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Weekly Energy Industry Summary
Commodity Fundamentals
Week of August 17, 2026
- Prompt-month natural gas settled at $2.69/MMbtu, down $.04 on Monday, August 17.
- One week ago, Prompt-month natural gas settled at $2.79/MMbtu, on Monday, August 10.
- Two weeks ago, Prompt-month natural gas settled at $2.78/MMbtu, on Monday, August 3.
- Prompt-month crude oil (WTI) settled at $84.50/bbl., up $2.10 on Monday, August 17.
- One week ago, Prompt-month crude oil (WTI) settled at $82.13/bbl., on Monday, August 10.
- Two weeks ago, Prompt-month crude oil (WTI) settled at $79.28/bbl., on Monday, August 3.
Natural Gas Fundamentals - Neutral/Bearish
- The Southern heat wave will ease a bit in the East next week, but in the Southwest, elevated summer temperatures will continue.
- Above the Mason-Dixon line, the temperatures are trending normal-to-below through next week.
- Summer is moving into the rear-view mirror from a power-generation demand perspective.
- Production of natural gas is grinding upward. Month-to-date, August production averaged 111.3 Bcf per day, up ratably about 2 Bcf per day from June, and up 3.4 Bcf per day over the same period last year.
- Higher oil prices are spurring increased output of "associated" natural gas production; gas that is "associated" with the production of crude oil.
- Near-dated natural gas futures are weak as rising production and ample storage inventories weigh against LNG exports and summer power-generation demand.
- LNG feedgas deliveries are increasing as the Freeport LNG terminal is coming back on-line after several weeks of scheduled maintenance. LNG feedgas volumes averaged 18.5 Bcf per day in August versus 16.5 Bcf per day over the same period last year.
- 2027-2031 strip prices settled yesterday (8/17) at $3.28, $3.67, $3.68, $3.62 and $3.57/MMbtu respectively.
- One week ago, 2027-2031 strip prices settled at $3.35, $3.68, $3.70, $3.65, $3.60 per MMbtu respectively.
Crude Oil - Bullish
- Point of Clarification: The "Bullish" moniker above will remain in place until further notice as the situation in the Persian Gulf remains highly unstable.
- Prompt-month crude (WTI) settled at $84.50/bbl., up $2.10 on Monday, August 17.
- The 60-day Memorandum of Understanding (MOU) that the U.S. and Iran signed on June 17, expired yesterday.
- Iran's foreign ministry ruled out talks to extend the MOU.
- President Trump said he was not interested in extending the deal.
- Fading hopes for an agreement anytime soon to resolve the conflict keep oil-futures buoyant and volatile.
- Higher oil prices are prompting increased natural gas production in the U.S.
Economy - Neutral
- U.S. housing starts were well below forecast in July, dropping 12.4% to 1.239 million.
- Data from The National Association of Home Builders' showed builder sentiment remains weak.
- The 30-year treasury yield hit 5.33%, a 19-year high, on inflation and spending concerns.
- Wholesale prices were flat in July, below expectations; a 0.2% increase was reported.
- The Consumer Price Index annual rate of inflation is 3.4%.
- The Federal Reserve Bank of New York's statewide manufacturing index rose to 20.6, its highest level in four years.
- The University of Michigan Consumer Sentiment Index fell in August to 51 from 55.2 in July. A final number for August will be published at the end of this month.
Weather - Neutral
- A strong heat wave in the South eases a bit in the East cut continues in the Southwest.
- Above the Mason-Dixon line, temperatures move into a more seasonal to slightly below-normal pattern next week.
Weekly Natural Gas Report
- Inventories of natural gas in underground storage for the week ending August 7 are 3,153 Bcf; an injection of 36 Bcf was reported for the week ending August 7. Stocks were 25 Bcf lower than this time last year and 198 Bcf above the five-year-average.
Weekly Power Report:
Mid-Atlantic Electric Summary
- The Mid-Atlantic Region’s forward power prices were slightly lower over that past week as market fundamentals remained stable during that time. The NYMEX natural gas prompt-month contract continues to remain tempered, well below the $3.00/MMBtu level, with ample supply and comfortable storage levels offsetting the impact of elevated cooling demand and a modest supply-demand deficit. Weekend forecast changes were mixed, with cooler trends in the East offset by warmer/hotter adjustments from the southern Plains into the West. The primary feature is a southern heat ridge, with storm systems tracking along its northern edge from the Midwest into the East. The ridge will begin to retreat from the South later this week and shift toward the West, while the southern Plains remain the pivot point for persistent heat. This evolution will lead to a milder pattern across the Midwest and East next week, with heat continuing from the southern Plains and Texas into the West. The forward electricity prices for the 2027-2031 strips were, on average, -2% lower over the past week and were unchanged over the past month. The month-to-date, day-ahead price thus far for August in West Hub is $59.03/MWh which is -34% lower than July’s final settlement price average of $89.78/MWh.
- PJM Files Interim Resource Adequacy Service (IRAS) with FERC – On 8/13, PJM filed its IRAS proposal at FERC. The proposal would require each Load Serving Entity (LSE) to bring new capacity in an amount equal to new large load or be subject to PJM curtailment instructions for shortfall amounts during stressed system conditions beginning on 6/1/27. IRAS load would be curtailed before demand response resources that are paid to voluntarily reduce their load during system emergencies. PJM also proposes that, beginning with the upcoming 2029/2030 capacity auction, new IRAS loads will not be included when calculating future power needs. IRAS load that is instructed to curtail could be eligible for credit, subject to state retail cost allocation rules in the affected areas. If approved by FERC, IRAS will be in effect for years in which PJM fails to procure enough capacity to meet the Reliability Requirement for the upcoming delivery year after the completion of that year’s 3rd Incremental Auction. If PJM has three consecutive delivery years in which IRAS is not in effect, the large loads previously subject to IRAS will no longer be subject to IRAS and BYONC resources will be relieved of their price taker offer obligation and participation obligations and can participate in the market as traditional capacity resources. Additionally, PJM proposes to maintain a central registry of all loads 50 MWs or greater, which will track each project including but not limited to location, in-service schedule, and the amount of IRAS load subject to curtailment. FERC must act on PJM’s filing no later than 10/12.
Great Lakes Electric Summary
- The Great Lakes Region’s forward power prices were slightly lower over that past week as market fundamentals remained stable during that time. The NYMEX natural gas prompt-month contract continues to remain tempered, well below the $3.00/MMBtu level, with ample supply and comfortable storage levels offsetting the impact of elevated cooling demand and a modest supply-demand deficit. Weekend forecast changes were mixed, with cooler trends in the East offset by warmer/hotter adjustments from the southern Plains into the West. The primary feature is a southern heat ridge, with storm systems tracking along its northern edge from the Midwest into the East. The ridge will begin to retreat from the South later this week and shift toward the West, while the southern Plains remain the pivot point for persistent heat. This evolution will lead to a milder pattern across the Midwest and East next week, with heat continuing from the southern Plains and Texas into the West. The forward electricity prices for the 2027-2031 strips were, on average, -2% lower over the past week and were unchanged over the past month. The month-to-date, day-ahead settlement price average thus far in COMED is $43.05/MWh or is -36% lower than July’s final price of $67.08/MWh, while that price for AdHub is $49.48/MWh month-to-date and is -32% lower than July’s average price of $72.31/MWh. In Michigan the month-to-date price thus far is $48.00/MWh or is -38% lower from the prior month, while in Ameren the average price so far for the month is $43.88/MWh or is -36% lower than last month’s final settlement price in July.
- PJM Files Interim Resource Adequacy Service (IRAS) with FERC – On 8/13, PJM filed its IRAS proposal at FERC. The proposal would require each Load Serving Entity (LSE) to bring new capacity in an amount equal to new large load or be subject to PJM curtailment instructions for shortfall amounts during stressed system conditions beginning on 6/1/27. IRAS load would be curtailed before demand response resources that are paid to voluntarily reduce their load during system emergencies. PJM also proposes that, beginning with the upcoming 2029/2030 capacity auction, new IRAS loads will not be included when calculating future power needs. IRAS load that is instructed to curtail could be eligible for credit, subject to state retail cost allocation rules in the affected areas. If approved by FERC, IRAS will be in effect for years in which PJM fails to procure enough capacity to meet the Reliability Requirement for the upcoming delivery year after the completion of that year’s 3rd Incremental Auction. If PJM has three consecutive delivery years in which IRAS is not in effect, the large loads previously subject to IRAS will no longer be subject to IRAS and BYONC resources will be relieved of their price taker offer obligation and participation obligations and can participate in the market as traditional capacity resources. Additionally, PJM proposes to maintain a central registry of all loads 50 MWs or greater, which will track each project including but not limited to location, in-service schedule, and the amount of IRAS load subject to curtailment. FERC must act on PJM’s filing no later than 10/12.
Northeast Energy Summary
- New England energy forward strips continue their volatility but, in contrast to most week's since late February, actually moved lower marginally. The calendar 2027 - 30 strips moved down an average of 0.5% on the week which is in contrast to global natural gas prices (particularly the prompt month Dutch TTF contract) moving up 11% on the week. We've typically seen a strong, positive correlation between the Dutch TTF contract price and New England forward energy prices because the region's reliability of liquified natural gas during the cold winter months and the need to pay the global market price to financially incentivize LNG cargoes to New England. For this past week, the correlation weakened but is likely temporary with potentially summer heat dissipating and lower risk of daily wholesale prices potentially driving Mass Hub forward prices lower. Upward pressure for global natural gas continues as the US war with Iran moves into a stalemate with Strait of Hormuz traffic last week ranging from only 3 to 16 passages (pre-war passage averaged ~130). As both Europe and Asian prepare for the winter ahead stocking natural gas in storage will continue to be a priority. LNG cargo buying could tick up further and with it, price increases. The Dutch TTF prompt month contract has moved from a low of $13/MMBtu in late June following the 60-day cease fire agreement between two countries to now $21/MMBtu with more upside potential as winter draws near. The European storage situation isn't yet considered dire but inventories are well below the 5-year average by 23% and currently at 59% capacity. Storage was at 72% capacity last year at this time and with at 90% target by December 1, EU countries will either need to accelerate their buying or risk missing those supply goals.
- Earlier this year, Maine passed LD 2112 to allow municipalities to establish aggregation programs to procure electricity. The law also requires the Public Utilities Commission (PUC) to initiate rulemaking for the program, including the process municipalities must follow to establish an aggregation program, standards for approval of a program, the opt-in and opt-out procedures for customers, timing and notice requirements for automatic enrollments, consumer protection and transparency requirements, requirements for data sharing by the electric distribution companies (EDCs), a standard service agreement for suppliers serving an aggregation program, a process to ensure EDCs do not incur costs to implement these requirements, and provisions to minimize impacts to default service. The PUC must initiate this rulemaking before Jan 1, 2027; in order to do so, the PUC opened Docket 2026-00210 and is seeking stakeholder input.
- New York Moves to Create Statewide Demand Response Platform - On 8/13, the Public Service Commission (PSC) acted to initiate the Excelsior Power Program, a statewide demand response platform intended to consolidate utility customer direct load control programs, improve customer participation, and deliver lower-cost grid reliability benefits. The program was directed by Governor Hochul and supported by $33 million in the FY 2026-2027 state budget, including $30 million for customer payments and $3 million for utility administrative costs. Utilities with existing “bring your own thermostat” programs must submit an initial implementation proposal within 30 days. Concurrently, all utilities must file a more detailed second-phase proposal within 120 days. New enrollees are expected to receive $25 monthly bill credits during their first year, although roughly 120,000 customers already enrolled in voluntary demand response programs will not be eligible. The program is designed to standardize participation across utilities, reduce administrative costs, expand eligible controllable devices beyond smart thermostats, and increase the aggregate value of distributed resources during peak demand periods. Department of Public Service staff cautioned the platform is unlikely to launch before late 2027
ERCOT Energy Summary
- Summer was consistently strong last week in Texas with temperatures 100-102 F in Dallas, upper 90’s in Houston while San Antonio and Austin ranged from 101-102 F on high side before a storm moved through over the weekend.
- Looking at the last weeks of August, we will start with conditions this week. Temperatures are responding to the dry conditions in Texas, with readings reaching the upper end of the guidance. On Monday, Dallas reached 106°F, Houston 99°F, and San Antonio 100°F. Expect a rinse-and-repeat pattern today, with similar temperatures. This level of heat will remain in place through the balance of the week, alongside another dip in wind generation on Friday and Saturday. The following week also looks hot, with temperatures generally within a degree or two of this week’s levels and little moderation expected until later in the 11–15-day period. However, the lower temperatures and increased rain risks shown later in the 11-15 have not moved forward in the timing
- Forward prices in ERCOT corrected last week after selling off the week before due to Gov. Abbott’s mandated audit of data centers, while will likely delay developments in outer years. Cal 2027 North Zone was up 4.1% week over week, Cal 2028 was higher by ~6.3% and Cal 2029 was higher by ~5%.
ERCOT Real Time Prices
Source: ERCOT
- Real time prices remained in the upper $20’s/MWh last week as strong renewable (wind & solar) helped keep prices in check. The only one hours last week when prices rose above $100/MWh
Recent Solar, Wind and Battery Milestones:
- ERCOT hit a new solar output record on Sunday 8/16 of 23,517 MW at 11:15 am CT. This surpassed the another record set on August 15th for 23,486 MW at 12:05 pm CT. The top four days for ERCOT Solar output have occurred so far this August.
- There were no new battery records last week. On the battery front, ERCOT set its 5th new charging record since June 1st on August 7th of 11,245 MW at 9:25 am CT, super seceding the July 4th charging record set of 10,522 MW. On June 1st the charging record was set at 7,847 MW, with the 3.3 GW growth representing a growth rate of 43% so far this summer.
- The new all-time maximum load record of 91,089 MW from July 22nd still stands but August has traditionally seen ERCOT set its new peak loads. ERCOT set a new maximum solar output record 35,281 MW on July 30th and the second new one this week. On July 8th ERCOT set a new discharge record for batteries of 11,674 MW breaking the record of 10,372 MW set back on March 13th.
- June 25th saw a new record output for combined renewables of 51,974 MW, the second this week and breaking the previous record of 47,919 MW on May 14th. ERCOT set a new wind record last week at 28,928 MW on May 17th at 11:50 PM CT as winds were strong overnight. The previous maximum wind record of 28,715 MW set on 3/14 at 10:55 pm CT. ERCOT also set a maximum renewables output of 47,919 MW on May 14th at 3:15 pm CT. This was ~900 MW higher than the previous record from last June.
Generator Outages
- Thermal generation outages held steady last week (8/10) at 9-10 GW amid continued warm temperatures. Wind, solar and batteries again helped provide adequate reserves. While this heat event was short lived its demonstrates how forced outages can rise during an extended heat wave event. August could see a return of above normal temps as that is typically the month ERCOT sets its highest loads.
https://www.gridstatus.io/graph/ercot-outages?iso=ercot&outageType=thermal
Source: ERCOT & Grid Status
TX Legislature, PUCT, & ERCOT News:
PUCT Discusses ERCOT Data Center Audit Plan and 765-kV Transmission Lines; Action on Batch Audit Process Expected 8/20 - Chair Gleeson convened a special open meeting on 8/14 to discuss ERCOT's proposed large load audit framework and the development of 765-kV transmission lines. During public comment, several legislators, joined members of the public in expressing opposition to the proposed 765-kV transmission projects. Although the commission did not make any decisions regarding the transmission lines, the issue is expected to receive attention during the House State Affairs Committee hearing on 8/19.
In response to Gov. Abbott's August 3rd Executive Order that called for an audit of all large load applications before any would be allowed to connect to the ERCOT grid, ERCOT filed for a “good cause exemption”. ERCOT provided a high-level overview of its 8/10 good-cause exception filing related to large load interconnections, noting that a more detailed discussion including implementation timelines is expected at the 8/20 open meeting. ERCOT described a two-track approach for evaluating large load interconnection requests. First, ERCOT plans to accelerate implementation of the verification requirements contained in PGRR145, making verification a mandatory gating step for all Batch 0 interconnection attestations, with no exemptions based on load type.
Second, ERCOT will launch a "community impact information" audit in response to Governor Abbott's directive to review data centers and virtual currency mining facilities seeking interconnection. This audit will apply only to unenergized data centers and crypto mining facilities of 25 MW or greater and will not extend to other categories of large industrial load.
Testifying at the meeting was ERCOT general counsel Chad Seely, who told the commissioners that the verification process for large loads connecting was to be done in parallel with the “Batch Zero” interconnection study will now be separated and worked on exclusively by ERCOT. The verification process would be done as “a gating item before we begin the interconnection study process,” Seely testified. Giving the commissioners a sense of timeline for the verification process Sealy said, ““It will take us several months to go through that process,” he said of the verification process and audit. “It was going to already take us about nine months to go through that process from September to April. We don’t anticipate it’ll take as long as nine months to do that, but it is now a gating issue.”
PUCT Receives Comments in Project No. 58000, Rulemaking to Update Wholesale and IOU Retail Transmission Cost Recovery in ERCOT - This rulemaking is aimed at ensuring that transmission costs associated with rapid large-load growth are assigned to the customers driving those investments rather than shifted to residential and small-business ratepayers. The proposed rule would replace ERCOT's current 4 Coincident Peak (4CP) transmission cost allocation methodology with a 12 Coincident Peak (12CP) approach, require transmission-related billing based on monthly system peaks, and establish new transmission cost recovery mechanisms for large loads, including data centers and other customers exceeding 75 MW. The rulemaking also requires large loads to begin paying transmission-related charges when reserved capacity becomes available, even if the customer has not yet energized, and directs certain interconnection fees and forfeited financial security to offset transmission revenue requirements. On 8/11 the PUCT received approximately 60 sets of comments reflecting significant disagreement over how transmission costs should be allocated.
The proposed minimum billing demand (MBD) requirement for large loads is a central issue in the proceeding. Consumers argue that large customers should be required to pay based on 100% of contracted transmission capacity for the full life of transmission assets to protect existing customers from stranded infrastructure costs. Data center developers, large-load advocates, and flexible-load providers counter that a 100% MBD requirement for 20 years would substantially over-collect costs, reduce operational flexibility, and undermine demand response programs that support grid reliability. Several parties have proposed lower or declining minimum billing demand levels over time, while others seek differentiated treatment for loads co-located with generation resources that may impose fewer transmission costs on the system. There is broad consensus that large loads should bear the costs they cause, but significant disagreement remains regarding the appropriate balance between protecting ratepayers from stranded transmission investments and preserving incentives for flexible operations, curtailment, and innovative load-serving arrangements. The PUCT is expected to adopt a final rule by the December 2026 statutory deadline.
CAISO, Desert Southwest and Pacific Northwest Energy Summary
- California ended last week on a bit of a lull as temperatures moderated but there is still plenty of summer left. Temperatures in the 90s are common across inland Southern California. Our reference point for the LA Basin (Burbank airport) looks to be moving up to 97 degree mark by Wednesday while Sacramento looks to trail is a few degrees behind this week. Record challenging heat will be seen across parts of the Desert Southwest today, particularly around Phoenix where daytime highs are forecast to climb into the low 110s. Even the Pacific Northwest is seeing a brief wave of heat in the mid to upper 90s. The models are generally in good agreement regarding the weather pattern to take us through the end of August with consistent above normal temperatures from the Rockies westward, with the exception of the major coastal population centers where temperatures will remain closer to normal.
- Natural gas demand has moved higher for three days in a row as cooling demand increases. Up north, PG&E's demand hit 1.9 Bcf/d while SoCalGas made it to 1.7 bcf/d moving up a couple ticks from the weekend. Because of the pop in demand, daily gas prices rose, PG&E’s gate to the city cleared at $3.38 Bcf for flow Tuesday while SoCal’s gate moved up a dime to $3.77. NorCal is currently running short on gas imports from the Pacific Northwest, forcing them to pull gas out of storage. We expect cash gas prices to remain supportive given the conditions on the grid as the above normals look to stick around for the balance of the month. Slightly more so in SoCal as the year over year storage situation has slowly tilted to the negative side; while their storage is right around 100 Bcf, it is now trailing last year at this time by 4 Bcf.
- Despite all the extra heat, the CAISO grid is in good shape and dispatchers have tools at their disposal to manage the demand. Peak loads have dropped a bit from their highs earlier in the month, the late day peak on August 4th was over 43 GW but dropped to as low as about 32 gigawatts on Saturday and looks to make it to a little over 40 GW by tomorrow. Day-ahead index for flow on Tuesday have come off the Monday sugar high despite the warming temps. In SP15, the heavy load fell to $40.71 MWh, while NP15 settled at $45.88, both down about $4.00 from yesterday. Power imports from neighboring states did most of the heavy lifting to keep the grid steady. As we move into the late innings of summer, the imports will tail off as the dams, especially those in the Desert, work through water conditions set by a winter snowpack that never showed up.
- Update to one of our stories last week – a pair of decent water years earlier this decade offered a brief reprieve, but it was never going to be enough to reverse the damage of a megadrought now in its third decade. Lake Mead, the reservoir behind Hoover Dam, now at 1,039 ft, continues to see its level fall to lows not seen since it was initially filled about 90 years ago. The water level at Lake Powell, the States’ second-largest reservoir and the one upstream behind the Glen Canyon dam, has also fallen to a new record low, now down to 3,519 ft as of Monday, further heightening concerns about the water crisis on the Colorado River system. Our focus is energy, so we’ll let others more qualified handle the importance of the water supply to millions along with the agriculture angles, but every foot of decline chips away at how much power the dams can produce. Hoover still has room to run as Lake Mead sits well above the 950 foot mark where the dam can no longer generate, the cushion for Glen Canyon is getting thin as its turbines shut down at 3,490 ft, which is now just 29 ft away. A good lunchtime read on the topic here.
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