New base special 20 february 2014

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NewBase 20 February 2014 Khaled Al Awadi

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South Korean consortium wins $6bn deal to build Iraq refinery Hadeel al Sayegh www.thenational.ae/business/energy

The Iraqi oil ministry awarded Hyundai E&C, Hyundai Engineering, GS Engineering & Construction, and SK Engineering to undertake engineering, procurement and construction works for the planned 140,000 barrels per day (bpd) refinery, which is located 100 kilometres south of Baghdad.

The project follows regional economic development plans that include power plants and refineries to increase electricity production, build up infrastructure and spur job creation. The Karbala Refinery Project, which includes the construction of four refineries, is expected to produce a range of products including liquefied gas, petrol, gas oil, fuel oil and jet fuel to serve growing domestic needs.

Hyundai E&C and its affiliate Hyundai Engineering have taken a 37.5 per cent share in the project worth $2.26bn, Hyundai E&C said in a regulatory filing yesterday, GS has a 37.5 per cent share, while SK has a 25 per cent share, the statement said.

“Gas represents a valuable commodity and economic multiplier for Iraq’s reconstruction and infrastructure development,” Luay Al Khateeb, the visiting fellow at Brookings International, wrote in a paper co-published by Harvard University’s Belfer Centre and Rice University’s Baker Institute Center for Energy Studies in November.

“As much of Iraq’s gas is associated and will be a by-product of oil production – unlike other Middle Eastern countries – its production could be cost effective and competitive to regional markets; the development cost of gas is linked to capturing, processing, and transportation, with no cost required for exploration and production,” Mr Al Khateeb said. “However, due to the lack of infrastructure facilities, 55 per cent of current gas production is flared, leaving very little to feed the deprived national grid and industry.” Iraq’s monthly oil production in January was 3.05 million bpd, according to Bloomberg data.

About Iraq Refining ( NewBase research )

Current Iraqi refining capacity is estimated at over 900,000 bbl/d, although estimates vary because effective capacity has fallen below nameplate capacity in many cases.




Existing refineries in Iraq

Refinery Location Nameplate capacity (bbl/d) Notes

North Refining Company

Baiji North-Central Iraq 310,000 New Fluid Catatylic Cracker being installed

Haditha North-West Iraq 16,000

Kisik North Iraq 10,000 10,000 bbl/d under contstruction

Kirkuk North-East Iraq 30,000

Qaiarah North Iraq 20,000 Needs extension of pipeline

Siniya North Iraq 20,000

Midland Refining Company

Daura Baghdad 210,000 Needs extension of pipeline

Diwaniya East of Najaf 20,000

Najaf Najaf 30,000

Samawa Najaf 30,000

South Refining Company

Basrah Near Basrah 140,000 Adding 70,000 bbl/d

Missan South-East Iraq 30,000

Nassiriya South-Central Iraq 30,000

Kar Group (private)

Erbil Erbil 40,000

Source: Middle East Economic Survey, FACTS Global Energy

Iraqi refineries produce too much heavy fuel oil relative to domestic needs, and not enough other refined products such as gasoline. To alleviate product shortages, Iraq set a goal of increasing refining capacity to 1.5 million bbl/d. Iraq has plans for four new refineries as well as plans for expanding the existing Daura and Basrah refineries.

Planned new refineries in Iraq

Refinery Nameplate capacity (bbl/d) Investment Front end engineering contract

Nassiriya 300,000 $9 billion Foster Wheeler

Kirkuk 150,000 $5.5 billion Shaw Group

Missan 150,000 $5 billion Shaw Group

Karbala 140,000 $5 billion Technip

Total 740,000

Source: Middle East Economic Survey, FACTS Global Energy




Abu Dhabi, Vitol buy Shell's Australian oil assets for $2.2bn By Reuters

Royal Dutch Shell has sold its downstream Australian assets to Dutch-owned oil trader Vitol and the Abu Dhabi Investment Council for about A$2.4 billion ($2.2 billion), The Australian Financial Review reported on Wednesday.

The sale would mean Australia's Macquarie Group and its partner Glencore Xstrata were not successful in their efforts to buy the assets, the newspaper said without attributing sources.

Shell has been planning to sell the business, which includes a refinery, import terminals and 900 service stations, as part of a reported worldwide divestment program under CEO Ben Van Beurden, worth about $15 billion.

A Shell spokesman in Australia told Reuters he would not comment on "speculation". A Glencore Xstrata spokesman declined to comment.

The refinery, which struggles to compete with larger, more efficient facilities in Asia, faces an uncertain future. It is believed that Vitol, the world’s largest oil trader, has earmarked the 60-year-old refinery for closure once it takes control of the business.

Shell had planned to convert the refinery, which employs 500 people, into a fuel import terminal if a buyer could not be found. A Shell spokesman in Australia told Reuters he would not comment on “speculation”.

A closure would be a further devastating blow to the Victorian economy, coming hard on the heels of the announcement on Tuesday that Alcoa’s Point Henry smelter will close in August and the planned withdrawal of car makers Toyota, Holden and Ford from Australia.

Vitol and its partners are reported to have won out in the bid for the assets over another party made up of Macquarie Capital and powerful miner-trader Glencore Xstrata. Private equity investment firm TPG had also been vying for the assets though has been out of the sale process for some time.

The sale is part of Shell’s reported wider plan under chief executive Ben van Beurden to offload up to $US15bn ($16.7bn) of assets worldwide in the next two years.

Shell, which has a partnership with supermarket operator Coles in Australia, has had its Geelong refinery on the market since April 2013. It later broadened the sale to include Australian petrol stations.

120,000-barrel-per-day Geelong refinery,

near Melbourne, in Australia.




Nobel to sell Israel's Tamar gas to Jordanian

By: (Reuters) Steven Scheer ,

The partners in the Tamar natural gas field off Israel's Mediterranean coast have signed a deal to sell at least $500 million of gas over 15 years to two Jordanian companies in the first deal outside of Israel. Under the agreement, Tamar will supply 66 billion cubic feet to Arab Potash and its unit,

Jordan Bromine - a joint venture with U.S. Albemarle - at their facilities near the Dead Sea, Noble Energy said on Wednesday.

Texas-based Noble owns 36 percent of the field. Israel's Delek Group, through its units Avner Oil Exploration and Delek Drilling, holds a 31.25 percent share. Isramco Negev has a 28.75 percent stake, and Dor Gas Exploration holds 4 percent. Jordan is hungry for gas amid numerous attacks on a pipeline in the Sinai peninsula that has halted supplies from Egypt.

Tamar, discovered in 2009, is estimated to hold more than 280 billion cubic metres of gas. It began production last March and has already signed a number of lucrative deals in

Israel. The field came on line months after Egypt halted gas supplies to Israel.

After a lengthy and heated debate, the government last year decided to allow 40 percent of its natural gas reserves for export. It is using gas as an opportunity to improve relations with its neighbours including Jordan. It is also thought Israel could ultimately sell gas to Turkey, although ties between the two countries have been frosty over the last few years.

The nearby and much larger Leviathan field last month signed a 20-year, $1.2 billion deal to supply gas to planned a Palestinian power plant once Leviathan starts production in 2016 or 2017. Leviathan is estimated to hold some 540 billion cubic metres of gas, enough to supply Europe for a year. Tamar and Leviathan were the two of the largest gas finds in the past decade and overnight turned Israel into a gas exporter.

Tamar's sales to Jordan are expected to start in 2016 once minimal required infrastructure has been completed. The selling price will be based on a floor of at least $6.50 per one thousand cubic feet of gas with upside linked to the price of Brent crude oil. Noble said it would also charge a fee for marketing and sales services and for the transfer of gas to Jordan. Gross revenue is expected at $500 million with actual sales dependent on final purchased quantities and oil prices at the time of sale, Noble said.

"This deal will pave the way for additional export projects which could enhance regional cooperation as well as provide additional supply to the domestic market and enhanced security of supply through development of additional reservoirs and infrastructure," said Lawson Freeman, Noble's Eastern Mediterranean vice president.

Completion of the deal is subject to various closing conditions and regulatory approvals. Noble said it was in a "number of additional negotiations to sell significant quantities of natural gas from both fields to multiple customers." Earlier this month, Australia's Woodside Petroleum signed a deal to take a 25 percent in Leviathan for up to $2.55 billion.




Eni considers own Mozambique LNG Plant to secure 2018 first shipment http://www.2b1stconsulting.com

The Italian national oil company Eni and its partners China National Petroleum Corporation (CNPC

or PetroChina), Kogas from South Korea, Galp Energia from Portugal and Mozambique Emprecia

Nacional de Hidrocarbonetos (ENH) are evaluating alternative solutions to develop its Mozambique

liquefied natural gas (LNG) project on fast track in order to load the first shipments in 2018.

Together with the Texas-based Anadarko Petroleum Corporation (Anadarko), Eni managed to unveil the gigantic resources of natural gas lying in the deep offshore water Mozambique.

While Anadarko was leading the exploration on the Area-1 of the

Rovuma Basin, Eni was confirming the potential of the region in the Area-4.

On the Area-1, Anadarko expect to accumulate 100 trillion cubic feet (tcf) of natural gas and Eni more than 70 tcf.

Geographically, Mozambique is perfectly located on the Africa East

Coast to export LNG to Asia.

In that perspective, the Mozambique Government motivated the two teams leaders Anadarko and Eni to sign, end of 2012, a memorandum of understanding (MOU) to develop jointly the onshore part of the Mozambique LNG projects and coordinate their efforts regarding the offshore part where fields are linked between the Area-1 and Area-4.

As a result, Eni and Anadarko have started the feasibility study to build the Afungi LNG Park in the Cabo Delgado Province on the northeast coast of Mozambique. According to the reserves consolidated by Eni and Anadarko, this onshore of the Mozambique LNG project is planned to be developed jointly in five different phases of two trains per each phase. Since the feasibility study has been completed for this onshore Mozambique LNG project, three teams of engineering companies are bidding for the front end

engineering and design (FEED) contract.

Eni and Anadarko to agree on Afungi LNG operator

Eni and Anadarko had decided to call for tender on the base of a competitive FEED in order to save time on the engineering, procurement and construction (EPC) phase of the project with already the target to ship first LNG to Asia in 2018.

If it is clear that Anadarko is the operator of the Area-1 and Eni of the Area-4, the question is still pending on the name of the operator of the jointly developed Afungi LNG Park.




This question will need to be answered before the final investment decision (FID) required to sanction the competitive FEED to the winning engineering companies team.

On Area-1, the Anadarko holds 36.5% with Mitsui E&P 20%, BPRL Ventures Mozambique 10%, Videocon 10%, PTTEP 8.5% and ENH 15%.

On Area-4, the Italian leader Eni concentrates 50% through the joint venture Eni East Africa by which PetroChina holds 20%, with the remaining shares being split between Kogas 10%, Galp Energia 10%, and ENH 10%.

With their deep pockets and 70% interests in the project, Eni and PetroChina do not intend to lose time in the development of Mozambique LNG project.

In the same way as they are studying a floating liquefied natural gas (FLNG) solution to speed up the development of the offshore part in Mamba , they are now considering to build their own LNG plant in Quionga, close to Tanzania boarder.

In respect with the reserves in places in the Rovuma basin, Mozambique holds enough gas to feed the Afungi LNG Park, Mamba FLNG and an additional Quionga LNG plant, that would secure first

LNG shipment for Eni and PetroChina from Mozambique LNG by 2018.

NewBase Comments / research :-

Figures given by Anadarko, show the initial two of four trains to be built at the site will require an investment of $8-10bn. Other facilities cost of investment are as shown below in the attached image .




CB&I wins $370m Kuwait refinery contract TradeArabia News Service

Texas-based CB&I has won a $370 million contract from Kuwait National Petroleum Company (KNPC) for setting up its new clean fuels project at the Mina Abdullah I refinery. CB&I, a part of a joint venture led

by Petrofac International along with Samsung Engineering Company, will execute the Mina Abdullah I refinery project.

The project scope includes engineering and procurement for two atmospheric residue desulfurization units, which were previously licensed by Chevron Lummus Global, a joint venture between CB&I and Chevron. The clean fuels project is one of KNPC's major investment projects to upgrade the Mina Abdullah and Mina Al-Ahmadi refineries in order to reach a daily production target of 800,000 bpsd from the current 736,000 bpsd.

Commenting on the win, Patrick K. Mullen, the president of CB&I's Engineering, Construction and Maintenance operating group, said: "This award builds on CB&I's proven experience in the refining industry." "The installation of these units will reduce sulfur, enhancing the ability of Kuwaiti petroleum products to compete on the world market and meet stringent international environmental regulations," he added.-

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NewBase Special Report 20th February 2014

LNG And Challenges Facing Global Gas Market

by G. Allen Brooks

.as more liquefied natural gas (LNG) volumes from Qatar are going to Asia rather than Europe due to better

prices. As we monitor the growing global gas market, and the role LNG plays in its dynamics, there have

been a series of interesting developments that may impact the market’s future dynamics.

In the United States last week, Sempra Energy (SRE-NYSE) subsidiary Cameron LNG LLC won approval from the Department of Energy to export domestic natural gas to countries that do not have free trade agreements (FTA) with the United States. Additionally, the Federal Energy Regulatory Commission okayed the firms’ environmental impact statement, which allows Sempra to move forward in selecting a contractor to build the three cooling trains needed to liquefy up to 1.7 billion cubic feet (Bcf) per day of gas for export. The Cameron terminal becomes the sixth export facility approved by the government to ship gas to

countries without FTAs with the U.S. The six terminals have a combined 8.5 Bcf per day approved export capacity when fully up and running, which represents 11.2% of the current monthly gross volume of natural gas withdrawn from fields based on the latest data as of November 2013 (the latest data available) from the Energy Information Administration’s (EIA) Form 914 survey of gas producers.

If we assume that only these six terminals are built and operate at peak volumes, which would be in 2019 as cited by the press release from Sempra Energy, the 8.5 Bcf per day of LNG exports would represent a lower percentage of estimated gas output – 9.4% if gas production grows at 3% per year, which is below the 3.3% growth rate posted for the last 12 months of reported data. (We calculated the increase between the revised estimate for November 2012 from the Form 914 survey to the initial estimate for the month of November 2013.) The projected LNG export volumes would represent 9.7% of future domestic gas production volumes if production grows at 2.5% a year, an estimate below the 2.8% growth for the latest 12 months based on measuring the change from the initial monthly production estimates for the months of November 2012 and 2013, respectively.

We found it interesting that the November 2013 Form 914 gross production estimate is about 5 Bcf per day higher than the Lower 48 gas supply estimate employed by the EIA in its Short-Term Energy Outlook (STEO) that forecasts energy markets for the next two years and is revised every month. The EIA projects natural gas output to grow by 2.1% in 2014 and 1.3% in 2015, respectively. The EIA provides quarterly estimates for production and other gas market measures, but if we look at the annual averages that reflect the agency’s growth projections, dry gas production volumes would be 70.26, 71.49 and 72.28 Bcf per dayfor 2013, 2014 and 2015, respectively. To put these numbers in perspective, the initial November 2013 Form 914 production estimate for the Lower 48 states was 75.94 Bcf per day.

While it may appear we are splitting hairs over differences in projections of future natural gas supply, those differences will become important to the extent the DOE and FERC continue to approve applications for LNG terminal export permits from among the remaining 20 projects already in the approval queue. The projections are also important because of the difference in the base from which the projection is made and the higher Form 914 growth rate compared to the STEO growth rates. At what percentage of supply will




exports significantly begin to impact natural gas prices? That topic will become the center of the debate over whether the federal government should approve additional LNG export terminals. Manufacturing companies that use natural gas and who are building new plants to capitalize on low U.S. prices will be up in arms if the current cost competitive advantage these manufacturers have against producers from other

regions of the world narrows or possibly disappears due to government policies. There does remain the possibility that the federal government could rescind or restrict export approvals if it determined that shipping natural gas out of the United States was no longer in the nation’s best interest. We remind you that this would not be the first time the federal government reversed energy policies when faced with conditions that could harm the general public. A reversal, or significant limitation of LNG exports, would certainly upset the current view of how the global LNG market will be functioning by the end of the decade.

Another development that could upset the global LNG market is the current expansion of the

Panama Canal. Panama has been building bigger locks and dredging deeper and wider channels to allow the larger container ships and LNG carriers that are increasingly populating the global shipping fleet to traverse the isthmus and reduce the time necessary to move cargos from the Atlantic to Pacific basins. Reducing the travel time could materially improve the profitability of trade, although Panama will extract some of that profit for the use of its canal. For the emerging U.S. LNG export business, the most attractive market on a relative profit measure is to ship gas from the Gulf Coast to Asian markets rather than European buyers. Today, the price difference between Japan and Europe may be as much as $5 per thousand cubic feet of natural gas, not all of which is consumed by extra transportation costs.

A significant issue for the Panama Canal expansion is that the contract was likely underbid. In addition, there appear to be issues with the design specifications and the soils involved in the construction. As a result, the project has fallen behind its original construction schedule and now the third locks’ construction is considerably over budget. The cost overrun is estimated at $1.6 billion out of a total estimated project cost of $5.25 billion. The project was approved by the Panamanians in a referendum in 2006 and commenced work in 2007. The Panama Canal Authority successfully arranged $2.3 billion in financing from a consortium of

international banks in December 2008 at the height of the financial crisis. How to resolve the cost overrun has been an issue for several months but recently reached a critical point when the construction consortium led by Spanish construction company Sacyr said that without resolution it would be forced to stop work. In the past week, reports are that progress on resolving the problem has been made and construction will continue. The original completion date for the expansion was 2015. With the addition of the third set of locks to enable the canal to capture the largest ships to be available by 2025, the project will not be finished until 2019.




The expansion will allow larger cargo ships to pass through the canal. Now, those large ships must offload their containers at one end of the canal, have them loaded on smaller ships that traverse the canal and then have them re-loaded on to the large ships waiting at the other end. To understand the impact the canal expansion will have on shipping economics, note the relative size difference between ships that can currently pass through the canal compared to those that can pass once the expansion is finished. The impact will also be true for LNG carriers. The new, large carriers – Q-Max – that were built to move gas from Qatar to customers worldwide are 1,132-feet long, 177-feet wide and have a draft of 39-feet. This puts

them in the same category as the post-panamax ships in Exhibit 6.

Being able to move very large LNG carriers through the canal will open up more profitable Asian routes to US exporters. Based on the delay in the canal’s expansion, access to Asia may not be available until close to the end of this decade.

The third major issue to potentially impact the global LNG market was the February 9th election for the governor of Tokyo.

Japanese voters elected the candidate backed by Prime Minister Shinzo Abe who favors reducing the country’s reliance on nuclear power in the medium- and long-term and increasing the share of power generated from renewable resources. The opposition candidate attempted to make the election a referendum over nuclear power. Surveys continue to show that the Japanese people favor abandoning nuclear power, either immediately or in the longer term. However, these surveys also show that nuclear power is not as high on the list of voter concerns as jobs, the Japanese economy, an aging population and growing welfare payments.

The last of the country’s nuclear power plants were shut down last September, although there are efforts underway to convince certain provinces to allow restarting some plants. In the interim, the Japanese utility industry has been an aggressive buyer of LNG to fuel its gas-powered plants and the 14 new ones scheduled to enter service between April 2014 and March 2015. Japan accounts for about one-third of all the global LNG shipments. At

the same time, the government waved the country’s carbon emissions restrictions, thus enabling utilities to burn more coal. The industry responded last year by increasing its coal consumption by 16% during the first ten months, while it imported 11% more coal. The use of coal will continue to increase for the




foreseeable future as the industry plans to construct more coal-fired power plants. Cheap coal contributed to a 0.7% decline in the value of coal imports for the first ten months of 2013 while LNG costs soared by 14.3%. Some forecasters believe that the attraction of cheap coal may undercut the LNG market in Japan,

although others say gas purchase decisions are not impacted by low coal prices.

Taken together, the continued approval of U.S. LNG export terminals, the potential delay in the expansion of the Panama Canal and Japan’s push to use more coal and renewables to help offset expensive LNG, along with the Groningen field output reduction and the resulting increase in Russian gas supplies

to Europe, these developments make clear that the global LNG market will be subject to headwinds, tailwinds and crosswinds through 2020. Whatever we may think about how the LNG business will evolve by 2020, those thoughts should probably include alternative scenarios. The global gas industry certainly isn’t going to shrink given the momentum from consumers, producers and regulators, but the projections of market growth may need adjusting. Those adjustments will create knock-on effects in other markets –some relatively easy to forecast, but others unforeseen. +++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++




NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE

Your partner in Energy Services

Khaled Malallah Al Awadi, MSc. & BSc. Mechanical Engineering (HON), USA ASME member since 1995 Emarat member since 1990

Energy Services & Consultants Mobile : +97150-4822502

[email protected] [email protected] Khaled Al Awadi is a UAE National with a total of 24 yearsKhaled Al Awadi is a UAE National with a total of 24 yearsKhaled Al Awadi is a UAE National with a total of 24 yearsKhaled Al Awadi is a UAE National with a total of 24 years of experience in theof experience in theof experience in theof experience in the Oil & Gas sector. Currently working as Technical Affairs Specialist for Emirates Oil & Gas sector. Currently working as Technical Affairs Specialist for Emirates Oil & Gas sector. Currently working as Technical Affairs Specialist for Emirates Oil & Gas sector. Currently working as Technical Affairs Specialist for Emirates

General Petroleum Corp. “Emarat“ witGeneral Petroleum Corp. “Emarat“ witGeneral Petroleum Corp. “Emarat“ witGeneral Petroleum Corp. “Emarat“ with external voluntary Energy consultation for the GCC area via Hawk Energy Service as a UAE operations base , Most of h external voluntary Energy consultation for the GCC area via Hawk Energy Service as a UAE operations base , Most of h external voluntary Energy consultation for the GCC area via Hawk Energy Service as a UAE operations base , Most of h external voluntary Energy consultation for the GCC area via Hawk Energy Service as a UAE operations base , Most of

the experience were spent as the Gas Operations Manager in Emarat , responsible for Emarat Gas Pipeline Network Facility & the experience were spent as the Gas Operations Manager in Emarat , responsible for Emarat Gas Pipeline Network Facility & the experience were spent as the Gas Operations Manager in Emarat , responsible for Emarat Gas Pipeline Network Facility & the experience were spent as the Gas Operations Manager in Emarat , responsible for Emarat Gas Pipeline Network Facility & gas comprgas comprgas comprgas compressor stations . Through essor stations . Through essor stations . Through essor stations . Through

the years , he has developed great experiences in the designing & constructingthe years , he has developed great experiences in the designing & constructingthe years , he has developed great experiences in the designing & constructingthe years , he has developed great experiences in the designing & constructing of gas pipelines, gas metering & regulating stations and in the engineering of supply routes. Many of gas pipelines, gas metering & regulating stations and in the engineering of supply routes. Many of gas pipelines, gas metering & regulating stations and in the engineering of supply routes. Many of gas pipelines, gas metering & regulating stations and in the engineering of supply routes. Many

years were spent drafting, & compiling gas transportyears were spent drafting, & compiling gas transportyears were spent drafting, & compiling gas transportyears were spent drafting, & compiling gas transportation , operation & maintenance agreements along with many MOUs for the local authorities. He has become a reference for ation , operation & maintenance agreements along with many MOUs for the local authorities. He has become a reference for ation , operation & maintenance agreements along with many MOUs for the local authorities. He has become a reference for ation , operation & maintenance agreements along with many MOUs for the local authorities. He has become a reference for

many of the Oil & Gas Conferences held in the UAE andmany of the Oil & Gas Conferences held in the UAE andmany of the Oil & Gas Conferences held in the UAE andmany of the Oil & Gas Conferences held in the UAE and Energy program broadcasted internationally , via GCC leading satelliteEnergy program broadcasted internationally , via GCC leading satelliteEnergy program broadcasted internationally , via GCC leading satelliteEnergy program broadcasted internationally , via GCC leading satellite ChanneChanneChanneChannelslslsls . . . .

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NewBase 20 February 2014 K. Al Awadi

Economy & Finance

New base special 20 february 2014