November 2015, Vol. 242, No. 11
Features
With a Chill in the Air, Thoughts in New England Turn to Heating Bills
As winter approaches, the hot topic of conversation in the Northeast once again becomes the looming frigid temperatures and accompanying burdensome cost of heating homes and offices along with powering manufacturing plants.
With this in mind, the Access Northeast project developers plan to upgrade existing pipeline facilities and market area storage assets in New England to deliver – on peak days – up to 1 Bcf/d of natural gas for electric-generation markets.
The expansion, with potential savings of $1 billion annually to electricity customers in New England, isn’t expected to come online until the end of 2018. However, with wholesale electric prices in New England increasing over 175% from December 2014 to February 2015, any sign that additional infrastructure is on the way is welcome news to consumers.
The federal Department of Energy (DOE) reports New Englanders paid almost 21 cents a kilowatt hour in January and average first-quarter household electricity prices that were two-thirds higher than the national average. This inequity became even more apparent with business management consultant ICF International’s well-publicized findings that if Access Northeast had been in service during the extreme 2013-14 winter, savings in the region would have totaled $2.5 billion.
“Customers are paying dearly due to pipeline constraints,” said Lee Olivier, executive vice president at Eversource Energy. “Infrastructure improvements are needed to solve the region’s energy challenges and a scalable solution that will enhance existing pipeline systems has numerous benefits.”
Eversource, Spectra Energy – owner of the Algonquin system – and Spectra Energy Partners announced in February that National Grid was joining Access Northeast as a co-developer. That meant Spectra had locked up generating plants serving 70% of the electricity customers in New England.
“This project is different from other expansions that are designed more for local distribution companies or marketers,” Richard Kruse, vice president for regulatory and FERC (Federal Energy Regulatory Commission) compliance officer for Spectra, told P&GJ. “The primary focus is getting gas to generators currently attached to Algonquin and Maritime pipelines. Most of these generators do not have firm capacity. They mostly rely on capacity release (from LDCs) and that’s interruptible.”
The Access Northeast expansion is designed to maximize direct pipeline interconnects to as many as 60% of ISO New England’s power plants, upgrading facilities on the Algonquin system and market area storage capabilities in New England. Located in New York, Connecticut, Rhode Island and Massachusetts (see map), the project will include 125 miles of additional pipeline, with most of the expansion falling within existing corridors.
While the pipeline expansion will be built to handle average year-around loads, adding 550 dekatherms a day (dth/d), there will also be an LNG tank constructed that will allow an additional 440 dth/d to be delivered during winter peak months.
That the tank will be located on land already owned by Eversole should be advantageous when it comes to the permitting process. Another plus for the project is that it takes place primarily in existing right-of-way and involves picking up and laying expanded pipeline capacity rather than building out onto additional land.
“I don’t think any pipeliner would say getting permits in today’s environment is easy, but it’s certainly easier if you are using existing right-of-way,” Kruse said.
Access Northwest is in the prefiling stage and while most comments from the public have thus far has come from adjacent landowners looking for more specifics, pricing has been a significant issue for local officials. Among the most frequent questions has been, “Who pays for the project?” Answered simply, Kruse said, that process requires electric distributions companies to gain authorizations from various state commissions to collect the cost from customers.
With Massachusetts investigating the ability of its Economic Development Council (EDC) to recover these costs through rates, New Hampshire conducting a similar process and Connecticut preparing to launch a rate stabilization plan (RSP), the region appears to be nearing a consensus.
“The political heat that people have been taking is generating some very positive developments on the state regulatory and state political front,” Kruse said.
The Quandary
In the wake of the shale boom, natural gas has become so inexpensive and plentiful in the United States that many producers are clamoring to export the product. Yet in New England, the lack of pipeline capacity from the Marcellus and Utica shales has found the region importing LNG from as far away as the Middle East.
More and more in recent years, demand for natural gas in New England has been driven by the power-generation sector, which increased its usage share from 15% to 51% in the relatively short time between 2000 and 2011, according to ISO New England data. This occurred during the same period the region grew more dependent on natural gas for heating. In fact, according to the DOE, gas-fired plants supply 44% of New England’s electricity, a hefty jump from an 18% share of the market in 2000.
Power-generation companies traditionally don’t rely on firm capacity contracts for their supply while LDCs hold most firm capacity to ensure the winter needs of residential and business customers. The crux of the problem becomes obvious: power plant operators want to run at high-load factors during the winter – the same time LDCs are pulling back capacity.
This creates a challenge for an electric industry that needs the gas-fired generators to maintain the reliability of the electricity grid, but claims its operators can’t afford the capacity because they aren’t paid enough in the electricity market.
At the moment, most power-generation companies rely on capacity acquired either through capacity release from LDCs, which is interruptible and recallable, or they use interconnection points (IP). During the last three or four years, Kruse said, there have been very little IP left over.
“That means when it gets really cold they (power generators) lose out on the capacity,” he said. “We’ve been in discussion with the electric distribution companies in New England that are having to flow through the cost of the current structure every winter. When it gets cold the electric rates really fly up, and they have to reflect that in their retail rates. It’s quite a challenge for the region to pay the higher energy costs generated due to this lack of assured fuel supply.”
Economic Fallout
A recent study commissioned by consumer advocacy group New England Coalition for Affordable Energy pointed to at least five years of additional financial hardships for customers if the region’s energy infrastructure isn’t expanded.
Conducted by Boston consulting firms La Capra Associates and Economic Development Research Group, the study found the fallout from not acting would lead to hikes in total energy bills between 2016 and 2020 of $5.4 billion. Additionally, it concluded about 167,600 jobs would be lost, along with a drop in disposable income in the region of about $12 billion. The authors said the study’s focus was on reviewing infrastructure investment primarily for economic purposes – to reduce prices – rather than investment deemed to be needed solely for reliability purposes.
“The large number of job losses quantified in the study are caused by the combination of higher energy costs and the loss of additional infrastructure investment,” said Carl Gustin, spokesman for the coalition. He said higher energy costs alone would cause the region to lose 52,000 private sector jobs by 2020, virtually negating 80% of private-sector job growth projected for that year.
The region has already incurred $7.5 billion in higher energy costs during the past three winters due to the natural gas pipeline system reaching capacity because of demand placed on it for electricity generation and space heating, the study said.
“The positive news is that infrastructure projects have been proposed and some are underway that would mitigate or eliminate these adverse consequences,” Gustin said.
Despite this data, not everyone is so sure that more infrastructure, at least in the form of major pipelines and associated buildouts, is the best answer for New England’s energy woes.
GDF Suez, which not coincidentally owns a Boston Harbor terminal capable of receiving LNG and an offshore receiving port near Gloucester, MA, argues that imports would offer enough relief without charging electricity customers for additional natural gas pipelines.
A study by research group Skipping Stone and commissioned by GDF Suez to access New England’s energy markets found “only modest pipeline improvements” are necessary to create long-term stability to the electricity grid, when LNG supplies and backup oil turbines are placed in use to cover shortfalls.
“Incremental capacity additions to New England’s conventional pipeline infrastructure to serve native annual load for LDCs will likely continue to be economic if demand growth occurs, without a large pipeline’s detrimental effect of ‘crushing’ secondary market values and imposing uneconomic load-factor costs on ratepayers,” the report said.
While calling the Suez district gas plant, which has been in the region for years, a “vital component of peak-day supply,” Kruse expressed reservations about the Skipping Stone study.
“What I would be concerned about would be the capacity of the pipelines to deliver that LNG to power plants on a reliable basis without additional pipeline capacity being constructed,” he said. “When LNG was flowed in the past, it had been because on a peak day it was needed and there weren’t other supply options.”
According to its records, Algonquin has run at almost 100% capacity from the west for the last three years.
“One of the keys things we want to achieve with this project is to be able to tell the region that these power plants will be able to get gas on a firm basis,” Kruse said.
Other Voices
Separately, a study by Virginia-based consulting firm ICF International and released by Kinder Morgan, which plans a 188-mile Northeast Expansion Direct (NED) of the Tennessee Gas Pipeline through New Hampshire and western Massachusetts, believes the NED could save New Englanders $3 billion annually.
The report further found if NED had been online during the brutal winter two years ago, savings in the region may have reached $3.7 billion for the year. It also stated the Kinder Morgan pipeline, which will bring an added 1.3 Bcf/d online after its completion in 2018, will reduce costs annually between $2.1-2.8 billion for the following 10 years.
Tennessee Gas Pipeline (TGP), a Kinder Morgan company, recently announced the start of its non-binding PowerServe open season, a customized firm service designed to meet the needs of gas-fired generators, specifically in the Northeast and New England.
PowerServe firm service will use assets from the NED project, including regional storage, line pack and legacy TGP facilities. It will offer up to 740,000 dth/d of capacity in the open season. The amount of capacity and specific assets required to provide the no-notice and non-ratable hourly service components of the service will be determined following the close of the open season based on shipper interest.
“The ICF study supports NED’s potential contribution to reducing and stabilizing prices, and improving reliability through increased gas availability,” said Kimberly S. Watson, president of Kinder Morgan’s East Region Gas Pipelines. “New England needs more natural gas capacity, and NED would provide the region with direct access to abundant, reasonably priced supplies of gas. Additional gas supplies will bring down energy costs in New England and benefit consumers who now bear the burden of paying some of the highest energy costs – if not highest – in the country.”
A recent New Hampshire PUC staff report was described by Kinder Morgan spokesman Richard Wheatley as “encouraging” in that it points to the possibility of substantial consumer savings brought about by “additional pipeline capacity and the NED project.”
On Sept. 27, Kinder Morgan announced TGP reached agreements with producers, local distribution companies (LDCs) and a New York end-use market participant totaling 627,000 dth/d for the supply path component of the proposed NED. As a result, the company said it will provide a direct supply link from natural gas fields in Pennsylvania to existing and future Northeast and New England markets, and firm transport of incremental supplies for delivery at or near Wright, NY. From the Wright area, shippers can deliver into the market path component of the NED project for transport to Dracut, MA, or into TGP’s existing pipeline system, or into the Iroquois Gas Transmission system.
Additionally, Atlantic Coast Pipeline (ACP), in mid-September, applied to FERC to build a 564-mile interstate natural gas transmission pipeline designed to meet electricity generation needs for part of that adjoining region.
ACP, formed by Dominion (45%), Duke Energy (40%), Piedmont Natural Gas (10%) and AGL Resources (5%), would transport natural gas from Harrison, WV southeast through Virginia with an extension to Chesapeake, VA and south through central North Carolina to Robeson County.
“The Atlantic Coast Pipeline is essential to meeting the clean energy needs of Virginia and North Carolina, and has significant benefits for West Virginia as well,” said Diane Leopold, president of Dominion Energy.
If all goes as planned, the pipeline should be under construction during the second half of 2016 and in-service in late 2018. The ICF study found one-time construction activity on the project could add an annual average of $456.3 million into the economies of the three states involved, supporting 2,873 jobs in the region through 2019. Additionally, consumers and businesses in Virginia and North Carolina could save an estimated $377 million annually in lower energy costs.
Taking AIM at Relief in 2016
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A second major expansion effort in the region for Spectra – expected to come online a couple of years earlier – is its Algonquin Incremental Market (AIM) project. Located in New York Connecticut, Rhode Island and Massachusetts, the fully owned Spectra venture is expected to be completed in November 2016. In other words, in time to provide relief next winter.
“This is a fairly significant expansion of just shy of 342,000 dth/d, and it’s been certificated and is under construction, which will take two years,” Richard Kruse, vice president for regulatory and FERC compliance officer for the company, told P&GJ.
The AIM Project bolsters the capacity of Spectra’s existing Algonquin Gas Transmission system and will allow abundant regional gas supplies from the Appalachian basin to flow into the Northeast.
The project involves expanded pipeline capacity on the Algonquin Gas Transmission system. According to the company, 93% of the project’s facilities would fall within or adjacent to existing rights-of-way, while 70% of the facilities would replace pipe within existing rights-of-way.
Algonquin has signed long-term contracts for all of the project’s capacity, beginning in November 2016, with 10 shippers – eight southern New England LDCs and two municipal utilities that deliver natural gas to their service areas in Connecticut, Massachusetts and Rhode Island.
Each of the contracts was approved or has been evaluated by each shipper’s state regulatory commission or municipal authority process, which determined that the shipper contracts are in the public interest. There are no Maritimes & Northeast Pipeline Company deliveries involved with the AIM Project.
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The AIM Project will not be used to transport natural gas for export as LNG. The additional supplies will be used exclusively within southern New England.???
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Richard Kruse
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