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Results were released today for the first auction of the year, and 13th overall, in Washington’s Cap-and-Invest program. With prices down over $5 from Washington’s last auction, today’s results may be a reflection of covered entities’ growing confidence in a future linked market, following on the release last week of a draft linkage agreement between Washington, Québec and California.
The auction showed a continuation of the strong demand seen in all of Washington’s auctions thus far, and is projected to generate $183 million in revenue for investments in communities, affordability and climate resilience in Washington State.
Washington’s Cap-and-Invest auctions are administered quarterly by the Department of Ecology (Ecology). During the auction, participating entities submitted their bids for allowances. Under the Climate Commitment Act — Washington’s landmark climate law that sets a binding, declining limit on pollution — major emitters in Washington are required to hold one allowance for every ton of greenhouse gas they emit, with the total number of allowances decreasing each year. This system requires Washington’s polluters to reduce their emissions in line with the state’s climate targets, as fewer allowances become available annually.
Today’s results come just over a week after the release of a draft linkage agreement between California, Washington and Québec. The decline in auction prices seen in today’s results may be a reflection of improved confidence among covered entities that, upon finalization of linkage processes in each jurisdiction, they will have access to a larger pool of allowances from a future joint market with California and Québec.
California and Québec have shared a linked market for over a decade, demonstrating that well-designed linked cap-and-invest programs can lead to deeper pollution cuts while supporting economic growth. Adding Washington to this established partnership would build on a proven model and strengthen the programs of all participants. Merging into a larger market would likely lead to more stable, predictable allowance prices, which is crucial for polluters to make decisions about compliance planning and investing in decarbonization.
Washington has been making steady progress towards their linkage rulemaking, which they’re expecting to finalize in mid-2026. California has been working to update their own program rules, including updating their emissions allowance budgets, and is expected to take up its own linkage process this year as well. Linkage is a key opportunity for climate leadership for both states, to take a step that will strengthen one of our best and most cost-effective tools to reduce emissions and raise revenue for community investments.
With a draft agreement now published, Washington, California and Québec are taking a significant step towards market linkage and stronger programs that can drive long-term emissions reductions with greater certainty. Washington’s Department of Ecology is taking public feedback on the draft through May 1, and the linked market could launch as early as 2027. The need for scalable, durable climate action at the state level has never been greater, and these jurisdictions are showing how working across borders can drive meaningful progress.
With Governor Abigail Spanberger’s signature on a budget agreement that directs the Commonwealth to immediately rejoin the Regional Greenhouse Gas Initiative (RGGI), Virginia is back on track with the climate policy the state needs. This budget agreement — which legislators call the “caboose” budget — doesn’t just cut pollution, it supports communities as they adapt to increased flood risk and creates a dedicated pathway to increase energy affordability for those who need it most.
A huge dose of gratitude goes out to the General Assembly and the Governor for recognizing that a cleaner grid and affordable bills go hand-in-hand. By re-entering this proven, multi-state program, Virginia is securing a healthier, more resilient and more affordable future.
Virginia’s journey with RGGI has been eventful. The General Assembly originally passed a law in 2020 requiring participation, and the Commonwealth successfully participated from 2021 to 2023. Unfortunately, the Youngkin administration unlawfully withdrew the state from the program in 2024. While a court ruled his unilateral repeal “unlawful and without effect” in November 2024, an ongoing appeal kept Virginia on the sidelines.
With Governor Spanberger’s signature, that uncertainty is over. Virginia is back in the game.
RGGI is a practical, market-based solution to climate pollution. Power plant owners are required to purchase an allowance for every ton of carbon dioxide their plant emits. Over time, the supply of these allowances decreases, which steadily drives down emissions across participating states. Beyond delivering cleaner air, RGGI actively reduces utility reliance on dirtier, more expensive fossil fuels. This transition leads to steadier, more predictable energy bills, greater energy independence and enhanced grid security.
When power plants purchase carbon allowances, the revenue generated flows directly back into participating states.
Here is how RGGI revenue is put to work in Virginia:
The Virginia Department of Environmental Quality has now been instructed to begin the necessary steps to rejoin RGGI immediately, a process that should conclude by the end of May. Rejoining RGGI is a victory for every Virginian who wants cleaner air, lower utility bills and neighborhoods that are protected from the impacts of climate change. Thank you, Governor Spanberger, Delegates and Senators, for prioritizing Virginians and climate over polluters.
It’s becoming all too common for families and businesses to experience the symptoms of a strained electricity grid—whether it’s rising bills or more frequent power outages. Between growing demand, aging infrastructure and extreme weather, the U.S. grid is under immense pressure. For Western states, the challenge is especially pronounced: during peak hours of electricity demand, up to 70% of states’ power is imported from neighboring states’ utilities. Decision makers across the region are looking for guidance as they plan for the next generation of the grid.
Transmission lines deliver electricity from where it’s generated to homes, businesses and schools. Building and improving the transmission system is the key to ensuring the lights stay on and utility bills remain affordable. Since new transmission lines can take several years to come online, utilizing existing grid infrastructure more effectively can lead to solutions in the near term. Utilities in Western states typically use , which means there is significant capacity for serving new load and integrating new generation quickly and affordably. To ease costs and keep the grid reliable, we need to build new transmission lines and make the most of existing infrastructure.
A coalition of utilities, developers, states and Tribes recently published a roadmap for planning a more reliable and affordable grid throughout the West. The Western Transmission Expansion Coalition (WestTEC)’s 10-Year Horizon report offers important insights for decision makers, providing clear guidance for states and transmission developers navigating landscape marked by rapidly growing demand and shifting priorities. This coalition’s findings should spur action to ensure continued access to affordable and readily available electricity. Otherwise, families and businesses will foot the bill for an ever-growing demand for electricity.
There are four primary reasons why proactive planning is so necessary to maintaining a reliable, affordable electrical grid:
Importantly, as demand shifts and generation capacity grows, the infrastructure for getting power where it needs to go—transmission—isn’t keeping pace.
Taken together, these pose major challenges for state decision makers and make clear the need for coordination across states for transmission planning.
WestTEC was launched in 2023 to address this need for long-range transmission planning. Facilitated by the Western Power Pool—a group of electric utilities in the Western United States and Canada that share resources—the coalition is charged with supporting the Western Interconnection, the power grid that spans much of the Western U.S. and parts of Canada and Mexico.
WestTEC’s new report is a key component of the effort to increase transparency and coordination in transmission planning. It details the reasons for proactive planning and dives deeper into the transformative forces reshaping the grid. It also identifies projects that will help the West meet demand growth, seamlessly integrate new generation, and increase reliability. The report identifies 12,650 total line miles of upgrades needed to meet the region’s forecasted needs. Around 9,400 miles worth of projects are already planned, with close to one fifth of these under or nearing construction. That leaves around 3,300 line miles of identified upgrades that still need to be developed to address reliability, deliverability, and efficiency goals across the region.
Building this technology comes with a price tag—roughly $5.3 billion per year. Though that number seems steep, it’s actually just a fraction of the total spending on Western electricity, which was nearly $120 billion in 2024. In fact, it’s only about 2.5% of today’s average retail electricity price. Importantly, transmission has front-loaded costs that are repaid over time. A recent report from Americans for a Clean Energy Grid estimates that, for every $1 invested in transmission, customers see up to $4.70 in benefits. In other words, these transmission upgrades have the potential to translate into massive future savings for families and businesses without breaking the bank today.
Stronger transmission networks can ensure states reap the full benefits of forthcoming Western electricity markets. A more interconnected grid helps utilities manage stressors like extreme heat. When local conditions tighten and electricity is constrained, states can share resources to ensure reliable electric service. A more coordinated and connected transmission grid also produces significant economic benefits. The Western Energy Imbalance Market allows participants to buy and sell power in real-time. Since 2014, the market has resulted in over $7.4 billion in total market benefits. Coordinated transmission planning and development create the conditions for a mature, fully regional electricity market that benefits every participating state.
The forces pressuring the grid will only grow more complex, but the collaborative solutions offered by WestTEC give decision makers the knowledge and tools to tackle the challenge. The coalition is also producing a 20-Year Horizon Report that looks at planning scenarios into 2045, which will address uncertainty, help understand how transmission needs change over time and allow for evaluation and right-sizing of the 10-year horizon upgrades. The 20-year report will also forecast the benefits of key transmission portfolios, which can help decision-makers better argue for and defend the recommended upgrades.
As developers and states start taking steps to implement WestTEC’s recommendations, engaging communities from the beginning of the process can ensure better outcomes for all. A recent EDF report found that early engagement with communities and Tribes helped reduce opposition to transmission projects, avoid costly delays and deliver lasting value for both developers and communities. A more resilient, interconnected grid is a more reliable, affordable grid—and one that offers clear benefits for the West.
Developers and states should rely on the guidance offered by the WestTEC report to start pursuing recommended upgrades, communicate costs and benefits to customers and engage in a collaborative development process that involves communities at each stage.
California surpassed 2.5 million zero-emission vehicles years ahead of schedule. Nearly $12 billion in private-sector electric vehicle investments have been announced. EVs can now power homes during outages. Fleets can slash fuel costs by more than 60%. Many communities near ports breathe cleaner air. These aren’t projections – they’re results already delivering across California.
State leadership and targeted investments made this progress possible. As lawmakers finalize the budget amid federal attacks on California’s clean vehicle authority, the state’s clean transportation budget stands out as one of the most powerful tools to protect public health, lower costs, expand consumer choice and sustain economic momentum.
Environmental Defense Fund applauds the Governor’s proposed $200 million light-duty vehicle incentive and urges the Legislature to commit at least $1.5 billion to fund the full spectrum of clean vehicles and infrastructure (see our fact sheet for more recommendations).
After housing, a car is the second-largest household expense, and purchase prices remain a real barrier for families who want to choose cleaner vehicles. Incentive programs like Gov. Newsom’s proposed new light-duty incentive and Clean Cars 4 All help remove that barrier – especially for low- and moderate-income households replacing older, high-polluting cars with options that fit their budgets. Funding these programs in the final state budget is essential to keep clean transportation within reach for California families.
Once on the road, the savings continue. EV owners in California can save up to $1,500 in fuel and maintenance over a passenger vehicle’s lifetime, while heavy-duty truck operators can save up to tens of thousands of dollars per vehicle. With volatile fuel prices and rising living costs, those savings matter now. These state incentives for buyers deliver immediate relief at the point of sale and long-term affordability every month after.
Electric vehicles do more than move people. Bidirectional charging turns EVs into mobile batteries that charge from the grid and supply power back to homes during outages. One Santa Cruz-area family already powers their entire home with their electric pickup truck during frequent mountain blackouts.
They’re not alone. Across California, EV owners are running refrigerators, lights, phones and medical equipment when the grid fails. By 2045, this distributed battery network could deliver over $10 billion annually in grid savings by cutting peak demand, avoiding costly upgrades and lowering rates for all customers.
Despite significant progress, transportation remains California’s largest source of smog and climate pollution, with communities near ports, warehouses and truck routes bearing the heaviest health burden for decades. Clean truck investments are beginning to change that reality.
At the Ports of Los Angeles and Long Beach, electric drayage trucks are replacing diesel vehicles that operate all day in nearby neighborhoods. California-based companies like Tradelink Transport are deploying zero-emission trucks that eliminate tailpipe pollution while dramatically lowering operating costs.
Replacing heavy-duty diesel vehicles could deliver up to $5.6 billion in statewide health and environmental benefits while modernizing California’s goods-movement system. Demand for the Clean Truck and Bus Voucher Incentive Project consistently exceeds available funding – clear evidence that fleets are ready to electrify when incentives exist. The Legislature should continue funding this essential cost-saving and public health program.
In Humboldt County, McKinleyville Union School District used California Climate Investments to purchase four zero-emission school buses, cutting fuel and maintenance costs by 60% while improving air quality for 250 students. In rural communities, the Funding Agricultural Replacement Measures for Emission Reductions (FARMER) program helps growers replace diesel equipment with cleaner alternatives, reducing both air pollution and fuel costs.
Yet despite its success, the current state budget left FARMER without funding – ignoring an urgent need among California’s agricultural communities that must be addressed this year.
Major corporations also see the value. In 2024, PepsiCo announced a major expansion of its California electric fleet, including 50 Class 8 Tesla Semi trucks and 75 Ford E-Transit vans to cut costs and carbon dioxide (CO₂) emissions. By energizing 20 trucks ahead of schedule, the company estimates it will avoid roughly 8,000 tons of CO₂ and save about $1 million in fuel costs. These projects support jobs across manufacturing, construction, utilities and technology – and they depend on stable, multi-year state investment to scale.
Federal rollbacks of national standards and the loss of key tax credits have rattled the ZEV market, triggering clean energy investment cancellations nationwide that wiped out 39,000 jobs and $29 billion in 2025, according to EDF analysis. California’s state transportation budget remains one of the Legislature’s most reliable tools to preserve momentum, protect affordability and deliver results. The Legislature should seize this opportunity.
These ZEV buyer incentives accelerate adoption now to lock in long-term savings, cleaner air, consumer choice and economic benefits for decades. Meanwhile, EV costs continue to fall rapidly across multiple segments. Passenger electric vehicles are nearing upfront price parity with gasoline models – and in some cases, they’re already cheaper.
California’s clean transportation investments are working – at homes, ports, schools, farms and businesses statewide. The question is whether California’s leaders will continue building on what’s already succeeding. The evidence from communities across California is clear: continued investment delivers real returns. Now is the time to double down.
Results were released today for the February 18 auction for the joint California–Quebec Cap-and-Invest market, the first of the year and the first since the California Air Resources Board (CARB) published its initial plans for updating this cornerstone climate program.
Today’s allowance prices, detailed below, signal lackluster demand and suggest there is ample room in the emissions market to tighten the cap in order to maximize program benefits for the achievement of California’s climate emissions reduction targets, cost of living and the state’s economy. With almost 88% of the allowances in this auction bought by compliance entities, it’s clear that the low prices are not just the result of financial interests’ speculation — there is real opportunity for tightening these allowance budgets and reducing emissions in the near-term. Modestly improving market confidence is important given that recent uncertainty leading up to last year’s program reauthorization through 2045 cost the state roughly $3 billion.
California’s Cap-and-Invest program serves as the state’s emissions backstop: a foundational policy to cap and reduce climate pollution, while generating critical revenue to invest in energy affordability, climate resilience, infrastructure, and more. And, California’s suite of climate policies produced one of the largest annual emissions reduction while California’s economy continues to grow. The latest data from CARB shows statewide greenhouse gas emissions fell another 3% in the most recent inventory — equivalent to taking more than 2.6 million gas-powered cars off the road for a year. Cap-and-Invest is a key part of that success. But there’s still more that California needs to do in order to make sure this program is really delivering reductions at the pace and scale required to meet its climate targets while also addressing household energy affordability.
With the formal rulemaking process now in motion, CARB has a pivotal chance to set the cap-and-invest program’s ambition at a level that truly meets this moment — both for cutting emissions and delivering tangible benefits to communities across California. EDF supports the adoption of a stronger emissions cap and stronger reductions in the cap compared to what CARB proposed in the Initial Statement of Reasons (ISOR).
The allowance budget reductions outlined in the agency’s proposal reflect only the minimum needed to align with the 2030 emissions reduction targets, well below the stronger pathway CARB previously presented. The proposal would remove about 118 million allowances from 2027-2030 and set a post-2030 pathway to an 85% emission reduction by 2045. While this represents progress compared to the existing cap trajectory, deeper reductions before 2030 are essential to ensure the program drives near-term emissions cuts and maximizes benefits for households and communities across California.
Preliminary modeling conducted by Greenline Insights for EDF shows CARB could reduce emissions at a faster pace while maintaining cumulative cost savings for low- and moderate- income households.
With a growing list of states considering policies like California’s and seeking to join the state’s emissions market, the stakes could not be higher. California pioneered this policy and must show that it works. The relatively weak demand for allowances seen in today’s auction results — selling out current vintages, but at the price floor — illustrates a tighter cap and faster rate of emissions reduction are the most logical path forward to meet the affordability needs of households across California and the urgency for climate action at scale.
This blog is part of a series by EDF on the development of a regional electricity market in the West. Other blogs in the series explore the overall importance and benefit of a regional market, the impacts of market participation in Colorado and California, and opportunities unlocked via passage of California AB 825.
After decades of effort, a regional electricity market in the Western U.S. is taking shape. Recent legislation in California marked a critical step forward in a decades-long process to establish an independent, West-wide power market that will deliver cleaner, more affordable and more reliable electricity to consumers in the West. This new market could deliver real savings to Arizonans’ electricity bills. To fully realize these benefits, utilities must embrace regional cooperation.
Arizona’s largest electric utilities, including Arizona Public Service (APS), Salt River Project (SRP), and Tucson Electric Power (TEP), are all primed to join a regional “day-ahead market” within the next few years. They have two options: 1) the Extended Day-Ahead Market (EDAM), which will be governed by a new independent Regional Organization for Western Energy (ROWE) and operated by the California Independent System Operator, which is poised to be the largest and most resource-diverse market in the region; and 2) Markets+, another day-ahead electricity market that will be run by the Southwest Power Pool.
New analysis from Aurora Energy Research and EDF compares these two options and finds that APS could save its residential customers nearly $110 million annually more than projected under their current market selection if they instead went with the larger market option. For APS customers, that’s about $50 per year in savings. Additionally, if all Arizona utilities joined the larger market, they would collectively save $114.9 million per year more than the alternative market. These results underscore the significance of this decision for the utilities and their consumers in Arizona.
Arizona stands at a pivotal moment for its energy future. Last August, state utilities experienced record-breaking peak demand driven by high temperatures exceeding 110 degrees across Phoenix and Tucson. It follows a trend of electric demand exceeding summer forecasts as heatwaves become more common due to climate change.
At the same time, growing industrial demand for power, primarily from data centers, is reshaping the state’s energy landscape. If all proposed data center facilities are built, APS and Salt River Project, the state’s two largest utilities, could face up to 17,000 MW and 12,000 MW respectively in new demand by 2038, more than doubling their current peak capacity. These and other pressures are leading to significant cost increases for Arizonans; for example, last year APS proposed a rate increase of nearly 15% for residential consumers, outpacing the national consumer price index of 6.7% for electricity services.
With over 11,000 MW of installed solar capacity and projections to exceed 14,000 MW over the next five years, the state ranks among the top five nationally for solar generation. This could position Arizona as a leading exporter of cheap, clean power, when it produces more than it can use. Efficient regional structures that integrate and dispatch energy across state lines can generate new revenue while displacing more expensive power when needed.
Arizona needs solutions that can drive more efficient use of energy resources to limit cost increases wherever possible and ensure reliable electric service despite more strain on the grid. Expanding the use of markets to facilitate more trading between Arizona and its neighboring states is one such solution, and Arizona utilities are actively pursuing joining new markets to share energy resources and balance load growth. However, the choice of market matters in terms of the scope and scale of benefits both utilities and their customers can garner from trading efficiencies.
Utilities can already buy and sell power with each other via bilateral trading agreements, but markets create opportunities to optimize trading between many participants across a wider geography. In short, this benefits Arizonans by allowing their utilities to buy the cheapest power available and to sell their excess power to more customers when it’s not needed in Arizona. A wider market geography also means access to more diverse sources of power when Arizona needs its most, reducing the risk of reliability problems like brownouts at moments of grid stress.
Arizona’s utilities have already seen the benefits of regional markets through the Western Energy-Imbalance Market (WEIM), a voluntary real-time market launched in 2014 that lets utilities buy and sell power to manage near-immediate imbalances in supply and demand. By pooling their resources, WEIM participants access the cheapest energy available, which is a critical capability when localized shortages occur, like during heat waves when demand spikes. The 20 participating utilities have generated an estimated $7.82 billion in benefits, including about $128 million in savings for APS, TEP, and SRP in 2024 alone.
However, a real-time market like WEIM can only do so much — adding a day-ahead market, where utilities buy and sell power to serve forecasted needs a day in advance, would deliver even greater reliability and cost savings.
Since 2021, the California Independent System Operator (CAISO), which runs WEIM, has been in the process of establishing the Extended Day-Ahead Market (EDAM) to provide a day-ahead service that would benefit the West. While many utilities, including those estimated to serve nearly 50% of load in the region, have already signed onto join EDAM, several others have been reluctant to join or have actively pursued participation in an alternative market. Among those seeking an alternative include Arizona’s APS, TEP and SRP.
One main concern with EDAM has been market governance — until just a few months ago, EDAM could not be governed by an independent entity per California law. To overcome that impasse, a group of utility regulators from several Western states, including Arizona, launched the Pathways Initiative in 2023 aimed at creating a market structure that would be independent of CAISO and represent the interests of the entire region. That effort marked a major success with the adoption of AB 825 in California last September, paving the path the for creation of an independent Regional Organization for Western Energy (ROWE) — one governed by a body representing Western state interests — that will have exclusive authority over both the WEIM and EDAM, as well as future market offerings that could improve the cost and reliability of electricity throughout the West.
Over the past several years, another competing day-ahead market by the Southwest Power Pool (SPP) — called Markets+ — has taken shape. While significantly smaller and less connected than the EDAM market footprint, several Western utilities have already committed to joining including APS, TEP, and SRP.
Both EDAM and Markets+ aim to deliver cheaper, more reliable electricity, but the choice between them will shape how Arizona utilities interact with neighboring states, manage growing demand, and maintain grid reliability. For a power market, the size and footprint matter. As utilities commit to one market or the other, the benefits of regional coordination — and the risks of fragmentation — become increasingly clear.
To evaluate the potential impacts for ratepayers in Arizona of utilities’ market choices, Aurora Energy Research evaluated the impacts of APS, TEP, and SRP’s participation in two different regional market options, both of which offer day-ahead market services beginning in 2026-2027:
There are currently 38 balancing authorities in the West, which are the organizations in charge of managing electricity supply and demand across a geographic area, handling the dispatch of power resources to ensure the lights stay on. Currently, ten balancing authorities, have either committed or publicly signaled their intent to join EDAM — we estimate this represents 45%-50% of total electricity demand across the West.
By comparison, eight balancing authorities, which we estimate to make up about 25%- 30% of total demand in the West — and, important to this analysis, includes APS, TEP and SRP — have signaled their intention to join Markets+. Other balancing authorities in the region have not yet decided and are most likely waiting to see which market structure will yield the most benefits at the lowest cost, while a few others have opted to join SPP’s RTO West, a market option offering full RTO services. It is worth noting that the percentages cited above are for committed entities; the map below includes those balancing authorities and accounts for others that Aurora Energy Research determined likely to join one market or another.
Understanding market participants is critical because a larger marketplace, with more diverse energy resource offerings, will yield greater benefits to participants.
To evaluate outcomes associated with participation in these two different market options, Aurora Energy Research used a production cost model to compare the revenues and costs associated with production and delivery of electricity for Arizona utilities.
The full APS Report from Aurora Energy Research provides significant additional information regarding this analysis, including primary drivers of these costs savings.
Our analysis suggests that the larger, more resource-diverse day-ahead market offered under EDAM stands to benefit Arizonans more than available alternatives. Precisely what next steps should be taken in Arizona’s path to market participation will be determined by the utilities and state regulators.
However, the choice of market will have consequences on electricity rates, reliability and emissions for decades to come. At the very least, this analysis warrants additional consideration — and perhaps further modeling — of market choice to ensure which one is ultimately accepted by Arizona utilities is in the best interests of Arizonans.
