In response to Hurricane Isaac, EIA invoked its emergency-activation survey Form EIA-757B to collect daily data on the status of natural gas processing plant operations.
The survey, completed Friday, September 7, showed that Hurricane Isaac caused considerable disruption to processing infrastructure, although it had a negligible effect on natural gas prices because of ample onshore production and surplus storage.
The last time EIA invoked Form EIA-757B was for Hurricane Ike in September and October 2008. Hurricane Isaac made landfall on the evening of August 28, 2012, and ultimately disrupted natural gas processing operations for more than 10 of the 13.5 billion cubic feet (Bcf) per day of total processing capacity in the affected area. The survey captured plants with capacities greater than 100 million cubic feet per day.
The bar chart shows five items:
- Operational capacity (green): Sum of capacity of natural gas processing plants in the path of Isaac that was operating at normal levels
- Reduced capacity (yellow): Capacity that was processing gas at a reduced rate relative to pre-Isaac levels
- Ready to resume capacity (orange): Capacity that was able to process natural gas but was not currently receiving adequate volumes of gas from upstream to justify starting up the plant, or did not have a downstream delivery point able to accept its products
- Shut-in capacity (red): Capacity that was unable to process gas because of damaged plant infrastructure or power outages
- Maintenance capacity (brown): Capacity that was shut down for maintenance because of reasons unrelated to Isaac
Data collected on this survey are compiled with other data and used to provide critical information on the status of energy infrastructure to policy makers, emergency response teams, media, individuals, and businesses in the U.S. Department of Energy’s Situation Report.
Just prior to Isaac making landfall, there were 25 natural gas processing plants in the affected area that were not undergoing maintenance, accounting for 12.6 billion cubic feet per day of available processing capacity. However, widespread power outages (affecting nearly 890,000 customers in Louisiana), reduced gas flows, and the potential for flooding reduced or curtailed operations at many of these plants. Plants most commonly attributed closures to a lack of upstream supply, although a few also cited damage to downstream infrastructure that would receive their dry gas or their natural gas liquids products.
Processing facilities play a key role in the overall natural gas supply chain because they purify and “dry out” raw natural gas from producing wells. This process results in pipeline-quality natural gas for delivery to end-users and a mix of natural gas liquids products to be separated by fractionators.
The Department of Interior’s Bureau of Safety and Environmental Enforcement’s final update on the effects of Isaac on offshore oil and natural gas operations, released on September 11, 2012, indicated that less than 5% of Gulf of Mexico oil and natural gas production remained shut in.
The Federal Gulf of Mexico has accounted for a progressively smaller share of U.S. natural gas production in recent years. This is because of steadily declining offshore production volumes in the Gulf, combined with growth of shale gas production in various onshore basins and improved pipeline infrastructure to deliver that gas to market.
In 2000, Federal GOM gross natural gas production accounted for more than 20% of total U.S. gross natural gas production; in 2011, Federal GOM represented only 6% of total U.S. gross natural gas production. As a result of these historically low levels of offshore production, increases in onshore production, and strong natural gas storage stocks, Isaac-related shut ins have had little effect on natural gas prices or on gas supply for areas outside the path of the hurricane.
The U.S. shale boom has driven the cost of Gulf Coast light, sweet oil to its lowest level versus Brent crude in almost a quarter century as the nation’s dependence on foreign supplies wanes.
Light Louisiana Sweet, the benchmark grade for the Gulf Coast known as LLS, has traded on the spot market at an average of 15 cents a barrel more than Brent this year, the smallest premium since at least 1988, data compiled by Bloomberg show. The spread’s highest annual average was $4.02 in 2008.
The drop has cut costs for refiners in Texas and Louisiana accounting for 45 percent of U.S. capacity and replaced competing shipments from Africa. Gulf imports of light, sweet crude have fallen 56 percent since 2010, according to U.S. Energy Department data. A shale-oil influx from the Eagle Ford formation in Texas and Bakken in North Dakota and new ways to bring crude to the Gulf, such as this year’s reversal of the Seaway pipeline, may accelerate the shift.
“The market dynamics are changing,” Edward L. Morse, head of commodities research at Citigroup Global Markets in New York, said in a telephone interview. “When the Gulf Coast was a crude importer, they had to attract crude from elsewhere in the world, which meant LLS had to be at a premium to Brent. But now we’re moving into a totally different situation.”
Light Louisiana Sweet, a grade prized because its low- sulfur content and density make it easier to process into fuels such as gasoline, was 92 cents cheaper than Brent yesterday. It averaged 20 cents less than the benchmark in the third quarter.
Brent oil for October settlement rose 40 cents, or 0.4 percent, to $113.49 a barrel yesterday on the London-based ICE Futures Europe exchange. The contract advanced as much as 0.5 percent to $114.05 in trading today.
U.S. oil output surged to the highest level in 13 years in July, according to weekly Energy Department data. The U.S. met 83 percent of its energy demand from domestic sources in the first five months of this year and is heading for the highest annual level since 1991, department figures compiled by Bloomberg show.
“Unconventional oils and gas are changing everything about our competitiveness in the United States,” Bill Klesse, Valero Energy Corp.’s chief executive officer, said yesterday at the Barclays CEO Energy/Power Conference in New York. “Before you know it, we’re going to have so much light, sweet crude that in the U.S. Gulf Coast we’re not going to be importing light, sweet crude, and we think that happens next year.”
Houston, New Orleans and other ports along the Gulf Coast accepted about 554,000 barrels a day of light, sweet oil from outside the U.S. in June, down from 964,000 barrels a day in June 2011 and about 1.25 million in June 2010, according to the Energy Department’s Energy Information Administration.
The West African nations of Nigeria, Angola, Gabon and Equatorial Guinea accounted for 58 percent of the light, sweet crude imported into Gulf Coast ports in June 2012. North African nations accounted for a further 30 percent.
LLS will become about $5 a barrel cheaper than Brent during the next 12 months, David Pursell, a Houston-based managing director for Tudor, Pickering, Holt & Co., said in a telephone interview. The discount would take into account the extra cost of getting LLS to other customers, such as refiners on the East Coast, Pursell said.
Like oil in the Midcontinent, the relationship between LLS and Brent has been upended by surging shale production. West Texas Intermediate oil at Cushing, Oklahoma, the U.S. benchmark grade traded on the New York Mercantile Exchange, shifted to a discount to Brent almost two years ago after trading at a premium for decades.
Cushing inventories surged to 47.8 million barrels in June, the highest level since Energy Department records for the hub began in 2004. The WTI-Brent spread reached a record $27.88 in October. It was at $18.03 a barrel today.
“Over the last year and a half, with the WTI-Brent spread blowing out, the primary beneficiaries have been the Midcontinent players,” Cory Garcia, a Houston-based oil analyst for Raymond James & Associates, an arm of the financial-services company with almost $40 billion under management, said in a phone interview. “As LLS disconnects next year, the benefits to Gulf Coast refiners will be brought to the forefront.”
Enbridge Inc. (ENB) and Enterprise Products Partners LP (EPD) reversed the flow of crude on the Seaway pipeline on May 19. The link, carrying as much as 150,000 barrels a day from Cushing to Gulf Coast refineries, is scheduled to pump as much as 400,000 barrels a day early next year.
- Report: Shale boom revamping U.S. refining industry (fuelfix.com)
- Gulf of Mexico production ramps up after Isaac (fuelfix.com)
(RTTNews.com) – Enterprise Products Partners L.P. (EPD) and Enbridge Inc. (ENB, ENB.TO) said Thursday that modifications to the Seaway crude oil pipeline allowing it to transport crude oil from Cushing, Oklahoma to the U.S. Gulf Coast have been completed.
According to the companies, the pipeline is in the process of being commissioned, and the first flows of crude oil into the line are expected to begin this weekend.
The reversal of the 500-mile, 30-inch diameter pipeline, which had been in northbound service since 1995, provides North American producers with the infrastructure needed to access more than 4 million barrels per day of Gulf Coast refinery demand.
The reversal will initially provide 150,000 BPD of capacity, which is expected to increase to more than 400,000 BPD in the first quarter 2013 with additional modifications and increased pumping capabilities.
Seaway Crude Pipeline Company LLC is a 50/50 joint venture owned by affiliates of Enterprise Products Partners and Enbridge Inc. In addition to the pipeline that transports crude oil from Cushing to the Gulf Coast, the Seaway system is comprised of a terminal and distribution network originating in Texas City.
For comments and feedback: contact firstname.lastname@example.org
Josh Lewis , 27 March 2012 04:45 GMT
The addition will increase the capacity of the pipeline by 450,000 barrels per day to 850,000 bpd.
Enbridge said the expansion was supported by additional commitments received during the supplemental binding open commitment period, with terms ranging from five to 20 years.
Enbridge also announced it planned to proceed with the expansion of its Flanagan South project which would add incremental capacity for shippers seeking transportation from Flanagan, Illinois, to the US Gulf Coast.
The Flanagan South pipeline will also be used to transport some of the additional commitments for the Seaway pipeline from Flanagan to the Seaway System.
“Expansion of the Seaway pipeline, along with Enbridge’s Flanagan South project, will provide crude oil producers in the Bakken region and other emerging crude oil sources capacity to move secure, reliable supply to US Gulf Coast refineries, offsetting supplies of imported crude,” Enbridge chief executive, Pat Daniel, said in a statement.
Enbridge said the first phase of the reversal of the Seaway pipeline was nearing completion and would provide 150,000 bpd of southbound takeaway capacity from Cushing to the Gulf Coast by 1 June.
It added pump station additions and modifications, which are expected to be completed by the first quarter 2013, would increase capacity to 400,000 bpd, assuming a mix of light and heavy grades of crude.
- Seaway – Echo terminal link planned (mb50.wordpress.com)
(Reuters) – The U.S. Strategic Petroleum Reserve is not quite as strategic as it used to be.
As President Barack Obama moves closer to an unprecedented second release of the U.S. emergency oil stockpile in a bid to bring down near-record fuel prices, experts say dramatic logistical upheavals in the U.S. oil market over the past year may now make such a move slower and more complicated.
Moving to tap the four giant Gulf Coast salt caverns that hold 700 million barrels of government-owned crude would still almost certainly knock global oil futures lower, delivering some relief at the pump for motorists and helping Obama in the November election if he can prevent gasoline from rising above $4 a gallon nationwide.
On Thursday, prices fell by as much as $3 a barrel after Reuters reported that Britain was set to agree to release stockpiles together with the United States later this year. UK officials said the timing and details of the release would be worked out prior to the summer, when prices often peak.
But the logistics of getting that crude oil to willing refiners are more complicated than ever.
The reversal of a major Texas-to-Oklahoma pipeline will lower the distribution capacity of the SPR’s largest cavern, according to John Shages, who oversaw the U.S. oil reserves during the Bush and Clinton administrations. A resurgence in domestic oil output and the potential closure of the East Coast’s biggest refinery is curtailing demand for crude.
There is little doubt that SPR oil would eventually find buyers, since it is basically auctioned to the higher bidder. But it may move more slowly than the government hopes.
“The logistical system in the United States is shifting,” said Guy Caruso, the former head of the Energy Information Administration. “That probably is going to cause SPR officials to rethink how that oil would be distributed especially in an extreme scenario.”
The mechanics of the release may prove almost as tricky for Obama as rallying international support for a second intervention in as many years, or fending off attacks from Republicans who will likely brand it as a pre-election gimmick.
The U.S. shale oil boom and rising imports of Canadian oil sands crude have transformed the U.S. energy landscape, with industry now scrambling to move a glut of oil from the center of the country down to the U.S. Gulf Coast — reversing historical trends that were the basis for the SPR’s original planning.
The nation’s emergency oil stockpile, created by Congress in the mid-1970s after the Arab oil embargo, was designed to transport oil primarily via pipeline from the Gulf to refineries in the area and to buyers further north.
“The fact that pipelines go south and not north is a major change,” says Edward Morse, global head of commodities research at Citigroup and a former energy expert at the State Department.
The Department of Energy says the SPR can distribute crude to 49 refineries with a capacity of more than 5 million barrels per day — about one-third the U.S. total — and five marine terminals. It is designed to be capable of releasing oil within two weeks of an order, and to sustain a rate of 1 million bpd for as long as a year and a half, enough to meet 5 percent of U.S. demand.
Today it can discharge oil at a maximum rate of 4.25 million bpd, just below its 4.4 million bpd design capacity, a department official said. The reduction was due to a damaged storage tank.
Industry analysts, however, are skeptical.
Morse says that the maximum rate now appears unachievable, and that logistical problems constrained the government’s release of 30 million barrels of oil last summer — its largest ever — in response to the disruption of Libyan oil supplies.
Oil from the reserves must compete with crude already being transported via pipeline or tanker, often on crowded waterways, so there may not be enough capacity in the system to immediately take in millions of additional barrels of oil.
The Energy Department released an average of 743,000 bpd last August.
The department said it conducts thorough assessments of commercial capabilities to move oil from the reserves on a routine basis and remains confident it could supply the market with 4.25 million bpd if needed.
Many analysts doubt that much would ever be needed at once.
“Absent a serious disruption of great magnitude, it is inconceivable that the U.S. would draw down its inventory of SPR at the maximum rate,” said Shages, who now runs his own firm, called Strategic Petroleum Consulting, LLC.
Even so, the system now has less flexibility.
The move to reverse the flow of the 350,000 bpd Seaway Pipeline to move crude oil from Cushing, Oklahoma, where there is a glut, to Gulf Coast refineries will almost certainly hurt the distribution capability of the SPR’s Bryan Mound storage tank in Freeport, Texas, says Shages.
Bryan Mound is the largest of the four sites, capable of holding about a third of the SPR’s total crude. About 43 percent of last year’s release came from Bryan Mound, data show.
After operator Enterprise Products completes the process of reversing the line by June, it will be limited to shipping crude via two Gulf of Mexico terminals and a system of local pipelines into Houston area refineries.
But Bryan Mound will still be able to discharge crude at a rate of 1.25 million bpd, according to an energy department official.
“When the pipeline is reversed, the distribution capability of crude from the SPR site will still be nearly 25 percent more than the site’s maximum drawdown rate, ensuring more than sufficient distribution capability,” the official said.
The Capline from Louisiana to Illinois, the largest such south-to-north pipeline, in theory has plenty of spare capacity since it has been running at less than a quarter of its 1.2 million bpd — but that is because a glut of Canadian and North Dakota crude is already sating the big Midwest refiners.
Meanwhile Gulf Coast plants are filling up on growing output from the Eagle Ford shale in Texas, reducing import demand. Because most U.S. crude oil cannot legally be exported, SPR supplies will typically only displace seaborne imports.
U.S. crude oil imports into the Gulf Coast region, known as Padd 3, fell 8 percent last year to below 5 million bpd, the lowest level since the 1990s.
Last year, at least some of the crude released from the SPR traveled further afield, beyond the Gulf Coast.
Tesoro, whose only refineries are on the West Coast, bought 1.2 million barrels, while East Coast refiner Sunoco bought 1.4 million barrels. Obama issued 44 waivers to the Jones Act to allow companies to use non-U.S. tankers for shipments last year.
But the East Coast looks a less likely market this year. Sunoco is set to close its 335,000 bpd Philadelphia refinery before June if it does not find a buyer. That could cut the region’s capacity to less than 700,000 bpd.
Ultimately the rate of release means little if you cannot get the oil quickly to those who need it most, says Mark Routt, a senior oil market consultant at KBR Advanced Technologies.
“To say that you have this drawdown capability, but you’re putting oil in places it doesn’t need to go, isn’t really helpful to the market,” Routt said.
- Tapping oil from the SPR may be trickier than ever (business.financialpost.com)
- Is China’s SPR soaking up all the oil? (business.financialpost.com)
- Is The SPR Release Already Priced Into Oil Prices? (zerohedge.com)
- Obama, the politics of the SPR and energy (lack of) exploration! (politicsandfinance.blogspot.com)
- U.S. lawmakers worry about East Coast refining capacity – Financial Post (business.financialpost.com)
- Seaway – Echo terminal link planned (mb50.wordpress.com)
- A Brief History of the U.S. Strategic Petroleum Reserve [OIL LOANS, OIL SALES] (ibtimes.com)
News wires 02 March 2012 02:57 GMT
The proposed pipeline would be about 40 miles long, Enbridge executive Brad Shamla told Reuters.
“We are shipping crude out over a dock to other destinations on the Gulf Coast,” he said.
Shamla said that pipeline will be about 80 miles in length and be done in 2014.
The plan was announced as the companies continued their purging of the 500-mile Seaway pipeline, which they said was ahead of schedule.
The pipeline will begin by carrying 150,000 barrels per day by 1 June from the oil hub of Cushing, Oklahoma, to Gulf Coast refineries, said Shamla.
The pipeline is the first of several projects to siphon the glut of crude oil sitting in Cushing to the refineries along the Gulf Coast.
The reversed Seaway pipeline capacity is expected to grow 400,000 bpd in 2014 but could increase more if the current open season seeking more firm shipping commitments is successful, Reuters reported.
- Seaway pipeline creates contango with oil glut (mb50.wordpress.com)
- TransCanada to Build Keystone XL Leg (TRP, ENB) (247wallst.com)
- Seaway crude oil pipeline purging for reversal (business.financialpost.com)
- Rail and Pipeline expansions and project to move more Bakken Oil from North Dakota and Saskatchwan (nextbigfuture.com)
- Oil Pipeline from Cushing, Oklahoma to the Gulf Coast will continue (oklahomarealestate.wordpress.com)
- Enbridge, Enterprise advance Gulf Coast pipelines (business.financialpost.com)
Sunoco‘s Philadelphia refinery is on the banks of the Schuylkill River. The company plans to pull out of the refining business altogether, which could help put the Northeast region in a precarious position. Photo: MIKE MERGEN / HC
Northeastern states are slated to lose half of their regional capacity for fuel production by midyear as financial woes push refineries there to idle, a trend likely to increase the region’s dependency on Gulf Coast supply.
A Houston-to-New York pipeline is making major expansions to accommodate growing demand to transport gasoline and other fuels up north from the Gulf Coast to fill the potential supply void.
The Gulf already supplies about half of the Northeast’s demand for petroleum products, said Mindi Farber-Deanda, head of the liquid fuels market team for the U.S. Energy Information Administration.
But the shutdown of production at two major Pennsylvania refineries last year and potential closure of a third could put the region in a precarious position and stress supplies of gasoline, jet fuel and heating oil, the agency concluded in a new report.
“It’s marginal, but it matters,” Farber-Deanda said of the drop in the Northeast’s local fuel production. “Before, you could get a certain percentage of supply from local refineries. Now you get it from Europe and the Gulf.”
The report noted that Northeastern states could experience “spot shortages with price hikes” for gasoline and other fuels as refineries discontinue operations.
Sunoco announced last month that it will idle operation of its 335,000 barrel-per-day refinery in Marcus Hook, Pa., part of the company’s plan to pull out of the refining business altogether. If Sunoco doesn’t find a buyer for its 178,000-barrel-per-day Philadelphia refinery by July, it will go off line, too, the company has said.
ConocoPhillips announced a similar move in September, taking its 185,000-barrel-per-day Trainer, Pa., refinery off line to prepare it for sale.
A combination of the sagging economy and improved fuel efficiency in vehicles and equipment has caused demand for some fuels to plateau. Meanwhile, competition from larger and more efficient refineries on the Gulf Coast and imports from Europe put pressure on local fuel producers, said Bill Day, a spokesman for San Antonio-based refiner Valero.
“They found it very difficult to compete,” he said. “If there was demand for product there, those refineries wouldn’t close down.”
Valero pulled out of the Northeast in 2010, when it sold its Delaware City, Del., and Paulsboro, N.J., refineries.
The struggling European economy has left refiners on the continent with plenty of gasoline to ship overseas.
Cleaner heating oil
A bigger concern for the Northeast is heating oil.
Demand for ultra-low-sulfur heating oil is expected to rise next fall, when regulations taking effect in New York will require use of the cleaner fuel in boilers that warm buildings. A limited number of refineries are equipped to produce it.
“Heating oil concerns are probably the greatest,” said Terry Higgins, executive director of refining for consulting company Hart Energy. “A cold snap, with a strong surge on heating oil needs, could be a strain on the system.”
Room to grow
The Gulf Coast is replete with refineries that are expanding or have room to increase production, he said. Motiva Enterprises, a joint venture of Shell and Saudi Aramco, is nearing the end of a massive expansion of its Port Arthur refinery to increase production of ultra-low sulfur fuel and other petroleum products.
In 2010, Gulf Coast area refiners produced a net 3.4 million barrels per day of ultralow-sulfur distillate fuel oil, a category that includes the clean heating oil, according to Energy Information Administration data. That’s up from just 23,000 barrels per day in 2005.
Colonial Pipeline, a major thoroughfare for shipping fuels from Gulf Coast refineries to East Coast markets, has seen growing demand from refiners to ship larger amounts of its products north, spokesman Steve Baker said.
The 5,500-mile pipeline transports heating oil, as well as gasoline, diesel fuel and other petroleum products.
Last year, Colonial added 120,000 barrels per day of carrying capacity to its system. By mid-2012, it will have expanded the flow of distillates – including heating oil, jet fuel and diesel – by another 55,000 barrels per day. In December, the company announced it would expand its gasoline transport capacity by another 100,000 barrels per day.
In total, the expansions will increase the system’s capacity by about 8 percent, Baker said.
“We have seen a rising demand throughout the year” for fuel transport between the Gulf Coast and the Northeast, Baker said. “These are big capital investments. It’s a significant increase.”
- Gasoline May Rise Above $4 a Gallon as Northeast Plants Shut (businessweek.com)
- Gas could soar past $4 per gallon by summer, analyst says (nj.com)
- Refining Sector Woes Going From Challenging To Worse (TSO, VLO, MPC, WNR, CVI, XOM, CVX, COP, BP) (247wallst.com)
- Amid fears of price spikes, Dems press Chu to fill Northeast oil reserve (thehill.com)
By unanimous consent, the House on Friday approved a bill that permits three LNG tankers to participate in “coastwise” trade – carrying cargo between U.S. ports. The Senate approved the legislation on Thursday.
The Mariner Project, a joint venture between Sunoco Logistics Partners L.P. and MarkWest Energy Partners L.P., would transport ethane produced from the Marcellus Shale by pipeline to Marcus Hook and then by sea to the Gulf Coast, where ethane is used to make plastics.
Because there are no qualified U.S.-flagged LNG vessels available to carry the fuel between Marcus Hook and the Gulf Coast petrochemical plants, the Mariner Project needed a waiver to the Jones Act, the 1920 law that protects markets for U.S. vessels.
U.S. Sen. Pat Toomey and U.S. Rep. Pat Meehan, whose district includes Marcus Hook, promoted the Jones Act waivers. The Republicans argued the project would generate 300 to 400 new construction jobs and 25 long-term jobs to operate the shipping terminal.
The three LNG tankers are American-built, American-owned vessels that now fly foreign flags. Reflagged as U.S. vessels, the ships must also employ U.S. crews and be maintained in America.
Toomey and Meehan had steered the three LNG tankers into special legislation that was being rushed through Congress to allow 60 foreign ships to participate in the America’s Cup sailboat race. The bill appeared to have smooth sailing ahead.
But as the legislation landed in the House this month, it became freighted with five additional vessels whose sponsors also sought Jones Act waivers. That caused delays.
The American Maritime Partnership, a lobbying group of U.S. transporters and shipbuilders, objected to the five vessels, saying they “could have an adverse competitive impact on existing operators in the coastwise trade.”
Legislators agreed this week to remove two of the vessels, allowing for the bill’s passage.
The maritime association, in a letter to lawmakers, said it did not object to the three LNG tankers because they “present a unique situation insofar as there are no coastwise-qualified U.S.-flag vessels that would compete against those ships.”
But Sunoco’s project is not a sure bet. Energy analysts say the sea route will have a hard time competing with proposals to move ethane cross-country by pipeline, the cheapest mode of transport.
- Canada: Encana Optimistic About LNG Exports (mb50.wordpress.com)
- ExxonMobil Eyes North American LNG Exports (mb50.wordpress.com)
- Japan hopes to buy LNG from U.S. by 2015 (mb50.wordpress.com)
- Chesapeake CEO Opposes US LNG Exports (mb50.wordpress.com)
- Petronet in Talks to Buy Capacity at US, Australia LNG Terminals (mb50.wordpress.com)
- USA: Sempra to Pursue Tolling Fee for Cameron LNG Export Scheme (mb50.wordpress.com)