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New England’s Gas Demand Grows Long, Supplies Grow Short

December 8, 2016 | By Warren Waite

New England is a unique corner of the United States in a lot of ways. It’s the birth place of the American Revolution; natives speak in their own dialect and slang; sports fans have ‘’wicked’’ passion for their home teams; and, in terms of the natural gas world, New England is much like peninsular Florida with limited natural gas pipeline paths and capacity into the region. But unlike Florida, the winter months in New England can be wicked cold.

The saga of limited natural gas deliveries by pipeline to New England isn’t new, but access to relatively cheap global liquefied natural gas (LNG) is. The dynamic of limited natural gas availability and power generators in the region relying more heavily on gas than ever before is a problem not in search of a solution -- the solutions are known -- but is hampered by how to pay for reliable heat and electricity. Is it cheaper to pay for the price spikes or for new pipelines? Can New England rely on substitute diesel fuel for grid reliability and still meet commitments to fight global warming?

In this week’s Get the Point, we take a look at how New England supply and demand dynamics played out over the last three winters, assess the crucial role of LNG, and discuss the challenges going forward in the face of pipeline project setbacks that occurred in 2016.

From a power perspective, the energy mix and the reliability of that supply to generate electricity is evolving. The resources available to New England’s Independent Service Operator (ISO-NE) are not the same this winter as they were a few winters ago when the region felt the brunt of the polar vortex.

Barring a repeat of the polar vortex events in 2014 and 2015, ISO-NE says it’s in good shape for this winter thanks to its Winter Reliability Program, the implementation of an expansion project on Algonquin Gas Transmission and the likelihood of robust supplies of LNG.

However, by 2019-2020 the need for certainty of supply grows more crucial. Nearly 2.5 gigawats (GW) of new gas-fired capacity is to be supplied by Algonquin by 2019, but Access Northeast, a major expansion project to support that power demand growth, is on hold while the stakeholders reassess their plans.

The approval, construction and implementation of numerous gas pipeline projects is critical to meet New England’s future electricity needs. Other issues also are in play, including state mandates related to renewables and to rate structures, electric transmission needs and the distribution of cost for new gas pipelines. Each issue is the subject of a tug-of-war by vested organizations in the region.

Market Conditions

During the summer and shoulder months surrounding peak winter, getting pipeline gas delivered to local distribution companies (LDCs) and natural gas-fired power plants is a relatively non-constrained task. Supplies are bountiful, demand is limited and pipeline constraints are usually encountered only during maintenance induced events. That quickly changes when Old Man Winter shows up (we define peak winter as December, January and February), and New England LDCs and power generators have to compete with upstream markets in the Northeast for scarce supply.

New England Demand and Price

As shown in the chart above, New England gas demand is very cyclical and peaks near 4.5-4.8 billion cubic feet per day (Bcf/d). If piped natural gas was unconstrained, then gas-fired power generation would be larger and those peaks would be a lot higher. To supplement natural gas, imported LNG is stored throughout the region, and it is gasified to meet incremental gas demand (more on that in just a minute).

The chart above also displays Algonquin City-Gate (AGT-CG) spot market prices. During the winters of 2012/13 and 2014/15, prices on AGT-CG spiked hard due to peaking demand and scarce supply.

How prices will react in a particular winter is not just due to winter in New England being cold, but where within the Northeast the cold is located, how severe the cold is and how long it lasts. During the Polar Vortex winter of 2013/14, it was extremely cold everywhere in the Northeast for a prolonged period of time. AGT-CG peaked at $78.64/MMBtu on Jan. 23, 2014.

Since then, winters have been less extreme and prices have stabilized. But that could easily change.

The Role of LNG

Unfortunately for New England, the geology doesn’t exist for underground natural gas storage; instead the region uses above-ground LNG storage and a handful of LNG import terminals to mitigate the shortfalls of long-haul pipeline gas capacity. According to the Northeast Gas Association, there is 29.4 Bcf of LNG storage accessible to New England, and those storage terminals have the capacity to vaporize and send out 4.3 Bcf/d of gas.

New England LDCs own 16.1 Bcf of LNG storage with a vaporization capacity for daily sendout of approximately 1.4 Bcf/d.

Also, these four facilities serve New England (see map, too):

  • Distrigas, a subsidiary of ENGIE (formally named GDF Suez), located in Everett, Mass. is an LNG import facility with 3.4 Bcf/d of LNG storage capacity with vaporization capacity near 0.7 Bcf/d.
  • Canaport LNG terminal in Saint John, New Brunswick, Canada, has onsite storage capacity of 9.9 Bcf, and the facility can transport up to 1.0 Bcf/d on Brunswick Pipeline where it interconnects at the U.S. border with Maritimes & Northeast Pipeline (M&NE) which then traverses through Maine southbound towards Boston.
  • Northeast Gateway and Neptune LNG are import facilities without storage capacity.

LNG Import Facilities, Northeast

Of course, not every terminal is used at the same exact time and operates in perfect synchronization with the others to meet the demand of the region. Some of the LNG import shipments are part of long-term sales and purchase agreements, and other imported cargoes are purchased on the LNG spot market. Then there is the logistics of getting the gas to market and the ultimate end-user, be it a LDC or a power generator.

Meanwhile, two interstate pipelines transport vaporized LNG to New England end-users. Tennessee Gas Pipeline (TGP) can receive gas from Distrigas and Canaport via interconnect deliveries off of M&NE Pipeline. Algonquin Gas Transmission (AGT) can receive gas from Distrigas, Canaport via M&NE, Northeast Gateway and Neptune.

The Distrigas facility in Everett does more than just interconnect with TGP and AGT. It also has the ability to dispatch up to 0.1 Bcf/d via trucks, which help support localized refill efforts of LDCs in the region whose 16.1 Bcf of LNG storage is spread across multiple small-scale facilities. Moreover, the Everett terminal directly connects to National Grid (Greater Boston LDC) and the Mystic Generation Station.

Unfortunately, information on how all of the regional LNG storage facilities operate is not available to the public. U.S. Department of Energy data can help us see volumes shipped to select import terminals to gather a sense of how often and when LNG imports arrive in New England. For Canaport in the graph below, PointLogic Energy sourced terminal data from IHS Markit (PointLogic’s parent company).

LNG Imports Compared to New England Demand

Looking at the chart above, which compares New England gas consumption against the timing of LNG imports, one notices that cargoes arrive almost year-round and don’t necessarily bunch during winter peak months. Secondly, Everett (blue diamonds) is by far the most active facility due to its connectivity to an LDC, a power plant, LNG trucks and several interstate pipelines. Also note that Everett is owned by ENGIE, which is also a global LNG player. The vast majority of Everett’s imports come from Trinidad under long-term contracts, thus it is not totally dependent on New England’s short-term price and market fundamentals.

The location and quantity of LNG imports are important to note since the different terminals’ connectivity to infrastructure differ and Everett is the favored source of LNG.

Over the past three winters, Everett received an average 23.0 Bcf of LNG imports, and in the past three summers it averaged 24.6 Bcf of imported LNG. Northeast Gateway received a marginal 2.5 Bcf of cargoes over the last two winters, while the utilization of Canaport has been declining. Canaport only received 9.0 Bcf of LNG imports during winter 2015/16 while over the prior two winters it received nearly 15.0 Bcf.

The Role of Gas-Fired Power

Thus far we’ve established the depths of pipeline gas demand, volatility in the Algonquin City-Gate price and the role regional LNG plays to help bridge the gap. It is important to remember that LNG in New England (whether it is piped in long distance or vaporized from an LNG storage facility) is used for more than space heating of residential and commercial spaces and industrial use. LNG is used in the power sector. ISO-NE and the utilities it coordinates and regulates rely on a mix of fuels to help generate power to meet fluctuations in electricity demand. Those sources range from nuclear, coal, natural gas, heating oil, hydro and renewables. While much of those are baseload sources, some of the use of natural gas, coal and heating oil are influenced by availability and price.

Over the past three peak winters (the December-February period) the market share of natural gas (a combination of pipeline gas and vaporized gas from LNG) for electric generation has increased despite a decrease in total net generation load.

Peak Winter

ISO-NE is in its fourth year of its Winter Reliability Program, which helps address concerns about performance of the electric grid when resources are dispatched in severe cold-weather conditions. According to ISO-NE, the program incentivizes generators that run on oil and dual fuel (oil and gas) to increase inventories (gas generators would contract for LNG) by compensating them for a portion of the costs related to any fuel inventory that is unused at the end of each winter. The program also includes a demand-response component. But the winter of 2017/18 will be the final year of the program. By mid-2018 ISO-NE will switch to a ‘’Pay-for-Performance’’ incentive in the capacity market.

Over the years, participation in the Winter Reliability Program has grown and has changed somewhat in how compensation is structured. The current year’s program is summarized below, along with the results of last year.


Winter 2015/16 was unseasonably warm, and no LNG was utilized in the program. This means that gas-fired generators that contracted for LNG via the program were compensated $2.15/MMBtu on the eligible amount to offset the risk of unused contract volumes. For winter 2016/17, the participating volume of LNG is roughly 41% of the year prior and it’s at a lower payment rate. This is obviously less than winter 2015/16, but it is on par with winter 2014/15 LNG participation.

In recent years, each state across the country has responded in its own way to a regulatory push for cleaner energy sources. Some states have set renewable portfolio standards and have looked for ways to reduce fossil fuel emissions in various forms.

Though the details and politics of that subject is beyond the scope of this article, the impact of such decisions over the years is something to note. Namely, coal-fired capacity has been shut down, and more is on its way out of service in the future. New England is no exception to this trend. Below is a graph showing the fossil fuel mix during the past three peak winter seasons. Note that coal and heating oil (green and red shaded areas) were more evident during the polar vortex events in early 2014 and early 2015.

Fossil Fuel Mix During Peak Winter


In June 2014, the Salem Harbor Generating Station, a three-unit coal and one-unit oil power plant was retired. The site of that facility is being remediated, with the old plant demolished and a new facility rising, Footprint Power’s 675 MW natural gas-fired plant scheduled to go into service by June 2017.

More is on the way. By June 2019, a total of 2,983 MW of new gas-fired power plants (the vast majority supplied with gas by AGT) will be online. Conversely, ISO-NE will lose 2,205 MW due to future retirements.

New Build and Retirements

It should be apparent the future energy mix for ISO-NE consists of less coal, less oil, less nuclear and a lot more natural gas-fired power plants. How will these power plants get their supply during critical times of need when many of these plants don’t have firm in-path natural gas transportation contracts?

While some of the utility owned plants may have access to some gas capacity through the utilities portfolio of gas contracts, many cannot justify or even pass along the costs attributed to year-round gas transport when their dire gas needs are limited to only the coldest days of winter over a 90-day period. Are these utilities better off not paying the sunk cost of transport demand charges, but paying a premium for gas supplies at whatever the spot price is during times of need?

That is the longstanding conundrum. The layers of complexity are vast and regional concerns extend beyond just gas supply. Organizations such as the non-profit New England States Committee on Electricity (NESCOE), which is governed by a Board of Managers appointed by each of New England governors to represent the collective views of six New England states on regional electricity matters, are trying to find answers. Integrating Markets and Public Policy (IMAPP), led by the New England Power Pool (NEPOOL) is another project to identify and explore potential changes to wholesale power markets that could be implemented to advance state public policy objectives in New England.

Key Pipeline Projects

From a gas pipeline perspective there have been many projects planned to deliver cheap Marcellus-sourced supply into New England. One project, Algonquin Incremental Market (AIM), came online in November, and others are slated in the years ahead.

But the bigger story is delayed or canceled projects that were expected to provide substantial new gas volumes to the area in a few years. Kinder Morgan’s Northeast Energy Direct (NED) was pulled in April 2016 due to the lack of capacity commitments. Getting enough electric-based utilities to commit for long-term pipeline capacity was the major challenge cited by the company.

A similar challenge faced Spectra’s competing Access Northeast project. While this project had the capacity commitments, in October 2016 state-level regulatory support for how those utilities would recapture costs through rate increases fell apart. Access Northeast isn’t dead according to Spectra, but it is on hold until 2019 or later as the company reassesses the project. For more on the challenges on these two projects, please see our Sept. 15th edition of Get the Point.

PointLogic Energy, Company Filings

While LNG has been and will continue to be a solution to solving winter reliability concerns within New England, the table above summarizes a host of projects that look to pipe gas in to the area. PointLogic tracks the development of all interstate pipeline projects in North America and has detailed information on each as well as a summary explaining what each project accomplishes.

Start a Free Trial of PointLogic Energy's Pipeline Flow Data

Broadly speaking, the bulk of the above projects will add compression and looping to expand west-to-east flows into New England. (The exceptions are Continent to Coast and in part Atlantic Bridge, which allow for gas supplies to back feed into New England from Canada.) If it is eventually built, Constitution will provide an artery of supply to other pipelines and projects.

Stakeholder Points of View

PointLogic's editorial staff covers the important news events taking place within the energy patch. Below is an excerpt from a recent PointLogic news story that provides keen insight to the operational readiness of ISO-NE directly from the ISO itself.

Since the Polar Vortex winter of 2013/14, FERC has asked the leaders of Regional Transmission Organizations (RTOs) and Independent System Operators ISOs to provide input to the Commission on their preparedness for the upcoming winter heating season. At the Oct. 20 FERC meeting, the RTO and ISO representatives said they are well-prepared for a winter that’s projected to be cooler than last year but very much in line with the 30-year average.

FERC has emphasized to the organizations that they should improve gas and electric industry coordination to improve fuel availability, noted FERC Chair Norman Bay. “The commission revised its relations to better coordinate the schedule of wholesale gas and electricity markets in light of increased reliance on natural gas…and to provide additional scheduling flexibility to all shippers on the interstate natural gas pipelines with the goal of improving generators’ access to fuel during extreme winter events,” he said.

Peter Brandien, vice president of system operations at ISO New England said the ISO has conducted emergency preparedness tests and has assessed its capacity deficiencies. The group is reviewing on a monthly basis its load-shedding procedures, and coordinating with other transmission operators. “We share information with other reliability coordinators in the Northeast, let them know where we stand,” he said. One key in the region is the availability of dual-fueled units. “We want to make sure that those units – that we understand so that we can plan into the operations, if for some reason during the day the gas got tight and we had to coordinate the switching of fuels for generators,” Brandien said.

Another positive is that pipeline expansion projects completed since last winter have added about 345,000 Dth/d of potential gas supply to the area, he said, equivalent to 1,500 MW of generation or more.

Eventually LDCs will use a lot of that gas from those expansions for direct service to res/com consumers, but for now power operators are benefiting from the added supply. “It probably will take a while for the LDCs to go into that expansion. It’s not going to go from nothing to full utilization. For the next couple of years, we will probably take advantage of that additional expansion and have more gas available at colder temperatures,” Brandien said.

While he does not foresee operational issues, Brandien said that there’s always uncertainty. “It’s really about whether we have the fuel to operate the generators,” Brandien said.

“LNG is critical to our winter reliability program,” he continued, though he added that a survey of operators indicated that they are planning this year to use “a bit more oil, less LNG.”

The bottom line: “As long as the LNG continues to come to those locations, I think we will be in pretty good shape to get through this winter. It’s all going to depend on how cold temperatures get and how much LNG is injected into the system.”

But a week after the FERC meeting referenced above, Connecticut’s Department of Energy and Environmental Protection threw in the towel and ceased consideration of Spectra’s Access Northeast project. In a PointLogic news story covering the fallout of that decision, Spectra spokesman Creighton Welch nicely summarized the long-term issue at hand:

"ISO-NE, the electrical grid operator for the region, recently stated that New England’s power generation situation is precarious during the winter time, and that beyond 2019 it may become unsustainable during extreme cold conditions without immediate action to solidify the regions energy infrastructure. Simply put, the regional pipelines are running full and demand is growing which exacerbates the possibility of electric black-outs and shortages of natural gas for home-heating,” Welch said.

As noted earlier, ISO-NE says the region is likely to be okay in the 2016/17 winter. However, by 2019-2020 the certainty of supply grows even more crucial. Remember that nearly 2.5 GW of new build gas-fired capacity is to be supplied by Algonquin by 2019.

Yet a key project to support that power demand growth, Access Northeast is on hold while the stakeholders reassess their plans. The approval, construction and implementation of the aforementioned gas pipeline projects are critical.

Other issues that are linked to solutions are state mandates, electric transmission and the capacity markets are being addressed by NESCOE and NEPOOL’s IMAPP. Solving the growing demand for gas-fired electricity and the ownership and distribution of cost for new gas pipelines is a riddle that will take regional stakeholders, federal and state agencies, among others, to solve.

Stay tuned to future Get the Point postings involving New England as infrastructure and regulatory items progress and the market develops.

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