Growing Pains - AI Power Consumption

Energy Markets Update

Editor’s Note & Introduction to IceTec: Thank you all for joining us after a few weeks hiatus! In this newsletter we'll cover major news in energy markets, including PJM’s recent eyewatering capacity market auction, offer key takeaways from major legislative developments, notably the BBB and the recently released federal AI action plan, as well as ongoing rate cases.

Veolia Acquires IceTec Energy Services!

We also want to update our readers on an exciting recent acquisition made by our business unit. Earlier this month, Veolia added IceTec Energy Services to our family. IceTec is a leading technology firm and energy market integrator that is focused on the optimization of dispatchable energy resources in North American energy markets. IceTec will help Veolia improve the efficiency of its own portfolio of managed assets, but it will also help our clients do the same by monetizing behind the meter generation, battery storage assets, and even optimizing complicated central plant dispatch for different goals such as cost, efficiency, or carbon. Please reach out to commodity@veolia.com if you would like an introduction to the IceTec platform!

Weekly Natural Gas Inventories

Source: EIA

Market Update

Natural gas prices logged their first major retreat since April as strong production data outweighed short term concerns over a pending short squeeze.
Dry gas production, now approaching 107 Bcf/d, is up about 4 Bcf/d since last year. While increased LNG exports have gobbled up most of the year-over-year excess, consumer demand has been relatively flat and more gas is being injected into storage than previously anticipated. With national inventories now >5% above the 5 year average and end of season projections topping 3.8 Tcf, there is now an increased expectation of surplus going into the winter rather than deficit.
This also creates an opportunity for fixed price buyers, particularly those who had been waiting for a bargain on a 2026 contract that previously seemed a bit out of reach. The 2026 NYMEX calendar strip is down almost 9% over the past two weeks, now < $4.00 /MMbtu. Calendar years 2027 and 2028 are down about 5%.
Another 4 Bcf/d of LNG export capacity is expected to hit the market next year; the focus of most fundamental analysts over the next 6-12 months will be on the rate at which producers deploy new rigs to meet this demand.
A trade deal between the US and EU announced earlier this week would set a 15% import tax on many EU goods reaching the US, and it also includes a commitment by the EU to purchase $750b a year in US energy. While stocks of US LNG exports increased on the news, it had most analysts doubting how the US, which now only exports a total of $165b per year, could possibly build the infrastructure to enable these vastly expanded targets in any meaningful timeframe.
Last week PJM finalized its most recent capacity auction covering the period June 2026 - May 2027, and signaling more pain ahead for PJM customers. Coverage below will detail auction values and anticipated rate impacts.
Earlier this week, the EPA moved to eliminate the 2009 Endangerment Finding which grounds federal regulations on emissions in the Clean Air Act, claiming the potential savings of its repeal ($54 billion) outweigh the costs of increased environmental impact through fossil fuel use. The move would serve to remove or limit power plant emission standards, thereby recentering incentives around fossil fuels as the source to meet growing demand from data centers, a growing population, and electrification.
Private equity firms have shifted heavily towards the natural gas market as they dump funding into gas-fired power plants, investing $49b through 6/2025 (compared to $4.34b in all of last year).

PJM Capacity Auction Clears at Record-High (… again)

Last week, PJM hosted its annual Base Residual Auction (BRA) for the capacity period June 2026 - May 2027. The auction, which aims to secure sufficient electricity generation capacity to meet future electricity demand, secured 134,311 MW of unforced capacity generation (UCAP) at an RTO-wide clearing price of $329.17/MW-day. This represents the highest clearing price in the 20-year history of the BRA and a 22% increase over last year’s already record-high $269.92/MW-day.

Until last year, capacity was a stable and oversupplied cost component of the energy supply cost stack in PJM, often making up <5% of customers’ total electric bill. Last year’s auction exposed a significant mismatch between supply/demand – which we’ve covered in detail in previous newsletters – resulting in blowout capacity clearing prices up 833% year-over-year and growing the capacity component to >25% of customers’ total electric costs.

Source: PJM 2026-2027 BRA Report

Last year’s auction result was mired in controversy and ultimately led PJM to push back the 2026/27 auction by six months to introduce market reforms and address shortfalls in the existing auction structure.
Most notably, FERC approved a price floor and ceiling for the subsequent two auctions for 2026/27 and 2027/28, and the inclusion of Reliability Must-Run (RMR) power plants (plants scheduled for retirement that are kept running due to grid reliability needs) which were excluded from the previous auction. Many analysts agree that the exclusion of Wagner (843 MW) and Brandon Shores (1289 MW) contributed to major capacity shortages that ultimately were reflected in the July 2024 auction results.
While clearing prices were subsequently capped at $329.17/MW-day per recent market reforms, absent the collar PJM estimates that prices would have cleared 15% higher at $388.57/MW-day.
Since June marked the start of the 2025/26 capacity year, C&I customers are just now receiving their first invoices reflecting the higher capacity cost increases ranging from $0.021/kWh to $0.035/kWh. PJM anticipates that the rate impact starting in June 2026 will add another 1.5-5%.
While near-term capacity costs remain challenging, PJM is undergoing significant measures to address supply/demand imbalances in the longer-term:
- Investment in new generation: The 2026/27 auction introduced 2,669 MW (UCAP) of new generation and uprates, reversing the downward trend in new generation observed over the last three auctions. While the brief one-year lead time limited brand-new project development, PJM’s Reliability Resource Initiative has so far attracted more than 9,300 MW (ICAP) in planned new projects and uprates to existing generators. All projects are projected to come online by 2031.
- Delayed plant retirements: Following the 2025/26 BRA, 17 generating units (approximately 1,100 MW) have withdrawn their planned retirements, expanding the pool of available generating capacity.
- Interconnection reforms: PJM is working to streamline the interconnection process and clear the infamously backlogged queue, with 72,000 MW expected to clear the queue by mid-2025 and an additional 100,000 MW by the end of 2026.

Source: PJM 2026-2027 BRA Report

Despite these improvements on the horizon, we expect many of the price pressures in the capacity market to endure in the near-term, namely the next three+ years. The fact remains that PJM is now supply constrained, consistent load growth is anticipated, and backlogs major equipment implying that we could be a few years away or more from adding any meaningful generation capacity. We strongly encourage customers to stay out in front of this market to manage rate impacts over this period.
For example, customers may opt for retail contract structures that minimize the impact of capacity costs (“pass-through” or “trued-up” capacity products) to avoid excessive premiums baked into fixed offers by suppliers. Or, individual sites may prioritize demand response efforts to lower capacity tags, thereby lowering future costs.
IceTec Energy Services specializes in demand response and capacity cost mitigation efforts for customers in PJM and across the U.S. For more information on these services or guidance on how to manage capacity obligations more broadly, please contact our team commodity@veolia.com.

Could the AI Boom Mean Doom for the Power Grid?

Last week, the White House released its AI Action Plan, making it clear that winning the global AI race is a priority of the Federal Government. The plan highlighted the necessity to build AI datacenters in tandem with the energy infrastructure to power them. Grid operators and utility companies have already been preparing for datacenter growth, but the message from the White House signals support for fossil fuel infrastructure and streamlining buildouts to meet pending growth. The realities of both process constraints, and physical constraints in labor and material will undoubtedly create headwinds.

Datacenter demand is forecasted to nearly triple from 2024 to 2030, reaching almost 600 TWh or roughly 14% of all US electrical consumption. AI data centers are expected to lead this growth with facilities exceeding > 100 MW demand now becoming the norm. The generation that will be needed to supply this growth will be expensive, especially given the competition of equipment and people in an already inflation-prone business.
Dominion Energy estimates that it will have to invest over $40 billion in Virginia over the next five years, which would double the current book value of the entire system. Utility companies are struggling to come to terms with who will be footing the bill. Under the traditional utility model, utilities typically take on the risk of building out their infrastructure to meet future load projections. The rapid expansion of datacenter customers, the density of the power requirements, and the potential uncertainty of this load with respect to timing and credit, raise some profound concerns amongst utility executives.
Utilities are increasingly suggesting that the tech companies pay more upfront to connect their datacenters to the grid. Earlier this month, Ohio became one of the first states to make it a requirement. These attempts have encountered resistance from “hyperscalers” which include Amazon, Microsoft, Meta, and Google. Although they’re willing to pay the cost for power, they posit that they shouldn’t be responsible for bankrolling the grid investments required to support infrastructure upstream of the interconnection.
Another solution being actively implemented is onsite power. The standard approach being used is gas generation, if firm capacity is available, but other deployments include some solar and large batteries to relieve both physical and financial congestion issues. Thus far, datacenters have been somewhat reluctant to pursue load curtailment, preferring to pay massive premiums to ensure uptime. This could be forced on them as growth in the sector increasingly puts physical constraints on the grid.
Texas recently passed legislation requiring datacenters to disconnect from the grid during peak demand hours. The law would apply to any loads of 75 MW or more that interconnect to ERCOT starting in 2026 and mandates that shutoff equipment be installed prior to interconnection. This will allow utilities to disconnect loads during emergencies. The legislation also sets forth a voluntary demand response procurement program and gives participants a 24-hour notice period to reduce load or switch to backup generators when a peak event is likely.
The construction and infrastructure challenges are daunting. A May report from S&P signaled that OEM gas turbine manufacturers are quoting 5-7 years for delivery of prime movers, meaning that new projects being led by either datacenters or utilities alike could be waiting well past 2030 for power. Much of this was before tariff impacts, inflation, and the impacts of the BBB were understood. Power supply has become the primary bottleneck to AI growth. Given that hyperscalers have an edict to charge on at breakneck spread however, we can only assume that there will be fierce competition of existing power supplies through the end of the decade. This invariably means higher energy and capacity prices for most consumers.

Still Betting on Securing a PPA? You’ll Need to Bet on These Numbers:

7 - 4 - 20-26, 12 - 31 - 20-27

Last month we discussed how the One Big Beautiful Bill (herein referred to as “BBB”) reshaped the solar development process. But for buyers - the companies and institutions that have financed much of the renewable energy growth by inking Power Purchase Agreements (PPAs) - the more important question is: What do you do now?

The PPA Landscape Has Shifted, Fast

The BBB rolls back much of the tax incentives that were promulgated under Biden’s Inflation Reduction Act. This primarily impacts wind and solar project ability to secure the production tax credit (PTC) and investment tax credit (ITC) under Section 45Y and Section 48E of the Internal Revenue Code. Under the BBB. Solar and wind projects will become ineligible for clean electricity tax credits if placed in service after December 31, 2027, unless construction begins before July 4, 2026 (see charts below). The qualification of construction commencements is that 5% of project capital must be expended by July 2026, then projects would have four additional years to be put in service. This has changed the risk and responsibility balance between developers and buyers.
Here’s the new reality:
- Timelines are shorter. Analysts call it a “race forward” - developers must spend heavily on engineering, site control, and studies before they even know if a project will connect. Most analysts expect that the construction commencement deadline will be the primary target for developers, meaning that the projects should probably be committed (i.e., PPAs signed) and financed by the end of the year to ensure mobilization of construction work.
- Costs are likely going to be higher. The developed projects with interconnection agreements in hand and readied construction paths are likely well positioned to find eager buyers and may require premiums. Developers are locking in land, engineering, and queue deposits early, meaning they need buyers to commit sooner to help offset that capital.
- Certainty is harder to find. Interconnection has always been messy, but now the delays are compounded by BBB‑driven permitting demands and front‑loaded planning. A buyer signing a PPA today might not get clear answers on delivery dates or pricing structures for months, because so many inputs (interconnection, equipment sourcing, financing) are in flux. This adds to uncertainty around timing, price, and project availability. Invariably developers will seek to de-risk these components by leaving them undefined, and/or providing outs by which the developer can either adjust price or exit commitments.

Source: Veolia, Data from IRS

In short: The PPA buying process hasn’t stopped. In fact we could see a lot more activity over the next couple years as developers rush to get deals done before an anticipated slowdown. However, the starting line has been moved up, and the track is steeper.

What Buyers Should Know Today (That Wasn’t True 2 Months Ago)

You’ll see more “provisional” PPAs. Developers may bring partially baked projects to the table with site control in place and engineering started - but interconnection studies still pending. Two months ago, you might have seen more “shovel‑ready” PPAs; now, buyers are being asked to sign earlier, with more assumptions baked in.
Expect milestone‑based commitments. Instead of a single take‑it‑or‑leave‑it price, contracts now often have triggers: pricing can reset if a project slips a year, or buyers might need to cover certain pre‑construction costs if financing gaps open.
Financing scrutiny is higher. Tax equity investors and lenders are asking harder questions about timelines and contingency plans. The BBB introduces stringent FEOC restrictions, disallowing tax credits for projects with material assistance from entities tied to countries like China, Russia, Iran, and North Korea. That means buyers may see longer due‑diligence periods before a PPA can close as the tax equity partner will have more at stake.
Interconnection Risk. Interconnection uncertainty now bleeds into your contract. Buyers will increasingly see clauses about “anticipated delivery dates,” with wiggle room written in. Think of it as the “storm warning” section of a PPA - acknowledging delays that are beyond the developer’s control.

Source: Berkeley Lab

What This Means for Veolia Clients

For Veolia’s commercial and industrial clients, this changing PPA landscape matters for three reasons:
- Contracting early matters. If you wait for a “perfectly ready” PPA, you may be waiting years - and paying higher capacity costs in the meantime.
- Terms will be more complex. Expect milestone clauses, provisional pricing, and stronger legal language around risk-sharing.
- Active sourcing is critical. Buyers can no longer assume developers will carry all the early‑stage costs; PPAs are becoming a partnership from day one, not just a “sign and forget” contract.

Mid-Year Rate Case Updates: Large Impacts in CA, NY, MA

A July 2025 update to Powerlines “Utility Bills Are Rising” report concluded that US utilities approved or requested rate increases totaled $9 billion for Q2 2025 and brought 2025’s total rate increase requests up to $29 billion.
This outpaces the first half of 2024 when requested or approved rate increases totaled $12 billion an increase of 240%.
2025 Q2 rate increases are distributed throughout the contiguous US with the largest impact being felt in the West where $4.4 billion in rate increases have been requested, accounting for 48% of the quarter’s total rate hikes.

Source: Powerlines

40 million consumers are expected to be impacted by these rate hikes in 2025 Q2, with 25% of impacted customers located in the West and 50% located in the South. Overall, this amounts to a near doubling of utility customers facing raising rate costs compared to 2024 Q2.
Justification for rate increases vary by region but a unifying rationale across these proposals is the recoup of funding for distribution and transmission upgrades.
Residential gas and electric utility bills have increased at a rate which outpaces the average price increases seen for consumer goods and services (Consumer Price Index; excludes energy and food). Residential gas rates have increased by nearly 40% since 2019 and residential electricity rates have increased by nearly 30% since 2021.

Source: Powerlines

As reported in our New Year, New Rates edition, only 58% of proposed utility rate increases were approved from 2023 through August 2024, making the likelihood of realizing all $29 billion in rate increases slim.
Shown below are pending and approved utility rate cases which have been submitted over the last year.

Source: S&P

Within California, the lion share of proposed rate increases are expected to be finalized by the end of 2025 with $5.2 billion in proposed increases potentially impacting customers' 2026 gas and electric bills. The largest increase is being proposed by Southern California Edison for their electric service. The proposal is its General Rate Case (GRC) application for the next 4 years in comparison to its 2024 revenue. Contrary to its expected decision date of Feb 2025, the CA PUC only released a proposed decision on July 29th, reducing the request by $727 million.
2025 is also shaping up to be a decisive year for natural gas rates in the Commonwealth of Massachusetts with $200 million in proposed natural gas rate increases. This proposal is coming on the heels of a Fall 2024 25% gas rate increase by Eversource. The increases were attributed to higher natural gas prices along with recouping costs from energy efficiency programs.
In NY, Consolidated Edison proposed a $1.6 billion increase for electricity revenue which would amount to a 11.4% increase in their total revenue compared to their revenues previously approved for the 2026 rate year. If approved, Consolidated Edison residential gas customers could expect delivery bills to increase by 18% for commercial users and 19% for residential users.

Market Data

Market data disclaimer: Data provided in the "Market Data" section is for the newsletter recipient only, and should not be shared with outside parties.