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Weekly Energy Industry Summary

Commodity Fundamentals

Week of December 8, 2025

By The Numbers:

  • Prompt month NYMEX natural gas settled at $4.92/MMbtu, down $.38 on Monday, December 8.
  • Prompt month NYMEX crude oil settled at $58.88/bbl., down $1.20 on Monday, December 8.

Natural Gas Fundamentals - Neutral

  • December begins on a cold note for the first time in 12 years.
  • After rallying to a three year prompt-month high last Friday, gas prices backed off as forecasts for a mid-month warm up, most pronounced in the southern and middle tier of the country, tempered bullish sentiment.
  • Production has been surging over the past several weeks as the end of 2025 nears.
  • Production has exceeded 110 Bcf per day for several days over the past two weeks.
  • Month-to-date, natural gas production averaged 109.3 Bcf per day versus 103.5 Bcf per day for the same period last year.
  • Residential demand averaged 47.5 Bcf per day month-to-date versus 41.6 Bcf per day for the same period last year.
  • Industrial demand averaged 26.3 Bcf per day month-to-date versus 25.8 Bcf per day for the same period last year.
  • LNG exports month-to-date averaged 18.8 Bcf per day versus 14 Bcf per day for the same period last year.

Crude Oil - Neutral/Bearish

  • NYMEX (WTI) prompt-month crude settled at $58.88/bbl., on Monday, December 8 down $1.20.
  • Global commodities trader Trafigura said the global oil market is headed for a "super glut" in 2026.
  • Crude oil is under pressure as crack spreads tighten, reducing profits to refiners and disincentivizing forward purchases.
  • Saudi Aramco lowered its price to Asian customers by $.30 per barrel for January adding to near-term bearish sentiment.

Economy - Neutral

  • Layoffs crept higher in recent months, but the job market remains fundamentally steady, the Labor Department reports.
  • Jobless claims fell to a recent new low as the Labor Department reported 191,000 Americans filed for new unemployment benefits the week of November 29.
  • Most Fed watchers expect a modest rate cut before the end of the year.
  • Confidence among small businesses in the U.S. edged up in November, with optimism boosted by higher sales expectations.
  • Housing remains sluggish.

Weather - Neutral/Bullish

  • Cold air remains in the northern tier and Great Lakes Region through this week.
  • A general warm up, most pronounced in the South, and Southeast will move into the Mid-Atlantic and lower Midwest in the middle of the month.
  • Cold air remains available to move south toward the end of the month.
  • Constellation's weather desk is calling for a cold January.

Weekly Natural Gas Report:

 
  • Inventories of natural gas in underground storage for the week ending November 28 are 3,923 Bcf; a withdrawal of 12 Bcf was reported for the week ending November 28.
  • Gas inventories are 191 Bcf above the five-year average and 18 Bcf less than the same time last year. 
Values reflect week ending Dec. 5, 2025
Prices reflect week ending Dec. 5, 2025

Weekly Power Report:

Mid-Atlantic Electric Summary

  • The Mid-Atlantic Region’s forward power prices were slightly higher on the week with most of the price support on the front of the price curve for 2026.  January natural gas futures built momentum on expected cold fronts and sustained much of the progress following a government inventory report that showed underground supply continued to decline as winter heating demand and LNG volumes escalated. The easing of the cold pattern gained some support over the weekend, but we still face a cold pattern for the next ten days.  It will be very cold in the East to start this week, with a brief midweek pause before another surge of strong cold air moves into the eastern half of the nation this weekend. Forward power prices for the 2026-2030 terms were 1% higher, on average, week-over-week, but saw a 5% increase for the 2026 term.  The back of the curve was relatively unchanged for the 2027-2030 terms.  The final day-ahead settlement price average in West Hub for the month of November was $53.76/MWh, which is 5% higher than the prior month of October and 70% higher than the prior year.
  • PJM Presents Information on 2026 Large Load Additions for the 2026 Load Forecast - On 11/24, PJM’s Load Analysis Subcommittee (LAS) reviewed PJM’s new large load adjustments for the upcoming 2026 load forecast.  PJM significantly trimmed many of the EDCs’ large load requests and the overall proposed large load adjustment for the 2026 forecast aligns closely to the large loads already included in the 2025 forecast through ~2032.   At the 11/24 meeting, PJM outlined its validation process for Electric Distribution Company (EDC) requests, which included assessing project firmness and applying standardized modeling criteria.  Projects with binding agreements were classified as firm, minimum ramp periods of three to eight years were imposed, and a default 70% utilization rate was applied unless otherwise supported.  Non-firm projects were heavily discounted - particularly before 2030, when PJM excludes all non-firm projects - with national-trend scaling applied thereafter.  PJM also confirmed that industrial load growth is already captured in economic models and excluded duplicative requests.  Several EDCs saw significant reductions in their large load requests.  PJM currently hosts roughly 40% of U.S. data center capacity, with potential growth of up to 30 GW between 2025 and 2030.  

Great Lakes Electric Summary

  • The Great Lakes Region’s forward power prices were slightly higher on the week with most of the price support on the front of the price curve for 2026.  January natural gas futures built momentum on expected cold fronts and sustained much of the progress following a government inventory report that showed underground supply continued to decline as winter heating demand and LNG volumes escalated. The easing of the cold pattern gained some support over the weekend, but we still face a cold pattern for the next ten days.  It will be very cold in the East to start this week, with a brief midweek pause before another surge of strong cold air moves into the eastern half of the nation this weekend.  Forward power prices for the 2026-2030 terms were unchanged for the week, but saw a 4% increase for the 2026 term.  The back of the curve was actually -1% lower, on average, for the 2027-2030 terms.  The final day-ahead settlement price average in COMED for the month of November was $36.91/MWh, which is 6% higher than the prior month of October and 63% higher than the prior year, while the same settlement average in AdHub was $47.37/MWh, which was -3% lower than last month but 62% higher than the prior year.  In Michigan the final day-ahead settlement price average for the month of November was $41.92/MWh, which is 5% higher than the prior month of October and 53% higher than the prior year, while the same settlement average in Ameren was $37.63/MWh, which is 7% higher than last month and 47% higher than the prior year. 
  • PJM Presents Information on 2026 Large Load Additions for the 2026 Load Forecast - On 11/24, PJM’s Load Analysis Subcommittee (LAS) reviewed PJM’s new large load adjustments for the upcoming 2026 load forecast.  PJM significantly trimmed many of the EDCs’ large load requests and the overall proposed large load adjustment for the 2026 forecast aligns closely to the large loads already included in the 2025 forecast through ~2032.   At the 11/24 meeting, PJM outlined its validation process for Electric Distribution Company (EDC) requests, which included assessing project firmness and applying standardized modeling criteria.  Projects with binding agreements were classified as firm, minimum ramp periods of three to eight years were imposed, and a default 70% utilization rate was applied unless otherwise supported.  Non-firm projects were heavily discounted - particularly before 2030, when PJM excludes all non-firm projects - with national-trend scaling applied thereafter.  PJM also confirmed that industrial load growth is already captured in economic models and excluded duplicative requests.  Several EDCs saw significant reductions in their large load requests.  PJM currently hosts roughly 40% of U.S. data center capacity, with potential growth of up to 30 GW between 2025 and 2030.  

Northeast Energy Summary

  • On November 12, the New Hampshire Department of Energy (NH DOE) released their Renewable Portfolio Standard 2025 Review, the last review of the RPS program required by New Hampshire’s RPS law.  The report provides a detailed background of the program, the objectives of the program, the impact the program had on promoting development of renewable energy resources in New Hampshire, and recommended policy changes to further advance the goals of the RPS program.  The review notes that New Hampshire does not have as aggressive RPS obligations as other New England states, as New Hampshire has prioritized balancing renewable energy goals while avoiding undue burdens on ratepayers.  The review concludes that the program succeeds in achieving this balance as New Hampshire has seen growth in renewable energy resources but maintains lower electricity prices than the average New England rate in all but one of the last 7 years. The review also includes five suggested legislative policy recommendations.  First, the review recommends establishing a Class III RPS obligation of 5% and removing the ability for the DOE to review and lower the obligation as necessary.  Current law sets the obligation for Class III resources, including methane and biogas, at 8% and allows the DOE to lower the obligation to 0.5% if it determines not enough Class III RECs are produced to meet the obligations of suppliers.  The review claims setting the obligation at 5% and removing the ability to lower the obligations will provide market certainty. The department has typically lowered the obligations to 0.5-1%.  Second, the review suggests that the state amends the RPS statute to require a review of the RPS program again in 2030, 2035, and 2040 to ensure the program is still functioning to meet policy objectives.  Currently, the 2025 Review is the last one required by state law.  Third, the review advises the state maintains the ability to count net metered facilities that are not REC-registered to count towards RPS compliance.  The review claims this would prevent unnecessary costs being passed on to ratepayers.  Fourth, the review notes that the state should examine whether the final 25.2% obligation should be maintained, increased, or decreased beyond 2025 to align with the state’s 10-year energy strategy.  Finally, the review suggests the state consider adopting or integrating a Clean Energy Standard into the RPS framework to account for low/zero-carbon energy resources that fit within the policy objectives of the RPS.  The report says this will help maintain existing resources such as hydropower facilities but also help promote the development of small modular nuclear reactors. 
  • As part of the NYISO’s Reliability Planning Process (RPP) NYISO recently posted its biennial Comprehensive Reliability Plan (CRP) Report highlighting various reliability concerns within the system over the next 5-10 years, many of which were noted in the NYISO’s most recent Reliability Needs Assessment (RNA) and Q3-2025 Short Term Assessment of Reliability (STAR) Report. The NYISO noted the Ny states aging generation fleet/infrastructure, the rapid growth of large loads, and the difficulty indeveloping new dispatchable resources, along with the increase in extreme weather events as main concerns.  A solicitation for solutions for these needs has been issued and the NYISO will begin stakeholder discussions about possible modifications to its Reliability Planning Process before the next RNA assessment begins in 2026.
  • On December 5th, the New York State Reliability Council (NYSRC) Executive Committee set the Installed Reserve Margin (IRM) for the 2026-2027 Planning Year (PY) at 24.5%, up from the current IRM (PY 2025-2026) of 24.4%, but lower than the 25.6% IRM recommended as part of the NYISO’s Special Sensitivity Case technical study, which was used as the Final Base Case. In addition to utilizing results from various sensitivity and technical studies, the NYSRC considered reliability risks noted in the NYISO Q3 Short Term Assessment of Reliability (STAR) report, as well as planned modifications to the Local Capacity Requirement (LCR)  methodology and other factors into the final IRM.  The IRM requirement at 24.5% equates to an ICR of 1.245 times the forecasted NYCA 2026 peak load.

ERCOT Energy Summary

CAISO, Desert Southwest and Pacific Northwest Energy Summary

  • Late summer weather has returned to SoCal as daytime highs in the 80s become common this week while overnight lows drop into the 50s. NorCal will see mild temperatures as well as 50s and 60s dominate the outlook for the next 10 days. Across the Western U.S., widespread above to much above normal temperatures will be seen through the next couple of weeks as the coldest air is expected to remain trapped in Western Canada heading into the final third of the month with limited colder signals for the States. Wind generation out of the Pacific Northwest will average above normal this week and be rather strong at times as a strong Pacific flow combines with storminess making MWh available just as the weather eliminates the need for them. In California, diversity in the renewable stack will balance to some degree as in-state wind generation will be much below normal as the high-pressure system that ushers in autumn temps also flattens out the wind; yet it will clear out the cloud deck providing near ideal late year solar generation conditions. Let’s not overlook a downside to this late season warmth – it’s impacting snowpack. Although we’re still early in the water year, snow is a crucial part of the equation for pricing come spring and summer and we’re off to a pretty lousy start.
  • The mild weather’s impact on demand volumes will be seen during the overnight hours and morning ramp. While the weather warms this week there is still a possibility of further gas withdrawals from storage in both PG&E and SoCal territories in a continuation of activity seen over the last couple of weeks. This is counter-intuitive, so let’s review. Temperatures in the West stand in stark contrast to other parts of the country and demand levels should be easily met using import volumes. But as demand spikes in regions to the east, molecules move in that direction. Producing regions like the Permian, Rockies and Canadian imports will send their output towards the area of greatest need (price) and the import volumes available in California dwindle, thus the pull from storage.
  • As the flow of natural gas into California slows, that is not the case with electrons on the grid. Strong solar production across the deserts in-state and to our immediate east will keep midday prices in check at the same time the return of Palo Verde 3 from a refueling outage puts 1200 megawatts of generation back on the grid and in need of finding a home. Imports from the DSW hit their highest levels since last February over the weekend as that unit ramped back up to full steam. Index buyers should see lower prices (negatives in SP15?) during peak solar hours this week and diminished evening ramp prices.
  • The Wildfire Forecast & Threat Intelligence Integration Center (known by its easy-to-remember acronym: WFTIIC) serves as California's integrated central organizing hub for wildfire forecasting, weather information, threat intelligence gathering, analysis and dissemination. Its dashboard tracking fire watches, red flag warnings and active fires at the time we went to press was showing a rare triple goose-egg reading on those three dials. Enjoy the slow days.

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