To Market, To Market

Head north out of Kenai, Alaska, on the Kenai Spur Highway and spectacular scenery glows around you on a sunny autumn day.

Cook Inlet lies to your left, and it’s not uncommon to see the towering Redoubt volcano across the way puffing a steam cloud. The big mountain’s snow-capped beauty gets lost on locals, who painfully remember when the mountain exploded 30 years ago, coating the Kenai Peninsula in thick ash. The stuff was so fine it could pass through automobile air filters, and not a few engines suffered the consequences. The mountain grumbled again in 2009.

To the right lies the forest primeval. Oh, watch for moose trotting along the road, especially at twilight.

But the breathtaking scenery breaks into something resembling the very industrial Houston Ship Channel as the highway enters the settlement of Nikiski—a fertilizer and cogeneration operation, ship docks and a refinery. Between them lies an unusual looking plant with three large, white and fully insulated tanks.

Quiet nowadays, this is the Kenai LNG plant, the nation’s first stab at liquefied natural gas (LNG) exports, built to supply Japanese customers. This was the largest gas liquefaction plant in the world, with a capacity of 200 million cubic feet per day, when a Phillips Petroleum Co. and Marathon Petroleum Corp. joint venture opened the plant 50 years ago. That ranks smallish by today’s standards.

Then and now

By comparison, Cheniere Energy’s Sabine Pass plant in Cameron Parish, La., can process 4 billion cubic feet per day (Bcf/d).

Plant operations ended in 2015 as gas reserves trailed off in the Cook Inlet fields that feed it. Alaska’s citizens want to keep the remaining gas to serve Anchorage.

Oddly, Marathon Petroleum, which now owns the plant outright, as well as the nearby refinery that it gained in its 2018 purchase of Tesoro Corp., has explored converting the plant to an import facility to provide gas to fuel the refinery’s operations.

But if this corner of Alaska’s gas business remains quiet, the rest of the world’s gas business is booming, and the U.S. will become a much-larger player.

Kinder Morgan Inc. projected in a second-quarter investor presentation that U.S. LNG imports will rise from 3 Bcf/d in 2018—3.4% of domestic gas demand—to 17 Bcf/d in 2030—14.3% of domestic demand.

Kinder Morgan, No. 3 on the Midstream Business Midstream 50 list of the sector’s biggest publicly held players, will watch the trend closely. The presentation noted that 40% of all U.S. gas moves through one of Kinder Morgan’s own pipelines. The corporation also is developing the Elba Island LNG plant near Savannah, Ga.

Worldwide demand for natural gas grew 4.6% in 2018, its fastest annual pace since 2010, according to the International Energy Agency’s (IEA) Gas 2019 report. Gas accounted for almost half the increase in primary energy consumption for all fuels, according to the IEA.

Rising demand

And that gas-heavy trend likely will accelerate, the IEA predicted. Gas demand is expected to rise by more than 10% over the next five years.

“Supplies to meet growing global demand for natural gas will come from both new domestic production in fast-growing economies but also increasingly from major exporting countries, led by the development of abundant shale gas resources in the United States,” the IEA said in its summary of the report. “The strong growth in LNG export capacity will enable international trade to play a growing role in the development of natural gas markets as they move towards greater globalization.”

The IEA said the U.S. will be the world’s largest exporter of LNG by 2024, jumping past Australia and Qatar, shipping 100 billion cubic meters (3.5 trillion cubic feet) per year. That’s estimated to be one-eighth or more of all the gas the nation produces annually.

The whole LNG market will change radically in the next few years, S&P Platts said in a third-quarter report entitled New Horizons: The Forces Shaping the Future of the LNG Market.

“Growing, flexible U.S. volumes and new supplies from Qatar, Russia and emerging producers will open up new LNG trade flows and reinforce global interconnectivity in the 2020s, reducing overall voyage lengths, lowering delivery costs and creating fertile ground for the development of spot and risk markets,” the report said. “But there are conflicting forces: Just as LNG occupies a more central role in national energy and economic strategies, it has also become increasingly exposed to trade battles that could fragment trade flows.”

The long-term, point-to-point deals between one LNG producer and one LNG customer will disappear. Liquefied gas will become more likes its crude oil cousin—an actively traded commodity—with spot market and rapidly changing deals. That will help draw in new players at both ends of the market, who have sat on the sidelines, given the extravagant costs of both liquefaction and gasification.

Where to?

Where will those growing gas markets be? There will be significant shuffling in the LNG customer mix but the one to watch will be China, Brian Bradshaw, partner with Sidley Austin, told Midstream Business.

The IEA noted that, in addition to a new export leader—the U.S.—there will be a new top importer: China.

Wells Fargo noted in a recent analysts’ report on LNG that, in the first three years since the start-up of Cheniere Energy’s Sabine Pass liquefaction plant in Cameron Parish, La., South Korea has received the most tankers loaded with U.S.-produced LNG. But industry observers point to South Korea’s neighbor as the big—and getting bigger—LNG buyer.

“China’s going to be the largest buyer of LNG,” Bradshaw said. The Asian giant faces significant air pollution problems, and LNG represents one answer to that challenge.

“Yianjing, China, is on the coast, and they have a huge industrial park there,” he cited as an example. “All of the coal-fired power plants have to be converted [to gas]. Just the amount of coal-fired power plants that need to be converted is very significant,” over and above any prospective for China’s industrial growth.

One challenge China and its LNG suppliers face is the limited number of Chinese LNG import players—and their limited landing infrastructure, he added.

“The biggest problem China has right now that is the regasification facilities are, even though owned more broadly, all in the hands of just a few companies,” Bradshaw said. It’s unclear how your LNG is going to be landed in China. You have to be talking to someone who has real access to the capacity.

“But they have to convert,” he explained, referring to the major air pollution problems in large Chinese cities. “If you spend any time in Beijing, you can appreciate the need to diversify from the coal-fired power plants. It’s going to happen; it has to happen.

“It’s just if the LNG will be coming from us or will it be coming out of Qatar or Australia? We have to decide where the United States ranks in the list of suppliers.”

China takes the lead

Moody’s Investor Service projected the same trend for the Chinese market in an investor report published as the third quarter began.

“Natural gas demand is likely to grow in all regions worldwide, led by China, which is likely to account for over 40% of global demand growth through 2035—largely for environmental reasons,” it said. “Chinese demand developments will increasingly dominate the price signals for traded natural gas markets globally.”

Greg Haas, director of integrated oil and gas for Stratas Advisors, agrees that China will be the key LNG market. He added a challenge: The rumbling trade war between the U.S. and the Asian power.

“First and foremost, hopefully this trade war with China gets rectified amicably,” Haas told Midstream Business. “From the perspective of LNG, that is probably the number-one market on the planet for growth of metric tons of LNG.” The trade dispute, “I think for the rest of this year it might be a little bit of a problem, but hopefully by 2020, and then for 2021 through 2023, we’ll see a more normalized view towards U.S. LNG exports, because we’ll certainly have the capacity to help to fulfill their needs.”

Bradshaw said South America represents another emerging market for U.S. LNG, a region where Gulf Coast plants enjoy an advantage due to comparatively short voyages relative to other suppliers in the Middle East or Australia.

Coals to Newcastle

There are other potential new LNG markets out there, including some surprises. In a classic coals-to-Newcastle deal, Saudi Arabia’s Saudi Aramco signed a 20-year agreement to buy 5 million metric tons per annum (mtpa) from a Sempra Energy plant now under construction at Port Arthur, Texas, and also will take a 25% equity stake in the first phase of the project.

The deal will allow Aramco to build on its plans to become a major player in global LNG trade. The firm also plans to significantly expand its own gas production, including recent offshore discoveries in the Red Sea.

Also, the kingdom needs gas to meet soaring domestic consumption, Ahmad AlSa'adi, senior vice president of technical services at Saudi Aramco, said in a recent interview.

Elsewhere, “I think India will continue to be a buyer, and that will become the second-largest market” after China. “I think Japan will likely be a good market as well as South Korea,” Haas said.

But India, like China, has infrastructure challenges. A recent article in LNG Condensed noted, “While the government is pushing its city gas program hard, protracted delay is the norm rather than the exception, casting doubt on the rapidity with which Indian LNG demand can grow.”

The Wells Fargo analysis noted that President Trump and Vietnam’s Prime Minister, Nguyen Xuan Phuc, issued a statement following the June G20 economic summit in Osaka, Japan, that the two countries intend to negotiate an LNG sales agreement. Vietnam has announced plans to build its first regasification terminal in a deal with South Korea’s Samsung. Vietnam also has deals in the works for Russian LNG coming from Siberia.

Europe

Western Europe represents a significant LNG market, given the region’s developed economies, environmental concerns and declining North Sea production. Renewables, thanks to a strong environmental movement, likely will provide a significant share of European power and heating needs.

“With extensive regasification and storage capacity, flexible demand and liquid trading options, Europe is steadily cementing a key role in the global LNG market. It is emerging not only as a global balancer, but also as a demand center in its own right, price anchor, and ‘put option’ due to its ability to efficiently redirect cargoes or absorb surplus volumes in times of oversupply, a market condition that is likely to reappear in the mid-2020s,” the Platts report said.

That’s good news for LNG exports, according to Moody’s.

“Natural gas exports to Europe are likely to keep growing as it pursues carbon-reduction efforts, as its indigenous sources of supply diminish, and as its dependence on Russia raises energy security concerns,” its report said.

“There was a big push to get renewables, but you can’t run an entire economy off renewables,” Bradshaw said. “There’s too much variability if the sun doesn’t shine or the wind doesn’t blow. You still have to have some sort of carbon-footprint power plant, and gas-fired is the best thing going.”

The Atlantic Basin has a well-developed LNG market with two pricing points, in the Netherlands and U.K. But those positives are offset in great part by Russia.

Russia’s pipes

“Russia can turn on their pipelines and bring as much gas as they want in, coming across Europe, and that really drives the price down,” Bradshaw said, “although there is the very real threat that Russia can jack up prices—or shut in pipeline flows—on a moment’s notice.”

U.S. LNG exports could get a boost if President Trump follows through on potential sanctions imposed on the Nord Stream 2 pipeline project between Russia and Germany. There’s divided opinion in Europe on the project, with some—particularly the Nordic and Baltic countries—concerned that it would increase the continent’s already heavy dependence on Russian gas. But the project enjoys considerable support in Germany, which is seeking stable gas supplies.

“It’s all geo-political. People are concerned with what would Russia can do, what is China going to do and what’s the United States going to do? All of those things impact how ultimately it plays out,” he added. “If you’re a local distribution company or you have a gas-to-power project you’re trying to do in Brazil, you’re still getting swept up into what’s the first market and what it’s going to go to, what’s the second market, and how pricing works in those markets because that’s going to really push how pricing’s going to work in your market as a secondary or tertiary market for the big off-takes.”

It’s complicated

Who buys from whom is a complex business, Bradshaw explained.

“The biggest problem with all of this is you can’t talk about just one issue because it involves a whole cluster of issues. If one of the things changes, it impacts everything, so how you price depends on will it go to, say, Europe? If it’s going to Europe, that’s going to make the prices go higher in Asia,” he said. “Fundamentally, there are still the Atlantic Basin and the Pacific Basin, and they’re priced differently, and they work differently.

The world’s two major canals, the Suez and Panama, serve as pricing points due to the limits they place on tanker size.

“This has affected trade for the last thousand years,” he added. “If you have to go all the way around South America or Africa, you’ve got a long, long haul. It means you price things differently. People don’t like to do that.”

Profitability

Liquefaction plants, tankers and terminals represent big, multi-billion dollar investments and there has to be a return on investment for the firms building and operating them. That is a major concern right now—wherever the customers may be.

“Another thing that’s limiting current exports, or penetration around the planet’s market places, is the potential for negative netback,” Haas cautioned. “That means by the time you buy the gas, liquefy the gas, load it up in a ship, move that ship across the seas to wherever the buyer is, and then regasify it, then move it to end place markets, the netback to the selling entity in the U.S. is in many cases negative these days.

“It’s a money-losing proposition to go very far these days with a lot of natural gas—especially for the stock market [investors],” he added.

Tellurian Inc. rated its cryo-spread—calculated by subtracting the NYMEX Henry Hub price from the premium LNG netback to the U.S. Gulf Coast—at a thin 97 cents per million British thermal units (MMBtu) for August contracts.

All of this tends to make European markets the more likely customers for U.S. plants, given the comparatively shorter tanker sailings across the Atlantic.

“But I’m even hearing negative netbacks are starting to pop up in Europe from the U.S.,” Haas said. Russia plays a big role in the market for both economic and political reasons.

“I have not tracked globally that [Russian] dynamic, but it would make sense, to the extent that Russia has the capacity with its pipelines and the capacity of send out its gas production,” he added. “It makes sense that they would try and block the U.S. importations of the LNG into their home territory, where up until recent years they have been dominant and expected to be the dominant provider of natural gas for this century.”

LNG exports represent a significant slice of the overall U.S. gas business by now—and it promises to get bigger. In July, Cheniere Energy announced the first cargo from Train 2 of its new Corpus Christi, Texas, plant. The operation’s Train 1 shipped its first LNG at yearend 2018. Train 3 is scheduled to start making cold in 2021.

Corpus Christi’s three plants will have a capacity of 13.5 mtpa. Eventually, the plant could be enlarged to make 23 mtpa. That’s a lot of gas—and just one of several plants under construction in the U.S. They will add to LNG coming out of Cheniere’s Sabine Pass operation and Dominion’s Cove Point, Md., plant on Chesapeake Bay that takes a big chunk of Marcellus and Utica gas production.

The ripple effect

But there could be a ripple effect in the oil and gas industry if LNG sales prices go—and stay—negative. Haas noted there’s already a slowdown in the construction and start-up of new LNG capacity. Meanwhile, Wells Fargo noted third-quarter LNG tanker rates averaged $56,000/day. That’s up from as low as $42,000/day in the first quarter but well below peaks around $75,000/day last year.

“There are a couple of things people are starting to wonder about, such as the potential for shut-ins,” Haas said. “But I think prices would have to be significantly lower, maybe in the $1.50-1.60 per MMBtu range, for shut-ins to actually start happening, and I think that we’ll stay above those prices.

“We could test the two-dollar range, though, like in the high $1.90-1.95, somewhere there,” he added. “But the LNG business still has a significant volume of business tied to long-term deals, although that business model has been changing to something more akin to the comparatively fast moving crude oil market.”

That could change “in the blink of an eye,” he noted, “but that said, it’s kind of a big transactional cost to renegotiate.”

“I think, maybe, perhaps 80% of the flows are pretty much locked in on contracts,” Haas said. “That extra 20% is typically held by the house, the owner of the LNG facility, and that’s traded on their own account in the spot market. So that is really kind of what we think is at risk. And so, does that really hurt the gas story in the U.S.?”

Back to Alaska

The next chapter in the LNG story could open right back where we started: Nikiski, Alaska. The terminus—a gigantic liquefaction plant, storage tanks and docks—could go up, right down the road from the mothballed Kenai plant.

The Alaska Gasline Development Corp. (AGDC), a joint venture of Alaskan producers and the state, envisions a three-train liquefaction plant that could cool and ship 20 mtpa of LNG.

If built, that plant would enjoy significant distance advantages to customers in China, South Korea and Japan over LNG coming from the U.S. Gulf Coast, Australia or the Mideast. Alaska lies a just a week or so sailing time from those markets. Compare that to weeks, or maybe a month, of travel through the Panama Canal or across the Indian and Pacific Oceans.

Plus, the plant would be fed by trillions of cubic feet of gas proved reserves below ground on Alaska’s North Slope.

Problem: The North Slope lies 800 miles away, as far as Houston is from St. Louis. It would take a lot of pipe to connect the two ends of the operation, and that makes the economics iffy at today’s prices. Meanwhile, AGDC has moved ahead with the Federal Energy Regulatory Commission process.