AFPM: Ethane exports begin to build

Logistics infrastructure is an important area of activity in the US right now, as producers seek to transport and export shale products

The sudden drop in crude oil prices this year has already caused some midstream companies to cancel plans to build new processing plants due to the accompanying drop in operational oil rigs. Nonetheless, the US still has plenty of natural gas liquids (NGLs) that need to be moved from production areas to markets, whether it is to crackers on the Gulf Coast or to overseas plants in Europe and India.

The abundance is shown by both prices and inventories. As of the week ending 20 February, US propane inventories stood at 55m bbl – an increase of 31m bbl year-on-year, according to Peter Fasullo, principal at En*Vantage.

Meanwhile, companies are leaving as much ethane in the natural gas stream as possible, in a phenomenon called ethane rejection. This likely stands at 500,000 bbl/day, Fasullo adds.

Shale gas infrastructure is being built rapidly to get product to market Copyright: Rex Features

Ethane prices, meanwhile, have remained below 20 cents/bbl for much of the year. It is the lowest price since ICIS began assessing ethane prices in 2011.

US ethane, however, will soon find a home overseas. By mid-year, ethane and ­propane should start arriving at Sunoco Logistics’s NGL terminal in Marcus Hook, Pennsylvania, through a 70,000 bbl/day pipeline. From Marcus Hook, the ethane will go to INEOS’s gas cracker in Rafnes, Norway. New vessels to transport the ethane are scheduled to enter into service in 2015.

Sunoco’s terminal is a special case, as the ethane is not going to replace naphtha, says Dan Lippe, president of Petral Consulting. Instead, the chemical will help the Rafnes cracker make up for its original source of feedstock in the North Sea, where ethane production is dwindling.

On the US side, the terminal is unlikely to do much to affect the supply and demand balance, Lippe says. He estimates that the Marcellus field has about 60,000-80,000 bbl/day of unrecovered ethane – more than enough to supply the first phase of Sunoco’s Marcus Hook terminal.

Any propane exports, however, will be more crucial for the eastern US.

The northeast US will need new export capacity because it lacks sufficient capacity to store large amounts of NGLs, Fasullo says. This is critical during the warm summer months, when demand for propane as a heating fuel plummets. “Northeast propane prices can get very distressed in the summer months,” he explains.

Even before the drop in oil prices, proposed pipelines to transport Y-grade NGLs out of the eastern US fell through because midstream companies could not attract enough interest. Companies may thus have to rely on trains and barges to ship excess propane out of the region. Upcoming export capacity could help reduce oversupplies of propane.

MARCUS HOOK EXPANSION
By the fourth quarter of 2016, the second phase of Sunoco’s Marcus Hook project – Mariner East 2 – should start operations. It will have more units for ethane as well as propane and butane for both domestic and international markets. Mariner East 2 should have an initial capacity of 275,000 bbl/day.

The new ethane terminals are not limited to the east coast. By the third quarter of 2016, Enterprise Products plans to complete an ethane terminal at its Morgan’s Point facility on the Houston Ship Channel. It will be able to load ethane at a rate of about 10,000 bbl/hour. On a daily basis, the effective capacity will be more like 200,000 bbl, according to En*Vantage’s Fasullo.

That is a significant amount of ethane that could pressure prices, Petral’s Lippe notes.

Moreover, Enterprise is considering an 
expansion of its Gulf Coast ethane exporting capacity. The company has not confirmed that the project will go forward, nor has it disclosed a possible capacity.

Given current ethane and naphtha prices, Lippe doubts that companies are better off switching to lighter feeds shipped from the US Gulf Coast. The companies, though, have take-or-pay contracts, so they will likely proceed with the shipments, he says.

What is crucial is not today’s pricing. These projects and supply agreements were planned over a horizon of several years. Pricing will change, possibly making overseas ethane shipments a winning strategy.

In addition to ethane export capacity, the US Gulf will also have more capacity to ship liquefied petroleum gas (LPG). Last year, Targa Resources was scheduled to add an 
additional 2.0m bbl/month of capacity at its Galena Park terminal, bringing total capacity to 6.5m bbl/month.

In the first quarter of this year, the Mariner South pipeline should begin shipping ­propane and butane to Sunoco Logistics’s terminal in Nederland, Texas. This pipeline has an initial capacity of 200,000 bbl/day. By early 2016, the terminal should starting loading its first propane ship, Sunoco’s CEO Mike Hennigan said in a recent earnings conference call.

Between now and 2016, Enterprise and Phillips 66 plan to add up to 12.4m bbl/month of LPG export capacity on the Gulf Coast. This includes Enterprise’s expansion at the Oiltanking terminal which, combined with its other terminals, will give the company the capacity to load more than 16m bbl/month of propane, butane or LPG.

The US will need this additional capacity because of expected increases in LPG production, Lippe says. LPG exports, though, will require US companies to adjust to a new paradigm, that of a major international exporter, he adds.

LPG EXPORTS TO GROW?
The first LPG export terminals in the US only started shipping product a few years ago. Its customers, moreover, are powerful, as they include major chemical companies in 
Europe as well as importers in Japan, Lippe says. The latter country is using US LPG to replace imports from its traditional suppliers in the Middle East. The US will be juggling these parties at a time when it will have enormous supplies of LPG. “The most important thing you have to learn is how to manage an environment where you are supply-long and at the mercy of powerful buyers,” says Lippe.

“The midstream industry has to recalibrate everything it does because we will be supply-long, exporting like mad, for the next 15-20 years. This is what we are going to be doing for a long time.”

More factors are also coming into play. While some midstream companies are continuing to develop processing plants, others have started to halt plans for projects that were scheduled to start up after 2015.

ONEOK was among the latest to halt plans, citing the drop in US rig counts and the resulting effect on gas production. Processing plants need gas to process, Lippe says. If companies cut back on production, that will limit demand for processing plants.

Critically, companies are cutting back on oil rigs – the source of the rich gas that needs processing the most. “It’s all about the gas and the gas producer. It’s not about the gas processor,” Lippe notes.

And with the volatility in oil prices, companies are going to be reluctant to expand drilling until the market stabilises, Fasullo says. “Producers are not going to make commitments to processing plants that are going to be built beyond a year or so until they understand what their drilling plans are going to be.

“With crude prices where they are right now, there is just too much uncertainty.”

OBAMA VETOES KEYSTONE XL PIPELINE PROJECT

Although president Obama has vetoed the Keystone XL pipeline, others are being built in the US to carry shale gas and oil Copyright: Rex Features

The Keystone XL pipeline linking Canadian oil sand fields with US consumers through a terminal at Steele City, Nebraska, will likely remain in limbo following President Barack Obama’s veto of legislation that would have authorised its immediate construction. Because the Keystone pipeline crosses the border between Canada and the US, it needs presidential approval or an act of Congress before it can be completed.

Since Obama vetoed that Act of Congress, the Keystone project will go back to what will likely be more rounds of study.

Behind the veto and the studies are concerns about emissions of carbon dioxide (CO2) caused by oil sands production, explains Ken Medlock, senior director of the Center for Energy Studies at Rice University. Oil sands, opponents say, produce more CO2 than traditional production methods. Those opposed to the pipeline worry that the project would encourage more production from oil sands by lowering transportation costs.

However, the majority of oil sands’ CO2 does not come from production, Medlock says. It comes from people burning the resulting fuel in their automobiles. “The carbon dioxide emissions occur at the wheel, not the well,” he says.

As a result, halting the Keystone pipeline or even reducing oil sands production will likely do little to reduce CO2 emissions, as long as people continue driving automobiles.

Regardless, the Keystone project will likely be subject to more studies and delays. The latest studies could revolve around the sharp drop in oil prices and its impact on oil sands production.

In an earlier study, the US State Department concluded that if oil prices exceed $75/bbl, Canada will continue to produce oil sands regardless of the pipeline, Medlock says.

Oil prices are now below $75/bbl. Companies may reduce oil sands production if they cannot find a cheaper way to ship the product. That cheaper way would be the Keystone pipeline. Therefore, with crude prices below $75/bbl, the Keystone pipeline may increase oil sands production and, hence, CO2 emissions.

Medlock believes this view is myopic, since oil sands were profitable when crude was close to $30/bbl. Moreover, crude prices could once again rise above $75/bbl.

“What we are doing is kicking the can down the road,” says Medlock. If the studies and delays continue the Keystone pipeline will likely need a new president before it gets approved. “In the meantime, we can have this interesting discourse over a pipeline project,” Medlock adds.

PIPELINE PROGRESS
Meanwhile, other pipeline projects have made more progress. Many of the long-haul natural-gas liquid (NGL) pipelines have been completed. A little more than a year ago, Enterprise Products began injecting ethane into its 125,000 bbl/day Appalachia-to-Texas Express (ATEX) pipeline, bringing the gas from the Marcellus shale field in the eastern US to Mont Belvieu, Texas, the nation’s NGL hub. The pipeline stretches for 1,230 miles (1,979 km).

In October 2014, ONEOK announced the expansion of its 540 mile Bakken Natural Gas Liquids (NGL) Pipeline to 135,000 bbl/day from 60,000 bbl/day. The pipeline connects the Williston Basin in North Dakota to the 245,000 bbl/day Overland Pass Pipeline in southern Wyoming. Overland, in turn, leads to Conway, Kansas.

Earlier in September, Enterprise announced the completion of the first part of its Aegis ethane pipeline, which connects Beaumont, Texas, to Mont Belvieu. This segment is part of the planned 270 mile Aegis pipeline. When Aegis is completed, it will create a 500 mile header system that stretches from Corpus Christi, Texas to the Mississippi river in Louisiana.

The next segment, between Beaumont and Lake Charles, Louisiana, is scheduled to be completed in the third quarter of 2015. The final segment, from Lake Charles to the Mississippi, is expected to be complete by the end of 2015. Aegis will have a capacity expandable to 425,000 bbl/day.

The Aegis header system will be a major ethane supply artery available to more than 20 petrochemical plants that will be in operation along the US Gulf Coast by 2020. By that year, these plants are expected to represent more than 90% of US ethylene production capacity.

In November, Lone Star – a joint venture between Energy Transfer Partners and Regency Energy Partners – announced plans to build a new NGL pipeline from the Permian Basin shale play in western Texas to the US Gulf Coast. The pipeline will be 533 miles long. The 24 inch (61 cm) portion will be able to transport 375,000 bbl/day from the Permian Basin to Bosque county, while a 30 inch portion will transport 495,000 bbl/day from Bosque county to Mount Belvieu.