New base special 27 may 2014

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NewBase 27 May 2014 Khaled Al Awadi

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Mubadala Petroleum to sell complete stake in offshore Thai oil block www.oilreviewmiddleeast.com

Mubadala Petroleum will sell its entire stake in a Thai oil block to an upstream oil and gas firm

KrisEnergy for US$102.5mn.

More than 80 per cent of Thailand’s oil and gas production is located in the Pattani Basin.

Block G10/48 covers 4,696 sq km in Thailand and is estimated to hold 19.6mn barrels of oil. The offshore block contains three oil discoveries and production in one of them is expected for the second half of 2015, KrisEnergy said in a statement

KrisEnergy had acquired a 25 per cent non-operated working interest in Block G10/48 in November 2009. Mubadala Petroleum is the operator of G10/48 and holds the remaining 75 per cent working interest. Mubadala Petroleum is a unit of Mubadala Development Company, an investment firm of the government of the UAE.




Saudi's SABIC inks $595m JV deal for Singapore plant By Reuters

Saudi Basic Industries Corp, Sabic, said on Monday one of its units has entered into a $595 million 50-50 joint venture agreement with Korean petrochemical manufacturer SK Global Chemical for a refined oil products plant in Singapore.

The joint venture between SABIC Industrial Investment Company and SK Global Chemical will own a plant that has been recently completed by SK at its complex in Ulsan, South Korea and will use cutting edge Nexlene technology, Sabic said in a statement.

The new venture will be located in Singapore with an expected annual capacity of 230,000 tonnes. The plan is to set up production bases in highly competitive polyethylene markets in Saudi Arabia and worldwide, the company said.

The agreement is subject to regulatory approval.




Lithuania nears LNG deal with Norway’s Statoil Reuters/Oslo Lithuania is close to signing its first liquefied natural gas (LNG) purchase with Norway’s Statoil, the prime minister and energy companies said, which would end Russian firm Gazprom’s monopoly as its supplier.

The deal, if finalised, would help the Baltic state reduce its total dependence on pipeline gas imports from Russia, its former master in the Soviet Union, which Lithuania sees as a top risk to its national security.

“We have agreed on the main commercial terms (with Statoil), and we are now negotiating the technical details,” Dominykas Tuckus, the head of Litgas, a gas trading arm of state-owned energy group Lietuvos Energija, told Reuters

yesterday. “We plan to complete negotiations in June.”

Statoil confirmed that talks were in an advanced stage, with contract documents pending finalisation and approval. “We want to finalise the deal as soon as possible, with the first deliveries starting in January 2015,” Morten Eek, a spokesman for Statoil, said.

Qatar was one of the bidders, but Prime Minister Algirdas Butkevicius said he authorised Litgas to continue talks with Statoil. Litgas earlier said it was negotiating a five-year deal to import 0.54bn cubic metres (bcm) of gas annually via a new LNG import terminal at Klaipeda port city starting from 2015.

Statoil said the volume would be 0.55 bcm per year, which amounts to six to seven LNG cargoes. Eek declined to comment on the price. Tuckus said the LNG price agreed with Statoil would not be fixed but would “reflect the trends in the global gas market”.

Litgas was also planning to sign master trade agreements with multiple LNG suppliers to buy LNG cargoes on the spot market, he added. Statoil’s Snoehvit LNG facility, Europe’s only liquefaction plant, processed about 4bn cubic metres (bcm) of gas in 2013, while Lithuania’s total gas consumption amounted to 2.7 bcm last year. Snoehvit mainly delivers LNG to Europe and Asia.

Norway’s Hoegh LNG earlier agreed to lease a floating LNG import terminal to Lithuania. Norway’s energy boom is tailing off years ahead of expectations, exposing an economy unprepared for life after oil and threatening the long-term viability of the world’s most generous welfare model.




New IGU Wholesale Gas Price Report Published Source: IGU, ( see attached file, full report )

The 2013 IGU Wholesale Gas Price survey is the sixth to be undertaken in a series which began at the

start of the 2006 to 2009 triennium culminating in the World Gas Conference in Buenos Aires.

Prior to the 2013 survey, previous surveys were undertaken for the years 2005, 2007, 2009, 2010 and

2012. The six surveys are now indicating the changing trends in wholesale price formation

mechanisms over a period of rapid and significant change in the global gas market.

In the 2013 survey responses were received for some 65 out of 108 countries, but these responses

covered 93% of total world consumption.







China and Russia ink PetroChina-Rosneft Orient Petrochemical The State-owned China National Petroleum Corporation (CNPC or PetroChina) and the Russia oil and gas champion OAO Rosneft (Rosneft) signed an agreement on the design and construction planning of the Tianjin Refinery and Petrochemical complex to be built through their joint venture PetroChina-Rosneft Orient Petrochemical Tianjin Company in the China eastern Province of Tianjin.

The signature ceremony of the agreement between CNPC and Rosneft was held during the visit of the President Putin in China in May 2014.

On November 2006, Rosneft and PetroChina signed the first agreement to establish a joint venture for the Tianjin Refinery and Petrochemical complex.

In October 2007, Rosneft and PetroChina established this joint venture under the name of PetroChina-Rosneft Orient Petrochemical Tianjin Company Ltd (Tianjin Refinery).

In this Tianjin Refinery joint venture the working interests are shared between:

- PetroChina 51% is the operator

- Rosneft 49%

To be located in the Bohai Bay, the Tianjin Refinery is expected to supply the fast growing and industry intensive Provinces of eastern China in transportation fuels and hydrocarbon products.

The purpose of this joint venture is for China to secure the sourcing of crude oil, from Russia in this case, and for Russia it brings a opportunity to increase its export of crude oil with long term agreement against prepayment.




At that time PetroChina and Rosneft were intending to supply crude oil the Tianjin Refinery by pipeline from Thaishet in Russia to Tianjin through Daqing in the northeast of China.

But all Rosneft and PetroChina studies for the construction of such a pipeline were leading to costs compromising the entire Tianjin Oriental Refinery project.

PetroChina-Rosneft Orient Petrochemical at feasibility

After investigating all alternative solutions, a new agreement was signed in 2010 defining the delivery to the Tianjin Refinery by tankers from Russia to the Port of Tianjin and then through a 42 kilometers inlet pipeline to the site.

In Tianjin, PetroChina and Rosneft selected a site in the Nangan Industrial zone to build the PetroChina-Rosneft Orient Petrochemical Tianjin integrated refinery.

This Tianjin Refinery should have refining capacity of 13 million tonnes per year (260,000 barrels per day) of crude oil out of which 9.1 million tonnes shall be sourced from Russia.

The refined crude should be light for 80% of the capacities.

In addition to the refinery, the petrochemical complex should include:

- Aromatics production units

- Pyrolysis plant

- 300 gas stations for the distribution of the transportation fuels

With these gas stations, PetroChina is targeting to compete with its historical local rival Sinopec in the Northern and Eastern China Provinces such as Beijing, Changzhi, Hebei, Jinan, Liaoning or Shandong.

The Tianjin Refinery is budgeted to require $4.6 billion capital expenditure.

According to the terms of the agreement signed in May 2014, PetroChina and Rosneft finalized the planning for the whole construction program in beginning with the feasibility study and the preparation of the documents for regulatory approval in expecting the first production in 2020 for the PetroChina-Rosneft Orient Petrochemical Tianjin refinery project.




Tech Talk - China, Russia and East Siberian natural gas The recent agreement between Russia and China for the sale of some 38 billion cu m of natural gas a year for 30 years, at a reported price of $400 billion ends a long-going negotiation between the two countries over the price of that supply. (Which works out at roughly $10 a thousand cubic feet, just over double current US prices). The price apparently includes some $25 billion to help with construction of the pipelines that will start feeding gas into the Chinese networks within four years. It is less than the price of LNG in the Pacific, and thus will likely lead to market adjustments for that product.

Figure 1. Potential interconnections to bring Russian gas into China (Washington Post ) It is equally of interest to see where the other ends of the potential pipelines lie, since this locates the natural gas fields that will be used to provide the supply. Looking at the distribution of pipelines and fields, the current preponderance of connections into Europe is hard to miss, at the same time as is the large gap in development in the Eastern side of the country.




Figure 2. Natural gas basins in Russia (Oil Peak )

Thus while the potential connection from Urumqi to Gorno-Altaisk allows the Chinese pipeline into a feed from the network that supplies Europe, that market is not going to go away. Yet the two towns are just 560

miles apart and the connection has been known as the Altai project, or Western connection, since it was first planned over 10 years ago, extending a new pipe up towards Yamal and the basins that feed Europe.

Figure 3. The Altai pipeline project (Gazprom )

Developments that reach up into Eastern Siberia, above Lake Baykal and Mongolia into the fields of Kovyktinskoe and Chayandinskoye through the “Power of Siberia” pipeline will allow gas from those fields to also feed Western China.




Figure 4. The connecting fields and pipelines for natural gas from Eastern Siberia (Gazprom )

The gas fields will feed into gas production facilities in Irkutsk and Yakutsk with oil production scheduled to start from Chayandinskoye this year, and natural gas production to follow by 2017. The field is expected to yield 25 billion cu m of natural gas and 1.5 million tons of oil a year at full production, and is estimated to hold 1.2 trillion cu m of natural gas. Kovyktinskoe was licensed to Gazprom in 2011 for exploration and production and is estimated to hold natural gas reserves of 1.5 trillion cu m. Smaller local fields at Bratsk and Chikanskoye have been developed since 2007, with the gas being used locally to supply the region.

Figure 5. Developing natural gas fields

in Eastern Siberia (Gazprom ) These two fields alone therefore seem capable of meeting the current sales volume that is to be needed for China, given that the time to delivery is some four years, and both fields are anticipated to be on line, with the gas production facilities, within three years.

Pipeline construction is already underway. The “Power of Siberia” will initially connect into Vladivostock, taking the natural gas to the higher demand industrial Eastern China, but likely the additional funding that China is now providing will also help the Westward expansion to the Western

gateway.




Figure 6. The Power of Siberia natural gas pipeline as planned. (Gazprom )

The natural gas pipeline is being routed along with the East Siberia – Pacific Ocean (ESPO) oil pipeline to simplify logistics, the second section of which was opened by President Putin at the end of 2012, a year ahead of schedule. The two sections will have a capacity of handling 80 million tons of oil a year (roughly 1.6 mbd) as supplies increase from the different fields to achieve that target. (The largest current contributor is the Vankor field producing slightly more than 500 kbd).

Yorubcheno-Tokhomskoye is expected to come on line in 2017, reaching full production of around 100 kbd by 2019, as the field develops the natural gas associated with the field will also be brought into the network. There is anticipated to somewhere around 60 trillion cu. m of natural gas in Eastern Siberia (about 23% of the Russian reserve in 2009) and as this is only now being developed and the infrastructure put in place, it can be expected to last for some considerable time.

So far I have not mentioned the reserves that are now on line at Sakhalin Island. Gazprom built the Sakhalin–Khabarovsk–Vladivostok pipeline in 2011and this carries the natural gas down to Vladivostok, and thence largely into China and other Asian markets. The island also has an LNG facility which supplies that fuel to Japan and North Korea.

Figure 7. Natural gas pipeline from Sakhalin Island (Gazprom )

The pipeline is intended to carry up to 30 bcm per year of natural gas

from Sakhalin fields, particularly those offshore.

Given the size of the fields that are thus available to Russia and that will feed into pipelines that will be in place at the time called for in the new agreement it is clear that the new market will not likely require any input from the fields that are currently supplying Europe and other markets.

As industries switch out of coal and into natural gas, however, a change driven partly by environmental and partly by cost considerations, so the demand for natural gas may potentially increase significantly. (As a minor indication of this the primary fossil fuel at the university in town is now natural gas and the coal fired plant just closed). There is less capacity to store natural gas than other fuels, which can raise some concerns over available supply in particularly cold days of the year. Such

factors may change the situation somewhat, but realistically I would suspect that natural gas will play an increasing role in global fuel supplies for at least another decade.




India: Shell in talks to buy stake in southern India LNG project http://maritimeintel.com/shell-exploring-30-percent-stake-in-kakinada-lng-import-terminal/

Royal Dutch Shell is reported to be considering a 30 percent stake in GAIL India proposed floating liquefied natural gas import terminal project at Kakinada in Andhra Pradesh. Shell last year had announced plans to build a floating LNG of up to 5 million tonnes per annum capacity off the Kakinada coast in a JV with Anil Ambani Group firm, Reliance Power.

Reliance Power earlier this year exited the project and now Shell has decided to join the GAIL-led project which was announced in 2011. The Hindu newspaper quotes sources privy to talks said Shell, GAIL and the Government of Andra Pradesh are talking about the possible equity structure.

Shell, they said, may take 30 percent stake.

Europe’s largest LNG importer GDF Suex UK with whom GAIL originally planned the Kakinada

terminal will take 26 percent. The remaining 44 percent will be held by Andhra Pradesh Gas

Distribution Corp, a company jointly promoted by GAIL Gas Ltd and Andhra Pradesh Gas

Infrastructure Corp. GAIL Gas is wholly-owned subsidiary of GAIL India.

Shell already operates a 5 million tonne LNG import facility at Hazira in Gujarat, GDF Suez is

present in India in the natural gas business since 1997, with a 10 percent stake in Petronet, the

owner of LNG import terminals in Dahej and Kochi. FSRU is a faster and low-cost solution for

LNG importation. This is the first of its kind in India.




APPEA Warns of Rising Exploration Costs Press Release, APPEA

The urgent need to address the global cost competitiveness of Australia’s oil and gas industry has

been highlighted by a new analysis that shows fewer exploration wells are being drilled offshore

despite significantly higher expenditure.

An analysis of recent data released by the Australian Bureau of Statistics and APPEA shows the number of offshore wells drilled in Australia has fallen by more than two-thirds since 2003, while the total cost has increased five-fold.

While the cost of individual wells varies considerably depending on a range of geographical, geological and technical factors, the average cost of drilling offshore wells is now more than $130 million.

APPEA Western Region Chief Operating Officer Stedman Ellis said the analysis is further evidence of the significant cost pressures on Australia’s offshore exploration and production.

“These figures reflect a range of factors, including higher daily rig rates and the fact that drilling is shifting

further offshore to deeper, more remote and more difficult waters,” he said.

“The increase in drilling expenditure reflects broader cost pressures across the value chain from

exploration to development and through to production. These are being exacerbated as the industry moves

into more complex offshore areas. The low-hanging fruit has been picked.




“Australia is already at the top of the cost curve for bringing gas to market. Greenfield projects in this

country can be almost double the cost of new LNG competitors in East Africa, North America and other

locations.

“These cost pressures are responsible for a new pricing paradigm that has seen domestic gas prices rise to

more sustainable levels.”

The exploration cost analysis is contained in an APPEA submission to Western Australia’s independent Economic Regulation Authority supporting its recent recommendation that the WA Government immediately abolishes its costly and inefficient domestic gas reservation policy.

Ellis said the ERA had supported APPEA’s long-held view that the reservation policy threatened the state’s energy security by discouraging investment in new domestic gas projects.

“Big industrial gas customers who benefit from gas reservation in WA have been trying to argue that record

investment in offshore exploration shows the policy is not a disincentive to producers,” he said.

“But they conveniently ignore the fact that while exploration expenditure has increased since the policy’s

introduction, the number of wells drilled has steadily declined.

“Australia’s ability to develop new gas projects is already threatened by rising costs at home and growing

competition abroad. Policies that dictate where and how gas can be sold represent a further barrier to

investment.

“APPEA believes long-term energy security is best delivered through efficiently operating markets and by

encouraging new entrants and competition, a view that is shared by other Australian governments that have

considered and rejected the need for reservation policies.”




Indonesia offering 21 conventional and shale oil and gas blocks for tender in 2014

Source: energy-pedia

Indonesia announced Friday it is offering 21 conventional and shale oil and gas blocks in its first bidding round for 2014. The blocks on offer include 13 conventional oil and gas blocks and eight shale blocks, Oil and Gas Director General Eddy Hermantoro told reporters at an industry convention on Friday.

Indonesia is offering six conventional blocks via direct proposal tender (North Central Java Offshore,

Kualakurun, Garung, Offshore Pulau Moa Selatan, Dolok, South East Papua), five conventional blocks via regular tender (North Madura II, Yamdena, South Aru II, Aru Trough I, Aru Trough II) and two conventional blocks via direct proposal from Pertamina only (Abar and Anggursi). The tender schedule for the conventional blocks is as follows:

• DIRECT PROPOSAL TENDER: Access Bid Document : June 2, 2014 – July 14, 2014: Bid Submission : July 16,

2014




• REGULAR TENDER: Access Bid Document : June 2, 2014 – October 1, 2014: Bid Submission : October 6, 2014

Indonesia is offering three shale blocks via direct proposal tender (Sakakemang Deep, Selat Panjang Deep,

Palmerah Deep), three via regular tender (Shinta, North Tarakan, Kutai) and two via direct proposal from Pertamina only (Jambi I Deep and Jambi II Deep). The tentative schedule for the unconventional oil and gas bidding round is as follows:

• DIRECT PROPOSAL TENDER: Access Bid Document: June 23, 2014 - August 6, 2014: Bid Submission: August

07, 2014

• REGULAR TENDER: Access Bid Document: June 23, 2014 - October 20, 2014: Bid Submission: October 21,

2014

BID DOCUMENT ACCESS The Bid Document which correspond to 1 (one) block shall be purchased in the amount of Five Thousand US Dollars (US$ 5,000). Payment shall be made to the account of "Kegiatan Pelaksanaan Pengelolaan (KPP) Wilayah Kerja Minyak dan Gas Bumi number 122.00.0110899-5, Bank Mandiri Cabang Jakarta Kebon Melati” (Swift Code BMRIIDJA). Send an email to [email protected] confirming your payment, stating amount and block(s) name, and attach the proof of payment.

MIGAS will reply your email confirming Bid Document pick up schedule.




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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]

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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 Oil & Gas sector. Currently working as Oil & Gas sector. Currently working as Oil & Gas sector. Currently working as

Technical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary EnTechnical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary EnTechnical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary EnTechnical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation for ergy consultation for ergy consultation for ergy consultation for

the GCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operations the GCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operations the GCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operations 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 & gas compressor stations . ThrougManager in Emarat , responsible for Emarat Gas Pipeline Network Facility & gas compressor stations . ThrougManager in Emarat , responsible for Emarat Gas Pipeline Network Facility & gas compressor stations . ThrougManager in Emarat , responsible for Emarat Gas Pipeline Network Facility & gas compressor stations . Through the years , he has developed h the years , he has developed h the years , he has developed h the years , he has developed

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routes. Many years were spent drafting, & compiling gas transportation , operation & mairoutes. Many years were spent drafting, & compiling gas transportation , operation & mairoutes. Many years were spent drafting, & compiling gas transportation , operation & mairoutes. Many years were spent drafting, & compiling gas transportation , operation & maintenance agreements along with many MOUs for ntenance agreements along with many MOUs for ntenance agreements along with many MOUs for ntenance 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 andthe local authorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE andthe local authorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE andthe local authorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE and Energy program broadcasted Energy program broadcasted Energy program broadcasted Energy program broadcasted

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NewBase 27 May 2014 K. Al Awadi

Economy & Finance

New base special 27 may 2014