For the second time in four decades, the U.S. LNG industry is being shaken by new technology.
Once again the need for liquefied natural gas imports is being questioned and equity analysts at Pritchard Capital are going step further to say North America will become an LNG exporter.
Forecasting “natural gas prices in Asia may remain higher than in North America,” Pritchard analyst Ray Deacon said “the ultimate destination of LNG coming from the Middle East is Asia and not the U.S.”
Noting the progress in developing an LNG export facility at Kitimat in northwestern British Columbia, also attracted by Asian gas demand, Deacon projected: “We end up exporting natural gas as LNG from North America, as it seems unlikely North America will be a major import destination for LNG.”
Beyond Kitimat, the analyst said, “Chesapeake (Energy Corp.) has hired Citi Bank to look at LNG export” possibilities.
Questions about future U.S. natural gas supplies in the late 1960s resulted in creation of an LNG import industry with construction of a terminal in Everett, Massachusetts, which received its first LNG shipment in November 1971.
The next year, the Elba Island, Georgia, terminal was authorized. It went into operation in the late 1970s along with a third terminal at Cove Point, Maryland. In 1980, the Federal Energy Regulatory Commission Web site says, deliveries to Elba Island and Cove Point were suspended due to the high cost of LNG.
The cost, as always, was relative. In this case it was relative to the dropping price of domestic natural gas as improved drilling technology tapped large gas reserves and produced a “gas bubble” of excess supply that lasted through most of the 1980s.
No one is predicting a gas bubble for the second decade of the 21st century, but Joe Benneche, a naturally gas analyst at the U.S. Energy Information Administration believes “there certainly is a possibility in the short term” as a result of reduced demand in a slow economy and the increase in gas production from shale.
Technology advances in producing natural gas from shale formations have added a different dynamic to the whole situation, the EIA economist pointed out.
“It is a great game changer,” according to the American Gas Association’s Managing Directory of Policy Analysis, Chris McGill.
Based on the advances in technology, he said, the estimated reserves in the U.S. “have grown by 50 percent since 1990” and now total 100 years of supply.
Pointing out “the gas saturated rock is the real deal,” the AGA analyst said the ability to produce gas trapped in shale has reduced the exploration risk because the locations of North America’s shale deposits are well known.
This allows investment to be focused on production technology in what has been likened to a manufacturing process, McGill added.
Pritchard’s Deacon said he estimates the various North American shale reserves will be profitable at gas prices of $3.50 to $5 per thousand cubic feet (Mcf), adding the exploration and production “industry is not going to have much problem growing their production with gas priced at $5 (an Mcf).”
Stating the “consistent thing” about the latest forecasts is strong supply, McGill said the question is demand.
“What will be the new demand structure?” he asked, wondering what will happen to gas supplies if climate change legislation is adopted calling for natural gas to take over a significant power generation load in as little as five years.
For Deacon, the questions are economic. When will industrial demand return? And, will Canada’s oil sands be economical to develop?
"People are forgetting that (development of the oil sands will require) one to two billion cubic feet per day of natural gas,” Deacon said.
“The significantly increased potential for producing gas … makes us 1) less in need of additional LNG, and 2) tends to lower our market price and makes us a less desirable market to sell into,” was Benneche’s conclusion.
“Whether or not North America will start exporting to any great extent is a much more difficult -- and potentially politically involved -- question that I will generally stay away from for now, he continued, noting “it is obviously a possibility.”
For analyst Deacon “the only way to be positive on LNG is to say the credit system will not finance” the pipelines needed to deliver the new gas supplies to market.
One credit analyst who no longer covers the world natural gas markets describes the supply changes “are a paradigm shift” in the markets and predicts the result will be more debt restructuring by developers of the LNG import terminals now in operation.
Such efforts were used in 2008 by Cheniere Energy when the opening of its Sabine Pass LNG Terminal on the Texas/Louisiana border was not greeted with the expected number of cargoes, IPAA Economics Vice President Fred Lawrence pointed out.
Presently North America is using only 10 percent of its LNG import capacity, AGA’s McGill pointed out.
There will continue to be regional needs for North American LNG imports because of problems with the pipeline infrastructure, EIA’s Benneche said, citing the first U.S. import terminal at Everett, Massachusetts.
Built to provide supply security for the Boston metropolitan area which was then at the end of the U.S. pipeline network, the terminal was the only one in the U.S. to operate throughout the 1980s and 1990s.
Many of the infrastructure problems supporting the Everett terminal continue to exist despite the construction of the Maritimes & Northeast Pipeline delivering Sable Island gas to the U.S. Northeast.
That pipeline itself has needed gas from the Canaport LNG Terminal in St. John, New Brunswick, in 2009 while the Sable Island production facilities were repaired.
Benneche sees the need for some regional terminals to provide the security of supply flexibility, but has no suggestions how such infrastructure will be financed.
As for the LNG terminals now in the regulatory approval process, Deacon is “pretty skeptical” about any of them being built.
In Oregon, where three terminals have been proposed, Avista Utilities has asked state regulators for permission to cut rates more than 20 percent effective November 1 to reflect a drop in the price of natural gas.