This article was originally published on RBN Energy by Housley Carr
This winter the Northeast US is being blasted with record cold weather. As a result, daily natural gas prices in both New York and New England have spiked more than $30/MMBtu above the US benchmark at Henry Hub, LA. But the average price you’ll pay for natural gas in the region will likely depend on whether you root for the New York Giants or the New England Patriots. With their dismal records and embarrassing mistakes, it’s not easy being a Giants (or Jets) fan these days. But on average – thanks to new gas pipeline capacity added this past fall, natural gas prices in New Jersey and New York have remained less volatile relative to US benchmark Henry Hub, LA than prices in New England. That is because the six-state region continues to suffer from woefully inadequate gas transmission infrastructure. Today we begin a two-part analysis of the still-stalled effort to deliver more supplies to gas-hungry New England.
In the first blog in this three-part series—“Another Gassy Day in New York City—The New Gas Pipelines”—we described how several major pipeline projects between the Marcellus and the Big Apple have eased gas delivery constraints in the region and shrunk price differentials this year. The economic impact of this de-bottlenecking should be substantial: Spectra Energy figures its $1.2 billion New Jersey-New York expansion project, which came online November 1 (2013), will save customers $700 million/year in lower gas prices. In contrast the failure to relieve gas-pipeline congestion in New England has had the opposite effect, driving up wintertime gas prices and even threatening the reliability of the electric grid by forcing gas powered generation to shut down in the absence of firm supplies.
Figure 1 shows monthly average historical and forward-curve prices for natural gas delivered into New York City and at Algonquin city gates in New England as of December 31, 2013. The prices are shown as premiums to CME/NYMEX Henry Hub Louisiana. The historical data shows that both New York and Algonquin average prices increased in the winter months. Recent pipeline enhancements that eased most constraints into northern New Jersey and New York City have reduced winter New York City premiums to Henry Hub going forward but the lack of pipeline capacity serving New England means that Algonquin premiums to Henry Hub remain larger in the winter months going forward. (Forward curves tell us the value that futures traders will pay today for deliveries in the future--see Seasons in the Shade for more on natural gas forward curves and seasonality).
Source: CME data from Morningstar (Click to Enlarge)
New England wants to use more natural gas. Homeowners and businesses in the region know there are potential savings if they switch to gas from oil for space heating. (See “Fuel for the City—Dislodging Oil From the Northeast,”) The power generation sector also sees potential cost savings from switching to gas as well as regulatory benefits to shifting away from coal and oil to comply with tightening environmental regulations. But as we said in “Déjà vu All Over Again—Northeast Natural Gas, Pipelines and Big Decisions,” New England can’t benefit fully from cheap Marcellus gas until sufficient pipeline capacity is in place to deliver gas when it’s needed—even on the coldest winter day. The rub is that the Federal Energy Regulatory Commission (FERC) will not allow new pipeline projects to be built unless they demonstrate “market need” by securing binding commitments of 10 years or more for the capacity the new or expanded pipelines would provide. Unless New England can find a way to power through FERC’s pipeline-approval process (and their own state regulatory issues, for that matter) the region may face gas-delivery shortfalls for years to come.
Five pipelines provide virtually all of New England’s gas—the Tennessee Gas Pipeline (TGP), the Algonquin Gas Transmission (AGT) line, and the Iroquois Gas Transmission (IGT) line from the west through New York State, and the Maritimes & Northeast Pipeline (MNP) and the Portland Natural Gas Transmission (PNGT) from the east and north through New Brunswick and Quebec, respectively. (There’s also the Everett, MA LNG import terminal, though it’s become much less of a factor because higher international gas prices make imports to the US uneconomic at present.) Figure 2 below, from an ICF International report to ISO-New England, the region’s electric-system overseer, shows the region’s pipelines as well as its gas-fired power plants. (Several more gas-fired plants are being planned.)
Source: ICF International/ISO-New England (Click to Enlarge)
All is generally well (though gradually tightening) during the spring, summer and fall as far as gas pipeline capacity into New England is concerned. But during the winter months, when gas needs for space heating rise and gas needs for power generation can soar, the existing pipeline infrastructure through New York State simply does not have enough capacity to meet demand reliably, especially when gas is needed most. Fresh in the minds of just about anyone associated with gas and electricity supply in New England are several frigid days last January and February. TGP, AGT, IGT and PNGT were operating at or near full capacity and couldn’t accommodate the additional demand for gas from power plants, and, with gas production from the Sable Offshore Energy Project (SOEP) in decline and the Deep Panuke not yet producing (see “Is Late-arriving Deep Panuke Gas a Case of ‘Right Place, Wrong Time?’”), the MNP was only partially full. The result: gas prices at the Algonquin Citygate spiked and several New England power plants had to sit idle without secure supplies. ISO-New England – the electric power system operator - has taken steps to avoid a repeat this winter; its Winter Reliability Program, which runs from December through February, gives owners of oil-fired and oil-or-gas-fired plants monthly payments for stockpiling oil, just in case there’s not enough gas to run some plants on the coldest days. And given the weather in New England this week (January 2nd) that program is likely getting a workout right now. But ISO-New England acknowledges the program is only an interim solution, and the market anticipates that, even with the pipeline enhancements being planned, the gas-price spiking the region saw last winter and this is likely to be repeated year after year for the foreseeable future. Figure 3 highlights historic and expected New England gas price volatility according to the ICF-ISO New England report.
Source: ICF International/ISO-New England (Click to Enlarge)
So the question is – can the New England gas supply challenge be fixed? The answer is that before that can happen, a number of market and capacity issues need to be addressed. One of the toughest is that most gas-fired plants don’t like to enter into contracts for firm (non-interruptible) pipeline capacity like local distribution companies (LDCs) do. Instead, generators typically hold less costly interruptible gas-delivery contracts and rely on LDCs releasing unneeded pipeline capacity when power plants really need extra gas. But when its very cold out and gas demand for space heating is sky-high, LDCs typically have little or no pipeline capacity to release. Why don’t gas-fired plants lock up firm pipeline capacity for themselves? To put it bluntly, the electricity market structure in New England doesn’t provide sufficient incentives for generators to ante up the higher costs associated with firm contracts for gas delivery. The market does not provide enhanced payments to power plants that virtually guarantee power when it’s needed, nor does the market really penalize generators for promising power and then failing to provide it. ISO-New England is working on improving things, but it’s a complicated matter, largely because compensating gas-fired power plants for locking in firm pipeline capacity they may only need a few hundred hours a year would raise power prices for everyone.
Another issue is that the gas and electricity markets in New England are not aligned. That is, the region’s “gas day” and “electric day” start at different times, making it difficult for power plant operators to schedule their upcoming gas needs (see Cats and Dogs in the Regions). Still another problem is the increasing number of gas-fired power plants in New York State—between the Marcellus and the western edge of New England—that grab pipeline capacity and high-demand-day gas that otherwise could flow through to power plants in New England.
To overcome these issues, pipeline companies are planning to increase the flow of gas moving into and through New England from the west. But one of the two nearer-term projects under development is small in scope, and the other was scaled back for that all-too-familiar reason: insufficient firm contracts. The smaller effort is Kinder Morgan’s Connecticut Expansion project on the TGP. This $77 million, fully subscribed project will provide 72 Mdth/d of additional capacity into southwestern Massachusetts and northern Connecticut. It will involve 13 miles of new pipeline loops in the TGP 200 Line system in New York, Massachusetts and Connecticut, and the acquisition of an existing lateral pipeline. Kinder Morgan plans to file an application for a certificate of public convenience and necessity in early 2014, and hopes to complete the project by November 2016. That’s the same target date that Spectra Energy has for finishing its Algonquin Incremental Market (AIM) project, which will add up to 342 Mdth/d of capacity to the AGT through Connecticut, Rhode Island and Massachusetts. The original plan for AIM called for adding up to 500 Mdth/d, but weaker-than-expected interest among LDCs, gas marketers and generators in locking in capacity led to a trimming of the project’s scope.
AIM and the Connecticut Expansion will help - starting in the winter of 2016-17, but they won’t be enough. Thankfully, other pipeline projects are in the works, including a potential game-changer—Kinder Morgan’s planned Northeast Expansion, a new, 150-mile pipeline from Wright, NY (north of Albany) to Dracut, MA (north of Boston) that could move as much as 1.2 Bcf/d. In the next episode we’ll look into that project and several others that, if built, could enable New England to take full advantage of the Marcellus gas near its western border.