The rapid growth in power demand, driven largely by data centers, has strained PJM’s existing generation fleet during periods of extreme summer weather. During the early- and mid-July heat waves this year, demand on the grid approached available system capacity, forcing PJM to rely on its most expensive generation resources—and at times demand response—to serve the final increment of load.

On July 2, PJM system-wide day-ahead spot prices exceeded $1,000/MWh ($1.00/kWh). Some of the most constrained load zones, such as the Baltimore Gas & Electric Zone (BGE), saw spot power prices peak at approximately $1,600/MWh, due to high congestion costs associated with importing power into the zone from elsewhere on the grid.

Outside of these periods of grid stress, spot prices have cleared at much more reasonable levels, though the impact of rising demand is still evident. So far in August, as temperatures have moderated, PJM system-wide hourly spot prices have averaged 5.05¢/kWh. That compares with 3.85¢/kWh over the same period in 2025—a 31% increase—when much of the anticipated data center demand had yet to materialize on the grid.

With the last month of summer still in front of us, and a surprise heat wave on our doorstep, we will wait and see how spot prices react.

PJM’s Reliability Backstop Procurement and Proposed Large Load Registry

As discussed in last month’s newsletter, PJM has proposed a Reliability Backstop Procurement (RBP) to address the 6,831 megawatt (MW) capacity shortfall from its 2028/2029 Delivery Year Base Residual Auction. Pending approval from the Federal Energy Regulatory Commission (FERC), the RBP process would begin September 30.

PJM has also proposed a Large Load Registry (LLR) that would track end-use customers—data centers or otherwise—with cumulative peak demand of 50 MW or greater at a delivery point or point of interconnection. Existing Large Loads in service before June 1, 2027, would generally be required to register by March 1, 2027.

For most small and mid-sized commercial and industrial (C&I) customers, the registry itself creates no direct obligation. The risk is downstream: if the Large Load designation later becomes the basis for allocating RBP costs or other reliability obligations, existing Ohio manufacturers could end up as the financial backstop for load growth they did not cause.

That risk prompted the Ohio Energy Leadership Council (OELC) to intervene in PJM’s RBP proceeding in FERC Docket No. ER26-3380-000. OELC’s comments support PJM’s resource-adequacy objective, but urge protections for existing customers: a 150 MW threshold for non-data-center loads, measurement based on system-peak Peak Load Contribution rather than individual peaks, and a demonstrable link between a customer’s load and the growth driving the RBP. OELC also pressed PJM to prioritize dispatchability, duration, and fuel assurance when selecting RBP resources.

Brakey Energy will continue to monitor PJM’s RBP proceeding and the proposed LLR, particularly as they relate to potential costs for Ohio C&I customers. If you have questions, please contact Katie Emling.

Residential Corner

Sky-high capacity prices coupled with increased data center demand have kept residential rates at the highest levels in recent memory. We recommend customers with an approaching contract expiration migrate to this 9-month fixed-rate offer from Energy Harbor for 9.59¢/kWh.

Regarding natural gas, Brakey Energy has long viewed the distribution utilities’ Standard Choice Offer (SCO) as a prudent default strategy for supply. However, this approach can produce volatile bill outcomes, like the wild ride many customers experienced during the extreme cold this past winter. With natural gas settlement prices having since remained reasonable, and the commodity itself trading at compelling values relative to power, customers on the SCO are likely seeing manageable bills.

Natural Gas Market Update

The NYMEX price for August settled at $2.725 per Million British Thermal Units (MMBtu) on July 29, 2026. This price is down 15.7% from the July 2026 price of $3.231 per MMBtu. This settlement price is used to calculate August gas supply costs for customers that contract for a NYMEX-based index gas product.
The graph below shows the year-over-year monthly NYMEX settlement prices for 2022, 2023, 2024, 2025, and 2026 year to date. Prices shown are in dollars per MMBtu of natural gas.

Figure 1: NYMEX Monthly Natural Gas Settlement Prices

Figure 2 below shows the historical August 28, 2024 through August 28, 2026 Around the Clock (ATC) forward NYMEX natural gas prices in dollars per MMBtu for the balance of 2026 (labeled as “Custom Strip”) and calendar years 2027, 2028, 2029, 2030, and 2031.

Figure 2: ATC Calendar Year NYMEX Natural Gas Prices

*Pricing courtesy of Direct Energy Business.

Forward natural gas prices have continued to trade at or near multi-year lows through 2027, and have largely traded flat for outlier years 2028 and beyond. Although total demand for natural gas has been higher this summer than the previous two summers, due to increased LNG export capacity and higher power burn demand, domestic production has remained robust and near all-time highs.

As we transition from summer to autumn, market participants will be looking to early winter weather outlooks and forecasts, which could reintroduce volatility to the forward gas market.

Electricity Market Update

Figure 3 below shows the historical August 28, 2024 through August 28, 2026 ATC forward power prices in dollars per Megawatt hour (MWh) for the balance of 2026 (labeled as “Custom Strip”) and calendar years 2027, 2028, 2029, and 2030 for the AD Hub.

Figure 3: ATC Calendar Year Power Prices for the AD Hub

*Pricing courtesy of Direct Energy Business.

Forward power prices continue to trade near multi-year highs, principally due to the unpredictable impact of future weather events on spot power prices, the constrained grid conditions amidst the fast-paced growth of large data center loads, and the extension of the capacity price cap through the 2029/2030 delivery year.

Although forward power prices have not followed forward gas prices downward, movements in forward gas prices can still influence forward power prices, as gas-fired generation accounts for approximately 40% of all electric generation in PJM. As autumn approaches, market participants will be paying close attention to early winter weather outlooks, which may bring increased volatility to energy markets.

The post Ohio Energy Report: August 2026 appeared first on Brakey Energy.

On July 14, PJM released the results of its Base Residual Auction for the June 1, 2028 through May 31, 2029 delivery year. The auction cleared at the federally approved price cap of $325.00 per MW-day across the entire PJM footprint, including Ohio’s utility zones. This equates to approximately $118.63 per kW-year and is approximately 2.5% below the prior planning year’s capped clearing price of $333.44 per MW-day.

PJM procured approximately 138,318 MW of unforced capacity, but the auction still fell roughly 6,831 MW short of PJM’s reliability requirement. The shortfall reflects continued load growth, particularly from large-load customers, combined with limited new generation entering the market. Only about 317 MW of new generation and 208 MW of uprates cleared the auction, reinforcing concerns that supply is not keeping pace with projected demand.

Without the temporary price cap, PJM estimated that the auction would have cleared at approximately $554.72 per MW-day across most of the region, while the ComEd Zone (encompassing Chicago and Northern Illinois) would have cleared at approximately $776.69 per MW-day. The value of capacity commitments would have increased from about $16.4 billion to nearly $29.7 billion. Although suppliers may have bid differently without the cap, the simulation illustrates the gravity of PJM’s current supply-and-demand imbalance.

To address the shortfall, PJM is planning a one-time reliability backstop procurement, with bidding expected to begin in September. The procurement is intended to attract incremental generation, storage and demand-side resources that may not otherwise be developed through the normal auction process. However, the program remains subject to FERC approval, and because most new resources require several years to develop, it is unlikely to provide an immediate solution to PJM’s capacity shortage.

Peak Loads for Summer 2026

Brakey Energy provides email and text alerts in advance of potential Capacity and Transmission Coincident Peaks (CPs) to those clients that elect to receive them. As of July 29, 2026, Brakey Energy has issued 7 Capacity CP alerts, 8 FE (ATSI Zone) Transmission CP alerts, and 6 AEP Ohio CP alerts during Summer 2026. Brakey Energy also issued 7 winter alerts for the AEP Zone in January and February of this year.

Capacity CPs occur during the five one-hour intervals when demand on the PJM grid is at its highest. Transmission CPs for FE customers occur during the five one-hour intervals when demand on FE’s zonal grid is at its highest. The Transmission CP for AEP customers occurs during the one-hour interval when demand on AEP’s zonal grid is at its highest.

The tables below list PJM’s and FE’s five highest loads and AEP’s single highest load this year, as well as the day and time of each occurrence. This is based on preliminary data.

Table 1: Five Highest Loads for PJM through July 29, 2026

Table 2: Five Highest Loads for ATSI Zone through July 29, 2026

Table 3: Single Highest Load for AEP Zone through July 29, 2026

The summer CP season ends on September 30, which is still more than two months away. However, we believe there is a strong probability that many of the PJM and ATSI loads listed in the tables above – particularly the top three – will be CPs at the end of summer. Similarly, there is a strong likelihood that AEP’s load on July 1, 2026 will set AEP Zone’s 1CP for the November 1, 2025, through October 31, 2026 CP year.

Brakey Energy will continue monitoring weather and load forecasts and will issue alerts to participating clients as warranted. If you are a Brakey Energy client and would like to receive these alerts, please contact Catherine Nickoson.

AES Ohio Files Stipulation and Recommendation in First Forecasted Rate Case

On July 21, 2026, AES Ohio, PUCO Staff, and 16 other parties filed an unopposed Stipulation and Recommendation (“Stipulation”) with the Public Utilities Commission of Ohio (PUCO) that would resolve the utility’s three-year rate plan proceeding for 2027 through 2029. If approved, the settlement would increase AES Ohio’s annual distribution revenue requirement by approximately $124.0 million in 2027, $30.5 million in 2028, and $21.3 million in 2029.

Bill impacts are expected to be moderate since several existing riders would be rolled into base distribution rates and reset to zero beginning January 1, 2027. The resulting rates would remain subject to annual true-ups based on AES Ohio’s actual investments, revenues, and expenses.

Of particular importance to commercial and industrial customers, the Stipulation would establish a new Curtailable Use Reliability Benefit (CURB) Program that would commence on January 1, 2028. CURB, modeled after FirstEnergy’s Economic Load Response Program Rider, would provide qualifying energy-intensive customers with a monthly credit of $6.00 per kW of curtailable load, less a $150 monthly administrative charge, in exchange for reducing load during emergency curtailment events called by AES Ohio or PJM.

For purposes of R.C. 4909.192(A), an ‘energy-intensive customer’ was recently defined as one that meets any one of the following qualifications: (i) the customer has billing demand greater than 25 MW at a single location, (ii) self-assesses the kWh tax under R.C. 5727.81, or (iii) has peak demand in excess of 1 MW and can curtail or self-generate over 70% of its monthly peak electricity demand within 120 minutes.

CURB program capacity would be capped pro-rata at 25 MW during 2028 and would increase to 50 MW during 2029. Data center tariff customers would not be eligible except through a separate PUCO-approved reasonable arrangement.

If you have any questions about AES Ohio’s Stipulation or the CURB program awaiting PUCO approval, please contact Katie Emling.

Residential Corner

Sky-high capacity prices coupled with increased data center demand have kept residential rates at the highest levels in recent memory. We recommend customers with an approaching contract expiration migrate to a 6-month offer with Direct Energy for 9.09¢/kWh.

Regarding natural gas, Brakey Energy has long viewed the distribution utilities’ Standard Choice Offer (SCO) as a prudent default strategy for supply. However, this approach can produce volatile bill outcomes, like the wild ride many customers experienced during the extreme cold this past winter. With natural gas settlement prices since remaining reasonable, and the commodity itself trading at compelling values relative to power, customers on the SCO are likely seeing manageable bills.

Natural Gas Market Update

The NYMEX price for July settled at $3.231 per Million British Thermal Units (MMBtu) on June 26, 2026. This price is up 6.3% from the June 2026 price of $3.040 per MMBtu. This settlement price is used to calculate July gas supply costs for customers that contract for a NYMEX-based index gas product.
The graph below shows the year-over-year monthly NYMEX settlement prices for 2022, 2023, 2024, 2025, and 2026 year to date. Prices shown are in dollars per MMBtu of natural gas.

Figure 1: NYMEX Monthly Natural Gas Settlement Prices

Figure 2 below shows the historical July 30, 2024 through July 30, 2026 Around the Clock (ATC) forward NYMEX natural gas prices in dollars per MMBtu for the balance of 2026 (labeled as “Custom Strip”) and calendar years 2027, 2028, 2029, and 2030.

Figure 2: ATC Calendar Year NYMEX Natural Gas Prices

*Pricing courtesy of Direct Energy Business.

The forward natural gas market remains in a pronounced state of contango through the balance of 2026 and into calendar year 2029. Strong domestic production and temporary maintenance-related outages at key Liquefied Natural Gas (LNG) export facilities have helped soften forward prices through 2027, while outer years have remained relatively flat.

Although much of the country has experienced record-setting heat this summer, forward natural gas prices have continued to trend lower, as domestic natural gas demand (excluding LNG exports) has remained generally in line with prior summers. Combined with robust production, this lack of meaningful demand growth has contributed to continued softness in the forward market through 2027.

Electricity Market Update

Figure 3 below shows the historical July 30, 2024 through July 30, 2026 ATC forward power prices in dollars per Megawatt hour (MWh) for the balance of 2026 (labeled as “Custom Strip”) and calendar years 2027, 2028, 2029, and 2030 for the AD Hub.

Figure 3: ATC Calendar Year Power Prices for the AD Hub

* Pricing courtesy of Direct Energy Business.

Over the course of 2026, the forward power market has largely decoupled from the forward natural gas market. This breakdown in the historical correlation between the two markets reflects a widening imbalance between rapidly growing electricity demand and the pace of new gas-fired generation development.

When forecasted PJM grid demand exceeds 150 GW, PJM has been increasingly forced to dispatch higher-cost generation resources and, at times, demand response to maintain system reliability. Extreme spot prices have resulted from this imbalance, and forward power prices have traded higher as a result.

The capacity price cap discussed above may be amplifying this dynamic. When the capacity auction clears at an administratively capped price, the scarcity value the cap suppresses does not disappear. Rather, revenue that suppliers would typically recoup through the capacity market appears to be leaking into the energy market, with sellers reflecting that shortage value in forward energy prices.

Because PJM must rely on higher-cost resources to serve the last increment of load during the highest-demand hours, forward power prices have not softened alongside forward natural gas prices. Instead, the forward power market has retained a significant risk premium, reflecting uncertainty surrounding future supply adequacy as large new loads continue to seek interconnection while new generation additions lag behind. Consequently, forward power prices have become increasingly sensitive to demand forecasts as well as weather forecasts and patterns, while becoming less responsive to movements in the natural gas market.

The post Ohio Energy Report: July 2026 appeared first on Brakey Energy.

The inaugural Ohio Energy Leadership Summit (“Summit”) took place on Tuesday, June 16, at the Hilton Cleveland Downtown, bringing together approximately 140 commercial and industrial energy users, electric and gas distribution utility executives, legislators, and other energy professionals for a full day of discussion on Ohio’s evolving energy landscape.

Presented by the Ohio Energy Leadership Council (OELC) and co-sponsored by BakerHostetler and Dynegy, the Summit was designed as a practical forum for large energy users to hear directly from industry leaders on utility rates, reliability, infrastructure investment, and strategies for managing rising energy costs.

The day began with welcoming remarks from Renee Rambo of Johns Manville, a member of OELC’s Board of Directors, framing the Summit’s purpose: fostering collaborative dialogue among customers, utilities, and other stakeholders at a time of significant change in Ohio’s energy markets. The first panel focused on Ohio electric and gas utilities, centered on reliability, modernization, infrastructure investment, and how commercial and industrial customers may be affected by future utility spending.

Throughout the day, sessions addressed electric and natural gas rate trends, transmission and capacity costs, utility programs, and customer strategies for controlling costs. Brakey Energy team members including Matt Brakey, President and Katie Emling, Energy Analyst, presented in three of the Summit’s breakout sessions. The Summit also provided valuable networking time, connecting attendees with peers, service providers, and policymakers facing many of the same challenges.

On behalf of OELC, Brakey Energy would like to thank all those who attended and contributed to making this inaugural Summit a successful day of education, advocacy, and networking.

Figure 1. Ohio Electric and Gas Utility Panel Discussion at the Ohio Energy Leadership Summit.

Left to right: Matt McKenzie (AEP Ohio), Josh Davis (Enbridge Gas Ohio), Russ Lang (Ferroglobe), Renee Rambo (Johns Manville), David Proano (BakerHostetler), and Matt Brakey (Brakey Energy).

FirstEnergy Files Proposed Data Center Tariff

On June 12, 2026, Ohio Edison, The Cleveland Electric Illuminating Company, and The Toledo Edison Company filed an application with the Public Utilities Commission of Ohio seeking approval of a new Data Center Tariff, Schedule DCT. The filing follows a PUCO directive requiring the FirstEnergy (FE) utilities to create a separate class for data centers to help ensure that future costs are properly allocated to those customers and not shifted to other nonresidential and residential customers.

FE’s proposed tariff would apply to data center operators, including mobile data centers and cryptocurrency mining facilities. The tariff would require data center customers to take service under the normally applicable rate schedule for their service voltage, but with additional protections such as long-term contract requirements, collateral tied to the cost of new infrastructure, and a minimum monthly billing demand equal to the greater of actual usage or 85% of contract capacity. New data center load would also not be eligible to participate in FirstEnergy’s Non-Market Based Services Rider transmission pilot program.

The proposal is similar in concept to AEP Ohio Power Company’s (Ohio Power) Data Center Tariff, which went into effect in July 2025. Both address the same issue: data centers can create large infrastructure needs, and utilities want assurance that the data center customer, not other customers, will be responsible for costs if a project does not materialize or fails to use its reserved capacity.

However, there are important differences between FE’s proposed DCT and Ohio Power’s Schedule DCT. Ohio Power’s tariff is generally focused on large new or expanded data center loads of 25 MW or more, while FE’s proposal does not include a stated minimum load threshold. FE also proposes a minimum contract term generally equal to the load ramp period plus ten years, compared with Ohio Power’s load ramp period plus eight years. FE’s filing reflects a continued move by Ohio utilities toward specialized rate structures for data centers, balancing economic development against protections for existing customers.

Ohio Energy Costs Expected to Remain Elevated

A recent Crain’s Cleveland Business article published on June 15, 2026, warned that Ohio’s electricity costs have risen sharply and are likely to remain elevated or even continue rising in the years ahead. Retail electric prices for Ohio Edison customers in Northeast Ohio have essentially doubled over the last five years, while utilities and grid operators are planning billions of dollars in additional investments to maintain reliability and serve growing demand.

A major driver is the rapid growth of data centers, particularly newer AI facilities that require enormous amounts of power around the clock. Matt Brakey, President of Brakey Energy, explained that while earlier cryptocurrency-related loads were often flexible and could reduce usage during grid stress, many AI data centers are “24/7 operations” with far less ability to curtail. That lack of flexibility is placing upward pressure on costs even as the supply side faces its own challenges.

The changing generation mix is another key factor. As older coal-fired power plants have retired, replacement resources have not always provided the same dispatchable capability during periods of high demand. Brakey emphasized that the grid still needs resources that can operate when demand is highest, noting that wind and solar often fall short during peak demand hours because they are “not dispatchable.” This has grown more important as PJM’s capacity prices have risen sharply, reflecting a tighter supply and demand balance across the regional grid.

Adding new generation and transmission infrastructure will take time. Brakey noted that new dispatchable thermal generation can take years to come online, and that supply chain constraints are creating “multi-year backlogs” for critical equipment. In short, even with agreement that more supply is needed, building it may take years.

For commercial and industrial customers, the takeaway is clear: elevated energy costs are unlikely to be temporary. Customers that actively manage peak demand, evaluate procurement strategies, monitor utility rate cases and tariff changes, and participate in demand response or other cost-management opportunities will be better positioned to control costs.

FirstEnergy Announces Updates to SSO Rates

Compared to one year ago, July 1 electric costs for FirstEnergy (FE) customers that take electric generation service under Ohio Edison’s (OE), the Illuminating Company’s (CEI), and Toledo Edison’s (TE) Standard Service Offer (SSO) will be approximately 1.15¢ per kWh higher on average across all FE companies and rate schedules. The SSO is the default rate charged by the utility for generation services to customers that do not contract with an alternative supplier. FE’s SSO generation rates are higher in the three summer months of June, July, and August than in the other nine months.

The tables below compare the current and July 1 SSO rates per kWh for OE, CEI, and TE Residential (RS), Secondary (GS), Primary (GP), Subtransmission (GSU), and Transmission (GT) rate schedules. These rates will change again on September 1.

Table 1: OE SSO Rates

Table 2: CEI SSO Rates

Table 3: TE SSO Rates

In our experience, these SSO rates include a healthy supplier risk premium compared to competitive market options. If you are a nonresidential customer nearing the end of your current electric generation agreement and do not wish to default to FE’s standard service offer, please contact  Brandon Powers.

Residential Corner

Sky-high capacity prices coupled with increased data center demand have kept residential rates at the highest levels in recent memory. We recommend customers with an approaching contract expiration migrate to a 12-month offer with Better Buy Energy for 9.19¢/kWh.

Regarding natural gas, Brakey Energy has long viewed the distribution utilities’ Standard Choice Offer (SCO) as a prudent default strategy for supply. However, this approach can produce volatile bill outcomes, like the wild ride many customers experienced during the extreme cold earlier this winter. With natural gas settlement prices since remaining reasonable, customers on the SCO are likely seeing manageable bills.

Natural Gas Market Update

The NYMEX price for June settled at $3.040 per Million British Thermal Units (MMBtu) on May 27, 2026. This price is up 18.8% from the May 2026 price of $2.559 per MMBtu. This settlement price is used to calculate June gas supply costs for customers that contract for a NYMEX-based index gas product.

The graph below shows the year-over-year monthly NYMEX settlement prices for 2022, 2023, 2024, 2025, and 2026 year to date. Prices shown are in dollars per MMBtu of natural gas.

Figure 2: NYMEX Monthly Natural Gas Settlement Prices

Figure 3 below shows the historical June 29, 2024 through June 29, 2026 Around the Clock (ATC) forward NYMEX natural gas prices in dollars per MMBtu for the balance of 2026 (labeled as “Custom Strip”) and calendar years 2027, 2028, 2029, and 2030.

Figure 3: ATC Calendar Year NYMEX Natural Gas Prices

*Pricing courtesy of Direct Energy Business.

Forward natural gas prices for the balance of 2026 have remained volatile but rangebound around their 2-year lows for the past two months. While trends in the oil market suggest the Iran Conflict is nearing resolution, forward gas prices for the balance of the year are likely to remain sensitive to any new developments, along with ever-changing summer weather forecasts.

For calendar year 2027 and beyond, forward gas prices have also traded lower over the past two months, but with less volatility than the balance of 2026. Domestic gas production has rebounded after a brief dip in late April and early May and now sits near record levels. Gas in storage sits at a slight surplus to the 5-year average, and the U.S. Energy Information Administration (EIA) projects healthy storage heading into winter. This has helped soften forward gas prices in all outlier years, especially 2027, now trading near 2-year lows.

Electricity Market Update

Figure 4 below shows the historical June 29, 2024 – June 29, 2026 ATC forward power prices in dollars per Megawatt hour (MWh) for the balance of 2026 (labeled as “Custom Strip”) and calendar years 2027, 2028, 2029, and 2030 for the AD Hub.
 
Figure 4: ATC Calendar Year Power Prices for the AD Hub

*Pricing courtesy of Direct Energy Business.

Forward power prices have continued to trade at or near multi-year highs, not only for the balance of 2026, but for outlier years as well, and in contrast to the forward gas market, which has trended lower since winter’s end.

As data center loads have begun materializing on the grid, rather than existing only as projected future demand, PJM’s supply-demand fundamentals have evolved. Although natural gas prices remain relatively low, growing electricity demand and tightening reserve margins have increased the likelihood that higher-cost generation resources will be needed to satisfy peak demand and maintain required operating reserves. This is contributing to higher locational marginal prices (“LMPs”) and, in turn, helping to keep forward power prices elevated.

Historically, efficient combined-cycle natural gas generators have frequently set the marginal price. Today, however, expectations of stronger load growth, tighter reserve margins, and greater reliance on higher-cost resources during peak conditions have reduced the degree to which forward power prices move in tandem with natural gas prices. These developments help to explain why forward power prices have remained near multi-year highs despite the recent softening in the forward natural gas market.

The post Ohio Energy Report: June 2026 appeared first on Brakey Energy.

The countdown has officially begun. We are now just two weeks away from the inaugural Ohio Energy Leadership Summit taking place June 16 at the Hilton Cleveland Downtown, and final preparations are underway for what promises to be an outstanding educational and networking event for Ohio energy users.

The final program agenda with a complete schedule of the day’s events, featuring a full lineup of confirmed speakers and session timings at the Cleveland Hilton Downtown.

As a reminder, Brakey Energy clients receive complimentary registration to attend the Summit. If you have not yet registered and would like to participate, feel free to reach out to Catherine Nickoson for the registration code.

With more than 100 attendees already registered, the Summit is shaping up to be a premier gathering of business leaders, energy directors and professionals from top organizations are attending, including representatives from Ferroglobe, Marathon Petroleum, Liberty Casting, Progressive Insurance, Ferragon Corporation, BDG Wraptite, McGean, First Quality Enterprises, Cenovus Energy, Nordson Corporation, NiSource (Columbia Gas), Dynegy Energy Services, Johns Manville, AEP Ohio, FirstEnergy, Greater Cleveland Partnership, Caterpillar, NRG, Sauder Woodworking, Presrite Corporation, Iten Industries, Federal Metal, Airgas, Enbridge Gas Ohio, Vallourec Steel, Great Lakes Cheese, Ampica, IGS Energy, Metallus, Ford, Brakey Energy, Case Western University, Greater Cleveland Regional Transit Authority, and Charter Steel, and many others are expected to attend.

Valet parking at the Hilton Cleveland Downtown is complimentary and included with registration.

We look forward to seeing many of our clients and industry partners on June 16 for a day of valuable insights, meaningful discussions, and networking opportunities.

The post BE OELC Summit Update appeared first on Brakey Energy.

The start of this summer’s capacity cost management period is less than one week away. For customers on generation contracts that pass through capacity charges, these charges are based on the customer’s metered demand during the five one-hour intervals when demand on PJM’s electric grid is at its highest. These intervals—known as Coincident Peaks (CPs)—typically occur during June, July, August, or September. A customer’s average demand during these CPs determines its capacity charges for the next delivery year, which runs from June 1, 2027 through May 31, 2028.

PJM’s capacity rate will increase from $270.43/Megawatt (MW)-day to $329.08/MW-day on June 1, 2026. Based on the Base Residual Auction results, the 2027/2028 Delivery Year capacity price is $333.44/MW-day. We expect prices to remain elevated in future delivery years, but capped based on the Federal Energy Regulatory Commission’s approved extension of the existing price collar.

To help manage capacity charges for the 2027/2028 delivery year, customers can take steps to reduce demand during this summer’s CPs. Brakey Energy supports these efforts through our CP alert notification system, which allows participating customers to reduce electric usage during forecasted peak periods.

We will soon be issuing a CP forecasting report to clients enrolled to receive CP alerts this summer. The report outlines historic CP trends and provides our summer peak load forecasts.

If you are not enrolled to receive these alerts and would like to participate, please email Catherine Nickoson. Please also contact Catherine to change your registration preferences, including adding or deleting which employees receive the alerts. This is a service available only to Brakey Energy clients.

Take Steps This Summer to Mitigate Your 2027 Transmission Costs

While managing capacity costs is important, many customers can achieve comparable savings through transmission cost management. Eligible FirstEnergy (FE) customers may opt out of the utility’s transmission-related riders and instead pay for transmission and related services through their certified retail electric service (CRES) suppliers, based on their Network Service Peak Load (NSPL). Participation in FE’s transmission pilot program is currently limited to customers identified in the ESP IV case, those who gained access during the brief expansion of the program under ESP V, or received approval for enrollment from a Reasonable Arrangement application with the Public Utilities Commission of Ohio.

American Electric Power (AEP) offers a similar transmission pilot program under its modified ESP III. However, unlike FE, AEP bills customers directly rather than through their CRES providers. Participation is currently limited to customers grandfathered into the program in July 2024 or those who enrolled during the December 2024 expansion under AEP’s ESP V. Customers interested in joining the program in April 2027 will have the opportunity to enroll through a first-come, first-served queue that reopens on December 1, 2026.

For FE and AEP customers currently enrolled in a transmission pilot program—or those planning to join AEP’s program in April 2027—transmission charges for next year will be based on each customer’s demand during the 2026 Transmission Coincident Peaks (CPs).

For AES Ohio non-residential customers served at primary voltage and above, as well as secondary-voltage non-residential customers who opt in, 2027 transmission charges will be based on demand during AES Ohio’s single CP set this summer.

To help reduce transmission charges, eligible FE and AEP pilot program customers—as well as applicable AES Ohio customers—can take steps to lower demand during Transmission CPs. Brakey Energy supports these efforts through our CP alert notification system. Participating clients receive alerts in advance of anticipated CPs and can reduce electric usage during those periods. This service is available exclusively to Brakey Energy clients.

If you are a participating client that would like to change your registration preferences, including adding or deleting which employees receive the alerts, please email Catherine Nickoson.

FirstEnergy Files First Three-Year Base Rate Plan with PUCO

FE and its Ohio utilities (Ohio Edison, the Illuminating Company, and Toledo Edison) filed their first-ever Three-Year Rate Plan (TYRP) with the Public Utilities Commission of Ohio (PUCO) on May 22, 2026. This application marks a significant shift in how electric distribution rates will be set in Ohio going forward.

The filing was made under Ohio’s recently enacted utility ratemaking framework via House Bill 15, which replaces traditional backward-looking rate cases with a forward-looking, multi-year approach. Instead of recovering only historical spending, utilities can now seek approval for projected investments and planned distribution system upgrades over a three-year horizon.

According to FE, the proposal is designed to support continued investment in reliability, grid modernization, vegetation management, and customer service enhancements across northern Ohio. The company said it plans to invest approximately $800 million annually in poles, wires, substations, and grid technology improvements throughout the TYRP period.

The case will now proceed through the PUCO review process including testimony, discovery, staff audits, and third-party intervention. Stakeholders will closely evaluate forecasted capital spending assumptions, reliability and outage reduction metrics, customer affordability impacts, earnings and return on equity levels, and proposed reconciliation and annual true-up mechanisms. Brakey Energy clients will be represented in this case through the Ohio Energy Leadership Council.

A final PUCO decision is expected sometime in 2027, with approved rates likely phased in annually over the three-year plan period.

Ohio Energy Leadership Summit to Take Place on June 16, 2026 in Cleveland

The inaugural Ohio Energy Leadership Summit: The Definitive Commercial & Industrial Utility Rate and Energy Strategy Conference will take place on Tuesday, June 16 at the Hilton Cleveland Downtown (100 Lakeside Avenue East, Cleveland, Ohio 44114).

The conference is scheduled to kick off at 8:45 AM and conclude at 6:00 PM. It will feature keynote perspectives, executive utility panels, and focused breakout sessions covering critical topics including grid reliability, distribution investments and rate cases, PJM market developments, natural gas supply trends, and strategies for managing energy costs in an evolving regulatory environment.

The program is designed for commercial and industrial energy consumers and is presented by the Ohio Energy Leadership Council, with sponsorship support from BakerHostetler and Dynegy (powered by Vistra).

Brakey Energy team members will be participating in three workshops or interactive panels during the conference.

You can view the full agenda, speaker lineup, and register through the conference event page. Brakey Energy clients and members of the Ohio Energy Leadership Council will receive complimentary registration. Other large energy users are able to access discounted registration. If you’re interested in attending, feel free to reach out to Catherine Nickoson for the registration code.

Residential Corner

Sky-high capacity prices coupled with geopolitical turmoil has kept residential rates at the highest levels in recent memory. We recommend customers with an approaching contract expiration migrate to a 12-month offer with AEP Energy for 9.39¢/kWh.

Regarding natural gas, Brakey Energy has long viewed the distribution utilities’ Standard Choice Offer (SCO) as a prudent default strategy for supply. However, this approach can produce volatile bill outcomes—like the wild ride many customers experienced during the extreme cold earlier this winter. With natural gas settlement prices easing, many of our friends on the SCO can now safely unbuckle their seatbelts, at least until we need to strap in again next winter.

Natural Gas Market Update

The NYMEX price for May settled at $2.559 per Million British Thermal Units (MMBtu) on April 28, 2026. This price is down 17.3% from the April 2026 price of $3.095 per MMBtu. This settlement price is used to calculate May gas supply costs for customers that contract for a NYMEX-based index gas product.

The graph below shows the year-over-year monthly NYMEX settlement prices for 2022, 2023, 2024, 2025, and 2026 year to date. Prices shown are in dollars per MMBtu of natural gas.

Figure 1: NYMEX Monthly Natural Gas Settlement Prices

Figure 2 below shows the historical May 27, 2024 through May 27, 2026 Around the Clock (ATC) forward NYMEX natural gas prices in dollars per MMBtu for the balance of 2026 (labeled as “Custom Strip”) and calendar years 2027, 2028, 2029, and 2030.

Figure 2: ATC Calendar Year NYMEX Natural Gas Prices

*Pricing courtesy of Direct Energy Business.

Forward natural gas prices over the past month have been little changed overall, for both the short-term and long-term. Domestic production has eased off the all-time highs that were observed over the winter, but remains robust. Meanwhile, liquefied natural gas (LNG) exports have reached new records as the Golden Pass export hub has come online and steadily increases its export capacity.

Market participants across all energy markets are paying close attention to developments in the Iran Conflict and the potential re-opening of the Strait of Hormuz, which has effectively been shuttered since the conflict began in early March. The potential for elevated volatility in the forward gas market (and all energy markets) remains as the conflict continues.

Electricity Market Update

Figure 3 below shows the historical May 27, 2024 – May 27, 2026 ATC forward power prices in dollars per Megawatt hour (MWh) for the balance of 2026 (labeled as “Custom Strip”) and calendar years 2027, 2028, 2029, and 2030 for the AD Hub.

Figure 3: ATC Calendar Year Power Prices for the AD Hub

*Pricing courtesy of Direct Energy Business.

Forward power prices have broken their correlation to forward natural gas prices in recent weeks; while forward gas has traded down since the start of the Iran Conflict, forward power prices have been little changed overall – though they have softened from the recent multi-year highs seen in April. Forward power prices tend to be “sticky” compared to other commodities because electricity cannot be cost-effectively stored in large quantities.

As we progress into summer, market participants will be analyzing load and weather forecasts as data center load is expected to have a sizeable impact on grid conditions – a fundamental factor that has likely contributed to forward power prices continuing to trade with a risk premium compared to forward gas.

The post Ohio Energy Report: May 2026 appeared first on Brakey Energy.

The inaugural Ohio Energy Leadership Summit: The Definitive Commercial & Industrial Utility Rate and Energy Strategy Conference will take place on Tuesday, June 16 at the Hilton Cleveland Downtown (100 Lakeside Avenue East, Cleveland, Ohio 44114).

The conference is scheduled to kick off at 8:30 AM and conclude at 6:00 PM. It will feature keynote perspectives, executive utility panels, and focused breakout sessions covering critical topics including grid reliability, distribution investments and rate cases, PJM market developments, natural gas supply trends, and strategies for managing energy costs in an evolving regulatory environment.

The program is designed for commercial and industrial energy consumers and is presented by the Ohio Energy Leadership Council, with sponsorship support from BakerHostetler and Dynegy (powered by Vistra).

Brakey Energy team members will be participating in three workshops or interactive panels during the conference.

You can view the full agenda, speaker lineup, and register through the conference event page. Brakey Energy clients and members of the Ohio Energy Leadership Council will receive complimentary registration. Other large energy users are able to access discounted registration. If you’re interested in attending, feel free to reach out to Catherine Nickoson for the registration code.

AEP Ohio’s New Base Rates Went Into Effect April 10

On April 1, 2026, the PUCO issued its Opinion and Order in AEP Ohio’s May 2025 Base Distribution Rate Case (Case No. 25-392-EL-AIR et al). In its decision, the PUCO adopted the join stipulation and recommendation in the case that was filed on January 7, 2026. The settlement established a return on equity of 9.84% and a base distribution revenue increase of approximately $11 million. This is a fraction of the $97 million that AEP Ohio sought in its Application.

Costs previously recovered through AEP Ohio’s Enhanced Service Reliability Rider (ESRR), Distribution Investment Rider (DIR), and Economic Development Cost Recovery Rider (EDCRR) were rolled into recovery through the utility’s base distribution rates. Therefore, although base distribution rates increased for General Service customers, the ESRR, DIR, and EDCRR rates decreased. The new base distribution rates that went into effect on April 10 are summarized below according to rate schedule.

Table 1. Base Distribution Rate Updates for Non-Demand Metered GS-1 Customers

Table 2. Base Distribution Rate Updates for General Service Secondary, Primary, and Transmission Customers

Data Center Tariff (DCT) customers will be subject to the new base distribution rates in addition to a new $20,000 per month supplemental charge for DCT customers served at Transmission voltage. This is a supplemental charge that will not apply to existing load, is not a base distribution rate, and will not be included in the calculations for rider charges billed on a percentage of base distribution rates.

As part of the approved settlement in the case, AEP Ohio will also refund approximately $105 million to customers over an 18-month period as a result of the Tax Cuts and Jobs Act, contributing to a net revenue decrease of $58.7 million.

If you are an AEP Ohio customer and would like to better understand how your distribution costs have been impacted through this rate case, please contact Kate Emling.

Ohio Supreme Court Rules on Landmark Submetering Case

On April 22, 2026, the Ohio Supreme Court (“the Court”) issued its Slip Opinion In re Complaint of Ohio Power Co. v. Nationwide Energy Partners, L.L.C. The Court’s decision fundamentally reshapes how electric submetering is treated in Ohio and has important implications for landlords, tenants, and commercial/industrial (C&I) customers.

In its ruling, the Court concludes that third-party submetering companies, like Nationwide Energy Partners (NEP), are “public utilities” under Ohio law because they purchase electricity and resell it directly to end users, namely tenants.

The Court rejected the prior position of the PUCO, which had found that submetering companies were not utilities and therefore not subject to regulation. Instead, the Court applied a plain-language interpretation of Ohio statutes and concluded that: (1) tenants are “consumers” of electricity, even in submetered properties, (2) submetering providers are “engaged in the business of supplying electricity” because they buy, price, bill, and control electric service delivery, and (3) as a result, these companies fall under PUCO jurisdiction and must comply with utility regulations.

This decision closes a long-standing regulatory gap by bringing large-scale submetering companies under PUCO oversight. For Ohio’s energy market, it introduces greater consumer protection and regulatory clarity, but also increased compliance obligations for landlords and third-party energy providers. C&I customers pursuing non-traditional energy structures, such as behind-the-meter energy solutions, microgrids, or energy resale arrangements, should closely evaluate how this expanded definition of a public utility could affect their strategies going forward.

The case was remanded back to PUCO to determine how regulation should be applied and to revisit related issues, including service territory rights and certification requirements. We will reach out to our impacted clients once the PUCO issues regulatory clarity. If you have any questions about how you may be impacted by this recent ruling, please contact Katie Emling.

Residential Corner

Sky-high capacity prices coupled with geopolitical turmoil has kept residential rates at the highest levels in recent memory. We recommend customers with an approaching contract expiration migrate to a 12-month offer with AEP Energy for 9.39¢/kWh.

Regarding natural gas, Brakey Energy has long viewed the distribution utilities’ Standard Choice Offer (SCO) as a prudent default strategy for supply. However, this approach can produce volatile bill outcomes—like the wild ride many customers experienced during the extreme cold earlier this winter. With natural gas settlement prices easing, many of our friends on the SCO can now safely unbuckle their seatbelts, at least until we need to strap in again next winter.

Natural Gas Market Update

The NYMEX price for April settled at $3.095 per Million British Thermal Units (MMBtu) on March 27, 2026. This price is up 4.2% from the March 2026 price of $2.969 per MMBtu. This settlement price is used to calculate April gas supply costs for customers that contract for a NYMEX-based index gas product.

The graph below shows the year-over-year monthly NYMEX settlement prices for 2022, 2023, 2024, 2025, and 2026 year to date. Prices shown are in dollars per MMBtu of natural gas.

Figure 1: NYMEX Monthly Natural Gas Settlement Prices

Figure 2 below shows the historical April 29, 2024 through April 29, 2026 Around the Clock (ATC) forward NYMEX natural gas prices in dollars per MMBtu for the balance of 2026 (labeled as “Custom Strip”) and calendar years 2027, 2028, 2029, and 2030.

Figure 2: ATC Calendar Year NYMEX Natural Gas Prices

*Pricing courtesy of Direct Energy Business.

Since the start of the Iran conflict in March, forward natural gas prices have moved lower, diverging from oil and gasoline, which have trended upward. This decline in gas prices can largely be attributed to four factors: the relative energy independence of the U.S., mild weather at the end of winter, strong early-season storage injections that have pushed inventory levels above the five-year average, and expectations that higher oil prices will eventually drive increased oil production, bringing additional natural gas supply with it due to associated gas from oil drilling.

Forward natural gas prices for the remainder of 2026 have declined the most, reflecting the strongest impact from these market factors. Prices for calendar years 2027 and 2028 have also trended downward, hovering at or near two-year lows. In contrast, prices beyond 2028 have been less affected, as longer-term pricing is driven more by broader fundamentals, particularly expectations for global liquefied natural gas (LNG) production and export capacity.

Electricity Market Update

Figure 3 below shows the historical April 29, 2024 – April 29, 2026 ATC forward power prices in dollars per Megawatt hour (MWh) for the balance of 2026 (labeled as “Custom Strip”) and calendar years 2027, 2028, 2029, and 2030 for the AD Hub.

Figure 3: ATC Calendar Year Power Prices for the AD Hub

*Pricing courtesy of Direct Energy Business.

Although forward natural gas prices have softened markedly since the start of the Iran Conflict, this has not been the case in the forward power market. Forward power prices tend to be “sticky” compared to other commodities because electricity cannot be cost-effectively stored in large quantities. Data centers are contributing to large increases in load forecasts on the grid, and the resulting risk premium in forward power prices has been buoying the market across all terms, even with natural gas prices falling to two-year lows.

The post Ohio Energy Report: April 2026 appeared first on Brakey Energy.

On March 20, 2026, Ohio Senate Bill 103 (SB 103) went into effect after being signed into law by Governor Mike DeWine on December 19, 2025. SB 103 introduces structural changes to natural gas ratemaking, with a focus on large-load customer treatment, cost recovery mechanisms, and regulatory timelines. The legislation builds on reforms established under prior energy legislation and signals a continued shift toward forward-looking rate design and economic development support.

Key components of SB 103 that will impact natural gas rate design in Ohio include:

• Flexibility for large-load customers to enter into custom rate arrangements with local distribution companies, subject to approval from the Public Utilities Commission of Ohio (PUCO);
• Increased protections for existing customers from subsidizing large-load infrastructure investments;
• A shift away from gas utility rider-based recovery mechanisms and a greater reliance on base rates;
• Acceptance of forward-looking cost projections, or “forecasted test years” rather than historical test years to establish base rates;
• Redefined, accelerated PUCO deadlines for issuing orders in gas rate cases; and
• Rate case cadence that mandates utilities file rate cases at least every three years.

While SB 103 will not immediately change rates, it will influence how rates are structured, updated, and negotiated going forward, which will make proactive engagement in rate cases all the more important for commercial and industrial customers in Ohio.

Electric Distribution Utilities to File Annual Reliability Reports March 31

On January 22, 2026, the PUCO finalized a new process for annual statewide electric reliability reporting, as required under House Bill 15. The framework is intended to improve transparency into utility performance and introduces circuit-level reliability data, which is a meaningful development for large commercial and industrial (C&I) customers.

Under the new process, Ohio electric distribution utilities, including AEP Ohio (AEP), FirstEnergy (FE), AES Ohio, and Duke Energy Ohio must submit their first annual report containing detailed reliability data to the PUCO by March 31, 2026. PUCO Staff will then issue a draft statewide report for stakeholder comment before publishing a final version.

The reporting will include circuit-level outage frequency and duration metrics, identification of the worst-performing circuits and substations, and tracking of planned reliability upgrades. Circuits with “persistent reliability issues” will be defined as those ranking in the worst-performing 8% for three consecutive years, creating a clear benchmark for ongoing performance concerns.

For C&I customers, this new reporting structure provides greater visibility into localized reliability performance, enabling:

• More precise identification of outage-related risks;
• Data-driven discussions with utilities on service quality; and
• Stronger support for escalation where chronic issues exist

Customers experiencing recurring outages, such as those on consistently underperforming circuits, will now have access to the data needed to better understand and address these challenges. Brakey Energy will monitor these filings and help clients interpret results and identify opportunities to mitigate reliability risks.

Transmission Charges Changing for FirstEnergy Customers on April 1, 2026

The Non-Market-Based Services Rider (Rider NMB) rates are set to change April 1, 2026 for residential and non-residential customers of FE’s three Ohio operating companies: Ohio Edison (OE), the Illuminating Company (CEI), and Toledo Edison (TE). Rider NMB recovers FE’s non-market-based costs for transmission and ancillary services, with the largest component being PJM’s Network Integration Transmission Service (NITS) charge.

Beginning April 1, the Rider NMB rate for nonresidential customers will range from $4.8415 per kW (for TE GS customers) to $10.9703 per kVa (for TE GT customers).

Current and April 1, 2026 Rider NMB rates for OE, CEI, and TE Residential (RS), Secondary (GS), Primary (GP), Subtransmission (GSU), and Transmission (GT) rate schedules are shown in the tables below. Rates are per kilowatt hour (kWh) for RS customers and per kilowatt (kW) or kilovolt-ampere (kVa) for GS, GP, GSU, and GT customers. As it often the case, there will be material variance in percent changes between the different operating companies and rate schedules.

Table 1: OE Rider NMB Rates

Table 2: CEI Rider NMB Rates

Table 3: TE Rider NMB Rates

Clients that are participating in FE’s transmission pilot program are opted out of paying the NMB rider. If you have any questions about this pilot program or how the new NMB rates will impact your electric costs, please contact Katie Emling.

AEP Ohio’s Transmission Rates Changing April 1, 2026

Earlier this month, the PUCO approved rate updates to take effect beginning April 1, 2026 for AEP’s Basic Transmission Cost Rider (BTCR). With the sole exception of the demand based rate for transmission voltage customers, BTCR charges will be increasing, and fairly significantly at that. We believe that it is large data center load served at the transmission voltage level that has not only kept a lid on this rate, but actually reduced it by approximately 6%.

Select interval-metered customers, including Brakey Energy clients, may have elected to participate in a transmission pilot program. For participants, the demand portion of BTCR charges is calculated based on the customer’s load during AEP’s 1CP, as opposed to the default method, which uses monthly billed demand. Demand-based BTCR rates for customers participating in AEP’s transmission pilot program will increase by approximately 9.3%.

It’s also worth noting that the demand based rate for transmission level customers in the pilot program is more than twice as high as the same rate for transmission level customers not enrolled in the pilot program. This means that the stakes are even higher for pilot customers to successfully manage their load during the AEP single coincident peak.

The tables below show the current and April 1, 2026 BTCR kWh and kW-based rates for non-transmission pilot program customers and transmission pilot program customers of AEP Ohio. The percentage change for each rate is also summarized.
 
Table 4: Current and April 1, 2026 BTCR Rates for AEP Ohio Customers

Table 5: Current and April 1, 2026 for AEP Ohio Customers Participating in the Transmission Pilot Program

If you would like more information about how the BTCR impacts your monthly electric costs, please contact Katie Emling.

Residential Corner

Sky-high capacity prices coupled with geopolitical turmoil has kept residential rates at the highest levels in recent memory. We recommend customers with an approaching contract expiration migrate to a short-term eight month offer with Dynegy for 9.09¢/kWh.

Regarding natural gas, Brakey Energy has long viewed the distribution utilities’ Standard Choice Offer (SCO) as a prudent default strategy for supply. However, this approach can produce volatile bill outcomes—like the wild ride many customers experienced during the extreme cold earlier this winter. With natural gas settlement prices easing, many of our friends on the SCO can now safely unbuckle their seatbelts, at least until we need to strap in again next winter.

Natural Gas Market Update

The NYMEX price for March settled at $2.969 per Million British Thermal Units (MMBtu) on March 27, 2026. This price is down 60% from the February 2026 price of $7.460 per MMBtu. This settlement price is used to calculate March gas supply costs for customers that contract for a NYMEX-based index gas product.

The graph below shows the year-over-year monthly NYMEX settlement prices for 2022, 2023, 2024, 2025, and 2026 year to date. Prices shown are in dollars per MMBtu of natural gas.

Figure 1: NYMEX Monthly Natural Gas Settlement Prices

Figure 2 below shows the historical March 31, 2024 through March 31, 2026 Around the Clock (ATC) forward NYMEX natural gas prices in dollars per MMBtu for the balance of 2026 (labeled as “Custom Strip”) and calendar years 2027, 2028, 2029, and 2030.

Figure 2: ATC Calendar Year NYMEX Natural Gas Prices

*Pricing courtesy of Direct Energy Business.

Although the outbreak of war in the Middle East has wreaked havoc in global oil, gasoline, and LNG markets, volatility in the domestic natural gas market has been comparatively subdued. The United States’ relative energy independence has kept the domestic gas market insulated from the conflict’s shipping interruptions in the Strait of Hormuz. This, in combination with robust domestic production and a mild end to the winter, has helped keep a lid on forward natural gas prices.

As the war continues, elevated volatility can be expected across global energy markets, given the importance of the Strait of Hormuz to energy transportation. And, although well-insulated from the conflict, the propensity for volatility has created a risk premium in domestic natural gas prices.

Electricity Market Update

Figure 3 below shows the historical March 31, 2024 – March 31, 2026 ATC forward power prices in dollars per Megawatt hour (MWh) for the balance of 2026 (labeled as “Custom Strip”) and calendar years 2027, 2028, 2029, and 2030 for the AD Hub.

Figure 3: ATC Calendar Year Power Prices for the AD Hub

*Pricing courtesy of Direct Energy Business.

Similar to the domestic forward gas market, forward power price volatility has been subdued compared to the oil, gasoline, and LNG markets. Even so, however, forward power prices for the balance of 2026 through calendar year 2029 are trading near multi-year highs, buoyed by the same risk premium that has formed in all energy markets as a result of the war.

As we approach the summer, weather outlooks and forecasts will continue to grow in importance to the forward power market.

The post Ohio Energy Report: March 2026 appeared first on Brakey Energy.

In a February 12 letter to stakeholders, the PJM Board of Managers (“PJM Board”) announced its intent to pursue an extension of the existing capacity price collar that applies to the 2026/2027 and 2027/2028 delivery years (DYs) for the next two capacity auctions. This collar capped capacity prices in the two most recent auctions at approximately $325 per megawatt-day (MW-day).

In explaining its decision, the PJM Board cited stakeholder survey feedback, input from the White House National Energy Dominance Council, and concerns raised by governors from the 13 PJM states as factors supporting an extension of the price collar for the 2028/2029 and 2029/2030 DYs. Absent an extension, PJM’s Variable Resource Requirement (VRR) demand curve would have resulted in a significantly higher cap, approximately $550 per MW-day for the 2028/2029 DY.

As a next step, PJM must file a Federal Power Act Section 205 proposal with the Federal Energy Regulatory Commission seeking approval of the price cap extension before the 2028/2029 DY auction opens in June 2026. In parallel, PJM is developing a Reliability Backstop Procurement (“backstop auction”), envisioned as a one-time, transitional auction that would establish 15-year capacity contracts for new generation resources. The intent is to pair new generation with large, new loads, particularly data centers. PJM plans to file a detailed proposal with federal regulators by May 2026.

Load on February 2 Surprises to the Upside of Forecasts, Sets New AEP Zone Peak

The AEP Zone’s peak load through January 2026 was quickly and unexpectedly surpassed when load exceeded 24 gigawatts on the morning of Monday, February 2, 2026. Although PJM Interconnection’s Cold Weather Alert, Conservative Operations, Department of Energy Emergency Order, and generator restrictions remained in effect through February 2, load forecasts heading into the day were relatively modest compared to the 23,690 MW hourly load metered on January 27, 2026.

As shown in Figure 1, the gap between the final day-ahead forecast (evaluated at 11:45 PM on February 1) and actual metered load in the AEP Zone began widening during the early morning hours. At the morning peak, hour ending 8:00 AM, the metered load came in 1,779 MW higher than the prior day’s forecast.

Brakey Energy issued a coffee-fueled AEP Zone transmission coincident peak (CP) text alert shortly after 6:00 AM on February 2, followed by formal email and text notifications urging curtailment for the hour beginning at 7:00 AM.
 
Figure 1: Metered vs. Forecasted AEP Zone Load on February 2, 2026

With the National Oceanic and Atmospheric Administration forecasting above-normal temperatures across the AEP Zone through March, we expect severe winter weather to be behind us. As we transition into spring and the upcoming summer CP season, in our estimation it remains a coin flip whether the peak load summarized in Table 1 ultimately sets the single coincident peak (1CP) for the AEP Zone for the 12-month period ending October 31, 2026.

If the February 2 load holds as the 1CP, it would mark the fourth consecutive winter CP, potentially signaling that capacity CP management and increased distributed generation (e.g., solar) are continuing to suppress summer peak loads in the AEP Zone.

Table 1: Single Highest Load for AEP Zone through February 25, 2026

FirstEnergy’s New Base Distribution Rates Take Effect March 1

On February 24, 2025, following the Public Utilities Commission of Ohio’s (PUCO) Second Entry on Rehearing in FirstEnergy’s (FE) May 2024 base rate case, FE filed distribution rate updates with an effective date of March 1, 2026. These newly filed rates are based on the PUCO’s February 18th decision that slightly modified its November 19, 2025 Opinion and Order in the case.

These March 1 rates, which include updated capacity base distribution charges, result in a reduction of annual revenues for FE’s operating companies totaling approximately $39.4 million. This change in annual revenues stems from the PUCO’s decision to order FE to amortize approximately $245 million of previously deferred storm restoration expenses over a 25-year period, compared to the five-year period authorized by the PUCO’s initial order in the case.

The tables below summarize the current and March 1, 2026 base distribution rates for the Illuminating Company (CEI), Ohio Edison (OE), and Toledo Edison (TE) General Service Secondary (GS), General Service Primary (GP), General Service Subtransmission (GSU), and General Service Transmission (GT) customers.

Table 2. Rate Changes for FE GS Customers

Table 3. Rate Changes for FE GP Customers

Table 4. Rate Changes for FE GSU Customers

Table 5. Rate Changes for FE GT Customers

Although base distribution rates have increased across the board for all customers, these increases are coupled with rate changes to five distribution related riders, which have mostly decreased. These riders include the Tax Savings Adjustment Rider, the Distribution Uncollectible Rider, Advanced Metering Infrastructure / Modern Grid Rider, PIPP Uncollectible Rider, and Delivery Capital Recovery Rider. A new distribution rider called the Customer Credit Recovery Rider was also established in this case.

If you have questions about how these expected rate changes may affect your business, please contact Katie Emling.

Residential Corner

Sky-high Base Residual Auction (BRA) clearing prices and the not-too-distant deep freeze have resulted in historically high generation offers. We recommend customers with an approaching contract expiration migrate to a short-term nine-month offer with AEP Energy for 8.99¢/kWh.

Regarding natural gas, Brakey Energy has long found defaulting to distribution utilities’ Standard Choice Offer a prudent strategy for natural gas supply. However, this strategy can result in outlier bill outcomes – like many customers likely experienced from the recent extreme cold.

While we had previously recommended Columbus Gas of Ohio customers competitively source gas because of atypically high SCO auction clearing prices, we are comfortable again recommending the SCO because of lower clearing prices.

Natural Gas Market Update

The NYMEX price for February settled at $7.460 per Million British Thermal Units (MMBtu) on January 28, 2026. This price is up 59.2% from the January 2026 price of $4.687 per MMBtu. This settlement price is used to calculate February gas supply costs for customers that contract for a NYMEX-based index gas product.

The graph below shows the year-over-year monthly NYMEX settlement prices for 2022, 2023, 2024, 2025, and 2026 year-to-date. Prices shown are in dollars per MMBtu of natural gas.

Figure 2: NYMEX Monthly Natural Gas Settlement Prices

Figure 3 below shows the historical February 26, 2024 through February 26, 2026 Around the Clock (ATC) forward NYMEX natural gas prices in dollars per MMBtu for the balance of 2026 (labeled as “Custom Strip”) and calendar years 2027, 2028, 2029, and 2030.

Figure 3: ATC Calendar Year NYMEX Natural Gas Prices

*Pricing courtesy of Direct Energy Business.

The forward gas market has seen exceptional, record-breaking volatility over the course of this winter, especially in late January and early February. Winter Storm Fern’s nationwide impact was significant, but ultimately not as severe as meteorologists had predicted. Immediately after the storm, short-to-medium term weather forecasts indicated milder weather to close out the winter, causing forward gas prices to collapse nearly as quickly as they had risen in anticipation of the storm.

Forward gas prices beyond 2026 have traded in a tighter band, reflecting the trends of robust domestic gas supply – which continues to trend near all-time highs – and market participants’ continued expectation of a global LNG supply glut potentially forming in 2027-2028.

Electricity Market Update

Figure 4 below shows the historical February 26, 2024 – February 26, 2026 ATC forward power prices in dollars per MWh for the balance of 2026 (labeled as “Custom Strip”) and calendar years 2027, 2028, 2029, and 2030 for the AD Hub.

Figure 4: ATC Calendar Year Power Prices for the AD Hub

* Pricing courtesy of Direct Energy Business.

Short-term forward power prices for the balance of 2026 have followed trends in the forward gas market over the course of this winter, but the volatility has been less pronounced, comparatively. However, spot power prices on the other hand rose to extreme levels during the last week of January, peaking at over $1,000/MWh ($1/kWh). At the AD Hub, spot power prices averaged $104.61/MWh (10.461¢/kWh) in January, and $66.48/MWh (6.648¢/kWh) so far through February.

Forward power prices beyond 2026 have traded similarly to forward gas prices for the same period. Elevated capacity prices have helped to keep a lid on forward power prices, and the efforts to extend the $325/MW-day ceiling on capacity prices have helped relieve market anxieties about runaway capacity costs – at least temporarily – which has led to relative stability in forward power prices in outlier years.

The post Ohio Energy Report: February 2026 appeared first on Brakey Energy.

Beginning on January 24, a disrupted polar vortex sent temperatures across the central and eastern United States into a deep freeze. These prolonged subzero temperatures have resulted in elevated real-time and day-ahead hourly spot electric prices for customers throughout the PJM region.

As seen in the figure below, day-ahead spot prices at the Ohio AD Hub peaked on January 27, 2026, for hour ending 08:00 AM at a whopping $1,153 per Megawatt-hour (MWh), or $1.153 per kilowatt-hour (kWh). From January 1 through January 30, the average day-ahead spot price was $102.26 per MWh or 10.226¢ per kWh. This is primarily a weather-related effect and is not expected to persist, especially if temperatures normalize next month.

Figure 1: AD Hub Day-Ahead Hourly Spot Prices, January 1 – 30, 2026

These extremely low temperatures also produced elevated loads for transmission zones that rely heavily on electricity for space heating, including the American Electric Power (AEP) Zone. As a result, Brakey Energy issued five AEP Zone Transmission Coincident Peak (CP, or 1CP) alerts to clients enrolled in AEP Ohio’s Basic Transmission Cost Rider (BTCR) transmission pilot program. These alerts spanned from January 24 through January 30, 2026. In total, Brakey Energy has issued seven AEP Zone 1CP alerts so far this winter.

As shown in the table below, the preliminary metered load on January 27 currently holds the highest peak load to date in the AEP Zone since the current CP year began on November 1, 2025.
 
Table 1: Single Highest Load for AEP Zone through January 27, 2026

For context, AEP’s 1CP for the previous period (2024/2025) was 23,726 MW, only 56 MW higher than the preliminary metered load on January 27.

Brakey Energy will continue to monitor weather and load forecasts and will issue alerts to participating clients when warranted.

FirstEnergy Files April 1, 2026 Update to Non-Market-Based Services Rider

The Non-Market-Based Services Rider (Rider NMB) rates are set to change April 1, 2026 for residential and non-residential customers of FirstEnergy’s (FE) three Ohio operating companies: Ohio Edison (OE), the Illuminating Company (CEI), and Toledo Edison (TE). Rider NMB recovers FE’s non-market-based costs for transmission and ancillary services, with the largest component being PJM’s Network Integration Transmission Service (NITS) charge.

For 2026, the NITS rate in the ATSI Zone – the transmission zone serving FE’s Ohio customers—increased by 3.4% compared to 2025. Despite the NITS rate remaining near current levels, Rider NMB rates for various operating companies and customer classes will either increase or decrease based on each rate class’s share of the summer 2025 peak loads and forecasted billing determinants for the class’s cost recovery allocations.

If approved by the Public Utilities Commission of Ohio, the updated Rider NMB rates will take effect on April 1, 2026. Current and proposed April 1, 2026 Rider NMB rates for OE, CEI, and TE Residential (RS), Secondary (GS), Primary (GP), Subtransmission (GSU), and Transmission (GT) rate schedules are shown in the tables below. Rates are per kilowatt hour (kWh) for RS customers and per kilowatt (kW) or kilovolt-ampere (kVa) for GS, GP, GSU, and GT customers.

Table 2: OE Rider NMB Rates

Table 3: CEI Rider NMB Rates

Table 4: TE Rider NMB Rates

Clients that are participating in FE’s transmission pilot program are opted out of paying the NMB rider. If you have any questions about this pilot program or how the new NMB rates will impact your electric costs, please contact Katie Emling.

AEP Files April 1, 2026 Update to Basic Transmission Cost Rider

Earlier this month, AEP Ohio filed proposed April 1, 2026 rate updates for AEP Ohio’s BTCR. Based on the filing, the energy component rate for each non-residential customer class will decrease by approximately 7%. The demand-based billing component of transmission costs for the majority of AEP Ohio non-residential customers in the Secondary or Primary rate classes will be decreasing or increasing by approximately 1%, respectively. Additionally, General Service (GS) Transmission class customers can expect around a 6% decrease in the demand-based BTCR rate. These overall rate reductions can be attributed to the non-residential load growth in the AEP Ohio territory, primarily from data centers.

Select interval-metered customers, including Brakey Energy clients, may choose to participate in a transmission pilot program. For participants, the demand portion of BTCR charges is calculated based on the customer’s load during AEP’s 1CP, as opposed to the default method, which uses monthly billed demand.

Demand based BTCR rates for customers participating in AEP Ohio’s transmission pilot program will again be increasing by approximately 9%, just as it did last April. This rate is more than double the per kW rate billed to standard GS Transmission customers not enrolled in the transmission pilot program.

The tables below show the current and proposed April 1, 2026 BTCR kWh and kW-based rates for non-transmission pilot program customers and transmission pilot program customers of AEP Ohio. The percentage change for each rate is also summarized.

Table 5: Current and Proposed April 1, 2026 BTCR Rates for AEP Ohio Customers

Table 6: Current and Proposed April 1, 2026 for AEP Ohio Customers Participating in the Transmission Pilot Program

If you would like more information about how the BTCR impacts your monthly electric costs, please contact Katie Emling.

Residential Corner

Sky-high Base Residual Auction (BRA) clearing prices and the recent deep freeze have resulted in ever-elevating generation offers.

We recommend customers with an approaching contract expiration migrate to a short-term ten-month offer with AEP Energy for 8.89¢/kWh. We’re actually surprised they haven’t pulled this offer yet given how much power prices have spiked in the last week.

Regarding natural gas, Brakey Energy has long found defaulting to distribution utilities’ Standard Choice Offer a prudent strategy for natural gas supply. However, Columbia Gas of Ohio (“Columbia”) rates have recently jumped. For Columbia customers, and for any customer wanting price certainty this winter, Energy Harbor is currently offering a six-month deal for $0.6390 per hundred cubic feet (ccf).

Natural Gas Market Update

The NYMEX price for January settled at $4.687 per Million British Thermal Units (MMBtu) on December 29, 2025. This price is up 5.9% from the December 2025 price of $4.424 per MMBtu. This settlement price is used to calculate January gas supply costs for customers that contract for a NYMEX-based index gas product.

The graph below shows the year-over-year monthly NYMEX settlement prices for 2022, 2023, 2024, 2025, and January 2026. Prices shown are in dollars per MMBtu of natural gas.

Figure 2: NYMEX Monthly Natural Gas Settlement Prices

Figure 3 below shows the historical January 30, 2024 through January 30, 2026 Around the Clock (ATC) forward NYMEX natural gas prices in dollars per MMBtu for the balance of 2026 (labeled as “Custom Strip”) and calendar years 2027, 2028, 2029, and 2030.

Figure 3: ATC Calendar Year NYMEX Natural Gas Prices

*Pricing courtesy of Direct Energy Business.

Forward natural gas prices have experienced extreme volatility, particularly the February 2026 NYMEX contract, which surged from a low of $3.02/MMBtu on January 16 to an intraday-high of $7.83/MMBtu on January 28 – a 259% increase in seven trading days – which is the most rapid increase since natural gas trading began on the NYMEX in April 1990. This surge can be attributed to the restriction of supply from the south due to wellhead freezes, combined with outsized heating and power burn demand for electric heating for nearly two thirds of the US population resulting from Winter Storm Fern.

While the most volatility has been concentrated in the February 2026 contract, the balance of 2026 has also traded markedly higher since January 16. Market participants will be paying close attention to the Energy Information Administration’s natural gas storage reports over the coming weeks in order to evaluate the storage outlook for the rest of the year, which could bring volatility to natural gas forward prices beyond this winter and beyond 2026.

Electricity Market Update

Figure 4 below shows the historical January 30, 2024 – January 30, 2026 ATC forward power prices in dollars per MWh for the balance of 2026 (labeled as “Custom Strip”) and calendar years 2027, 2028, 2029, and 2030 for the AD Hub.

Figure 4: ATC Calendar Year Power Prices for the AD Hub

* Pricing courtesy of Direct Energy Business.

Much like the forward gas market, the forward power market has experienced extreme volatility, mostly concentrated in February 2026 forward prices. Prices for the balance of 2026 are currently trading at a premium compared to outlier years 2027 and beyond and will likely correlate strongly with trends in the forward gas market for the remainder of the winter.

Beyond 2026, forward power prices are trading in a tight range. PJM, its member states, and the FERC, all continue to grapple with the impending supply-demand imbalance resulting from data center growth and the lack of new generation capacity to support it. These ongoing and unresolved challenges bring uncertainty to the market, and forward power prices across the board are trading near multi-year highs as a result.

The post Ohio Energy Report: January 2026 appeared first on Brakey Energy.

On December 17, 2025, PJM Interconnection announced the results of its Planning Year 2027/2028 Base Residual Auction (BRA). The auction procured 134,478.1 megawatts (MW) of unforced capacity from generation resources and demand response across the Regional Transmission Organization (RTO).

The auction cleared at $333.44 per MW-day for the entire PJM region, which includes the ATSI, AEP, DAY, and DEOK transmission zones. This price matched the Federal Energy Regulatory Commission’s (FERC) approved capacity price ceiling and represents a 1.3% increase compared to the prior auction for the 2026/2027 Delivery Year (DY).

The 2027/2028 DY is the second and final year in which a FERC-approved capacity price collar is in effect. Without the capacity ceiling in place, PJM’s simulations (based on the existing offers in the auction) would have resulted in an RTO-wide clearing price of approximately $542.83/MW-day, which is $196.36/MW-day or 58.9% above the ceiling-limited clearing price. It’s important to note that PJM doesn’t know how actual offers would have changed if the price collar was not in effect.

In its press release announcing the auction results, PJM stated that the capacity secured through the BRA, combined with Fixed Resource Requirement resources, falls short of PJM’s reliability requirement by 6,623 MW. In practical terms, the committed supply does not meet PJM’s long-standing reliability standard, which is designed to maintain a reserve margin sufficient to withstand a one-in-ten-year extreme weather or system event.

PJM Executive Vice President Stu Bresler underscored the challenge, noting that electricity demand – particularly from data centers – continues to grow faster than new supply additions. He emphasized that addressing this imbalance will require coordinated action among PJM, market participants, policymakers, and large load customers.

AEP Zone Load Registers Within Historical 1CP Range on December 15

Brakey Energy provides email and text alerts in advance of loads having the potential to set the year’s American Electric Power (AEP) Zone Transmission Coincident Peak (CP, or 1CP) to clients enrolled in AEP’s Basic Transmission Cost Rider (BTCR) transmission pilot program. On December 15, 2025 an arctic blast swept across the Great Lakes, sending much of the AEP Zone into subzero temperatures with the wind chill. As a result, Brakey Energy issued a CP alert for the morning of December 15.

As shown in the table below, the preliminary metered load on December 15 holds the highest peak load to date in the AEP Zone since the current CP year began on November 1, 2025.
 
Table 1: Single Highest Load for AEP Zone through December 21, 2025

The PJM Regional Transmission Organization predicted that AEP’s peak load this winter would reach 24,776 MW. For context, AEP’s 1CP for the previous period (2024/2025) was 23,726 MW, only 148 MW higher than the metered load on December 15.

Even though the load on December 15 is within 1% of the AEP Zone’s previous 1CP, we believe that, in the wake of new data center load coming online across the transmission zone over the past year, it is probable that the load registered on December 15 will be displaced by later this winter or this coming summer.

Brakey Energy will continue to monitor weather and load forecasts and will issue alerts to participating clients when warranted.

PUCO Orders FirstEnergy to Pay Over $250 Million in Restitution, Refunds, and Forfeitures

On November 19, 2025, the Public Utilities Commission of Ohio (PUCO) issued orders concluding its investigation related to the federal criminal probe into the passage of House Bill 6. In two orders, the Commission found FirstEnergy’s (FE) Ohio utilities – Ohio Edison (OE), The Illuminating Company (CEI), and Toledo Edison (TE) – violated Ohio law, PUCO rules, and prior Commission orders.

The PUCO ordered the utilities to pay $250.7 million in combined customer restitution, refunds, and civil forfeitures. Of that amount, FE was ordered to pay $64.1 million in civil forfeitures to the State of Ohio’s General Reserve Fund. These forfeitures were imposed by the Commission for violations of corporate separation requirements, disclosure failures in prior PUCO proceedings, and deficiencies identified in a 2021 audit. PUCO cited a pattern of inadequate separation between regulated utilities and unregulated affiliates that contributed to the HB 6 scandal.

The remaining $186.6 million will be paid as restitution to customers over three billing cycles, including treble damages tied to HB 6-related expenditures and additional amounts identified through a PUCO audit. These credits will flow through to customers through the Delivery Capital Recovery Rider (Rider DCR) and the Demand Side Management and Energy Efficiency Rider 2 (Rider DSE2) – Part 2 for customers who did not previously opt-out of paying Rider DSE charges. These distribution credits will appear on customers’ bills for the three billing cycles ending in January, February, and March 2026.

The tables below summarize the rather significant Rider DCR credits that will be returned to customers served under OE, CEI, and TE Residential (RS), Secondary (GS), Primary (GP), Subtransmission (GSU), and Transmission (GT) rate schedules. Rider DCR credits on a per kWh basis will also be issued to OE, CEI, and TE customers billed under the companies’ three lighting tariffs.

Table 2. Rider DCR Credit Rates for OE Customers

Table 3. Rider DCR Credit Rates for CEI Customers

Table 4. Rider DCR Credit Rates for TE Customers

FirstEnergy Files Updated Rates for January 1 Based on PUCO’s Ruling

On November 26, 2025 following the PUCO’s Opinion and Order in FE’s May 2024 base rate case, FE filed distribution rate updates with an effective date of January 1, 2026. The filed rates were based on the annual revenue requirement approved by the Commission in the case, which is an increase of $34 million in the aggregate for FE’s three operating companies. On a company specific basis, OE was ordered to lower its annual revenues by $17.4 million, TE was ordered to lower its annual revenues by $24.4 million, and CEI was approved to increase its annual revenues by $75.9 million.

The tables below summarize the current and filed base distribution rates for FE GS, GP, GSU, and GT customers. Subject to PUCO approval, the rates summarized below would go into effect. However, if requests for rehearing should be filed by intervening parties in the case (deadline of December 19) and a rehearing is granted, we would expect the implementation of these rates to be delayed as the rehearing takes place.

Table 5. Rate Changes for FE GS Customers

Table 6. Rate Changes for FE GP Customers

Table 7. Rate Changes for FE GSU Customers

Table 8. Rate Changes for FE GT Customers

Although base distribution rates have increased across the board for all customers, these increases are coupled with rate changes, mostly decreases, to five distribution related riders. These riders include the Tax Savings Adjustment Rider, the Distribution Uncollectible Rider, Advanced Metering Infrastructure / Modern Grid Rider, PIPP Uncollectible Rider, and Rider DCR. A new distribution rider called the Customer Credit Recovery Rider was also established in this case.

If you have questions about how these expected rate changes may affect your business, please contact Katie Emling.

Residential Corner

Sky-high Base Residual Auction (BRA) clearing prices have resulted in sustained elevated generation offers. Elevated winter power prices only makes this problem worse.

We recommend customers with an approaching contract expiration migrate to a short-term six-month offer with Energy Harbor for 8.69¢/kWh.

Regarding natural gas, Brakey Energy has long found defaulting to distribution utilities’ Standard Choice Offer a prudent strategy for natural gas supply. However, Columbia Gas of Ohio (“Columbia”) rates have recently jumped. For Columbia customers, and for any customer wanting price certainty this winter, Energy Harbor is currently offering a six-month deal for $0.5890/ccf.

Natural Gas Market Update

The NYMEX price for December settled at $4.424 per Million British Thermal Units (MMBtu) on November 26, 2025. This price is up 31% from the November 2025 price of $3.376 per MMBtu. This settlement price is used to calculate December gas supply costs for customers that contract for a NYMEX-based index gas product.

The graph below shows the year-over-year monthly NYMEX settlement prices for 2021, 2022, 2023, 2024, and 2025. Prices shown are in dollars per MMBtu of natural gas.

Figure 1: NYMEX Monthly Natural Gas Settlement Prices

Figure 2 below shows the historical December 22, 2023 through December 22, 2025 Around the Clock (ATC) forward NYMEX natural gas prices in dollars per MMBtu for the first quarter of 2026 (labeled as “Custom Strip”) and calendar years 2026, 2027, 2028, and 2029.

Figure 2: ATC Calendar Year NYMEX Natural Gas Prices

*Pricing courtesy of Direct Energy Business.

The forward gas market has experienced significant volatility in the month of December, with the January 2026 NYMEX contract alone swinging between a high on December 5 of $5.50/MMBtu and a low of $3.84/MMBtu on December 16 – a 30% swing. This volatility, particularly in the short term, is attributed to fast-changing weather forecasts and near-record production levels.

Outlier years in 2027 and beyond continue to trade mostly flat, and the overall state of contango has remained intact. Market participants continue to price in the possibility of a global LNG supply glut in outlier years, resulting in more gas availability domestically and depressing forward prices.

Electricity Market Update

Figure 3 below shows the historical December 22, 2023 through December 22, 2025 ATC forward power prices in dollars per Megawatt hour (MWh) for the first quarter of 2026 (labeled as “Custom Strip”) and calendar years 2026, 2027, 2028, and 2029 for the AD Hub.

Figure 3: ATC Calendar Year Power Prices for the AD Hub

* Pricing courtesy of Direct Energy Business.

The forward power market has also experienced increased volatility in recent weeks. While forward power prices in the short term through 2026 have correlated with trends in the gas market, outlier years in 2027 and beyond have also experienced volatility, unlike the gas market.

The volatility in outlier years can be attributed to the increasing presence of data centers and their future load forecasts, combined with PJM’s projected potential shortfalls in generation capacity. As stakeholders work to develop resolutions to this supply-demand imbalance, the forward power market is likely to remain volatile.

The post Ohio Energy Report: December 2025 appeared first on Brakey Energy.