While most now expect liquefaction and export of natural gas from North America to happen, how much will be sent abroad and what it will mean for global markets and gas-oil price indexation are unclear.
Liquefied natural gas (LNG) exports from the United States will be too little to bend global gas markets away from oil price indexation, and a shale gas revolution abroad is too far off to decouple natural gas and oil prices in other parts of the world, Bernstein Research Senior Analyst Neil Beveridge said in a recent note. However, markets in Asia are getting restless with high prices, and in the United States there is wide disagreement among pundits about how much LNG eventually will be exported.
“In our view there is little to no chance of any change in the current pricing structure for international pipeline gas or LNG [liquefied natural gas],” Beveridge said. “To the relief of the LNG industry and investors in LNG producers, oil-linked pricing is here to stay. There is no such thing as a global gas market — and we think there is unlikely there will ever be in the next 20 years.” The bounty of natural gas being thrown off by shale plays in the United States will have “a far greater impact” on the domestic gas market than global markets, Beveridge said.
U.S. gas demand is about 67 Bcf/d, and shales produce about 25 Bcf/d, or about 35% of total North American supply. Assuming half of the 90 million metric tons per year of LNG export capacity proposed for the Lower 48 states is built, export capacity would be 40-50 million metric tons per year, or about 6 Bcf/d by 2020.
Global trade in oil-indexed natural gas should be about 90 Bcf/d by 2020, Beveridge said, which would mean 2020 exports from the United States would be less than 7% of the oil-indexed gas market.
“This is too small to move the needle in the context of the global trade in oil-indexed gas,” Beveridge said. “To be meaningful, U.S. Lower 48 LNG exports would have to exceed 150 [million metric tons per year] to make a fundamental difference to global pricing of LNG. Given that this volume of exports would push U.S. domestic gas prices towards international levels, we see this as an unlikely scenario.”
However, LNG customers in Asian markets are growing increasingly dissatisfied with the high prices they must pay for LNG, particularly when natural gas in the United States sells for so much less. Importers Japan and India recently launched a project to research global LNG pricing. The energy-hungry countries pay far more than Henry Hub prices for their imported gas because their supply contracts are linked to oil prices, and they said recently that they would like alternative pricing structures.
Last month, Japan’s Ministry of Economy, Trade and Industry (METI) and the Asia Pacific Energy Research Centre held the Liquefied Natural Gas Producer-Consumer Conference in Tokyo. It was the first global conference in the field where people from the public and private sectors assembled from both the producer and consumer sides, according to METI. “For Japan, it is important not only to ensure a stable supply of LNG but also to procure it at low cost,” said Japan Minster of Economy, Trade and Industry Yukio Edano, according to a summary of the meeting published by METI on its website. “It is a challenge to consider a new pricing system to replace the current system of linking the gas price to the crude oil price (gas-oil price link), which has lost its rationality, with one that will be beneficial for both producers and consumers.”
At the meeting representative of Tokyo Gas complained about the high prices Japan must pay for supply and called for alternatives. “LNG prices for Japanese users are deviating far from the international standard because of the gas-oil link,” the meeting summary said. “If the deviation continues, gas consumption will be curbed and a shift to other energy sources will proceed. Therefore, by introducing the Henry Hub pricing and a link to the European gas price, Tokyo Gas aims to bring LNG prices in East Asia to the international standard. Moreover, upstream development is necessary from the perspective of stable supply, and support by the Japanese government is also very important.”
However, new LNG production projects need to be supported by contracts with oil-linked pricing for their economics to work, Beveridge said. “The expansion of gas projects in Australia would not have been possible without the direct linkage between oil and gas prices given the high cost inflation and the increase in project costs to US$3,500-4,000/ton,” he said. “At these prices, operators need a real LNG price of US$12-14/Mcf (FOB) to generate a marginal return on investment.”
A typical LNG contract has a slope of 0.12-0.14 times oil price, so the LNG industry needs $100 oil to make projects work, Beveridge said. The labor and supply constraints seen in Australia also will bedevil western Canadian export projects, which will compete with the Alberta oilsands for workers and equipment, he said. East Africa developments will require “enormous new infrastructure investments.”
In Alaska, where a commitment to develop LNG exports was just made by producers (see NGI, Oct. 8), a proposed $65 billion project would need to fetch the same kind of prices for its output as Australian projects in order for it to work, Beveridge said.
“So although buyers may have more choice as to where the gas comes from, the oil link with LNG is still needed for projects to get commercially developed,” he said.
In January Cheniere Energy Partners LP’s Sabine Pass Liquefaction LLC signed a sale and purchase agreement with Korea Gas Corp. that indexed prices to Henry Hub (see NGI, Feb. 6). This, apparently, has thrown a wrench into some LNG contract talks elsewhere. At a recent Calgary energy conference, Apache Corp. Vice President David Calvert, manager of the company’s Kitimat, BC, LNG joint venture, said projects such as Kitimat need long-term contracts based on oil prices.
“It [the Cheniere-Kogas contract] created quite a ripple through the marketplace,” Calvert said, adding that the deal caused “unrealistic expectations,” as reported by Bloomberg.
Without development of an active spot market in Asia — an unlikely event — LNG projects will need long-term contracts to get built, Beveridge said, but suppliers will resist Henry Hub pricing since U.S. exports will play such a small role in the global gas market. “Although we expect the U.S. to export some LNG, it will not be of sufficient volume to enable buyers to walk away from existing [oil-indexed] contracts,” Beveridge said.
Not everyone believes in the long-term survival of oil-indexed pricing for gas abroad. Rice University’s Ken Medlock, a Baker Institute energy fellow, recently told NGI that linking U.S. gas markets with the world will cause Asian and European market players to take gas storage positions in the United States “because what you have when you have both import and export capability in the U.S. is a direct link to all the storage we have in this country,” Medlock said (see NGI, Aug. 13).
But that won’t happen anytime soon, Medlock allowed, citing the need for development of continental pipeline systems abroad, particularly in China, an argument also made by Beveridge. While Beveridge figures on 6 Bcf/d of exports from the Lower 48 by 2020 and Medlock sees far less, there are yet more opinions on eventual exports.
A decade from now, North American (Canada, Alaska and Lower 48) exports will be about 10 Bcf/d, according to the base case of an analysis released last week by LCI Energy Insight and Energy Ventures Analysis (EVA). However, they said if this is to happen, North American LNG projects will need to capture about 60% of the Asian market’s uncontracted LNG demand.
“Obtaining this market share will be a tall order in light of the intense competition among a host of proposed global liquefaction projects that are earmarked to serve the Pacific Basin,” the firms said in their report. “…[T]he potential uncontracted LNG supply earmarked for the Pacific Basin exceeds uncontracted Asian demand by about 12 Bcf/d, which implies that some of these projects will be either delayed or canceled. Furthermore, unlike the proposed Lower 48 liquefaction projects, all of the other competing liquefaction projects have dedicated gas reserves.”
The 10 Bcf/d in 10 years projection is higher than Beveridge’s and Medlock’s estimates, as well as a projection from Bentek Energy LLC, which recently said exports from the United States could reach as high as 5.4 Bcf/d by 2020, and another 1.4 Bcf/d could be exported from Canada. LCI-EVA said the two key uncertainties in their outlook are the question of whether/when the U.S. Department of Energy (DOE) will issue more permits for export to non-free trade agreement (FTA) countries (see NGI, Oct. 1); and how global competition for LNG market share in the Pacific Basin evolves.
The analysts reviewed 24 proposed North American LNG export projects, totaling more than 32 Bcf/d of capacity, by their tally. These include 17 projects proposed for the Lower 48 with combined capacity of 23.3 Bcf/d. The Lower 48 projects consist of eight brownfields, with combined capacity of 12.6 Bcf/d; four greenfields, with combined capacity of 6.7 Bcf/d; three offshore projects, with combined capacity of 3.9 Bcf/d; and two “special” small-scale projects, with capacity of 0.1 Bcf/d.
There also are 20 proposed liquefaction projects with combined capacity of 25.2 Bcf/d elsewhere in the world that are competing for the same market share, the analysts said. In about 2016 it is expected that North America will start to export LNG with the startup of the first phase of Cheniere Energy Inc.’s Sabine Pass (1.3 Bcf/d) and the Kitimat LNG (1.3 Bcf/d) projects, according to the analysts.
Cheniere Energy’s Sabine Pass project is the first and only Lower 48 export development to have received DOE authorization to export to non-FTA countries. The project, for which construction is under way, has left its competitors behind while they wait for DOE to decide whether more exports to non-FTA countries would be in the public interest. This first-mover advantage is significant, the LCI-EVA analysts said. “Probably the most significant competitive advantage is being a first mover,” they said, “and despite any extenuating circumstances, securing long-term offtake agreements.”
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