* New England gas pipeline capacity strained
* Heating and power demand boosts need for gas
* Gas imports have decreased this year
By Jeanine Prezioso
NEW YORK, Nov 28 (Reuters) - An abrupt surge in the premium for cash natural gas prices in the Boston area this month has highlighted how the shale gas revolution has yet to reach several U.S. markets, notably New England.
The spread on the December natural gas contract price at Spectra Energy’s Algonquin pipeline citygate point for the Boston area on Monday blew out to a high of $6.49 above the New York Mercantile Exchange benchmark Henry Hub futures price. That was up from $1.07 a month earlier for November gas.
The spot price for natural gas at Algonquin jumped to a high of $14 per million British thermal units (mmBtu) on Monday before settling at $12.53 for gas delivered the following day, compared with $7.09 on the previous Monday.
The abrupt price spike runs counter to the prevailing trend in recent years as a surplus of shale gas oozes across the country, flattening out the so-called “basis spreads” that once offered savvy traders roller-coaster volatility.
That trend is not as pronounced in New England because the hefty pipeline build-out in much of the Mid-Atlantic and Northeast U.S. that complemented the U.S. shale production bonanza has so far passed the region by.
New York, by contrast, has seen the fruits of more shale gas supply as pipeline expansions and planned projects have eased prices. The premium on the Transcontinental pipeline Zone 6 point at the New York citygate, historically one of the most volatile, was just $1.95 above the futures price on Monday while the spot price has remained steady in the $3 to $5 range.
The difference, say traders, is due to logistics. Boston is served mainly by Spectra’s Algonquin pipeline, whose capacity is strained, especially when it gets cold and drives up gas-fired heating demand.
Kinder Morgan’s Tennessee Gas Pipeline also delivers gas to the Boston area and has made at least one expansion to deliver more supply from the giant gas-producing Northeastern bedrock known as the Marcellus Shale to markets in New York and New England, but Algonquin serves as the baseline.
“There are large pockets in given market areas that infrastructure is screaming at to alleviate these gluts and droughts,” Stephen Schork, founder and editor of The Schork Report, an energy research letter in Villanova, Pa.
While Spectra plans to expand the pipeline’s capacity it won’t be for a few years. Meantime, market watchers and traders expect Algonquin to be one pocket where prices will continue to widen until pipeline expansions are realized, or U.S. prices rise to meet the price of global gas imports.
The lack of pipeline capacity has happened as demand for the fuel to generate power has grown as coal has fallen out of favor.
Some 52 percent of the electricity generated in New England in 2011 was generated by natural gas fired generators, compared with 15 percent in 2000, the New England grid operator said.
Canadian gas supplies have not been the panacea some thought, either from gas imports or Canadian production.
Flows on the Maritimes and Northeast pipeline, majority owned by Spectra Energy, which connects gas production offshore Nova Scotia to markets in Canada and pipelines in Massachusetts, have shown zero supply coming into the United States at times during the last month.
The pipeline flows in both directions but supply into the United States is lower this year than last, according to Thomson Reuters Natural Gas Analytics, as Canadian demand has been higher, some of which is being drawn from the oil industry.
Spectra says it has no trouble meeting demand, though the Algonquin pipeline, which can transport up to 1.5 billion cubic feet per day (bcf/d) from producing regions in the Gulf Coast into points as far north as Massachusetts, has had to limit gas flows on the line to some customers during periods of cold weather in recent weeks.
Spectra plans to expand the line and had a “robust response” for the open season it held to gauge customer interest, a spokeswoman said. It will be entering into agreements with shippers and plans to put the expansion into service by 2016.
New England has also sourced gas supply on pricier foreign imports of liquefied natural gas (LNG), which have decreased this year as cheap natural gas has forced LNG exporters to sell the fuel into higher paying markets.
January spot cargoes of LNG in Asia are fetching prices in excess $15 per mmBtu as nuclear outages in South Korea prompted demand for gas.
The Maritime pipeline also delivers gas from Spanish firm Repsol’s Canaport LNG terminal in Saint John, New Brunswick, which it hooks into from Emera’s Brunswick pipeline. Canaport has a maximum sendout capacity of 1.2 bcf/d, enough to heat 5 million homes, the company says.
But last year Repsol contracted with Korea Gas Corp to supply LNG. LCI Energy Insight data shows LNG sendout at the Canaport facility via the Brunswick/Maritimes pipeline between 100 million cubic feet per day and 203 mmcf/d since Nov. 9.
A Repsol spokeswoman would not comment on the Canaport terminal’s imports or sendout saying that information was commercially sensitive, but said it has “firm supply for its firm customers.”
It’s not only that LNG is being drawn into Asia. Prices in Europe are also higher than U.S. prices.
European LNG cargoes could be diverted to the U.S. market since they’d need only to cross the Atlantic to do so, but Europe is still paying $10-$11 per mmBtu, said Chris Micsak, senior energy analyst with Platt’s Bentek Energy in Evergreen, Colorado.
Without at least a $10 sustained price, at minimum, for more than a month in New England, it will be hard to attract what few cargoes are in the Atlantic Basin.