Natural Gas Transportation and Market Constraints

Natural gas is transported through a pipeline system to move it from where it is produced, to where it is refined, and eventually to where it is used in your business. In the Northeast, the gas you burn is typically coming from an out of state source and because of this, travels through one or more, wider-diameter, higher-pressure interstate and/or intrastate transportation pipelines before it is then distributed to you through the smaller-diameter, lower-pressure local distribution company pipelines.

Based on the inherent nature of a pipeline transportation and distribution system, the space needed to get the gas to you is limited and bears a cost. This cost is largely dictated by the amount of gas a pipeline can physically move and the amount of demand for gas on that pipeline. The Northeast is an especially constrained market for gas because of the limited number of pipelines that feed it and the high demand for gas, especially during the winter months.

Since the utility companies are required to provide service to every customer within their gas distribution network, they are also responsible for obtaining the capacity (space) needed to serve those customers. This capacity comes in the form of capacity assets that are generally some assortment of transportation pipeline capacity, storage capacity, and peaking capacity. These assets are managed as a portfolio by the utility with each type of capacity representing a different percentage of the overall capacity needed to serve their customers and each type also having its own cost associated with it.

A brief overview of each type of capacity mentioned is listed below:

• Pipeline capacity, which is the transportation capacity on interstate or intrastate pipeline systems that can be used for deliveries of gas to the utility.
• Peaking capacity, which is capacity used by the utility to reduce the amount of gas service required from a pipeline during peak periods, often for space limitations/cost avoidance reasons. This can come in the form of LNG injections at a specific location close to the end user.
• Storage capacity, which are off-system storage facilities used to accumulate and maintain gas inventories for re-delivery. The storage capacity also includes its withdrawal, and the associated transportation capacity used to deliver such gas.

The utility assigns an estimated TCQ for each customer using data like a daily baseload of gas consumed and a heating factor. These can be based on the customer’s historic gas usage during the most recent twelve-month period, or the best estimates available to the utility should actual gas usage information be partially or wholly unavailable. Depending on the utility the TCQ may be fixed when the customer purchases their gas from a supplier and remain in effect until the customer returns to the utility for gas supply or will be changed annually in November to account for peak day usage changes.

Each year the utility companies proportionately release their capacity assets to suppliers at a cost, based on the aggregate TCQ of the customers they are serving in their utility pool(s). Also on an annual basis, the utility companies reassess the parameters associated with this release of capacity assets to suppliers based on the changing makeup of the underlying portfolio of capacity asset entitlements they manage.

When the program parameters are reset, it can entail the changing of both the capacity asset percentages needed to serve a customer as well as the cost associated with each type of capacity asset. The Company then determines the pro-rata shares of these capacity assets assigned to each supplier based on the product of the aggregate TCQ of every customer they serve, times the applicable capacity allocators (or percentages of each type of capacity asset owned) at each capacity type cost.  For suppliers, purchasing these assets from the utility is not optional, but required to serve customers, and all suppliers face the same relative costs each year when the specifics of the capacity release program are announced. For capacity exempt customers, the supplier is not released capacity assets by the utility to serve them, and instead the supplier is responsible for obtaining their own capacity assets to serve the customer.

Market Changes Driving Increased Costs

As the mix and cost of capacity assets released by the utility to the supplier changes each year, the cost basis for the supplier to serve their customers also changes and may be vastly different from the costs to serve a customer at the outset of the contract. Most supplier agreements are constructed with language that allows them to adjust the price to the customer to pass through these incremental costs to serve stemming from capacity release program annual adjustments. However, there are different approaches by suppliers in how that language is worded in their agreement and in how it is utilized by them in serving their customer base.

Of note, May 2024 saw the retirement of Mystic Generating Station’s units 8 and 9, that were kept online for an additional two years by the Northeast power grid operator (ISO-NE) for reliability reasons. Everett Marine Terminal (EMT) fueled those units with imported Liquified Natural Gas (LNG) and with those units no longer in operation, EMT was also facing the prospect of shutting down. Utilities in the Northeast worked to make agreements with EMT to keep it operational for the next several winters for their own reliability reasons. Those contracts have enabled the terminal to remain operational through the winter of 2029-2030 but have also significantly increased the peaking capacity costs to utilities.

Everett Marine Terminal (EMT) and Algonquin Pipeline Impacts

EMT is the longest operating LNG import facility of its kind in the United States and has been a staple of the Northeast gas market for decades, serving as a critical reserve gas resource. You can understand the utilities concern for EMT shutting down when you understand more about where it is located and the service it has historically provided. EMT is connected directly to two interstate pipeline systems and a utility system directly and because of this it is uniquely positioned to provide seasonal peaking supply to the utilities in the Northeast. It is geographically positioned at the extreme east end of the pipeline network and provides a supply source downstream of pipeline constraints on the coldest days of the year. It has 3.4 Bcf of storage capacity near the largest load center of Massachusetts, which is a state that does not have any existing underground storage capacity. It can provide needed pressure support directly into the interstate pipelines to the end of the system when it is needed. Finally, it has also served as a source of incremental gas supplies for utilities on a spot basis during extreme weather conditions.

Also of note, May 2024 also saw the Algonquin Gas Pipeline, which is one of the major pipelines feeding the Northeast, file a general rate case with FERC proposing rate increases and tariff modifications. The rate increases were sought by the pipeline operator for capital improvements to modernize its systems, operations and maintenance expenses, and overall rising costs largely based on inflation. These increases were approved by FERC and will increase the pipeline’s capacity costs to utilities significantly.

Conclusion – Rising Costs for Customers

These changes and others ultimately lead to a higher cost of the capacity being purchased by utilities and ultimately released to suppliers to serve their customers.