Energy Markets Update
In this newsletter, we cover the factors you need to know impacting US energy markets as well as the barriers impacting the United State's climate goals, the next steps following PJM's capacity auction, resistance to data center growth and a PG&E rate hike approval.
Table of Contents
Weekly Natural Gas Inventories
Source: EIA
Source: EIA
US Energy Market Update
A summary of recent news in wholesale power and gas markets.
- In a widely anticipated move yesterday afternoon, the US Fed cut interest rates by half a percentage point, a sign that the Fed has reached an inflection point in its roughly three year campaign to stymie inflation. Inflation peaked at 9.1% in mid 2022 and the 12-month rolling average is now 2.5%.
- The route in natural gas spot markets continues all throughout North America with prices in the West dipping to just above $1/MMbtu in August, the lowest in the Nation. The West has been bolstered by two years of above average snowpack, overperforming hydroelectric resources, and a strong gas storage position.
Source: S&P
- In the Nymex futures market, there remains a $0.70/MMBtu spread between prompt (@ $2.30/MMBtu) and the upcoming winter package (@ $3.02/MMbtu). This is just barely giving producers financial motivation to stay the course. Further collapse in the curve would likely reveal additional supply cuts, invariably postponing a more severe tightening in the market later in 2025.
- Our general buy-side posture is to take advantage of deals particularly in late 2025 and 2026, allow some room in the portfolio for near term prices to crater, but don’t get too comfortable with the prospect of a mild winter just yet. We see the most significant opportunity remaining in the regional basis and power markets where premiums remain high in many markets.
- On September 6, Massachusetts and Rhode Island announced the selection of three offshore wind projects with a cumulative capacity of 2678 MW, the largest procurement ever of this kind in the US. Absent from the initial announcement was the state of Connecticut, the third party in the tri-state partnership. Although additional announcements may be forthcoming, some have speculated that CT may have balked at the presumed higher price tag of these projects. No price details on these projects have been announced thus far.
- Prices for 2024 Green-E Renewable Energy Credits have declined by more than 50% this year, providing an opportunity for customers to make late year purchases to offset their scope 2 emissions.
Clean Energy Headwinds Sink Climate Goals
As the United States grapples with the global urgency to cut carbon emissions and transition to a clean energy future, the scale of what’s required is becoming more clear, and more elusive. America’s renewable energy transition is falling behind due to high costs, bureaucratic red tape, and reliance on expensive, unproven technologies.
- A good example of America’s current uphill battle is New England, a region notable for it progressive energy policies. A recent report from ISO New England estimates that the region will need to add 97 gigawatts of new wind, solar, and battery capacity by 2050 to meet its decarbonization goals. Yet by 2045, these resources are projected to meet just 10 GW of the region’s peak winter demand, leaving a significant gap in capacity and reliability.
- The cost of building out renewable infrastructure is daunting. According to ISO New England’s Transmission Study, the region alone will require $16 to $26 billion in transmission investments to support the renewable build-out. Similar challenges exist across the nation, indicating that the path to decarbonization is not only technologically complex but financially difficult.
Source: ISO New England
- Wind and solar have experienced exponential growth rates but their native intermittency, in addition to resource and integration constraints, have yet to give way to an orderly pathway to large-scale adoption. Renewable energy alone won’t be enough. Interest in backup technologies like synthetic natural gas and small modular reactors may be consequential distractions – both face technological hurdles and appear prohibitively expensive.
- Even if the funding is available, getting projects built in the U.S. has been notoriously slow. The National Environmental Policy Act (NEPA) review process, while essential for ensuring environmental protection, often results in years of delays for major infrastructure projects. A recent study found that these reviews can add an average of four years to project timelines. The bipartisan Energy Permitting Reform Act (EPRA) of 2024 offers a potential solution to this bottleneck. The bill, introduced by Senators Joe Manchin and John Barrasso, aims to streamline permitting for energy infrastructure projects, reducing unnecessary delays. While not perfect, EPRA represents a step toward breaking through the bureaucratic red tape that holds back clean energy development. The bill wouldn’t be the first of its kind wither on the vine. Critics argue that it gives too much leeway to fossil fuel interests, highlighting the challenge policymakers have in balancing efficiency and environmental responsibility.
- Groupthink by state policymakers has added to the financial pain. Perhaps setting all GHG reduction targets on the same 2030 timeline was a bad idea and had some predictable complications? The NY “peaker rule” and the NJ “permissible emissions rate rule” have proved ineffective and costly. The NJ rule was explicitly designed to shut down power plants with emissions rates above a specific threshold, whether they run for 1 day or 365 days per year. Scrapping capacity resources that don’t materially contribute to emissions, because they run so infrequently, is wasteful economically, environmentally, and administratively.
- Finally, consumers are feeling the strain of the clean energy transition. A survey by EY found that while 65% of U.S. consumers value sustainability when choosing an energy provider, only 45% are willing to pay any more for renewable energy. As for the other 55%, what is their threshold for rate increases? Is it 20%, 50%, 100%....(ratepayers in California, where bills are entrenched above $400/MWh, may soon be able to offer some guidance here.) As the cost of living rises, the gap between consumers' green ambitions and financial reality is widening. Utilities are struggling to meet sustainability goals while keeping costs low. As companies invest in renewable energy, build new infrastructure, and tackle emissions reduction targets, these costs invariably get passed onto consumers.
Source: S&P
- America’s clean energy transition is being held back by a combination of high costs, ineffective regulation, and bureaucratic delays. To avoid further setbacks, the country needs a focused approach that prioritizes proven clean energy solutions, support for utility scale projects, streamlined permitting processes, and renewed efforts on stabilizing the costs of the existing infrastructure to prevent market volatility and ratepayer frustrations.
PJM's Capacity Auction – What Now?
The price of capacity in PJM surged by over 900% in its latest auction. The grid operator, which manages power in 13 Mid-Atlantic and Midwest states, is facing backlash from all sides.
- Several factors have contributed to PJM’s current crisis.
- First, the retirement of numerous thermal baseload power plants has left a significant gap in generation capacity. These retirements, driven by both regulatory changes and market forces, have not been adequately replaced by new generation projects. Also, many of them were announced just months before the auction, blindsiding stakeholders.
- Administrative delays in holding PJM’s capacity auctions have disrupted the typical timeline for securing capacity three years in advance. The July auction covers June 2025 to May 2026 and a December 2024 auction will procure resources for June 2026 to May 2027. Simply put, 11 months is not long enough to build a utility scale generation asset.
- Additionally, flaws in the capacity market rules, such as the exclusion of reliability must-run (RMR) resources from auctions, have added billions of dollars in unnecessary costs. According to ratepayer advocates, the failure to include RMR resources in the last auction alone contributed an additional $5 billion to the total cost.
- Stakeholders across the energy industry have responded to PJM’s record-high capacity prices in different ways. Investor-owned utilities (IOUs) in deregulated states like Illinois, New Jersey, and Pennsylvania have advocated for the opportunity to reenter the power generation business, arguing that their participation could help meet PJM’s capacity needs. Executives from companies such as Exelon and FirstEnergy have publicly stated that utilities should be allowed to build new generation to address the supply shortfalls and mitigate unnecessary volatility. However, state utility regulators have been hesitant to shift the long term financial risk of new generation onto ratepayers, making it difficult for utilities to regain a foothold in the generation market. Meanwhile, state lawmakers are exploring legislative solutions to help bring new power supplies online more quickly. In Maryland, for example, legislators are considering bills that would promote energy storage systems and streamline the interconnection of solar energy projects to meet demand faster. Others are pushing PJM to reverse its policy of excluding RMR plants from the auction parameters. They are right to do so.
- There are a few things PJM and its stakeholders can do.
- One step could be to delay planned retirements of power plants and potentially reactivate generation facilities to provide a short-term boost to capacity. In fact, some plants that earlier this year submitted deactivation notices, are already reversing course in lieu of higher prices. As problematic as this sounds, and the gaming concerns need to be addressed, this should be encouraged for the next auction.
- State lawmakers can take legislative action to streamline the approval process for new power generation projects and promote distributed energy resources, such as solar power and energy storage, as a bridge to meeting long-term supply needs.
- Expanding demand response (DR) programs would also help manage peak demand more effectively, reducing the strain on the grid. This remains the most significant way for users to mitigate cost increases next year, and it pays. Additionally, better use of Peak Load Contribution (PLC) notifications can improve demand management by signaling when peak periods are expected, allowing utilities to plan accordingly. Contact your commodity advisor at commodity @veolia.com to learn about the compensation rates for participation in active or passive demand response.
- PJM faces many challenges and there may be more pain to come. By reactivating generation, expanding demand response programs, and reforming market rules, PJM and its stakeholders can have a significant impact on both near term and long term procurements. At over $14billion per year, the stakes are high, and ratepayer patience is not infinite. Contact your energy account representative for assistance and more information on energy procurement in the PJM region.
Mounting Resistance to Data Center Growth
Energy demand from datacenters is projected to increase by 160% in the next five years as the AI frenzy shows no signs of waning. This explosive growth raises two critical questions for the nation’s power grid: can it keep up with industry demand, and who will foot the bill for necessary upgrades?
- For years, data centers displayed a stable appetite for power. However, AI – which consumes approximately 10x more electricity per query than a Google Search and 8x more than non-AI datacenters, is having a meaningful impact on grid planning.
- The U.S. power grid – already strained by overcrowded interconnection queues, aging infrastructure, and grid congestion – may struggle to withstand the combined pressures of the AI revolution and an accelerating green energy transition. As a result, utilities, large tech companies, regulatory agencies, and others are clashing against the backdrop of an ill-equipped grid.
Source: Goldman Sachs
- Despite multi-billion dollar investments by the federal government, utilities still need to invest $50 Billion in new generation capacity and add 5–15 GW of capacity specifically to meet the needs of datacenters in coming years, according to Goldman Sachs.
- Grid congestion – which occurs when there is insufficient transmission to accommodate the flow of lowest-cost electricity and/or insufficient generation where it is needed – has become a pressing concern as utilities are increasingly being forced to obtain electricity from pricier sources to meet demand.
- The costs associated with congestion more than doubled between 2021 and 2022 (a price increase of about $20.8 Billion).
- Ultimately, congestion and other capacity-related cost increases are passed onto consumers. The latest capacity auction in PJM (previously reported on here) paints a solemn forecast for the kinds of cost increases we can expect going forward.
- Some areas of the grid are feeling the pressure of rising demand more than others as a few states with competitive energy prices, strong connectivity, and abundant land have emerged as “hotspots” for datacenter growth.
- In PJMs recent capacity auction, while all customers face massive increases, customers in northern Virginia, a hotspot in the AI buildout, saw prices that were 15X higher year-over-year.
- Central Ohio, another hotspot, has recently experienced mounting tension between utilities – who are tasked with providing reliable, affordable power to consumers – and large tech companies, whose operations are requiring these rapid upgrades to grid adequacy and infrastructure.
- This came on the heels of American Electric Power Ohio (AEP) proposing a tariff in May that would increase upfront costs for datacenter operators in the area. The utility, which expects to raise its load profile by 40% across all service territories in the next six years, proposed a tariff that would require datacenters to pay a demand charge based on 90% of their contract capacity (up from 60%). The proposal aims to serve datacenters’ needs while minimizing the additional costs of new infrastructure for residential and business customers.
Source: Ohio American Power
- While the jury is still out on AEP’s proposed tariff, if approved, it will set an important precedent for how grid operators and data center developers will collaborate in other “hotspots” such as Northern Virginia and Maricopa County, Arizona, while minimizing the cost burden to consumers.
- Colocation present another challenge and opportunity. By colocating datacenters with existing nuclear power plants, a scenario that FERC is reviewing at the moment, it may be possible mitigate, to a small extent, the capacity and transmission needed to serve data centers. However, this is only true if data centers pay the prevailing rate for transmission service, not bypass the transmission system altogether and shed higher marginal costs onto other ratepayers. If done right, it is possible to locate data centers adjacent to nuclear power stations where density of supply and demand have natural synergy, but if done wrong, this simply increases costs to other ratepayers.
PG&E Rate Hike Approved
California regulators approved another PG&E rate hike, the fourth this year, to recover wildfire mitigation costs, despite opposition and concerns about its impact on customers.
- Last week, the California Public Utilities Commission approved a rate hike that they acknowledged “may negatively impact ratepayers”...
- The increase, described as “interim”, sets a plan to recover nearly $1 billion over 17 months. This figure represents only about half of the money the utility initially sought to recover in its case. And this rate increase is in addition to the general rate increase from 2023 of nearly 11 percent.
- The main driver behind the rate increase? Lack of timely recovery of costs related to wildfire mitigation. The utility insists that the costs recovered from this rate hike will save ratepayers $67 million in avoided interest costs and improve risk and credit perceptions of PG&E. But given this is the fourth PG&E rate hike of this year, customers are skeptical.
- The intangible benefits of PG&E’s creditworthiness may appear one-sided when the new rates take effect on customer bills. Customers can expect to see their monthly bills rise an average of 2.3% over 17 months compared to the rates effective at the beginning of this year. Changes in bill impacts vary based on client consumption and tariff, as well.
- SincePG&E’s bankruptcy in 2020, rates have increased by 54%. Activist groups, such as The Utility Reform Network, and politicians, including Governor Gavin Newsom, are advocating for lower rate increases, but to no avail.
- We continue to monitor PG&E rates for our California customers and report on any possibility of material changes to their bills.
Market Data
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