Natural gas demand in New England, particularly for power generation, has grown rapidly over the last decade, and the addition of a liquefied natural gas (LNG) import terminal would provide the greatest enhancement to gas supply reserve margins in the region, according to a new report by the Power Planning Committee of the New England Governors' Conference.
The report called "Meeting New England's Future Natural Gas Demands: Nine Scenarios and Their Impacts," which was represented to the region's governors in March, examines the costs and other considerations of nine different ways the region could add to reserve margins and increase supply reliability. It determined that there should be a positive gas supply reserve margin until about 2012 unless demand grows faster than currently projected or the region's satellite LNG vaporization capacity suddenly becomes unavailable.
New England's gas demand reached about 850 Bcf/year in 2004 and the Energy Information Administration expects demand growth to continue at an annual rate of about 1.38% for the next 20 years. About 10,000 MW of gas fired power generation has been added to the region's power grid since 1999, and natural gas is now the largest component (52%) of the regional power generation fuel portfolio with about 17,341 MW installed as of winter 2003-2004.
That has led to a stressed gas delivery system during peak winter demand periods when gas supply must meet heating requirements as well as power generation needs.
About 80% of the region's gas supply comes through the pipeline grid and the other 20% comes from LNG that is mostly delivered via truck from the Distrigas import terminal in Everett, MA. The region has no underground gas storage fields. Local distribution companies use about 46 satellite LNG storage tanks (15 Bcf of capacity) scattered around the region to hold the LNG. Vaporization is about 1.3 Bcf/d, or 35%, of peak day demand.
"Overall, New England's natural gas demand is growing though not as fast as some forecasters have suggested," the committee said in the report. "As a result, the demand/supply balance, given no drastic contingencies, does not reach dangerously close levels, as some forecasters have estimated, until after 2010.
"All sources, however, agree that the amount of New England's electric generation that will use natural gas as a fuel, on an annual average basis, is rapidly growing. Compared to the amount of gas needed for space heating on these days, the portion of natural gas supply used for electric generation on a peak demand winter day is about 23% of total demand."
That can stress the system on peak gas demand days. If for some reason LNG vaporization capacity at the region's satellite LNG facilities is unavailable, a shortfall in supply could occur. "The consequences of a shortfall in pipeline capacity or supplies also can be dire," the report warned. "A pipeline reserve margin shortfall and subsequent drop in the LDCs distribution pipelines can set off an extended gas outage that would risk public safety in freezing temperature conditions."
Furthermore, if "gas demand grows at a rate equal to or higher than recent growth rates, the region's gas delivery infrastructure would be insufficient to deliver all needed gas after 2010."
As a result, the region needs to look at supply enhancements. The report examines the costs and considerations of nine potential enhancements to gas reserve margins: greater fuel switching, electricity efficiency improvements, renewable generation additions, the addition of KeySpan's proposed Providence liquefied natural gas (LNG) facility, another new LNG import terminal the size of Poten & Partners Weaver's Cove LNG proposal, the addition of an offshore LNG terminal, an LNG terminal added upstream on the pipeline grid in Canada, coal gasification and additional nuclear generation.
What it finds are that the greatest enhancements to reserve margins come from the LNG scenarios, but those scenarios also are the most costly because of the cost of natural gas and of terminal construction. Some of them, particularly the onshore in-region LNG terminals, also come with "many safety concerns" depending on their proximity to population centers, the committee said.
While the onshore in-region LNG terminal would provide 1.37 Bcf/d of gas supply enhancements under normal demand conditions in 2010, a 77% increase, it also would cost an estimated $5.97 million/Bcf of gas, the report found. That compares with electric efficiency measures that would add 0.97 Bcf/d of supply enhancements to the region in 2010, would cost $2.82 million/Bcf and would provide other enhancements such as lower fuel costs due to the reduction of gas usage by gas-fired generators.
The gas reliability enhancements in 2012 and costs for the other scenarios, according to the report, are as follows:
The committee made no final choice of supply alternatives for the governors. While the LNG scenarios made the greatest enhancements to supply, the report found that any of the other options also would lead to positive supply reserve margins even in a high demand case.
"On the other hand, no one of the scenarios, developed by itself, is sufficient to provide positive reserve margins in the event that there is no vaporization available at existing sites. While we recognize that this is an extreme scenario it reinforces the importance of maintaining the current vaporization capacity to maintain gas supply reliability."
The report also noted that the timing of the supply enhancements also vary for each scenario. For example, any supply benefit from the nuclear power option wouldn't arrive until 2011. The renewable option provides immediate benefits in 2005 but the benefits are very small all the way through 2012, starting at 0.01 Bcf/d in 2005 and ending at 0.13 Bcf/d in 2012.
For more details from the report go to http://www.maineenergyinfo.com/energytrenddata.html.
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