Jones Act leaves New England out of LNG boom
Western Canada, the U.S. Gulf Coast, West Texas and Appalachia are all overflowing with natural gas. So much so that prices are down and occasionally have turned negative in some areas, when producers actually had to pay someone to take their gas.
Too bad there is no easy way to move more of that gas to the U.S. East Coast, New England and Canada’s Maritimes provinces, where natural gas customers are paying the highest prices in North America.
The obstacles are by land and by sea.
There is not enough pipeline capacity to reach the Eastern Seaboard. And a 99-year-old federal law, the Jones Act, requires that only U.S.-built and U.S.-flagged ships can move cargo between U.S. ports. The problem is, no such liquefied natural gas carriers exist.
Examples of too much supply in gas-producing regions and too little of it reaching the gas-consuming coast are economically painful.
Next-day natural gas prices at the Waha hub in the Permian Basin in West Texas tumbled to their lowest on record Nov. 27 because of limits on the amount of gas that could move out of the region by pipeline, Reuters reported. Prices fell to an average of 25 cents per million Btu that day. Even worse than a measly quarter, traders said small amounts of fuel were sold at negative prices as producers struggled to get rid of their gas.
That compares to the U.S. benchmark price at Henry Hub, Louisiana, which averaged about $4 per million Btu in November.
The Permian is the biggest oil-producing shale basin in the country, and because gas is associated with much of the oil coming out of the ground, it is also the nation’s second-biggest shale gas region, behind Appalachia. Permian drillers want the oil, which is much more valuable than gas, so they deal with the gas as best they can.
New pipelines are being built or planned to move Permian gas production to the Gulf Coast, where a growing number of liquefaction plants can turn it into LNG for export, and to Mexico, which needs U.S. gas to cover its own production shortfall. But until the new lines are up and running, West Texas producers will have to take what they can get.
The imbalance is just as noticeable in Canada, where last May 3 spot prices at Alberta’s AECO pricing hub closed at just 5 cents per million Btu, about $2.50 less than the U.S. benchmark price that day.
Then in October, gas prices in Western Canada went into a freefall as a ruptured pipeline limited producers’ ability to get their gas to market. With one less conduit to move Canadian gas to customers south of the border, spot prices at Alberta’s AECO trading hub fell to 8 cents per million Btu on Oct. 19.
At the other end of the price spectrum in November, gas prices at the New England trading hub rose to $13.70 per million Btu for Nov. 21, about triple the year-to-date average, Reuters reported.
And when gas costs more, so does electricity. Next-day power prices in New England on Nov. 21 were about four times the national average.
When winter hits New England, power and gas prices can spike quickly because most consumers use gas to heat their homes and businesses, and most of the region’s electricity usually comes from gas-fired power plants.
Companies have tried to build more pipelines to bring gas from the Marcellus shale basin in Pennsylvania and other plays, but they have encountered objections from residents in Virginia, Massachusetts and New York, and denials of state permits in New York.
Pipeline developers, however, are not giving up. Calgary-based operator Enbridge will continue to push federal, state and local regulators to allow new gas pipelines that could serve New England with production from nearby Appalachian basins, CEO Al Monaco said Feb. 15.
“It’s never been more clear that we need additional gas infrastructure and nowhere is that more evident than in the U.S. Northeast,” Monaco said during a conference call with analysts to discuss fourth-quarter financial results.
“This is actually an unbelievable irony when the Marcellus is sitting right next door to this market,” Monaco said.
The LNG story in New England is just as ironic.
The U.S. shale boom keeps breaking records, producing more gas than the country needs and triggering billions of dollars of investments in export terminals. LNG carriers are leaving the docks for Europe, South America, Asia, even Canada this month. But without a U.S.-flagged LNG carrier, there is no way to move affordable Gulf Coast LNG to the East Coast.
Instead, New England has to import LNG from overseas to meet peak winter demand. The LNG import terminal in Boston harbor received about 24 cargoes in 2018, with all but one coming from Trinidad and Tobago. The other cargo was Russian LNG. Dominion Energy’s Cove Point, Md., terminal took in a Nigerian cargo in December 2018.
And then this month, a load of U.S. gas left the dock at Cheniere Energy’s export terminal in Sabine Pass, La., headed to the Canaport LNG import terminal in New Brunswick. It was the first delivery of U.S. LNG to Canada, where the Atlantic seaboard provinces have become a customer for U.S. gas to replace domestic supplies since the Sable Offshore Energy Project ceased production in December 2018 after 19 years of serving the region.
The Canadian Maritimes “will transform from being an exporter of domestic gas to being an importer of gas from the U.S.,” said Canada’s National Energy Board. Before the U.S. cargo, Canaport received six LNG deliveries in 2018 from Trinidad, Norway and elsewhere. And like New England, there is not enough pipeline capacity to move prolific supplies of U.S. shale gas or Western Canadian gas into the Maritimes.
Which means high prices for consumers. Maritimes’ consumers already pay the highest average residential gas bills in Canada, according to the National Energy Board, with bills averaging $160 a month, roughly double British Columbia, Alberta and Saskatchewan.
Larry Persily is a former Alaska journalist, state and federal official who has long tracked oil and gas markets and projects worldwide.