Rising cost of electricity fuels debate over need for Tennessee Gas Pipeline

Last modified: Thursday, October 16, 2014

When National Grid announced recently that it will increase electricity prices this winter, that was enough to raise some eyebrows.

Not only will its Massachusetts Electric customers have their bills jump by more than one-third beginning next month because of rising fuel costs to generate that power, but competing Western Massachusetts Electric Co. said it will likely also be raising its prices for the six months beginning in January.

This comes as the Tennessee Gas Pipeline Co. moves forward with controversial plans for its Northeast Energy Direct natural gas pipeline, which the company says is needed for New England to power its electric grid and lower energy costs to compete with other regions.

“Limited natural gas transportation infrastructure ... has led to extremely high electricity prices in the Northeast U.S., and threatens the reliability of the region’s electric grid,” Tennessee Gas reported last month in its request to the Federal Energy Regulatory Commission for the pipeline across Massachusetts. “As a result of the fact that current natural gas transportation infrastructure is inadequate to meet the growing demand in the New England region, gas prices in New England are the highest in the United States.”

It quoted an industry association study as predicting that 6 billion cubic feet a day of new natural gas pipeline capacity will be needed in the Northeast by 2020, and 10.1 billion cubic feet per day of capacity will be needed by 2035.

Not everyone is convinced that the Tennessee Gas proposal — which would cross Plainfield and nine Franklin County towns on its way from Wright, N.Y., to Dracut — will benefit this area, or is even needed, although there is agreement that New England’s pipeline infrastructure is inadequate to meet what appears to be a growing demand for natural gas.

ISO-New England, the independent power operator for the region, which buys and sells electricity based on cost of supply and constantly changing demand, says the cost of electricity is directly affected by natural gas prices.

Of the 31,000 megawatts of capacity in the region’s generating system, 43 percent in 2013 was fueled by natural gas, nearly twice the 22 percent fueled by oil-fired generators, and nearly three times the 15 megawatts generated by nuclear power. That’s contrasted with 2000, when oil capacity was 34 percent of the system and natural gas represented 18 percent, according to ISO.

Heat vs. power

When temperatures last January hovered below zero for four days, plummeting to minus-8 at one point, system operators who oversee the region’s electricity grid struggled to keep power on throughout the region, since gas-fired generators that had been committed in the “day-ahead” fuel market could not get the needed gas supply in the secondary market from heating companies such as Berkshire Gas, which are given priority by maxed-out pipelines.

“We saw several times through the winter where reliability was seriously challenged,” said ISO spokeswoman Lacey Girard. “System operators were having a hard time matching supply and demand.”

In some cases, the limited gas supply actually sent the price of gas higher than that of oil, she said. But by and large, high demand from a growing number of gas-heating customers sent the price of gas higher than that of oil, she said.

But oil-fired generators and coal-fired plants often idle more because their generation costs are higher than those that burn gas and they can take 24 hours to ramp up to full power. Thus, they are not always as good an option as gas plants for meeting surges in demand, said Girard. And in the case of last February’s Blizzard Nemo, they did not have the necessary oil on hand and were caught off guard by problems getting delivery, even as power lines and electric substations were being hit by the same storm.

ISO, which is charged with long-range planning for the region, is also looking at 3,400 megawatts of power generation either recently retired or coming offline in the next four years — including the 1,535 Brayton Point coal and oil-burning plant, the 749-megawatt Salem Harbor coal and oil-burning plant, 604 megawatt Vermont Yankee nuclear plant and 342-megawatt oil-fired Norwalk Harbor station.

Also factored into the mix are more than 8,000 megawatts of older oil and coal-burning plants, including Mount Tom and West Springfield, that ISO identifies as “at risk” of retiring, along with more than 5,000 megawatts of gas-burning plants and 3,000 megawatts of wind turbines that developers are talking about building, another ISO spokesman, Michael Giaimo, recently told the Franklin County Selectmen’s Association.

The “challenge,” Giaimo told the group, is that the bulk of those wind projects are in northern Maine, requiring additional transmission capacity to deliver that power thousands of miles southward.

The same is true of the need for additional pipeline capacity, said Girard.

“To operate the grid more reliability, that’s what its going to take — more infrastructure,” she said, essentially echoing the 2013 Black and Veatch study done for the semi-independent New England States Committee on Energy, which tries to guide the region’s governments on energy policy.

Doubts about need

Yet not everyone is sure that the need for capacity is as clear-cut.

NESCOE, which represents the six states in the region, recently faulted ISO’s 2018-2019 installed capacity program for ignoring renewable energy sources that will be available.

The calculation, it said, “ignores its interim, conservative forecast of hundreds of megawatts of solar PV projected to come on-line in the next three years. ... By excluding these resources from the three-year forward calculation, consumers are paying for unneeded future capacity,” NESCOE said.

In fact, Massachusetts is in the process of re-analyzing the Black & Veatch study, saying “Since the Black & Veatch study was published, economic and technological forces, legislative and regulatory initiatives, proposed ISO New England wholesale market reforms, and market trends may have changed some of the basic assumptions in the Black & Veatch integrated model of natural gas and electric power markets.”

Giaimo told the selectmen’s association that although wind and solar projects are expected to ramp up in the decade ahead, along with energy efficiency, most of that additional 1,300 megawatts in solar capacity by 2023 and 1,000 megawatts attributable to energy efficiency by 2023 are counted not as generation, but rather as reduction of demand.

But skeptics reject the notion of building a $3 billion to $4 billion pipeline, as well as other gas pipelines proposed for the region, as a “transition” to a greener energy future, saying those investments work against green goals.

“It is unclear whether Massachusetts needs additional infrastructure to meet demand, and if so, how much,” state Energy and Environmental Affairs Secretary Maeve Vallely Bartlett wrote last month to FERC Secretary Kimberly D. Bose, asking Tennessee Gas to share data on how much unmet demand it perceives to be from heating customers or electric generation “(and) … whether the company is planning to serve customers outside the state or even New England with its proposed pipeline.”

Kathryn Eiseman, director of the Massachusetts Pipeline Awareness Network, said, “New England’s own projections make clear that the energy efficiency programs that we already have in place are keeping annual electricity demand from rising.”

The issues her anti-pipeline group wants addressed are replacement sources for the oil, coal and nuclear plants that are being retired, and the pipeline “bottlenecks” that result on the coldest winter days when gas is being used for electrical generation and heating.

Instead of allowing new pipelines to be built, connecting Marcellus shale gas with liquefied natural gas terminals being built in New Brunswick for export and ultimately raising natural gas prices to global market levels, Eiseman proposes that solutions should include increased LNG storage for power plants, keeping oil-fired plants as a transition in the short run, and expansion of renewable and energy efficiency and conservation programs.

Shanna Cleveland of the Boston-based Conservation Law Foundation agrees, saying, “The real problem isn’t a major deficit of pipeline capacity, but a failure to deal adequately with the increased use of natural gas for power generation. ... Unlike natural gas utilities that supply homes and businesses with gas for heating, which buy gas on long-term ‘firm’ contracts that guarantee access to gas, the companies that own natural gas power plants typically buy cheaper ‘interruptible’ contracts because there isn’t currently a mechanism that allows them to pass through the additional costs of buying firm supply.”

And Claire Chang of the Greenfield Solar Store, who attended last week’s selectmen’s association meeting, said that although natural gas is cheaper than oil, the trajectory for solar power is great enough that it can undercut natural gas and other fuel sources, if only policies and pricing structures still controlled by traditional energy companies would allow it to happen, including the advance of electricity storage.


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