New pipeline infrastructure should accommodate expected rise in Permian oil production


As crude oil production in the Permian Basin of western Texas and eastern New Mexico has increased, pipeline infrastructure has also increased to deliver this crude oil to demand centers on the U.S. Gulf Coast.

One indicator of a potential shortfall in available takeaway capacity in the Permian is a negative spread between the price of West Texas Intermediate (WTI) crude oil at Midland, Texas, and the price of WTI at Cushing, Oklahoma.

Going forward, the Midland versus Cushing discount, which recently widened to more than $1 per barrel (b), is unlikely to be either as large or as persistent as it was following the rapid increase in Permian production from 2010 to 2014. At points in both late 2012 and mid-2014, WTI-Midland was priced at least $15/b lower than WTI-Cushing. Pipeline capacity expansions and other market changes are now underway to deliver more Permian crude oil to demand centers.

Compared with other oil producing regions, the Permian has a large number of productive geological formations stacked in the same area. The Permian’s in-region refining capacity, close proximity to large refining centers on the Gulf Coast, and existing pipeline infrastructure also make the Permian attractive to oil producers.

Crude oil production in the Permian grew from 886,430 barrels per day (b/d) in January 2010 to nearly 1.5 million b/d in January 2014, and this production level was more than could be accommodated by in-region refining capacity and pipeline capacity. This situation resulted in large price discounts at the crude oil gathering and transportation hub in Midland, Texas, compared with Cushing, Oklahoma, indicating that pipeline capacity was becoming constrained and crude oil was likely moving out of the region by more expensive methods, such as rail or truck.

In 2014, WTI-Midland averaged a $6.94/b discount to WTI-Cushing, compared with a $1.68/b average discount during 2013. However, as new and expanded pipeline capacity was added, WTI-Midland’s discount to WTI-Cushing narrowed, falling to an average of $0.18/b in 2015 and $0.07/b in 2016.

With the rise in oil prices from their low point in early 2016, EIA’s April Short-Term Energy Outlook (STEO) expects crude oil production growth in the Permian to accelerate. EIA’s April Drilling Productivity Report (DPR) indicates a total of 310 oil-directed rigs active in the Permian, 158 more than at the same time last year. The DPR also estimates crude oil production in the Permian at 2.3 million b/d as of April 2017, or almost 300,000 b/d higher than the same month in 2016.

Pipeline infrastructure in the Permian is now better equipped to handle new production than it was in 2014. Several pipelines that came online to accommodate rising Permian production in recent years, such as Magellan’s BridgeTex pipeline, Sunoco Logistics’ Permian Express pipeline, and Plains All American’s Cactus pipeline, are undergoing expansions that are set to come online later this year, adding approximately 340,000 b/d of capacity.

In addition to expansions of existing pipelines, Enterprise Product Partners is building a new Midland-to-Houston pipeline with a capacity of 450,000 b/d, expected to come online later this year. Other pipeline expansions are planned for gathering systems and intra-Permian pipeline infrastructure to bring increasing volumes of oil to the larger pipeline origin points like Midland. After 2017, several more new pipelines and expansions are planned, or are in the planning stages, that could carry any additional increases in Permian production.

Other pipeline project developments recently completed in the Gulf Coast will allow Permian crude oil to be sent to refining centers in Corpus Christi and Houston in Texas, St. James in Louisiana, and points in between.

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EPA, Clean Energy Spared Trump’s Ax in $1.1 Trillion Budget Deal

Environmental programs marked for death or deep cuts by President Donald Trump got a reprieve in the government funding deal revealed early Monday by congressional leaders — at least for now.

The Environmental Protection Agency, targeted for $247 million in cuts for this year’s funding, instead escaped with a budget trimmed by $81 million — or 1 percent — and no staff reductions. Research divisions within the Department of Energy received increases despite calls by Trump to slash or eliminate them. For example, its advanced research program, which would have been cut in half under Trump’s 2017 spending plan, instead will get a $15 million increase in funding this year.

“Trump threatens a lot of things, but ultimately Congress is going to what it wants to do,” said Stan Collender, a budget analyst and executive vice president of Qorvis MSLGroup in Washington. “What Congress is quickly learning is let the president talk as much as he wants, but ultimately we are going to present him with a bill he is either going to veto or not.”

Next year’s budget, which Congress will begin debating in the coming weeks, will be the real battleground. And the administration isn’t waiting: it has diminished the Obama-era focus on climate change in several ways, including changes to government websites unveiled last week.

Congress needs to pass the omnibus bill or another stopgap measure by the end of this week to avoid a government shutdown. The prospect of Trump shouldering blame for the government closing increased the leverage of Democrats and allowed many of Trump’s top priorities to be pushed aside. Democrats said they were able to stave off dozens of environmental policy riders, allowing just a few to slide through.

Read More: EPA Touts Successes of Programs Trump’s Budget Aims to Kill

The omnibus “reflects the reality there is a lot of support for clean energy,” said Gregory Wetstone, president and CEO of the American Council On Renewable Energy, which represents companies such as solar panel maker First Solar Inc. and electric vehicle battery manufacturer Panasonic Corp. “We are not done, but it’s a good day.”

When it comes to energy policies, this year’s budget is just one round of a longer fight. And Trump doesn’t need Congress to move forward with other parts of his agenda, as his administration has shown in recent days. Employee buyouts at the EPA have already begun; EPA is dropping websites devoted to explaining the science of climate change; and work on energy innovation programs has ground to a halt.

“This is mostly an extension of the status quo. We look forward to 2018 to right-size the role of energy and environment in federal spending,” said Chrissy Harbin, a spokeswoman for Americans for Prosperity, the political group backed by billionaire brothers Charles and David Koch. “The fiscal year 2018 appropriations process is probably a much better opportunity.”

Read More: Trump Climate Pivot Takes Shape in Overhaul of Federal Websites

Trump’s fiscal 2018 budget proposal included sweeping cuts to federal environmental programs, including a $2.4 billion, 30 percent reduction for the EPA and another $2 billion in cuts from the Energy Department’s offices of efficiency, renewable energy and other areas. It also proposed ending dozens of programs, ranging from EPA’s Energy Star certification of appliances to the Energy Department’s loan guarantees for innovative clean-energy technology.

At the EPA, roughly 3,200 employees would be culled from the agency’s 15,000-member workforce. Even without a budget cut, the agency is already moving to implement that plan: EPA staff were summoned to early buyout information sessions last week and counselors were offering employees advice on how to handle “transition in the workplace.”

Regardless of the budget changes, the EPA is already undergoing a dramatic reorientation of its policy. Administrator Scott Pruitt has described his “back to basics approach” as one of “working in coordination with states to create a healthy environment where jobs and businesses can grow.” That shift is already manifest on EPA websites, as agency staff obliterate a climate change portal and add new information about “energy independence.”

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How U.S. Rice Farmers Could Slash Their Emissions (and Costs)

Generations of Arkansas rice growers who farmed the flood plains near the Mississippi River had little reason to pay attention to water supplies or their impact on a changing climate. Dan Hooks is different.

Defying the common practice of constantly flooding fields—which creates methane and makes rice the biggest emitter of greenhouse gases among U.S. crops—Hooks experimented for three years with a low-water technique on 500 acres of rice. Turns out, when he allows the crop to dry out before irrigating again, he’s cut water usage in half and saved money without hurting yield.

“If farmers weren’t willing to change, we’d still be using mules,” Hooks said by telephone from Slovak, Arkansas, about 70 miles (113 kilometers) west of the Mississippi, the biggest U.S. river and a water source for millions of people. “I’m happy to be a guinea pig.”

While fossil fuels like oil and coal get most of the blame for climate change and pollution, agriculture also contributes to the problem. American farmers—the world’s biggest grain producers—are responsible for 9 percent of all U.S. greenhouse-gas emissions, and rice has three times as much per acre as corn and five times that of wheat, according to a University of California-Davis study in 2012.

The technique used by Hooks, called Alternate Wetting Drying, reduces methane emissions, as well as water and fertilizer use. The concept was developed three decades ago in Africa and popularized in Asia during the 1990s. It’s now being employed in the U.S. on 35,000 acres, from southeast Missouri to Louisiana’s Gulf Coast, by farmers calling themselves Nature’s Stewards. The group thinks changing the way rice is cultivated could mean a more carbon-friendly future for the Mississippi Delta, the biggest growing region.

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Solar provides another option for farmers


WASHINGTON, Iowa — Even with a roof over their heads, some of Kurt Hora’s pigs are still finding a way to soak up some sunshine.

Hora, who farms near here in Washington County, put solar panels on two of his buildings about three years ago.

“We have a 2,400-head site, and the panel on the one building generates enough power for the entire site,” he says. “Our power bill for that site used to be $600 per month, and now if we have a sunny month, we’re paying the $18 service charge and that’s about it.”

Hora also has a panel on a nursery building. His electric bill for that building shrunk from $400 per month to the service charge fee.

He attended a meeting a few years ago involving the use of solar panels. Several local hog producers had already made the jump to solar energy.

“It sound pretty interesting, and after going to the meeting and talking to some people, we wanted to try it,” Hora says.

The panel on his finisher is about 200 feet long, he says.

“We’re starting to see quite a few of these in our area,” Hora says.

The popularity of the panels for ag and other uses has grown steadily over the past few years, says Joel Zook, energy planner for the Winneshiek Energy District in Decorah.

“Five years ago, we had three solar panel installers looking for work in this area, and now, most electrical contractors install panels as part of their regular business,” he says. “We have a lot of panels on homes around Decorah, along with some businesses and farm operations.”

Zook says farmers use the panels on structures ranging from dairy barns to grain dryers. He says most are cutting their energy costs by as much as 90 percent.

Zook says there are several programs available for those interested in solar energy. He says the federal government offers a tax credit of 30 percent of the cost of the installed system.

The tax credit remains at 30 percent through 2019 before dropping to 26 percent in 2020 and 22 percent in 2021.

“Iowa tax credits are set at half of the federal tax credit, but are set to expire at the end of 2017 unless the legislators extend them,” Zook says.

He says both local RECs offer some sort of net metering program, where kilowatts are tracked and excess wattage can be cashed in by the user. The programs vary depending on the provider.

“Some will allow you to rollover what you have as well,” Zook says. “The cash you might receive isn’t a whole lot, so it’s best to install the system based on your actual usage.”

He says MidAmerican Energy and Alliant Energy also offer net metering programs.

Zook says the cost of solar panels continues to trickle down, which should make the systems even more popular.

“You can save the same amount of energy with a lighting upgrade as installing solar, for about a quarter of the cost,” he says. “I recommend that anyone get an energy assessment and see where they can save energy before installing solar. NRCS has some great cost-share programs through EQIP for energy efficiency.”

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Chinese economy growing while oil production shrinks


April 17 (UPI) — While posting better-than-expected growth for the first quarter, the Chinese statistics bureau said Monday that crude oil production was down from last year.

China reported crude oil production down 6.8 percent compared with the first quarter of 2016. The National Bureau of Statistics reported Monday that national output was lower because industry costs were elevated, oil imports increased and refineries curbed activity.

According to the official Xinhua News Agency, China produced 350 million barrels of oil during the first quarter. The official news agency stated that “accelerating exploration to ensure domestic oil supply, speeding up construction of pipeline networks and developing clean alternatives” are among the national priorities for the Chinese energy sector.

According to pricing agency S&P Global Platts, China’s oil demand is up 5.3 percent year-over-year because of the infusion into oil storage tanks, a boost in holiday travel and “robust” economic growth. As the second-largest economy in the world, behind the United States, the Chinese government said Monday that first quarter growth was 6.9 percent, above the full-year target of 6.5 percent.

Mao Shengyong, a spokesperson for the statistics bureau, said the first quarter figures were indicative of an economy growing at its fastest rate in a year and a half.

“Generally speaking, the national economy has continued with stable and sound momentum in the first quarter as growth rebounded moderately and economic adjustment was steadily promoted,” the spokesperson said.

Economists at the Organization of Petroleum Exporting Countries reported in their market report for April that full-year growth for China was moderating from 6.7 percent last year to an estimated 6.3 percent, though that still outpaces most other major economies, apart from India.

Elsewhere, China said its production of natural gas more than doubled from last year as China National Petroleum Corp. advances in shale projects in southwest Sichuan Province.

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New U.S. pipelines to drive natural gas boom as exports surge

U.S. energy firms are scrambling to finish a slew of pipelines that will unleash rich reserves of shale gas in Pennsylvania, West Virginia and Ohio as the nation prepares to become one of the world’s top natural gas exporters.

The pipelines are expected to boost output from shale fields in the three states by giving producers access to new domestic and international markets.

Those states could supply about a third of all U.S. natural gas once the pipeline expansion is complete, up from about 25 percent now, according to projections from the U.S. Energy Information Administration (EIA).

The network will bring cheaper fuel supplies for power generation and industry being built in the eastern half of Canada and the United States, especially along the U.S. Gulf Coast. It would also transport the huge volumes needed to feed facilities that chill the gas to liquid so it can be shipped internationally.

The construction addresses a lack of pipeline capacity that has stunted development of two of the largest shale fields in the United States, the Marcellus and Utica formations.

The lines should allow output to increase from both fields by about 50 percent in the next two years, according to the EIA. Gas from the Marcellus and Utica is among the cheapest in the country.

Among the largest projects under construction are Energy Transfer Partners LP’s (ETP) Rover; TransCanada Corp’s Leach XPress; and Williams Cos Inc’s Atlantic Sunrise. Those lines will move gas out of these shale basins to markets in Canada, the U.S. Midwest and Southeast, including expected connections to Gulf Coast export terminals.

The completion of the lines will be a welcome boon for the firms and their investors after a tough couple of years. A slump in international energy prices led to reduced demand for new oil and gas pipeline capacity from producers.

ETP and other firms were also hit by a growing protest movement of environmentalists, Native American rights groups and U.S. military veterans, which delayed big ticket projects such as the Dakota Access Pipeline.

Contractors building ETP’s $4.2 billion Rover gas pipeline from Pennsylvania to Ontario will hire up to 15,000 workers during construction of the line, expected to be completed by late 2017, according to ETP spokesperson.


Just over a decade ago – before technological innovation unleashed huge oil and gas supplies trapped in shale rock – U.S. gas production from conventional fields was in decline and the nation was expected to become one of the world’s biggest importers of natural gas.

High prices for fuel encouraged petrochemical and chemical industries to move abroad.

Now, amid the shale revolution, the nation is producing 50 percent more gas, making it the world’s biggest producer as energy firms opened up new energy frontiers across the United States.

Prices for gas have averaged less than $3 per million British thermal units over the past two years, a third of the price in 2005, and are expected to remain mostly below that level through at least 2023, based on current futures trading on the New York Mercantile Exchange.

That cheap and ample supply motivated industrial firms to spend billions to build and expand manufacturing facilities mostly along the U.S. Gulf Coast but also in the Midwest, such as chemical companies that use gas to make plastics.

Royal Dutch Shell PLC last year agreed to build a multibillion-dollar petrochemical complex near Pittsburgh to be close to the source of the Marcellus and Utica gas. It will employ about 6,000 workers to build the facility and is expected to create about 600 permanent jobs when completed.

Abundant supply has also sparked interest from many countries in buying U.S. LNG exports.

The United States is expected to become a net exporter of gas this year or next for the first time since 1957 on the back of those rising LNG exports as well as pipeline flows to Mexico.


At the center of activity in both the Marcellus and Utica is Pennsylvania, which accounts for about 20 percent of U.S. gas production, making it bigger than any state other than Texas.

Pennsylvania’s output rocketed from 0.5 billion cubic feet per day (bcfd) in 2006 to 14.5 bcfd in 2016, according to the EIA and the Pennsylvania Department of Environmental Protection.

One billion cubic feet is enough to fuel about 5 million homes – or every house in Pennsylvania.

Still, the state has the potential to pump a lot more gas as more pipelines provide producers with avenues to new markets.

At least five pipelines capable of transporting over seven bcfd from the Marcellus and Utica are scheduled to open in 2017, with five more due for completion in 2018, capable of moving another five bcfd.

Pipeline capacity from Pennsylvania, Ohio and West Virginia was around 23 bcfd in 2016, according to the EIA and Thomson Reuters data. If all pipes under construction are completed, that would rise to more than 35 bcfd.

The pipeline construction and gas production expansion mean billions of dollars in new investments in Pennsylvania and hiring that will extend well beyond the energy sector, said Ryan Unger, CEO of the Team Pennsylvania Foundation, a nonprofit foundation focused on public-private partnerships.

“We are in a position now where we can maximize the state’s resources to create good, stable jobs in Pennsylvania,” Unger said.

Some of the biggest drillers in Pennsylvania stand to benefit most from increasing pipeline capacity. They include units of Chesapeake Energy Corp, Cabot Oil & Gas Corp, Range Resources Corp and EQT Corp.

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Nigeria: Opec Members Invest in 160 Projects Worth $156 Billion

Members of the Organisation of Petroleum Exporting Countries, OPEC, have budgeted to invest in 160 oil and gas projects worth $156 billion.

The projects covering exploration, production and refining are to be executed between 2017 and 2021 in the various nations, including Nigeria, Iran, Iraq, Kuwait, Saudi Arabia and Venezuela, Qatar, Indonesia, Libya, the United Arab Emirates, Algeria, Ecuador, Gabon and Angola.

In its latest report, OPEC disclosed that regardless of all the challenges and uncertainties, OPEC Member Countries continue to invest in additional upstream capacities.

It indicated that on top of the huge capacity maintenance costs that Member Countries are faced with, they continue to invest in new projects and reinforce their commitment to the oil and gas market as well as to the security of supply for all consumers.

The cartel stated that needless to say, this is only a reflection of OPEC’s well-known policy that is clearly stated in its Long-Term Strategy and its Statute.

It pointed out that almost 8 mb/d, of potential refining projects in OPEC Member Countries with a relatively new surge in capacity additions from Iran, if all projects are implemented as planned.

According to OPEC, a review of viability of these projects suggests that around 2.2 mb/d of distillation units will be added to the refining sector in OPEC Member Countries in the period 2016-2021.

It stated that this combines around 1.7 mb/d of additional crude distillation capacity and 0.44 mb/d in the form of condensate splitters.

The organisation indicated that condensate splitters additions are planned in Iran and Qatar and set to start falling off by 2020.

It stated that the overall OPEC Member Countries’ distillation capacity (including splitters) is set to reach a level of 13.3 mb/d by 2021.

“An important set of secondary units will also be undertaken during the period 2016-2021, the bulk, around 1.9 mb/d, will be added in the form of desulphurization units, and the rest, estimated at around 1.2 mb/d, will come in the form of conversion capacity (0.62 mb/d), and octane units (0.63 mb/d). The additional refining capacity in OPEC Member Countries will come from condensate splitters, new Greenfield and ‘grassroots’ projects, supplemented by expansions at existing facilities.”

“The largest OPEC Member Countries’ new refineries are megaprojects, expected to come on stream during the medium-term period; these are in Kuwait (Al Zour project), Saudi Arabia (Jizan project) and Venezuela (Anzoetagui). Other relatively sizable projects, with a common trend among crude producers to process heavy crudes domestically and also aiming to satisfy increasing local demand, include new refineries in Lobito, Angola; Manabi (Refinery del Pacifico), Ecuador; Khozestan and Kermanshah projects in Iran; Fujairah and Dubai projects in the UAE.”

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Old Guard Calls Foul on Sweeter LNG Deals Luring New Buyers

Buyers in the world’s largest liquefied natural gas markets are concerned upstarts are winning better deals than traditional customers who helped underwrite the industry.

New importers in the Middle East and South Asia could be getting cheaper LNG than established users in North Asia, according to Hiroki Sato, a senior executive vice president with Jera Co., one of the world’s biggest buyers of the super-chilled gas. Sellers may be sweetening deals to lock up fresh customers as new projects, made possible partly by long-term commitments from buyers in countries including Japan and South Korea, flood the market, he said.

To raise the tens of billions of dollars needed to build an LNG project, developers have traditionally needed to find both large natural gas resources as well buyers willing to commit to purchase contracts that can last more than 20 years. Jera’s wariness over how new importers are being courted highlights the growing pressure on sellers trying to manage old relationships while winning new customers amid the oversupply of capacity that’s tilted the seaborne gas market in favor of buyers.

“Japan and some other Asian countries are traditional foundation buyers for many LNG projects, but substantial demand is now coming from emerging markets” Sato said in an email Friday. “I am afraid their price may be cheaper than ours. Who supported the greenfield projects? We traditional buyers have a right to the cheapest price.”

Many Japanese customers and other big buyers signed supply deals between 2012 and 2014 when prices were at their peak, according to Kerry Anne Shanks, an analyst at Wood Mackenzie Ltd. in Singapore. Those contracts require them to buy gas at a higher percentage of the price of crude — known as oil indexation — than newer agreements, she said.

Last year, Pakistan State Oil Co. agreed to import LNG from Qatar at 13.4 percent of the price of oil, while Japan’s Chubu Electric Power Co., Kansai Electric Power Co. and Tokyo Electric Power Co. Holdings Inc. all reached deals in 2012 with the country at a price 14.9 percent of oil, according to Bloomberg New Energy Finance. Chubu has another contract from 2007 at 17 percent.

“Clearly these foundation buyers are annoyed that low-credit buyers in emerging markets are getting better deals than them,” said Shanks. “But it is a function of when the deals were signed.”

Spot LNG in Northeast Asia has fallen from nearly $20 per million British thermal units in early 2014 to $5.65 as of last week, according to World Gas Intelligence.

As demand in a traditional buyer like Japan is seen falling as more renewable power comes online and nuclear plants restart, gas producers are focusing on emerging markets and new importers to soak up a coming flood of supply. Beyond offering cheap prices to new LNG entrants, sellers are also seeking ways to create even more customers by encouraging projects that spur the fuel’s use.

While Japan is the world’s biggest importer of the fuel, its future growth is unclear, according to Alexander Medvedev, deputy head of Russia’s Gazprom PJSC. The world’s largest gas exporter is setting its sights instead on China and developing countries including India, Pakistan, Bangladesh and Vietnam, he said in an interview last week.

Royal Dutch Shell Plc sees investing in gas pipelines as one way to unlock demand in countries with rudimentary infrastructure, Maarten Wetselaar, director for integrated gas and new energies, told reporters last week at the Gastech conference outside Tokyo. Floating storage and regasification units — the term for import facilities that are cheaper and faster to build than traditional terminals — are key to capturing new demand, along with using LNG as fuel for ships, Engie Global LNG Chief Executive Officer Philip Olivier said at the event.

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Iran struggles to expand oil exports as sea storage cleared

Iran has sold all the oil it had stored for years at sea and Tehran is now struggling to keep exports growing as it grapples with production constraints, shipping and oil sources say.

Since the easing of international sanctions in January 2016, Iran tried to make up for lost sales by releasing millions of barrels parked on tankers offshore.

Tanker tracking and oil sources said Iran had sold its last stocks from the floating storage in the past two weeks. Much of the oil stored was condensate, a very light grade of crude.

With no more stocks at sea, Iran has lost a vital resource that had propped up exports.

“We do think that (floating storage) has been the primary cause of the boost in exports,” Energy Aspects analyst Richard Mallinson said, adding that now floating storage had ended total exports of crude and condensate were likely to slip.

“We see a very difficult path for Iran to raise crude output until it can get the Western expertise and investment back into the upstream, which has been notably slow to materialize,” he added.

After Western sanctions were eased, Iran’s output jumped from about 2.9 million barrels per day (bpd) to about 3.6 million bpd in June.

But it has barely risen since – fluctuating between 3.6 million and 3.7 million bpd – even though Iran fought hard with fellow OPEC members to be excluded from production cuts that came into effect on Jan. 1 and will last till June.

The Organization of the Petroleum Exporting Countries pledged to reduce output by about 1.2 million bpd, but Iran was allowed a small increase to compensate for years of isolation. Yet it has produced less in the past three months than it was allowed.

Iranian Oil Minister Bijan Zanganeh said last month Tehran was prepared to produce 3.8 million bpd if OPEC agreed to extend cuts to the second half of 2016, effectively signaling there was little hope of a steep rise in Iranian output.


Prior to the lifting of sanctions, Iran stored unsold oil on ships, which peaked in 2015 at 40 million barrels on around 25 tankers. The country has up to 60 oil tankers in its fleet.

Iran’s drawdown of floating storage gathered pace in September. By the start of 2017, Iran still held an estimated 16 million barrels of oil on ships. Since then, they have emptied.

While the EU and United Nations lifted sanctions on Iran over its nuclear program more than a year ago, the United States has held separate measures in place and President Donald Trump’s administration has promised a tough line.

This has increased concerns among Western banks about offering finance to Iran, slowing energy investment decisions.

French oil company Total said in February it planned a final investment decision on a $2 billion gas project in Iran by the summer, but said this hinged on a renewal of U.S. sanctions waivers.

“The uncertainty over the U.S. position on further sanctions is casting a huge shadow on the oil trade with Iran,” said Paddy Rodgers, chief executive of tanker company Euronav.

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LNG giants in biggest shake-up as US supply flows to Asia


KUALA LUMPUR • Opec is not the only decades-old energy hegemony being turned on its head by United States shale.

Liquefied natural gas (LNG) sellers from Qatar to Malaysia that dominated gas sales to Asia for years are facing the prospect of rising American exports.

While fewer than 30 US shipments have landed in Asia, their effect was felt even before they arrived.

LNG trade last year jumped the most in five years, contract lengths were sliced in half in the past decade, and spot prices slumped more than 60 per cent in the past three years.

That means the global LNG titans gathering in Tokyo this week for Gastech are in the midst of the biggest shake-up since the industry was founded in the 1960s.

Just as American crude is increasingly making its way to Asia, the world’s biggest oil market, the burgeoning armada of gas shipments from the US and elsewhere are poking holes in the financial system on which the industry’s multibillion-dollar plants are funded.

“As US exports ramp up, we’re going to see even more flexibility with more people trying to buy and trade volumes,” said Mr Chong Zhi Xin, a gas analyst for Wood Mackenzie in Singapore.

“The old models of stable long-term contracts will really have to change. We’ve already seen the impact of US LNG on contract trends, with more destination flexibility coming into play.”

In the 1960s, when projects in Algeria and Alaska started chilling natural gas, the LNG trade was as simple as the industry’s engineering was complex.

Energy companies borrowed heavily to develop gas fields and build liquefaction plants, and to pay off the debt, they signed decades-long contracts with electric utilities to buy the fuel at a fraction of the price of oil.

Now, with hydraulic fracturing lowering production costs, US exporters are setting the price of LNG based on natural gas trades at Henry Hub in Louisiana.

They are also eliminating destination restrictions that require ships to arrive at a specific port, which most previous contracts included, meaning traders can buy shipments and flip them to whatever market needs them the most.

“There are more new types of players coming into the market,” said Mr Keisuke Sadamori, director of energy markets and security at the International Energy Agency.

“It’s no longer the long-term, bilateral, dedicated deal between a certain public utility and exporter, but a more flexible and liquid market.”

By 2020, the US could become the world’s third-largest exporter, behind Australia and Qatar, with capacity to produce 71 million tons of the fuel a year.

It could pass both those countries by 2035, said Ms Meg Gentle, chief executive of prospective shale gas exporter Tellurian.

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