Beware of Ducks

Energy Markets Update

Editors Note: 

As Halloween approaches, it’s a good time to look beyond the scares and prepare for the heating season. Our winter outlook provides perspective on current fundamentals and potential market impacts. It’s never too early to prepare - now is the time to review winter plans with operators and assess both near- and longer-term energy exposure.

This issue also highlights the growing prominence of the ‘Duck Curve” in North American markets, the phenomenon by which solar depresses daytime prices and boosts late afternoon prices. We examine the growing role of batteries in managing peak demand and supporting grid flexibility across the duck curve, as well as how Veolia is helping customers capture these opportunities through its Flexible Energy Solutions Group (aka Flex). We also explore the continually evolving structure of the PJM market and what it means for energy strategy.

Nothing too spooky here - just practical insights for the season ahead. Happy Halloween and beware of ducks!

Table of Contents

• Energy Market Update
• Winter Energy Outlook: Cushioned but Cautious
• The Evolution of the Duck
• BYOB: Encouraged at Parties, Rejected at FERC
• Summer Peaks: A Recap of Veolia's 2026 Peak Demand Notification Program

Weekly Natural Gas Inventories

Source: EIA, Veolia

 Energy Market Update 

• As we turn the corner towards winter, energy markets invariably become more volatile. This is the season when winter premiums are tested against pre-winter fundamentals, namely storage, recent spot price trends, and weather forecasts. We cover the fundamental side in detail in our Winter Energy Outlook.  

• Winter premiums have indeed been strong this year so we do expect gyrations in the coming weeks. NYMEX gas has been on a steady slide since Q1, with the 26/27 winter strip losing roughly 30% of its value since March 2026. This presents an excellent value to lock in certainty over the next year at a 20%+ discount to the trailing 12 month index rate.  

• Power prices have been more sticky. As we’ve covered in past updates, key drivers keeping pressure on power futures are both the actual and perceived tightening of the supply-demand balance, as well as the sting of last winter’s scarcity pricing felt throughout the Mid-Atlantic and Northeast.  

• On the power side, the forward winter strips are currently priced at the 81 percentile of the 2-year trading range for New England, 79 percentile in New York, and 97 percentile in PJM East. In other words, both winter and 2027 fixed rate premiums are well intact. 

• The chart below depicts how the 1 year forwards and upcoming winter forwards (Dec-Feb) compare to spot prices realized over the trailing 3 years for those same tenors. To accentuate, fixed 2027 power in PJM East will cost 2x what it averaged in the spot market over the past 3 years.  
  
  Source: ISOs, Argus, Veolia
• Spot prices have been moderately strong in 2026, relative to prior years, buoyed by stubborn NYMEX gas prices in the first half of the year and higher heat rates due to shrinking reserve margins. In some markets, we have seen heat rates improve through the summer, indicating potential alleviation of constraints and more efficient price formation. Take a look at Philadelphia and Boston as examples.
  Source: ISOs, Veolia
• It has not been all bearish news in spot markets though. Just last week in PJM, unusually warm weather, combined with a large cluster of power plants down for fall maintenance, pushed PJM into emergency mode on October 13 and 14. The lights stayed on but PJM said weeks like this are becoming normal because electricity demand from data centers is growing faster than new power plants and power lines are being built. If you hadn’t noticed, PJM has been increasingly expressing its concern over the pace of new generation additions.
• Texas has also been struggling to keep up with a rapidly changing grid. Despite rather typical temperatures for the season, hourly prices in the North Zone hit about $300/MWh on multiple days during the first week of October. The presentation of high prices is occurring more frequently in the late afternoon hours after solar generation drops off; the Duck is in Dallas–see our coverage of the Duck Curve below.
• Did we mention that ERCOT/Texas set an all-time peak electricity demand record of 91,134 MW (91.1 GW) on July 22, 2026 - approximately 5.6 GW above the previous record set in August 2023? Adding to that stat, the week ending August 22 also saw record average demand of 74.5 GW. The peaks were met primarily by natural gas (~48%) and solar (~32%), with battery storage supporting evening demand.
• In summary, markets in North America are looking increasingly regional. Describing the market in broad strokes, even within the respective RTOs, is becoming less useful. We need to examine evolving fundamentals at the regional level to make sense of it all. Stay tuned!

National Headlines You May Have Missed

• The Federal Energy Regulatory Commission (FERC) proposed a "blanket" authorization program for LNG plants, a first of its kind. The proposal is a notice of proposed rulemaking, allowing for LNG export terminals (and the smaller LNG "peak shaver" storage plants in the Northeast) to make upgrades, swap out equipment, boost capacity, and even build new liquefaction trains, tanks, and marine berths without requesting permission from FERC for a separate, case-by-case order each time. While this is a privilege Interstate gas pipelines have had since 1982, the usual suspects are already lining up against it, including nine blue-state attorneys general. If the proposal goes through, more gas gets out the door faster, and that's bullish for both LNG majors and the Marcellus & Utica E&Ps.

• Harvest diesel costs surge across the Farm Belt & California: Diesel prices peaked at $6.68/gal and $7.46/gal, respectively, last month, according to the EIA. Our analysts note a hidden inflationary pressure just as the fall harvest moves from the field through heavy-duty farm equipment (plows, dryers, and trucks) to reach market. Although the USDA’s September outlook forecasts "food at home" prices rising just 2.4% this year, fuel costs historically take about two months to reach the grocery aisle. With groceries carrying a larger CPI weight (8.2%) than energy (~7.3%), sustained diesel premiums threaten to turn food into the next major driver of headline inflation.  

• Millennium Pipeline launched an open season for its Ramapo Enhancement Project, targeting 60,000 Dth/day in added capacity to Algonquin Gas Transmission by November 2028. It could support Enbridge’s Project Beacon to increase New England deliveries, helping ease winter supply constraints and reduce price volatility where January forwards typically exceed $20/MMBtu.

• See our continued coverage of ERCOT-related solar and battery deployments, along with our 2026 Peak Load Season Roundups below. Spoiler alert: Our Analysts dispatched alerts correctly identifying all seven events across the Northeast and PJM again this year.

Winter Energy Outlook: Cushioned but Cautious

U.S. natural gas and power markets are entering the 2026 - 2027 winter heating season on relatively strong fundamental footing. However, emerging structural demand presents a wildcard. Below is our breakdown of the key drivers, emerging trends, price risks, and regional dynamics shaping the market this winter.

Supply Trends:

• Production: US dry natural gas production is on track to set an annual record, averaging 112.2. Bcf/d for the entire 2026 and 116.1 Bcf/d in 2027, driven by associated gas from Permian Basin, Haynesville and other Northeast shales. For winter 2026-27, NGSA expects production to average 112.5 Bcf/d, up ~2.5 bcf/d from last year and ~ 7 bcf/d above the three-winter average. 

Source: Natural Gas Supply Association (NGSA)

• Storage Baseline: Working gas inventories stood at 3.64 Tcf as of October 16 (-4% YOY and 1% above the 5-year average). EIA projects inventories to reach ~3.85 Tcf by the end of October, ~2% above the five-year average and near last summer’s end-of injections level. This marks the healthier pre-winter storage position, providing a solid cushion heading into the heating season. 

Source: Veolia, EIA

 Demand Drivers: 

• While on the demand side, structural needs are being outpaced by the supply wave. Residential, commercial, and industrial use is projected to remain steady in winter 2026-27 under normal weather conditions, with LNG exports and power sector demand, two primary drivers leading growth as indicated in the figure below. Natural gas demand is forecasted to grow by 1.6 Bcf/d year over year, below the 2.5 Bcf/d increase in production. This includes significant growth in LNG, power burns demand and reductions in C&I demand. 

Source: NGSA, Energy Ventures Analysis (EVA)

• LNG Export: LNG feed gas demand is expected to rise by 2.2 Bcf/d, as per NGSA’s 2026-27 winter outlook. With Corpus Christi Stage 3, Plaquemines, and Golden Pass ramping up, the U.S. is poised to be the world’s largest LNG exporter heading into 2027.
• Power Generation Burns: Natural gas remains central to U.S. power generation as data center demand surges. The NGSA projects U.S. data center capacity to more than double, from 44 GW in 2025 to over 93 GW by 2028, with gas meeting much of the incremental load. The EIA expects natural gas to maintain ~40% of U.S. electricity generation through 2026-2027.
  

Source: NGSA, EVA

Weather Outlook: Strong El Niño and its impact

• While fundamentals provide a clear baseline, weather remains the wildcard for winter pricing. NOAA's October outlook indicates a strong El Niño from December 2026 to February 2027, favoring warmer-than-average conditions across much of the West and Northern US, wetter conditions across parts of the South and East and a mild hurricane season. Warmer weather conditions could moderate heating demand, support storage levels and put downward price pressure.

 Source: NOAA 

• A strong El Niño could also disrupt renewable generation, lower solar output expected across South and West and variable wind and hydropower generation, increasing volatility into regional power-market. Drought-related Panama Canal restrictions could disrupt LNG shipping routes and increase transit times.

• Historically, strong El Niño winters (e.g., 2015-16 and 2023-24) have been bearish for natural gas prices, but weaker El Niño winters (e.g., 2018-19 and 2009-10) still had some blocking and turned out colder than expected. Recent winters have proven that even short-duration cold outbreaks (e.g. winter storms Fern, Heather, Elliott, etc.) can still trigger severe demand spikes, freeze-offs, and pipeline constraints. These events can drive exponential regional gas and power price increases. Unlike previous warmer winters, today’s higher LNG export demand leaves less flexibility: warm weather could accelerate storage builds, while extreme cold could quickly tighten the market. Hence, a strong El Niño could be a reason to lean mild, but not reason enough to eliminate cold-weather risks.

Price Outlook and Volatility

• Reflecting strong fundamentals and milder weather outlook, forward curves have retreated from post storm peaks. EIA's latest forecasts Henry Hub spot prices to average $3.16/MMBtu in 2027, down 9% from 2026. EIA forecasts natural gas spot price in Q1 2027 to be ~70% lower than in Q1 2026, as shown in the figure below:

Source: Veolia, EIA

• Mild weather may soften demand and keep gas prices range-bound in early winter, with increasing upside price risk in January and February if cold arrives. Production freeze-offs, LNG outages, pipeline constraints could amplify volatility, and spike regional basis. Power markets remain highly regional and depend heavily on local generation availability, congestion, transmission and capacity constraints, reserve margins, renewables ramps, load growth and gas deliverability - not just Henry Hub. Constrained Northeast markets and parts of PJM may remain exposed to sharp price spikes even if benchmark gas prices remain relatively low.

Overall, the U.S. enters winter with strong production and healthy storage levels, providing a cushion against sustained price increases. However, rising LNG exports and industrial demand leave less flexibility than previous winters. Extreme cold outbreaks, production disruptions, and regional infrastructure constraints could quickly tighten supply-demand balances and trigger exponential changes in price, even over fewer hours. For energy buyers, monitoring market fundamentals and regional price trends will be critical to manage energy costs. Veolia is here to help clients navigate market uncertainty, provide tailored energy-market guidance, and develop strategies to mitigate risks and manage energy costs.

The Evolution of the Duck

Every buyer and seller of solar power knows the duck curve, the pesky diurnal profile that appears when solar penetration rates reach a critical mass, causing daytime prices to plummet and performance of solar assets and contracts to suffer. First seen in California (CAISO) in the early 2010s, the shape is now appearing in other ISOs as solar fleets grow. Even as market prices are expected to rise, understanding how this profile evolves is key to knowing how solar vPPA monthly settlements will be affected. Below, we look at where the duck stands in key markets and what could reshape it next.

Source: Veolia

Where the Duck Stands Today

• The pattern: Solar’s capture rate (the percent of average market price a project realizes) falls as solar’s share of load rises. As the belly of the duck curve drops deeper and evening peak prices increase, solar’s realized market price declines in relation to the average market price. This is a prominent challenge for Virtual Power Purchase Agreements (vPPAs) as the performance of the contracts will suffer when a project is only able to capture moderate or low prices in the middle of the day, and miss out on higher market prices in the evening. This phenomenon has resulted in some projects performing poorly, despite being in markets with high average prices.  
  
  

Source - Lawrence Berkeley National Laboratory - 2025 Utility-Scale Solar Data Update
*SPP excluded from the chart due to small solar penetration rates (<1% in 2024)  

• CAISO, the bellwether: The shape was first acknowledged around 2012, when solar served just 1.2% of CAISO’s load. Signifying that this phenomenon can have an impact while solar is still developing in a market. Capture rates fell from 120% of average market prices in 2012 to 38% by 2024. This realization raised the question of how quickly solar’s value would deteriorate as it's built out in other markets. 
• ISONE, NYISO & ERCOT: Capture rates fell from ~120% to ~80% between 2012 and 2024. Texas (ie: ERCOT), in an attempt to control the situation, rebranded the phenomenon as the “dead armadillo curve”. 
• To see how this relationship has played out in practice, we plotted prices against solar generation for ERCOT and MISO, two of the most active vPPA markets. In both, solar’s ability to capture high-price periods continues to erode as the solar fleet expands. 
• ERCOT: Capture rates have kept falling, to 66% in 2025 and 62% in 2026 through September. The belly is deepening in the early afternoon, and prices now peak in the early evening (hrs 18-21). 
  

Source: Veolia

• MISO: It added ~6 GW of utility-scale solar in 2024, doubling its solar capacity. Capture rates fell to 92% in 2025 and 84% in 2026 year to date, and peak pricing has moved to late evening as solar ramps down (the dark blue line). 
  

Source: Veolia

What’s Next for the Duck?

• Slowing Supply: The One Big Beautiful Bill Act (OBBBA) accelerated the solar tax credit phaseout. Projects that began construction after July 4, 2026 must be operational by the end of 2027 for full credits, and projects commencing construction before that date are generally working on a 2030 deadline for safe harbor. Higher project costs pose barriers to entry which should, all else equal, flatten the curve by lifting midday prices. 
  Source: LevelTen Energy 
• Data Centers: Their flat, around-the-clock demand lifts midday load and prices, helping the belly. But it also adds strain at the evening peak, steepening the neck. Data centers that bring their own power can switch to backup generation at peak, which would ease prices for the rest of the grid.
• Curtailment: Operators curtail solar when supply outpaces demand, which temporarily flattens the belly. But there isn’t enough solar left to meet demand later in the day, so costlier generation is called on and late afternoon prices rise. 
• Battery Storage: This is the most direct solution. CAISO battery discharge tripled in the first five months of 2026 compared to the same period in 2024. Solar-plus-storage moves midday energy into the evening peak, and residential and commercial batteries can relieve peak demand. CAISO and ERCOT have scaled storage rapidly, and batteries were largely spared from the OBBBA cuts. 

Source: S&P 

The duck curve is not new, but its cost and shape (think American Black vs your common Mallard) depends on where a market sits on it, and the major markets are all moving down the curve. ERCOT is well along, MISO and NYISO appear to be crossing, and PJM is still early on the curve, with a modest solar share and prices driven largely by load growth, though the shape is beginning to emerge. The major takeaway is that rising power market prices do not automatically improve vPPA settlements for buyers, because solar only earns the portion of the price it produces into.  

BYOB: Encouraged at Parties, Rejected at FERC

• Earlier this month, FERC largely rejected PJM’s proposal for connecting data centers and other large loads (≥50 MW), including its proposed Interim Resource Adequacy Service (IRAS) and bring-your-own-new-capacity (BYONC) rules. The plan can likely be reworked, but it appears that it will require much more state level involvement. 
• The framework was intended to keep new data center load from colliding with a capacity market that is already under pressure, following the recent auction for the 2028/2029 delivery year, which finished 6,831 MW short of its reliability requirement. 
• IRAS was part of PJM’s broader effort to manage these reliability and cost impacts of new large-load connections; the core idea being that large loads entering service after June 2027 could “connect now, curtail first”— i.e. fast-track through the interconnection queue today in exchange for a promise to curtail first during grid emergencies, even before customers enrolled in voluntary demand response. A companion bring your own new capacity (BYONC) option would have allowed large loads to reduce that curtailment risk by procuring their own capacity upfront. This framework was intended to support a new market for bilateral capacity agreements while protecting PJM resource adequacy if large loads wanted to connect sooner. 
• That bilateral “backstop” capacity auction had already been postponed five months from its original October schedule, however it looks increasingly in peril after this most recent FERC ruling. 

The issue

• FERC’s objection was based on jurisdictional differences between federal and state regulators. FERC oversees wholesale power markets and interstate transmission, while states regulators/PUC’s regulate retail rates and the terms under which individual customers receive power. 
• FERC viewed the IRAS framework as effectively offering large loads different service terms from other customers in exchange for faster interconnection—which is considered an intrusion into state authority over retail service and rates. 
• This precedent is critical to any future curtailment plan. Creating a separate retail service class for data centers—with faster connections or lower rates in exchange for accepting curtailment risk—could require approval on a state-by-state, utility-by-utility basis. 

What FERC approved

FERC did approve two elements of PJM’s broader proposal:

• Defining a large load as 50 MW or more at a single site; and 
• Creating a registry to track large loads, including their locations, ramp schedules, and capacity arrangements. 
• The registry will give PJM better visibility into current and prospective large-load projects and their expected demand growth. It does not, by itself, change the interconnection process, but it should improve PJM’s ability to plan transmission and generation needs years in advance. 

Practical Impacts

• PJM projects that data centers could account for roughly 30% of peak demand—or about 67 GW-by 2036. Those figures underscore the urgency behind PJM’s proposal and the significance of FERC’s rejection, which leaves the region without a clear path for managing that growth. 

• Practically, the decision means:

1. No interconnection “fast lane”—at least for now. Projects that were banking on connecting under IRAS in exchange for a higher curtailment risk will need to go through PJM’s traditional interconnection process.
2. States retain central authority. FERC has reinforced state authority to determine which retail customers are curtailed during emergencies.
3. Better visibility into large-load growth. The registry will track the location and ramp schedules of large loads, helping PJM plan for future grid planning.
4. Resource adequacy remains top of mind. With FERC also rejecting PJM’s proposed backstop procurement mechanism in July, questions remain about how the region will address capacity shortfalls and manage potential price impacts to consumers.

• PJM is not alone in confronting the challenges of data-center growth. RTOs across Texas, the Midwest, and California are all considering their own interconnection reforms. But because PJM’s data-center demand has outpaced many other regions—largely due to its proximity to data-center hubs in VA and surrounding areas—any framework that wins FERC approval could become a model for other regions. 

Summer Peaks: A Recap of Veolia’s 2026 Peak Demand Notification Program

• Veolia provides a variety of peak alert and automated dispatch programs to track and predict system peak loads, helping our clients reduce exposure to capacity costs while supporting reliability across the grid. Below we recap the results of our standard voluntary “Peak Alerts” program. For information about our automated program supports our energy dispatch and transmission curtailment programs through our Flexible Energy Services line, please contact commodity@veolia.com

• Compared to 2025, summer peak demand varied across the three regions–NYISO, PJM, and ISO-NE– with some experiencing increases while others recorded declines (see furthest right column on the table below), emphasizing the ongoing balancing act and importance of grid reliability and capacity planning by each ISO. All system level peaks occurred after 5pm this year.
  

Sources: NYISO, ISO-NE ,Veolia

• Our Analysts dispatched alerts correctly identifying all seven events across the Northeast and PJM again this year with the complete list and boldened actuals summarized in the table below. We only had to call events on two days in NYISO and ISO-NE, and twelve days in PJM.

Source: Veolia

• To learn how alerts can help manage capacity charges throughout the year, particularly in markets with exceptionally high costs, please contact commodity@veolia.com.

Market Data

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