The pace of change is increasing the risks to reliability across North America. The supply of electricity is not growing fast enough to keep up with demand growth. What was once a simple problem of supply and demand has become complicated by rapid change and increasing variability. Unless we prioritize reliability as the resource mix evolves and becomes more variable, we are at risk for serious and more frequent disruptions. The West must move quickly and more decisively to ensure resource adequacy over the next decade.
WECC's annual Western Assessment of Resource Adequacy (Western Assessment) examines resource-adequacy-related risks concerning the reliability of the Western Interconnection over the next 10 years. Through an energy-based probabilistic approach, WECC looks at the risks throughout the interconnection and five subregions. This work is meant to help stakeholders target specific areas and topics for deeper evaluation and mitigation.
The forecast rate of demand growth over the next decade is double what was forecast just two years ago.
Current resource plans forecast staggering demand growth over the next decade. For the Western Interconnection, annual demand is forecast to grow 20.4%, from 942 TWh in 2025, to 1,134 TWh in 2034. That growth rate is more than double the 9.6% growth forecast in resource plans filed in 2022, and over four times the historical growth rate of 4.5% between 2013 and 2022.
New large loads create reliability challenges that must be addressed immediately.
A major driver for the increase in demand over the next 10 years is the expansion of large loads like data centers, manufacturing facilities, and cryptocurrency mining operations. These loads consume immense amounts of energy, can be constructed quickly, have different consumption patterns, and require changes or additions to infrastructure. In some cases, large loads require a steady supply of power at all times, while in other cases, their demand can fluctuate, creating a need for large ramping capability. There can be challenges with the way large loads behave during grid disturbances, including their ride-through capability. According to current plans, the effects of large-load growth are greatest in the next three to five years; however, more large loads will likely be added to future forecasts.
To meet growing demand, entities plan to build unprecedented amounts of new resources over the next decade. Never has generation been built in the West at the rate called for in current resource plans. These plans could be unattainable given past struggles to build planned resources on time.
Current resource plans include 172 GW of new generation resources to be built in the next decade. This is more than double the generation capacity added in the last 10 years and will require an exceptional effort to carry out. Between 2014 and 2023, entities added 74 GW of new generation. Demand growth and resource retirements are driving up the number of new resources needed in the next 10 years.
If demand grows as expected and industry experiences delays and cancellations in building new resources over the next decade, the West will face potentially severe resource adequacy challenges.
Over the last six years, only 76% of planned resource additions came online in the year scheduled, and in 2023, that number was 53%. Resource margins are shrinking, leaving less buffer for cancelled and delayed projects. If the resource build-out over the next 10 years mimics the last five years, by 2034, the West will have hundreds of hours each year when demand is at risk.
Variability will continue to increase, exacerbating the risk of having inadequate dispatchable energy.
Over 85% of the 172 GW of planned resource additions in the next decade are variable resources (wind and solar), battery storage, or a hybrid. The addition of so many energy-limited resources, along with decreases in baseload resources and changes in load patterns, is creating more variability in the system. This increases uncertainty as to when and how much energy is needed and available. As uncertainty increases, risk increases.
Is the current resource planning structure adequate?
Entity resource plans seem overly optimistic. While planning entities provide specific information about the resources they plan to add in the next one to five years, in many cases, they provide generic, non-specific "placeholder" resources in long-term planning five to ten years out. Traditional resource planning and review practices do not have a mechanism to ensure that resources will actually be built.
Load Growth
Over at least the last decade, the Western Interconnection has experienced fairly steady and predictable load growth. This has changed. Large loads like data centers, manufacturing facilities, and cryptocurrency mining operations, as well as large-scale electrification, add substantial demand to the system in a very short time.
Load Changes
Annual Demand
Demand for electricity across the Western Interconnection is expected to grow 20.4% over the next 10 years. That is more than double the 9.6% growth projected in resource plans filed in 2022. Much of this increase is attributed to plans for large load facilities across many areas in theWest.The greatest area of load growth is the Desert Southwest (DSW), which is forecasting almost 35% load growth over the next decade.
The issue is not confined to the 10-year future. Large-load growth affects every year over the next decade, with greater effect in the next few years. For example, in 2023, the load projections for the NW-Central subregion showed a change from 128 TWh in 2025 to 139 TWh in 2034. This year's projections show an alarming increase in both the near and long-term: from 167 TWh in 2025 to 190 TWh in 2034. Data centers, manufacturing facilities, and to a lesser extent electrification, are driving this increase.
Peak Demand
Peak demand in the Western Interconnection occurs in the summer. Based on plans submitted by the BAs, the expected peak demand for the Western Interconnection will grow from 164 GW in 2025 to 193 GW in 2034, an increase of 17.2%. This represents a slight increase from 2023 resource plans.
According to 2024 resource plans, the projectedpeakis slightly lower for NW-Central than it was in 2023 plans, while it is slightly higher for the DSW subregion. For the California-Mexico (CAMX) subregion, the peak reflected in 2024 plans is also slightly lower each year until 2034, when the projected peak demand is identical (66 GW) to the projections made in 2023. The projections for NW-Northeast have not changed much between 2023 and 2024 resource plans, while the 2024 projections are slightly lower for the NW-Northwest subregion.
In addition, although the peak demand in the Western Interconnection overall occurs in the summer, many entities see their peak demand in the winter. As the climate changes, some of these entities are becoming dual-peaking. This introduces challenges to resource planning for entities that have historically seen one predominant peak.
The planned addition of large-load centers, as well as electrification, has caused the load-forecast growth rate to more than double over the next decade, changing the game for system planning.
Impact of Large Loads
Large loads like data centers, manufacturing facilities, and cryptocurrency mining operations add a large amount of concentrated load to the system. In some cases, new large loads inundate a service area, overwhelming existing infrastructure. Some new large-load consumption patterns are different than traditional load patterns, requiring around-the-clock energy. Others have a significant amount of variability.
Integrating large loads often requires changes or additions to power system infrastructure. Large-load facilities can be built relatively quickly, as fast as 18 months, while building new generation resources and transmission infrastructure can take years. In addition, the question of cost allocation can complicate the construction of new infrastructure.
Resource Changes
Resource plans for the next 10 years include large numbers of new generation resource projects. Never has generation been built in the West at the rate called for in many current resource plans. Delays or cancellation of these projects can put resource adequacy and reliability at risk.
Planned Additions
Planned Resource Additions
Over the next decade, entities in the Western Interconnection plan to add more than 172 GW of new generation capacity—almost 145 GW in battery storage, solar, and wind, according to resource plans filed in2024.That is up from 121 GW of resources in2023 10-year plansand is more than double the amount of generating capacity added in the last 10 years (73.7 GW). The existing generating capacity in the Western Interconnection as of 2023 was 299.5 GW.
Historical Resource Additions
Between 2018 and 2023, approximately 76% of the proposed resource additions came online in the year scheduled. In 2023, only 53% of thenew generation resources scheduled to come online that year actually came online; the rest were delayed or cancelled.
Solar
Entities plan to add nearly 68 GW of solar capacity over the next decade, more than any other resource. This will almost triple the amount of solar capacity that was in operation in 2023 (35 GW).
Wind
Wind capacity is projected to grow by nearly 40 GW from now until 2034. This increase will more than double the 37 GW in operation in 2023.
Battery Storage
According to 2024 resource plans, battery storage will grow by more than 37 GW by 2034. In 2022, resource plans projected a total of 23 GW of storage by 2032, and that was 14 times more than what was operational in 2021 (1.6 GW). As of 2023, there was more than 10 GW of energy storage (battery and other forms of storage) installed in the Western Interconnection, primarily batteries but also pumped hydro. One major driver of new storage is the extension of the investment tax credit (ITC) for storage-solar projects and creation of a 30% ITC for standalone storage.
Retirements
Planned Retirements
Entities plan to retire 25.85 GW of generation over the next 10 years. This is down slightly from resource plans filed in 2023, in which entities planned to retire 27 GW over the next decade, but is up considerably over the last 10 years. Retirement dates over the coming decade varied slightly compared to resource plans filed a year ago, but did not vary as much compared to the retirement delays we saw in 2023 resource plans. In 2025, for example, current resource plans call for 5.1 GW to retire, up from 4.2 GW in 2023 resource plans (but still down considerably from 2022 plans, when 7.4 GW were slated for retirement in 2025). Current plans also show a significant change in retirements in 2033. A year ago, 3.8 GW was set for retirement in 2033; in 2024, that dropped to 1.3 GW.
Changes in Planned Retirements
Most of these planned retirements (more than 24 GW) are baseload generation, such as coal, natural gas, and nuclear. In 2025, more than 4.4 GW of coal is set for retirement, and more than 3.6 GW of gas is slated for retirement in 2026.
In December 2023, California regulators voted to allow Diablo Canyon nuclear plant to remain open an additional five years—until 2030; it had been set to close in 2025. Diablo Canyon’s two reactors have a combined generating capacity of more than 2.2 GW and accounted for 7% of California’s in-state electricity generation in 2023.
Scenario Analysis
Challenges like supply chain issues, geopolitical turbulence, a shortage of skilled workers, siting issues, and the increasing interconnection queue can disrupt planned resources, which puts the interconnection at risk for resource shortfalls.
Scenario Analysis
Historically, the number of new resources that were built according to plan and on time has varied. In 2023, only 53% of planned resources were successfully built and brought online as scheduled. In other years the success rate was better. Between 2018 and 2023, only 76% of planned resource additions came online as scheduled.
If the past is a model for building planned resources over the next 10 years, resource adequacy will be at risk. To examine this, WECC evaluated four resource build-outscenarios:
- All planned resources are built on time
- 95% of planned resources are built on time
- 85% of planned resources are built on time
- 55% of planned resources are built on time
All Additions Scenario
If all planned additions are completed and operational on time, there are 89 demand-at-riskhoursover the next decade.
95% Scenario
In this scenario, there is demand at risk in every year except 2024 and 2026. In 2025, there are three hours of demand at risk, all in the NW-Northwest subregion. By 2034, that number increases to 91 demand-at-risk hours across the NW-Northwest and NW-Northeast subregions.
- NW-Northwest: Most of the demand at risk is in this subregion, including all three hours in 2025 and 82 hours in 2034.
- NW-Northeast: A total of 46 hours of demand is at risk over the next 10 years.
85% Scenario
If only 85% of resources are built on time, demand at risk begins to increase significantly in 2029, when 36 hours are at risk. This increases nearly every year until 2034, when 129 hours of demand is at risk. The vast majority of the demand at risk is in the NW-Northwest subregion.
- NW-Northwest: There is minimal impact in the short-term—a total of 16 hours of demand at risk through 2028. That increases nearly every year through the end of the 10-year period, peaking at 87 demand-at-risk hours in 2034.
- NW-Central: Demand-at-risk hours appear in 2031, with a total of 16 hours, and increase to 41 hours in 2034.
55% Scenario
In this scenario, there are a total of eight demand-at-risk hours in 2025 growing to 952 hours by 2034.
- CAMX: CAMX relies heavily on imports, resulting in no demand-at-risk hours in this scenario.
- DSW: Demand is at risk starting in 2028 (one hour) and increases to 69 hours in 2034.
- NW-Northwest: Demand is at risk every year over the 10-year period, starting with 8 hours in 2025 and climbing to 787 hours in 2034
- NW-Northeast: Demand is at risk every year starting in 2029 with two hours and increasing to 31 hours in 2034
- NW-Central: Demand is at risk after 2031, with a maximum of 65 hours in 2034
If significant numbers of new resources are delayed or cancelled, much of the Western Interconnection may not be resource adequate over the next decade.
Risks to Planned Resource Additions
Supply Chain Disruptions
Supply chain issues that surfaced during the pandemic in 2020 continue to affect the industry, particularly the construction of new projects and the interconnection of new generating resources. A recent survey found that supply chain issues remain a significant problem in 2024.
Interconnection Queue
The interconnection queue nationwide grew more than 30% in 2023 and has increased eightfold in the last decade. The planned additions over the next 10 years will exacerbate this issue, although FERC Order 2023 calls for reforms to reduce the backlog and address uncertainty in the interconnection process.
Siting Delays
There has been increasing resistance to building new energy facilities, particularly wind, solar, and battery projects. These projects have encountered opposition in at least 45 states, according to a recent report that found that local opposition to new energy facilities is widespread and growing.
Increased Costs
Increased costs of materials for new wind and solar construction, transmission expansion, and replacement of plant equipment have caused project delays and maintenance deferrals. The rise in interest rates in recent years has also substantially increased the cost of capital for all energy projects.
Variability
The addition of 107 GW of variable resources and retirement of 26 GW of generation, most of which is coal and natural gas, will increase system variability in the next 10 years. These changes increase risk and create challenges in system planning and operation.
Replacing Generation Resources
Over the next decade, the addition of 107 GW of wind, solar, and battery hybrid generation must cover load increases and replace 26 GW of retired resources, of which almost 25 GW are coal, natural gas, and nuclear resources. The capacity factor of variable resources is lower than baseload resources like coal, natural gas, and nuclear. Replacing the 25 GW of retired baseload resources will require much more installed capacity of wind, solar, and storage resources.
Increases in variable resources, decreases in baseload resources, and changes in load patterns are driving an increase in variability across the system. Variability creates uncertainty, and uncertainty creates risk.
Traditionally, resource planning has been based on capacity and focused on ensuring there is enough capacity to meet peak demand. This has been based on the assumption that resources are available as expected (accounting for forced outages). However, with increasing variability, looking only at resource capacity is no longer enough. An examination of energy availability is crucial to ensuring the West has enough energy to meet demand at all hours of the year.
WECC receives nameplate capacity and historical generation information from Balancing Authorities. From this, WECC calculates the expected energy output of each resource and aggregates that number to get the expected energy for the entire resource fleet. The expected energy is lower than the nameplate capacity because resources do not produce at full capacity all the time. An increase in energy-limited resources widens the gap.
As the variability of the resource mix increases, so does the range of possible generation output at any given time. Depending on system and resource fleet conditions, more or less than the expected energy may be available. Instances when less energy is available can create risk, particularly when load is high. This can be the case during extreme weather events that cause simultaneous load increases and reductions in wind and solar output.
To address this, WECC calculates the probability distributions for each resource in the fleet. These distributions show the probability that a resource will generate at levels other than the expected level. The probabilities form a band of variability where the most likely output is in the middle and the least likely outputs are at the edge. The wider the band, the higher the variability on the system and the more possibilities planners and operators need to account for.
The size of the variability band increases over the next decade, indicating that while the West is building large amounts of new resources, the overall variability of the resource fleet is increasing.
Resource Planning
Existing resource planning practices allow a lack of specificity about the resources entities need to meet demand, particularly in the long term. The resulting uncertainty about future resource additions puts the resource adequacy of the interconnection at risk.
Planning Resource Additions
Planning entities provide WECC with information about new resources they will need to meet demand over the next 10 years. In the near term, this information includes specific resource additions for the next one to five years. Typically, entities have a higher level of certainty about these resources because they are in some state of development.(Tier 1 or Tier 2 resources)Entities also include resources that are not yet under development (Tier 3 resources). When Tier 3 resources are included in near-term plans, they often reflect specific resources the entity can add relatively quickly (Tier 3 Specified). When they are included in later years of a resource plan, they are usually generic placeholder resources (Tier 3 Generic). In these cases, there is less certainty about whether the resource will be built. These resources often lack unit characteristics and may be grouped together instead of listed as individual plants or units.
In the past, when there was steady, predictable load growth and a generation surplus, entities could grossly estimate the resources needed 5 to 10 years in the future and hone those plans later. There was enough surplus generation in the interconnection to cover situations where new resources were built late, cancelled, undersized, or when demand increased unexpectedly. However, given the level of change in the West, the large amounts of new generation needed over the next decade, and obstacles to building it, delaying long-term resource decisions may put the resource adequacy of the interconnection at risk. This leaves the industry in a difficult position, because it needs more clarity about the future in a world that is becoming increasingly hard to predict. Resource plans that include large amounts of Tier 3 resources likely overestimate the ability to build generation.
Recently, there have been efforts to conduct longer-term planning on a 20-year horizon to meet needs identified by industry and the Federal Energy Regulatory Commission (FERC). In its Order 1920, FERC requires 20-year transmission planning to ensure the industry is preparing for the long-term future of the electric grid. While planning further out may allow the industry to see potential risks sooner, that work is only as good as the information on which it relies. Planning entities struggle to specify new resources in their 10-year resource plans; hypothesizing a resource mix in the 20-year future to study transmission may be incredibly challenging. To be successful, requirements for 20-year—and longer—planning horizons will spur advances in long-term resource planning.
Resource Adequacy Programs
Resource adequacy programs can help manage resource adequacy by taking advantage of operating efficiencies and diversity across the entities in their footprint. The California ISO's reliability requirements program sets resource adequacy requirements for load serving entities in the ISO. The CAISO program has functioned for years and is integrated with its other functions.
The Western Resource Adequacy Program (WRAP) is a developing program with the goal of providing a region-wide, collaborative approach to resource adequacy. The WRAP is administered through a FERC-approved tariff that allows participants to phase into full, binding participation, including being subject to non-compliance charges for failing to meet the requirements of the program. Efforts to launch the binding program have encountered several obstacles. In April 2024, WRAP participants indicated they lacked critical mass to be able to move to the binding phase by Summer 2026. Participants cited challenges that include procuring sufficient firm capacity to meet program requirements and avoid charges. In an effort to move toward a binding program by Summer 2027, WRAP will file tariff changes with FERC that include a temporary reduction of non-compliance charges so participants can fully participate in the program and have access to WRAP capacity reserves on the worst of operating days.
To commit to a resource adequacy program, entities must know what resources they will have to offer. Resource plans that contain large numbers of Tier 2 and Tier 3 resources provide little certainty about future resource capacity, meaning entities cannot be confident in what resources they will have to offer. This may create reticence and, ultimately, delays on the part of entities in joining these programs.
Additional Considerations
Resource adequacy is interwoven with other issues such as transmission planning, policy making, and shifts associated with a changing climate. Each introduces significant risks to reliability.
Transmission Considerations
The modeling tool WECC uses for the Western Assessment transfers electricity between entities when one has a shortfall and the other has sufficient available energy to meet that shortfall.
The analysis in this report differs from that in the Interregional Transfer Capability Study (ITCS), an assessment on which WECC collaborated with NERC and the other Regional Entities to gauge the ability to transfer electricity between regions in the U. S. and Canada, and to determine prudent additions to transfer capability to support reliability. Congress mandated the ITCS in the Fiscal Responsibility Act of 2023. The ability to transfer power between regions could be a key to maintaining reliability amid the changing resource mix and as climate change brings more extreme weather.
Imports
WECC’s analysis includes imports, or the ability for entities to transfer electricity between subregions. Studying the ability to import electricity is important because the Western Interconnection was designed to take advantage of its geographic and resource diversity. Imports are critical to reliability, particularly as the variability of the system increases. However, under some extreme conditions, either the resources or the transmission capacity may be reduced or eliminated altogether. Looking at different importscenarioshelps WECC better understand the interplay between resource adequacy and transmission availability.
The analysis shows that every subregion relies on the ability to import or transfer electricity, although the impact is much less significant in the DSW and CAMX subregions. The NW-Northwest and NW-Northeast subregions were the most affected in terms of demand at risk, with more than 1,900 hours of demand at risk every year.
Energy Policy
Federal and state policies are driving changes in the electric system. Several states in the West have ambitious clean energy goals, for example, and federal legislation has steered unprecedented amounts of funding to the energy sector.
Together with the Bipartisan Infrastructure Law (BIL), the Inflation Reduction Act (IRA) has accelerated the transformation of the electric grid by making fundingavailablefor the development and deployment of clean energy manufacturing facilities and research in the form of tax credits, loans, investments, and other programs.
Batteries and electric vehicles have drawn the most investment—since the IRA’s passage, $114 billion in new projects in those industries have been announced, a recent analysis indicates. Also, according to the White House, the U.S. was projected to build more new electric generation capacity in 2024 than has been built in the last two decades, with 96% of that being renewable energy.
At the state level, Washington's Clean Energy Transformation Act requires utilities to supply the state's customers with electricity that is 100% renewable or free of greenhouse gas emissions by 2045. California also has a goal of 100% of its electricity coming from renewable energy and zero-carbon resources by 2045. And Oregon's Clean Energy Targets bill requires the state's electricity providers to significantly reduce the greenhouse gas emissions levels of the electricity sold in the state: 80% below baseline emissions levels by 2030, 90% below baseline emissions levels by 2035, and emissions-free by 2040.
Weather
Extreme weather events are increasing in frequency and intensity, in some cases becoming more extreme, unpredictable, widespread, and longer-lasting. These events affect generation, particularly as the resource mix and the demand for electricity becomes more variable. As weather becomes more extreme, what used to be considered extreme is becoming more normal. This is changing how we manage the system.
FERC has approved several new weather-relatedstandardsin recent years, to help close reliability gaps, and utilities and planning entities continue to adapt their projections to account for climate change.
Through its 10-year and 20-year assessments, WECC examines the impact of severe weather on resource adequacy by assessing how the subregions in the Western Interconnection rely on imports to remain resource adequate during events that trigger high demand for electricity. As the climate changes and events become more widespread, it is important to understand how to use the diversity of the interconnection and its evolving resource mix to ensure resource adequacy.
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