It’s Summertime in the LDC

Energy Markets Update

In this newsletter, we cover the factors you need to know impacting US energy markets as well summertime power charges, new carbon credit guidelines, regional transmission plans, Massachusetts infrastructure and changes to account numbers, and utility earnings.

Weekly Natural Gas Inventories

Source: EIA

US Energy Market Update

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

US gas prices dipped after the holiday weekend with the spot retreating from $2.85 to under $2.55 per MMBtu over the past week.
Market fundamentals are still expected to grow tighter in the coming months as demand is outpacing supply, particularly in the generation sector which is putting cheap molecules to use. Due to moderate weather through the shoulder months however, the imbalance has not resulted in a material drawdown of gas inventories, which remain the strongest in years.
Temperature forecasts released from NOAA this week show a warm up across major coastal load centers over the next couple of weeks. Many analysts expect injections into gas inventories to slow in the middle of June–prospective buyers may wish to preempt this by securing hedges over the next couple of weeks.
In its annual Summer Energy Market and Electric Reliability Assessment, the Federal Energy Regulatory Authority (FERC) set its expectations that summer peak demand in the US would be up 2.7% this summer compared to last. The anticipated increase is attributed to warmer weather, economic growth and data center load growth.

Summertime Demand Charge Management

Reduced consumption for a few select hours (which Veolia predicts and provides for free) during high grid stress could result in significant energy savings.

It’s Summertime in the LDC (Local Distribution Company) and all people will agree that we, are well qualified to represent your PLC (Peak Load Contribution)... credit Sublime.
With Memorial Day Weekend already behind us, many large power consumers are beginning to prepare for the transition to the cooling season and all that it entails–tuning HVAC systems, checking setpoints, and reviewing energy curtailment plans. Electric costs during the summer are often escalated by higher peak demands and associated charges necessary to support air conditioning loads. Sometimes these monthly ratchet demand charges are hard to avoid given long utility peak periods, but there is also a less obvious yet equally important capacity charge component set during summer peak hours that is easier for building managers to address.
Capacity charges have varying names across regions, such as Capacity Tag ("Cap Tag") or Coincidental Peak ("CP") Contribution. They refer to the kilowatts (kWs) of demand on a building's meters during the annual peak or a series of peak hours on their respective grid. Unlike utility peak demand charges, these programs originate from the wholesale supply market – the “grid” – and they are designed to provide generation adequacy by allocation of costs based on each customer's contribution when the grid is most constrained (i.e., coincident peak demand periods).
The specific rules and makeup of these capacity charges vary between Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs), however they do share many similar traits related to peak demand measurement (see table below).

Source: Veolia

Note that some regions such as NE-ISO and NYISO establish a customer’s peak demand threshold based on a single hour in the summer. Others take a simple average of 4-5 hours on different days throughout the summer. The key point here is that it is much easier for facility managers to target load management response on just a few days during the summer vs 8+ hours every day that is more typical of utility-derived peak demand charges.
Lowering demand during these small number of peak events can lead to substantial cost savings. Capacity charges are a significant component of electricity costs. Even modest reduction of a building’s coincident peak demand can result in annual savings ranging from hundreds to thousands of dollars, depending on your location (see chart below).

Source: Veolia

Veolia can help your business implement a new strategy to manage capacity charges. If you haven't worked with us before, enroll in our free alerts email list, and we'll notify you when peak demand periods are likely to occur. This allows you to communicate with facilities managers and staff to reduce consumption during these critical times. This is known as “informal” demand response because there is no enrollment or obligation. We can also provide access to “formal” demand response programs that allow your facility to receive payments for a firm commitment to provide specified demand response levels.
Last season, our PLC alerts accurately predicted peak load tags across several major ISOs like NYISO, PJM, and ISO-NE with 100% accuracy, enabling customers to take action and minimize their capacity charges.
Don't miss out on this opportunity to proactively manage your energy costs. Reach out to us at commodity@veolia.com with any questions or to confirm your enrollment in our peak load alert emails for the summer of 2024. Our team is ready to support your business in navigating the complexities of capacity charges.

Guidance from Biden Administration on Voluntary Carbon Credits Market

New guidelines from top climate advisors provide an effective rulebook for responsible participation in the voluntary carbon markets.

On May 28th, the Biden Administration released a voluntary carbon markets policy statement with several principles for responsible participation in voluntary carbon markets. While the guidelines aren’t legally binding, the administration hopes to establish a benchmark for carbon credit issuing and purchasing, and restore integrity to a market that has been plagued by scandals and accusations of transparency issues.
The guidelines include seven principles, which clarify that carbon credits should only be awarded for projects that bring additionality, meaning the reduction in carbon emissions would not have occurred without the “incentives of the crediting mechanism.” The guidelines also state that corporate buyers should prioritize reducing their emissions before purchasing carbon credits. This is consistent with a common mitigation framework often referred to as the Greenhouse Gas Mitigation Hierarchy, which prioritizes the functions of GHG avoidance, reduction, and replacement over financial measures such as RECs and offsets.
The summarized seven principles are:

Carbon credits should meet credible integrity standards and represent accurate decarbonization.
Activities funded by credits should avoid social and environmental harm.
Companies should focus on reducing their own carbon emissions first.
Companies should publicly report their carbon credit transactions.
Credit buyers' sustainability claims should accurately reflect the climate impact of their purchased credits, and “should only rely on credits that meet high integrity standards."
Buyers and sellers should continue to improve the market’s integrity.
Market participants and policymakers should attempt to lower market transaction costs over time.

The policy statement, which was signed by the United States Secretary of Energy, amongst other top federal climate advisors, addresses the high volume of “phony” carbon credit projects in recent years that have tainted the industry’s reputation, despite a much larger inventory of legitimate and important mitigation projects.
There have been several accounts of “natural” carbon capture projects, such as afforestation and forest conservation efforts, that have not resulted in the reduction of carbon emissions correlated with the number of tradable credits generated. The high price of tech-based carbon reduction projects such as carbon capture and sequestration, when compared to natural carbon reduction credits such as forestry management, undoubtedly contributes to suspicions around market legitimacy. Both are important, however natural carbon reduction credits are vastly easier and cheaper to achieve, sometimes even passively.

Source: S&P

Transmission Plans From East to West

Two costly transmission plans were released in California by CAISO and in New York and Massachusetts from National Grid.

CAISO, whose authority primarily oversees the development of high-voltage transmission lines within its California territory, approved a comprehensive transmission planning proposal on May 23rd.
- CAISO’s 2023-2024 Draft Transmission Plan included 26 new transmission projects needed to meet California load growth and clean energy transition goals. On May 23rd, CAISO’s Board of Governors approved the 10-year transmission plan and its $6.1 billion cost.
- $4.6 billion of the costs are identified to be “policy-driven,” meaning the seven projects are needed to support the state’s renewable generation requirements. $1.5 billion of the costs will originate from 19 reliability-driven projects which will provide infrastructure upgrades to address load growth and grid stability concerns across a wider region.

Source: CAISO

The transmission plans include two offshore wind-related transmission projects in Northern California, costing an estimated combined $4.1 billion.
In the northeastern United States, National Grid also unveiled a five-year $35 billion investment plan to improve its transmission operations in New York and Massachusetts. Approximately $21 billion of the investment will be allocated to efforts in New York and $14 billion to Massachusetts, which overall represented a 60% increase in investment compared to the previous five years.
- $4 billion of National Grid’s New York investments will be allocated to its Upgrade Upstate program, a culmination of more than 70 transmission enhancement projects across Upstate New York. Notable power projects are located near Buffalo, Rochester, and Syracuse and include new substations and 1,000 miles of transmission lines rebuilding.
- Additionally, approximately $14 billion of New York’s investment plan will be allocated to natural gas infrastructure. The utility proposed a $5 billion three-year plan to improve its downstate New York gas business, citing a need for improvements in reliability and gas line replacements.
- National Grid’s Massachusetts funds will be primarily allocated to installing smart meters, modernizing infrastructure, and upgrading its electric and gas assets against extreme weather events.
- National Grid’s investments come as the Department of Energy’s National Transmission Needs Study stated that a 255% increase in transmission development was needed to support New York and Massachusetts clean energy growth policies.

Changes In Massachusetts: Expiring Power Plants & New Account Numbers

Massachusetts' Mystic power plant has officially closed down at the same time as the state's utilities have propped un an LNG terminal...and role out new account numbers.

This week marks the last week of commercial operations of Mystic Generation Units 8 & 9, one of the largest power plants in New England located adjacent to downtown Boston. The two x 700 MW combined cycle gas turbines are owned by Constellation Energy, and while they have run less than 10% of the time in recent years, they do provide reliability assurance to the region.
Earlier this month, regulators in Massachusetts approved long term contracts between regional gas utilities and the adjacent LNG import terminal that had historically provided all the fuel to Mystic Generation Station. The contracts extend the life of the beleaguered terminal by another six years and calm fears, for now, about regional gas availability. The terminal had hinted it would close along with Mystic Generation Station if not for the supply contracts.
The agreements will provide the utilities with the option to take 17 bcf of storage gas over a six year period at an average price of $57 per MMbtu. Constraints on the New England gas system can elevate clearing prices for the whole region so despite the high price, it could very well mitigate higher clearing prices that would otherwise impact all buyers of both gas and power in the region.
As such, ratepayers in Massachusetts and Connecticut are playing a key role in financing the continued operation of some of the region's most critical energy infrastructure with “out-of-market” payments. Readers may recall that Connecticut ratepayers entered into a 10-year power purchase agreement with Millstone Nuclear Station, ensuring that asset will have a stable price of power at least through the end of the decade.
Also relevant for customers in Massachusetts, the Commonwealth’s two largest utilities will be updating utility account numbers over the next couple weeks. Eversource (for electric and gas customers) and National Grid (for gas customers only) will begin using a more standardized 10-digit format in June. Accounts currently under contract should not be impacted – service will not be interrupted – however it is possible invoices will be delayed a couple weeks for the June service period.

Utilities Earn Lower Returns on Rapidly Increasing Rate Base

Amongst other factors, a limiting economic environment and mild weather has led to traditionally poorer profits for utilities.

In 2022 and 2023, the average earned return on equity (ROE) for utility companies decreased. This has been largely attributed to higher inflation, which has increased costs to utilities between rate cases, as well as lower margins realized during the COVID-19 pandemic.
From 2015 to 2021 the ROE for utilities increased annually and actually exceeded targets set by regulators from 2016 to 2021. Utilities earned more by spending less on investing in and maintaining infrastructure. In many states this resulted in small credits back to utility customers to rectify excessive profits beyond designated thresholds–one of stipulations of maintaining a monopoly. In recent years, that trend has reversed as utilities are now making somewhat less than their authorized returns.
Another issue that caused this decrease brought about by the COVID-19 pandemic were the state instituted disconnected moratoriums. By preventing utilities from cutting service to non-paying customers, utilities incurred non-recoverable costs and ROEs took a hit.
Weather has not been in utilities’ favor either over the past few years. With more mild summers and winters on average, customers are not spending as much to cool and heat their homes and businesses. This leaves a gap in revenue for utilities that is necessary to increase their ROE.

Source: S&P

One of the many repercussions of this paradigm is that costs and rates are now increasing at much higher rates compared to prior years.
Utilities have filed some of the largest rate cases ever over the past few years. This is a worry for customers as many of the factors causing a need for these large rate increases (inflation, high interest rates) are also putting pressure on their other expenses. Utility rate case requests amounted to more than $18.13 billion in 2023, compared to an average of $6.4 billion per year in the 10-year stretch from 2011 to 2020. On average, only about half of these requested amounts are authorized but the key takeaway is that utilities are earning a slightly lower return on a much bigger pie, and this pie is poised to grow significantly throughout the next decade.

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.