PORTLAND — Where the coastal prairie meets Corpus Christi Bay, stubborn sunflowers bloom in the hard-packed earth and 90 construction cranes draw slashes across the blue sky.
From this spot, Houston-based Cheniere Energy in 2019 expects to launch global shipments of natural gas produced in Texas shale fields.
The idea would have sounded absurd a decade ago, when everyone thought the U.S. was running out of oil and natural gas.
Instead, the burgeoning export plant, on the remnants of a ranch that once spanned 1 million Coastal Bend acres, is one of the latest examples of the turnaround in the domestic energy industry.
After a decadeslong slide, U.S. oil and gas production have surged with shale drilling, the process of using water, chemicals and sand pumped at high pressure to shatter tight rock.
The mud of ancient sea beds buried deep in the earth holds vast stores of oil, but resembles a hard, black countertop, and no one could produce oil and gas from it before fracking.
National oil production next year is expected to reach around 9.9 million barrels per day and surpass the previous high of 9.6 million barrels per day from 1970.
This year, the U.S. Energy Information Administration expects the U.S. to become a net exporter of natural gas. It already surpassed Russia in 2009 to become the world’s largest natural gas producer.
The rush of new hydrocarbons into the U.S. market has spurred billions in port construction and new pipelines, helped create a glut of oil on the world market, and is changing the mix of electric power generation in both the U.S. and Mexico.
The Port of Corpus Christi now exports more crude oil than any other U.S. port, around 316,000 barrels per day, more than double its daily exports last year.
Mexico, which has vast natural gas reserves but can’t keep pace with the demands of its growing population, has turned to Texas natural gas. In May, U.S. pipeline exports of natural gas to Mexico reached 129 billion cubic feet, more than double the level of May 2014, and most of it came from Texas.
The Cheniere liquefied natural gas plant, in Portland across the bay from Corpus Christi, is like a city under construction all at once, and everything is Texas-sized — from the $10 billion price tag for the first phase of construction, to the more than 5,000 workers on site every day.
Hurricane Harvey made landfall on Aug. 25 in Rockport about 15 miles north as the crow flies. The Category 4 storm caused workers to move equipment to high ground and evacuate, but put the Port of Corpus Christi on the weaker side of the hurricane. Harvey left only cosmetic damage at the Cheniere site.
Construction is about 70 percent complete, and wasn’t slowed much by Harvey.
Already, a 48-inch, 23-mile pipeline is in the ground to deliver natural gas from Sinton to the plant, where it will move through the long, rectangular units called “trains” that super cool methane gas. At minus 260 degrees, methane becomes liquid and condenses to 1/600th the volume of its gaseous state, making it possible to export by ship.
Two concrete storage tanks, which employees refer to as the Yeti coolers of the plant, will hold the LNG until it’s loaded onto special tankers.
“These tanks are big enough to store a 747 inside,” construction manager Keith Hendricks said. “Basically it’s 42 million gallons of LNG.”
Across Corpus Christi Bay from the Cheniere mini-city, at the Port of Corpus Christi offices, chief commercial officer Jarl Pederson talked about how the port became the first in 2015 to export crude oil when Congress lifted a decades-old export ban. Last year, the port exported products to 26 countries.
“All the story is about the energy renaissance in the United States,” Pederson said. “It’s a large global shift.”
The Cheniere project is part of $50 billion in construction and investment happening in and around the port — all projects announced in the years after shale oil was first discovered in the field just north of Corpus Christi, the Eagle Ford Shale.
Though the Eagle Ford is known for oil, it started as a gas field in 2008 and 2009. Prices dropped though — thanks to shale gas discoveries across the U.S. and the classic economic theory of supply and demand — and producers started chasing the more profitable crude oil.
In oil wells that happened to be drilled far from existing natural gas pipelines, many companies burned off the natural gas as an unwanted byproduct that was too expensive to get to market.
Natural gas flaring still is common in the Eagle Ford, but most of that natural gas makes it to market, and it has been there all along. Although gas has been overshadowed by oil, Webb County, the southernmost reach of the Eagle Ford before the formation continues across the Rio Grande into Mexico, is the state’s biggest producer of natural gas.
Much of the Eagle Ford’s hydrocarbons flow to Corpus Christi for refining and manufacturing. The port can receive around 2 million barrels per day of crude oil now, but there are six new pipeline projects in the works to connect the booming Permian Basin oil field in West Texas to the port — even more product that ultimately will get exported.
“We think at least a couple of those will be built,” Pederson said. “It will have to go to export. The U.S. is not consuming it. We’re not building new refineries to process it.”
So far, Cheniere is the only company to have shipped LNG from U.S. shale fields abroad, all from its LNG plant and terminal in Sabine Pass, Louisiana. The first tanker sailed last year.
In August, the company announced it had become the country’s largest physical purchaser of natural gas, buying as much as 3 billion cubic feet per day, enough to run 21 natural gas-fired power plants the size of the largest one owned by San Antonio’s CPS Energy.
Despite rhetoric this year about trade wars and the renegotiation of the North American Free Trade Agreement, the export of oil and natural gas appear — on the surface at least — to have political support.
The Trump administration has described the LNG industry as a critical part of expanding the domestic energy industry.
Cheniere even has gotten the presidential shout-out. In June, President Donald Trump highlighted a deal between Cheniere and South Korea.
During a joint appearance with South Korean President Moon Jae-in, Trump talked about the 20-year agreement to make 3.5 million tons of LNG available to Korea Gas Corp. each year.
“This month Cheniere is sending its first shipment of American liquefied natural gas to South Korea in a deal worth more than $25 billion,” Trump said during a speech at the White House.
Vice President Mike Pence in July touted a Lithuanian firm’s decision to purchase U.S. LNG, saying: “It will benefit not only our prosperity, but it will contribute to regional security and stability.”
In August when it was delivered, the U.S. State Department highlighted the shipment again as it arrived in Lithuania, noting it was more than a dozen sent to Europe by Cheniere out of Sabine Pass this year.
Not everyone sees LNG exports as good for business, though.
U.S. manufacturers argue that LNG exports could deplete domestic supplies and cause natural gas price spikes.
Some point to Australia, one of the world’s largest LNG exporters, where the government said earlier this year said it would tamp down on exports because they were causing domestic prices to rise. Customers in eastern Australia were paying more for gas than Japanese customers receiving the country’s LNG, and it was not popular.
In a letter sent to Energy Secretary Rick Perry in August, the Industrial Energy Consumers Alliance asked him to stop issuing permits for new LNG export terminals that would send natural gas produced in U.S. fields to countries without a free-trade agreement, such as the one Canada and Mexico have with the U.S.
U.S. oil and gas producers counter that the country has abundant natural gas. The government estimates there’s 86 years of supply in the ground still.
It’s not just LNG that’s controversial in some quarters. The utilities industry has questioned the increasing use of natural gas for electricity generation, too. About a third of electricity generation was from natural gas last year.
The Energy Department in August released a much-anticipated study on grid reliability and security, which noted that coal-and nuclear-fired power plants have been shutting down because of cheap natural gas, not because of environmental regulations. (Utility-scale wind and solar are also beating nuclear and coal on price).
Last week, Perry followed up that report and directed the Federal Energy Regulatory Commission to consider setting rates that would require utilities to pay coal and nuclear plants for all of the full costs and all of the power they produce, compensating them for the full value of their “reliability” — the idea that they are important to stabilize the grid because wind and solar are intermittent sources.
That move created strange bedfellows. The oil and gas industry, the solar industry and the wind industry have teamed up to oppose Perry’s idea.
The American Petroleum Institute this year also issued a report defending the use of natural gas-fired power plants.
The report argues that natural gas has a “unique ability to support grid operations across the board” because it’s cheap and reliable — natural gas plants can be fired up at will when needed, the same as coal or nuclear plants. The oil and gas industry has tried strategically position natural gas as an ideal compliment to solar and wind.
Marty Durbin, API chief strategy officer and executive vice president, said the study was in the works for two years after API noticed that natural gas electric generation was drawing criticism within the utilities industry.
“It’s a disrupting force in the market,” Durbin said. “What we started to see was some individual utilities say we can’t be too reliant on natural gas. You don’t know what’s going to happen to the cost.”
Durbin said the supply of U.S. natural gas keeps getting “bigger and bigger,” though.
Cris Eugster, chief operating officer at San Antonio’s municipally-owned CPS Energy, said that proximity to the Eagle Ford Shale is one of the reasons the utility bought the Rio Nogales natural gas combined cycle power plant in 2012 to replace an aging coal-fired plant.
“This is right on the edge of the Eagle For Shale, so this gas is Texas gas,” said Eugster. “The problem and challenge with natural gas before shale happened it was a highly volatile fuel… you could have price spikes and there was a lot of volatility in the price of gas. With shale, I think that whole picture’s changed. Now gas is a lot more plentiful.”
Eugster noted the lack of volatility in natural gas prices since 2008 and 2009.
“So I think that also bodes well from a cost standpoint that you have that kind of stability in your fuel source with this type of asset,” he said.
The natural gas industry has been in a rut of low oil prices for a long time — a good thing for customers like CPS, or for residential customers who use natural gas for cooking and heating, or for a company like Cheniere that wants to buy low at home and sell high abroad. A decade ago, prices soared above $13 per million British thermal units, but are hovering around $3 now.
Texas Railroad Commissioner Ryan Sitton said in a recent interview that he’s more bullish on natural gas than on crude oil for the long term, though.
“Which one has the greater upward mobility in the next five years? I think it’s actually gas,” Sitton said. “There’s almost no way for it to go down and a lot of potential for it to go up.”
It will take a combination of things to raise natural gas prices, though — everything from more exports to Mexico by pipe, LNG exports to Asia or Europe, increasing use of natural gas for utility generation, and having more fleet trucks switch to using compressed natural gas as a fuel instead of diesel, Sitton said.
If prices rise to $4 or $5 per British thermal unit, “We won’t be flaring anything. They’ll be building all the pipelines they can to capture that,” Sitton said.
For now, the abundance of low-cost natural gas in the U.S. has found a willing buyer in neighboring Mexico.
Mexico has its own shale and conventional natural gas reserves, which have been the subject of speculation as the country opens its oil and gas fields to outside investment for the first time since the 1930s.
Mexico’s state oil company, Petróleos Mexicanos, or Pemex, controlled nearly every aspect of the nation’s oil production and distribution since 1938, but Mexican officials decided in 2013 to end that monopoly.
It hasn’t been able to develop its own gas fields quickly enough, though. Last year, Mexico imported 53 percent of the natural gas it used, according to its Ministry of Energy. What it can’t bring in by pipeline from Texas or produce itself, it’s bringing in by LNG tanker.
LNG import terminals also help Mexico solve another energy infrastructure need — the LNG tanks also act as storage facilities.
Antonio Garza, former ambassador to Mexico and a former railroad commissioner, said Mexico’s energy reform aims to boost its own natural gas production in the long-term, but market forces are at work now.
“This means that as prices stay low, it makes more business sense to import cheap natural gas rather than invest more to produce it domestically,” Garza said. “But if natural gas prices rise — for example, as new U.S. LNG terminals begin exporting natural gas to other regions — then we could see more interest in developing Mexico’s natural gas reserves and infrastructure.”
Daren Gursel, analyst with the research and consulting firm Wood Mackenzie, said Mexico has seen increasing demand for natural gas for electric generation at the same time its own gas production has stagnated and plummeted. It’s not a quick thing to turn around, so Mexico is trying to complete hundreds of miles of pipeline to connect with Texas.
“Mexico relies more on the U.S. in the coming years,” Gursel said.
In the first seven months of the year, the U.S. sent 39 LNG shipments to Mexico, according to the Department of Energy. It was the top country for U.S. exports, where 23 percent of domestic LNG was delivered, and all of the cargoes originated at Cheniere’s Sabine Pass plant.