October 30, 2014 Wilmington, NC – Go Energies just entered the petroleum transport business! For years, Go Energies has been delivering bulk fuel using common carriers. Now, Go Energies has its own bulk fuel transport trailers which enable timely, precise deliveries at a fair price. Currently Go Energies delivers to North Carolina, South Carolina and… Read more »
Posts By: Paul
Phil Dorroll grew up in the fuel industry and remembers the time – not so long ago – when all retail transactions at Go Gas stations, which his father owns, were in cash. Fleet fuel sales were written up on paper tickets. He knew there had to be a better way of managing and tracking… Read more »
A Canadian federal Joint Review Panel recommended that the Canadian federal government approve Enbridge Inc.’s Northern Gateway crude oil export project, subject to 209 required conditions. “We find that the project’s potential benefits for Canada and Canadians outweigh the potential burdens and risks,” the panel said in its report on Dec. 19.
Its decision followed more than 18 months of community hearings. “We are of the view that opening Pacific basin markets is important to the Canadian economy and society,” the report said. “Societal and economic benefits can be expected from the project.
The panel found that environmental burdens associated with the project’s construction and routine operation can generally be effectively mitigated. While some may not despite reasonable best efforts and techniques, “continued monitoring, research, and adaptive management of these issues may lead to improved mitigation and further reduction of adverse effects,” it said.
The report acknowledged that the project may require some people and local communities to adapt to temporary disruptions during construction. It also said that environmental, societal, and economic consequences of a large oil spill, while unlikely and not permanent, would be significant, and urged Northern Gateway Pipelines LP, the Enbridge subsidiary which would build the project, implement appropriate and effective spill prevention measures and spill response capabilities.
“It is our view that, after mitigation, the likelihood of significant adverse environmental effects resulting from project malfunctions or accidents is very low,” the report said. “For all of the above reasons, we are of the view that, overall, the Enbridge Northern Gateway Project, constructed and operated in full compliance with the conditions we required, is in the Canadian public interest. We find that Canadians will be better off with this project than without it.”
Project’s route, capacity
The $6.5 billion (Can.) twin pipeline would run 1,177 km (732 miles) from oil sands production facilities in northern Alberta to the Kitimat deepwater port at the head of Douglas Channel in British Columbia. The proposed project would transport 525,000 b/d of crude oil for export and import 193,000 b/d of condensate.
The Northern Gateway Project team filed its formal application with the JRP in May 2010, and has been engaged in outreach with Aboriginal groups and stakeholders for more than 10 years, Enbridge said on Dec. 19. The team is studying the panel’s recommendations in advance to the Canadian government’s final decision, which is expected by July 2014.
“From the beginning of this project, Northern Gateway has worked with one goal in mind: to access new markets by building a safer, better pipeline,” said Janet Holder, the project’s leader. “The [JRP] conducted the most comprehensive and science-based pipeline review in Canadian history and their report reflects the input of thousands of Canadians. Their report is an important step towards that goal.”
She said the Northern Gateway Project team will work to meet the JEP’s conditions, as well as the 5 conditions for heavy oil pipeline development British Columbia Premier Christy Clark has imposed, of which the Panel’s recommendation is one.
The project’s opponents emphasized that the JRP’s decision is an important part of the review process, and should not be considered as final approval for it. “The fact is this pipeline will never be built,” Danielle Droitsch, the Natural Resources Defense Council’s Canada Project director, said on Dec. 20. “[Canadian Prime Minister Stephen Harper] needs support from First Nations and a social license to build this pipeline – and he has neither.”
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Natural gas prices climbed steeply in Dec. 19 trading on the New York market following the release of a government report showing a record weekly withdrawal of gas from underground storage, which analysts attributed to cold temperatures across the country in recent weeks.
The US Energy Information Administration reported a decline of 285 bcf for the week ended Dec. 13 (OGJ Online, Dec. 19, 2013). Because of the upcoming Christmas holiday, the next EIA gas storage report will be released Dec. 27, one day later than normal.
In January, Fed officials plan to trim $10 billion/month from their economic stimulus program. The program has supported crude oil prices by weakening the dollar, making oil cheaper to buy with other currencies. Currently, the Fed spends $85 billion/month in its bond-purchase program.
“The taper announcement is having a positive impact on equities markets, and crude oil is going along for the ride,” Stephen Schork, editor of the Schork Report, told the Wall Street Journal.
Heating oil for February delivery climbed 1.8¢, settling at a rounded $3.03/gal. Reformulated gasoline stock for oxygenate blending for January delivery was up 4.3¢ to a rounded $2.74/gal.
The January natural gas contract on NYMEX rose 20.9¢ to settle at $4.46/MMbtu. On the US spot market, the gas price at Henry Hub, La., increased 1.1¢ to a rounded $4.27/MMbtu.
In London, the February ICE contract for Brent crude oil climbed 66¢, closing at $110.29/bbl. The ICE gas oil contract for January was up $6.25 to settle at $935.25/tonne.
The Organization of Petroleum Exporting Countries’ basket of 12 benchmark crudes closed at $107.49/bbl on Dec. 19, up 75¢.
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A Chesapeake Energy Corp. subsidiary agreed to spend $6.5 million to restore 27 sites damaged by unauthorized discharges of fill material into streams and wetlands at its West Virginia natural gas production sites to settle charges that it violated the Clean Water Act, the US Department of Justice and Environmental Protection Agency jointly announced on Dec. 19.
They said Chesapeake Appalachia LLC also agreed under the settlement to implement a comprehensive plan to comply with federal and state water protection laws, and to pay a $3.2 million civil fine. That amount is one of the largest ever imposed for violating the CWA’s Section 404 program, which prohibits the filling or damming of wetlands, rivers, streams, and other US waters without a federal permit.
The federal government and West Virginia’s Department of Environmental Protection (WVDEP) alleged the company impounded streams and discharged sand, dirt, rocks and other fill material into streams and wetlands without a federal permit in order to construct well pads, impoundments, road crossings and other facilities related to gas extraction.
A Chesapeake Energy spokesman said the settlement represents a key milestone in resolving federal and state claims relating to surface construction activities which occurred in West Virginia before November 2010. “The company is fully committed to regulatory compliance and is working with EPA, the Army Corps of Engineers, and WVDEP to restore the impacted sites,” he said in a Dec. 19 e-mail.
The alleged violations occurred at 27 sites, including 16 which involved hydraulic fracturing, and involved about 12,000 linear ft of stream, or about 2.2 miles, and more than three acres of wetlands, DOJ and EPA jointly said.
They said Chesapeake Appalachia will be required to fully restore the wetlands and streams wherever feasible, monitor the restored sites for up to 10 years to assure the restoration’s success, and implement a comprehensive compliance program to ensure future compliance with the CWA and applicable state law.
To offset the impacts to sites that cannot be restored, the company will perform compensatory mitigation, which will likely involve purchasing credits from a wetland mitigation bank located in a local watershed, the two federal entities said.
EPA said it discovered some of the violations through information provided by the public and routine inspections. Chesapeake Appalachia also voluntarily disclosed potential violations at 19 of the sites following an internal audit. EPA issued administrative compliance orders for violations at 11 sites in 2010 and 2011. Since that time, the company has been correcting the violations and restoring those sites in full compliance with EPA’s orders, the agency said.
The settlement also resolves alleged violations of state law brought by WVDEP, the two federal entities said. The state is a co-plaintiff in the settlement and will receive half of the civil penalty, they said.
A consent decree, which was lodged Dec. 19 in US District Court for West Virginia’s Northern District, is subject to a 30-day public comment period and court approval.
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Peruvian President Ollanta Humala Tasso has enacted legislation that mandates a long-planned modernization and upgrade of the Talara refinery be completed by 2017 on the grounds of public necessity and national interest.
The bill, signed into law on Dec. 17, outlines a 4-year modernization megaproject at Talara that will cost an estimated US $3.5 billion, according to a release from the Peruvian government.
State-owned Petroperu will invest $2.7 million, while private companies involved in the construction and operation of new service units for the upgrade will invest the remaining $765 million, Humala said.
Following completion of the modernization project, which is slated to run from 2014 to 2017, crude oil processing capacity at Talara will rise to 95,000 b/d from its current capacity of 60,000 b/d, according to Humala.
Previous plans to modernize the Talara refinery, located at Piura, 1,200 km north of the country’s capital, Lima, faced a series of delays due to allegations of political corruption in the bidding process (OGJ Online, Oct. 13, 2008; Jan. 28, 2008; May 5, 2003).
Having adopted its first energy reforms since 1960, when it increased already major barriers to private sector participation, Mexico will try now to temper expectations as it reverses course and implements changes that include bigger roles for outside companies, an official of its government said.
“This set of reforms is not aimed at privatizing [national oil company Petroleos Mexicanos], which most people in Mexico oppose, but in reducing energy costs, which most people favor,” said Enrique Ochoa Reza, the Mexican energy ministry’s undersecretary of hydrocarbons during a Dec. 19 discussion at the Atlantic Council.
Congress passed constitutional amendments essential to reform earlier this month (OGJ Online, Dec. 13, 2013). A majority of Mexico’s states ratified changes in Articles 25, 27, and 28 of the national constitution authorizing the reforms, and President Enrique Pena Nieto said he will enact them soon. Pemex has 90 days after they are published to indicate where it wants to keep working, after which the energy minister will have 180 days to respond, Ochoa said.
Private-company participation in exploration and production, which has been confined to service contracts, will expand to profit and production sharing. “Refining and petrochemicals, which were closed, now will be open,” said Ochoa. “So will transportation, storage, and distribution.”
Systems in trouble
Change was possible because growing numbers of people recognized the country’s energy systems were in serious trouble, according to Ochoa. Crude oil production had dropped by 1 million b/d over 10 years, natural gas imports had climbed from 3% of consumption in 1997 to 30% in 2012, gasoline imports had risen from 25% to 44% of supply, and petrochemical imports had climbed from 41% to 66%.
With electricity costing 25% more than the US average and much higher gas prices, manufacturers have been leaving Mexico, Ochoa said, adding: “It’s as much an economic as an energy issue.”
How Mexico implements its energy reforms will be crucial, other speakers agreed. “In the course of a year, Mexico managed a formidable accomplishment,” said David L. Goldwyn, president of Goldwyn Global Strategies LLC and former international energy security coordinator at the US State Department. “If it succeeds, it could be a major producer again by 2025.”
In addition to allowing more private investment, he said, the reforms separate energy policy from industry supervision; establish a new set of autonomous and independently funded licensing, safety, and environmental regulators; develop an independent electricity system and an agency to ensure open access for gas transportation; and create a new and transparent national petroleum fund to be managed by the country’s central bank.
“It will ensure the government’s share of hydrocarbon revenue is capped, resources are shared with current and future generations, research and development is encouraged, and a rainy day reserve is available,” Goldwyn noted in a new report, Mexico Rising: Comprehensive Energy Reform at Last, which the Atlantic Council released on Dec. 19.
“There’s been a paradigm shift since 2005, when the US mainly was concerned about finding new supplies,” said Duncan Wood, director of the Mexico Institute at the Woodrow Wilson Institute for Scholars. “Now, it’s on the verge of becoming a significant oil and gas exporter, while Canada is moving ahead with its own exports. Real North American energy market integration seems possible. Mexico’s reforms would be icing on the cake.”
Jorge R. Pinon, associate director of the Latin American and Caribbean Program at the University of Texas at Austin’s Center for International Energy and Environmental Policy, said, “Pemex won’t go away. It won’t be privatized either. It may be recapitalized along the line of Petrobras and Ecopetrol, but it will need to move carefully and be re-engineered.”
He warned the company also “faces a possible brain drain as many of its engineers and geologists retire and others go to work for private companies that come into Mexico as a result of these reforms. Pemex also might need to seek joint ventures downstream since Mexico imports $20 billion/year of oil products and natural gas, Pinon said.
Ochoa said Mexican gasoline imports don’t benefit consumers because competition with Pemex hasn’t been allowed. “We see private branding possibly being allowed as part of the next legislation. We’re looking for a major change downstream, but it will take time,” he said.
Goldwyn said legislation, budgets, outsourcing, and leadership will be important benchmarks for Mexico in the next 6 months. He noted that after the Macondo deepwater well accident and crude oil spill in 2010, US President Barack Obama brought in Michael R. Bromwich to make necessary major offshore oil and gas regulatory changes. “Mexico may need to do something similar,” he said.
More support needed
Wood said regulation will be especially important. “There now is a very small, underfunded hydrocarbons agency that is being asked to bring the right people in,” he said. “It will need much more support.”
Many US universities have relationships with Mexico’s government and private companies and potentially could contribute, Pinon observed.
“Independence is a major issue,” Ochoa conceded. “Upstream and downstream regulators must have it. They will be allowed to keep up to 3 years of their budgets in a trust fund so they can keep operations consistent. The biggest change will be that regulation will move out of Pemex.”
Transparency also will be essential, the speakers agreed. “The industry welcomes it across the whole process,” said Pinon. “It already has to share a lot of data. Good governance where it operates also is important. I think Mexico has gone through a major cultural change which makes this possible.”
Ochoa said, “There’s a full commitment to transparency in this administration. We looked at how other governments do it. More important, the Mexican people want it.” Outside companies should be able to book their reserves from joint ventures, he continued.
Goldwyn added, “If they can’t, they won’t invest.”
He said Mexico will need to manage expectations. “There are indications benefits won’t accrue for 3-5 years, yet the government went ahead anyway because it felt it was necessary. These reforms, while impressive, won’t do the entire job, but there’s no turning back now.”
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OMV has agreed to sell its 45% interest in the Bayernoil refining complex near Ingolstadt, Germany, and related businesses to Varo Energy BV, a midstream company owned by The Carlyle Group and Vitol Group. Terms weren’t disclosed.
The Austrian company has been seeking a buyer for the interest for 2 years to focus on exploration and production and refining strongly integrated with petrochemical manufacture (OGJ Online, Jan. 13, 2012).
The 215,000-b/d Bayernoil complex has integrated plants at Vohburg and Neustadt.
The transaction with Varo Energy also includes related inventory, a bitumen plant, and the Bayernoil wholesale business.
OMV will continue to operate refineries in Schwechat, Austria; Burhausen, Germany; and Petrobrazi, Romania.
Vitol and Carlyle International Energy Partners (CIEP) each will own 50% of Varo Energy after AtlasInvest sells its share to CIEP and Vitol reduces its current stake.
Varo Energy will acquire from Vitol all shares in PT Holdings GMBH, the holding company for Petrotank Neutrale Tanklager GHBJ and all shares in Vitol Germany GMBH.
After completion of the transactions, Varo Energy will have interests in refining, wholesale distribution, and storage.
In addition to the Bayernoil interest, Varo Energy owns the 68,000 b/d Cressier Refinery near Neuchatel, Switzerland, which it bought in mid-2012 from Petroplus Holdings and restarted earlier this year (OGJ Online, May 3, 2012).