Despite marginal gas production growth for natural gas in 2002, LNG's share of the world's trade in natural gas set records. Last year, marketed world gas production edged up only 1% to 2,580 billion cu m (bcm; 1bcm = 37.3 Bcf and 0. 73 million tonnes of LNG), reflecting the continued economic slowdown in many parts of the world.
Exports and imports of gas rose 2.6% to 697 bcm, while LNG shipments increased 4.3% to a record 430 bcm.

In the first half of 2002, demand for LNG was stagnant but raised more than 8% in the second half. Spot and short-term LNG sales accounted for a record 9% of the total.
LNG now accounts for 27.4% of internationally traded volumes and 5.8% of marketed production. Since the end of 2002, four new trains have been commissioned: Trains 2 and 3 in Trinidad and Tobago's Atlantic LNG project, Train 3 at Nigeria LNG, and the first train of Malaysia's LNG TIGA.
An additional 40 million tonnes/year (tpy) of capacity is under construction. Many more expansions and new projects are being considered not only in countries that currently export LNG but also in new parts of the world, including Iran, Bolivia, Peru, Angola, Russia, and Equatorial Guinea. This is the first of two articles that will review major trends in LNG markets, exports, and projects based on the most recent information available.  The concluding article, next week, will review exports and liquefaction facilities.

Evolving industry
When the LNG industry originally developed in the 1960s and 1970s, it was largely market-driven. For the UK, France, Spain, and the US, LNG was a means of supplementing pipeline supplies in the face of existing or anticipated shortfalls.
Japan, which lacked domestic and pipeline supplies, LNG from Alaska and the Asia-Pacific region was virtually the only source of natural gas available and mitigate dependence on Middle Eastern oil.
In this early period, security of supply was the main concern of buyers and project developers alike. Plants were over-engineered to prevent supply interruptions; long-term contracts (typically 20 years) with stringent take-or-pay requirements linked buyer and seller in an ironclad chain.  Ships were exclusively dedicated to projects. Consequently, only large companies with big balance sheets could participate, creating what has been called "the world's most exclusive club."

Today, one of the major forces driving the global LNG industry is the desire of producers and resource owners to commercialize reserves they have already discovered.  ExxonMobil Corp., Royal Dutch/Shell Group, TotalFinaElf SA, ChevronTexaco Inc., ConocoPhillips, Petroliam Nasional Bhd. (Petronas), Statoil ASA, Qatar Petroleum General Corp., and other private and state owned companies with substantial reserves are seeking to develop markets by building their own terminals, buying interests in other companies' receiving terminals, or acquiring access in open-access terminals. At the same time, LNG buyers such as Tokyo Gas Co., Tokyo Electric Co., and Korea Gas Corp. are acquiring shares in upstream reserves and liquefaction plants and buying their own ships in order to maximize their investments.

There is no necessary correlation between size of reserves and LNG production capacity despite its enormous reserves, Iran for political reasons, has never become an LNG exporter, although several projects are now being developed or proposed. 

Apart from Abu Dhabi, the Middle East was not a participant in -the LNG industry until the 1990s, in part because of policy decisions to develop gas resources for chemicals and other uses.  Trinidad, on the other hand, became a major exporter because of its proximity to major markets and government support despite its much smaller reserve base.

As a rule of thumb, it takes 1 Tcf of proved gas reserves to produce 1 million tpy of LNG for 20 years plus a tailgas requirement of 1 to 3 Tcf.
Thus, a 6million-tpy project requires a reserve base of around 8-10 Tcf, a criterion met by many fields.  If the feed gas contains economically valuable quantities of condensate and LPG, this can add I 0I S% to project revenue; such impurities as C02 and nitrogen can damage the economics.  A preferred feed-gas parameter is at least 80% methane, less than 4% acid gas, less than 1 % nitrogen, at least 3% propane, and 4% butane.

The cost of production can range from effectively zero when the resources are large and rich in condensates to $1 /Mcf or even higher.  Typically the government of the producing country charges a royalty and gets revenue from owning a share in the production and liquefaction plant.

Over the past decade there has been a 35% to 50% decline in LNG production and transportation costs.  The average cost of I tpy production capacity is now around $250/tonne for a greenfield plant and $175 for an expansion train, compared with more than $500 in 1965-70 and $300$400 throughout the 1970s and 1980s.

Economies of scale clearly play a role in bring costs down. The average train size has grown from around 1 million tpy in the 1960s to 3 million tpy in 2000, while the number of tariffs per project declines. Today trains in the 4-4.8-million tpy range are becoming the standard for new construction (e.g., Nigeria LNG Trains 4 and 5, Northwest Shelf Train 4, Ras Laffan Train 3), and ExxonMobil is looking at 7-million-tpy trains for a new project in Qatar.

Also contributing to lower costs is:
Enhanced engineering know-how and project execution techniques.
Advances in technology (e.g., gas turbines instead of steam turbines, larger more efficient axial compressors, improved equipment configurations)
Competition at the frontend engineering design (FEED) stage as well as for construction contracts (e.g., Atlantic LNG). Larger and fewer storage tanks.
Integration of LNG terminals with power plants (e.g., EcoEl6ctrica in Puerto Rico)
 In the future, floating production storage and offloading facilities (FPSOS) could take advantage of modular construction to reduce costs.

LNG prices are falling
As new importers China and India negotiate more favorable terms, old importers such as Japan and Korea are obtaining price and offtake concessions when they renegotiate their contracts.  Although as yet no single world price for LNG exists, the expanding spot trade has led to a greater influence of US prices, and projects are being developed to supply markets in several regions. Some people in the industry believe LNG is on its way to becoming a commodity.

Ship costs are also coming down from a peak of more than $250 million in 1991 to around $160-$170 million today.  Nine new ships were delivered in 2002, bringing the total fleet to 140 at yearend.
 

The world's biggest producer and exporter of gas is inexorably losing its grip on the  market. Indonesia pioneered and dominated the regional market for 25 years through its state-owned energy company, Pertamina. 

Indonesia seeking bigger LNG supply to China's Fujian 
JAKARTA, Dec. 9 (Xinhua) 
The Indonesian government is expecting to raise its liquefied natural gas (LNG) supply to Fujian Province of China to 5 million tons a year, an official said here Tuesday. The two sides agreed to deepen cooperation in energy sector during a meeting held Monday evening, said Iin Arifin Takhyan, director general of oil and gas under the Ministry of Energy and Mineral Resources. Indonesia and China signed an LNG supply contract in 2002 under which Indonesia pledged to supply Fujian with 2.6 million tons of LNG a year starting from 2007. Iin told reporters at the parliament building that Indonesia is making efforts to obtain an LNG supply of 5 million tons a year in line with the growing demand for LNG in  Fujian. Iin said both sides "have been preparing an LNG terminal in Fujian. " 

In earlier days Pertamina was Southeast Asia's only supplier on the market and had the power to dictate prices. But the entry of new players from Malaysia, Australia, Brunei and Qatar in the late 1980s heralded a new buyer's market that remains to this day. Pertamina lost its monopoly for handling the marketing of Indonesian liquefied natural gas (LNG) overseas in 2001. 

Now Malaysia, Australia, Qatar and Russia all threaten Indonesia's regional LNG export markets. Qatar, with its huge gas reserves, has been able to lower LNG production costs, making its gas cheaper than other countries'. Qatar offered a price for a Taiwanese contract that was even lower than the Indonesian domestic price, said Minister of Energy and Mineral Resources Purnomo Yusgiantoro. 

China, bent on enhancing its own energy security, started to change the equation in Asia's regional energy market when it awarded a highly contested tender to supply liquefied natural gas to Guangdong province to a consortium led by Australian energy giant Woodside Petroleum Ltd. China did follow up with a second contract for Fujian province to Tangguh LNG, an Indonesian project in Papua. 
Nonetheless, Australian Prime Minister John Howard, who had visited Beijing to lobby for the Australian bid, hailed China's announcement of the Guangdong contract as "a new energy partnership between our two nations". 

Golkar, now in opposition after having ruled Indonesia during the entire length of former president Suharto's reign, castigated the government of President Megawati Sukarnoputri for weak lobbying and sending a delegation headed by Megawati's husband Taufik Kiemas to Beijing to push for the Guangdong contract, China's first deal to import foreign natural gas.

The shock waves have reverberated through Indonesia's gas industry, prompting Resources Minister Purnomo to warn that Indonesia could no longer rely on its old paradigms for selling LNG. The warning has not been ignored and, 12 months later, amid a stream of bad news for the country's LNG exports, the government has prepared to bite the bullet, face the loss of part of its traditional markets, and focus on domestic demand. 

There could be more bad news coming. Japan, the world's largest LNG importer, Taiwan and South Korea have been buyers for Indonesian LNG for decades. Combined demand in the three countries is likely to increase by some 35 million tonnes by 2010. Though they still take most of Indonesia's LNG exports under long-term contracts of between 20 and 30 years, these will expire in the next few years.

One 8.4-million-tonne contract with Japan expires in 2010 and another, of 3.6 million tonnes, in 2011. Sales contracts with Kansai Electric, Kyushu Electric, Nippon Steel, Tohoku and Tepko, amounting to a total of 10.15 million tonnes per year, are set to expire in 2010. 

Also, Japan's Tohoku Electric Power Co moved the goalposts this month by shortening a long-term LNG import contract with Pertamina and slashing the volume from 3 million tonnes to 830,000 a year. Megawati herself, on an official visit to Tokyo, vainly lobbied the Japanese government to urge Japanese buyers to extend their purchase contracts. 

A week earlier  Taiwan's state-owned Taiwan Power Co (Taipower) had awarded an $8.6 billion contract to its state-owned Chinese Petroleum Corp (CPP) to supply LNG to its Tatan power plant. The LNG will come from Qatar's Ras Laffan (Rasgas) project. United Resources, which lost the bid, would have sourced LNG from Tangguh. 

Tangguh's  gas fields contain 14.4 trillion cubic feet of proved and certified natural-gas reserves.
The plant is  designed to have an installed capacity of 7 million tonnes per year from two initial processing facilities, but desperately seeks supply contracts to supplement the minor "runner up" contract to supply Fujian.

The project includes development of gas fields and construction of the LNG plant, tankers, related infrastructure and pipelines, but delivery of gas from Tangguh will not be before early 2007,  coinciding with completion of China's Fujian gas terminal. This left the plant, where construction is expected to get under way next year, with only the one confirmed order, although a new deal, still being negotiated with Japan's Western Buyer, may give Tangguh a 2.6-million-tonnes-a-year LNG supply contract starting from 2010. Japan, to guarantee stable supply, wants the 6.0-million-tonne-a-year contract to stipulate that LNG will be supplied by two producers - Bontang and Tangguh. The whole deal would bring Indonesia $8.5 billion over 25 years. 

The Bontang plant uses a pool of natural gas piped from the offshore East Kalimantan fields operated by Total, Unocal and Vico. It is owned 55 percent by Pertamina, 20 percent Vico, 10 percent Total and 15 percent by Japan Indonesia LNG Co (JILCO).

The two major facilities, Arun at Lhokseumawe, in Aceh, and Badak, in Bontang, condense natural gas by refrigerating it to one-six-hundredth of its volume for shipment in  tankers. Both plants were built in the late 1970s under supply contracts to Japan, although excess production was sold to other buyers. They have combined production capacity of 31.6 million tonnes. Bontang accounts for 22.25 million tonnes of that, and this output alone accounts for some 25 percent of the Asian LNG market. 

However, neighboring Malaysia is expanding output this year from its third LNG venture at Bintulu in the north of Borneo that could boost its capacity to 23 million tonnes a year, leaving Bontang in second place. 
The Bontang plant uses a pool of natural gas piped from the offshore East Kalimantan fields operated by Total, Unocal and Vico. It is owned 55 percent by Pertamina, 20 percent Vico, 10 percent Total and 15 percent by Japan Indonesia LNG Co (JILCO).

Total, the world's fourth-largest energy firm, has said the future of its business in Indonesia would depend on Japanese buyers' readiness to extend their LNG purchase  contracts from the Bontang plant. Total supplies 65 % of the feed gas to the eight refineries at Bontang. LNG and LPG products are exported and the condensate is returned to Unocal facilities in Santan,  East Kalimantan. 

Pertamina plans a ninth production line, Train-I at Bontang, to compensate for falling output from the Arun plant, which liquefies gas supplied by Exxon Mobil Corp. But Total chief executive officer Thierry Desmarest has said the company is unlikely to build the new train until it can confirm that Japanese buyers would extend their contracts. "It is more important for us to confirm that our existing trains have a market," he warned. This ninth train, if it goes ahead, would add 3 million tonnes' capacity and cost about $550 million to build. 
The Bontang plant can also expect a much longer production period than originally predicted, with discoveries of new reserves in East Kalimantan still continuing. One of  Korea Gas's two contracts to buy LNG from Arun, for 2.3 million tonnes a year, ends in 2007 and the Tohoku Electric contract for 3 million tonnes a year ends in December 2004. 

All the signs are that the government is fundamentally rethinking its domestic energy strategy. 
Moving to natural gas from the expensive, mostly imported, fuel oils would redress a  situation where the country's domestic gas sector, despite extensive reserves, remains almost undeveloped compared with its neighbors.
Investment is planned in pipelines and LNG receiving terminals to supply the essential infrastructure for domestic distribution. The Indonesian government is currently  negotiating with a consortium to build two receiving  terminals, expected to be completed by 2007. 

State-owned gas-distribution company Perusahaan Gas Negara (PGN) and state-owned power utility Perusahaan Listrik Negara (PLN) will join the consortium to build the terminals, one near Jakarta and the other at Surabaya, the country's second-largest city and industrial area. 

LNG could not compete with oil-based fuels for years in the local market because of the government's subsidy policy. International Monetary Fund insistence on the gradual scrapping of the fuel subsidies has also helped to bring the domestic gas market into planner's radar screens. 

Major customers include PGN, the state fertilizer producer, which processes it into ammonia and urea, and scores of large industrial users throughout Java. PLN has now been persuaded to look on natural gas as the fuel of choice for several of its power plants. Increasing the amount of LNG and piped gas sold in Java and other areas of the country that face energy shortages makes real sense, with annual power demand estimated to be growing by about 10 percent annually. 

Proper development of the country's domestic gas market would not only produce enormous savings, but would also deliver an environmentally clean fuel.

The Brunei Liquefied Natural Gas plant in Lumut, one of the largest in the world, was upgraded and expanded at a cost of around B$100 million in 1993. LNG from the plant is transported to Japan by a fleet of seven specially-designed 100,000-tonne tankers with a capacity of 73,000 cubic metres of LNG each. The sale of LNG has grown to be as important a revenue earner as oil exports. Domestic market takes up only 2 per cent of the LNG produced.

At the current rate of production, the proven reserves of natural gas is estimated to last another 40 years. However, the discoveries of new gas fields and the possiblity of more finds will enable Brunei to benefit from the growing demand for LNG in Asia, which is needed primarily for power generation. 

North Asia is seen as the world's largest LNG market over the next twenty years, and Australia, like its competitors, is looking to supply the growing regional and global demand for LNG. India, too, presents significant market opportunities. Australia - again, like its competitors - is fortunate in having huge uncommitted gas reserves and close proximity to potential new markets in Asia. And - of great importance - Australia is seen across the world as a reliable and secure supplier.

Expansion plans for the North West Shelf LNG Project in Western Australia, the planned Gorgon field development - and other projects in the Northern Territory - have the capacity to expand the industry and add considerably to LNG trade worldwide, especially in the Asia Pacific. The North West Shelf Project is the largest single resource project in Australia, and represents a AUD 12 billion investment in off-shore production and onshore processing facilities. The Joint Venture Participants' expansion of facilities at Karratha will potentially double Australia's LNG production to 14.5 million tonnes by 2003. 
 

Lake Charles The LNG Terminalling Service Agreement enables BGLS to control approximately 81% of the capacity of the Lake Charles LNG importation terminal from 1 January 2002 until 31 August 2005. From 1 September 2005, BGLS will control 100% of the capacity. The terminal currently has the capability to receive, store, vaporise and deliver an average daily send-out of 630 mmscfd of gas on a sustainable basis, and 1 bcf per day on a peaking basis. The terminal has access to 15 major intrastate and interstate natural gas pipelines, as well as to Henry Hub, through the Trunkline Gas Pipeline system.  In October 2001, CMS Energy Corp, then owners of the Lake Charles LNG terminal, announced a planned expansion of their facility. This expansion is scheduled to be completed by the start of 2006. The sustainable throughput capacity will be expanded to 1.2 bcfpd, storage increased from 6.3 bcf to 9 bcf, and a layberth and ancillary services constructed. All of the capacity of the expansion is committed to BGLS. 

BGLS is pursuing a number of options to create a diversified supply portfolio for the Lake Charles terminal. These include buying LNG from a variety of suppliers, including third-parties as well as BG equity LNG production, building a portfolio of LNG supply with a variety of tenures, including short-term and long-term contracts, and purchasing LNG on both a Free on Board (FOB) basis using BG’s own or acquired shipping resources, and on an ex-ship or Carriage, Insurance and Freight (CIF) basis whereby the supplier provides shipping. 

On 13 May 2003, BG announced the signing of the following two long-term LNG purchase arrangements:
a MoU for 2.5 mtpa of LNG for 20 years, beginning in 2005 or early 2006, from the Nigeria LNG (NLNG) Plus project (Trains 4 and 5) in Finima, Bonny Island, Nigeria. In addition, beginning in 2003, the agreement will provide BG with the ability to purchase all excess volumes not taken by NLNG’s long-term customers of Trains 1, 2 and 3. The purchase is on a CIF basis whereby NLNG supplies the shipping. 
a LoU for 3.4 mtpa for a period of 17 years beginning in 2007 from a proposed LNG project to be developed by Marathon Oil and its partners on Bioko Island, Equatorial Guinea. The purchase is on a FOB basis with BG supplying the shipping. Feedstock gas for the project will be sourced primarily from the Marathon-operated offshore Alba Field, in which it has a 65% interest.  On 2 July 2003, a further LNG supply announcement was made:

initial deliveries of 3.6 mtpa, starting 2006, representing the entire output of Train 2 of the Egyptian LNG project (ELNG), in which BG is a partner (see page 34). The purchase agreement will cover the entire output of ELNG Train 2 but will provide for volumes to be switched to BG’s Brindisi LNG terminal in Italy, approximately one year after Train 2 commercial operations start.  In addition, BGLS is planning to purchase volumes from BG’s interest in Atlantic LNG Train 4, which is anticipated to commence operations in the first quarter of 2006. 
 
Sempra, Shell on Course for LNG Land Permit
BNAmericas 3/18/2004 URL: http://www.rigzone.com/news/article.asp?a_id=11644

It is "practically a fact" that energy companies Shell and Sempra will receive a land permit for their proposed liquefied natural gas (LNG) terminal at Costa Azul in Mexico's Baja California state, the state's minister for economic development, Sergio Tagliapietra, told BNamericas.

Tagliapietra addressed a letter to "the international community" on March 12 saying that the state supports companies "that have met all the legal and technical requirements associated with LNG projects in Baja California." The move reflected concern about the possible negative fallout in the international business community when US company Marathon abandoned a US$1.5bn energy complex after the state government expropriated the land where the project was planned.

The state government maintains that Marathon did not follow the proper procedure because the company never applied for permission from the state and Tijuana municipal authorities although it obtained a permit from national energy regulator CRE in 2003.
"Companies know that it is necessary to comply with the regulations as well as responding to the market demands. Sticking to the law guarantees and gives certainty to investments," Tagliapietra said. "We are a state that promotes investment and aim to provide the best information possible for companies to make decisions. On the other hand, companies should act in accordance with the regulations that apply in each case," he added.

Apart from the Sempra-Shell project, ChevronTexaco plans a regasification terminal 13km offshore from Tijuana. "Both projects will generate benefits and contribute to the strengthening of our state's infrastructure, making us more attractive to investment. However, it is not the state government alone that determines whether these plants get built," Tagliapietra said.

Shell and Sempra have received a permit from the CRE and ChevronTexaco expects to receive one sometime this year, but the latter's project has attracted negative press because of its location near the environmentally-sensitive Coronado Island.

South Korea is expected to import larger quantities of gas and oil from Oman, according to Shin Kook Hwan, South Korean Minister of Commerce, Industry and Energy. "The demand for oil and gas is increasing in South Korea, which means we are going to import more gas and oil from Oman, our steadfast partner," he said. South Korea is the biggest buyer of Oman's LNG.  The first shipment was sent last April. The agreement requires Korea Gas Corp (Kogas) to import 4.1 mm tpy of LNG annually for 25 years. Since then, 19 cargoes of LNG have been exported, of which 15 have been to Kogas. Oman supplies 10 % of South Korea's LNG needs. 

Hwan said South Korea is involved in the offshore Bukha Hanjam gas project in Musandam near the Strait of Hormuz. "Given the opportunity, we will go for more joint ventures." He was optimistic about winning the $ 750 mm Sohar Refinery contract.  "Our companies have won contracts in Oman before and we expect to win more," said the minister, referring to Daewoo's $ 65.5 mm deal to build a reef at Sohar port and Hyundai's $ 25.5 mm dredging and reclamation contract for the port due for completion by 2002. Samsung and Hyundai are bidders for the construction of the Sohar Refinery with a planned capacity of 75,000 bpd.  Hwan said talks with Maqbool bin Ali Sultan, Oman's Minister of Commerce and Industry, were very fruitful, marked by the signing of an MoU to promote exports, investment and training. He also met with Ahmed bin Abdulnabi Macki, Minister of National Economy. "The visit has brought us still closer."  Maqbool bin Ali Sultan said the two sides discussed the possibility of joint ventures in tourism and information technology, with both laying increasing emphasis on trade contacts. "We want to benefit from the South Korean experience in the development of small and medium-sized businesses," the Omani minister said.  The Korean minister voiced concern over rising oil prices, hoping the GCC states would impress upon OPEC to stabilise energy supplies. 

Oman, an independent oil producer, exported more than 150,000 bpd to South Korea last year. 
 

The Indonesian government is expecting to raise its liquefied natural gas (LNG) supply to Fujian Province of China to 5 million tons a year, an official said here Tuesday. The two sides agreed to deepen cooperation in energy sector during a meeting held Monday evening, said Iin Arifin Takhyan, director general of oil and gas under the Ministry of Energy and 
ineral Resources. 

Indonesia and China signed an LNG supply contract in 2002 under which Indonesia pledged to supply Fujian with 2.6 million tons of LNG a year starting from 2007. Iin told reporters at the parliament building that Indonesia is making efforts to obtain  an LNG supply of 5 million tons a year in line with growing demand for LNG in Fujian. Iin said both sides "have been preparing an LNG terminal in Fujian. " 
Taiwan

Petroplus International and BG Energy Holdings, a subsidiary of BG Group, have announced that they plan to work together  on the continuing development of Petroplus' proposed LNG import terminal at Milford Haven in Wales. The terminal, which has already  received planning permission, will bring jobs to Wales and gas to help to meet the expected UK supply shortfall from 2007 when the  new facility is expected to become operational. 

Under the terms of a Memorandum of Understanding (MoU) signed, BG intends to purchase a 50 % equity stake in Dragon LNG, a  special purpose project company already established by Petroplus to develop the project. In addition to this equity position, BG intends  initially to contract for the use of 2.2 mm tpy of capacity at the facility. This represents half of the initial planned throughput capacity.  Dragon LNG's sale of the remaining 2.2 mm tpy throughput capacity of the terminal is ongoing. 

The existing Milford Haven site includes marine docking and unloading facilities at three berths. The development proposal provides for  the adaptation of these facilities for use as an LNG tanker berth, with pipelines and other facilities as necessary for unloading LNG and  transporting it to storage tanks onshore within the existing area. 

Paul van Poecke, CEO, Petroplus Logistics, said: "We are very pleased to announce the successful conclusion of an MoU with BG.  We are looking forward to working closely with our new partner, whose experience and leading role in the global LNG market will help  us to develop further the work we have done over the past two years at our Milford Haven site. The transaction is a significant step  forward in Petroplus' strategy of rebalancing activities and is consistent with our broader strategic agenda."   Martin Houston, Executive Vice President and Managing Director, North America, Caribbean and Global LNG, said: "BG is already a  major supplier of gas to the UK and is committed to continuing to seek new ways to serve this growing market. 

The development of this facility with our partner, Petroplus, will allow us to deliver competitively priced natural gas to meet expected  market requirements. This project will extend our position in the UK and strengthen our LNG leadership position in the Atlantic Basin."   The Petroplus Milford Haven facility, located in Wales, United Kingdom, was acquired by Petroplus from Chevron in 1998. The complex  comprises 1,550,000 cm of storage capacity, deepwater jetties and a mothballed refinery including a cogeneration facility. Petroplus  Tankstorage, a wholly owned subsidiary of Petroplus International, currently operates the site as a commercial tank farm for petroleum  products. 

Petroplus International was established 10 years ago and is a leading player in the European midstream oil market. The midstream  sector encompasses refining, marketing and logistics (predominantly tank storage).   Petroplus is the owner of refineries in Antwerp (Belgium), Cressier (Switzerland) and Teesside (United Kingdom) with a total capacity of  270 000 bpd. Petroplus has a sales volume in excess of 20 mm tpy of oil products and a storage capacity of almost 5 mm cm  throughout Western Europe. Petroplus International is publicly listed in the NextPrime segment of Euronext, Amsterdam.   LNG represents one of BG Group's core business segments. The company is involved in developing LNG projects in Trinidad & Tobago,  Egypt, Italy, India, Indonesia, Bolivia and Iran. 

In January 2002, BG LNG Services (BGLS), a wholly owned subsidiary of BG Group, took 81 % of the capacity at North America's  largest operating import terminal, Lake Charles in Louisiana, which has the capability to receive, store, vaporise and deliver 4.7 mm  tpy. From September 2005, BGLS will take 100 % of the capacity. In March 2003, the Federal Energy Regulatory Commission gave  approval for expansion of the terminal to 8.9 mm tpy. Construction of the expansion plant is expected to be completed by the beginning  of 2006. 

BG has four business segments -- Exploration & Production, LNG, Transmission & Distribution and Power Generation. Active in some  20 countries on five continents, its core geographical areas are the UK, Kazakhstan, Egypt, Trinidad and Tobago, South America and  India. 

The contracts were awarded to CB&I Europe BV and CMP Holdings BV, both units of The Woodlands, Tex.-based Chicago Bridge & Iron Co. NV (CB&I).

The CB&I units will handle the engineering, procurement, and construction (EPC) of two 100,000 cu m LNG storage tanks, which will be the first LNG tanks designed and constructed in Russia, according to CB&I.

The CB&I units were selected to construct the tanks by Chiyotec Ltd. and CTSD Ltd., both of which were awarded contracts along with their Russian partners, NIPIgasperabotka and Khimenergo Consortium, for the implementation of the overall LNG project by the project's owner, Sakhalin Energy Investment Co. Ltd. (SEIC).  SEIC shareholders are Shell Sakhalin Holdings BV, Mitsui Sakhalin Holdings BV, and Diamond Gas Sakhalin BV.

CB&I said that completion of the tanks is anticipated in spring of 2OQ7 and first LNG is expected to be delivered from the terminal during 2007. 

Qatar will spend $25 billion over the next six years to more than quadruple its LNG export capacity to 63.5 million t annually, said Faisal Mohamed al-Suweldy, vice chairman of Qatar Liquefied Gas Co. (Qatargas).

He noted that Qatargas already has heads of agreement signed with ExxonMobil for exporting 15 million t per annum to the UK market and with ConocoPhillips for sending 7.5 million t per year to the US.

The country this year is already exporting about 15 million t to Japan, South Korea and Spain, with a small amount to the US.
This level increases to 26 million t of LNG 2006, when 7.5 million t to India, and Italy begins importing 3.5 million t annually. 
 

Brazil has discovered giant gas reserves with an unimaginable impact in the future, since they are just a hundred miles away  from the country's main industrial concentration, Sao Paulo which is equivalent to 40 % of the country's GDP.   The enormous "bubble" off-shore Santos port could hold reserves equivalent to 40 tcf. This compares with Argentina's total reserves of  34 tcf and Bolivia's 54 tcf, according to Oscar Prieto head of Comgas, the gas consortium of Shell and British Petroleum in Brazil.
Although six to eight years must elapse before the new discovery reaches Brazilian consumers and the local industry adapts to the  new energy system, this is not precisely good news for Bolivia, one of South America's poorest countries that has plans for a massive  sale of natural gas from the continent's heartland to Sao Paulo transported by a pipeline already in operation.   However, according to Mr Prieto, Petrobras, Brazil's main oil consortium with a dominant market position has some tough decisions  ahead: changing the country's industry's energy supply from hydro and oil to natural gas, or convert natural gas and export liquid  by-products.   "Besides the Bolivian pipeline mostly financed by the Brazilians cost over $ 2 bn", said Mr Prieto who nevertheless anticipated Brazil  will be interested in a quick development of methanol for the fertilizer industry.   As to residential consumption, "Brazil, Sao Paulo is mainly tropical, with practically no need for heating and therefore gas consumption  is mainly for cooking and water heating" explained Mr Prieto adding that Comgas has only 400,000 gas clients among the city's 6 mm  electricity consumers.   "In Buenos Aires Metrogas (BP & Shell) has a gas net of 12,000 km but in Sao Paulo Comgas is limited to 3,300 km. Argentine clients  consume three times the average Sao Paulo resident". 

Brazil studies proposals for LNG/petrochemical complex
http://www.gasandoil.com 15-11-03 Source: OGJ 

The state of Rio de Janeiro is studying proposals that could lead to development of a $ 5 bn LNG and petrochemical complex at a key port area. LNG and petrochemical exports from the complex would target the US. The complex would fed by natural gas-both the vast reserves recently discovered off the state and growing supplies imported from neighbouring Bolivia.  Rio de Janeiro State Energy, Shipbuilding, and Oil Sec. Wagner Victer told that there are advanced studies evaluating the construction of LNG plant and an industrial complex in an area of Sepetiba Port, south of the city of Rio de Janeiro.  "Around $ 2 bn has been allocated to start the LNG project; however, depending on the number of trains set for the liquefaction plant and the dimensions of the export terminal, plus other plants, costs will most probably increase to $ 5 bn." 

Other investments envisaged involve units for gas processing/NGL recovery, ammonia-urea, and olefins (namely ethylene and propylene) with possible intermediates such as polyethylene, high-density polyethylene, and polypropylene also under consideration, Victer confirmed. The project will be financed by the National Economic and Social Development Bank (BNDES). The draught Sepetiba port is strategically located near the country's main consumer markets, Sao Paulo and Rio de Janeiro, and available infrastructure includes a Petroleos Brasileiro (Petrobras) pipeline network already in place.  "The Sepetiba port was included by the federal government in the export processing zone (ZPE), so it is entitled to fiscal benefits for exports. And furthermore the ICMS sales tax over assets usually charged by the state government will be scrapped for this project," Victer said. "Sepetiba is a developed port complex, and its geographical position is also privileged in relation to recent discoveries of estimated reserves of 420 bn cm of natural gas on the BS-400 block in the Santos basin by [Petrobras]. Furthermore, Petrobras owns land at the port for its PetroRio petrochemical hub, which was never developed." 

According to Victer, this will help to expand the gas liquids-based olefins complex under construction in the same region, where plans call for production of 515,000 tpy of PE, an ammonia-urea plant, and a gas processing/NGL recovery unit.  "Besides exporting LNG, the gas available from Brazilian reserves and by the take-or-pay contract with Bolivia can be used to implement other petrochemical installation projects, such as a first-separation phase of ethane and the supply of the residential and automotive markets with natural gas, plus the generation of [electric power]." 

The secretary confirmed that the natural market for exporting Brazilian LNG would be the US and his plans for the developing the project call for participation in a joint venture with multinational oil and gas companies. At the top of his list of multinationals are Houston-base El Paso and Norwegian state oil company Statoil. El Paso operates one of the largest natural gas pipeline systems in North America and is heavily involved in LNG import schemes. Statoil's US unit is a trading and marketing business that delivers 600,000 bpd of crude oil, gasoline, butane, and propane into the US.  Victer also said that other companies are welcome to participate. Jacob Sannes, director of Statoil in Brazil, told the project is "very interesting, but the company will not make a formal decision about the project before having more details and negotiating with Petrobras and the government." 

Victer, formerly head of Petrobras's exploration and production division, also noted that "the goal of the joint venture is to take advantage of the estimated 420 bn cm of natural gas reserves recently discovered by Petrobras off the coast in the Santos basin. This great potential could add supplies to the domestic and foreign markets and boost the petrochemical sector."  The secretary also said the state's strategy is to back out imported petrochemical feedstocks such as LPG with domestic natural gas andto substitute in power generation schemes natural gas for low-value-added refined products such as fuel oil, which could be further refined into higher-value products. Another consideration would be the environmental benefits from the replacement of gasoline with vehicular natural gas. 

Victer also noted that the project would contribute to the government's policy of generating more jobs and improving the trade balance, being negatively affected by Brazil's imports of natural gas from Bolivia under a take-or-pay contract paid in dollars.  The Brazilian government until recently had been negotiating with Bolivia for greater flexibility in the take-or-pay contract that calls for payment for a minimum of 14 mm cmpd even if actual volumes fall below that level. In 2004, this minimum will rise to 18 mm cmpd, but Brazil's consumption currently is only 13 mm cmpd, said the mines and energy ministry. 

Negotiations were halted prior to the recent ouster of Bolivian President Gonzalo Sanchez de Lozada due to massive and bloody protests sparked by a project proposed to export Bolivian gas as LNG via Chile to Mexico and the US. Lozada was replaced as president by his vice-president, Carlos Mesa, who promised to call upon the Bolivian people to vote in a referendum as to whether they wanted this project to go ahead or not.  After Mesa took office, Marco Aurelio Garcia, an international aide to Brazilian president Luiz Inacio Lula da Silva, told that the referendum will probably also include the natural gas sales to Brazil. "I do not believe that Bolivia is hostile in relation to gas exports to Brazil, but the country is a historical enemy of Chile and Peru through which the natural gas would be exported to the US." Garcia was on an official mission in Bolivia to try to mediate the trade conflict before Lozada resigned. 

The shortfall of Brazilian gas demand vs. Bolivia's takeaway capacity has been blamed on a projected flurry of gas-fired power plant construction in Brazil that has yet to materialize. But Victer says he does not believe that the gas-fired electric power plant boom projected for Brazil has failed yet.  "In my opinion market conditions did not correspond to the expectation, and this led to a contraction of these projects. Due to the [government's] new energy model, which is more attractive to private investors, and to adjustments in the natural gas market being proposed by the mines and energy ministry, a new impetus for the development of gas-fired thermoelectric plants may take place for joint [development] with other projects." 

Victer said that the LNG export facility will probably come on stream within 4-5 years, depending upon environmental licensing and agreements with the market players that would concur in purchasing its output.  "Brazil's 20-year contract with Bolivia calls for eventually importing 30 mm cmpd of natural gas, and this figure is currently being used as a parameter for the LNG export project to the US.” However, the secretary stressed that this and the number of trains to be built for the project depend on how much firm interest is shown by foreign companies to import LNG from Rio de Janeiro. "The final project will be defined only by the first quarter of 2004," he added. 

Peru LNG
Peru LNG SRL, led by Dallas-based Hunt Oil Co. and South Korea's SK Corp., agreed to sell 400 MMcfd of Camisea gas-equivalent to 2.7 million tonnes/year of LNG to Belgium's Tractebel Electricity & Gas International beginning in late 2007 or early 2008.

Peru LNG has called for bids for construction of a $1 billion liquefaction plant with an initial capacity of 4.4 million tonnes/year of LNG-600 MMcfd of natural gas-at Pampa Melchorita near Caiiete, 169 km south of Lima.  It later will spend another $800 million for additional wells, pipelines, and other facilities.  Tractebel will ship the LNG from the plant and regasify it in Mexico.

Sempra Bolivian LNG
Sempra Energy's plan to build an LNG terminal in Baja California is not threatened by the weeks of violent unrest in Bolivia that toppled the country's leader. Sempra CEO Stephen Baum met with the former Bolivian president and "emphasized they could literally miss the boat if they don't get their act together."

Botivia's new president Carlos Mesa promised to hold a national referendum on the question of gas exports to mollify protestors who opposed the idea. Bolivia's Margarita Field has some 13 tcf but a pipeline would need to cross Chile to a proposed LNG plant on the Pacific. 

Sempra signed a memorandum of understanding with Pacific LNG in 1991 to enter into exclusive negotiations for Bolivian gas but the pact expired in August of last year, Sempra said. The parent firm owns Southern California Gas, America's largest gas distributor and is talking to Pacific rim nations looking for supply and is exploring Alaska as a possible gas source. Sempra won't start building the Baja terminal until it lands long-term contracts with shippers, Baum assured investors. The fmn doesn't have any such agreements now. 
 

Egyptian Oil Minister Sameh Fahmy announced his country will rise to sixth position in the world in terms of exporting LNG.   "The latest discoveries of gas fields will enable Egypt to reach that position by 2006," Fahmy told. He said Egypt signed an agreement to supply Jordan with gas and was seeking similar arrangements with Syria, Lebanon, Turkey and  Israel. Egypt said its gas reserves exceeded 55 tcm and were expected to increase to 65 tcm in a short while. Reports since have put the gas  reserves at between 100 tcm and 120 tcm.

Apache Inks 25-Year Deal to Sell Egyptian Gas
Apache Corporation 12/16/2003 URL: http://www.rigzone.com/news/article.asp?a_id=9983

Apache Corporation has signed a Memorandum of Understanding for a Gas Sales Agreement, Field Development Plan and Deepwater Development Lease for a minimum of 2.7 trillion cubic feet (Tcf) of natural gas over 25 years from the deepwater portion of its Egyptian West Mediterranean Concession. Total revenue to all parties under the agreement, net of estimated development and infrastructure costs, is approximately $6 billion. Production is expected to commence in 2007.

"Principal terms include supplying approximately 400 million cubic feet of gas (MMcf) per day to the Egyptian market over the first five years and 375 MMcf per day for the remainder of the term," said Apache Chief Executive Officer and President G. Steven Farris. "Upon finalization of the agreements, we will have effectively contracted for all of the gas we have found to date in the deep water."

Farris said Apache will begin appraisal drilling on the concession and start infrastructure construction soon after the final agreements are executed. In addition, he said, "We have another five Pliocene-age gas exploratory prospects and eight Miocene-age prospects in the area."

The MOU was signed with the Egyptian General Petroleum Corporation and the Egyptian Gas Holding Company.

In its first deepwater foray, Apache discovered gas in the deepwater portion of the concession in May 2002 with its Abu Sir-1X well. Three consecutive discoveries and a successful appraisal well followed. Apache operates the deepwater portion of the concession with a 55 percent contractor interest. RWE-DEA has a 35 percent interest and BP holds the remaining 10 percent.

"We're extremely pleased at the sense of urgency with which this Memorandum of Understanding was reached, and thank Egyptian Petroleum Minister Sameh Fahmy for his invaluable assistance in moving this project forward," Farris said.

The West Mediterranean Concession is completely separate from Apache's Khalda Concession, where the company has announced two major discoveries, Qasr-1X and Qasr-2X, and believes it has found 1 Tcf to 3 Tcf of gas reserves and 20 million to 70 million barrels of condensate reserves.