Lagging pipeline build squeezes power supply market in shale-rich New England

New England’s limited natural gas pipeline infrastructure is pushing up peak winter electricity prices in New England to record highs, particularly for utilities that buy on a short-term basis, according to Steven V. Camerino, president and CEO of distribution utility New Hampshire Electric Cooperative.

Spectra Energy's AIM project will transport natural gas supplies from the Appalachian basin to the Northeast. Image credit: Spectra Energy

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Speaking at FC Gas Intelligence’s Natural Gas Power Generation US 2015 conference in May 19, Camerino said that New England’s pipeline infrastructure is inadequate to serve the region’s rising natural gas-fired generation, calling the situation “pretty scary” and a “crisis.”

New England’s heavy reliance on natural gas as a fuel source means that gas fundamentals typically set the price for wholesale electricity in the region.

New England generation capacity is around 31,000 MW, and the share of natural gas generation has increased from 18% in 2000 to 43% in 2014, Camerino said, citing ISO New England estimates.


Natural gas and wholesale electricity prices in New England are linked. Source: ISO New England.

According to Camerino, New England is short of between 1.3 and 2.3 bcf/day of pipeline capacity to meet the needs of gas-fired generators across its six states.

Even though about 14 million people in New England live within driving distance of the Marcellus Shale, America’s biggest natural gas field, heating and electricity prices hit a regional record this past winter.

“Our cars can get there, but our pipelines cannot,” Camerino said.

This past winter, New England gas prices were about 175% higher than the rest of the country, he added. In the first half of 2015, almost all New England utilities saw a surge in the average residential electricity rates, with increases ranging between 7% and 100%, according to Eversource Energy data.

The price spikes in New Hampshire were particularly high for utilities that procure their power from the market on a near-term basis, such as Unitil and Liberty, which saw average residential electricity rates (energy only) shoot up by 85% and 100%, respectively.

In the same period, PSNH – which covers some of its portfolio with its own generation assets – and New Hampshire Electric Cooperative – which holds long-term supply resources – saw price increases of 7% and 29%.

“[The electric supply portion of New Hampshire Electric Cooperative’s] residential rates only went from 9 cents to 11.6. But Unitil and Liberty went from 7.7-8.4 cents to 15.5 cents for power supply during the winter. That is a crisis,” Camerino said.

New England’s difficulties were already highlighted in winter 2013-2014, when spot gas prices in the region were on average much more volatile than prices in the Midwest, even though the latter experienced a significantly harsher winter.

Firming up supply
Pipeline companies and some utilities argue that adding incremental natural gas pipeline capacity would provide essential energy cost relief to both electricity and natural gas consumers in New England.

One problem, according to Camerino, is that the gas generators in the region rely heavily on secondary pipeline capacity. Since all of the firm capacity in New England is contracted for by the local gas distribution companies (LDCs), there is little available supply for generators during the coldest days.

During a peak on January 28, 2014, for example, about three quarters of the gas-fired generation in New England was offline because generators did not have enough gas to meet the hike in demand.


New England's current pipeline infrastructure is inadequate to serve region’s natural gas-fired generation. Source: ISO New England

In recent years, ISOs in the US Northeast have pursued different strategies to compensate some of the generators with backup fuel supplies.

“We were able to brace through the last few winters by putting storage in the tank in terms of oil because we realized we weren’t going to get gas on cold days,” said Peter Brandien, vice president of System Operations at ISO New England.

“That deals with the reliability problem. It doesn’t address the price volatility issue,” Camerino said.

Switching to oil plants pushes up wholesale power prices and raises greenhouse gas emissions.

Market incentives are another problem, according to Camerino. Since ISO New England dispatches based on marginal generation price, it cannot adequately compensate generators that firm up their supply on a long-term basis, effectively discouraging them from holding firm gas pipeline capacity.

“Because gas-fired generators are not assured that they will be able to recover the long-term costs associated with contracting for new pipeline capacity, in most cases they cannot financially justify the required long-term contractual pipeline commitments that are required for the expansion of pipeline facilities,” Kinder Morgan said in a June filing on its proposed Northeast Energy Direct (NED) pipeline project to Massachusetts regulators.

The current crop of proposals in New England includes five other pipelines projected to come in service in 2016-2018.

Spectra Energy is looking ahead to more than $3 billion worth of development for three pipeline projects: the Access Northeast – a joint proposal with Eversource Energy and National Grid to deliver 1 bcf/day of capacity after November 2018 – as well as the Atlantic Bridge Project to New England and the Maritime provinces, and the Algonquin Incremental Market (AIM) project, which is already under construction.

The Portland Natural Gas Transmission System (PNGTS) has also proposed a small project, the C2C, to bring 150,000 MMbtu/day of additional gas capacity to New England.

Iroquois Gas Transmission System’s SoNo project to build a 650,000 MMbtu/day pipeline in New York could also have a favourable effect on New England, Camerino said.


 Proposed incremental pipeline capacity in New England. Source: FC Gas Intelligence.

But it’s not yet clear how the pipelines will be funded or how to distribute the burden of new costs among the generators, utilities, distribution companies and consumers in New England. There are also fears about stranded costs if the new capacity can’t be absorbed.

Others say pipeline expansions should be part of a comprehensive solution for the Northeast that also includes LNG imports, more renewable energy capacity, energy efficiency and improved market incentives.

Gas plants set to dominate
The long-term price stability from abundant supplies of shale gas in the US have supported a much more rapid shift to gas-fired electricity generation in New England.

While the annual gas consumption by the residential, commercial and industrial sectors in the region has remained stable since 2000, the power generation sector has significantly pushed up gas consumption in the region, according to the US Energy Information Administration (EIA).


 Source: ISO New England Net Energy and Peak Load by Source.

Total electricity demand in New England is forecast to grow by 1% annually.

Meanwhile, the region is expected to retire about 3,500 MW of coal-fired, oil-fired and nuclear generating capacity in the next five years. A further 6,000 MW could be retired by 2020, representing 20% of the existing generating fleet, Camerino said.

The share of gas-fired generation is set to rise further as operators currently propose to build around 9,500 MW of new plant in the ISO New England grid, of which 57% would be natural gas plant and 42% wind power capacity.