The US’ western energy markets are undergoing a major transformation. On May 1, 2026, the California Independent System Operator (CAISO) and PacifiCorp switched on the extended day-ahead market (EDAM), the biggest expansion of centralised electricity trading in the US Western Interconnection in a decade. For the first time, a day-ahead, security-constrained economic dispatch (SCED) will co-optimise generation and transmission across balancing authority areas (BAAs) that stretch from California to Wyoming. It builds on the real-time Western Energy Imbalance Market (WEIM), which has generated cumulative benefits of USD8.6 billion since its launch in 2014 across a region representing approximately 80 per cent of western electricity demand. A rival design is coming as Southwest Power Pool’s (SPP) Markets+ targets an October 2027 go-live with a coalition of utilities across the Desert Southwest, Pacific Northwest and Rocky Mountain states.
Having two competing, voluntary day-ahead markets (DAMs) at almost the same time is reshaping how electricity moves through a region historically dominated by bilateral, contract-path trading across more than 30 balancing authorities (BAs). It is also exposing a structural problem that regulators are increasingly concerned about. As centralised markets multiply without bringing transmission systems under single control, new seams – boundaries that pose reliability, congestion and pricing challenges – are forming faster than the coordination agreements needed to manage them, as explained by a November 2025 Federal Energy Regulatory Commission (FERC) staff whitepaper.
EDAM: Products, governance, market participants and early results
The launch of EDAM was accompanied by day-ahead market enhancements (DAME), which improve day-ahead scheduling, dispatch and price formation while better managing uncertainty from growing renewable generation. DAME introduced four new hourly-procured and settled day-ahead products: Imbalance Reserve (IR) Up and Down, and Reliability Capacity (RC) Up and Down. IR manages uncertainty between the DAM and the real-time market (RTM) by incorporating expected net-load variability directly into day-ahead scheduling. This replaces the previous reliance on the Residual Unit Commitment (RUC) process to address forecast deviations. Resources awarded IR must offer the reserved capacity into the RTM and are compensated for the opportunity cost of withholding energy. RC addresses differences between cleared day-ahead supply and updated load forecasts, strengthening the RUC process by ensuring sufficient capacity is available within the day-ahead timeframe. Resource adequacy (RA) capacity is required to bid into RC-Up, while still remaining eligible for RUC compensation under the new DAME framework. There is no equivalent mandatory requirement for RC-Down.
For battery energy storage systems, DAME replaced the prior state-of-charge (SOC) constraints with a new “envelope” approach, which accounts for energy and ancillary service awards together, while the RTM continues to enforce the legacy SOC constraint.
Governance and eligibility were also redesigned around a day-ahead resource sufficiency evaluation (RSE), a pre-clearance test ensuring each participating BAA has enough resources before its schedules are accepted. In the market’s first weeks, all three live BAAs – CAISO, and PacifiCorp’s east and west areas – passed every RSE test administered between May 10-25, 2026, indicating that the core reliability safeguards were working as designed even during early market adjustments.
PacifiCorp became the first and only external participant to join EDAM at its launch on May 1, 2026, through its two BAAs: PacifiCorp West (PACW), serving northern California, Oregon and Washington, and PacifiCorp East (PACE), serving Utah, Wyoming and Idaho. Together, these systems form the largest privately owned transmission network in the Western Interconnection. PACW is typically a net importer of electricity, while PACE has historically been a net exporter due to its large thermal generation fleet. Portland General Electric (PGE) is the next utility scheduled to join, with market activation planned for October 2026. Several more entities are set to join in 2027: the Balancing Authority of Northern California (BANC), the Los Angeles Department of Water and Power (LADWP), the Public Service Company of New Mexico (PNM), and the Turlock Irrigation District (TID). Imperial Irrigation District, NV Energy and PowerWatch are expected to join in 2028. Meanwhile, Idaho Power has also expressed its intention to participate, but has not yet signed an agreement.
Figure 1: Map of market participants of WEIM and EDAM
Note: *These entities have publicly indicated a leaning towards EDAM as their preferred day-ahead market. Map boundaries are approximate and for illustrative purposes only. Map as of April 2026
Source: CAISO
EDAM’s performance in the first weeks
According to CAISO’s first Western Energy Markets Observations report, released on June 1, 2026, market performance remained mixed during the first month of EDAM operations. CAISO continued refining market processes, with day-ahead run times ranging from about 100 minutes to over five hours, and several days missing the 1 pm publication target due to validation and market processing steps. Power flows between CAISO and PacifiCorp were bidirectional, rather than consistently flowing in one direction, indicating the market was identifying economic opportunities across regions instead of supporting one-way arbitrage.
IR Up prices initially spiked in PACW (including parts of Oregon) but declined by mid-May, while prices in CAISO and PACE (Utah, Idaho and Wyoming) remained relatively low and converged, reflecting improving market integration. Day-ahead and real-time price convergence also improved in the PacifiCorp regions, although CAISO noted it was still too early to identify long-term trends. Meanwhile, CAISO day-ahead energy prices remained within normal seasonal levels, and virtual trading activity showed little change from pre-EDAM patterns, suggesting the new market had not significantly altered trading behaviour.
Like most new electricity markets, EDAM experienced several technical issues during its May 2026 launch. To support market stabilisation, CAISO temporarily extended (for 180 days) the price-correction window from 3 to 10 business days for the DAM and from 5 to 10 business days for the RTM. Reported issues included incorrect shadow prices, intertie transfer capability (ITC) constraint errors, greenhouse gas pricing defects, and Open Access Same-time Information System (OASIS) reporting errors. CAISO stated that these problems were limited to specific intervals and did not materially affect overall market outcomes after corrections.
The early issues, many involving intertie constraints and price formation across BAAs, highlight the complexity of coordinating markets across multiple transmission systems. CAISO has committed to publishing monthly EDAM performance reports and reviewing results with stakeholders as the market matures.
Table 1: Comparison of key features of EDAM and Markets+
Sources: CAISO; SPP; Global Transmission Report
SPP’s Market+: Key features and comparison with EDAM
Since 2021, SPP has expanded its footprint westward through the Western Energy Imbalance Service (WEIS), a real-time balancing market broadly comparable to CAISO’s WEIM. SPP is now extending its market offering through Markets+, which, like EDAM, will introduce a centralised DAM while also providing integrated real-time balancing services.
Markets+ received FERC approval of its tariff in January 2025 and entered Phase Two implementation in June 2025 after SPP secured USD150 million in financing. Unlike EDAM, which extends an existing CAISO market platform, Markets+ is being built as a new day-ahead and real-time market with its own resource sufficiency, flexibility reserve and settlement structures, intended as a competitive alternative to CAISO’s EDAM. As of late October 2025, 11 entities had signed Phase Two funding agreements – Arizona Public Service (APS), Bonneville Power Administration (BPA), Chelan County PUD, Grant County PUD, Powerex, Public Service Company of Colorado (PSCo), Puget Sound Energy, Salt River Project, Tacoma Power, Tri-State Generation & Transmission and Tucson Electric Power – while roughly 40 organisations, including clean-energy advocates, public power groups and Canadian marketer Powerex, hold seats in Markets+ Phase Two governance. Registration deadlines are already shaping the future market footprint. SP asked BAs to confirm participation by September 2025, transmission service providers by October 2025, and market participants by April 2026 to be included in the planned October 2027 market launch.
SPP is also pursuing a parallel strategy: a full expansion of its RTO into the Western Interconnection, known as RTO Expansion (RTOE) or SPP RTO West. FERC approved the plan in March 2025, and it took effect on April 1, 2026, making SPP the first organisation to operate an RTO across both the Eastern and Western Interconnections. The expansion was led by nine founding members and ultimately brought more than 20 entities under SPP’s Integrated Marketplace, transmission planning and reliability coordination services – a broader set of services than WEIS or Markets+ offer alone. The WEIS programme itself was discontinued as part of the RTO West launch, as most of its participants moved into RTO’s Integrated Marketplace. Markets+ remains under development and is intended to provide a standalone DAM and RTM for Western utilities that chose not to join the SPP RTO.
The result is a western electricity market in transition. CAISO’s WEIM and EDAM, SPP’s expanding RTO West, and the forthcoming Markets+ are together reshaping market participation across the Western Interconnection. These platforms are not separated by geography alone; several utilities participate in, or maintain operational interfaces with, more than one market, making coordination between them an increasingly important issue.
Figure 2: Map of organised electricity markets in western US
Source: FERC’s 2025 State of the Markets
While both markets aim to improve electricity market coordination in the Western Interconnection, they differ significantly in their governance and market design. Both EDAM and Markets+ are regional day-ahead market initiatives, but they differ in their governance and design. EDAM extends CAISO’s existing market to participating BAs and is governed through CAISO’s governance framework. In contrast, Markets+ is a stand-alone market developed by SPP, allowing BAs to remain independent while accessing centralised DAM and RTM services under SPP’s governance. A key difference is their cost recovery approach. EDAM includes an access charge approved by FERC via tariff revisions to recover transmission costs for each participating BAA based on inputs from its transmission service providers. Market+ does not adopt the same access charge model, instead focusing on delivering overall economic benefits and net savings for participants. The CAISO’s EDAM has the first-mover advantage with its May 2026 launch, while Markets+ remains in Phase Two implementation.
EDAM’s own governance is also changing. In September 2025, California passed a law (AB 825) that lets CAISO hand decision-making over the WEIM and EDAM rulebook to a new, independent body: the Regional Organization for Western Energy (ROWE). ROWE was formally incorporated in early 2026 and, from January 2028 at the earliest, could take over primary authority from the CAISO-linked governing body that runs the markets today. The aim is to give Western states and utilities more direct control over market rules, without CAISO holding the final say. This marks a real point of contrast with Markets+, which has been governed by SPP and a participant committee from the outset, rather than moving toward independent governance over time.
Nonetheless, both markets face a common structural challenge: transmission availability across most of the West is still governed by contract-path constructs rather than the flow-based modelling used in the East. That reliance, combined with inconsistent methodologies, may complicate efforts to maintain reliability, manage congestion and fully realise the economic efficiencies EDAM and Markets+ are each designed to unlock.
Figure 3: Comparison of the timeline of CAISO EDAM and SPP Markets+ evolution
Source: Global Transmission Report
Western market seams coordination
The western grid’s fragmented landscape is set to witness major changes as EDAM and Market+ pull dozens of BAs into two overlapping, separately governed day-ahead platforms. The November 2025 FERC staff whitepaper on “Seams Coordination in the Western Interconnection” described the resulting boundary between the two markets as creating reliability, operational and market efficiency “seams”. In the East, seams between RTOs such as PJM and Midcontinent Independent System Operator (MISO) were resolved over two decades through joint operating agreements (JOAs) and market-to-market coordination, built on the premise that regional transmission organisations (RTOs) operate as single BAs with functional control over members’ transmission systems. That premise does not hold in the West: neither EDAM nor Markets+ participants transfer functional control of their systems to the market operator, and BAAs remain distinct, with some large federal entities staying outside any centralised market altogether. The whitepaper concludes that seam agreements in the West are likely to involve more parties than their Eastern counterparts, requiring coordination across multiple tariffs, operating protocols and balancing authorities rather than relying on a single governing agreement.
These seam problems arise from several interrelated factors, including overlapping transmission ownership and scheduling rights, inconsistencies in transmission modelling, and congestion caused by loop flows. If left unaddressed, these can limit the full economic and reliability benefits anticipated from initiatives such as EDAM, WEIM and Markets+ and create both operational and reliability challenges.
The whitepaper identifies three priority areas for coordination. The first is transmission modelling – moving from the contract-path methodology still used across much of the West to the flow-based, or flowgate, an approach used in the Eastern RTOs and increasingly being adopted by some Western utilities, including APS. Second, reliability and congestion coordination, particularly around loop-flow management, since schedules cleared in one market can produce unintended flows over facilities outside its footprint. Third, coordinating electricity transfers for cost savings, ranging from simple intertie bidding rules to fuller interchange optimisation in which market operators incorporate the neighbouring shadow prices and constraint data directly into their own security-constrained dispatch. None of these is a quick fix. FERC notes that Eastern approaches cannot simply be replicated in the West. Instead, effective seams agreements will require continued coordination among CAISO, SPP, the two reliability coordinators, and numerous BAs.
Notably, two seams coordination efforts are already underway. First, Reliability Coordinator West (RC West) and SPP RC, the West’s two reliability coordinators, have advanced a North American Energy Standards Board (NAESB) proposal to expand the enhanced curtailment calculator (ECC), the tool used since the 1990s to manage unscheduled flows, with explicit treatment of system operating limits and interconnection reliability operating limits. A 2024 task force white paper found the ECC covers only five paths and cannot address flows affecting broader SOLs, leading BAs to resolve such issues with inconsistent, individual methods. The proposed enhancement would standardise a flow-based methodology for assigning curtailment and relief obligations. The proposal has cleared the NAESB Wholesale Electric Quadrant Committee and now awaits the NAESB Executive Committee before it can be filed at FERC for incorporation into federal regulation.
Second, SPP’s Markets+ Seams Working Group (MSWG), which includes CAISO, affiliated BAs and public interest organisations, has produced a Seams Strategy and Roadmap, approved in April 2025 and updated with a milestone timeline in October 2025, covering cross-market scheduling, outage and model coordination, interchange and dynamic transfer treatment, and minimum data-exchange transparency.
The way forward
The growth of regional DAMs marks a turning point for the Western Interconnection. Both EDAM and Markets+ are expected to help integrate more renewable and low-carbon energy, lower system costs through more efficient dispatch, strengthen regional coordination, and improve grid reliability as centralised market operations expand.
Even though the two markets share these goals, they are developing along separate, overlapping paths. As participation grows, the interface between EDAM and Markets+ could become a source of operational complexity – creating challenges for transmission coordination, congestion management, price formation and reliability across market boundaries.
Capturing the full benefits of regional market integration will require close coordination between the two market operators. Priorities include building robust flow-based transmission models, improving real-time congestion management and reliability coordination, and getting the most value from transactions that cross market seams. With most remaining western BAs expected to align with either EDAM or Markets+ in the coming years, how well this coordination works will determine whether the Western Interconnection becomes a more integrated, efficient and reliable electricity market.