Grid Status

Clash of the day-ahead markets has dominated conversations in the Western Interconnection, but first to the finish line is neither EDAM nor Markets+, but the Southwest Power Pool's fulsome western expansion. The Western power grid is changing fast, starting with SPP expanding its RTO West in April 2026. This initial expansion will start small, with two WAPA regions, but it represents the first market in North America to cross the interconnection barrier. Managing this expansion across DC ties with limited capacity relies on the addition of a second reference bus and careful coordination to manage flows and reserve requirements across two balancing authorities. Not everyone in the West is jumping wholesale into markets. In one case, independence will create interesting dynamics for index pricing, as Douglas PUD, part of the Mid-C triad, is uncommitted while Grant and Chelan are joining Markets+. How will this impact Mid-C moving forward? To the north, Powerex, the power marketing arm of BC Hydro is joining Markets+. To BC’s East, Alberta is reforming its market, enhancing day-ahead processes, implementing nodal pricing, altering price caps, and more. Dynamic market activity in the West takes place against a backdrop of a beautiful yet capricious natural environment. From wildfires to winter storms, the Western Interconnection faces significant challenges across its intensely varied regions. For all of this and more, check out our new blog wrapping up (link in comments) our two-part series on changes and challenges to markets in the West.

We're not trying to trick you, but if you factor Halloween into your decision-making, you might be in for quite a treat. Like any event that changes daily routines, Halloween impacts load curves across the country. This typically manifests in weaker load over the evening, exactly when goblins and ghouls are out going from door to door. Over the past 9 years, real-time load has underperformed almost all of PJM’s forecasts over the evening peak, precisely during prime trick-or-treating hours. While load forecasting is a complex, data-intensive process, there is a magnitude of human touch and behavioral analysis that needs to be factored into forecasting, particularly on holidays and cultural events. Be sure to watch our live pages to see if RTOs and ISOs have exorcized the forecast ghosts of Halloween past this year!

ISO New England Inc. just became the first multi-state ISO to phase out coal, nearly two and a half years ahead of schedule. Merrimack, New England’s last coal-fired power plant, retired in September, well ahead of its scheduled 2028 deactivation, marking the end of coal generation in the region. After a steady decline over the past decade, ISO-NE joins neighboring NYISO, as well as IESO, one step further, in having retired its coal. While seen as an important milestone in New England’s decarbonization, Merrimack’s retirement comes at a time when ISO-NE is under increasing supply pressure. Offshore wind, one of the region’s few local resources, has been slow to scale and is under active attack from the federal government. ISO-NE has collectively benefited from state-level policy that led to the widespread installation of behind-the-meter solar, cutting deeply into summer demand. Winter, however, is another story. Gas supply constraints plague the region, which relies on plants with onsite storage, such as oil, coal, and the recently retired LNG-fueled Mystic, when the grid is most stressed. Apart from internal generation, imports from Hydro Québec have declined in recent years, even as a new HVDC tie line is nearing completion. A further drop in flows from HQ may put additional pressure on the region’s ties with New Brunswick, which still has coal in its generation fleet. As older thermal units continue to be replaced, oftentimes by intermittent renewables, having access to real-time information across markets is increasingly important. Track net load price spikes across the country and keep an eye on our ISO-NE live page this winter to see how the region adapts to operations without coal.

As the PJM Interconnection prepares its 2026 load outlook, individual utility forecasts indicate a rapidly shifting landscape, with smaller zones anticipating a surge in demand. The balancing question in play is whether large zones can continue to scale larger, or if small areas have the headroom to steal momentum in the datacenter race. In Ohio, Dayton anticipates an increase from its existing 35 MW of large load to over 6,335 MW in just 6 years, a ~18,000% jump. PPL reports more than 15 GW of large loads by 2035 in comparison to 248 MW today, almost 5 GW more than COMED, a zone that today serves 2-3x the total demand. While the RTO is bound to continue seeing load growth, these forecasts warrant skepticism, particularly when compared to other zones within PJM. AEP has revised its 2030 forecast down significantly, from 17,890 MW last year to 9,296 MW this year. AEP-Ohio alone accounts for over 5 GW of this reduction, largely driven by tariff changes requiring large loads to prepay for a portion of expected usage. Dominion, home to the world’s largest existing data center market, continues to lead the way with large load demand rising from ~7,200 MW today to ~24,000 MW in 2035. While large, this is a far more gradual increase compared to DAY or PPL, whose forecasts have ballooned in just the last year. At an RTO level, large load forecasts from all LSE/LDC presentations in September anticipate nearly 85 GW of growth over the next decade, approaching 100 GW in total by 2035. This rapid expansion will strain an already tense environment. PJM’s market monitor estimates that consumers are on the hook for billions in higher capacity prices due to forecasted data center load growth alone, and bullish load forecasts without firm capacity will likely send these estimates even higher in next year’s uncapped auction. Large loads are already reshaping operations and driving congestion across markets. Track demand growth and outcomes on our dedicated PJM page.

A little teaser of our next product release: Grid Status Insights. Insights is a real-time feed of expert commentary on energy markets and the electric grid — straight from our team of talented analysts. If you’ve enjoyed our blogs or social posts, you’re going to love this. Stay tuned.

It’s duck hunting season as California’s summer fades away and demand from batteries takes firm grasp of CAISO’s daily demand curves. Falling temperatures have reduced peak load, but they aren’t the only factors shaping demand. The California ISO's nation-leading battery fleet peaks its charging in the late morning or early afternoon as solar floods the state's grid. Battery charging flattens out load, smoothing midday operations. This was clear on September 25th: load with charging rose only ~1.2 GW from noon to the evening peak. Without accounting for storage, load would have declined by several GW then risen more to meet the evening peak, adding strain to dispatchable units and likely altering net interchange. As CAISO fully enters shoulder season, renewables and storage are expected to take an increasing share of the state’s fuel mix. Track mix and pricing impacts with our dedicated CAISO live page!

Net load volatility is on the rise as the Southwest Power Pool enters shoulder season. In decades past, the fall shoulder season left time for autumn extracurriculars like apple picking and the pumpkin patch. Today, new key metrics like net load drive outcomes, and they can be at their most volatile when outages rise and weather varies. On September 16th, SPP experienced high net load as the wind died off midday, leaving dispatchable generation to pick up 24 GW of additional demand from morning trough to afternoon peak. Further tightening the stack, an additional 3.8 GW of generation went on outage that morning. High sustained real time prices were seen during the midday as the on-peak North Hub DART spread settled at a significant -$111/MWh. Ten days prior, September 6th demonstrated that high net load doesn’t have to drive grid stress. On this day, net load comprised 95% of peak load compared to 79% on the 16th, but the ramp was much gentler. From morning to evening, net load only increased by 7 GW, a much shallower curve. Additionally, outages were 4.7 GW lower, and temperatures milder, contributing to an on-peak DART spread of -$5.56/MWh at the North Hub. Track the tricks and treats of outage season with Grid Status.

Recently released data from ERCOT shows just how much cryptominers can complicate grid forecasting. ERCOT load-watchers will know that many days this summer have had a strikingly flat peak load curve, driven by curtailment to avoid 4CP intervals. Less clear was just how much of the resulting forecast gap could be driven by extremely flexible crypto demand. It turns out the answer is a lot. While we can only estimate the specific breakdown given the many factors that make up load forecast error, the fact that crypto curtailment can account for the entirety of the error on certain days is clear evidence of their impact on the grid. This insight is derived from nearly 7 months of real-time cryptominer demand data, published by ERCOT. There’s more to be said about this report’s implications for long-term trends, but it’s useful in the here and now to understand how these facilities can already suppress grid-wide peak demand on hot summer days.

⚡Did you know that in NYISO, lightning can cause $1000 price spikes?⚡ The grid is no stranger to the chaotic threats of nature. From rodents to vegetation, managing the largest machine on earth is a never-ending battle. One of the clearest examples of weather’s impact on pricing is in NYISO, where lightning alone can trigger thousand-dollar price swings. Thunderstorm Alerts (TSAs) were established by ConEd after cascading, lightning-related outages contributed to the 1977 New York City blackout, and remain a tool designed to boost generation in New York City and on Long Island ahead of storm driven transmission restrictions. We break down the history behind TSAs in our new blog, explaining how the mechanism and NYISO have changed over time, why aging plants and stalled new builds keep pressure on the downstate region, and when and where to track storms to gauge TSA risk. https://lnkd.in/eJvBkDDC When you’re done reading the blog, check out our nodal price map for a new precipitation radar layer. We’re exploring the best ways to integrate weather data, so let us know what you think, and what you want to see next.