Energy Markets Update

Editor’s Note: In this update, we provide a snapshot of recent gas and power market movements, major infrastructure developments, and key policy shifts shaping the energy landscape. We cover NYMEX gas price swings, storage surpluses, and forward strip trends, alongside wholesale power premiums in key ISOs. Highlights include Enbridge’s pipeline expansions, Egypt’s LNG import pivot, the halt of the Revolution Wind project and its policy implications, new Treasury rules for wind and solar tax credits, ongoing utility consolidation efforts, and PJM’s capacity auction fallout with upcoming market reforms. 

Table of Contents

• Market Update
• Winds of Uncertainty: Revolution Wind Puton Ice
  
• Set a Course for Construction: The Safe Harbor Standard is Closing for Wind & Solar
• Duking it Out in the Carolinas
• Mid-Atlantic States Turn up the Heat on PJM 
  

Weekly Natural Gas Inventories

Source: EIA

Market Update

• In the past month NYMEX prompt-month gas futures posted their most significant decline since November ‘24, retreating to the $2.60 per MMBtu range in late August amid mild weather, robust production and persistent above-average gas storage levels. This week the October gas contract took a bullish turn, rising above the psychological $3 mark and settling just above at $3.029 per MMBtu at yesterday’s market close, though remains down 17% overall compared to the trailing 1-year of trading activity.
• This week’s storage report recorded a net injection of 71 Bcf, surpassing analysts’ expectations and maintaining levels roughly 6% above the 5-year average. The lingering impact of record production particularly from Western Canada continues to manifest in the healthy storage surplus.
• US gas demand retreated about 7% week-over-week, led principally by lower power burn. Even so the EIA adjusted its gas consumption forecast up 1% for the remainder of 2025, which if met will set a record 0f 91.4 Bcf/day.
  
  
  Source: EIA
• The 2026 NYMEX forward strip, currently trading at $3.885 per MMBtu and at a 12% premium to 2025, demonstrates marginal upward movement of ~0.5% month-over-month. This period however, has been marked by considerable volatility (21%), particularly in the near-term ‘25/early 26. The 2025 strip touched lows of $3.09 per MMBtu in late August before rallying to sustain levels in the high $3 range this week.
• Future years 2027/28 have demonstrated greater stability over the past month, with fluctuations of approximately 2% and currently trading within 1% of month-ago levels. The 2027 strip peaked at $3.93 per MMBtu, nearing but ultimately remaining below the critical $4 threshold for gas/coal parity and fuel switching.
• Winter gas pricing has declined 11% since early 2025, while the outer year '27/28 forward strips have maintained more consistent support (2-3%) over the same timeframe, a reversal of trends from earlier this year. Our recommended strategy remains to lock in long-term basis contracts and manage NYMEX intermittently given the lasting premium set for 2026 gas.
• Wholesale power markets have mirrored gas dynamics across most ISO’s, with significant 2026 premiums evident in PJM, SPP, and notably ERCOT at 43% higher than the average trailing 12-month wholesale price. This reflects the bullish demand trajectory anticipated in ERCOT, with forecasts projecting 14% demand growth in 2026, driven by rapid datacenter and manufacturing expansion.
   
  
  Source: Veolia, Data via Argus
• In other news: Enbridge recently reached an FID on two major gas pipeline expansion projects, signalling meaningful capacity additions ahead. The AGT Enhancement project will add 75 Mmcf/d of gas capacity in the Northeast by 2029 and will funnel over $300M into system upgrades. The Eiger Express Pipeline will transport 2.5 Bcf/d of gas from the Permian Basin in West Texas with a targeted completion date in 2028.
  
  
  • Both projects will be key to alleviating regional supply constraints persistent in the Northeast, with direct implications for NE power markets given natural gas's role as the marginal fuel for electricity generation.

       Source: Veolia, Data via Argus

• Egyptian-based firm Blue Ocean Energy has struck a $34B deal to import gas from Israel, seeking to address shortfalls in natural gas supply by ramping up LNG exports. Egypt’s promising Zohr field discovery in 2016 originally positioned the country to become a net exporter, but ultimately was set back by operational challenges. Egypt’s recent pivot to imports has left domestic demand consistently outpacing production.
• Just as New England electric customers became comfortable with DASI (Day-Ahead Ancillary Services Initiatives), ISO-NE announced this week a rebranding of the recently implemented ancillary services program. DASI, which replaced the region's traditional forward reserve market structure in favor of a day-ahead market for ancillaries, will now operate under the designation DAAS. Market participants should note this terminology adjustment for contracting purposes going forward.

Winds of Uncertainty: Revolution Wind Put on Ice

The Project at a Glance

Revolution Wind was supposed to be a landmark. Orsted’s 704 MW offshore wind farm, sited between Rhode Island and Connecticut, had 45 of its 65 turbines in the water and more than 80% of construction complete. The project promised to power over 350,000 homes across New England. Then, in late August, it all came to a halt.

A stop-work order from the Trump administration froze construction almost overnight – a gut punch to Orsted whose shares dropped more than 17% in a single day.

Source: Yahoo Finance

Why It Matters

This isn’t just about one wind farm. Revolution Wind was one of the furthest-along offshore projects in the U.S. and carried weight well beyond its 704 MW. Its pause sends an uneasy message about the offshore sector’s stability at a time when states are counting on offshore wind to hit renewable targets.

The U.S. pipeline stands at roughly 52 GW of planned capacity. For New England, losing or even delaying a nearly complete project means rethinking short-term energy strategies - and leaning more heavily on natural gas and imports in the meantime. Developers and state officials were caught off guard, and no one can say when, or if, the order will be lifted.

Market Implications

• Orsted’s balance sheet: Billions already spent, but revenue delayed indefinitely. Analysts are questioning the company’s U.S. expansion strategy.
• Investor confidence: The share plunge highlights how exposed clean energy developers are to policy risk, even when projects are nearly finished. Investors may start demanding higher risk premiums or shift capital to friendlier markets.
• The U.S. offshore sector: The stop has a chilling effect. Developers eyeing investment decisions in places like New Jersey or New York may think twice until federal signals are clearer.

What This Means for Clients
For most commercial and industrial buyers, the immediate impact is limited - Revolution Wind wasn’t slated to affect the market until closer to 2026. Its potential loss is material to the New England marketplace beyond 2026. The region was counting on its capacity, and it was already quite tight during the winter season when this project would have had an effect on price stabilization. Perhaps the bigger story is what the halt reveals: policy risk is back on the table for large-scale renewables.

Clients should expect:

• Continued reliance on gas and capacity markets in the near term. Offshore volumes that were supposed to ease pressure are stuck in limbo.
• More weight on distributed and behind-the-meter options. These smaller-scale projects remain insulated from federal pauses and can move faster through state and local permitting.
• Greater volatility in renewable procurement. Companies eyeing offshore PPAs may need backup strategies—or at least more patience—as the sector recalibrates.

Set a Course for Construction: The Safe Harbor Standard is Closing for Wind & Solar

In August, the Treasury Department issued updated guidance for  wind and solar projects to demonstrate commencement of construction, thereby qualifying for the Investment (48E) or Production Tax Credit (45Y) under the One Big Beautiful Bill Act (OBBBA). Effective September 2, 2025, these changes bring additional uncertainty to the tightening eligibility window, but avoid the drastic restrictions some had anticipated. The key takeaway is: Projects must demonstrate the start of their construction before July 5, 2026 to remain eligible for the tax credits. 

Previous Eligibility Rules:
Under the Inflation Reduction Act, solar and wind projects could demonstrate they are tax credit eligibility through the Physical Work Test or the Safe Harbor Test.

• Physical Work Test: Allowed significant on-site or off-site work (e.g., foundation digging, equipment manufacturing) to qualify as construction commencement, with no cost or completion percentage thresholds.
• Safe Harbor Test: Required developers to invest at least 5% of total project costs to qualify, including expenses like equipment orders or design contracts.
• Projects had to be placed in service within four years (or 10 years for offshore/federal land projects) to retain eligibility.

New Eligibility Rules:
The Treasury’s post-BBB guidance stipulates that construction on wind and solar projects “begins when physical work of a significant nature begins” on or off the proposed plant’s site.

• The Physical Work Test is now the primary method for demonstrating construction commencement, with no explicit thresholds for required work.
• The Safe Harbor Test is eliminated for most projects but remains available for small solar facilities (<1.5 MW per inverter string). The news caused shares in rooftop solar companies such as First Solar and Sunrun to jump by 9% and 8% respectively.
  • Capacity here is measured at each inverter’s string, meaning in theory larger solar projects could remain eligible if strings are placed in service in separate tax years.
• Wind and solar projects must start construction before July 5, 2026, and finish within four years to retain tax credit eligibility.
• Other electrical generation technologies (e.g., geothermal, hydroelectric) retain Safe Harbor eligibility through 2033.

Key Impacts:

• The lack of clear thresholds for the Physical Work Test introduces uncertainty for developers and financiers, requiring them to define acceptable standards for eligibility.
• The Safe Harbor Test was removed due to concerns over equipment stockpiling without designated project sites, but the explicit cost threshold it established removed ambiguity in determining which projects were eligible for the credits.
• The Treasury’s fast-tracking of these updates in response to an Executive Order from  President Trump leaves little hope that clarification will be provided prior to the 2026 deadline for wind and solar.

Duking it Out in the Carolinas

After watching rivals like Exelon successfully absorb Pepco Holdings and PPL Corporation expand by acquiring Narragansett Electric over the last handful of years, Duke is making another play to fully consolidate its two Carolina utilities—Duke Energy Carolinas (DEC) and Duke Energy Progress (DEP). Armed with promises of over $1 billion in savings and a compelling narrative about grid modernization needs in the data center era, Duke argues that regulatory barriers have kept a logical merger on ice for over a decade may be ready to thaw. Let's take a closer look.

• Duke Energy's August 14th filing to fully merge its two Carolinas utilities is more than just corporate housekeeping—it's a strategic bet that regulators are ready to embrace utility consolidation as a solution to mounting grid challenges. Despite owning both Duke Energy Carolinas and Duke Energy Progress since the 2012 Progress Energy acquisition by Duke, regulatory barriers have forced the two to continue operating as separate entities, creating what Duke argues are costly inefficiencies in an era when every dollar counts.
• With promises of over $1 billion in savings for retail customers through 2038, Duke is essentially asking FERC and state regulators in North and South Carolina to trust that bigger truly means better for ratepayers. Duke cites asset optimization, streamlined operations and regulatory efficiencies as the main factors that will generate savings. The proposal arrives at a pivotal moment when utilities nationwide are grappling with unprecedented infrastructure investments, raising the stakes for whether consolidation will be seen as a necessary evolution or a dangerous concentration of market power.
• DEC territory falls primarily in the west Carolinas and DEP the east. Not unlike much of the United States, the Carolinas are anticipating significant load growth in the coming years due to increased electrification and datacenter growth. As we covered in our previous newsletter, Growing Pains - AI Power Consumption, the infrastructure upgrades required to meet the inevitable increase in demand will be expensive, and utility companies like Duke are planning for that reality.

Source: Duke Energy

• Major utility consolidations like Exelon's 2016 acquisition of Pepco Holdings—creating a Mid-Atlantic powerhouse—and PPL Corporation's earlier expansion into Rhode Island through its purchase of Narragansett Electric demonstrate how the industry is reshaping itself to tackle mounting infrastructure costs and operational complexities. Recent operational management agreements, such as Public Service Enterprise Group’s (PSEG) takeover of Long Island's electric system in 2014, reflected the New Jersey utility’s drive to expand its footprint by targeting a rate base that was ready to buy power from any utility not called Long Island Power Authority (LIPA) after the mass outages experienced during Hurricane Sandy in 2012.
• Duke isn’t the only utility pursuing a merger this month. Black Hills Energy and Northwestern Energy have agreed to merge at the end of 2026, pending approval from FERC and state regulators. The proposed merger would create a single utility company headquartered in South Dakota and operating across eight states. Similar to Duke, the merging companies in the Northwest touted increased scale as being a necessity to prepare for datacenter growth, which has a national point of concern with the EIA now projecting this month 2.3% generation growth this year and 3% in 2026 (see EIA growth rates). While the impact to ratepayers is less explicit, leadership believes the merger will allow them to negotiate more competitively with prospective hyperscalers.

Source: EIA

• The challenge for FERC lies in distinguishing legitimate grid modernization needs from corporate empire-building, ensuring that utility consolidation doesn't tip the scales toward monopolistic control that could ultimately harm ratepayers despite promised savings. Regulators will have to determine the extent to which increased scale is necessary while preserving the competitive dynamics that keep rates fair and service quality high.

Mid-Atlantic States Turn up the Heat on PJM 

• The fallout from PJM’s most recent capacity auction for delivery year 2026-27, which cleared at a price 22% higher than last year’s already record-high results, is coming to a head as market participants and political representatives are calling for further transparency and leadership changes in PJM.
• In mid-July, Governors from nine PJM states banded together and submitted a letter to the PJM board proposing that two vacant board seats be filled; offering a slate of candidates nominated by the governors themselves.
• This comes on the heels of President and CEO of PJM, Manu Asthana, who recently announced his planned departure from the role at the end of 2025.
• In response to last year’s auction results, some states have taken even more drastic measures. In New Jersey, for instance, the general assembly passed a bill in June with a 60-18 majority, directing the NJ PUC to consider leaving PJM altogether; and instead join New York’s grid, or establish a single-state ISO.
• While it is unlikely that New Jersey or other states that have expressed interest in leaving PJM such as Pennsylvania or Maryland will do so, these political actions do point to the growing discomfort and frustration of PJM states amid shocking capacity auction results year-over-year.
• Since last year’s auction, we’ve covered various actions by the grid operator that attempted to remedy market shortfalls in the most recent auction from July 2025. Namely the operator set a temporary price cap and floor and reintroduced key reliability must run (RMR) plants to the auction’s available generating capacity.
• Moving forward, PJM is taking additional steps to reform its market structure. Recently they established a task force to develop a proposal for a biannual rather than annual auction, to better reflect seasonal risks and needs. This follows a broad sweeping trend of other ISO operators moving toward seasonal auctions, such as ISO-NE.
• PJM is also working toward clearing the backlog of projects currently stuck in the interconnection queue to get ahead of forecasted peak load growth, projected to increase 32 GW between 2024-2030. The newly-established Reliability Resource Initiative (RRI) is set to process 11,000 MW of new load within the next 18 months.
• Overall, the grid operator is managing wholesale markets and electric transmission across the largest ISO territory in the US (13 states) during a time of unprecedented load growth and overall push toward intermittent generation sources. These fundamental constraints in supply and demand have presented within recent capacity auction results in PJM, but are also fundamental issues experienced in other ISO regions.

Market Data

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