How 2026 Energy Market Shifts Show Up on Commercial Utility Bills

Allen Wang·October 12, 2026
How 2026 Energy Market Shifts Show Up on Commercial Utility Bills — Nectar blog

In January 2026, the Henry Hub natural gas price averaged $7.72 per MMBtu after Winter Storm Fern, according to the US Energy Information Administration. By spring, gas prices had fallen back, and the EIA now expects Henry Hub to average $3.48 for 2026 and $3.16 for 2027. For many commercial buyers, electricity costs didn't follow gas back down.

The longer trend points the same way. The average price of electricity to US commercial customers rose from 10.59 cents per kWh in 2020 to 13.37 cents in 2025, about 26%, according to EIA's Electric Power Monthly. Prices in 2026 have continued to run above 2025.

For years, watching natural gas was a reasonable way to anticipate electricity prices. Gas-fired generation sets the marginal price of power in much of the country, so when gas moved, power followed. As our partners at Stanwich Energy put it in a recent market note, gas still sets the stage, but regional markets now write the script. Each grid adds its own capacity, transmission, reliability, and policy costs on top of the fuel price, and those regional costs increasingly decide what a business pays.

Those costs don't show up as a single line. They're spread across supply charges, capacity and transmission pass-throughs, delivery riders, and demand charges. A buyer who only sees bill totals can't tell which shift is affecting which site. We see this in the bills we process every day. Here are the five shifts we're watching most closely in 2026, and where each one shows up on a commercial bill.

1 Load growth from data centers and electrification

After years of flat demand, US electricity consumption is growing again. In September, the EIA projected that US power use will set records in both 2026 and 2027, rising from 4,195 billion kWh in 2025 to 4,349 billion kWh in 2027, as reported by Reuters. The EIA also expects commercial sector sales, which include data centers, to exceed residential sales in 2026 for the first time since it began collecting the data.

Data centers are the most visible driver. A 2026 Department of Energy study found that they used about 4.7% of US electricity in 2024 and projected 9.5% to 15.3% by 2030, according to a Congressional Research Service summary. EPRI's 2026 projections land in a similar range, 9% to 17% by 2030, and note that Virginia is already the only state where data centers use more than 20% of electricity. Electrification of buildings, vehicles, and industrial processes adds to the growth.

New large loads are arriving faster than new generation and transmission can be built. In PJM alone, the 2025 load forecast projected about 32 GW of peak growth from 2024 to 2030, roughly 30 GW of it from data centers, as the Public Utilities Commission of Ohio's federal energy advocate noted in comments to PJM.

Where it shows up: higher supply prices in new contracts, higher capacity costs (see the next section), and, over time, delivery rate increases as utilities build the grid to serve new load.

2 Capacity costs

Capacity is what grid operators pay generators to be available during peak demand. In PJM, the grid that serves 13 states and Washington, DC, capacity prices have risen sharply:

  • 2024/2025: $28.92/MW-day, before the increase.
  • 2025/2026: $269.92, about 9 times the prior year.
  • 2026/2027: $329.17, at the price cap.
  • 2027/2028: $333.44, at the price cap, and the first shortfall against the reliability requirement.
  • 2028/2029: $325.00, at the cap. PJM estimates about $555 without it.

Sources: PJM's 2026/2027 and 2027/2028 auction reports, Utility Dive, and Stanwich Energy.

The 2027/2028 auction was the first since PJM's capacity market was created in 2007 to fall short of the reliability requirement, by about 6.5 GW, according to PJM's 2025 annual report. The 2028/2029 auction fell short by about 6.8 GW. Its slightly lower price reflects a recalculated cap, not looser supply. Without the cap, PJM estimates the price would have been about $555/MW-day across the region and about $777 in the ComEd zone in northern Illinois.

The effect on large accounts is substantial. One industry estimate cited by Utility Dive put the monthly capacity charge for a 10 MW industrial customer at roughly $70,000 in 2028, compared with about $6,000 in 2024.

Where it shows up: each account is assigned a capacity obligation based on its demand during a handful of system peak hours the year before. On a bill or supply invoice, capacity may be bundled into a fixed supply price, listed as a separate capacity charge, or passed through under a contract clause. As Stanwich has noted, how a supplier treats capacity in a fixed-price contract now matters as much as the energy price itself.

3 Regional divergence

Regional power markets used to move together. They no longer do. Winter Storm Fern made the differences visible in a single week:

  • New England relied on oil and imported LNG as gas pipelines hit their limits. Gas delivered on the Algonquin pipeline reached about $122/MMBtu on January 27, and winter wholesale market costs reached $6.5 billion, up 45% from the prior winter and the highest since 2014, according to ISO New England's Winter 2026 market report.
  • PJM and New York saw power prices spike as demand topped forecasts and gas supply tightened, Reuters reported.
  • Texas held up better. CBRE's analysis of the storm found that ERCOT's thermal fleet held, about 7 GW of batteries kept real-time prices in check, and ERCOT was the only region where forward power prices fell afterward. In PJM and the Northeast, 2027 and 2028 forward prices kept most of their storm premium.

Transmission limits sharpen these differences. During the storm, prices exceeded $1,500/MWh at some Mid-Atlantic nodes while nearby parts of Illinois saw negative prices, and US grid congestion costs have topped $10 billion a year for four straight years, according to Americans for a Clean Energy Grid. Stanwich describes the broader pattern in Why Commercial Energy Management Has Gotten Harder.

Where it shows up: sites in different regions see different cost trends at the same time, even under the same supplier. A portfolio-level average hides this. A multi-region organization needs to track supply, capacity, and delivery costs market by market.

4 LNG exports

US liquefied natural gas exports are rising fast, from 15.1 billion cubic feet per day in 2025 to a projected 17.6 in 2026 and 18.6 in 2027, according to the EIA. Corpus Christi Stage 3 and Golden Pass are adding capacity this year, and Port Arthur, Rio Grande, and the final Golden Pass train are expected next year, the EIA reported in April.

So far, domestic prices have been partly insulated. When international LNG prices jumped after the Strait of Hormuz closure earlier this year, US terminals were already running near full capacity, which limited how much of the shock reached Henry Hub, according to the EIA. But each new terminal ties more US gas demand to global markets. New export demand is already lifting prices at some Gulf Coast trading hubs, NGI reports, and it supports higher forward prices even while storage sits above its five-year average heading into winter.

Where it shows up: natural gas supply charges and, indirectly, electricity supply prices, especially in multi-year fixed-price contracts priced off the forward curve. Gas bills in regions with limited pipeline capacity, such as New England, are most exposed during cold snaps.

5 Rate cases, new tariffs, and riders

Utilities are asking regulators for more money than ever. Investor-owned electric and gas utilities requested a record $22.06 billion in rate increases in 2025, the highest total since tracking began in the early 1980s, according to S&P Global Market Intelligence. The advocacy group PowerLines, which counts requests differently, put 2025 at about $31 billion and counts $23.1 billion requested so far in 2026, including a record third quarter, Utility Dive reported.

Regulators are also writing new tariffs for very large loads. Recent decisions in Michigan, Kansas, Virginia, and Wisconsin require data centers and similar customers to sign long contracts and pay minimum bills based on 80% or more of their contracted demand. The stated goal is to keep other customers from paying for infrastructure built for new large loads. How well those protections work will shape delivery rates for everyone else.

Beyond rate cases, utilities are adding reliability and resilience riders, storm and wildfire recovery charges, more granular time-of-use periods, and real-time pricing options that shift more price risk to the customer.

Where it shows up: on the delivery side of the bill, as changed rates, new line items, or revised time-of-use windows. These changes are easy to miss because they arrive mid-year, through filings few customers read, and they apply automatically.

Where each shift appears on the bill

  • Load growth shows up in supply prices, capacity charges, and delivery rates. Check new contract pricing and rate case filings for your utilities.
  • Capacity costs show up as capacity charges, pass-throughs, or inside a fixed supply price. Check each site's capacity obligation and your contract's pass-through clauses.
  • Regional divergence shows up as different cost trends across sites. Check cost per kWh by region, not just the portfolio average.
  • LNG exports show up in gas supply charges and forward-priced electricity contracts. Check contract timing and winter exposure on gas accounts.
  • Rate cases, tariffs, and riders show up in delivery charges, new line items, and time-of-use periods. Check for line-item changes after each filing, and whether your current rate still fits.

What buyers should do now

The organizations that handle this market best aren't the ones taking the biggest positions. They're the ones with the clearest view of their exposure. In practice, that means:

  • Know each site's capacity and transmission obligations, and how they're set by peak days. Reducing load during those hours lowers next year's costs.
  • Read fixed-price contracts for pass-through clauses. Know which components are fixed and which can change, especially for capacity in PJM.
  • Track tariffs and riders per account. A rate change that applies to one utility's commercial schedule won't show up in a portfolio average.
  • Watch rate cases for the utilities that serve you. A rate filing tracker is a useful starting point; the order that comes out of each case is what lands on the bill.
  • Budget from line-item history, not last year's totals, so you can see which component is driving the change.
  • Time procurement with an advisor who follows each regional market closely. Our procurement advisory works through partners like Stanwich for this reason.

Where Nectar fits

All of this depends on seeing each cost component separately, for every account. Nectar collects and parses every bill at the line-item level, so supply, delivery, capacity, transmission, demand, and rider charges are each visible on their own. Tariff checks catch rate and rider changes as they appear on bills. Demand management uses interval data to show when peaks happen. And budgeting and forecasting builds on that history, so finance teams can see which market shift is driving next year's number.

The market is more expensive, more volatile, and more regional than it was a few years ago. The bill is where all of it lands, and it's the best place to start understanding it. If you want to see your own costs broken down by component, talk to our team. For how an energy advisor puts this data to work, see how Stanwich Energy uses Nectar.

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