Refineries UPDATE
December 2011
McIlvaine Company
TABLE OF CONTENTS
N.D. Tribes Seeking Proposals for 15,000-Barrel per Stream Day Refinery
BP Agrees to $50 Mln Texas City Refinery Fine
EPA Proposes Significant Changes to MRR and BAMMs
Keystone XL Delay Causing Concern among Big Oil, Benefiting Small Refiners
Use of Fraudulent Renewable-Fuel Credits Investigated by EPA
EPA will Delay Carbon Limits on Oil Refineries
North Dakota’s Bakken Shale to Get First New U.S. Oil Refinery in 35 Years
HollyFrontier Awards SAIC $38 Mln Contract for Tulsa Refinery Upgrades
Sunoco Confirms Former Eagle Point Refinery Assets for Sale
Petrobras Plans Four New Refineries to Increase Capacity by 1.3 Mln bpd
HPCL-Mittal $3.78 Bln Refinery Could Undergo Commissioning in January
Petrobras Seeks Partnership for Okinawa Refinery through Japanese Subsidiary
Delay to New $7.5 Bln Nghi Son Refinery Latest Downstream Setback for Vietnam
PKN Orlen Subsidiary UniPetro Considers Czech Refinery Closure
Neste Oil to Recover VOC Emissions at Its Porvoo Refinery Harbor
Poland Extends Deadline for Lotos Refinery Stake Bid
Rompetrol Installs New Units for Petromidia Refinery Modernization Project
Despite Reports Engen Will Not Close Durban Refinery
South Africa to Audit Refineries due to Increasing Unplanned Shutdowns
Japan to Lend $55 Mln to Iraq for Basra Refinery Upgrade
North Dakota’s MHA Nation, also known as the "Three Affiliated Tribes," was seeking financing/development proposals until December 1 for a tribally owned and operated 15,000-barrel per stream day refinery that would be built on the reservation near Makoti, N.D. The grassroots refinery would be located in the prolific Bakken Shale formation and is accessible to Enbridge's North Dakota oil gathering and interstate pipeline system.
When they originally conceived the refinery project in 2001, the Three Affiliated Tribes planned to use synthetic crude oil from Alberta's Oil Sands as the feedstock. However, with the rapid growth of production from the Bakken later in the decade, the project developer last year decided to use the more readily available local feedstock instead. In either case, the refinery would run a light sweet crude that would apply the same general site layout. However, the higher salt content and bottoms (residual oil) component of the Bakken crude demand additional refinery units: a vacuum crude heater; two decant oil tank heaters; a desalter and desalter brine disposal facilities; and additional air pollution control units (sulfur recovery, tail gas treating and amine treating).
The refinery would be North Dakota's second such facility; Tesoro's 58,000-bpd Mandan Refinery has operated near Bismarck since 1954. In addition, MHA Nation members say their project would represent the only tribal-owned refinery in the Lower 48 States.
Although the Three Affiliated Tribes' refinery would be small by industry standards, MHA Nation Clean Fuels Refinery Project Director Rich Mayer, Project Director of the MHA Nation Clean Fuels Refinery, said the facility would primarily supply diesel for drilling operations in the Bakken and naphtha for Oil Sands activities. Mayer said the refinery's focus on those two products and markets would enable it to carve out a good niche for itself.
"This is a way to vertically integrate Bakken oil," Mayer said.
"Refining is a tough business and we need to find a niche market," added Hall. "I think we've found it with diesel and naphtha."
Mayer added that the tribes will be mindful of growth opportunities.
"It's a modular design and we'd obviously like to see it expanded," Mayer said. Hall added than an expansion "may be sooner than later."
In August of this year the MHA Nation reached an important project milestone, obtaining a favorable record of decision from the U.S. Environmental Protection Agency (EPA) for the National Pollution Discharge Elimination System (NPDES) permit under the Clean Water Act. The vital NPDES permit, which the tribes had sought for eight years, would allow the refinery to discharge treated wastewater into a tributary of the East Fork of Shell Creek.
Just before the EPA was set to grant the permit following a required comment period, however, six tribal members formally appealed the decision during the first week of November. The six members, most of who are represented by the Washington, D.C.-based Environmental Integrity Project, contend the feedstock switch in 2010 warranted a new environmental review process by the EPA. The NPDES permit is on hold until the EPA's Environmental Review Board reviews the decision or the matter goes to court. A public comment period would follow a decision by the review panel, whose decision is subject to an appeal in federal court, an EPA spokeswoman told The Bismarck Tribune.
"EPA has until December 16, 2011 to file a response to the petitions supporting the issuance of the permit," said Andrea Aseff, Louisville, Colo.-based attorney with the law firm Fredericks Peebles & Morgan LLP, which specializes in American Indian law and is representing the MHA Nation. "MHA Nation intends to file a response in the appeal, as well, in support of the permit issuance and comprehensive analyses that led to such issuance."
"While it is true that the permit is stayed during this appeal, we are confident that the Environmental Appeals Board will understand the lack of merit in the petitions upon considering our response and the EPA's response," continued Aseff, adding that the appeal will not affect the RFP timeline.
"We will continue to prepare for construction and operation as scheduled, in order to enable a smoother and more expeditious process," Aseff concluded. "MHA Nation will stay its course so that, upon resolution of the permit appeal, the refinery will be well situated to continue its progress as planned. We will utilize this time to complete other necessary matters for the construction and full operation of the refinery."
The deadline for proposals was December 1, 2011.
After the MHA Nation receives the proposals, a rating team comprising members of the local community will rate and select the top candidates perhaps before January 1, 2012. The Three Affiliated Tribes hope that construction can begin next March or April, and the first phase of the project (with a nameplate capacity of 6,000 bpd) could conclude by late summer of next year.
Oil company BP has agreed to pay a US$50-million fine issued by the state of Texas for pollution at its Texas City refinery related to the deadly 2005 blast there.
BP had already agreed to pay the same sum for pollution charges to the U.S. government in 2009. On top of that, BP has to date paid US$71.6 million for safety violations to the Occupational Safety and Health Administration (OSHA) and a total of more than US$2 billion on other legal claims. Moreover, BP has spent US$1 billion on upgrading safety equipment and procedures at its Texas City refinery. However, the oil major does not admit any liability for the alleged pollution.
The agreement between Texas and BP, which will have to be confirmed by a state court judge in Austin, Texas and observe a 30-day period before enactment, brings an end to high-level litigation against the company in relation to the 2005 incident.
BP has been eager to put any charges from the 2005 Texas City refinery incident behind it as the company is actively marketing the 406,540-b/d asset, together with the 265,000-b/d Carson California refinery. The disposal plans are part of BP's wider asset divestment program to fund liabilities related to the 2010 Macondo oil spill. While no official interest has been revealed yet for the Texas City refinery, settled charges might contribute to higher interest and accelerated negotiations.
While refining margins have generally been low in recent years, Texas City is well positioned to benefit from dirtier, yet cheaper South American feedstocks, and, increasingly, shale oil production from the prolific Eagle Ford play in Texas. In fact, it might not be surprising for an Asian investor to approach BP over the asset as Asian companies have increasingly tried hard to establish themselves in the North American unconventional realm and could look towards healthy profits from unconventional oil processing in Texas. However, no announcements to this effect have been made by either BP or a potential buyer as yet.
Over the last few months, the EPA has proposed important changes to Subpart W of the Mandatory Reporting of Greenhouse Gases Rule (Mandatory Reporting Rule or MRR).1 In addition, the EPA finalized provisions that broadly expand the ability of covered entities to use best available monitoring methods (BAMMs) for compliance in the 2011 reporting year. These changes take important steps to reduce the reporting burden, but numerous compliance challenges remain.
The Mandatory Reporting Rule requires owners and operators of facilities in 45 covered industries to report their greenhouse gas (GHG) emissions to the EPA. The MRR provides rules for all industries subject to reporting and uses industry-specific subparts to detail the precise requirements for measuring, monitoring, and reporting GHG emissions. The GHGs under the Mandatory Reporting Rule are defined to include carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), and the fluorinated hydrocarbons.
Subpart W covers oil and gas production and distribution. Beginning on January 1, 2011, the following eight sectors were required to initiate monitoring and report their 2011 GHG emissions to the EPA by March 31, 2012:2
In general, the MRR requirements apply to facilities whose GHG emissions exceed 25,000 mtCO2e/y, 3 as well as certain other facilities expressly specified in the regulations. The Subpart W rules require monitoring of GHG emissions from covered facilities on January 1, 2011, with the first annual report, covering 2011 emissions, due to EPA by March 31, 2012.
As finalized, the original Subpart W rule raised a number of concerns and compliance challenges. Most significantly, many of the new measurements required to estimate GHG emissions were seen as difficult, if not impossible, to complete in the first year of reporting. Some measurements required the installation of costly new equipment, while others proved dangerous or technically impossible. In addition, some aspects of the rule, most notably the requirement to collect data at the field level, proved confusing. In response to petitions for reconsideration filed by a number of industry groups, the EPA has proposed a series of rules to modify Subpart W's requirements intended to collect the high-quality data EPA seeks while easing the data collection burden on covered sectors.
New Rules for the Use of BAMMs
On September 27, 2011, the EPA finalized amendments to Subpart W that extend the amount of time in which BAMMs can be used for certain required measurements under the rule.4 Under the final rule, BAMMs may be used to estimate any parameter required for the calculation of GHG emissions during the 2011 reporting year without prior approval of the EPA.5 In order to use BAMMs after 2011, owners and operators of covered sources must submit a notice of intent to use BAMMs to EPA by December 31, 2011. After submitting the notice of intent, owners and operators have until March 30, 2012, to submit a BAMM request, which can automatically be used without approval through June 30, 2012. Between March 30 and June 30, 2012, EPA will review those BAMM requests seeking permission to use the BAMM for a longer period of time. Upon EPA approval, a requested BAMM may be used for the time period indicated by EPA, which is not to extend beyond December 31, 2012.
While EPA does not expect that it will be necessary, the new BAMM rule does include provisions for requests to use BAMMs beyond 2012.6 Any owner or operator that wishes to use BAMMs in 2013 or later must file a BAMM request by September 30 of the preceding year for EPA review. The BAMM request may be approved by the EPA if the Administrator is satisfied that the owner or operator is faced with unique or unusual circumstances.7 The rule provides examples of "unique or unusual circumstances," including safety concerns associated with data collection methods.8 The preamble further clarifies the criteria for approval, noting that BAMM will be approved in unique or unusual circumstances, but that "extreme" circumstances are not required, as suggested by the initial rule.9
The new BAMM rule provides a significant expansion of the flexibility granted to owners and operators to use available data and estimation techniques in their GHG emissions calculations. Under the original rule, BAMMs were only automatically available for well-related emissions and specified activity data and were set to expire by June 30, 2011.10 The original rule permitted the use of BAMMs for leak detection until the end of 2011, but these BAMMs were only available upon request to, and with approval granted by, the EPA.11
Proposal to Extend the Reporting Deadline and Make Technical Corrections to the Rule
On August 4, 2011, the EPA proposed technical modifications to several subparts of the MRR including Subpart W.12. Most importantly, the proposal seeks comment on extending the submission deadline for 2011monitoring data until September 28, 2012.13
Reconsideration of the Use of Field-Level Reporting for Onshore Production
Finally, on September 9, 2011, EPA proposed additional technical corrections to Subpart W, which respond in part to petitions for reconsideration filed by several industry groups. EPA's proposal announces that it plans to finalize the proposed rules before the end of 2011, and the final rules will apply to the first emission reports to be filed in 2012.14 EPA concluded that it would be reasonable to incorporate these significant changes into reports to be filed for 2011 because they are primarily designed to provide additional clarifications and flexibility in reporting, but do not affect the type of information that must be collected to complete an emissions report.15
The most significant change in EPA's reporting rule will effect reporting in the onshore oil and natural gas production sector. In the original rule, an onshore oil and natural gas production facility is defined as all wells within a basin,16 but many of the reporting requirements were tied to field-level data.17 The rule defined "field" by reference to the Energy Information Administration (EIA) 2008 field list, raising significant concerns about the delimitation of field boundaries as well as challenges regarding how wells not in fields on the EIA 2008 list should be reported. To address these concerns, the EPA has proposed to adopt a sub-basin approach.18 The proposal would use county boundaries as the limits of sub-basins and then define four categories of wells within each sub-basin.19 The four categories of wells would be defined as follows: (1) conventional; (2) shale; (3) coal seam; and (4) other tight reservoir rock.20 Within each category, the proposed rule contemplates the use of operational criteria that will require multiple samples per sub-basin category for particular sources where the emissions profiles are variable.21
The rule also proposes a number of other clarifications and technical corrections to Subpart W.
The modification of the BAMM rules and the proposed technical corrections to Subpart W makes significant strides in easing the burden placed upon covered owners and operators with reporting obligations. However, the challenge ahead still remains significant. As 2011 draws to a close, it is essential that all owners and operators have Subpart W monitoring plans in place and ensure that these plans are being executed to collect all required data for reporting. While the expansion of the BAMM rules certainly eases some data collection challenges, Subpart W reporting remains a significant undertaking. Among the challenges that remain for covered owners and operators are determining the number of facilities, selecting a designated representative for reporting, and collecting appropriate data from third party service providers to report emissions from portable equipment.
> Footnotes
1) 40 C.F.R. Pt. 98.
2) 40 C.F.R. s. 98.3 (b). Note, however, that one of EPA's proposed rules would extend the reporting deadline to September 2012 for 2011 emissions under Subpart W.
3) The unit of measure for the Mandatory Reporting Rule is metric tons of CO2 equivalent (mtCO2e), this measurement requires that other reportable gases be converted using their global warming potential into a value that is equivalent to an amount of CO2. For gases with a higher global warming potential, the amount in CO2e will be greater than the actual amount of the gas emitted.
4) 76 Fed. Reg. 59533 (Sept. 27, 2011).
5) Id. 59535.
6) 76 Fed. Reg. at 59535.
7) 40 C.F.R. s. 98.234(f) (8)(iii). 8 Id.
9) 76 Fed. Reg. at 59538.
10) 40 C.F.R. s. 98.234(f)(2)-(3) (2010).
11) Id. s. 98.234(f)(4).
12) 76 Fed. Reg. 47392 (Aug. 4, 2011).
13) 76 Fed. Reg. at 47396.
14) 76 Fed. Reg. 56010, 56020 (Sept. 9, 2011).
15) Id.
16) The rule adopts the American Association of Petroleum Geologists' definition of basin. 40 C.F.R. s. 98.238.
17) 40 C.F.R. s. 98.238 (2010). Under Subpart W as finalized one measurement from each field is required to estimate emissions from well completions, well work-overs, and well unloading events.
18) 76 Fed. Reg. at 560026.
19) Id. at 56050.
20) Id.
21 Id. at 26026.
The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about specific circumstances.
The U.S. State Department's decision to delay TransCanada Corp.'s expansion of its Keystone pipeline system sparked quick concern in the North American energy industry. The pipeline is critical for companies that have invested billions of dollars in expanding the production capacity of Canada's oil sands and refurbishing U.S. refineries to handle heavy crude.
The State Department said November 10 it will postpone until after the 2012 election a decision on the Keystone expansion as it explores a rerouting that will avoid environmentally sensitive areas in Nebraska. Previously, a final decision was expected by the end of 2011, and TransCanada aimed to have the pipeline ready in 2012. The move would delay completion of the project by a year and a half, according to the American Petroleum Institute.
Vocal supporters of the pipeline expansion, dubbed XL, include companies like Valero Energy Corp. (VLO) and ConocoPhillips. Both companies are eager to have access to vast amounts of cheap, heavy Canadian crude for their U.S. Gulf Coast refineries, which currently buy heavy oil from Venezuela and Mexico. Houston-based Conoco, one of the original proponents of the Keystone pipeline system, has major investments in Alberta's oil sands. Exxon Mobil Corp., the world's largest publicly traded oil company and a big oil-sands producer, has also been a big pusher for the pipeline's approval, saying it would ease access to Canada's massive resources.
The Keystone expansion would double the amount of oil-sands crude that TransCanada ships to the U.S. to one million barrels a day, but environmentalists and officials have opposed it, alleging that exploiting Canada's oil sands produce more greenhouse gases than other types of crude and the corrosive nature of oil-sands crude could result in more spills. The oil industry says the pipeline is safe and will create thousands of jobs.
"Any delay in opening the Keystone XL pipeline extension is unfortunate for our nation," said Valero Chief Executive Bill Klesse, who in a statement called the U.S. government's move "short-sighted."
"The administration's decision will actually increase greenhouse gas emissions because without this project, oil will be transported further and by more carbon-intensive means. Valero continues to support the Keystone XL pipeline project, and we feel [the pipeline] makes too much sense not to approve," Klesse said.
The American Petroleum Institute said the project has been under review for three years already, and that further delays could jeopardize it.
But the delay is also likely to benefit refiners, such as Western Refining Inc. (WNR) and HollyFrontier Corp. (HFC), which have been making a killing due to their access to a glut of cheap crude in the U.S. midcontinent. The supply had been piling up earlier this year due to a lack of pipeline capacity to bring it out to the Gulf Coast. Analysts say that Keystone XL, in addition to bringing an additional 500,000 barrels a day of Canadian crude, would also help eliminate the glut by transporting 150,000 barrels of light, sweet crude from Cushing, Okla., to Texas refineries.
Excess supply in Cushing is keeping the barrel of U.S. benchmark West Texas Intermediate crude about $16 cheaper than a barrel of European benchmark Brent.
The delay "extends the amount of time midcontinent refiners will be making money hand over fist," said Sarah Emerson, an energy analyst with consultancy ESAI Inc.
TransCanada's direct competitors are likely to benefit, too. Enterprise Products Partners L.P. (EPD) and Enbridge Inc (ENB) have a joint venture to build the 500-mile Wrangler pipeline, connecting Cushing to Houston by mid-2013. There also has been talk of reversing the flow of the Seaway pipeline, a conduit owned by Conoco and Enterprise Products that brings 350,000 barrels a day from the Gulf into Oklahoma. "Frankly, it increases the chance of Wrangler happening and increases the chance of Seaway being reversed," said Brad Olsen, an analyst at Tudor, Pickering Holt & Co.
Oil markets are unlikely to see any near-term impacts from the decision, but that it would result in a continuation of the currently depressed prices for WTI, said Tom Bentz, director at BNP Paribas Commodity Futures in New York. "I don't really see that as a big impact right now," he said.
Fadel Gheit, an analyst with Oppenheimer & Co., says that the State Department's demurral is just delaying "the inevitable," as access to Alberta, one of the richest oil basins in the world, is key to both national security and the U.S. economy.
The Environmental Protection Agency has launched an investigation of Royal Dutch Shell PLC's Shell Oil Co., Exxon Mobil Corp. and several other companies to determine whether they used phony credits to meet renewable-fuel standards.
The EPA alleges the companies purchased fraudulent credits from a company called Clean Green Fuels LLC and used them to comply with 2010 standards for renewable-fuel use.
The EPA didn't say whether the companies knowingly used the false credits.
A spokeswoman for Shell Oil said "when the [credits] were purchased, they were believed to be valid" and the company is working with the EPA to resolve the issue.
Exxon Mobil didn't immediately respond to a request for comment and Clean Green couldn't be reached for immediate comment.
The EPA requires petroleum refiners to use a certain amount of renewable fuels. In order to demonstrate compliance with the standard, the companies submit renewable identification numbers, or RINs, to the EPA. The program includes a trading program whereby companies can purchase these RIN credits.
In violation notices sent to the companies earlier this month, the EPA alleged the companies bought RINs that were invalid.
The EPA sent out 24 violation notices. The violation notices were sent November 7, the EPA said.
The U.S. Environmental Protection Agency, struggling with an ambitious agenda on clean air regulations, said it will delay proposing the country's first-ever greenhouse gas limits on oil refineries.
The delay is the latest setback for the agency's new raft of clean air rules on everything from smog to mercury pollution that are heavily opposed by industry.
The EPA had been required to propose the rules on refineries by mid-December, as part of a court settlement with states and environmental groups.
"EPA expects to need more time to complete work on greenhouse gas pollution standards for oil refineries," a spokeswoman for the agency said. The EPA is working with the litigants to develop a new schedule to replace the current mid-December date for a rule proposal, she added.
The EPA made the comments after sources on both sides of the issue told Reuters the agency would not make the deadline.
The EPA has not told refiners exactly how it plans to cut emissions, and that figuring out how to do so is taking additional time, an oil industry source said.
"How they are going to regulate greenhouse gases, they are not sharing that with us," the source said.
The petroleum industry says it is more difficult to cut emissions from refineries than it is from power plants, the EPA's top target of emissions. Many power utilities can switch from coal, which emits large amounts of carbon dioxide when burned, to burning cleaner natural gas. Refineries, however, mostly already run on natural gas, they argue.
Tough rules on greenhouse gas emissions could add expenses to companies including Exxon Mobil Corp, Valero Energy Corp, and ConocoPhillips.
But refiners can easily cut emissions -- and save money, a source with one of the litigants said. They can do so by replacing inefficient boilers, installing better valves to reduce leaks of methane, a potent greenhouse gas, and by generating power with "waste heat" given off at the plants.
The delays on greenhouse gas plans come after President Barack Obama forced the EPA in September to delay new limits on smog emissions until 2013, saying it was part of an effort to reduce regulatory burdens on business.
That decision came as Republicans in the House of Representatives complained about EPA's raft of new clean air regulations, saying they would kill jobs and add expenses to businesses as they struggle with the weak economy.
The delay comes as time may be running out for world efforts to control global warming emissions. Concentrations of carbon dioxide and two other greenhouse gases reached record levels last year and will linger in the atmosphere for decades, even if the world halts output of the gases today, the World Meteorological Organization, the U.N.'s weather agency said.
The United States is sticking with Obama's pledge to cut greenhouse gas emissions by about 17 percent from 2005 levels by 2020. But a comprehensive energy and climate bill failed in the Senate last year, leaving emissions control largely to agencies including the EPA and the Department of Transportation. Recently those agencies proposed doubling auto fuel efficiency.
Meanwhile, U.S. CO2 emissions from energy sources last year rose nearly 4 percent as factories ran harder and as consumers boosted air conditioning during the hot summer.
The EPA has also delayed proposing a plan on reducing emissions from power plants, which are the country's single largest source of emissions blamed for warming the planet.
Those rules were initially delayed in June and again in September. Lisa Jackson, the EPA administrator, said the plan on power plants would be rolled out early next year.
It was unclear if the EPA would also miss the deadline to finalize the rules on refineries by mid-November, 2012.
The U.S. could see a new oil refinery for the first time in decades, as fuel demand within the oil industry itself spikes, according to Reuters.
Much has been made recently of the lack of approval for new nuclear power plants, but the country also has not seen another oil refining plant built in 35 years.
However, the Bakken shale oil fields in North Dakota have created a booming economy that is heavily reliant on a variety of different diesel-powered vehicles. With only one refinery in the state, a 58,000 barrel per day diesel plant owned by Tesoro Corp, demand often dramatically outstrips production, particularly if there are any issues at the distant facilities in the Midwest that supply much of the state's diesel.
"Trucks arrive at the loading station and some wait three to four hours and others in excess of eight hours," Bud Kerr, operations manager at hauling company J5, told Reuters. "The problem appears to be worse than what it was last year."
In response, Dakota Oil Process plans to build a 20,000 barrel-per-day refining plant that could fill around 10 percent of the state's diesel needs.
Reuters reports that the Bakken oil field also recently added its first new rail line to carry the region's output to larger refineries to the south.
A Virginia firm will design and build about $38 million in upgrades to the two HollyFrontier Corp. refineries in Tulsa starting in 2013.
Science Applications International Corp. (SAIC) of McLean, Va. will build a new sodium hydrosulfide unit, amine unit and complete a portion of an interconnecting pipe between the two facilities in west Tulsa, according to a statement from SAIC.
The work will be done primarily in Tulsa, the company said.
Holly Corp. purchased the two refineries separately in 2009 from Sunoco and Sinclair. They now operate them as one unit connected by pipelines.
Holly merged with Frontier Oil Corp. to form HollyFrontier earlier this year.
Holly Energy Partners LP, the subsidiary of HollyFrontier, has budgeted about $48 million on five pipeline interconnects. The parent company also is in the midst of spending up to $70 million on various improvements, including a new diesel hydrotreater.
Sunoco Inc. said on November 22 that some refinery assets of its shuttered Eagle Point refinery in southern New Jersey were up for sale but that there was no new news related to the former refinery. The refinery was shut in 2009.
Local Philadelphia-area media said, based on Mumbai-based media report from the Daily News and Analysis (DNA) that an Indian company had bought the assets and was planning to move the dismantled refinery to the city on India's east coast.
"I can confirm that we have been trying to sell some of the refinery equipment," said Thomas Golembeski, a spokesman for the company.
"We have nothing new to announce at this time related to the former Eagle Point refinery."
The New Jersey-based Gloucester Times had cited the DNA report saying that the Indian company Amerind Petroleum Pvt. Ltd was planning to purchase the equipment.
Golembeski said that the tank farm and related assets at the site of the former refinery had been sold to and were in use by Sunoco Logistics, a midstream company spun off from Sunoco who still holds a share.
Sunoco closed the refinery in 2009 due to poor profit margins along the Atlantic Basin. Earlier this year, they said they were also closing their remaining two refineries if there were no buyers.
Four refineries which Brazilian oil and gas giant Petrobras plans to build in Brazil will add about 1.3 million barrels of oil per day (bpd) to the company's refining capacity by 2020.
This was affirmed by the CEO of Petrobras, Jose Sergio Gabrielli, who on November 2 presented refining projects at the Downstream Asia 2011 conference in Singapore.
For 2020, Petrobras's domestic oil production is projected to stand at 4.9 million bpd.
According to Gabrielli, the company's new refineries will be much more efficient and with higher profit margins than the existing ones.
Petrobras currently has two refineries under construction -- a unit at the petrochemical complex Comperj, in Rio de Janeiro state, and the Abreu and Lima refinery, in northeastern Pernambuco state. The company also plans to build another two plants, Premium I and II, in the northeastern Maranhao and Ceara states, expected to be launched in 2014 and 2017, respectively.
Although Brazil has increased its crude oil production, it is facing a shortage of oil derivatives like diesel, liquefied petroleum gas (LPG) and naphtha, Gabrielli stated.
A planned US$3.78 billion (Rs 18,900 crore) HPCL-Mittal Energy Limited refinery in India, a joint venture involving Hindustan Petroleum Corporation Ltd, is expected to be commissioned within two months, according to sources.
HPCL chairman and managing director, S. Roy Chaudhury, recently visited the ambitious 9 million tonne oil refinery to get a first hand account on the progress of the project.
HMEL is a joint venture between Hindustan Petroleum Corporation Limited and Mittal Energy Investment Pte Ltd, Singapore - a Lakshmi N. Mittal Group company. Both the JV partners hold 49 per cent stake each in the company. The other 2 per cent is held by financial institutions.
The sources said Chaudhury held a meeting with senior staff of HPCL-Mittal Energy Ltd (HMEL) to discuss the marketing of finished products, among other issues.
"The trial run conducted at the refinery has remained successful and it is expected to be commissioned this month or next month," said a source.
The work on oil refinery commenced on November 14, 2007 with a capital outlay of Rs 18,919 crore.
After commissioning, the refinery will produce high value petroleum products such as LPG, naphtha, petrol, diesel, aviation fuel and pet coke.
The liquid products would be marketed through HPCL, while the solid products like sulfur, pet-coke and polypropylene would be sold directly by HMEL.
After its commissioning, the refinery -- known as Guru Gobind Singh refinery -- is estimated to attract an investment of Rs 1,300 crore in Polypropylene based downstream industry in Punjab.
It will be one of the few refineries in the country that will have the capacity to produce 440,000 metric tonne of polypropylene, an official said, adding that at present polypropylene granules are produced in Gujarat and Maharashtra.
Japanese refiner Nansei Sekiyu Kabushiki Kaisha, a subsidiary of Brazil's state-owned Petrobras, is seeking a partner to supply crude and buy fuel from its Okinawa refinery, an official at the plant told Reuters on November 1.
The Okinawa refinery has a nameplate capacity of 100,000 barrels per day (b/d), but is currently running at a utilization rate of 80%, which brings actual output to an average of 80,000b/d. The facility currently uses light crudes bought on the spot market to produce gasoline, kerosene and low sulfur fuel oil (LSFO).
Before the earthquake in March 2011, the utilization rate was only 60%, but fuel oil demand from power plants spiked in the aftermath of the earthquake to compensate for the fall in nuclear electricity generation, pushing the utilization rate up to 80%. A further increase in refinery runs is being considered, but would be hampered by the plant's relatively low complexity. Currently, about 40% of output goes to the Okinawa market, while the remaining 60% is exported.
Despite the refineries distance from Petrobras' main business in Brazil, the Okinawa refinery plays an important role in the company's long-term strategy. In 2010 Reuters reported that Petrobras was planning to use the site as a trans-shipment hub for the delivery of crude oil to Asia, increasing the company's oil exports to Asian markets by more than 33,000b/d. The NSS refinery has five storage tanks with a total storage capacity of 3.15mn barrels (bbl). Three of the refinery's storage tanks, each with a capacity of 630,000bbl, are expected to be used to store the oil imported by very large crude carriers (VLCCs).
While the facility currently relies on the spot market for feedstock, Petrobras is looking to tie it more closely with its operations in Brazil. Petrobras has mentioned the possibility that some of the feedstock could come from West Africa, the main focus will be on Brazilian medium grades with 24-28 degrees API, such as its Roncador 28 grade which has an API gravity of 28 degrees and sulfur content of 0.58%. Because of the facilities current configuration, heavier crudes, such as Roncador Heavy or Marlim, are off the table for the time being.
That could change in the future. In late 2008 Petrobras considered upgrading the refinery by adding secondary units capable for cracking heavy Brazilian crudes, but it was forced to shelve the project in the wake of the global financial crisis. The upgrade is now back on the table, with a final decision to be reached by the end of 2011. In addition to enabling the processing of heavy Brazilian crudes, the modernization of the plant would increase utilization rates and bring them close to 100%, in line with Japan's trade ministry measures on efficiency. This would mean the Okinawa refinery would have a higher LSFO yield, which would enable it to increase exports to China.
To realize this strategy, however, Petrobras has to secure enough cash for the needed investments. In August 2011 Kawakami said that the company was considering selling a stake in the plant. The cash could be used for an upgrade but would also likely be used for the development of deepwater fields in Brazil, a future source of feedstock for the plant.
The announcement that it is now considering bringing in an Asian partner that could help secure feedstock and would buy some of the output is in line with Petrobras' strategy. Indeed, such a deal would reduce costs as the refinery would not have to rely on the spot market as much as it does now and it would secure a steady stream of revenue.
The importance of the plant in Petrobras' long-term strategy makes the sale of a majority stake unlikely. However, it is an opportunity for investors and partners to gain exposure to both Asian oil demand and Petrobras' growing oil production. This is in line with the 'Hinomaru Oil' strategy adopted by many Asian companies, particularly in Japan, which consists of securing supplies through investments and partnerships with oil producing countries and their national companies.
BMI expects Asia Pacific oil consumption to grow from an estimated 27.5mn b/d in 2010 to as much as 31.0mn b/d by 2015, largely driven by growing demand from China and India. On the supply side, Brazil is likely to be the main driver of Latin American oil production, increasing from 10.0mn b/d in 2010 to 11.7mn b/d by 2015.
The delay to construction of the Nghi Son refinery is the latest downstream setback for Vietnam. It will slow PetroVietnam's strategy of diversifying refining feedstock away from domestically produced light sweet crudes better preserved for the lucrative export market.
The start of construction of the US$7.5bn Nghi Son oil refinery is likely to be delayed until Q112, according to an unnamed senior contractor executive quoted by Reuters on October 27. Industry sources said the delay was due to financing issues and government procedures, but the executive declined to comment. Construction at the refinery, in northern Thanh Hoa province 215 km south of Hanoi, had been scheduled to start in the final quarter of 2011.
Nghi Son will be Vietnam's second refinery, after the 140,000 barrels per day (b/d) Dung Quat facility came onstream in 2009. Nghi Son will have a capacity of 200,000b/d and is being developed by national oil company PetroVietnam, alongside Kuwait Petroleum International, Idemitsu Kosan and Mitsui Chemicals. Construction is being contracted out to Technip, Japanese engineering firm JGC Corporation and Spanish oil engineering group Tecnicas Reunidas. It is likely to be completed by 2015-16.
The feedstock for Nghi Son is to be sour Kuwaiti crude oil, according to Dominique Peiffert, the general director of French oil services group Technip's business in Vietnam. Processing heavier sour crudes will help preserve valuable light, sweet domestic crude for export. Oil produced from Vietnam's flagship Bach Ho field has an API gravity of 40.5° and a sulphur content of just 0.035%. It can therefore command a much greater premium on international markets than the Kuwaiti grade, which has an API gravity of 30.2° and a sulphur content of 2.72%.
The construction of Nghi Son is part of a wider strategy formulated by PetroVietnam to gear the country's refineries towards heavier crudes. The strategy follows an agreement with Venezuela's national oil company, PdVSA, that will see PetroVietnam secure heavy oil supplies from the Latin American country's Orinoco Belt. PetroVietnam also signed an agreement with Russian oil company Gazprom Neft in March 2011, which agreed to supply heavy crude from the Nagumanovskiy field.
Perhaps with these agreements in mind, the Vietnamese government authorized the sale of a 49% stake in the flagship Dung Quat refinery in August 2011. The sale will fund a US$1-2bn expansion and conversion of the refinery to heavy crudes. Following the upgrade, the facility will have a capacity of 200,000b/d. Completion is scheduled for 2017. In October 2011, PetroVietnam announced that JGC was completing a feasibility study for the plant's expansion and conversion. The study is due to be completed in December.
Vietnam's downstream industry has been dogged by a series of delays and technical difficulties. Delays to Nghi Son follow criticisms against the government following persistent outages at the Dung Quat facility, with some opponents pointing out that the plant is too far from feedstock sources offshore southern Vietnam. In particular, critics have claimed that the plant was built in Dung Quat for political rather than commercial reasons.
Active, Planned and Proposed Vietnamese Refineries
|
Location |
Name |
Capacity, b/d |
Capacity, tpa |
Status |
Start |
Built |
Owner |
Value, US$bn |
Price US$/bbl |
|
Dung Quat |
Dung Quat |
140,000 |
6,968,641 |
Active |
2005 |
2009 |
Petrovietnam |
3.0 |
21,429 |
|
Thanh Hoa |
Nghi Son |
200,900 |
10,000,000 |
Planned |
2012 |
2014 |
Idemitsu/KPC |
7.5 |
30,861 |
|
Ba Ria-Vung Tau |
Long Son |
200,900 |
10,000,000 |
Planned |
2012 |
2015 |
Petrovietnam |
8.0 |
39,821 |
|
Khan Hoa |
Vung Ang |
200,900 |
10,000,000 |
Proposed |
2011+ |
2013 |
Petrolimex |
4.5 |
22,399 |
|
|
|
742,700 |
36,968,641 |
Source: BMI Global Refining Database
UniPetrol, the Czech downstream subsidiary of Poland's PKN Orlen, may cease operations at the Paramo facility and continue with only its petrochemical business amid low refining margins and intensifying competition.
Although the asphalt and chemicals operations remain solvent, the refining operations have been losing revenues for the past two years. The Czech government's austerity measures have put pressure on demand for asphalt too as road-building programs have been cut back. The weak margins and lack of throughput at Paramo contributed to a third-quarter 2011 loss for owner UniPetrol. Sales of fuels fell by 1% in the quarter and declined by 9% from the year-ago period as high gasoline and diesel prices prompted more Czechs to buy fuel in neighboring countries.
PKN Orlen's strategy for its Czech downstream operations has been inconsistent over the past 12 months in the face of conflicting pressures from refining economics and national politics. Early in March the majority of shareholders announced their intention to sell the Czech refinery Ceska Rafinerska to Gazprom as a result of weak margins, falling demand and tightening emissions regulations.
PKN Orlen then moved to block the sale, apparently following disquiet from leading Polish politicians. Since then, rumors are circulating that PKN is looking to acquire Austrian peer OMV's chain of 220 filling stations for US$213 million (around EUR164 million). This would bring UniPetrol's total number of stations up to more than 520 across the Czech Republic.
Finland’s Neste Oil is building a system for recovering emissions released when loading ships at the harbor of its Porvoo Refinery. The system, valued at approx. EUR 23 million, will recover the majority of the volatile organic compounds (VOCs) released into the atmosphere when loading gasoline.
The new facility will reduce the refinery's overall hydrocarbon emissions significantly as gasoline loading at the refinery's harbor are the site's single largest source of VOC emissions. The VOCs form ozone in the lower atmosphere when they react with NOx in the presence of sunlight. Ozone is harmful to people, flora, and fauna.
"Thanks to the new system, we will be able to further reduce our environment footprint and also ensure that harbor personnel benefit from a cleaner working environment," says Niko Ristikankare, Neste Oil's Vice President, Shipping and Terminals.
The new system will reabsorb VOCs into gasoline during loading with the help of two absorption tanks and related equipment at the harbor, after which the gasoline used will be returned to the refinery for re-use. A similar system is already in use when loading tanker trucks at the Porvoo refinery's distribution terminal.
Construction work on the VOC recovery system began in October and the facility is due to be commissioned in the latter half of 2013.
Poland's treasury has announced it will once again delay the sale of its stake in refining firm Grupa Lotos.
The government has been trying to dispose of its controlling 53% stake in the country's second largest refiner since November 2010 but has pushed back the deadline for bids four times. The unions have voiced strong hostility to the privatization program fearing threats to jobs, while the main opposition party, the Law and Justice Party (which was roundly defeated in the recent general election) has also sought to block the process on the grounds of energy security. So far, Hungarian MOL and Anglo-British TNK-BP had submitted bids.
The Treasury has not specified a reason for this latest delay, although the financial storm currently overwhelming the Eurozone may well have undermined investor interest, resulting in unacceptably low bids.
The fact the Grupa Lotos has suffered a poor third quarter plays into this narrative to an extent: the company revealed a net loss of US$102.7 million (328.6 million zloty), compared with a profit of 1.05 billion zloty a year earlier, hence private valuations may be lower than those of the treasury. It is also possible that political considerations are again slowing the process.
The privatization of Poland's energy assets (including power generator PGE) are more the result of pressure to reduce the state's debt than economic ideology. Given that Poland has continued to post encouraging GDP growth even as the rest of Europe suffered a recession has alleviated this pressure somewhat. Concurrently, the government may be less keen to offload its stake than in 2010. Finally, the problems that have engulfed TNK-BP since it announced its intention to bid in June may well have reduced its interest in the stake.
Romania's Rompetrol Rafinare, which is part of the Rompetrol Group, owned by Kazakh National Company KazMunayGas, has now commissioned six of nine new units as part of the Petromidia Refinery modernization project, KazMunayGas said.
The company put in operation the catalytic cracking unit, Claus gas desulphurization, amine unit, new flare system and the air separation unit. It also and modified hydro-fining unit for vacuum gas into hydro-fining unit for diesel fuel.
The modernization project's 2010-2011 investment program will be fully accomplished in Q1 2012 after installation of three more new units: the mild hydrogen cracking unit, the hydrogen plant, and a sulfur recovery unit.
The total cost of the project that was launched in 2006 is $367 million.
After modernization the Petromidia refinery will increase its annual processing capacity from 3.7 million tonnes to 5 million tonnes, refining Urals crude only.
"The project will introduce the company to the top 25 refineries in South and Eastern Europe. Upon completion of this project the Petromidia refinery will fully switch over to Kazakh oil maintaining Euro 5 standard quality," said the Rompetrol Group Vice-President of Business Development Gavitv Kurkimov.
Modernization of the refinery Petromidia is part of the KazMunayGas strategy to expand its presence in Central and Eastern Europe, Romania, Bulgaria, Moldova, Ukraine and Georgia, which has Rompetrol gas stations, as well as in Turkey, Serbia and Greece.
This year, the Rompetrol Group planned to process 4.17 million tonnes of feedstock, including 3.94 million tonnes of crude oil and invest $216 million, of which $180 million will go to expand Petromidia refining capacity.
The Rompetrol Group, a large oil and gas company in Rumania, is wholly owned by JSC KazMunayGas Processing and Marketing The company has three refineries - Petromedia, Vega and Rompetrol Petrochemicals - and 1,042 filling stations in Romania, France, Spain, Moldova, Ukraine, Bulgaria and Georgia. The company owns a 25 percent share of the petroleum product retail sales market in Romania, a 3.5 percent share of the market in France, and a 1.5-percent stake of the market in Spain. Rompetrol works in 13 countries in service and trading.
Engen will not close its Durban refinery, despite a letter from its CEO suggesting a closure was being considered.
This comes after reports that Engen was considering closing its refinery, the second largest in South Africa, because of local opposition.
Provincial authorities visited the refinery during in November and warned that it needed to sort out its pollution problems.
CEO Ahmad Nizam Salleh, in an internal letter to colleagues, said the refinery was continuing to face serious challenges from the community and authorities in Durban.
Salleh said the refinery could not afford further disruptions and while the first option was to continue with business as usual and operate as efficiently as possible, another option was to "appraise the business model".
There were fires in the refinery in 2008 and 2009.
But, in a statement November 11, Salleh said: "Our shareholders have also given their assurance that they are committed to the Engen refinery."
The refinery is currently closed for maintenance.
This is not the first time in recent weeks that a company CEO has raised the issue of problems of doing business in SA.
Marc Wainer, CEO of property company Redefine, said his company would no longer spend money where local authorities were "dysfunctional, inefficient or adopt business practices which are dubious".
Delays and even bribes were required to get things done in certain areas, he said.
Redefine will concentrate on commercial and industrial portfolios in Gauteng, the Western Cape and KwaZulu-Natal. There will be no further business in commercial and industrial properties in the Eastern Cape, Northern Cape and North West.
The company pays rates of R100-million a year but does not get adequate provision of electricity, sewerage and water suppy, said Wainer, who added that deliberate delays were stalling business and complicating the process.
South African Energy Minister Dipuo Peters is planning to conduct an audit of the country's oil refineries to establish their reliability in the face of increasing unplanned refinery shutdowns.
The Ministry announced November 10 that the audit will establish the reliability, availability, and capacities of different facilities. This comes after the country experienced severe shortages of liquid petroleum gas (LPG) and bitumen as a result of planned and unplanned shutdowns at four of the country's six refineries In early November national oil company PetroSA recommenced production at its 45,000-b/d Mossel Bay refinery, while both the 125,000-b/d Engen and 180,000-b/d Sapref refineries remain shut. The Chevref refinery's bitumen plant has also lately been experiencing problems, exacerbating the bitumen shortfall.
The recent shortfalls are illustrative of the tight fuel supply-demand balance that exists amid government projections that South Africa may have to import about 8.5 billion liters of fuel per year by 2015 (the equivalent of 150,000 b/d) if no investment in additional refinery capacity occurs. Progress on making a decision on whether or not PetroSA's 360,000-400,000-b/d greenfield Mthombo refinery will go ahead has been slow, while the government has also been putting pressure on refiners to upgrade refineries to meet new fuel specifications and improve capacity.
The high cost of upgrading South Africa's current six refineries, however, has long been causing concern across the industry, with the South African Petroleum Industry Association (SAPIA) estimating the total cost will amount to US$3.7 billion (25 billion rand). SAPIA has warned that in order to upgrade refineries, an industry-wide shutdown and turnaround strategy will be required to enable each refinery to meet the government deadline of 2017. The resulting shortage of LPG and bitumen highlights the potential adverse consequences of simultaneous refinery shutdowns, and the government may yet seek to revise the upgrade deadline to avoid a reoccurrence.
Japanese Prime Minister Yoshihiko Noda said on November 22 Japan will provide loans of US$871 million (about JPY 67 billion) for Iraq's four new projects in the areas of oil, communication and health.
Noda made a pledge during his talks with visiting Iraqi Prime Minister Nouri Al-Maliki, according to a joint statement released after their talks here.
Of the total, US$551 million (about JPY 42.4 billion) will be used for the Basra refinery upgrading project with an aim of improving the quality of refined products and reduction of the supply-demand gap of oil products. US$35 million (JPY 2. 7 billion) will go to upgrade engineering services to introduce modern processes to the Baiji refinery.
Other projects include establishing new hospitals in suburban areas in such cities as Basra, Kirkuk and Karbala. The loans will be also used for communications network development project for major cities including Baghdad, Basra and Mosul.
During the talks, the two leaders recognized that Iraq's reconstruction process would be accelerated through implementing the four projects and the Japan-Iraq bilateral economic relations, including in the field of energy, would be further strengthened, the statement said.
In light of securing a stable energy supply for Japan, Noda appreciated Iraq's offer to provide additional crude oil to Japan in case of emergency. Sharing the view that Iraq will be a reliable liquefied natural gas trading partner with Japan, Noda and Al-Maliki welcomed the contract of the South Gas Utilization Project is to be signed, with Al-Maliki expressing expectation that a considerable portion of LNG from this project should be shipped to Japan as soon as practicable. The two also renewed their determination to further strengthen bilateral cooperation in the energy sector and the importance of promoting cooperation and dialogue especially regarding upstream business including the Gharraf, East Baghdad and Nasiriyah oil fields.
Sharing the view that the strengthening of economic ties is the driving force of the Japan-Iraq comprehensive partnership, Noda and Al-Maliki affirmed commitment to working together to further promote trade and investment between the two countries.
While welcoming the contribution of Japanese companies to improve Iraq's infrastructure, Al-Maliki expressed his high expectation that Japanese firms and business people will expand their business and investment in his country.
In order to facilitate Japanese companies to expand their abilities to work on large-scale projects, the two leaders also agreed to start discussions on an innovative financial scheme which could involve Japanese export credit agencies, which would require sufficient collateral, such as crude oil, so as to reduce financial risk.
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