A Tale of Two Citygates

Written by Weekly Market Update | May 21, 2026 5:28:12 PM

Energy Markets Update

Editors Note: It was the best of times for natural gas buyers. It was the worst of times for many electricity buyers. Our newsletter dials in on the interesting divergence of NYMEX gas and regional electric markets against the backdrop of summer preparedness, peak load management, and rising distribution costs. We also offer some budgeting tips for energy managers trying to make sense of it all.

Weekly Natural Gas Inventories

Source: EIA, Veolia

Energy Market Update

NYMEX prompt month gas continues to look soft with the May 2026 close of $2.56 /MMBtu, a sharp decline from February’s settlement of $7.46 /MMBtu. The decline in the cost of gas is not just a near term phenomenon; the 2027 strip is down 8% over the past six months while the 2028 strip has remained relatively flat over the same time period. Most contracts in this horizon are now trading at multi-year lows.
Power markets have been far more stubborn and are reluctant to follow gas down. A combination of factors such as drought, tighter reserve margins, and even the conflict in Iran have given traders reasons to hold out.
Thus, a tale of two citygates has emerged as the US energy market looks very different from the eyes of gas buyers and power buyers (see chart below). While it remains true that regional gas and power are still largely correlated, the conventional wisdom that “as goes gas, so goes power” seems to be under challenge. Each region has its own list of causal factors as to why power prices remain higher, despite falling gas costs.
- In PJM, rates are buoyed by thin reserve margins and higher likelihood of scarcity pricing in both summer and winter. It’s hard to ignore that this is not “the data center” effect, be it real or perceived. The largest price separations are present in areas with some of the largest datacenter growth.
- In New England, price separation is attributed to drought conditions in Canada and its implication of lower expected hydroelectric imports. Another significant driver is the rising cost of LNG imports due to the Iran conflict–yes, New England is uniquely positioned as the one US load center that imports LNG during very cold stretches in the winter. Volumes are relatively small, but they are priced at European spot rates, which have become quite expensive. This doesn’t quite explain why New York is showing very similar trading patterns.
All said, these trends may be grounded in some logic, but there will come a time for reckoning in the forward market if spot prices continue to reflect steeply discounted gas prices and fail to converge with frothy expectations.

A Tale of Two Citygates

Source: CME Group and Argus Forwards

On April 28, 2026, the Federal Energy Regulatory Commission (FERC) approved a settlement establishing a $325/MW-day price cap and a $175/MW-day price floor for the PJM capacity market. Those guardrails will be in place for the next 2 auctions:
- The Base Residual Auction for the 2028/2029 Delivery Year (closing July 7, 2026)
- The Base Residual Auction for the 2029/2030 Delivery Year (closing December 15, 2026)
Earlier this week, PJM proposed accelerating its 2029/2030 backstop capacity auction by moving the phase 2 “clean-up” auction from March 2027 to September 2026, allowing the entire process to finish this year. Some analysts believe this could reduce PJM’s 14.9 GW bilateral procurement target.
The Champlain Hudson Power Express (CHPE) transmission line entered commercial operations on May 13. The 1,250 MW line will export hydropower from Canada to New York City and provides a critical reliability asset in the wake of significant plant retirements in the state.
Brent oil is up to 109.26 a barrel, an increase of around 85% from last year. With no apparent end to the stalemate around the Strait of Hormuz, many analysts anticipate a price rally over the next month…fill up while it remains just a bit expensive.
Gas storage remains elevated at 2,391 Bcf as of the latest EIA storage report. This represents a net increase of 101 Bcf from the previous week. Stocks are 33 Bcf higher than last year at this time and 149 Bcf above the five-year average. At 2,391 Bcf, total working gas is within the five-year historical range.

National “Quick Hit” Stories:

NextEra Energy will buy Dominion Energy in an all-stock deal valued at nearly $67 billion. Dominion powers the world’s largest data center. The acquisition will create the largest regulated electricity utility globally with a market cap of $249 billion.
Last week a Utah county commissioner approved a data center project known as Stratos in Box Elder county in north-western Utah. The facility will require about 9GW of power, which is more than the entire state of Utah currently consumes and will have a 40,000 acre footprint. This proposal is sparking outrage as Utah has already been experiencing drought conditions and the data center will require water.
MISO's most recent Planning Resource Auction (PRA) resulted in lower capacity prices for the 2026-27 delivery year, with annualized prices falling to $116 - $126/MW-day from $212 - $217/MW-day last year. The decline was driven largely by a 4% increase in cleared capacity, with solar accounting for more than half of new additions—up 59% YoY.
A major refund for New England ratepayers is on the horizon following FERC’s recent decision to cut the allowed return on equity (ROE) for transmission owners and refund $1.5B in transmission charges dating back to 2011. The decision is estimated to save NE customers $100 million annually going forward, if and when it gets through a barrage of appeals.
ISONE has proposed the first update to its DASI program, an ancillary service initiative launched a year ago that has so far exceeded cost estimates by about 700%, or $800 million. The reforms, which primarily focus around lowering the procurement requirement by appropriately accounting for real-time generation from renewables, could reasonably be in place by the Fall after further discussion at ISO and subsequent FERC signoff.
PJM is proposing major changes to its capacity market to address rising electricity demand, especially from data centers, and unsustainable price volatility. The proposal outlines three possible frameworks: improving the existing capacity market with longer-term contracts, rationing reliability during shortages, or shifting toward energy & ancillary-based markets. The stakeholder discussions through 2026 will develop consensus on which reforms to implement.

2026 Summer Capacity Outlook

Temperatures reached over 90 degrees across major load centers in the Northeast this week, a sure sign that summer is around the corner, or perhaps, here already. With climate models showing strong indications of an El Niño pattern emerging in 2026, we’re anticipating higher than average temperatures this summer, especially in the Northeast. As many RTOs deal with capacity constraints due to retirement of legacy generation, datacenter growth and increasing electrification, a hot summer will test their limits. Let’s take a look at how RTOs are positioned to manage increased summer capacity.

NERC Assessment

The National Electric Reliability Council (NERC) published its summer assessment this week, highlighting that most of North America has adequate supply resources, with only a few regions facing elevated reliability concerns:
- The Pacific Northwest is facing prolonged drought conditions that will put strain on hydroelectric resources
- New England due to reliance on imports during peak hours

Source: NERC: 2026 Summer Reliability Assessment

NYISO

NYISO is on the hot seat this summer though the ahead-of-schedule COD of a new transmission line announced just this week will cool things down. According to their Summer Reliability Assessment, they have 34,615 MW of generation to meet 31,578 MW of projected peak demand under normal conditions. With 2,620 MW required for operating reserves, this leaves a 417 MW reliability margin, the thinnest in recent history. Operating reserves are a fixed mandatory amount of generation capacity that can be ready to ramp up in an emergency while a reliability margin is the excess capacity available after peak demand and operating reserves are accounted for. The ISO also projects capacity deficiencies of over 1,500 MW for periods of 3 days or more where average daily temperatures are above 95 degrees. We’re already testing those limits with an early heat wave. NYC’s May spot capacity price jumped to $33/kW-month, ~55% higher than last May’s price.
NYISO will be getting some timely relief as the Champlain Hudson Power Express (CHPE) transmission line entered commercial operation last week. The project finished ahead of schedule and is expected to provide 1,250 MW of hydropower to NYC. NYISO’s original reliability assessment did not bank on CHPE being operational; we’ll be on the lookout for a reassessment. Even with CHPE, NYISO still relies heavily on aging Gowanus, Narrows and Danskammer peakers, operating under emergency DEC peaker rule extension to maintain summer reliability. If an El Niño pattern continues, there is a strong chance that grid operators will need to initiate emergency operation procedures to maintain system reliability in the coming months.

PJM

Unlike NYISO, PJM is boasting sufficient supply resources to meet expected conditions this summer. PJM reported 180,200 MW of generation capacity to meet a projected peak load of 156,400 MW, a 23,800 MW margin. Although this summer’s outlook is promising, PJM’s reserve margins are continuing to tighten as data center load growth outpaces new generation. The RTO targets a 20% reserve margin to maintain a 1-in-10 Loss of Load Expectation. This year’s margin is ~15% while the 2027/28 auction cleared a ~14% reserve margin.
During periods of strained grid conditions, PJM also has the ability to call on demand response to bolster reliability. Roughly 7,800 MW of demand response assets are contracted in PJM for this summer and last summer non-emergency demand response was called on six times to help control peak use. As we’ve covered in previous newsletters, this will be a key strategy to maintain reliability as PJM navigates the future landscape.

MISO

MISO finalized its summer capacity auction for the 2026-27 Planning year at the end of April, and capacity offered into the auction increased to 141,000 MW, a 3.4% jump from last year. Immediately following the auction, annualized capacity prices across MISO zones fell; summer capacity prices dropped from $666.50/MW-day to ~$400/MW-day. Reliability margins now hover around 11%, exceeding MISO’s 7.9% reliability target. While there is still progress to be made in terms of bolstering reliability, this signals that MISO is taking some positive steps to address capacity shortfalls.
The increased capacity was mainly sourced from new solar assets, followed by gas and battery storage. The growth in new supply is largely attributed to the success of MISO’s Expedited Resource Addition Study (ERAS) program, which allows vetted resources to bypass the interconnection queue if they demonstrate readiness to operate. We covered the details of this program in a previous newsletter. While NERC reports that MISO is at high risk for power outages in the next few years, the grid operator is hopeful that the ERAS program will allow supply additions to outpace projected demand.

ISO-NE

According to the latest ISO-NE CELT report, the region has sufficient capacity to meet peak demand this summer. With roughly 29,300 MW of generating capability and a projected summer peak load of 25,228 MW, New England is operating with a ~16% reserve margin although NERC puts it closer to 14%, just above the 13% reference level. NERC has also put ISO-NE on elevated alert due to reliance on non-firm imports from neighbouring RTO’s that could have concurrent peak conditions. ISO-NE has not experienced data center growth to the same level as other RTOs which, along with high energy efficiency standards and robust demand response programs, has helped to maintain a comfortable level of reliability.
The bottom line - reliability is a top concern for all RTOs as demand grows and reserve margins get tighter. Expedited interconnection, demand response programs, and flexible data centers are proving to be necessary solutions to address shortfalls during summer. We’ll keep an eye on these stories as things heat up!

Peak Alert: The Summer Strategy Cutting Capacity Costs

Veolia is partnering with clients this summer to track and predict system peak loads, helping reduce exposure to capacity costs while supporting reliability across the grid. For most participating customers, this service begins on June 1st. Our base offering is available to active clients. For clients with behind-the-meter generation and/or that require automation services, we offer an enhanced Peak Load Notification service through our Flexible Energy Services group that provides wider geographic coverage, as well as transmission peak and capacity performance alerts. Please contact our Flexible Energy Service group at matthew.wolfe@veolia.com for additional information.

For newer readers, a quick refresher: Each Independent System Operator (ISO) calculates capacity obligations using Peak Load Contribution (PLC) or capacity tags. These tags reflect a customer’s share of system demand during the highest-load hours of the season and directly determine your capacity charges for the following year. The chart below shows the estimated cost reduction (2025 vs. 2026) by decreasing your Capacity Tag by just 1 kW across NYISO, PJM and ISO-NE. Even small reductions add up fast. In PJM there may be additional coincident benefits associated with the reduction of your transmission tag, which are omitted from this chart for simplicity.

Source: Veolia & ISO data

Here’s how each ISO sets the capacity tags:

PJM: Average usage during the five non-weekend, non-holiday peak hours, each set on different days between June 1 and September 30. Capacity Tags (Peak Load Contributions) take effect the following planning year from June 1 to May 31. Historically, PJM summer peak demand ranges between 140 and 160 GW, typically occurring in July and August. Nearly all-system wide peaks hit during late afternoon and early evening, specifically between hours ending 17:00 and 18:00 EDT. As noted, transmission charges for some utilities reference the same coincident peak hours.
NYISO: Usage during the single highest non-weekend, non-holiday peak hour in July or August. Capacity tags are set for the following Summer Capability Period (May 1 to April 30). Historically, NYISO summer peak demand has been ranged between 28 and 33 GW, typically occurring mid-to-late July. NYISO typically hits its system peak in the late afternoon to early evening, specifically between hours ending 17:00 to 19:00 EDT.
ISO-NE: Usage during the highest system peak hour of the year, occurring during any month or day of the week, sets the capacity tags that are effective for the capability year running the following June 1 to May 31. Historically, ISO-NE summer peak demand ranges between 23 and 26 GW, typically occurring from June to September. ISO-NE now typically hits its system peak late in the afternoon, specifically between hours ending 18:00 to 19:00 EDT.

Below is a table representing the historical summer ISO peaks for the past 5 years.

Source: Veolia & ISO data

2026 Forecasted Peak Load

The 2026 summer peak load predictions across the three ISOs are as follows:
- PJM: 159,329 MW
- NYISO: 31,578.6 MW
- ISO-NE: 25,228 MW
During summer months, Veolia monitors weather conditions and load forecasts from various ISO’s to identify potential peak demand events through the Peak Load Notification program. When a peak event is likely, we alert customers early in the morning - giving them sufficient time to implement consumption reduction strategies and minimize capacity charges.

Example of a Veolia peak day forecast for our customers:

Source: Veolia

Veolia is continuously enhancing its Peak Load Notification program for maximum accuracy and reliability. We value your feedback and welcome suggestions for improvement. If you’re not currently enrolled and receiving alerts but want to optimize your capacity charges, please contact our team at commodity@veolia.com to learn more. If you are interested in Veolia’s enhanced Peak Load Notification service that provides wider geographic coverage, as well as transmission peak and capacity performance, please contact our Flexible Energy Service group at matthew.wolfe@veolia.com

Utility Budgeting 101

Spring is in full swing—the season when many of our customers kick off budget planning for the upcoming fiscal or calendar year. The primary challenge is that utility costs are notoriously hard to predict. Often 40-60% of utility charges are indexed to wholesale market prices, and those costs may fluctuate dramatically from year to year. But with a solid understanding of your invoice cost components, where budgets typically derail, and best practices for accurate forecasting, you can build a much more predictable utility budget. Let's walk through it.

Breaking Down Your Utility Bill (and Your Budget)

We’ve covered the anatomy of a utility bill in previous newsletters. As a refresher, there are three main components of any power or gas bill:
- Supply Costs – The actual commodity price, driven by wholesale power and natural gas markets. Depending on your region, supply comes from your local utility (the default in most cases), a municipality, or a third-party supplier.
- Delivery Costs – The regulated cost to maintain the infrastructure that delivers energy to you. This always comes from your local utility.
- Usage and Demand – How much energy your building(s) consume (measured in kWh or Dth for volume, or kW and Dth-day or month for demand).
Both supply and delivery are expressed as a $/unit rate, applied to customer usage. The rates can be volumetric (e.g. $/kWh, or $/Dth), or demand-based ($/kW) depending on the type of charge.

Why Utility Budgets Go Off Track

Most budgets derail for one of two reasons:

Inaccurate usage forecasts: Your trailing 12 months of data is a solid baseline, but the savvy budgeter will also adjust for weather anomalies, planned operational changes, and other factors (more on those below). This is meaningful because even if your supply & delivery rates are 100% accurate, a significant delta between budgeted and actual usage will throw the entire cost off.
Unexpected market events: Winter Storm Fern is a perfect example—an unpredictable weather event that strained supply/demand nationally and caused month-over-month rate spikes exceeding 500% in some regions. This is precisely why many large energy buyers hedge their power supply through bilateral contracts. Locking in some or all of your energy load at a fixed price—especially during peak winter and summer months—protects from these kinds of shocks. It also helps to simplify your budget.

Best Practices & Tips From Veolia’s Advisory Team

To get started, pull your past year of usage data, and consider the following adjustments:
- Account for anomalies. If your building is primarily a heating load, look back at last year's weather conditions. Was it an unusually harsh winter? If so, consider adjusting your gas forecast down for the coming winter (assuming normal conditions return). Or, if last summer was cooler than normal, add a buffer to the electric load forecast for June-September. The key is recognizing outliers and adjusting accordingly.
  - Averaging usage across 2-3 years also helps to normalize anomalies
- Factor in planned operational changes: For buildings that are undergoing renovation, upgrading major HVAC equipment, experiencing changes in tenancy in the coming years, etc – these factors should be built into the usage forecast. For example, if part of the building is shutting down for 3 months for a tenant fit-out, adjust usage down for that period accordingly.
- Watch for utility rate changes. Regulated utilities file "rate cases" requesting increases (anywhere from 2-10% annually) on a predictable schedule—quarterly, biannually, or annually depending on the territory. Check your local utility's website and Public Utility Commission filings to anticipate upcoming changes.
- Monitor regulatory changes. Regional RTO/ISO operators often introduce new rate components to meet local grid, fuel security, or other needs. For example, ISO New England implemented DASI (Day Ahead Ancillary Services Initiative) last March, which added upwards of $10/MWh to every New England customer's supply cost.
- Build in a Buffer: Create a high and low-case in addition to the base case. For non-fixed price buyers, supply costs are often the most volatile component. Consider applying a +/- 10% buffer to your energy price forecast for these scenarios.
- Consider a managed supply approach: By default, customers are placed onto their local utility’s supply rate, which often fluctuates monthly or quarterly. In deregulated states, customers have the option to strategically manage their energy supply, with the potential to reach up to 100% budget certainty. The value is in minimizing volatility from the most unpredictable component of your energy budget (supply).
For guidance on utility budgets, strategic supply planning, or overall energy management, contact our team commodity@veolia.com!

Distribution Costs: An Overlooked Driver Behind Rising Bills

While power supply prices (the cost of the electron itself) often grab headlines, the costs of electric distribution, the poles, wires, and infrastructure that deliver power to your business can account for as much as 50% of your total cost. Those costs are escalating at a faster clip over the past 10 years and a recently published report from the Lawrence Berkeley Lab examines these distribution cost trends at the regional level, providing valuable insights into what's driving your total electricity expenses.

Your electricity bill has two main parts: the supply charge (what you pay for the actual electricity) and the distribution charge (what you pay to get that electricity delivered to you). For businesses focused on controlling energy costs and budgeting years ahead, understanding both components is essential for planning through 2027 and beyond.

Since 2014, investor-owned utility companies have increased their distribution spending by 6% each year, four times faster than the previous two decades. This spending boom now accounts for about 32% of the rise in retail electricity rates nationwide. The main reason isn't just building new capacity for growing demand. Instead, utilities are spending heavily to maintain and upgrade aging distribution systems that are now 40-70 years old and need significant work.

Source - LNL: Electric Utility Distribution Costs

The regulatory environment shows this pressure clearly. IOUs are requesting larger and more frequent rate increases than they have in decades, and Public Utility Commissions are approving them at higher rates. While regulators have tools to control costs, the trend shows that most of these increased expenses are being passed and the costs are revealing themselves as higher distribution components on power bills.

The replacement and upgrade of aging infrastructure are leading culprits for rate increases, but there are many factors. Over the past five years, the cost categories with the highest growth rates are line transformers and underground conduits.
Cost inflation has been a significant factor since 2020 as core commodities such as copper have been squeezed and supply chains have shifted.

Source - LNL: Electric Utility Distribution Costs

While not all requested rate increases are approved, regulators have been approving a higher percentage of utility rate requests over the past five years compared to the prior 20 year period.
Some regulators are more generous than others. The accompanying chart illustrates how approval levels vary significantly by region. In the most recent period (2021-2025), Public Utility Commissions in New England (ISO-NE) and the Southeast have approved the highest percentages of requested rate increases, reaching approximately 77% and 75% respectively. This indicates that utilities in these regions have been more successful in getting their proposed rate increases implemented compared to others.
There are some other caveats; some regions, particularly in ISO-NE, have increasingly relied on capital tracker mechanisms that once established, provide for a less contentious avenue for cost recovery.