U.S. energy production is extremely water-intensive, and climate change will impact U.S. water supply in myriad ways (see chapter 17). Increased evaporation rates or changes in snowpack may affect the volume and timing of water available for hydropower and power-plant cooling, and changing precipitation patterns can affect bioenergy production. In regions where water is already scarce, competition for water between energy production and other uses may also increase. Regions that depend on water-intensive power generation and fuel extraction will be particularly vulnerable to changes in water availability over time.
At 40 percent of total freshwater withdrawals, thermal power generation is the largest water consumer in the United States (Kenny et al. 2009). Seasonal and chronic water scarcity has resulted in electricity supply disruptions in the past, particularly during periods of low summer flow. For example, a drought in the southeastern United States in 2007 forced nuclear and coal-fired power plants within the Tennessee Valley Authority system to shut down some reactors and reduce production at others (National Energy Technology Laboratory 2010). Similar water-driven shutdowns occurred in 2006 along the Mississippi River at the Exelon Quad Cities Illinois plant and at some plants in Minnesota. A recent assessment found that nearly 60 percent of coal-fired power plants in the United States are located in areas subject to water stress from limited supply or competing demand from other sectors (National Energy Technology Laboratory 2010).
Although annual average precipitation will likely increase across the continental United States over the next century, changes in seasonality of precipitation, timing of spring thaw, and climate-driven changes to surface runoff may affect surface and groundwater supplies in some regions. Potential future water scarcity increases the risk of electricity supply disruptions in some regions. In particular, surface water and groundwater supplies in the Southwest, Southeast, and southern Rockies are expected to be affected by runoff reductions and declines in groundwater recharge, increasing the risk of water shortages (Georgakakos et al. 2014). According to the Electric Power Research Institute, approximately one quarter of electricity generation in the United States—250 GW—is located in counties projected to be at high or moderate water supply sustainability risk in 2030 (EPRI 2011). The study found that all generation types will be affected, with 29 GW of nuclear, 77 GW of coal, and 121 GW of natural-gas generation capacity in counties with “at risk” water supplies.
Hydroelectric generation accounts for 7 percent of the total U.S. electricity supply, roughly 20 percent of electricity generation in California and the Northeast and up to 70 percent of electricity generation in the Pacific Northwest (Energy Information Administration 2013; Georgakakos et al. 2014). Projected climatic changes, including more precipitation falling as rain and less as snow, reduced snowpack, and earlier peak runoff, may decrease annual water storage and runoff. The resulting reductions in stream flow will decrease available hydropower generation capacity. The degree of impact will vary widely by region, with the western United States expected to be at greatest risk.
Water also plays a vital role in oil and gas production. Large volumes of water are used throughout the production process, including enhanced oil recovery, hydraulic fracturing, well completion, and petroleum refining. As the share of U.S. oil and gas production coming from unconventional sources (including coal-bed methane, tight gas sands, and shale oil and gas) increases, access to water will similarly increase in importance in sustaining U.S. production growth (U.S. Department of Energy 2013a). In times of water stress, oil and gas operations must compete with other water users for access, limiting availability and driving up costs. During the severe drought of July 2012, oil and natural gas producers faced higher water costs or were denied access to water for 6 weeks or more in several states including Kansas, Texas, Pennsylvania, and North Dakota (Dittrick 2012; Ellis 2012; Hargreaves 2012).
Coastal Storms and Sea-Level Rise
The sea-level rise and coastal storm dynamics discussed in chapter 4 threaten important energy assets as well as commercial and residential property. Superstorm Sandy demonstrated the extent to which coastal storms can disrupt energy supply. Storm surge and high winds downed power lines, flooded substations and underground distribution systems, and damaged or shut down ports and several power plants in the Northeast (U.S. Department of Energy 2013b). More than 8 million customers in 21 states lost power, further threatening vulnerable populations reeling from the effects of the storm (U.S. Department of Energy 2012a). Sandy also forced the closure of oil refineries, oil and gas pipelines, and oil and gas shipping terminals, impeding fuel supply in the region.
More than half of total U.S. energy production and three quarters of electricity generation take place in coastal states (U.S. Energy Information Administration 2013). The concentration of critical facilities in vulnerable coastal areas creates systemic risk not only for the region but also for the nation as a whole. The Gulf Coast is a prime example. The region is responsible for half of U.S. crude oil and natural gas production and is home to nearly half of the country’s refining capacity, with nearly 4,000 active oil and gas platforms, more than 30 refineries, and 25,000 miles of pipeline (Entergy 2010; Wilbanks et al. 2012a). It is also home to the U.S. Strategic Petroleum Reserve (SPR), with approximately 700 million barrels of crude oil stored along the Gulf Coast for use in the event of an emergency (U.S. Department of Energy 2012b). With a substantial portion of U.S. energy facilities located in the Gulf, isolated extreme weather events in the region can disrupt natural gas, oil, and electricity markets throughout the United States (Wilbanks et al. 2012a).
Outside of the Gulf Coast, other regional energy hubs are also at risk. The National Oceanic and Atmospheric Administration warns that outside of greater New Orleans, Hampton Roads near Norfolk, Virginia, is at greatest risk from sea-level rise and increased storm surge. The area is home to important regional energy facilities, including the Lamberts Point Coal Terminal, the Yorktown Refinery, and the Dominion Yorktown power plant (Wilbanks et al. 2012a). On the other side of the country, many of California’s power plants are vulnerable to sea-level rise and the more extensive coastal storm flooding that results, especially in the low-lying San Francisco Bay area. An assessment performed for the California Energy Commission found that the combined threat of sea-level rise and the incidence of 100-year floods in California puts up to 25 thermoelectric power plants at risk of flooding by the end of the century, as well as scores of electricity substations and natural gas storage facilities (Sathaye et al. 2012).
Wildfires
Wildfires (see chapter 18) also pose a risk to the nation’s energy infrastructure. During summer 2011, severe drought and record wildfires in Arizona and New Mexico burned more than 1 million acres and threatened two high-voltage lines transmitting electricity from Arizona to approximately 400,000 customers in New Mexico and Texas. In 2007, the California Independent System Operator declared an emergency due to wildfire damage to more than two dozen transmission lines and 35 miles of wire, with nearly 80,000 customers in San Diego losing power, some for several weeks (SDG&E 2007; Vine 2008). More frequent and severe wildfires increase the risk of physical damage to electricity transmission infrastructure and could decrease available transmission capacity.
