California Screamin’

Energy Markets Update

In this newsletter, we cover the factors you need to know impacting US energy markets as well FERC's newest transmission planning order, the NYC capacity market, and a rate restructure and new power market in California.

Weekly Natural Gas Inventories

Source: EIA

US Energy Market Update

A summary of recent changes and important information about the US energy markets.

The prompt month gas contract continues to find support through the month of May, rallying from $1.64 per MMBtu on April 25 to roughly $2.50 today. While this move was anticipated – sub $2 gas cannot persist indefinitely, afterall – the path that spot gas will take over the coming months, given the 2025 average futures price of $3.45, is still very much up in the air. The market for gas in 2025 really hasn’t changed much since the beginning of the year, though it is showing increasing volatility this month.
- Gas demand is expected to set new records as we move into the summer, so prices will invariably tighten. This is largely priced in already.
- The market will be more prone to erratic swings. The market is far more prone now to bullish movements.
- We see value in at least taking some risk off the board by hedging into 2025 as rates are still quite reasonable compared to historical standards.
Preliminary summer forecasts indicate slightly warmer than average temperatures. We don’t take much stock in early forecasts, however it is notable that there is an increasing likelihood of a flip from el Nino to la Nina by late summer, which typically has a larger influence on winter fundamentals.
A barrage of recent long-term load forecasts from grid operators reflect bullish expectations about growth in the computing industry (i.e., AI) and electrification (i.e, heat pumps). The frenzy around AI power demand is real.
- Datacenter demand is expected to triple from 130 GW now to almost 400 GW by 2030, changing its share of total net load from 2.5 to 7.5% of all electricity consumption in the US.
- In January Mid-Atlantic grid operator PJM released its new long-term load forecast predicting net energy load growth of 2.4% per year over the next 10 years. This comes after relative load stagnation in that region since 2012.
- Last week ISO New England updated its long term forecast, anticipating 17% load growth over the next 10 years. This follows roughly 20 years of stagnation and at times, modest load reduction. New England does not anticipate the same level of data center growth–its power costs are too high–but electrification and EVs will be the primary driver.
Attorneys General representing half of all US States have sued the EPA after its April 25 carbon emissions ruling requiring all existing coal-fired power plants expected to operate past 2039, and any new gas-fired plants, to capture 90% of their CO2 emissions. The rule effectively requires plants to install carbon capture technology that is not commercially available. The backlash should not come as a surprise.

FERC Order 1920 Addresses Long Term Transmission Planning

A new FERC order marks the first effort towards streamlining long-term regional transmission planning.

In a long-awaited rulemaking on May 13th, FERC issued Order 1920, which will require regional transmission providers to incorporate a series of changes into the long-term planning, including the identification of transmission needs at least once every five years and the evaluation of benefits of any proposed solutions over a 20-year horizon.
Commissioner Allison Clements highlighted the order’s goal stating that the "status quo, last-minute, and piecemeal approach is an expensive proposition,” and “in the long run [this rule] will result in a far more affordable grid."
The ruling comes following a transmission report stating that the power grid may need to expand by 144% by 2040 in order to meet rising demand, at the expense of trillions of dollars. FERC Order 1920 is considered to be the first direct effort toward long-term regional transmission planning and outlines a clearer process for transmission providers to follow.

Source: S&P

The rule is open regional transmission builds to competitive bidding pressures, rather than granting monopoly rights to incumbent utilities. This was an important factor in keeping costs down.
The rule is also structured to incorporate a series of reliability benefit tests that will make it easier to allocate costs across a wider region of customers receiving benefits.
Additionally, the rule requires regional transmission providers to engage with state regulators for a six-month period, unless an agreement is reached earlier, to negotiate an appropriate cost allocation methodology. FERC hopes this forced collaboration will give transmission providers and state regulators the ability to better fund transmission plans with fewer costly delays.

Capacity Rates Surge in New York City

NYC's capacity rates have surged in the past year due to supply constraints amidst rising demand and greenhouse gas reduction commitments.

NYISO oversees the state’s capacity market, compensating generators for ensuring grid reliability through bi-annual auctions. These are fixed price payments that all ratepayers make to generators apart from volumetric energy payments. Over the past 12 months, downstate NY capacity rates have increased 3.6X, the most dramatic rise in a decade. Drivers of the rally include changes to the generation mix, such as closure of the 2,000 MW Indian Point nuclear plant in 2021, which transitioned to almost entirely natural gas-generated power, as well as legislative mandates like the Climate Leadership and Community Protection Act (CLCPA) and the Peaker Plant rule.
As the second-largest supply-side cost component for customers in Zone J (NYC), capacity is a real focus point for consumers who ultimately pay these costs.

Source: Veolia

Downstate NY ratepayers face challenges hedging power beyond 2025 due to the state's CLCPA mandate of 70% renewable electricity by 2030 and the Peaker Rule requiring strict emissions controls on fossil-fueled plants by 2023/2025. The ladder has resulted in nearly 40 plants announcing plans for retirement as they cannot or will not comply with the regulations.
Last fall, NYISO identified a 446 MW reliability margin deficit in New York City by summer 2025 due to rising demand and new emission limits on peaker plants. As a temporary solution to address the shortfall, NYISO allowed four NYC plants owned by Astoria Generating Company to continue operating for just two additional years. These plants are quite literally bage-mounted combustion turbines floating in New York Harbor off Brooklyn. In the chart below you will see the leftmost pink arrow corresponds to the extension announcement for those four plants providing some relief for 2025.

NYC (NYISO, Zone J) ATC Calendar Strip Pricing

Source: S&P

One promising development in the works is the 1,250 MW Champlain Hudson Power Express transmission line and other newly established Tier 4 generation projects that are anticipated in the next few years. These interconnections are likely to trigger some capacity price relief. Champlain Hudson Power Express is expected to begin operations in the Spring of 2026. If there are delays, we expect to see high prices persist unless there are major legislative changes to the Peaker Rule in New York.
The many uncertainties regarding how downstate NY will meet its energy requirements for the second half of the decade will linger for some time. We encourage buyers of power in Zone J to continue to work with our group to monitor ‘25 - ’30 wholesale prices, which will be influenced by both regional factors, as well as broader market fundamentals in the US.

California Restructures Rates Amidst Soaring Bills

In effort to combat California's rapid rise of electric retail rates, regulators have restructured electric charges to have a fixed charge and reduced hourly consumption rates.

The California Public Utilities Commission (CPUC) recently approved a controversial rule that will restructure electric rates for residential customers within the state’s three investor-owned utilities, which serve about 70% of the state. The CPUC stated that the changes aim to reduce electric bills for customers and further support the state's electrification efforts. It is doubtful that they will do either in any meaningful way.
The restructuring includes a new fixed monthly charge, $24.15 a month for most residential customers, and $6 to $12 a month for low-income customers. Additionally, the restructuring will reduce hourly consumption rates by roughly 20 percent, with prices of approximately between 5 cents/kWh and 7 cents/kW. The rate restructuring will be implemented by Q1 2026.

Source: CAL Matters

The controversial ruling comes at a time of high and continuously rising electric prices for California, which averaged 31.2 cents per kilowatt-hour in February of 2024, the second-highest state in the US behind Hawaii.
In fact, over the past decade, retail electricity prices have roughly doubled, especially in urban locations as shown below.

Source: Public Advocates Office at the CA Public Utilities Commission

Source: S&P

California retail energy prices have faced steep increases due to geography-driven grid costs, wildfire prevention and compensation, and renewable portfolio standards. About 66% to 77% of the state’s electric bills are believed to fund “fixed” portions of transmission providers’ costs, including maintenance, generation, transmission, and distribution costs, as well as wildfire mitigation.
Wildfire mitigation specifically was estimated to cost 10% of bills for nondiscounted customers of Southern California Edison and at 8.7% for customers of San Diego Gas & Electric, following a May 2023 CPUC report. Wildfire costs are only expected to increase as the three major utilities plan to spend $9.2 billion per year by 2025, up from $6.2 billion in 2020.
While the CPUC’s rate restructuring may lower costs for customers who electrify their homes and appliances, the state’s larger struggle to overall reduce electric costs remains unresolved. In other words, this is purely a cost shift that does little if anything to address the underlying problem.

California Plans for Expansion of Energy Market

California has formalized plans for a new "Extended Day-Ahead Market" allowing CAISO to use neighboring regions' resources to optimally balance its power market.

In December 2023, the Federal Energy Regulatory Commission (FERC) approved most aspects of a proposal from the California ISO (CAISO) to create an “Extended Day-Ahead Market” (EDAM). The point of the EDAM is to create an expanded footprint from which market participants, CAISO included, may access transmission and generation resources from neighboring regions to optimally balance the market.
This marks one of the most significant movements towards western market regionalization in a decade.
The EDAM is open to current participants of the CAISO Western Energy Imbalance Market (WEIM), with Pacific Gas and Electric Co, the Los Angeles Department of Water and Power, and the Balancing Authority of Northern California already signaling intent to participate. PacifiCorp has formally announced they will participate.
The EDAM will function similarly to the WEIM in that excess transmission capacity from members will be required to be made available to other market participants. WEIM reports member benefits of over $5B since its inception in Nov 2014. Conceptually there should be benefits to be had by leveraging a larger footprint from which to optimize dispatch.
The CAISO plans to onboard EDAM participants in the autumn of 2025, with a May 1, 2026, go-live date.

Market Data

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