The West Coast energy market is quietly restructuring. SPP’s RTOE went live April 1, 2026, CAISO’s EDAM goes live May 1, 2026, and Markets+ will be next to follow. These three markets are vying for control of the energy that powers Phoenix, Las Vegas, and Portland, marking the largest structural change to western wholesale power in decades. While most discussions are centered around market structure, the more interesting story is how this will impact utilities’ software stack.
For decades, the Western Interconnection has been the outlier in the US wholesale power market (where bulk energy prices are set). Much of the US has legally split vertically integrated utilities into parties who handle generation and those who handle transmission and distribution to customers. In these de-regulated markets, prices are set through a day-ahead double-blind auction run by market operators. Outside of California, the West operates without an organized day-ahead energy market (see Figure 1), instead relying on independent utility operations and CAISO’s 2014 installation of the Western Energy Imbalance Market (WEIM) which operates on five and fifteen-minute-dispatch across the Northwest and Southwest. This system is being replaced in real-time and will reshape the software demand of every utility in the region.
Figure 1: Regulated and deregulated energy markets across the US
Western utilities have three options outside of the status quo. Announced first was CAISO’s Extended-Day-Ahead-Market (EDAM), launching May 1, 2026, with PacifiCorp as the anchor participant and PGE expected to follow. EDAM is a natural progression extending day-ahead scheduling and unit commitment to WEIM participants without requiring full CAISO membership. SPP followed by announcing a similar option: Markets+, launching October 2027, with notable commitments from Arizona Public Service, Salt River Project, and more. Notably, EDAM and Markets+ extend day-ahead auctions into an area that is still legally a regulated market – a completely new structure with new challenges. The third option mirrors more directly the current deregulated markets in the East offering full regional transmission operator (RTO) membership via SPP’s RTO expansion (RTOE). The market went live April 1, 2026, and currently includes nine load serving entities making SPP the first RTO to span both the Eastern and Western Interconnection.
The differences between these market options and the current real-time-only model are where the software story lives (see Figure 2).
Figure 2: Western energy market restructuring software implications
Network Model Management and the Planning Burden
The most overlooked consequence of the Western market evolution is where planning authority lies. In current day-ahead, deregulated, markets (see Figure 1), the respective market operator (RTO/ISO) manages the responsibility of transmission planning and unit commitment on behalf of the utilities. In the EDAM and Markets+ structures, no RTO assumes governing authority over participants leaving utilities to act as their own balancing authorities and retain responsibility for planning. In this new market structure, both utilities and market operators will run independent network models, yet both will have to interface with each other increasing the complexity and criticality of communications / interoperability.
Utilities will be expected to export market-grade network topology, transmission constraints, and outage data in a format CAISO or SPP systems can digest – a task few are ready to meet. This new responsibility will mean large-scale integrations if not the removal of legacy systems with new software products. PacifiCorp, a Portland based utility, has publicly emphasized the importance of early vendor engagement as market rules evolve in preparation for this lift. CAISO leadership has also acknowledged the magnitude of system integration required across utilities participating in their EDAM market.
This lift is centered around the need for utilities and transmission operators to run network models independently while maintaining compatibility with each other – a problem vendors have not caught up with. The energy management systems (EMS) and network model management (NMM) products offered by GE Vernova, OSI (AspenTech), Hitachi Energy, and Siemens were built for a world where either the utility or the market operator individually handled dispatch. Every utility joining EDAM or Markets+ becomes a forced buyer of upgraded or rebuilt EMS and NMM, choosing from a vendor landscape where market leadership is still undetermined. The vendors who prove scaled success first will capture share quickly, with utilities adopting those solutions as table stakes for market participation.
Forecasting and the LMP Problem
The second software implication follows from the first. Once utilities are participating in day-ahead markets, they need to be able to predict the day-ahead market for optimization of generation and competitive bidding. At increasing value, utilities need to be able to account for nuances in locational marginal pricing (LMP) which arise due to grid congestion and variance in supply/demand by location. WEIM participants have dealt with real-time LMP for a decade, but the move to day-ahead introduces a need for forward price formation most Western utilities have never faced.
This creates demand for a category of software that has been underdeveloped in the WEIM region: nodal forecasting, analytics, and portfolio optimization. Yes Energy (Montagu owned) has already tailored their product towards SPP’s RTOE, updating data pipelines ahead of the April go-live. The bet is that market participants entering a new nodal pricing environment will be willing to pay for the data infrastructure, analytics, and forecasting tools that MISO, PJM, and ERCOT (see Figure 1) traders have relied on for years. The return on this bet will be determined by Yes Energy’s ability to compete against proven tools like Energy Exemplar (Blackstone/Vista owned) as new customers (utilities) enter the market for advanced forecasting software.
Bid-to-Bill and the Incumbency Question
Utilities will have updated needs not just for predicting prices but also for bidding and settling power at these prices. This is an area where vendors are visibly competing today. PCI Energy Solutions is positioning themselves as the natural choice for EDAM, with roughly 70% of current WEIM participants already running its bid-to-bill platform (see Figure 2). But this signals incumbency, not defensibility.
Day-ahead markets will demand capabilities PCI’s real-time product does not automatically enable: forward unit commitment, shadow settlements, and multi-day portfolio strategies – though PCI does offer these capabilities in other products. Bid-to-bill and broader energy trading and risk management (ETRM) platforms with proven success in the East (e.g., ION Commodities) are now looking Westward with PCI’s clients in their sights. The volume of new workflow requirements introduced by day-ahead market participation will drive utilities to either adopt new modules from current vendors or look beyond existing relationships.
What this Means for Software CEOs and Investors
These implications on network models, forecasting tools, and payment platforms, are not independent. All three stem from the transition to day-ahead operations and the lack of institutional market operator support in EDAM and Markets+. The next 18 months will separate the software companies who anticipate this transition from those who react to it. For PE investors, the window to seize a leadership position is closing quickly. For corporate strategy teams, honest evaluation of whether existing products can absorb new workflow requirements fast enough to retain accounts is essential for strategic planning.
Three questions worth consideration:
- What paths are our customers taking and how will they interact with our products differently under each market structure?
- Are we capable of handling the intensity of day-ahead planning that will be passed along to utilities in EDAM and Markets+ structures?
- What product stack will be demanded by utilities participating in unbundled day-ahead markets, full RTO members, and those who hold onto real-time only operations?
The team at Red Chalk Group is ready to help you tackle these questions. Reach out to us to learn more about growth strategy, go-to-market planning, and more.
