Tapas Peshin is senior product manager at PCI Energy Solutions.
One month into California Independent System Operator's Extended Day-Ahead Market, the most striking result is that PacifiCorp's eastern and western systems are already behaving like two different power markets.
In May, day-ahead energy prices in PacifiCorp East averaged just $8.62/MWh, less than half PacifiCorp West's $18.97/MWh. PacifiCorp East cleared negative in 17% of all hours, while PacifiCorp West went negative only 2% of the time. Those differences reflect fundamentally different resource mixes, operating conditions and exposure to California's solar-driven price dynamics.
The sample size is small. But after 31 days of hourly clears, the market is already revealing how distinct western balancing authorities may behave inside a shared day-ahead framework.
One utility, two price regimes
PacifiCorp is split into an eastern footprint, anchored in Utah and Wyoming, and a western one centered on Oregon. PACE carries more than twice the load of PACW. Its day-ahead schedule averaged about 5,600 MW in May against PACW's roughly 2,200 MW, and peaked near 7,650 MW versus PACW's 2,830 MW. More important than the size difference is the resource difference, and it showed up directly in price signals.
Averaged across May, PACE's day-ahead energy price cleared at $8.62/MWh while PACW cleared at $18.97/MWh. But the monthly average buries the real story, which is in the hourly shape. PACE's daytime hours collapsed into a deep, solar-driven trough. Across the midday block its day-ahead energy price averaged below zero, and 17% of all PACE hours in the month cleared negative, bottoming at -$41.78/MWh. PACW, by contrast, went negative in just 2% of hours.
The reason lies in the generation mix of the two balancing authorities. On the PACE side, cleared day-ahead energy in May came roughly one-third from coal, with wind and solar together supplying about half. That combination of abundant midday solar stacked on top of must-run coal is precisely the recipe for a steep net-load trough and the negative prices that follow. PACW's stack is the opposite: gas and hydro each accounted for roughly a third of cleared energy, a far more dispatchable mix that holds prices up and keeps the daily curve shallow.
The price spread between the two systems also varied significantly throughout the month, highlighting how transmission constraints, weather patterns and changing generation conditions can quickly alter relative market value across the West.
The greenhouse gas price that vanishes at noon
One of EDAM's more consequential design elements is how it prices greenhouse gas. CAISO applies a marginal GHG component to the locational price in its carbon-regulated footprint, reflecting the shadow cost of serving California-regulated load rather than a non-regulated area. With only PacifiCorp participating so far, the early behavior of that component is instructive.
Across May, CAISO's day-ahead GHG component averaged about $2.28/MWh but that figure is concentrated almost entirely in the overnight and shoulder hours. During the midday solar window, the GHG component sat at essentially zero: across the late-morning-to-afternoon block it averaged $0.14/MWh, and 96% of those midday hours cleared at exactly $0. The logic is straightforward. When California is awash in its own midday solar and net-exporting, there is no premium to serve regulated load from outside, so the component falls away. It reappears overnight and around sunrise, when the regulated area leans on imports and the cost of carbon compliance re-enters the price.
A useful reminder buried in this mechanism: the carbon-regulated area is not synonymous with CAISO. Valley Electric Association, a Nevada entity inside CAISO, is not subject to California's greenhouse-gas regulation and its May day-ahead price averaged about $10.70/MWh against $19.22/MWh at PG&E's hub, a gap consistent with sitting outside the carbon obligation. As demand and import reliance both climb this summer, the hours when that GHG component is not zero will be the ones to watch.
New products, and a launch without a scare
EDAM did not arrive alone. Day-Ahead Market Enhancements went live the same day, introducing Imbalance Reserve and Reliability Capacity as distinct day-ahead products on top of energy and ancillary services. Imbalance Reserve is procured in the integrated forward market to bridge day-ahead-to-real-time uncertainty; Reliability Capacity is committed afterward, in residual unit commitment, to backstop physical supply. Both come in upward and downward variants, and notably both are priced closer to locational energy than to traditional system-wide reserves.
What did not happen in May may matter as much as what did. Across the entire month, cleared supply shortfalls were nearly nonexistent. A handful of hours showed any shortfall in the new reserve and reliability products, and no area saw a sustained physical supply problem. For a market launch layering two new product types onto a brand-new day-ahead market, a quiet first month is exactly the outcome operators would have hoped for.
That said, PACW offered a preview of where the rough edges will be. As the smaller area with barely 2.8 GW at peak and a limited internal generation stack, its day-ahead clears were the spikiest on several early May days, with intraday price swings far larger than PACW's hydro-heavy fundamentals would suggest. When a bid stack is thin and a market is still finding its footing, it does not take much to produce a volatile clear. That fragility will ease as more participants join and liquidity deepens, but it is a useful marker of where a small balancing area is most exposed in its first weeks inside a larger market.
The next mile
PacifiCorp will not be alone for long. Portland General Electric is scheduled to join later this year, with a gas-and-hydro stack that should deepen Pacific Northwest liquidity, and 2027 brings a wider expansion. Balancing authorities inside California as well as the Public Service Co. of New Mexico in the Desert Southwest will be joining EDAM. Each new entrant changes the flows, the bid stack and the GHG calculus.
The first month does not answer the larger questions surrounding EDAM's long-term evolution, including congestion allocation, GHG treatment and competition with other regional market designs. But it does provide an early glimpse of what the market is likely to reveal: not a single western price signal, but the differences that already exist between western power systems.
If May established anything, it is that EDAM's first contribution may be transparency. By placing diverse balancing authorities inside a common day-ahead framework, the market is beginning to expose where resource mixes, operating constraints and carbon policies create fundamentally different economic outcomes. As more participants join over the next two years, those differences may become the most important story of all.
