Download Assessment of Climate Change Risks to Energy Reliability in the

 Assessment of Climate Change Risks to Energy Reliability in the WECC Region December 26, 2014 Prepared for Western Electricity Coordinating Council (WECC) 155 North 400 West Suite 200 Salt Lake City, UT 84103
Prepared by Molly Hellmuth, Peter Schultz, Judsen Bruzgul, Dana Spindler, and Heidi Pacini ICF International 1725 ‘Eye’ Street Suite 1000 Washington, DC AssessmentofClimateChangeRisksto
EnergyReliabilityintheWECCRegion
Executive Summary The purpose of this report is to inform Western Electricity Coordinating Council (WECC) Scenario Planning Steering Group (SPSG) participants of: 1) the types of climate change risks and impacts occurring at the nexus of energy‐water‐land that electric utilities need to be aware of and plan for; and 2) the types of risk management options that can be used to mitigate or reduce the identified risks and impacts. Given the dependence of energy systems on land and water supplies, and their sensitivity to a changing climate, climate impacts on energy reliability should be considered within an integrated energy‐water‐land context in order to better understand the full range of direct and indirect impacts. Throughout the report, the implication of the interdependency of energy systems, water systems, and land resources―and the compounding effect of climate change impacts across these sectors on energy reliability―has been highlighted. These compounding impacts are further exacerbated given the context of increasing population, and increasing energy and water demands across the entire WECC region. A range of direct and indirect risks to reliability of the energy system (demand, generation, and transmission and distribution) are identified for low and high emissions scenarios for four different climate drivers (temperature, water availability, extremes, and sea level rise/storm surge), in four WECC sub‐regions (Pacific Northwest, Southwest, Rocky Mountain, and Coastal). At the sub‐regional scale, the:  Pacific Northwest spans the northwest corner of Idaho, the non‐coastal portions of Washington and Oregon, and the northern reaches of California. Over 60% of the energy production in Oregon and Washington comes from hydroelectric generation, which is highly sensitive to shifts in peak flow from summer to early spring that effectively reduce water availability for generation during peak summer demand months.  Southwest covers Arizona, New Mexico, Nevada, and south and central California. About 64% of the energy produced comes from coal and natural gas (thermoelectric) generation. Heat waves, drought, and reduced water availability are projected to increase competition for water resources, limit the freshwater available for energy generation, increase energy demand, and decrease the efficiency of energy generation and cooling processes.  Rocky Mountain sub‐region covers Montana, Utah, Idaho, Colorado, and Wyoming. The vast majority (71.2%) of the energy produced in the Rocky Mountain region comes from coal‐fired thermoelectric plants. Extreme events, such as heat waves, droughts, and 2 wildfires are likely to increase, directly damaging energy infrastructure, and disrupting services, and reducing transmission line efficiencies.  Coastal sub‐region includes the areas west of the coastal ranges in California, Oregon, and Washington. More than 35 million people live in the major metropolitan areas along the West Coast, comprising more than 50% of the population in the entire WECC region. The densely populated areas of Los Angeles, San Francisco, San Diego, Seattle, and Portland place heavy demands on energy infrastructure in coastal communities. Energy reliability in the coastal regions will be uniquely impacted by sea level rise, storm surge, and other coastal storm effects. Based on the sub‐regional impacts, four key “nexus risks” were identified that define particularly critical challenges facing energy utilities in the WECC region. These “nexus risks” represent plausible compounding impacts on energy reliability that include direct and indirect impacts associated with the energy‐water‐land nexus. For each of these “nexus risks,” a series of management measures are identified that can be taken into consideration when addressing risks across the entire energy system―to specific elements within the energy system, or to areas within the traditional realms of land and water management. Nexus Risk #1: Long‐term increased temperature and decreased water availability will drive simultaneous increases in energy and water demands, while reducing efficiency and capacity in the energy system. Potential management measures include:  Promoting flexibility and adaptability: For example, diversity in energy supply can allow flexibility in light of reductions in water availability.  Securing adequate water supply: For example, in some areas, new water transfers, water supply contracts (e.g., from a farmer to a water utility), and groundwater usage, may help to ensure adequate water supply for generation and cooling, where feasible. Nexus Risk #2: Increasing intensity and frequency of heatwaves and drought, and shifts in timing, quality, and quantity of water supply, will reduce the ability to respond during peak periods of energy demand. Potential management measures include:  Adopting new technologies to enhance operational management and increase peak generation: For example, evaluation of operational changes (e.g., reservoir rule curve changes) given climate change may help to optimize energy generation from hydropower facilities given other constraints. Nexus Risk #3: Climate‐related extremes will increase direct electricity service interruptions. Potential management measures include:  Improving land use planning and management. For example, improvements in upstream land use management, including afforestation to reduce floods, erosion, silting and mudslides, can provide useful protection to existing infrastructure such as turbines. 3 
Updating hazard and emergency risk management plans to include climate change. For example, existing hazard plans may be updated to consider the occurrence of more frequent and intense droughts and floods.  Incorporating climate change projections into engineering design and planning: For example, robust design specifications that incorporate climate change could enable structures to better withstand more extreme conditions. Nexus #4: Increases in climate‐related extremes increase the risk of costly cascading electricity failures. Potential management measures include:  Increasing system flexibility and robustness: For example, increasing the number of transmission lines to increase power flow capacity and provide greater control over energy flows can increase system flexibility. Crosscutting management measures were also identified that apply to all of the identified “nexus risks.” The crosscutting measures are primarily “low‐regrets” investments that can improve system understanding, and encourage demand‐side efficiencies. These measures would effectively address inefficiencies across the energy‐water‐land nexus. Potential management measures include:  Increasing knowledge through monitoring and measurement: For example, investments in weather and hydrologic monitoring can provide critical information for adaptive management.  Raising the priority of energy demand management: For example, utilities, policy makers, and regulatory agencies can incentivize consumers to reduce energy demand by either increasing efficiency or reducing consumption.  Investing in water efficient systems: For example, investments and shifts toward less water‐intensive generation methods such as dry/hybrid cooling systems for thermoelectric power plants may prove to be more effective and sustainable.  Promoting active partnerships between energy and water utilities and managers: For example, promoting mechanisms to bring energy and water managers together to discuss the implications of climate change, and proactively work toward solutions may result in efficiencies across the sectors.  Exploring energy market mechanisms: For example, power exchange agreements can be set up to exchange power between utilities; they work best when different utilities have different load profiles and there is sufficient transmission capacity.  Employing energy‐smart engineering: For example, smart infrastructure investments can improve operational performance, and as a result, increase reliability in the face of potential climate change impacts. Policy and planning can be informed by a robust decision‐making approach to identify and test potential robust strategies, characterize the vulnerabilities of such strategies, and evaluate the tradeoffs among them. Proactive planning for climate change impacts can help utilities within 4 the WECC sub‐regions avoid costly reactionary measures and short‐term fixes to deal with disruptions or decreases in reliability. In cases where uncertainty is high and large capital investments are hard to justify, a practical approach may be to invest in low‐risk management strategies that deliver benefits regardless of the nature and extent of changes in climate. In other cases, large capital investments may be justified. Many of the presented management measures are “low‐regrets” actions that provide short‐term benefits because they address both current vulnerabilities and future risks. The measures described above provide general information regarding possible management measures to address reliability concerns given different climate impacts. However, detailed local assessments are necessary to provide greater understanding of climate vulnerabilities and to identify feasible management measures given the specific context and vulnerabilities. It should be considered that every management measure involves tradeoffs, which can increase or decrease stress on energy systems and water and land resources, respectively. Better understanding of these relationships can inform investment decisions that will likely require concerted and improved management of water and land resources, to enable more reliable energy systems. 5 1. Introduction The purpose of this report is to inform Western Electricity Coordinating Council (WECC) Scenario Planning Steering Group (SPSG) participants of: 1) the types of climate change risks and impacts occurring at the nexus of energy‐water‐land that electric utilities need to be aware of and plan for; and 2) the types of risk management options that can be used to mitigate or reduce the identified risks and impacts. The WECC region is diverse in terms of its energy supply system, geography, land use, economy, and climate. The WECC region currently produces electricity to serve approximately 70 million people, and the population is expected to increase by 30% (to 90 million people) by 2030. The population increase alone is likely to increase demand for electricity and water in the region―both through residential consumption and commercial activities. In the WECC sub‐regions, electricity is generated from a variety of sources including fossil‐
fueled natural gas and coal, nuclear, hydro, and other renewables (including geothermal, wind, solar, and biomass). The energy generation profile varies across the WECC region. The Southwest sub‐region (California, Nevada, New Mexico, and Arizona) is primarily powered by natural gas (43.8%), the Rocky Mountain sub‐region (Colorado, Utah, Wyoming, Montana, and Idaho) is primarily powered by coal (71.2%), and the Pacific Northwest sub‐region (Washington and Oregon) is primarily hydropower (62.4%)1. Across the WECC region approximately 7% of the electricity is produced by other renewables.2 See Figure 1 for the breakdown of energy production by sources for the Southwest, Rocky Mountain, and Pacific Northwest sub‐regions, respectively.3 1
EPA eGrid database, 2014. EPA eGrid database, 2014. 3
The energy production data is based on state statistics. Since the Coastal Region in this report is comprised of parts of California, Oregon, and Washington, statistics for this region are not available. 2
6 Figure 1: Energy production by source for the Northwest, Southwest, and Rocky Mountain sub‐regions and the total percentages for the entire WECC region (EPA eGrid database, 2014). The energy system in the WECC region has been robust in its ability to provide a reliable supply of energy, with only occasional interruptions as a result of extreme weather, and reductions in energy production as a result of water shortages. However, projected impacts of climate change are expected to increase the challenge of maintaining a reliable energy supply given increasing energy demands, competition for water supply, and shifts in the intensity and frequency of extreme events. Given the dependence of energy systems on land and water supplies, and their sensitivity to a changing climate, climate impacts on energy reliability should be considered within an integrated energy‐water‐land context in order to better understand the full range of management measures, trade‐offs, and constraints (see Figure 2). Better understanding of these relationships, while complex, represents a unique opportunity for WECC to make a contribution to the knowledge base of its members and stakeholders, as well as help them make better informed investment decisions that will likely require, in part, concerted and improved management of water and land resources to make energy systems more reliable in the future. There are opportunities to make investments now to manage climate risks that can provide immediate benefits or that are cost effective over the lifetime of the investment. 7 Uncertainty Considerations for the Energy Sector The non‐stationary nature of climate and other systems requires different techniques for assessing and managing risks. In general:  Engineering standards don’t reflect the fact that climate is changing; in other words, they don’t reflect the full uncertainty surrounding future climate.  Projected temperature change is more certain than hydrologic change; while changes at larger geographic scales are more certain than at smaller scales.  The resolution of projected climate information sometimes belies the deep uncertainty underlying it (i.e., the sign of precipitation change is not known with certainty for much of the United States, even if we were able to perfectly predict future greenhouse gas levels). There is significant additional uncertainty in:  Translating climate drivers into impacts on electricity system assets  Accounting for interacting effects of electricity system impacts  Accounting for indirect effects via changes in hydrology and land cover (i.e., the energy‐
water‐land‐climate nexus) Finally, the scientific community generally does not assign probabilities to emission scenarios. However, it is, in some cases, possible to assign probabilities to impacts, given a particular climate change. Nonetheless, it is possible to make improved decisions in the face of this uncertainty. Keys include:  Characterizing the uncertainties as fully as possible  Adopting a Robust Decision‐Making approach (see Section 4.6)  Identifying and applying metrics and indicators over time, to indicate which path one is on This report is organized into three main sections. The first section provides a regional overview of the WECC region’s changing demographics, energy, water, land, and climate drivers as well as general implications of these changes for energy reliability. The next section includes profiles of each WECC sub‐region’s unique geography, current and projected changes in climate drivers, the energy mix, demographic changes and demand, and interactions with water and land use. The final section provides information on the types of policy, planning, and engineering measures that can be taken to manage key climate risks to the energy supply system, considering the interconnections with water and land. 2. Overview of Climate Change Risks to Reliability in the WECC Region Energy reliability is the assurance that customer demand will be met in real time―requiring that supply and demand must be constantly and precisely balanced. Maintaining reliability depends on the operation of the entire energy system including the generation, transmission, and distribution systems. Demand growth, coupled with a shrinking generation reserve margin, 8 is at the heart of reliability concerns.4 Climate change poses direct risks to reliability (e.g., damage to energy infrastructure as a result of increased frequency and intensity of flooding or heat waves); but also, climate change impacts on interdependent energy, water, and land systems can result in compounded energy system reliability risks. The following sub‐sections present an overview of climate drivers and their impacts on the reliability of the energy system, including on the demand, generation, and transmission and distribution of electricity, taking into consideration potential compounding impacts as a result of energy‐water‐land interdependencies. Since climate varies across the WECC region, more detailed information on climate projections is provided in the sub‐regional sections. Four types of climate drivers are considered: temperature, water availability, extremes (flood, drought, heat waves, fire, and landslides), and sea level rise/storm surge.5 2.1. Temperature Temperature increases pose a variety of direct and indirect risks to the energy system, including through:  Increased energy demand  Reduced efficiency of thermoelectric power generation  Increased water demands for biofuel production  Reduced transmission efficiency and available transmission capacity Average annual temperature in the United States has increased over the past century,6 the number of record highs has increased, the number of record lows has decreased,7 and the frost‐
free season in the western United States has increased.8 Warming is projected to increase during all seasons, particularly during winter months in northern latitudes.9 At the energy‐water‐land nexus, temperature increases as a result of climate change could challenge electricity reliability by increasing the water demands of competing water users (i.e., domestic, agricultural water users), an issue in water constrained environments such as the Southwest. This effect is due, in significant part, to the increase in evaporation and transpiration that accompanies warming. The indirect impacts of increasing temperatures on land and water resources, when taken in combination with the direct impacts, can affect energy reliability, including increasing competing water demands (i.e., domestic, agricultural) in water‐
constrained areas. 4
Osborn and Kawann, 2001. Other climate drivers that impact on energy reliability, such as changes in wind and solar radiation, are not included. 6
Melillo et al., 2014 7
Romero‐Lankao et al., 2014. 8
Melillo et al., 2014 9
Romero‐Lankao et al., 2014. 5
9 The net demand for electricity is also projected to increase due to increased energy demand for cooling buildings as a result of temperature increases.10 A recent study11 found that if average annual temperatures were to rise by 4.5°F and 9°F, energy expenditures would increase by 10% to 22% by century’s end, respectively. Hotter and longer summers will increase the amount of electricity necessary to run air conditioning, especially in the Southwest; while warmer winters will decrease the amount of natural gas required to heat buildings, especially in the Northwest. Even where decreased demand from reduced heating surpasses increased demand from increased cooling, primary energy demand could still increase because electricity generation, transmission, and distribution are subject to significant energy losses under higher temperatures.12 There are three reasons why air temperature influences capacity and efficiency of a natural gas turbine: 1. Hot air is less dense, so the air mass in the turbine at higher temperatures is lower for a given volume intake. 2. Ambient temperature influences air’s specific volume, which influences the compression work and the power consumed by the compressor. 3. Pressure ratio within the turbine is reduced at higher temperatures, consequently reducing mass flow. Increased ambient temperatures reduce the capacity and efficiency of multiple components of thermoelectric generation because of differences in air density, specific volume and pressure (see box, above). For a 1.8°F increase in air temperatures, the output of natural gas‐fired combustion turbines is estimated to decrease by approximately 0.6% to 0.7%; combined cycles power plant output is projected to decrease by 0.3% to 0.5%; nuclear power plant output losses are projected to be approximately 0.5%; and dry cooling systems are projected to suffer 0.7% output losses.13 In addition, higher water temperatures can impact the efficiency of energy production.14 In some cases, high intake water temperatures may result in the shutdown of a facility, as happened at the Millstone Nuclear Power Station in Connecticut during the summer of 2012.15 Finally, about 90% of expected growth in per‐capita peak demand will come from temperature‐induced cooling demand, and 10% from temperature‐induced generation loss.16,17 10
Jaglom et al., 2014. Mansur et al., 2008. 12
DOE, 2013a. 13
DOE, 2013a. 14
Melillo et al., 2014. 15
Wagman, 2013. 16
Does not account for transmission losses. 17
Jaglom et al., 2014. 11
10 Additionally, increases in water temperatures may reduce the efficiency of thermal power plant cooling technologies, potentially leading to warmer water discharge from some power plants, which in turn can affect aquatic life. Warmer temperatures and shifts in the growing season may impact the ability to produce biofuels in the Great Plains, Coastal Region, and the Southwest.18 Although warmer temperatures may increase the number of frost‐free days by as much as two months by the end of the century,19 the warmer temperatures will simultaneously increase the need for irrigation of some biofeedstocks.20 Temperature poses risks to the reliability of transmission and distribution, including reducing transmission capacity, reduced transformer and substation capacity, increased line sag, and decreased labor production. Specific risks are outlined in Table 1. Table 1. Specific Risks to the Reliability of Transmission and Distribution given Increased Temperature Reduce transmission capacity  9oF warming decreases transmission line capacity 7–8%  Exacerbated by high night time temperatures (and low wind)  See, e.g., IEEE 738‐2006 Standard For Calculating the Current Temperature of Bare Overhead Conductors Diminish transformer and substation capacity  Decreased transformer capacity of approximately 0.7% for each 1°C of higher ambient temperature  E.g., 2–4% diminishment by end‐of‐century in CA under high emissions scenario  Small increase in line length can have dramatic effect on sag  Outage potential from line contact  Average system losses increase about 1.5% per 1% increase in load Increase line sag Increase T&D losses due to demand increases Impair transformer performance  E.g., substations in CA could lose 0.7–0.8% of capacity in the 2005–
(above 30°C) 2034 period Jeopardize infrastructure operation and maintenance  High‐heat procedures restrict labor if the temperature exceeds a certain threshold (e.g., 95°F) 2.2. Water Availability Changes in water availability can directly affect energy systems through:21 •
Reduced oil and gas production that requires large amounts of water 18
Melillo et al., 2014. 19 Melillo et al., 2014. 20
21
DOE, 2014. DOE, 2013a. 11 •
•
Impeded barge transport due to low or high river flows of crude oil, petroleum products, and coal, resulting in delivery delays and increased costs Decreased bioenergy production in some regions due to limited irrigation water At the nexus of energy‐water‐land, shifts in timing of peak stream flows from summer to spring can result in lower water storage supply in the summer for hydropower production, when both energy and domestic water demand are at their peaks. Higher temperatures, less snowpack, and decreasing water availability have reduced the Colorado River’s flow and left Lake Mead more than 100 feet below full storage capacity (see box on page 22, below). In 2010, water levels in Lake Mead were so low that Hoover Dam’s generating capacity was reduced by 23%, and dam operators were concerned that energy markets in the Southwest could be destabilized if the trends continued.22 Future energy technology choices can significantly affect water and land use, in water constrained regions such as the Southwest, ultimately influencing the buffer against further water stress afforded the region through its generous storage capacity in reservoirs.23 Each type of electricity generation has a unique process that relies on varying amounts of water and is sensitive to specific climate drivers. For example, water withdrawal (the amount of water diverted from a source) and consumption (the amount of water used up in the generation process, not returned to the source) varies by thermoelectric generation and cooling technology. Once‐through systems withdraw a much greater amount of water per megawatt‐
hour (MWh) of energy produced. Wet‐recirculating or closed‐loop systems have much lower water withdrawals than once‐through systems, but tend to have appreciably higher water consumption. In the western United States, wet‐recirculating systems are predominant. Dry‐
cooling systems use air instead of water to cool the steam exiting a turbine. Dry‐cooled systems use little to no water, and can decrease total power plant water consumption by more than 90%, but are less efficient. Therefore, the aforementioned changes in water availability will have highly varied impacts on generation, depending on the technologies that are deployed in a particular location. In general there have been slight increases in precipitation in the northwest and California, while average annual precipitation has mostly decreased across the rest of the WECC region. Runoff and streamflow at regional scales declined during the last half‐century in the Northwest, with no clear trends in other parts of the western United States, although a declining trend is emerging in annual runoff in the Colorado River Basin. Water availability is also affected by seasonal precipitation, snowpack, timing of peak flows, and glacial melt. Many snow‐dominated rivers have demonstrated evidence of earlier occurrence of peak flow as a result of warmer temperatures and shifts from snow to rain. Total seasonal snowfall generally decreased in 22
23
DOE, 2013a. Yates and Averyt, 2013. 12 southern and western portions of the United States.24 Spring snowpack has also shown decreasing trends from 1960 to 2002, with the significant exception of the central and southern Sierra Nevada. Additionally, decreasing mass and length of glaciers in North America have been recorded and can impact the availability of water.25 Average annual precipitation is projected to increase across the northern United States, and decrease in the southern United States, especially the Southwest. Basins in the southwestern United States and southern Rockies are projected to experience gradual runoff declines during this century. Basins in the Northwest to north‐central United States are projected to experience little change through the middle of this century, and increases by late this century. Figure 3 shows the regionally varied nature of projected changes in runoff by 2025–2039.26 The impacts of climate change on water supplies in the west are acutely felt by hydropower systems. Increased evaporation from higher temperatures combined with reduced river inflows could reduce reservoir levels and hydropower generation. The changes in hydropower production resulting from the projected changes in hydrology are estimated in Figure 4, indicating a slight net decrease in the Bonneville and Southwestern Power Authority regions and a slight net increase in the Western Power Authority region.27 24
Melillo et al., 2014. Romero‐Lankao et al., 2014. 26
DOE, 2013b. 27
DOE, 2013b. 25
13 Figure 3. Change in runoff for 2025–2039 relative to 1960–1999 (DOE, 2013b). The change shown is the median of a series of simulations that were driven by an ensemble of simulations from the Community Climate System Model version 3 using a medium‐high greenhouse gas emissions scenario (SRES A2). The climate model results were downscaled using the Regional Climate Model version 3 and input to the Variable Infiltration Capacity model. Figure 4: Historical and projected change in annual hydropower generation in three different power administrations using the runoff simulation approach shown in Figure 3 (DOE, 2013b). 14 2.3. Extreme Events Extreme events, including extreme precipitation, flooding, drought, wildfires, landslides, and extreme heat or heatwaves, all can impact energy reliability (see Figure 5). The interconnection between energy, water, and land can exacerbate the impact of these climate‐related extreme events. Key risks include:  Extreme heat or heatwaves can cause direct impacts to energy system infrastructure; elevated water temperatures due to extreme heat can significantly impact thermoelectric generation.  Drought can cause increases in demand for energy to pump water for agriculture while also decreasing water available for cooling at thermoelectric generation facilities and hydropower generation.  Wildfires, which are influenced by land cover, drought, and temperature, can have direct impacts on energy system infrastructure, especially fuel transport and electricity transmission lines that transverse large land areas.  Extreme precipitation and flooding can cause direct impacts to the energy system; changes in land cover can influence flooding severity and landslides, which can impact the energy system. Figure 5. Weather‐related grid disruptions, 2000–2012 (DOE, 2013a).
15 Heat waves have become more frequent and intense in the western United States and they are projected to become more intense in the future.28 Acute events, such as a day with extreme heat will have significant and short‐term impacts on the grid. Heat waves can stress distribution systems and cause more frequent brownouts and blackouts.29 Similar to temperature effects described above, heat waves can result in line sag in overhead power lines due to thermal expansion, causing power disruption and increasing fire risks. Such disruptions can cause temporary outages or increase the need for maintenance and repair of infrastructure. Drought intensity and frequency have been increasing over much of the western United States, especially during the last four decades.30 Much of the western and southwestern United States is projected to experience statistically significant increases in the annual maximum number of consecutive dry days: on average up to 10 days above present day values for parts of the contiguous United States by the end of this century under high emissions scenarios.31 During periods of limited precipitation, there can be an increased demand for both energy and water to meet increased agriculture (e.g., irrigation pumping) and municipal water demands (e.g., to pump and treat water), thus placing additional demand on the electrical system. Increased frequency and intensity of drought will also limit the freshwater available for the energy system, such as decreases in water for natural gas production with hydraulic fracturing, decreases in water for cooling at thermoelectric generation locations, and decreases in reservoir storage for hydroelectric generation. Where generation is dependent on biofuels, extreme heat could damage biofeedstock crops and warmer temperatures or drought can make forest stands more vulnerable to pest infestations, reducing bioenergy production and increasing fire risk.32 Seasonal and multi‐year droughts affect wildfire severity. The number of wildfires has increased in the Southwest and are projected to continue to increase in the area burned, both in the Southwest and in Colorado. Climate projections indicate that wildfires across the Southwest and Rocky Mountain sub‐regions could increase significantly by the middle to end of the century.33 Wildfires may cause direct physical damage to infrastructure and operational complications. For example, staffed facilities, including generation plants, are annually evacuated during wildfires,34 soot can affect transmission lines, ionized air in smoke can lead to arcing between lines, and firefighting fire retardants may foul transmission lines.35 Increases in 28
Melillo, et al., 2014. Wilbanks and Fernandez, 2013. 30
Melillo et al., 2014. 31
Melillo et al., 2014. 32
DOE, 2013a. 33
Melillo et al., 2014. 34
WECC, 2014. 35
DOE 2013, CEC 2012. 29
16 lightning strikes can damage lines and distribution poles; they can also lead to fires that cause indirect damage. A new study indicates ~50% increase in U.S. lightning strikes this century.36 Heat and flames from wildfires can also disrupt transmission.37 There have been observed increases in very heavy precipitation events across the west.38 By the end of the century, under a low emissions scenario, the 20‐year precipitation event39 is predicted to occur twice as frequently, and under a high emissions scenario the 20‐year event could occur three to four times as often.40 Projected increases in heavy rainfall events are expected to increase the potential for flash flooding. Warming is likely to directly affect flooding in many mountain settings, as catchment areas receive increasingly more precipitation as rain rather than snow, or more rain falling on existing snowpack. These projected changes can have direct impacts on energy infrastructure, such as increases in rates of erosion or scour at transmission line or fuel transport infrastructure. Rail lines often follow riverbeds and are the primary method of transportation for moving coal. Riverine flooding could degrade and wash out railroads and roadbeds that are critical for transporting coal to regional power plants. Landslides are associated with intense rainfall, increased runoff, extended periods of soil saturation, and wildfire events. While there are insufficient data on trends in landslide‐inducing storms to infer that these types of disturbance events are changing, as precipitation patterns shift and heavy precipitation events become more frequent, the conditions could become more suitable for landslides. Landslides can cause direct damage to infrastructure (e.g., increased sediment content can damage turbines) and result in operational disruptions (e.g., sedimentation can cause reduced storage volume in reservoirs). 2.4. Sea Level Rise and Storm Surge Local sea level rise can lead to chronic impacts and also interact with storm surge to increase potential impacts from flooding. At the energy‐ water‐land nexus, coastal land subsidence or changes in land cover due to coastal development, can exacerbate risks to coastal energy facilities as a result of sea level rise and storm surge. Key risks include:  Sea level rise can lead to permanent inundation of coastal energy infrastructure  Storm surge on top of sea level rise may increase frequency or severity of inundation of coastal energy infrastructure during storm events  Offshore energy production impacts from sea level rise  Intakes and outfalls in shallower water may experience greater impacts from storm surge and debris than those located further offshore in deeper waters 36
Romps et al., 2014 WECC, 2014. 38
A “very heavy” precipitation event, in this case, refers to the heaviest 1% of all daily events or a 100‐year event. 39
A 20‐year precipitation event is one that is predicted to occur once every twenty years or has a 5% chance of occurring in any given year. 40
Melillo et al., 2014. 37
17 
Coastal land subsidence from water or hydrocarbon extraction may increase local sea level rise The panels in Figure 5 show feet of sea level above 1992 levels at different tide gauge stations based on a) an 8‐
inch SLR and b) a 1.24‐foot SLR by 2050. The flood level that has a 1% chance of occurring in any given year (“return level”) is similarly projected to differ by region as a result of varying storm surge risk. Panel c) shows return levels for a 1.05‐foot SLR above mean high tide by 2050. Finally, panel d) shows how a 1.05‐foot SLR by 2050 could cause the level of flooding that occurs during today’s 100‐year storm to occur more frequently by mid‐
century, in some regions as often as once a decade or even annually. Figure 5. Projected sea level rise along the West Coast Global sea level has risen eight inches (Tebaldi et al. 2012)
since 1880 and is projected to rise another one to four feet by the end of the century. The observed and projected changes vary by region, as described in the Coastal sub‐region section below. Sea level rise and storm surge could inundate generation facilities within close proximity to the coast. Some facilities that are located on high ground in coastal areas may become isolated and inoperable even if the facilities themselves are not affected. Impacts from storm surge may be exacerbated by sea level rise and cause temporary inundation and flooding, which could lead to short‐term shutdowns or long term damage. Offshore energy production (e.g., those located off the coast of southern California) could be affected by sea level rise, storm surge, and extreme storms. Sea level rise may also increase salt water intrusion, which could further reduce the availability of freshwater for electricity production and other uses. 3. Sub‐Regional Profiles This section of the report presents the geographic scope, demographic trends, mix of energy generation types, and climate trends, projections, and impacts for high and low emissions 18 scenarios for the portions of the four sub‐regions41 of the WECC region that fall within the United States: Pacific Northwest, Southwest, Rocky Mountains, and Coastal.42 Presentation of the low and high emissions scenarios provides WECC with an envelope of potential plausible future conditions, under which risks and management responses can be considered. The low scenario is based on the low emissions scenarios from the Intergovernmental Panel on Climate Change (IPCC), including Representative Concentration Pathway43 (RCP) scenarios 4.5 and the Special Report on Emission Scenarios44 (SRES) B1, which are relatively similar to each other. The high emissions scenario is based on RCP 8.5 and SRES A2, which are also relatively similar to each other.45 3.1. Pacific Northwest The Pacific Northwest (PNW) sub‐region spans the northwest corner of Idaho, the non‐coastal portions of Washington and Oregon, and the northern reaches of California. The population of Oregon and Washington is anticipated to increase by about 27%, or 3 million additional people, by 2030.46 Over 60% of the energy production in Oregon and Washington comes from hydroelectric generation.47 Natural gas‐fired thermoelectric generation, coal‐fired thermoelectric generation, other renewables, and nuclear power comprise the majority of the remaining generation in the region.48 By mid‐century49, the average annual temperature in the Pacific Northwest is projected to increase by 2.0°F to 6.7°F, under the low emissions scenario (RCP 4.5) and by 3.1 to 8.5°F under the high emissions scenario (RCP 8.5). The frost‐free season has increased by 16 days during 1991–2012 relative to 1901–1960 in the Pacific Northwest and is projected to increase by 35 days by mid‐century, under the high emissions scenario (A2), relative to 1971–2000. Under a high (A2) emissions scenario, the number of days with temperatures that exceed 95°F are 41
Note that these sub‐regions DO NOT correspond to the WECC reporting areas. 42 Note that population and energy statistics for the sub‐regions are taken from the U.S. Census and EPA eGrid database, respectively, and data for entire states were used. However, specific comments about locations are discussed in the appropriate section (e.g., comments about the northern border of California are addressed in the Pacific Northwest section but the entire population of California is included in the Southwest sub‐region). 43 van Vuuren, D. et al., 2011. 44 IPCC, 2000. 45 Given that RCP scenarios were only recently published, there have been few impact studies based on the RCPs. Therefore, SRES and RCP information will both be considered in this report. Note that RCP 8.5 is representative of a continuation of the current path of global emissions increases, and is projected to lead to more than 8°F warming. Where sea level rise is included, the assumptions will be clearly stated. 46
U.S. Census, 2014. The majority of the population in the region resides in Oregon and Washington. California and Idaho populations were not included in this calculation because only a small portion of the state is considered part of the Pacific Northwest region. 47
EPA eGrid database, 2014. 48
EPA eGrid database, 2014. 49
2041–2070; increase relative to the average for 1950–1999. 19 anticipated to increase by five days (89%) and the number of days below 10°F are projected to decrease by seven days (15%) by the middle of the century.50 While model projections are inconsistent for future annual precipitation in the Pacific Northwest, they consistently project decreases in summer precipitation. Some models project more than a 30% decrease in summer precipitation for the 2050s (2041–2070, relative to 1950–
1999), although the average projected change for summer is notably smaller: −6 to −8% for a low (RCP 4.5) and high (RCP 8.5) emissions scenarios, respectively.51Additionally, the area‐
averaged snowpack in the Cascade Mountains has decreased by about 20% since 1950 and spring snowmelt is occurring 0 to 30 days earlier in the season, depending upon location. This has resulted in increases in late winter/early spring streamflows.52 By 2050, snowmelt is projected to shift three to four weeks earlier than the 20th century average, and summer flows are projected to be substantially lower, for the low emissions scenario (B1). Impacts of Climate on Water and Hydro in the Pacific Northwest Both droughts and heavy precipitation events can cause management and financial challenges for hydropower generation in the Northwest. Water shortages may result in a need to purchase additional power to meet contractual agreements and excess generation can cause the producer to flood the market with free or low‐cost electricity. Conversely, large river flow volumes can also present management challenges for hydropower utilities in the Northwest, when an oversupply of hydropower can lead to energy dumping. During periods of low water levels and low runoff in the Columbia River, as was experienced in 2010, the Bonneville Power Association (BPA) had to purchase power in order to meet demand and fill load obligations. In 2010 below average basin‐wide precipitation and streamflows resulted in $104 million gross increase in purchased power. Reduced hydropower generation in 2010 caused BPA to experience a net loss of $233 million (10%) from the prior year. Conversely, large river flow volumes can also present management challenges for hydropower generation in the Northwest. Following a dry winter, heavy rainfall from a strong Pacific storm in June 2010 nearly doubled streamflows in the Columbia River resulting in an oversupply of hydropower. “As a result, BPA disposed of more than 50,000 MWh of electricity for free or for less than the cost of transmission and incurred a total of 745,000 MWh of spill for lack of market in June 2010.” Collectively, these trends and projections indicate that the Pacific Northwest will experience more winter precipitation, earlier snowmelts, and less summer precipitation―which taken in combination results in an earlier peak streamflow, followed by declining late summer runoff. These shifts in water availability occur during the high energy demand period (summer), where competition for water is high, further stressing the reliability of hydropower generation. 50
Melillo et al., 2014. Snover et al., 2013. 52
Melillo et al., 2014. 51
20 Reductions in hydropower generation reliability during the summer, and in general, provide special challenges given the context of increasing extreme temperatures, and increasing water demand and energy demand during hot summer periods. A study by Markoff and Cullen (2008) indicates that based on the central estimates from each Global Circulation Model (GCM) for temperature change and summer precipitation for the high emissions (A2) scenario for the 2020s, winter time precipitation must increase by about 9% in the region in order to maintain current hydropower revenues. However, of all the 2020s scenarios, only the low emissions (B1) scenario predicts such an increase (9.4%). Extreme events are projected to become more frequent and intense throughout the Pacific Northwest, including heat waves, floods, and droughts. Increasing frequency and intensity of extreme events, such as flooding, wildfire, and landslides could impact generation, transportation, and transmission and distribution of electricity in the Pacific Northwest. Generally, flood risk is anticipated to increase the most in basins where precipitation falls as rain and snow due to an increase in winter rainfall and late spring snowmelt‐related runoff peaks.53 Additionally, under a high (A2) emissions scenario the number of days with more than three inches of precipitation is projected to increase by 22% by the middle of the century, as compared with a 1971–2000 baseline. More intense rainfall events are likely to increase runoff and subsequent flooding. Droughts may become more frequent as shifts in precipitation patterns are projected to result in longer, drier periods without significant rainfall. Wildfires have also become more rampant in the region; between 1970 and 2003 the area burned in western United States mid‐elevation conifer forests increased by 650% and models project that burned area in northern California could double by the end of the century. 3.2. Southwest The Southwest sub‐region covers Arizona, New Mexico, Nevada, and south and central California. The Southwest is projected to experience relatively rapid population growth by 2030, with a projected increase of more than 15 million people. Nearly half (43.8%) of the energy produced in the Southwest comes from natural gas‐fired thermoelectric generation, while coal‐fired thermoelectric generation contributes about 20%, nuclear 16%, hydroelectric 11%, and other renewables produce nearly 8%. 53
Melillo et al., 2014. 21 By mid‐century, the average annual temperature in the Southwest is projected to increase by 2°F to 6°F, and over 1°F to 4°F, compared to the 1970–1999 average under the high emissions (A2) and low emissions (B1) scenarios, respectively. The frost‐free season has increased by 19 days during 1991–2012 relative to 1901–1960 in the Southwest and is projected to increase regionally by at least 17 additional freeze‐free days under the high emissions scenario. Under the high emissions scenario (A2) the number of days with temperatures above 95°F is anticipated to increase by 20 days (44%) and the number of days below 10°F are projected to decrease by three days (20%) by the middle of the century compared to the 1971–2000 baseline. Climate warming is expected to increase peak period electricity demands for cooling in the Southwest. In California for example, peak energy demands are projected to increase between 10% and 20% by the end of the century due to the effects of climate change on summer afternoon temperatures.54 Extreme heat can also cause disruptions in transmission lines, as it did in Springerville, Arizona in 2011.55 July 2006 Heat Wave in California By the end of the century, California’s electrical grid may need to carry more than 23.7% more peak power per capita than it does today due to projected temperature increases alone. It will need to do so in the face of a 7.5% decrease in the capacity of fully‐loaded transmission lines. In July of 2006, over 80,000 customers in the LA DWP service territory lost power for days as 860 distribution line transformers malfunctioned or stopped working. 1.2 million PG&E customers lost power 1,150 distribution line transformers failed. High loads heated transformers and warmer‐than‐normal air failed to cool them, tripping circuit breakers, braking fuses, and burning insulation, causing short circuits inside transformers. Peak Load/Capita vs. Temperature
Sathaye et al. (2013)
Water availability in the Southwest is projected to decline as most of the region is projected to experience decreases in annual rainfall. Over the past 50 years across most of the Southwest, there has been less late‐winter precipitation falling as snow, earlier snowmelt, and earlier arrival of most of the year’s streamflow. Under a high emissions scenario (A2), by the end of the century precipitation in the Southwest is projected to decrease by as much as 30% during the 54
55
Tidwell et al., 2013. Wilbanks et al., 2012. 22 spring in parts of New Mexico, Arizona, and California.56 Across the region and all seasons, average precipitation is projected to remain the same or decrease, with the exception of northern Nevada where precipitation may increase up to 20% in the winter and fall.57 Between 2001 and 2010, streamflow totals in the Sacramento‐San Joaquin, the Colorado, the Rio Grande, and the Great Basin were 5% to 37% lower than the 20th century average annual flows.58 This trend is anticipated to continue with the snow water equivalent59 decreasing throughout the region. Figure 6 shows that in recent years water demands have exceeded supplies in the Colorado River Basin.60 This imbalance is projected to increase in the coming years due to increasing growth and declining flows due to a range of projected declines in flows.61 Figure 6. Colorado River long‐term supply‐demand imbalance in the 21st century (U.S. Bureau of Reclamation, 2011). 56
Projections for seasonal precipitation for 2071–2099 compared to 1970–1999 under an A2 emissions scenario. Melillo et al., 2014. 57 Melillo et al., 2014. 58 Melillo et al., 2014. 59
Snow water equivalent is the amount of water held in a volume on snow. 60
U.S. Bureau of Reclamation, 2011. 61
Hoerling et al., 2009. 23 Extreme events such as heat waves, flooding, and drought are projected to increase, while changes in wildfires are uncertain. Changes in Santa Ana winds, relative humidity, and temperature are factors known be relevant to fire weather conditions; projections indicate a reduction in Santa Ana wind events (reduce fire risk), a decrease in the relative humidity and an increase in temperature (favor fire risk).62 More studies on wildfires need to be undertaken, although risks to transmission in California are projected to increase (see box). Increases in atmospheric moisture in California’s coastal mountains and the Sierra Nevada are projected to increase riverine flood risk hazards. Flooding could cause direct damage to generation, transmission, and distribution assets. End‐of‐Century Probability that a Wildfire Affects a Transmission Line Sathaye et al (2012) project that wildfires will affect extensive portions of California’s transmission grid, with where the probability of exposure to wildfires for some lines projected to increase by 40% by the end of the century. The figure to the right shows the percent change in probability that wildfire will affect a transmission line for the GFDL climate model and a low (B1) and high (A2) emission scenario. Exposure potential greatest in areas with high fuel loading and drying. Heat waves during the summer are projected to become hotter and last longer.63 Drought is projected to become more frequent, intense, and last longer in the Colorado River Basin and across the Southwest.64 These changes can lead to many possible severe impacts, including increased competition for limited water resources limited the freshwater available for energy generation and increases in energy demand as more energy will be required for pumping and treating the limited water supply, while the warmer air and water temperatures can decrease the efficiency of energy generation and cooling processes. 3.3. Rocky Mountain The Rocky Mountain sub‐region covers Montana, Utah, Idaho, Colorado, and Wyoming. The Rocky Mountain sub‐region is the slowest growing part of the WECC region, projected to experience approximately 17% population growth or an increase of about 2 million people by 62
Gershunov et al., 2013. Melillo et al., 2014. 64 Melillo et al., 2014. 63
24 2030.65 The vast majority (71.2%) of the energy produced in the Rocky Mountains comes from coal‐fired thermoelectric plants, followed by natural gas‐fired plants (10.8%), hydroelectric power (11.9%), and other renewables (5.2%).66 Drought Leads to Large Reductions in Hydropower Generation at the Hoover Dam, Colorado
The Hoover Dam on Lake Mead and the Glen Canyon Dam on Lake Powell provide essential energy during peak demand hours to keep electricity rates lower in western states. This summer (2014), water levels in Nevada’s Lake Mead dropped to the lowest levels since the lake was filled in the 1930s. Historically low water levels led to a 23% reduction in hydroelectric generation. Annual production has declined during periods of drought, where total generation was 5.5 billion kilowatt‐hours in 1999, 2009 production was reduced to 3.7 billion kilowatt‐hours. The largest share of electricity produced by the Hoover Dam is consumed by the Metropolitan Water District of California, which requires a reliable energy source to deliver water to approximately 19 million customers in southern California. Decreased runoff from the Colorado River Basin compromises the ability of Hoover to produce sufficient energy to pump water from the Colorado River to customers in southern California. Increased energy costs would result in increased water costs in the region. Reduced snowpack in the Rocky Mountains and increased temperatures could compromise the ability of the Hoover Dam to continue to generate consistent amounts of electricity, under current operational practices. Increased demand for energy for cooling will occur simultaneously, resulting in the potential for demand to peak while generation capacity drops. Continued population growth in the region and increased demand for irrigation during hot dry periods will further stress the ability of the region to provide reliable energy. By mid‐century, the average annual temperature in the Rocky Mountain sub‐region is projected to increase by about 3°F and by 6°F, relative to the 1970–1999 average for the high (RCP 8.5) and low emissions scenario (RCP 2.6), respectively.67 Notice that climate and weather patterns vary significantly from low to high altitudes and from north to south along the Rocky Mountain range, and current research is fragmented across the different states and altitudes. However, there has been a clear upward trend in temperatures.68 The frost‐free season has increased by 10 to 19 days during 1991–2012 relative to 1901–1960 in the region and is projected to increase by nearly another eight weeks by the end of the century. 65
U.S. Census, 2014. EPA eGrid database, 2014. 67
Funk et al., 2014. 68
Barerra, 2009. 66
25 Water availability will be impacted by shifts in seasonal precipitation with potentially more rain falling in the northern latitudes and drier periods in the southern states. Under the high emissions scenario (A2), by the end of the century the northern portion of the Rocky Mountain sub‐region is projected to experience a 10% to 20% increase in precipitation during the fall, winter and spring followed by a 0% to 20% decrease during the summer.69 Over the same period of time, Colorado and Utah may experience modest increases in the winter and fall and no change or decreases during the spring and summer.70 Similar to the impacts in other regions, warmer temperatures and shifts in precipitation falling as rain rather than snow will impact the streamflow and availability of water in the Rocky Mountain sub‐region, resulting in impacts to the energy system due to the interconnectedness described above. Extreme events, such as heat waves, droughts, and wildfires are likely to increase. Heat waves will increase with the potential of the number of days over 100°F doubling in Wyoming and Montana by the middle of the century, even under a low emissions scenario (B1).71 Droughts are also projected to be more frequent, intense, and longer lasting in the Colorado River Basin. Generation facilities and transmission lines will become less efficient during days with extreme heat, while competing water demands rise, and the demand for energy increases as the number of days over 100°F are projected to double in part of the region. The fire season length and the frequency of large wildfires have also increased substantially in the region.72 In an analysis of large wildfires in the West from 1984 to 2011, scientists found a 73% increase in the average annual frequency of such fires in the Rocky Mountain sub‐region at the end of the period versus the beginning. This increase coincided with hotter temperatures and more‐severe droughts.73 Wildfires may cause direct damage to generation facilities, transmission lines, and distribution assets. They may also cut off access to facilities. 69
Melillo et al., 2014. 2071‐2099 projection compared to 1970‐1999 baseline. 71
Melillo et al., 2014. 72
U.S. DOI, 2011. 73
Dennison et al. 2014 70
26 3.4. Coastal The coastal sub‐region includes the areas west of the coastal ranges in California, Oregon, and Washington. Between 1970 and 2010 U. S. population growth in coastal watershed counties was significant, particularly in urban centers such as Puget Sound in Washington and San Francisco Bay and southern California. More than 35 million people live in the major metropolitan areas along the West Coast, comprising more than 50% of the population in the entire WECC region. The densely populated areas of Los Angeles, San Francisco, San Diego, Seattle, and Portland place heavy demands on energy infrastructure in coastal communities.74 The coastal regions will be uniquely impacted by sea level rise, storm surge, and extreme coastal storms. Uplift and subsidence cause sea level rise to vary in locations around the world. Sea‐level rise off the west coast of the United States is influenced by a variety of local factors including steric variations; wind‐driven differences in ocean heights; gravitational and deformational effects of melting of ice from Alaska, Greenland, and Antarctica; and vertical land motions along the coast. Therefore, sea level projections for California, Oregon, and Washington differ from global projections. The projections for California, Oregon, and Washington are illustrated in Figure 7. The steep change in projected sea level rise at Cape Mendocino reflects the transition from land subsidence in California, which effectively increases sea level rise, to land uplift in Oregon and Washington, which effectively decreases sea level rise. Figure 7. Projected sea level rise off California, Oregon, and Washington for 2030 (blue), 2050 (green), and 2100 (pink), When sea level rise is compounded by relative to 2000, as a function of latitude. Solid lines are the projections, and shaded areas are the ranges. Ranges overlap, as today’s 100‐year storm, storm surge indicated by the brown shading (low end of 2100 range and high end of 2050 range) and blue‐green shading (low end of 2050 could reach as high as nine feet in range and high end of 2030 range). MTJ = Mendocino Triple some areas along the coast of Junction, where the San Andreas Fault meets the Cascadia Washington. Off‐shore facilities may Subduction Zone. NRC, 2012. be at risk (outer continental shelf 74
U.S. Census, 2014. 27 marine and coastal facilities). California infrastructure is at risk, particularly in the low‐lying parts of the San Francisco Bay Area (see Figure 8). Additionally, an increase in the atmospheric moisture in California’s costal ranges will increase flood risk hazards in the region. Higher sea levels cause coastal erosion, more frequent coastal flooding, and saltwater intrusion into aquifers and estuaries.75 Sea level rise and storm surge may inundate and/or isolate critical generation facilities and distribution assets and transmission lines, while salt water intrusion could compromise or limit the availability of freshwater that is necessary for certain generation facilities. Finally, an increase in coastal storms may exacerbate concerns regarding acute disruption in generation and transmission and distribution. Figure 8. Substations exposed to a “100‐year” flood with a 1.4m Sea Level Rise (Sathaye et al., 2012). 4. Management Opportunities Throughout the report, the implication of the interdependency of energy systems, water systems, and land resources―and the compounding effect of climate change impacts across these sectors on energy reliability―has been highlighted. These compounding impacts are exacerbated by a context of projected increases in population and associated energy and water demands across the entire WECC region, which will further stress energy reliability. Since energy infrastructure can have lifetimes of 40 years or more, assessing long‐term climate change impacts, and identifying viable management options are important steps to ensuring the continued reliability of the electric system. 75
Melillo et al., 2014. 28 Throughout the report, four key “nexus risks” were identified that will challenge energy reliability in the WECC region, including:  Nexus Risk #1: Long‐term increased temperature and decreased water availability will drive simultaneous increases in energy and water demands, while reducing efficiency and capacity in the energy system. Where water availability is already constrained, for example in the Southwest, projected increases in temperature will result in higher energy demands for cooling, but reduced thermoelectric power generation and transmission efficiency. Overall higher water demands for energy production (e.g., biofuels and hydraulic fracturing for natural gas) and increased competition with other water users (e.g., environment, land, and domestic) will further reduce the system reliability.  Nexus Risk #2: Increasing intensity and frequency of heatwaves and drought, and shifts in timing, quality, and quantity of water supply will reduce the ability to respond during peak periods of energy demand. Intense or frequent drought can cause acute limitations in water for cooling of thermoelectric generation or hydropower production, and short‐term, intense heatwaves can trigger thresholds in operating conditions. In regions dependent upon hydropower, such as the Pacific Northwest, a projected continuation of shifts in the timing of peak runoff from summer to spring, and longer‐
term reductions in runoff as glaciers recede, will result in lower water supply buffers in the summer for hydropower production, when energy demand is highest, and competing water demands (such as domestic) are at their peak. More frequent and severe heat waves will likely increase the demand for electricity in the Southwest, where capacity to meet peak demand during heat waves is already a critical concern.  Nexus Risk #3: Climate‐related extremes will increase direct electricity service interruptions. Projected increasing intensity and frequency of floods, higher sea level and storm surges, increased wildfires, and potential increases in landslides, can directly result in costly damages to energy infrastructure, as well as disruptions to energy supplies. Changing landscapes as a result of climate and land development pressures can increase the risk and severity of impacts due to flooding, wildfires, and landslides.  Nexus #4: Increases in climate‐related extremes increase the risk of costly cascading electricity failures. Without sufficient capacity in the transmission lines, outages on the part of the system may result in cascading impacts. Due to the interconnected nature of water and energy, regional outages may impact the ability of water and sewage pumping stations to function and could result in public health concerns, such as sewage spills.76 These four “nexus risks” provide the structure for this section. For each of these risks, a series of management measures are provided, that can be categorized into two distinct types: policy and planning measures, and engineering and technological measures. Both types of measures can be applied to address risks across the entire energy system, to specific elements within the 76
FERC, 2012. 29 energy system, or to address areas within the traditional realms of land and water management. Before addressing the specific nexus risks, there are a range of crosscutting, low‐
regrets management measures that apply to all of the identified risks, primarily focused on the demand side, but also on improving information and monitoring. 4.1. Crosscutting Management Measures A range of primarily low‐regrets investments can be made to improve system understanding, and to encourage demand‐side efficiencies, that would effectively address inefficiencies across the key energy‐water‐land nexus impacts. These include policy, planning, and engineering measures that can be implemented by utilities, coordinating bodies, regulatory agencies or policymakers. In addition, integrating power sector planning across the nexus could result in improved system efficiencies that help to maintain energy system reliability. Increase knowledge through monitoring and measurement: Efforts to increase knowledge of the system (e.g., utility, grid) in light of climate change, such as investments in weather and hydrologic monitoring and impacts data, can provide critical information to decision makers given the uncertainty surrounding future climate variability and change. This information can be useful for adaptive management. Raise the priority of energy demand management: Utilities, policy makers, and regulatory agencies can incentivize consumers to reduce energy demand by either increasing efficiency or reducing consumption. While many of these strategies for demand side management exist in the absence of climate change, assessing the level of investment and the potential impacts on reliability under future climate scenarios may justify the need for demand‐side management. Future increases in demand in light of climate change may mean hitting critical system reliability thresholds sooner, leading to economic justification for enhancing or expanding energy efficiency and demand side management programs and investments. Such programs may include setting higher ambient temperatures in buildings to reduce cooling demands, promoting flexible work schedules to redistribute energy use away from peak hours, incentivizing customers to reduce loads during peak demands through pricing mechanisms.77 WECC could develop example language or standards that communities could use as guidance for adopting mandatory minimum energy performance standards for buildings and appliances. Promote active partnerships between energy and water utilities and managers: Given the energy‐water‐land nexus, water conservation and water demand‐side management strategies are critical in many regions, particularly those facing increased and more frequent drought and reductions in water availability. Strategies that may have been used only during periods of drought and/or heat waves may become more applicable as standard practice under future climate conditions, as hotter and drier becomes the new normal. Mechanisms to bring energy 77
Melillo et al., 2014. 30 and water managers together to discuss the implications of climate change, and proactively work toward solutions may result in efficiencies across the sectors. For example, increased coordination of water usage for power planning with other water and energy consumers (e.g., agriculture) may be required. Jointly developed public awareness campaigns could provide broad benefits. Explore energy market mechanisms: Electric utilities have some existing mechanisms that can be useful in times of drought, including purchasing electricity from the spot market.78 However, this requires significant excess supply in the market and sufficient transmission capacity. This strategy can be problematic during periods such as droughts or heat waves when energy supply and demand are affected over large geographic areas and options for supply are greatly diminished. Options purchased in advance can potentially reduce costs and limit risk attributable to a volatile spot market. Power exchange agreements can be set up to exchange power between utilities, they work best when different utilities have different load profiles and there is sufficient transmission capacity.79 PacifiCorp and APS have entered into such an agreement where the northern utility supplies APS in the summertime with electricity, and APS supplies power to PacifiCorp in the winter. Employ energy smart technology: Technological measures can be applied across the energy supply chain, or on specific elements within the energy supply chain. In general, creating more robust design specifications that incorporate climate change could enable structures to better withstand more extreme conditions, and operate more efficiently under changing conditions. Smart infrastructure investments can improve operational performance, and as a result, increase reliability in the face of potential climate change impacts. Smart technology investments might include:80  Smart meters that have outage notification capabilities which make it possible to pinpoint outage timing and locations more precisely, saving time and money.  Automated feeder switches that open or close in response to a fault condition reducing the number of customers affected by an outage.  Equipment health sensors to reveal possibilities for premature failures.  Smart microgrids to help to achieve a good match between generation and load. Technologies include advanced communication and controls, building controls, and distributed generation, including combined heat and power. 78
Harto et al., 2012. Harto et al., 2012. 80
US DOE, 2013b. 79
31 4.2. Nexus Risk #1: Long‐term Increases in Temperature and Decreases in Water Availability Drives Simultaneous Increases in Energy and Water Demands, while Reducing Efficiency and Capacity in the Energy System Addressing long‐term risks to energy reliability requires long‐term planning horizons, which fully explore the climate change risks to energy reliability, and take into consideration the impacts that climate change has on the energy‐water‐land nexus. Forward‐looking policy and planning measures that consider climate change can promote proactive approaches and early adoption of measures to addressing climate change risks on the energy system. Promote flexibility and adaptability: Given climate change uncertainty, a flexible and adaptable approach can improve capacity to adjust to new conditions. For example, increasing planning reserves can enable a flexible shift to alternate energy supplies. Yates and Avert (2013) demonstrate that future energy technology choices can significantly affect water availability and distribution amongst water users in the Southwest, ultimately influencing the buffer against further water stress afforded the region through its generous storage capacity in reservoirs. Reductions in water availability as a result of drought resulted in reduced hydropower generation, which is compensated for by increased natural gas generation, demonstrating the need for flexibility in energy supply. Evaluation of the changing seasonality of resources may result in supply source shifts, for example, a more heavy reliance on hydropower in the winter and more reliance on thermoelectric generation and alternative sources in the summer when streamflow is low. Design of feedstock that is more robust (e.g., tolerant to heat, salt, or water) can provide some flexibility for biomass/biofuels production.81 Secure adequate water supply: In some areas, new water transfers, and water supply contracts (e.g., from a farmer to a water utility) may be useful tools for ensuring adequate water supply for generation and cooling, where feasible. In other cases, groundwater may provide a sustainable backup water supply source if withdrawals over time do not exceed recharge rates, and the use of salt water for coastal facilities is another possibility. Contracts and backup plans need to be based on an understanding of the hydrologic future, which is different than the past. Introducing water use efficiencies, such as those described above, provide an alternative strategy in water scarce regions. Invest in water efficient systems: In some cases, investments and shifts toward less water‐
intensive generation methods such as dry/hybrid cooling systems for thermoelectric power plants may prove to be more reliable, despite reduced energy efficiency. This may imply retrofitting or enlarging thermoelectric cooling systems in water‐scarce areas to use dry cooling systems that require less water, or evaluating the efficacy of using dry cooling systems in the 81
ADB, 2012. 32 development of new thermoelectric power plants given climate changes. For biofuels, the introduction of more efficient irrigation systems for growing biomass/biofuel feedstock may reduce water demands. 4.3. Nexus Risk #2: Increasing Intensity of Heatwaves and Drought, and Shifts in Timing, Quantity and Quality of Water Supply, Reduces the Ability to Meet Peak Energy Demand The demand management and smart energy technologies described above under the crosscutting measures represent effective measures for reducing stresses by increasing efficiency or lowering energy and water demands, or by employing responsive smart grid technologies. In addition, many of the measures described above under Nexus Risk #1 can also help to buffer against high peak demands by securing water supply, or increasing adaptability and flexibility. Adopt new technologies to enhance operational management and increase peak generation: Hydropower plants can couple improvements in short‐term hydrologic forecasting to analyses of long‐term climate change to improve management and operational decisions regarding hydropower generation. Or they can evaluate operational changes (e.g., reservoir rule curve changes) given climate change to optimize energy output from hydropower facilities given other constraints and water priorities. Another option is to add peak generation capacity to deal with higher peak loads that may occur during more frequent and more intense heat waves. For example, adding pumped storage to conventional dams, or investing in closed loop pumped storage to meet peak demands. Adoption of new mandatory design codes for lines, transformers, and control systems that are designed to cope effectively with anticipated changes in peak loads during projected changes in high temperatures and disruptions from possible changes in frequency or intensity of extreme events can provide increased system robustness. 4.4. Nexus Risk #3: Climate‐related Extremes Will Increase Direct Electricity Service Interruptions Improve land use planning and management. Improved land use planning (e.g., rezoning land use) can be undertaken to better ensure siting of future power infrastructure in less vulnerable areas; although land use coordination and planning may face increasing challenges in siting land‐ and water‐intensive energy facilities as competition for these resources grows. Improvements in upstream land use management, including afforestation to reduce floods, erosion, silting and mudslides, can provide useful protection to existing infrastructure, including protecting turbines. Acquiring land for setbacks that allow space for projected increases in the floodplain. Integrate climate forecasts into facility planning and site selection processes. Revisiting vegetation management policies in light of projected increases in extremes and fires, may result in stricter regulations and maintenance schedules to prevent damage to 33 infrastructure during extreme storms, such as increased right‐of‐way spacing to mitigate line outages due to fires and storms. Update hazard and emergency risk management plans to include climate change. While rapid emergency response teams that can respond quickly in the event of damage are already standard practice for the utilities that provide electricity for the WECC region customers, emergency management plans could be re‐evaluated to ensure that service could be repaired rapidly in the event of a larger than historic disruption or a series of events, such as an early fall wildfire followed by flooding and landslides. The plans could also ensure that sufficient funding is accessible in the event of more expensive repairs. Existing hazard plans may be updated to consider the occurrence of more frequent and intense droughts and floods, or operational and maintenance procedures may be updated to be robust to projected changes in water availability. It may be appropriate to develop more stringent safety regulations against changing frequency or intensity of extreme events, including flooding, particularly for at‐risk nuclear power plants. Incorporate climate change projections into engineering design and planning: In general, robust design specifications that incorporate climate change could enable structures to better withstand more extreme conditions. Engineered solutions can improve the reliability of electricity transmission and distribution through hardening infrastructure and enhancing grid flexibility and control. Protecting existing infrastructure may involve elevating structures, insulating equipment, or building coastal barriers, for example. In some circumstances, deciding to forego new infrastructure investments, to relocate or retrofit existing infrastructure, or to build in redundancies in light of climate change may represent measures and decisions that enhance reliability. Infrastructure investments designed to maintain reliable energy generation during critical times can be retrofitted or augmented.82 Facilities can be designed to withstand flooding and inundation in areas with increased flooding risk from precipitation and/or sea level rise and storm surge.83 Other options may include modifying spillways, and installing turbines that are better suited to expected conditions to improve the reliability of hydropower.84 Installation and upgrading of cooling systems for substations and transformers in locations where temperatures are likely to increase can also increase system resiliency.85 82
ADB, 2012. ADB, 2012. 84
ADB, 2012. 85
ADB, 2012. 83
34 4.5. Nexus #4: Increases in Climate‐related Extremes Increase the Risk of Costly Cascading Electricity Failures Increase system flexibility and robustness: Specify redundancy in control systems, multiple routes, relocation, and/or underground distribution to protect against wind, high temperatures, corrosion, and flooding.86 The box, below, outlines specific measures that can be taken to manage risks to transmission and distribution, such as increasing the number of transmission lines to increase power flow capacity and provide greater control over energy flows. This can increase system flexibility by providing greater ability to bypass damaged lines and reduce the risk of cascading failures. 87 Managing Risks to Transmission and Distribution Transmission line capacity • build additional transmission capacity to cope with increased loads and to increase resilience to direct physical impacts • reduce line capacity requirements by producing a larger fraction of power at or near the destination • place transmission lines underground (also helps with fire and storm damage threats) Substation/transformer capacity • proactively install new types of cooling and heat‐tolerant materials/technology • install cooling systems for transformers • elevate substation control rooms to reduce potential flooding hazards Fire threats • increase fire corridors around transmission lines • use transmission line materials that can withstand high temperatures Erosion and flooding threats • create “green” buffers around exposed infrastructure • construct levees or berms to protect exposed infrastructure • elevate or relocate substations • consider extreme event threats in new siting • relocate towers/poles • reinforce towers/poles against flooding High wind threats • reinforce or replace towers/poles with stronger materials or additional supports to make them less susceptible to wind and flood damage Prediction and monitoring • invest in improvements to short‐ and medium‐term weather, climate, and hydrologic forecasting to improve lead times for event preparation and response • routinely monitor bell weather indicators related to climate, water, and T&D efficiency/costs Planning and design • revise design thresholds using climate change projections • incorporate climate change projections into planning processes 86
87
ADB, 2012. DOE, 2013. 35 Other measures to increase system robustness include evaluating the need for redundant cooling systems and enhancing protection of backup generation and cooling systems for nuclear facilities that may face increased exposure to flooding, other extreme events, and/or sea level rise and storm surge. 4.6. Conclusion Across the WECC region, demand drivers and climate conditions are projected to continue to change, with the potential to cause impacts across the energy‐water‐land nexus. Proactive planning for climate change impacts can help utilities within the WECC sub‐regions avoid costly reactionary measures and short‐term fixes to deal with disruptions or decreases in reliability. In cases where uncertainty is high and large capital investments are hard to justify, a practical approach may be to invest in low‐risk management strategies that deliver benefits regardless of the nature and extent of changes in climate. In other cases, large capital investments may be justified. Many of the presented management measures are low‐regrets actions that provide short‐term benefits because they address both current vulnerabilities and future risks. Given the interdependencies between energy, water, and land, integrating power sector planning with these sectors could improve the efficiency of managing climate‐related risks while maintaining system reliability. In that sense, while there are many management options that can be taken by electric utilities and coordinating bodies, some options would require coordinating with decision makers in other sectors (such as water and agriculture), and others by policy makers and regulatory agencies. Since the scientific community generally does not assign probabilities to emissions scenarios, it is difficult to assign full probabilities to particular risks. However, it is possible to assign probability of impacts within an emissions scenario. Technical approaches to quantifying the uncertainty in non‐stationary systems include importance sampling, fuzzy reasoning, and Bayesian methods. However, not all risk management approaches rely on quantifying uncertainty. Some accept the irreducible nature of some uncertainties and build off adaptive management practices to emphasize learning from the past and building resilience to possible change. Others, such as robust decision making, portfolio theory, scenario analysis and "no‐
regrets" approaches, focus on making decisions and developing management practices that will offer benefits over a wide range of possible outcomes. Regardless of the approach, risk management must consider the planning horizon and develop plans that appropriately address the investment needs and capacities across various time scales. Policy and planning can be informed by a robust decision‐making approach that can identify and test potential robust strategies, characterize the vulnerabilities of such strategies, and evaluate the tradeoffs among them. Robust decision‐making approaches (including modeling scenarios) are appropriate, given the deep uncertainties of climate conditions, demographic changes, technological and management conditions, and the complex relationships between climate change, water, land, and energy. 36 The measures described above provide general information regarding possible management measures to address reliability concerns given different climate impacts. However, detailed local assessments are necessary to provide greater understanding of climate vulnerabilities and to identify feasible management measures given the specific context and vulnerabilities. It should be considered that every management measure involves tradeoffs, that can increase or decrease stress on energy systems and water and land resources, respectively. Better understanding of these relationships can inform investment decisions that will likely require concerted and improved management of water and land resources to enable more reliable energy systems. 37 5. References Asian Development Bank (ADB). 2012. Climate Risk and Adaptation in the Electric Power Sector. Asian Development Bank, Mandaluyong City, Philippines. Barrera, Lina. Portraits of Climate Change: The Rocky Mountains. World Watch Magazine, July/August, 2009, Volume 22, No. 4. Available at: http://www.worldwatch.org/node/6160. California Energy Commission (CEC). 2012. Estimating Risk to California Energy Infrastructure from Projected Climate Change. CEC‐500‐2012‐057. Sacramento, CA: California Energy Commission. Available at: http://www.energy.ca.gov/2012publications/CEC‐500‐2012‐
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