Energy Market Update

Weekly Energy Industry Summary

Commodity Fundamentals

Week of September 15, 2025

By The Numbers:

NG '25 prompt-month NYMEX natural gas settled at $3.04/MMbtu, up $.10/MMbtu on Monday, September 15.
NG '25 prompt-month NYMEX natural gas settled at $3.09/MMbtu, one week ago.
Prompt-month crude oil settled at $63.30/bbl., up $.61/bbl., on Monday, September 15.
Prompt-month crude oil settled at $62.26/bbl., one week ago.

Natural Gas Fundamentals - Neutral/Bearish

Generally, fundamental supply/demand drivers are neutral to bearish for the coming week.
Weather is largely seasonal, albeit a bit above normal in the Midwest, but the average temperatures are falling with the advent of fall. The threshold of the low demand "shoulder" period is here.
Production is strong. Month-to-date gas production averaged 106.7 Bcf/d versus 100.8 Bcf per day for the same period last year.
Year-to-date production averaged 105.3 Bcf/d versus 101.6 Bcf/d for the same period last year.
Power generation demand is declining along with decreasing temperatures. Month-to-date demand for natural-gas-fired power generation averaged 39.9 Bcf/d versus 41.1 Bcf/d for the same period last year.
Residential and commercial demand, month-to-date, averaged 22.1 Bcf/d versus 22 Bcf/d for the same period last year.
LNG exports year-to-date averaged 15.3 Bcf/d versus 12.8 Bcf/d for the same period last year.
Exports to Mexico are flat year-over-year.
Storage inventories are on a trajectory to be at or near 4 trillion cubic feet by the end of October, or, nearly full.

Crude Oil - Neutral

NYMEX (WTI) prompt-month-crude settled at $63.30/bbl., up $.61, on Monday, September 15.
The EU has delayed Russia sanctions to coordinate action with the G7.
A sanctioned oil tanker has unloaded its cargo at the Indian port of Mundra despite the port owner's order not to allow sanctioned tankers to dock there.
California passes bill to boost oil production amid refinery shutdowns in the state.
China has been amassing crude oil in storage.
The International Energy Agency, which has repeatedly predicted that global oil demand growth will peak before 2030, has drafted a report admitting both oil and gas demand are set to continue growing for decades, Bloomberg reports.

Economy - Neutral

The U.S. added 22,000 jobs in August, fewer than expected.
The unemployment rate was 4.3%.
Jobs were gained in healthcare and lost in manufacturing and construction.
Some Fed watchers say that the jobs results increase the chance for rate cuts as early as this month.
The Bureau of Labor Statistics concludes the U.S. added 911,000 fewer jobs in the year ending in March than previously estimated; the labor market may well have had less momentum coming into 2025 than previously thought.
Equities markets remain elevated.
Crude oil and gasoline prices are relatively low compared to the prior three/four years.
The home building market is weak.

Weather - Neutral

The outlook for the second half of August has flexed down sharply with below-to-well-below normal temperatures prevailing through the eastern half of the country and staying lower-for-longer.
The West will be hot.
The tropics are ramping up, and this is generally bearish of natural gas.

Weekly Natural Gas Report:

Inventories of natural gas in underground storage for the week ending August 29 are 3,272 Bcf; an injection of 55 Bcf was reported for the week ending August 29.
Gas inventories are 173 Bcf above the five-year average and 73 Bcf less than the same time last year.

Values reflect week ending Sept. 12, 2025

Prices reflect week ending Sept. 12, 2025

Weekly Power Report:

Mid-Atlantic Electric Summary

The Mid-Atlantic Region’s forward power prices were unchanged over the past week as steady demand and more than adequate supply heading into the shoulder months, has the market consolidating of late. A storm moving up the Mid-Atlantic coast will bring cooler conditions to this region, followed by a temperature spike on Friday ahead of a weekend cold front. The highest temperature anomalies remain centered over the mid-continent and extend toward the upper West. The 11 to 15-day outlook brings a generally warmer-than-normal pattern, with the highest anomalies in the North. Power futures were unchanged over the past week and were 1% higher over the past month, for the 2026-2030 terms. The month-to-date, day-ahead settlement price average in West Hub for September currently is $33.18/MWh, which is -7% lower than last month and 7% higher than a year ago.
Federal Court Rules in Favor of Transmission Line - The U.S. Third Circuit Court of Appeals issued a 65-page ruling in a lawsuit filed by Transource Pennsylvania LLC against the Pennsylvania Public Utility Commission (PUC) affirming a lower court decision that the PUC had no authority to disregard a finding of need for a PJM-approved transmission line when determining whether to grant a certificate of public necessity and convenience (CPCN) for the line. The case stems from a project that was originally approved by the FERC in 2017 based on a finding by PJM that the transmission line was needed to reduce energy congestion and prices in Maryland, Virginia, West Virginia and D.C. and that the benefits of the project outweigh the costs. Before the PUC, Transource pointed to savings for energy customers in the southern part of the grid of more than $840 million over 15 years, but the PUC found that those savings meant that electricity costs for Pennsylvanians would increase by up to $812 million over the same period. The PUC therefore rejected Transource’s request for a CPCN to build the project. Transource took the PUC to federal court and prevailed in 2023, leading to an appeal by the PUC to the Third Circuit. On appeal, the Third Circuit panel unanimously found that the PUC violated the supremacy clause of the U.S. Constitution when it found that Transource had failed to demonstrate a need for the transmission line given that PJM already had found that the line was needed as part of the 9A Project pursuant to a FERC-approved tariff. In its order, the appellate court concluded that the PUC’s action “poses an obstacle to accomplishing federal objectives” and was therefore preempted. The appellate judge acknowledged that the PUC is not required to rubber-stamp any PJM approved project application but stated that the PUC cannot disregard PJM’s finding of need under a federal tariff. The PUC is currently weighing whether it will appeal the decision to the U.S. Supreme Court.

Great Lakes Electric Summary

The Great Lakes Region’s forward power prices were unchanged over the past week as steady demand and more than adequate supply heading into the shoulder months, has the market consolidating of late. A storm moving up the Mid-Atlantic coast will bring cooler conditions to this region, followed by a temperature spike on Friday ahead of a weekend cold front. The highest temperature anomalies remain centered over the mid-continent and extend toward the upper West. The 11 to 15-day outlook brings a generally warmer-than-normal pattern, with the highest anomalies in the North. Power futures were unchanged over the past week and 3% higher over the past month, for the 2026-2030 terms. The month-to-date, day-ahead settlement price average in COMED for September is $29.68/MWh, which is -20% lower than last month, while in AdHub the price is $32.35/MWh or -11% lower than last month. In Michigan the month-to-date, day-ahead settlement price average is currently $32.68/MWh or -23% lower than August, while Ameren’s current price average is $31.95/MWh, which is -20% lower than last month.
Governors Call for Transparency and State Representation in PJM Board Selection - On 9/10, seven governors from the states of PA, DE, IL, MD, NJ, TN and VA sent a letter to the PJM Board of Managers expressing disappointment that their recommended candidates, former FERC Chairman Mark Christie and former FERC Commissioner Allison Clements, were not nominated to fill two vacant seats on the Board. While the governors acknowledged the strong qualifications of the nominees advanced by the Nominating Committee, Dr. Robert (Bob) Ethier and Dr. Le Xie, they stated that neither represent the perspectives or priorities of the PJM states. The governors argued that the decision to disregard their recommendations signals a troubling trend of diminishing state influence in PJM governance. The 2024/2025 PJM Nominating Committee reviewed all candidates and, in accordance with the Operating Agreement, advanced Dr. Ethier and Dr. Xie for consideration. PJM members will vote on the nominees at the 9/25 Members Committee meeting. Governance issues will be discussed further on 9/22 at the multi-state technical conference in Philadelphia billed as a Summit on the State of PJM Interconnection.

Northeast Energy Summary

On September 2, Eversource Energy filed petitions (for Eversource Gas of Massachusetts and NSTAR) with the Department of Public Utilities to approve a 10-year contract with Enbridge to provide firm delivery of natural gas from their Algonquin Gas Transmission pipeline. Enbridge recently announced a final investment decision to expand the G-lateral pipeline in southeast Massachusetts and Rhode Island to deliver an additional 75 million cubic feet of natural gas per day starting in 2029. Now, Eversource has entered into an agreement with Enbridge to buy around 40% of the expanded capacity to serve customers in its NSTAR Gas and former Columbia Gas territories.
On September 5, the Connecticut Public Utilities Regulatory Authority (PURA) opened Docket 12-06-02RE04 and issued a notice of request for written comments. Docket 12-06-02RE04 was opened to implement SB4 which passed earlier this year. SB4, among other things, requires PURA and the electric distribution companies to revise the standard service procurement plan, examining modifications to the frequency of competitive solicitations and develop the ability to procure 25% of the standard service load through “dynamic market purchases,” which include spot market purchases “based on the active monitoring of day-ahead and real-time markets.” These provisions are an attempt to address energy affordability, which became a leading issue in states across New England over the last year with rising energy costs. Now, Connecticut is the latest state in New England to consider having utilities self-supply part of their standard offer service load. PURA’s notice requests feedback for several specific issues on the proposed standard service procurement amendments, including target levels of dynamic market purchases, interaction with current tranche sizes, development of proxy prices, interaction with nuclear power purchase agreements, securing environmental attributes for dynamic purchases, mitigating the risk for dynamic purchases, impact of ISO-NE capacity market reforms on dynamic market purchases, mitigating risk of customer migration, utilizing varying durations of standard service contracts, and purchasing separate fixed price energy supply and capacity contracts.
Recently, New York Governor Hochul announced more than $11 million was awarded to five clean hydrogen research and development (R&D) projects. The projects were selected through the Advanced Fuels and Thermal Energy Research Program, administered by NYSERDA. According to NYSERDA, the awarded projects will demonstrate new technology designs, cost reductions associated with hydrogen storage and distribution, evaluate large-scale clean hydrogen storage opportunities, and deploy zero-emission hydrogen-powered transportation. The awarded projects include:
- GTI Energy - Awarded $220,000 to evaluate NY geological hydrogen storage potential;
- National Grid Ventures - Awarded $2 million to install the first commercially deployed 100% hydrogen-fueled linear generator at National Grid’s Northport Power Plant in Fort Salonga;
- Plug Power Inc. - Awarded $2 million to partner with Verne to co-develop new hydrogen distribution trailers with cryo-compressed storage technologies;
- Stony Brook University - Awarded over $4.9 million for a low-pressure, ambient temperature hydrogen storage system at Northwell Health Hospital; and
- SWITCH Maritime LLC - Awarded $2 million to develop and demonstrate NY’s first hydrogen fuel cell-electric ferry

ERCOT Energy Summary

Last week, temperatures across Texas were in the low to mid 90’s for day time highs and the low 70’s for overnight lows. Wind generation was strong with flat average wind above 10 GW all week, averaging around 13 GW. Flat average solar output was +10 GW as well.
As we turn to the back half of September, a warmer-than-normal pattern is expected to persist throughout the two-week forecast period for Texas, though some widely scattered thunderstorm activity may cause some unevenness. As a result, highs are likely to remain in the lower to mid-90s. Wind generation is projected to be lower this week and again early next week before increasing once more. Looking to the 15-30 day models, both the European and American models show above normal day models, the Lower 48 is set up for a period or two of cooler weather in October that is focused over the Mid-continent. In both the American and European models, warmer temperatures are focused out in Western states and the East Coast. Texas and the Midcontinent are forecasted to be more normal.

ERCOT Forward Prices:

The forward calendar strips week over week and month over month basis were the following:

Source: ERCOT

ERCOT Real Time Prices

Wind and Solar Output

Source: ERCOT

As temperatures pulled back to mid 90’s and wind generation was strong, real-time prices had a hard time breaking $100/MWh.

Recent Solar, Wind and Battery Milestones:

Temperatures in the upper 90’s still drove net load, allowing batteries to reach a new maximum storage discharge of 7,656 MW on September 11^th at 7:30 PM CT. This is the 3^rd new battery storage record in September. Solar hit a new output record of 29,833 MW on September 9^th and its first new since July 29th.
Wind peaked at 28,470 MW on March 3^rd. The combined renewables record was set last week on June 21^st at 12:55 CT with 47,040 MW vs load of 73,320 MW or 64% of ERCOT load.

Generator Outages:

Last week, thermal (gas, coal, nuclear & hydro) maintenance as outages were held between 9-12 GW.

https://www.gridstatus.io/graph/ercot-outages?iso=ercot&outageType=thermal

Source: ERCOT & Grid Status

TX Legislature, PUCT & ERCOT News:

PUCT & ERCOT Discuss Conditions for Net Metering

As part of the PUCT’s project to consider rulemaking “Net Metering Arrangements Involving a Large Load Co-Located with an Existing Generation Resource Under PURA 39.169” ERCOT went thru a letter they submitted that identified all the stand alone generation resources in ERCOT as of September 1^st 2025 that could be connected to a new large load (>75 MW) in the future and could invoke the net metering arrangement process. ERCOT was intentional in describing their process due to the concerns raised by large loads seeking to co-locate with an existing Resource and who are currently in the final stages of the interconnection process but not yet modeled in ERCOT’s system. Some of these loads have argued that they have already incurred significant time and expense and should not be subject to the 180-day net metering arrangement approval process. At the heart of this discussion is ERCOT asserting their right to curtail large loads in a future event with limited Resource Adequacy to maintain grid reliability.

Texas PUC Approves Two New Gas Plants for Entergy Reflecting Costs of New Builds

Last week, at its monthly meeting the PUCT approved the construction of two new gas plants for the portion of east Texas served by Entergy that is not part of ERCOT. What is relevant to ERCOT customers is that the PUCT approved the plants with a hard “cost cap” of $2.4 billion so as to protect rate payers. The two plants will be the 754-MW Legend Power Station and 453-MW Lone Star Power Station for a total of 1,207 MW of new generation. These plants were deemed critical to serve “the significant growth in southeast Texas” per Entergy CEO as coincident peak load is expected to grow by ~20% by 2028. The plants are expected to be online by 2028. The Legend plant will have a hard cost cap of $1.6 billion while the Lone Star will have a cap of $799 million. That equates to approximately $1.8 million per MW for the two new plants.

CAISO, Desert Southwest and Pacific Northwest Energy Summary

Above normal temperatures will be the theme for the West heading into the back half of the month. Low to mid-90s are forecast across inland California early this week with low to mid-80s expected in the SoCal coastal cities. The above normal weather pattern is forecast to persist across the West into this weekend and early next week before the models suggest a more seasonable pattern builds in late month. Tropical Storm Mario is currently in the Eastern Pacific and is expected to track along the Baja Peninsula in the coming days. While it looks like Mario will dissipate by mid-week, some remnant moisture is on track to land in SoCal on Thursday bringing rain – yes, rain – to the region in September. The temperature forecast this day is wide, somewhere in the 80s for the LA Basin, depending upon how much rain falls. But the near notion of rain before November is an anomaly.
Abundant sunshine and hydro flow this spring took the pressure off the state’s gas system, and it entered the summer period with robust stocks. As the end of the cooling demand season nears, the gas system remains well positioned for the upcoming heating demand season. SoCalGas ended last week with an aggregated storage level over that of the same time in 2024 and it is roughly 2 Bcf below the peak storage level of 106 Bcf posted last year in early November. As temperatures glide down for the year, the CAISO grid will see springtime conditions re-emerge as solar swamps the grid midday and the need for thermal generation decreases. In recent days the spread between NP15 and SP15 Day Ahead index settlements has widened as moderating loads and solar overproduction brings negative prices back into the mix. Standing up our standard warning for those with interests in the West during Santa Ana season – the late summer/into fall potential for Santa Ana’s to percolate and royally ruin your day is top of mind for the next month and a half.
California lawmakers closed out the legislative year with one of the most sweeping overhauls of the state’s energy and climate policies in decades – a package that could give the governor a presidential debate-stage talking point on rising energy costs as his party shifts its focus to affordability. The six-bill deal, passed Saturday after legislators put their session into extra innings because of last-minute dealmaking, was sold as a way to ease gas prices and soaring electricity bills while preserving the state’s signature climate programs. The most contentious and consequential element of the lawmaking six pack was the reauthorization of the state’s cap & trade system. Weeks of tense negotiations culminated in a deal that extends the carbon pricing and credit trading program, which has been central to California’s climate strategy for nearly a decade. The renewed program, now renamed as “cap & invest” – aims to provide regulatory certainty for businesses and utilities, and has been extended to 2045. The extension, hammered out in backroom talks, was one of the most divisive elements of the package. The carbon-trading program, launched in 2013, is California’s way of putting a price tag on greenhouse gas emissions and penalizing those responsible for emitting. The program sets a strict cap on emissions for polluters and hands out a limited supply of permits companies can sell to other polluters if they cut enough emissions. The final agreement on the program preserved rules that let oil companies avoid paying the full cost of their emissions while leaving untouched a cap on carbon prices. This setup shields polluters while leaving consumers potentially exposed to higher gas prices.

LevelTen Energy Snapshot Graphs and Commentary

LevelTen Energy’s snapshot on U.S. and EU Power Purchasing Agreement (PPA) pricing is below. For more information on LevelTen please visit www.leveltenenergy.com.

Key Market Impacts to Renewables from the Renewable Power Teams at Constellation

Recent changes in policy are reshaping the landscape of the renewable energy sector. The elimination of the 5% CapEx safe harbor for tax credits, the initiation of a new Section 232 tariff investigation into wind turbine imports, and the introduction of stricter Department of Interior oversight are all contributing to increased uncertainty and risk. These developments have led to rising costs and heightened delays for federally and privately permitted wind and solar projects, posing significant challenges for developers and stakeholders across the industry.

OBBB EO 14315 Update: New Treasury Guidance (8/15) Removes 5% CapEx Standard but Avoids Worst Case Scenario for Renewables

5% Safe Harbor Eliminated: Starting 9/2, projects can no longer qualify as having commenced construction by spending 5% of total CapEx, a long-standing industry standard.
The Physical Work Test (PWT) is currently the sole method used to determine the “beginning of construction” (BOC) and requires developers to demonstrate ongoing and significant activity for qualification. Projects must be placed in service by the end of the fourth calendar year after BOC to remain tax credit eligible.
This change is not nearly as bad as many developers thought it might be as the PWT has long been the preferred method. While the elimination of the 5% safe harbor decreases flexibility for developers, it has often been viewed as the more expensive option.
Under these new rules, developers will look to build a pipeline of projects which use the PWT to commence construction before the July 4^th, 2026 deadline to qualify for tax credits.
While this update does not address Foreign Entity of Concern (FEOC) restrictions, it does note that further guidance is being drafted. Until the Treasury Department releases specific guidelines, developers will have to exercise rigorous diligence to fulfill the new requirements.

Tariff Update: Commerce Launches Section 232 Investigation into Wind Turbine Imports

National Security Review Targets Wind Components (Aug 13): The Department of Commerce initiated a Section 232 investigation into imported wind turbine components (including blades, nacelles, and tower flanges) citing national security concerns tied to foreign control and supply chain concentration. The review allows up to 270 days for findings and 90 days for presidential action.
Tariff Risk Adds Cost Pressure to the Wind Industry: Offshore wind developers face heightened exposure due to reliance on imported components. Dominion Energy recently estimated a $506M cost increase for its Coastal Virginia Offshore Wind project under existing tariffs, with further increases possible if new tariffs are imposed. Onshore wind, while slightly more insulated from imported components, will still experience cost increases if this tariff is put in place.
Stacking Risk and Cost Implications for Industry: Many wind components already face 50% tariffs under steel and aluminum rules. New wind-specific tariffs could stack, raising input costs and increasing levelized cost of energy (LCOE) by up to 10%, according to Capstone analysis.
Public Comment Period Now Open: The investigation’s public comment period is active. Commerce is expected to issue findings by May 2026.

Department of Interior (DOI) Update: DOI Actions Signal Growing Political Risk for Renewables, Even Fully Approved Projects

Revolution Wind & Lava Ridge Projects Undermined by DOI (Aug): DOI halted construction on the nearly complete Revolution Wind project and rescinded permits for the Lava Ridge Wind Project, despite prior federal approvals—signaling that even fully permitted renewable projects are vulnerable to sudden political disruption and regulatory reversal.
New Permitting Restrictions Add Delay & Uncertainty: DOI’s 8/1 Secretary’s Order and 7/15 memo centralize and politicize wind/solar reviews, requiring personal sign-off from the Secretary and prioritizing energy density over climate goals.
Federal vs. State/Private Land Irrelevant for DOI Oversight: DOI’s enhanced review process affects wind and solar projects regardless of land ownership—projects on state or private land still face potential disruption if they require federal permits, consultations, or approvals (e.g., for transmission lines or environmental impact).
Implications for Developers:
1. Obtaining approval on federal permits no longer guarantees protection, even for contracted or shovel-ready projects.
2. Delays may jeopardize tax credit eligibility under OBBBA timelines.
3. Increased scrutiny and unpredictability raise risk for buyers, lenders, and developers.

For questions on these items and more please reach out to SustainabilityTeam@Constellation.com and your inquiry will be directed to an inhouse expert.

Sustainability Corner – Information on Sustainability Concepts and Education

The Use of eGRID and Location-Based Emissions

The U.S. Environmental Protection Agency’s Emissions & Generation Resource Integrated Database (eGRID) is one of the most widely used tools for calculating electricity-related greenhouse gas (GHG) emissions. eGRID compiles plant-level data on power generation and associated emissions of carbon dioxide (CO₂), nitrogen oxides (NOₓ), sulfur dioxide (SO₂), and other pollutants. This data is aggregated by balancing authorities and subregions across the country, allowing organizations to estimate the emissions intensity of the electricity they consume.

In corporate greenhouse gas accounting, particularly under the Greenhouse Gas Protocol (GHGP), companies are required to report Scope 2 emissions—the indirect emissions from purchased electricity. Two approaches are recognized: location-based and market-based. The location-based method reflects the average emissions intensity of the grid where consumption occurs, regardless of contractual arrangements such as renewable energy certificates (RECs) or power purchase agreements (PPAs). Because it uses average grid data, eGRID is the standard dataset for U.S. companies calculating location-based emissions.

This approach provides transparency into the physical reality of regional electricity systems. For example, a facility in the Midwest, where coal remains part of the generation mix, will reflect higher location-based emissions than a similar facility in the Pacific Northwest, where hydropower dominates. By using eGRID data, organizations can benchmark facilities, track progress over time, and identify opportunities for efficiency or load shifting.

While the market-based method highlights a company’s procurement choices, the location-based method ensures consistency and comparability across industries. It also aligns with broader policy and scientific needs by representing the actual emissions intensity of electricity grids. In practice, both methods provide complementary insights: location-based emissions highlight the environmental impact of where companies operate, while market-based emissions reflect how they procure electricity. Together, eGRID and location-based reporting remain foundational for credible climate disclosures.

Constellation has been offering its customers Location Based emissions reporting for the last three years, 2024 reports are available in our customer portal with self-service functionality.