22 March 2013 13:44 [Source: ICB]
The booming production of shale gas and oil is raising serious questions over how to get it directly into the hands of customers and how much can be exported without affecting the low-cost advantage that is revitalising manufacturing in the US
"As you know, our member companies have shifted the feedstocks they use over time," says Jim Cooper, vice president of petrochemicals at AFPM. "In the US, we have a lot of flexibility in our manufacturing that other regions don't have. We can use the ethane that comes from shale production and we're very competitive worldwide regarding ethylene."
As each test-well from shale reserves produces more positive numbers, the problem of bringing the oil and gas down to the US Gulf region has increased. According to Cooper, there have been significant advances when it comes to drilling in the shale plays. "The imaging used when drilling has improved dramatically. We now have a much better understanding of what the shale play looks like," Cooper explains. "The advancement and experimentation of fracturing fluids has improved and is ongoing, including those that don't use water at all."
But once the oil is drilled, transporting it becomes the next struggle. Enter the Keystone XL and Seaway pipelines.
The Keystone XL pipeline would provide US refineries with upwards of 700,000 bbl/day of crude including conventional oil, shale oil, partially upgraded synthetic oil and oil sands-derived bitumen blends. The 875 mile (1,408 km) pipeline, a project of TransCanada, would cross the border between the US and Canada. It would transport oil from Hardisty in Alberta, and the Bakken shale formation in the US, to Nebraska and eventually to refineries along the US Gulf Coast.
However, the approval process on the pipeline has been a big struggle. On 1 March, the US Department of State issued an expected Environmental Impact Statement (EIS) as part of the process in the development of the Keystone XL pipeline.
While the state department did not judge the project, since other federal agencies will have an opportunity to review the draft and public comments will be welcomed, the EIS concluded that "approval or denial of the proposed project is unlikely to have a substantial impact on the rate of development in the oil sands or on the amount of heavy crude oil refined in the Gulf coast area."
The draft also said that "TransCanada's Keystone XL pipeline would have little effect on most resources along the project's proposed route if the company takes certain mitigation measures."
On 22 January, Nebraska's governor Dave Heineman announced the approval of a revised route for the Keystone XL pipeline. With that hurdle cleared, the next step is the review from the state department.
The Obama administration's decision is not expected until about mid-year.
Meanwhile, Enterprise Products and partner Enbridge completed the expansion of the 500 mile Seaway crude oil pipeline from Cushing, Oklahoma, to the US Gulf Coast in January this year. The expansion allowed capacity to increase from 150,000 bbl/day to 400,000 bbl/day.
In addition to the pipeline that transports crude oil from Cushing to the Gulf Coast, the Seaway system includes a terminal and distribution network originating in Texas City, Texas, which serves refineries locally and in the Houston area, and it includes dock facilities at Freeport and Texas City.
However, since its started, the Seaway pipeline has not been running at full capacity, which is raising an even bigger issue for some.
Enterprise spokesman Rick Rainey clarifies that the reduction is not because of technical problems with Seaway, or with the terminal, but because customers are not taking enough oil out of the terminal. "This may signal larger concerns, that instead of alleviating the glut at Cushing, we may just be exchanging one glut for another," says Phil Flynn, senior market analyst at Price Futures Group. "Are we are producing oil faster than the demand or the logistics and storage will allow? There are fears of a never-ending glut that may mean that we might not be able to take full advantage of our growing production prowess."
According to Flynn, the answer may be to allow widespread export of US oil and gas. But, as Flynn explains, under present legislation, that may pose an even larger problem. "Back during the Arab oil embargo, the US passed a law that banned all oil exports except for a few specific instances and President Reagan did allow exports to Canada. This president does have the authority to allow exports to other counties, yet that may be tough seeing that he is anti-oil," Flynn explains.
NATURAL GAS EXPORTS
The abundant shale resources in the US has also sparked a debate over whether to export natural gas as liquefied natural gas (LNG), creating rifts between industrial users and mid-stream project developers that want to ship LNG to overseas markets. In recent weeks, the various stakeholders have firmly entrenched their positions, as the regulatory US Department of Energy (DOE) is expected to renew its consideration of pending LNG export licences. Industrial consumers, primarily led by US manufacturing heavyweight Dow Chemical, have also become more vocal in supporting their stance to protect domestic natural gas prices. Dow Chemical opposes unchecked approvals of LNG exports and throws caution on the existing regulatory procedure.
Meanwhile, the Center for LNG, the US LNG industry's main trade organisation, and the American Petroleum Institute, have stepped up advocacy efforts to back approvals for LNG exports. More than 20 export projects have sought export licences from the US Department of Energy (DOE). Nearly all the proposals are seeking to export to countries outside free-trade agreements with the US, to nations such as Japan, China and India, which are major LNG consumers.
However, the DOE has halted approvals of any new LNG export licences for these countries since granting the first non-free-trade-agreement licence to US-based project developer Cheniere, which is adapting its existing Sabine Pass import terminal in Cameron Parish, Louisiana, to create an 18m tonne/year liquefaction facility.
Although the backlog of pending projects now totals more than 29bn cubic feet (bcf)/day of potential exports, most industry analysts estimate US LNG capacity will see expansion to between 6-8bcf/day by 2020, given the high barriers of capital costs and commercial realisation of liquefaction facilities.
A recent assumption by investment bank Goldman Sachs puts this estimate at about 6.76bcf/day of liquefaction capacity to be built between 2016 and 2020. "However, we highlight that potential demand growth in the next 10 years, particularly from Asia, is likely to once again tighten spot markets, creating the necessary conditions to accommodate some (but not all) of the large liquefaction projects currently being proposed in North America," according to a 19 February analysts note.
Yet some believe that exporting shale resources is not the best way to capitalise on the value of all that oil and gas. At a recent hearing in front of the US Senate Energy and Natural Resources Committee, Dow Chemical CEO Andrew Liveris expressed his concern that large-scale expansion of US LNG exports could combine with broader electric utility use of gas, an increasing role for natural gas as a transportation fuel and expanding drilling regulations to effectively kill the golden goose by driving domestic natural gas prices ever higher.
"Dow supports expanded exports and trade," Liveris said. "But we also believe it is crucial that DOE have the information and analysis necessary to properly apply the Natural Gas Act requirement that exports be consistent with the public interest." He urged Congress to ensure that DOE's LNG export-permitting process be opened to wider comment by the full range of industries that depend on natural gas as a fuel or feedstock.
But Jack Gerard, president of the American Petroleum Institute (API), argues that in addition to driving a domestic manufacturing renaissance, the new availability of natural gas positions the US as a global energy superpower. "LNG exports will create thousands of US jobs, generate billions of dollars in revenue, improve our trade deficit and spur major investment in infrastructure, which will strengthen our energy security," he said in his testimony. "The question before us is not whether we have the energy we need to grow and prosper. We do," Gerard said, adding: "The question is whether we have the political wisdom and foresight to create a national energy policy that harnesses our great potential as an energy superpower."
Andrew Gellman, the head of chemical engineering for Carnegie Mellon University in Pittsburgh, Pennsylvania, says the real way to gain full value from shale gas is to keep it in the US to use as feedstock for chemical production. "If we ship it out we'll have to buy the chemicals back from whomever gets it," he adds. "It's clear that we want to keep it here and try to process it."
Gellman and Carnegie University have teamed up with the AFPM to deliver a series of discussions entitled the "Manufacturing Renaissance Series," that will focus on the return of manufacturing to the US as a result of increased shale production. The first of these discussions took place on 10 January in Pittsburgh, Pennsylvania, at Carnegie Mellon.
At that meeting, they brainstormed the major issues associated with establishing a significant chemical manufacturing industry based on shale gas. Each issue will be addressed more deeply at upcoming meetings. The next one is set for 4 April in Pittsburgh. As of press time, the topic had not yet been decided. Possible topics that will be addressed include infastructure, research and innovation, education and workforce development, the environment, public policy and financing. But the export of shale resources was definitely a hot topic at the most recent event.
"I think there'll be some real tension between those who are in the business of exporting versus those in the business of adding value," Gellman says. "That tension is certainly going to be there." Further complicating matters is the fact that many companies only a few years ago built terminals to accept natural gas imports. Then the price of natural gas and oil went through the roof and vast stores of untapped resources were suddenly profitable.
"Now that we are no longer in a position to import natural gas, all those terminals are just white elephants, not doing anything," Gellman says. "If there is an opportunity for those companies to use the same terminals to export natural gas, they will certainly want to do that." Additional reporting by ICIS editors Ruth Liao and Joe Kamalick
REFINERY FEEDSTOCKS SHIFT TO LIGHTER CRUDES
The shale boom has caused refiners to rethink capacity projects
Copyright: Roy Luck
Before the peak of demand in 2007 and the recession in 2008-2009, seven new refinery projects were planned to be completed between 2011 and 2015, which would add about 1.1m bbl/day of medium and heavy crude capacity while reducing light capacity by 630,000 bbl/day, according to engineering consulting firm Turner, Mason & Company (TM&C).
However, since the shale oil production boom, refiners have reset course for projects that will increase light crude capacity while maintaining medium and heavy processing capacity.
This will lead to an increase in overall refining capacity.
In addition to several refineries that are maintaining current capacity by processing more light domestic grades and reducing foreign crudes, six new projects have been initiated or planned which will add 108,000 bbl/day of new light crude capacity alone, TM&C said.
Both Valero and Flint Hills have recently announced plans to increase the processing capabilities of Eagle Ford crude at their Houston and Corpus Christi refineries in Texas, respectively, while not changing total crude rates.
Despite growth from heavy Canadian crude growth - and projects at BP's Whiting refinery in Indiana and Marathon's Detroit refinery in Michigan in order to meet increasing mid-continent demand - Canadian crude will not be a major competitor to Latin American heavy crudes on the US Gulf Coast until the Keystone XL pipeline is completed, according to TM&C.
The domestic crudes are displacing light sweet crudes that are available for imports because the import of light sweet is pegged to the Brent price, explains Jeff Hazle, AFPM's senior director of refining technology.
"The effect on prices is dependent on last marginal barrel wherever it's from. This means that there is not going to be a lot of change. Refiners will continue the relationships with foreign importers," Hazle says.
"The real question is, can light sweet domestic production grow to a point where it can completely displace other imports and sustain that level?"
One problem that arises is within the product itself. According to Hazle, there are issues posed by domestic light sweet crudes because they are so paraffinic in chemical composition that they do not mix well with other crudes. This can cause refiners to run into operational problems.
"Refiners will take in as much as they can, but there are potential pitfalls," says Hazle. "It will be an interesting story down the road. Have they gotten everything out of them?"
CURRENT OVERSUPPLY WILL NOT LAST FOR LONG
Propane is enjoying a better winter than last year
Copyright: Sarah Ackerman
AFPM's Cooper says that if the US can keep ethane abundant, it will remain more competitive with other countries. "But it will take a while to build up infrastructure to get the propanes and butanes to petrochemical facilities. Build-up in capacity is different than a grassroots plant," says Cooper.
Ethane is certainly abundant right now, so much so that some processors have resorted to ethane rejection, where it is left in the natural gas stream and used to heat homes and businesses. ONEOK Partners, a natural gas processing company, had to revise its 2013 operating income outlook based on lower expected NGL volumes because of "anticipated widespread and prolonged ethane rejection".
The company said ethane rejection will be commonplace in 2013, adding that it has heard estimates that ethane rejection volumes are between 150,000 and 175,000 bbl/day. "We believe the ethane rejection number is higher, based upon what we've seen from mid-Continent and Rockies plants connected to our NGL systems," says ONEOK president Terry Spencer. "We are currently experiencing over 90,000 bbl/day of ethane rejection across our NGL systems and expect it to remain at those levels for much of this year."
However, he says they expect full ethane recovery during most of 2014 and 2015. "As we move through 2016 into 2017, we anticipate an undersupplied position as ethane demand will increase when these cracker expansions and new world class petrochemical facilities are completed."
Those facilities are projected to add 700,000 bbl/day of demand to the market, he adds. However, William Waldheim, a director for DCP Midstream, says ethane rejection is not as widespread as people think.
"The ethane environment is going to be oversupplied... but I think... it's really that the ethane has been rejected in the disadvantaged areas, which is Wyoming, the Bakken, in those types of areas," he argues. Those areas do not have the infrastructure, such as pipelines, to profitably extract ethane and transport it to the right places.
"So I would generally say that we won't be affected necessarily by ethane rejection. And I just remind everybody that the ethane component of the barrel is only about 10% of its value. We really are looking for a recovery in the price of propane with these export terminals that will be starting as we speak. And actually this summer, with increased propane exports, we would expect propane to begin to move to higher levels, which actually should help the price of ethane as well."
Two companies, Enterprise Partners and Targa, have announced plans to expand propane export facilities, and Vitol along with ConocoPhillips are considering building ports to handle propane exports. Propane is currently oversupplied in the Gulf Coast, as a result of last year's mild winter and increased production. Accordingly, spot prices have been much lower.
In fact, some chemical companies have decided to take advantage of the low price and crack propane instead of ethane.
Analysts say the amount of propane being cracked today is at record levels, although ethane continues to be the feedstock of choice for most petrochemical producers.
AJ Teague, chief operating officer of Enterprise Products, says once the expansion of its export terminal is complete, propane prices should strengthen. "Propane is enjoying a better winter than last year, and its relative weakness, I believe, is a reflection at least in part of the delay in our export expansion," Teague says.
"The 40m bbl we exported last year will grow to over 60m bbl this year." In 2012, Enterprise debottlenecked its existing export facility to add 100,000 bbl/day of capacity. Once the current expansion project is complete, capacity will increase by up to 3.5m bbl/month, bringing the total capacity to 7.5m bbl/month.
"The other thing that I think ultimately helps ethane to some extent is that propane competing with ethane and the crackers, because of the warm winter we had in the last year primarily, you're having a little stronger winter this year. When that export terminal comes up, we're going to be exporting quite a lot more propane," Teague argues. "So I think it will have the tendency to pull propane out of that competition with ethane and the crackers."
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