It is a good time to be an LNG buyer on the global market.
Long-term contracts with Asian buyers — the prospective market for the Alaska LNG Project — are almost exclusively tied to the price of oil through an energy equivalent formula.
While a flooded oil market has helped liquefied natural gas buyers dependant on its price, there is simply a lot of LNG right now, too.
“Today’s global LNG market is dreadful,” Kenai Peninsula Borough Oil and Gas Special Assistant Larry Persily said in an interview. “It’s just like oil; it’s way oversupplied.”
Persily served as the federal pipeline coordinator for Alaska natural gas projects before joining the borough.
In just a few years, delivered LNG prices in Asian markets has gone from nearly $20 per million British thermal units, or mmbtu, to less than half that. Japanese and Korean LNG buyers were paying $14.95 per mmbtu in May 2013; by last June, those prices were down to $7.25, according to the Federal Energy Regulatory Commission. In China, it was a little cheaper, at $7.10 per mmbtu on average.
The cause for the current bloated market is fairly simple: high demand for natural gas several years ago pushed producers worldwide to develop LNG projects. The 2011 Japan earthquake and subsequent Fukushima nuclear disaster drove the country to shut down its nuclear energy program, forcing utilities to buy LNG for electricity production, further straining the market and driving prices up.
Domestically, shale gas production exploded at roughly the same time and turned some Gulf Coast LNG import terminals into export facilities.
Most analysts expect it to remain an LNG buyers’ market for several years, along the same lines as oil, Persily said, but the value of those projections are always up for debate.
Eiji Hashio, a Tokyo-based vice president of Resources Energy Inc., said Japan is now buying about 90 million tons of LNG per year and about a quarter of that is on the spot market rather than long-term contracts.
Japan is viewed as a primary market in Asia for Alaska LNG. The country accounts for about 35 percent of the global LNG market, which stood at more than 240 million tons in 2014, according to the International Gas Union. Worldwide demand grew about 2 percent last year.
Combined, Japan and South Korea demand almost exactly half the world LNG market.
Resources Energy Inc. is an Alaskan-Japanese consortium looking to develop a smaller Cook Inlet LNG export project.
In July, the Japan Economy, Trade and Industry Ministry set a goal to resume nuclear power generation and increase renewable energy use — to the point where nuclear power meets 20 percent of the country’s electric demand by 2030 and renewable energy supplies another 20 percent.
Eiji said “industry is very suspect of those targets,” because the nuclear target would require restart of more than 30 of the country’s 43 reactors, many of which are aging facilities. Japan produced no nuclear power in 2014.
Still, he said the spot LNG market in Japan would likely diminish by 2020 as some nuclear power is brought back online.
Today about 35 percent of LNG is traded on the spot market, according to Damian Bilbao, BP’s business development director for the Alaska LNG Project, the $45 billion-plus North Slope LNG export proposal that partners the State of Alaska with BP, ConocoPhillips and ExxonMobil, the gas suppliers for the project.
Also in about 2020, many legacy contracts Japanese utilities have with gas suppliers will be expiring and a push towards decoupling LNG prices from oil will be emphasized, as will efforts to mirror the Henry Hub gas market of North America, Persily and Eiji said.
Doing so would hopefully relieve LNG buyers from the volatility of the markets, according to Eiji.
“The days of, ‘I’ll pay you whatever oil is with an energy equivalent factor; just send me the bill;’ those days are over,” Persily said.
Linking to Henry Hub — at least these days — would also mean very low LNG prices. Henry Hub natural gas was up 13 cents from the day prior Nov. 16, at $2.14 per mmbtu.
The prime advantage for Alaska LNG over Gulf of Mexico produced LNG is shipping. Tankers heading out of the Gulf must first go south through the Panama Canal and then traverse the entirety of the Pacific, adding days and “a couple bucks” per mmbtu to the final price of Henry Hub-linked Gulf LNG, Persily said.
Eiji also noted that not all contracts will be structured the same, even amongst a single portfolio. Buyers want a blend of LNG sources, which leads to a blend of pricing.
“What we would like to do is just cost-plus reasonable margin for the producers and developers,” he said simply.
More LNG supply is also being developed in Australia. Persily said three export projects began production within the last year and another three are in construction. In total, the new LNG projects down under should add about 10 billion cubic feet, or bcf, of natural gas to the market per day, he said.
Pegged at 20 million tons of LNG per annum, the Alaska LNG Project would add about 3 bcf per day to the world market over its 25-year initial design life.
At 90 million tons per year, Japan’s LNG demand roughly equates to 13.5 bcf of natural gas per day.
Worldwide capacity is expected to increase by about 50 percent over the next three years, Bilbao said.
Where does all that leave the Alaska LNG Project, hoping to move first gas around 2025?
Persily called today’s LNG market a “war of attrition” for export projects, which has likely helped Alaska with less feasible projects in British Columbia, Africa and other places falling out of sight.
The work going on in Australia is not in competition with Alaska because those projects are further along and already have sale and purchase agreements in place, Persily noted.
“After the dust settles later this decade, when hopefully the market begins to recover, the stronger projects will still be in the running. That’s the hope,” he said.
A report from the Department of Natural Resources consultant firm Black and Veatch estimated the AK LNG midstream costs alone at $7.30 per mmbtu.
Today’s global LNG prices simply aren’t workable for the Alaska LNG Project, but they don’t have to be, Black and Veatch consulting director Deepa Poduval said.
On its current schedule, the Alaska LNG Project won’t be in production for another 10 years and hopes are to keep the pipeline full of gas for another 25 years at minimum after that.
“You’re looking at a 50-year time horizon and you can’t make that decision based on a five-year forecast in prices,” Poduval said.
Realistically, there isn’t a specific price that makes the project feasible from the state’s perspective, according to Poduval. The state’s benefit will not only come from the sale of its gas, but also from corporate income taxes and property tax revenue, among other sources.
The Revenue Department announced in September that the producers had agreed to pay $15.7 billion to the state and local governments in PILT, or payments in-lieu of taxes, relating to the Alaska LNG Project.
Those payments would be made over the operating life of the project.
As a result, the state’s requirement for gas revenue is almost certainly well below what the producers will need, Poduval said. And among the three, varying financial positions will undoubtedly leave them with different perspectives as to what is a favorable project and LNG market.
Among the biggest variables is the capital cost of the project. Current cost projections between $45 billion and $65 billion leave a capital swing of more than 40 percent. Next comes project financing.
“What you probably need is (an LNG) price basis that works for the least common denominator. In effect it represents a level where everyone is basically happy — some are fairly happy, others are quite happy, but at that point where everyone believes uniformly that the project can be economical,” Poduval said.
Even with a push in Japan and other markets to separate natural gas prices from oil, the fortunes of the Alaska LNG Project will still lie somewhat in the value of crude. Higher oil prices will improve the health of the producers’ financials, if nothing else.
“I would think somewhere in the $70 (per barrel of oil) threshold would be important for our project,” Poduval said. “It probably needs to be higher than that to be confident for everyone and it will depend on the different pieces coming together.”
The producers will not be too worried with the LNG market and how it impacts the Alaska LNG Project for several years, according to statements from ExxonMobil and ConocoPhillips. Purchase and sales agreements will be negotiated during the front-end engineering and design, or FEED, process, which should begin late next year and continue for several years, based on the current project timeline.
ExxonMobil spokeswoman Kim Jordan wrote in a statement that the company expects LNG imports to Asia Pacific countries to grow by 60 percent by 2025, which could well position the Alaska LNG Project.
BP’s Bilbao said China, which hasn’t historically been an LNG player, will continue to grow its demand.
He also said that the current market gives the Alaska project partners an opportunity to drive down capital costs and continue to improve the project’s financials.
The fact that three of the world’s largest, reliable oil and gas producers are partnering with the State of Alaska is a major benefit to the project and can’t be ignored by potential customers looking for national energy security through LNG contracts, according to Bilbao.
When looking for buyers, LNG marketers want to “brand” their projects, he said, and Alaska LNG has credibility through its participants.
“You want buyers in the market looking to transact with your project,” Bilbao said.
Elwood Brehmer can be reached at [email protected]