US exports rise after surge in oil and gas production
The increase in US oil and gas production will be felt in nearly every corner of the global energy market for years to come
Early next year, a tanker laden with super-chilled gas from US shale fields will set sail from Cheniere Energy’s newly built Sabine Pass LNG export plant on the Gulf Coast. It won’t be the first time US gas leaves its borders – exports to Mexico and Canada have been on the rise and a small Alaskan LNG plant has been shipping gas across the Pacific for years – but it will mark an important moment in the transformation of US energy relations with the rest of the world.
Surging oil and gas production over the past decade has made export options a reality, upending well-established global energy trade flows in the process. In addition to LNG exports, pipeline gas shipments to Mexico and Canada are also on the rise as new infrastructure connects US gasfields with markets across the border.
Billions are also being invested in new pipelines, terminals and ships to export natural gas liquids, which are produced alongside shale gas and have also seen production swell. The swift arrival of huge amounts of US propane on international markets has already re-shaped global trade flows and ethane is set to join it.
The politics of oil exports are much more fraught – and for now most US crude is confined within America’s borders. That has sparked a heated political battle in Washington to overturn the 1970s era export ban.
But even so, US net oil and product imports have fallen to less than 5m barrels a day (b/d) this year, the lowest level in three decades.
While crude itself isn’t being exported in large quantities, refiners are using the flood of domestic production to export record amounts of refined products. Exports of gasoline, diesel, jet fuel and other fuel products have more than doubled over the past 10 years.
Full energy independence is still some way off, especially as crashing crude prices test the limits of the shale industry, but something close to it is in sight for the US.
The reversal in the country’s gas fortunes has been particularly dramatic. A decade ago, the US looked like it was headed for gas shortages. The then chair of the Federal Reserve, Alan Greenspan, warned that the US urgently needed to add LNG import capacity to stabilise the country’s notoriously volatile natural gas markets. Dozens of proposed LNG import plants around the country rushed to get government approval and break ground, a process echoed today in the frenzy to build export capacity.
They were, of course, proved wrong. LNG imports peaked at 2.1bn ft³/day in 2007, and that slowed to a trickle of just 36m ft3/d through the first seven months of 2015. Nearly all of the remaining regular US LNG imports travel a single route between Trinidad & Tobago’s Atlantic LNG facility to a regasification plant in Massachusetts in the northeast.
But building an LNG export industry will be difficult, especially as the global market turns against US gas. US exports will be hitting the market amid a glut of LNG supply and depressed prices that will make it much more difficult to compete than it would have been 18 months ago.
The largest draw for international buyers of US LNG was its unique pricing structure, being linked to the US Henry Hub benchmark rather than oil prices. When oil prices were at more than $100/b and US natural gas prices were around $3.50/m Btu, the economic advantage for US gas in Asia and Europe was clear. Even with the liquefaction fee and shipping costs, US LNG looked much cheaper than crude-linked LNG supply.
The low oil price has undermined that cost advantage, though. Spot LNG prices in northeast Asia have fallen to around $6.50/m Btu, less than a third of the peak of $20.50/m Btu in February 2014. At these prices, even with recent declines in Henry Hub prices, US LNG is not competitive.
Cheniere Energy’s Charif Souki, a pioneer in the US LNG export business, told a conference in Singapore in October that LNG prices would have to rise by 20% to 25% – closer to $10/m Btu – to make new US LNG projects competitive.
The outlook for LNG demand has also dimmed. In Japan, the world’s largest LNG buyer, demand peaked in 2012 in the wake of the Fukushima nuclear disaster, and looks set to fall further as nuclear plants are brought back into operation. South Korean demand has stagnated on slower economic growth and a push to build new coal and nuclear capacity. Chinese demand has not materialised in the way many LNG project developers had hoped. New LNG plants on the country’s coast are sitting under-used as gas demand growth in the country has flat-lined, although the government is lowering gas prices at the city gate to stimulate demand growth.
In Europe, US LNG will be welcomed, but there is only so much demand to go around as demand sinks to 20-year lows. Politicians on both sides of the Atlantic have talked excitedly about US LNG fundamentally altering the energy geopolitics of the continent, breaking Europe’s reliance on Russian gas. But this is a fantasy. Russian pipeline gas and gas piped from Norway will nearly always beat US LNG on price. Cheniere’s Souki acknowledged as much.
“Russian gas will still be the dominant player in Europe… Cheniere’s entry into Europe won’t dent prices there”, he said. That will leave US LNG at the shrinking margins of the European gas market.
Most of the 29 new LNG export schemes proposed to the Federal Energy Regulatory Commission – totaling 38.97bn ft3/d, close to half of US production – were never likely to get off the drawing board. As with the import terminal craze, the projects were mostly chasing the same buyers or sellers.
And the downturn will make it even more difficult for new projects to get sanctioned. “Why wouldn’t North America export say 20 or even 30bn ft3/d of LNG? Put simply, because there would be nowhere for it to go”, Pavel Molchanov, an analyst at investment bank Raymond James, wrote in a recent research note.
That gives a major advantage to those projects that have already locked in government permits, long-term supply deals, and have started construction on their facilities.
Of the 29 projects in various stages of existence, six are likely to be built and start operating before the end of the decade, says Raymond James.
Those plants will be exporting between 7bn ft3/d and 9bn ft3/d by 2020, according to the bank, equivalent to 10% to 12% of today’s US gas production. That figure will rise somewhat as the projects ramp up to full output in the early 2020s.
Cheniere’s Sabine Pass plant will be at the vanguard when it starts exports in early 2016. The $12.7bn project blazed the trail for the US LNG export industry. In many ways the company set the business model adopted by others, having established the Henry Hub-linked pricing formula and the unique tolling model in which producers pay a fee to run gas through the liquefaction plant, instead of having to own a stake in the plant itself.
Sabine Pass’ first 4.5m t/y train will be followed, Cheniere says, by three more trains coming online every six to nine months, eventually bringing total capacity to 18m t/y, producing around 2bn ft3/d at its peak. When finished, it will be among the largest liquefaction plants in the world.
The full effect of US LNG won’t really start to be felt on the market until later in the decade though. From 2018 to 2020, five more projects are scheduled to start exporting.
Dominion Energy’s 5.25m t/y Cove Point LNG plant in Maryland on the northeast coast is likely to be the second plant to come onstream, in late 2017 or early 2018, providing a nearby outlet for supplies from the prolific Marcellus and Utica shale gas plays.
Kinder Morgan’s small 2.5m t/y plant at Elba Island in Georgia on the Gulf Coast is next in line, targeting a late 2017 or early 2018 start. Shell is committed to buying all of the facility’s production, so there is little risk the project won’t move forward in spite of construction delays.
Cheniere is also moving ahead with a 13.5m t/y liquefaction plant in Corpus Christi Texas, which is likely to start up in late 2018 and reach full capacity in 2020.
Freeport LNG, owned by the former wildcatter Michael Smith as well as Global Infrastructure Partners and Japan’s Osaka Gas, started building its liquefaction plant in 2014 and is on track to start shipping LNG in 2018.
The last plant that looks most assured to go ahead is Sempra’s 12m t/y Cameron LNG project in Louisiana, which is likely to start up in early 2019.
Beyond these projects, it is not clear how many, if any at all, additional projects will be sanctioned and built anytime soon given the difficult market conditions.
One area worth watching will be the west coast, where there are two projects in Oregon – Jordan Cove LNG and Oregon LNG – battling it out. The west coast is ideal for shipping gas across the Pacific to northeast Asia, avoiding the logistical difficulties and added cost of having to pass through the Panama Canal. But there are concerns over their ability to secure enough gas supply and they are facing stiff competition for buyers from Canada’s own west coast LNG projects in British Columbia.
Other projects to watch will be those involving well-established and well-funded gas producers and LNG traders. ExxonMobil, Qatar Petroleum and ConocoPhillips are backing a $10bn effort to transform the Golden Pass LNG import plant on the Gulf Coast into a 15.6mn mt/y export facility capable of shipping 2bn ft³/d.
The Alaska state government is also pushing for a major LNG project of its own alongside BP, ConocoPhillips and ExxonMobil, though it faces huge challenges – not least of which is its daunting price tag of $45bn to $65bn.
The politics of LNG exports has been controversial. The gas industry has essentially won the debate over whether or not LNG exports should be allowed. But there are many opponents to exports, as petrochemical companies see the loss of their competitive advantage overseas, and the Obama administration has been cautious about moving too fast with approval permits – particularly the Department of Energy’s process to approve exports to non-FTA countries.
Political tensions over the issue could flare up if domestic gas prices rise once exports begin, an issue that has complicated Australia’s LNG export boom. Higher prices at home could quickly sap public and political support for LNG exports. In that sense, the relatively slow ramp up of exports could be a blessing in disguise for the industry because it is unlikely to affect consumer prices.
For gas producers looking for new sources of demand, Mexico has proved an unexpected and important lifeline. While the focus of the country’s energy reforms has been on opening its oil and gas fields to foreign investors, efforts are being made to gasify the country’s electricity system, leading to a surge in new demand.
Mexico has looked north of the border to take advantage of relatively cheap US supplies to feed a growing number of gas-fired power plants. US pipeline imports have surged from around 1.6bn cf/d to a record high of 3.3bn cf/d in August this year.
Mexican buyers have been paying around $3/m Btu this year, according to Energy Information Administration data, making US pipeline gas about a third of the price of LNG imports for Mexico.
This is only going to rise. Mexico has vast natural gas reserves, but state-owned Pemex has not been able to exploit those reserves on its own, and foreign investment will be slow to come into the country’s natural gas fields. Nearly all new gas demand then, will be met by US pipeline supplies.
Analysts at Barclays, the investment bank, expect exports to rise to around 5bn cf/d by 2020, though if all goes to plan in Mexico’s gas-fired power generation build-out, that could rise to 6.2bn cf/d. At those levels, pipeline exports to Mexico could rival LNG volumes at the end of the decade.
It isn’t just natural gas that is being exported, but also its liquid byproducts – especially propane and ethane. As with natural gas, surging shale production has created a glut of natural gas liquids – feedstock for the petrochemicals industry – that has seen prices plunge, denting producers’ profits and undermining the economics of some so-called liquids-rich shale plays. With the domestic market saturated for now, producers are looking abroad for new demand.
The US has quickly become a major exporter of propane. A rapid expansion of export capacity along the Gulf Coast has allowed exports to double from around 300,000 b/d in mid-2013, with the rise forecast to continue.
“Propane exports from the US are changing traditional propane trade patterns across the globe,” the EIA said in a November report.
Exporters are eyeing markets well beyond its backyard and they hope to crack Asia, where they will compete with traditional suppliers from Russia and the Middle East.
The US is also set to become a major ethane exporter. Production of the fuel will double from 1.2m b/d in 2013 to 2.5m b/d by 2024, easily outpacing domestic demand growth, according to estimates from Bentek Energy, a consultancy. Surging production has already seen prices collapse from $0.60/gallon in mid-2012 to around $0.20/gallon today, among the lowest in the world.
Companies in the US looking for new markets and those abroad keen to access cheap US feedstock have responded by drawing up export plans.
The first US ethane exports are to be sent from Sunoco’s Marcus Hook terminal in Pennsylvania, where ethane from the Marcellus shale will be sent to an Ineos gas cracker unit in Norway, with subsequent shipments also going to Scotland. A 200,000 b/d ethane export terminal operated by Enterprise Product Partners on the Gulf Coast is expected to start shipments in the third quarter of 2016. The world’s first Very Large Ethane Carriers, built in Chinese shipyards, will help take US ethane onto international markets.
Bentek expects ethane exports to rise to 400,000 b/d by 2024, which should help buoy domestic US prices. Soon, just about every molecule of the gas chain produced in the US will be exported
Now, the industry is lobbying hard to bring an end to the oil export ban so crude from US oilfields can be sent into international markets next.
As light crude output from shale fields across the US surged over the past five years – increasing production from just over 5m b/d in 2009 to 9.5m b/d in early 2015 – producers faced a daunting new problem: a glut of light oil risked swamping the domestic refining system’s capacity to process it.
Even before reaching that point, US producers were being hit as the US WTI crude benchmark started trading at a steep discount to Brent, a sharp break from the past when it was WTI that traded at a premium. In areas around the Bakken and Eagle Ford, where infrastructure bottlenecks trapped crude in local markets the discounts were even greater. When oil prices plunged in the summer, some Bakken producers saw their oil selling for less than $30/b.
There is already so much light sweet crude coming from domestic fields that imports into the Gulf Coast has fallen to close to zero in 2015, down from 850,000 b/d in mid-2010. That has pushed out imports from Opec’s light-oil suppliers Nigeria, Angola and Algeria. Light crude imports to the east coast have fallen by around 60% over the same time.
For oil producers, the obvious answer to the problem of limited domestic refining capacity is to lift what they consider an antiquated ban on oil exports – a ban rooted in the paranoia and fear that followed the 1970s Arab oil embargo. Opening international markets, they argue, would encourage more investment in production by boosting domestic crude prices and allay fears that domestic light oil production will effectively be capped by the country’s capacity to refine it.
The oil price crash and more recent decline in US oil production has taken some of the urgency out of the push to lift the export ban, but it remains a central issue for both producers and refiners.
There are many that defend the ban. Some argue that lifting it would raise prices at the pump. However a federal government study found that because gasoline prices are linked to international oil prices, not US benchmarks, there would be little if any affect on consumers.
If anything, the study found, fuel prices could actually come down slightly if lifting the ban results in more barrels coming onto the international market.
Many refiners, led by the CRUDE Coalition (Crude Refiners United for Domestic Energy) lobby group, have also come out against lifting the export ban. The group has mostly pushed the energy and national security benefits of keeping US crude in the US.
A political standoff
But there is clearly an economic self-interest involved as well. Refiners have enjoyed a golden age, as they are able to buy relatively cheap US crude feedstock and sell fuels linked to higher-priced international crude benchmarks.
The other, more existential, line of argument from environmentalists and many Democrats against lifting the ban is that the government shouldn’t be doing anything to encourage more oil production.
This has set the stage for a contentious and complex policy fight in Washington DC, where the issue will ultimately have to be decided in Congress. Republicans almost uniformly support lifting the oil export ban, and a bill to do just that has passed in the Republican-dominated House of Representatives.
Democrats, however, are more divided over the issue. Many outright oppose lifting the ban on environmental grounds, or simply to stand in opposition to the oil industry. Others, though, cautiously support lifting the ban, but only as part of a broader energy deal that would include incentives for renewables and energy efficiency.
President Barack Obama, who would have veto power over any legislation, appears to fall in the latter camp.
His administration has taken some steps to allow lightly-processed condensates to be exported and approved limited exports to Mexico in the form of crude swaps. At the same time, though, they have threatened to veto the House bill that called for the export ban to be lifted.
That doesn’t mean the issue is dead in Washington DC, but getting to a deal will be very difficult, and become even more so as the 2016 election nears.
The compromise that appears to be in the offing would be an omnibus package capable of winning over both sides of the political divide that would lift the oil export ban but also include clean energy incentives, such as extending production tax credits for wind and solar projects.
The Senate, where a supermajority of 60 votes will be needed to pass legislation, is the locus of action now.
“One of the things I didn’t want to see happen with oil exports is what I call the ‘Keystone Effect’,” Heidi Heitkamp, a Democratic senator from North Dakota and supporter of lifting the export ban, said in Washington DC recently. Keystone XL, she argued, had become ideological fodder for both sides, which exaggerated its importance and made agreement over the pipeline ultimately impossible.
“There are going to have to be compromises… what we’re trying to do now is work out where those compromises are and how we can move forward,” she said.
Heitkamp added: “The 500-pound gorilla is the White House, we have to have something that can get signed. But, you know, compromise is an elusive concept in Washington.”
An outright lifting of the ban isn’t the only option for lawmakers. They could instead limit exports only to Mexico or FTA countries. Alternatively, exports could be limited to certain light crude grades from certain locations, similar to the exemption of heavy crude exports from California.
But compromise will only become more difficult as the 2016 election nears and a sharpening of political rhetoric makes dealmaking even more difficult.
If nothing is done in the first couple months of 2016, the issue will likely be put on the backburner for the next congress and administration.
Reading the politics right will be crucial for the industry. To avoid US light oil becoming stranded, investment decisions will need to be made soon to deal with the potential fallout of decisions taken in Washington.
In the meantime, higher crude production is still being felt on international markets in the form of surging exports of refined products.
US refiners have been processing record amounts of crude, and more of the finished fuels are finding their way onto international markets, in many cases reversing previously entrenched trade flows. US refined product exports averaged 2.76m b/d through August this year, nearly three times what it was a decade ago.
Regardless of how the debate over the oil export ban plays out, the effects of the rise of the US’s shale industry will be felt around the world for years to come.