Electricity prices in Boston, which reached record premiums to New York costs last month, are poised to remain at all-time highs through March because of bottlenecks on natural-gas pipelines.
New England’s reliance on the fuel for power generation has grown to 52 percent from about 30 percent in 2001, though there have been no new pipelines transporting gas to the six-state region in 40 years. In New York, lines from wells in the Marcellus shale deposits of Pennsylvania and West Virginia boosted deliveries by more than 1 billion cubic feet a day this winter, enough to heat about 3 million homes.
Wholesale power in Boston is trading at the highest January premium to New York since at least 2005, according to grid data compiled by Bloomberg. Prices in New York recovered faster from a blast of arctic cold last week because of the increased gas supplies. The power premium may widen later this year and into 2015 as a Vermont nuclear reactor and one of the region’s largest coal plants are set to close, according to BNP Paribas SA. A new gas pipeline to New England isn’t scheduled to begin operations until 2016.
“The Boston, Massachusetts, hub is going to see a much more expensive winter power cost,” said Kate Trischitta, director of trading at Consolidated Edison Inc.’s wholesale energy trading unit in Valhalla, New York. “New York will be more moderate with the new pipelines in play and you see that priced in with that spread.”
Spot Boston on-peak power gained 70 percent from last winter, averaging $96.71 a megawatt-hour Nov. 1 through yesterday, the grid data show. New York City rose 49 percent to $77.82. The $18.89 premium is the most for the period in data going back to 2005.
Power for next-month delivery in New England is trading at $166.64 a megawatt-hour, the highest for this time of the year since at least 2005, according to broker data compiled by Bloomberg. Contracts are valued at a premium of $50.61 to New York in February and $15.99 in March. Last year was the first time that Boston emerged as the premium winter power market, averaging $6.23 from November through March.
“The pipeline constraint has shifted further north,” said Teri Viswanath, director of commodities strategy at BNP Paribas in New York. “These regional blowouts have firmly moved north and will be further exacerbated by the shutdown of alternative baseload generation in 2014.”
A cold snap last January that caused some power plants to run out of gas prompted ISO New England Inc. to pay almost $75 million to oil-fired generators to stockpile fuel and assure adequate power supplies this winter, according to Lacey Ryan, a spokeswoman for the grid operator in Holyoke, Massachusetts.
“Over the last five years or so we have been retiring a lot of coal plants, older heating oil and diesel plants and everyone is running on gas,” Tom Hahn, vice president of U.S. power derivatives at brokerage ICAP Energy LLC in Durham, North Carolina, said in a Jan. 7 interview. “We still don’t have enough pipeline capacity.”
Spot gas at the Algonquin City Gates, including Boston, averaged $11.17 per million British thermal units from Nov. 1 through yesterday, the most in eight years on the IntercontinentalExchange. The frigid weather sent prices to a 10-year intraday high of $50 on Jan. 6. Gas for delivery to New York at the Transco Zone 6 delivery point averaged $7.13 after jumping to a record $90 on Jan. 6.
Natural gas futures on the New York Mercantile Exchange averaged $4.03 during the same period and settled at $4.326 today.
The coldest day of the 21st Century in the U.S. came on Jan. 7, according to Commodity Weather Group LLC. More “brutal cold” is due at the end of January, and February readings may come in below normal, said Matt Rogers, president of the Bethesda, Maryland-based forecaster.
Output of shale gas at the Marcellus deposit will reach 14.23 billion cubic feet a day next month, up from 1.18 billion in January 2007, according to the U.S. Energy Information Administration, the Energy Department’s statistical arm.
Production gains were made possible by innovations in drilling and hydraulic fracturing, which allow producers to bore horizontally, then use explosives and a high-pressure stream of water, sand and chemicals to blast open fractures in the shale that free the fuel.
The U.S. met 86 percent of its energy needs in the first eight months of 2013, on pace to be the highest annual rate since 1986, government data show.
Spectra Energy Corp. (SE:US) spent $1.2 billion to boost capacity on its Texas Eastern and Algonquin gas systems in New Jersey and New York by 800 million cubic feet a day. Williams Cos.’ spent $390 million to add 250 million cubic feet a day from the Marcellus shale into Manhattan.
Spectra’s expansion was driven by city regulations that will require oil-burning boilers to switch to gas, said Bill Yardley, president of the Houston-based company’s U.S. transportation and storage division. The project’s anchor customers are Chesapeake Energy Corp., the second-largest U.S. gas producer, and Consolidated Edison Inc., which owns New York City’s power and gas utility.
The pipelines were the “first major lines” for the area in 40 years, said Tyson Brown, an analyst with the EIA in Washington.
In New England, building new lines is hindered by pipeline requirements that users reserve year-round capacity even though power generators only need the fuel when demand is highest, Yardley said. Pipeline projects need the so-called firm customers to help cover costs, he said.
Spectra, the operator of a 19,000-mile gas network from the Gulf Coast to Canada, is planning an $850 million Algonquin expansion to increase Boston deliveries by 350 million cubic feet a day in 2016, Yardley said. “They probably need more than that and it is going to remain a bottleneck for the next couple of years,” he said.
Existing gas shipments to New England from Canada declined because of reduced offshore production, while liquefied natural gas tanker shipments fell as suppliers found more lucrative markets elsewhere, Wei Chien, a natural-gas analyst with Genscape Inc. in Houston, said in a report.
Imports into the GDF Suez (GDFZY:US) LNG terminal in Everett, Massachusetts, slipped to 25 tankers last year from 37 in 2012, Carol Churchill, a spokeswoman at the company’s Distrigas unit, said in a Dec. 30 e-mail. Shipments are down from 63 in 2008.
It takes five days for tankers to sail to Boston from Trinidad with 3 billion cubic feet of gas, enough to generate 1,000 megawatts of electricity for 15 days, according to GDF.
The electricity supply-and-demand balance in New England “changed dramatically” as announced plant retirements create a deficit of more than 1,000 megawatts of generating capacity from a surplus of 2,000 megawatts in 2013, the grid operator said in a Nov. 25 letter to the Federal Energy Regulatory Commission.
Entergy Corp. plans to shut its 650-megawatts Vermont Yankee nuclear plant, about 90 miles northwest of Boston, in the fourth quarter as a drop of almost 70 percent in gas futures since July 2008 squeezed profits by driving down wholesale power prices amid high reactor operating costs.
ISO New England said the 745-megawatt Salem Harbor coal-and oil-fired plant in Massachusetts is slated to close this year. The grid operator also received shutdown notices totaling 3,135 megawatts, including the Brayton Point coal-fired plant in Massachusetts in 2017.
Given the gas-supply bottleneck, “New England is much more likely to trade at a premium to New York,” said Eric Bickel, a natural gas analyst at Schneider Electric in Louisville, Kentucky. “When we do see pipelines built later in the decade, that will come off.”
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