Italian energy giant Eni's oil field services company Saipem and Japanese engineering giant Chiyoda have signed a cooperation agreement to develop liquefied natural gas projects, Eni said in a statement June 6.

According to the memorandum of understanding, Saipem and Chiyoda agreed to work together to create an integrated joint venture to develop onshore LNG and gas treatment projects worldwide.

Saipem and Chiyoda will also cooperate on projects in the rapidly expanding LNG business and upstream sector "and other strategic markets", Eni said without elaborating.

Separately, Eni said it signed a memoradum of understanding with South Africa's State-owned oil company PetroSA to develop joint projects to explore conventional and unconventional hydrocarbons in South Africa and possibly other African countries.

Under the accord, Eni may also supply crude oil and refined products to the South African market, where demand for such products is growing rapidly, and consider leasing a storage facility at South Africa's Port Saldanha which is strategically located for the Asian, American and European markets.

Eni and PetroSA will also evaluate the potential for long-term LNG supplies to be provided by Eni to PetroSA for both power generation and gas to liquids in South Africa, and for Eni to help build new power plants.

AMERICAS

U.S.

Hess Drops Plan for Fall River LNG Terminal

Hess, the company behind a proposed liquefied natural gas terminal in Fall River is giving up on its plans to develop the facility, which had encountered strong local opposition.

In a statement issued June 13, Hess LNG cited “unfavorable economics for liquefied natural gas in the New England region” as the reason for withdrawing its applications with federal and state agencies.

“It’s tremendous news for the people of Fall River and the region,” said Rep. David Sullivan (D-Fall River), who opposed the project due to its proximity to residential neighborhoods and infrastructure in the city.

Sullivan said that while the company cited changing market considerations, local resistance to the project from elected officials and residents “had an impact.” Sullivan said the project, marked for a former Shell terminal in the north end of the city, would have been the largest LNG terminal in Massachusetts.

In a statement, Hess LNG President Gordon Shearer said, “The significant increase in natural gas production from shale resources in North America resulting in lower prices as well as the growth in demand for LNG in the rest of the world make it unlikely the company can secure supplies of LNG on economic terms attractive enough to ensure the sustained profitability of the project.”

Shearer said the company would concentrate on other projects, including one in Shannon, Ireland, while retaining its ownership of the Fall River site and exploring options such as the sale of the site.

In June 2005, the Federal Energy Regulatory Commission (FERC) approved the construction of a 200,000-cubic meter storage tank and other terminal facilities in Weaver’s Cove, drawing condemnations and promises to fight the plan from elected officials opposed to the project.

CANADA

Progress, Petronas Pursue British Columbia LNG Export Project

Progress Energy Resources Corp. announced June 2 it has executed a binding framework agreement to create a strategic partnership with the Malaysian national oil company, PETRONAS, to develop a portion of Progress' Montney shale assets in the Foothills of northeast British Columbia (the "Transaction"). Progress will sell 50 percent of its working interest in its Altares, Lily and Kahta properties (the "North Montney Joint Venture") to PETRONAS for CDN$1.07 billion. The agreement also reflects the desire by both parties to explore additional opportunities to develop liquefied natural gas export capacity in British Columbia.

"This is a breakthrough transaction for Progress: the partnership we are launching will enable us to accelerate our growth strategy," said Michael Culbert, President and Chief Executive Officer of Progress. "We are very pleased to form this long-term partnership with PETRONAS. They share our belief that our North Montney shale assets are a world-class resource that deserves significant investment. We look forward to benefiting from PETRONAS' significant global expertise including their leadership in developing infrastructure and accessing LNG markets. As well as enhancing Progress shareholder value, this partnership will also generate substantial economic benefits for local communities and the province of British Columbia, while leveraging the environmental benefits of Canada's abundant and clean-burning natural gas resources globally."

Under the terms of the framework agreement, PETRONAS will pay 25 percent of the total consideration (CDN$267.5 million) in cash at closing and 75 percent of the total consideration in the form of a capital carry whereby PETRONAS will pay 75 percent of Progress' share of future capital expenditures in the North Montney Joint Venture over the next five years to a total of CDN$802.5 million. The Transaction provides Progress with the capital required to accelerate the development of its unconventional assets and unlock the value underlying the Company's vast Montney land holdings.

In addition to the above Transaction, PETRONAS and Progress will establish an LNG export joint venture (the "LNG Export Joint Venture") to be 80 percent and 20 percent owned, respectively. The LNG Export Joint Venture will launch a feasibility study to evaluate building and operating a new LNG export facility on the West Coast of British Columbia. PETRONAS would be the operator of this facility, and PETRONAS and Progress would jointly market the LNG utilizing PETRONAS' well-established and extensive network of customers in the largest LNG markets globally.

"Canada is poised to take a larger role on the world's energy stage. Developing new export options for Canadian natural gas producers is a logical step in connecting our vast resources with growing Asian demand for environmentally responsible energy sources like natural gas," said Mr. Culbert. "We look forward to working with West Coast British Columbia communities as we pursue this opportunity to build a new facility that will add value to British Columbia's natural resources while creating considerable long-term local economic benefits."

In connection with the LNG Export Joint Venture, PETRONAS will provide a standby equity financing commitment of up to $600 million, for Progress' capital requirements arising from the North Montney and LNG Export joint ventures from which Progress can draw down at the time of a successful LNG final investment decision.

The North Montney Joint Venture comprises 149,910 working interest acres in which PETRONAS will acquire a 50 percent interest and Progress will be the operator. The North Montney Joint Venture lands represent approximately 20 percent of Progress' rights in its northeast British Columbia Foothills land holdings, which total approximately 700,000 net acres. Progress holds approximately 900,000 net acres of Montney rights over its entire British Columbia and Alberta land base, making it one of the largest Montney land rights holders. The joint venture properties include five wells with minimal production at this time.

The closing of the transaction is subject to the execution of definitive agreements and receipt of regulatory approval.

BMO Capital Markets acted as exclusive financial advisor to Progress on this transaction.

PETRONAS, national oil and gas company of Malaysia is engaged in the oil, gas and petrochemicals industries with strategic business assets and interests in more than 30 countries. It is one of the world's leading LNG companies and is fully involved in every value chain of the LNG business, from liquefaction and shipping to re-gasification and trading. Apart from its Malaysian production facility, currently one of the world's largest, PETRONAS also owns interests in LNG assets in Australia, Egypt and the United Kingdom.

MEXICO

Vopak, Enagas to Acquire Altamira LNG Terminal from Shell

Vopak and Enagas from Spain have reached agreement with current owners Shell (50%), Total (25%) and Mitsui & Co., LTD. (25%) to acquire 100% of the shares in the LNG import and re-gasification terminal in Altamira, Mexico. For this purpose, a joint venture has been established in which Vopak owns 60% of the shares and Enagas 40% (with joint management control). The closing of the transaction is subject to the conclusion of project financing and government approvals.

The LNG terminal facilitates overseas LNG imports and supply of gas into Mexico by a joint venture of Shell and Total, and has been operational since 2006 under the highest safety and technical standards. The facility consists of 2 fully operational tanks of 150,000 cubic meters (cbm) each and a jetty capable of receiving LNG vessels with a capacity of up to 216,000 cbm. The terminal has a throughput capacity of 7.4 billion cubic meters per annum (bcma), which is fully contracted for a long-term period. The capacity can be expanded up to 10 bcma by building and operating a third tank. The Vopak/Enagas joint venture is expected to take over operational control in Q3 2011.

Located on the east coast of Mexico adjacent to the Vopak Chemicals Terminal in Altamira, the terminal has excellent connections to the existing Mexican gas infrastructure securing the supply of gas to power plants in the vicinity as well as to Mexico City. The Mexican gas usage is expected to grow in the coming decades mainly due to new gas fired power plants coming on stream which will lead to increasing imbalances between local demand and supply. The terminal will be able to facilitate the expected additional LNG imports resulting from this imbalance by expanding its capacity.

Vopak actively pursues a global growth strategy for LNG. The aim of this strategy is to facilitate key customers in markets that show an (increasing) imbalance between the demand and supply of natural gas by operating independent third party LNG import and re-gasification terminals. Currently, Vopak and its partner Gasunie are constructing the first Dutch LNG import terminal in Rotterdam with a throughput capacity of 12 bcma. This terminal will become operational in September 2011.

Vopak is the world's largest independent tank storage service provider, specializing in the storage and handling of bulk liquid chemicals, gasses and oil products. Vopak operates 79 terminals with a storage capacity of more than 25 million cubic meters in 30 countries. The terminals are strategically located for users along the major shipping routes. The majority of its customers are companies operating in the chemical and oil industries, for which Vopak stores a large variety of products destined for a wide range of industries.

Enagas is the technical manager of the gas system and common carrier for the high-pressure gas network in Spain. In the LNG area, the company owns three LNG re-gasification terminals: Barcelona, Cartagena and Huelva. These terminals have a total send out capacity of 4,650,000 cbm/hour and a total storage capacity of 1,900,000 cbm. Enagas also has a 40% ownership in the LNG re-gasification terminal of Bilbao and is currently constructing El Musel LNG terminal in Gijon, which will be operational in 2012. Enagas' facilities include close to 10,000 km of high-pressure gas pipelines over the entire Spanish territory; two underground natural gas storage facilities in Serrablo: (Huesca) and Gaviota (Vizcaya) and is developing a new strategic storage facility in Brihuega (Guadalajara).

BRAZIL

Brazil Petrobras Plays Waiting Game with Possible Partner PdVSA on $6.3 Bln Abreu e Lima Refinery Project

Venezuela's national oil company, Petroleos de Venezuela SA, faces an August deadline to put its cash on the table if it wants to remain a partner in a joint-venture refining project in Brazil, the downstream director at Petroleo Brasileiro ( Petrobras), said June 2.

In August, construction of the Abreu e Lima refinery in Pernambuco state will have consumed most of the 10 billion Brazilian reais ($6.3 billion) loan Petrobras got from Brazil's National Development Bank, or BNDES, Paulo Roberto Costa told Dow Jones Newswires in an exclusive interview. "Starting in September or October, we're going to need financial backing from partners in the refinery," Costa said.

The refinery project will move forward with or without PdVSA, as the Venezuelan company is also known, Costa said. Petrobras will build the 230,000-barrel-a-day facility solo with its own financial resources should PdVSA back out of the deal, the executive added.

Petrobras included the full cost of construction of the $16 billion, 230,000-barrel-a-day refinery in its business plan just in case, Costa said. "There won't be any problems, no delays," Costa said.

"I had to have two alternatives in hand," Costa said, noting plans for the refinery with or without PdVSA as partners. "Now, what's important in the hypothesis that [PdVSA] doesn't participate is that the work is going to continue normally without any financial problems."

PdVSA needs to reach a deal with the BNDES on its 40% share of the loan and ante up the additional cash needed to continue work on the refinery by August or September, Costa said. "Or, as we understand it, [PdVSA] will have lost [interest] or no longer has interest in participating [in the project]," Costa said.

PdVSA is still working closely with the BNDES to hammer out the necessary loan guarantees, but Costa said that he has no information that a deal has been worked out yet.

The refinery joint venture, however, has been fraught with difficulties from the start. In 2009, PdVSA and Petrobras finally reached a shareholders agreement after years of rancorous talks. Petrobras will have 60% of the project, with PdVSA holding 40%. The refinery has also been saddled with cost overruns, allegations of overcharges and difficult negotiations between Petrobras and PdVSA on crude oil supplies.

There are some positives for Petrobras should PdVSA not participate in the refinery. Should PdVSA pull out of the project, construction costs would decrease by about $400 million because the refinery will not need specialized equipment designed to process heavy crude from PdVSA's Carabobo field.

PdVSA and Petrobras will each provide about half of the crude oil to be processed. The refinery features two individual production trains, one for heavy oil from Petrobras' Marlim field and one for heavy oil from PdVSA's Carabobo field.

Petrobras plans to boost refining capacity to 3.6 million barrels a day by 2015, up from current capacity of 1.9 million barrels a day, to meet expectations for growing fuels demand in Brazil.

ASIA

AUSTRALIA

Australia Delays by One Month Inpex's Ichthys Project Decision

Australia has deferred by a month a decision on whether to approve Inpex Corp's Ichthys liquefied natural gas project in the Northern Territory.

Environment Minister Tony Burke is now scheduled to make a decision on July 7, back from June 8, according to a document posted on the Australian Environment Department's website June 7.

The Japanese oil and gas producer said earlier it expects to make a final investment decision on the $20 billion-plus project with partner Total SA in the fourth quarter of this year.

It is expecting to seal binding agreements for the entire planned annual output of 8.4 million metric tons of LNG by around autumn in Japan, Inpex President Toshiaki Kitamura said early in June.

WA State Regulator Recommends Chevron Wheatstone LNG Project Approval

Chevron Corp. on June 15 received the conditional support of regulators in Western Australia State for its A$25 billion Wheatstone gas-export project, a key milestone in its drive to meet fast-growing Asian demand for clean fuels.

The recommendation by the Environmental Protection Authority moves Wheatstone closer to construction, with Chevron aiming to formally approve the project's first two processing units with a combined annual capacity of 8.9 million metric tons of liquefied natural gas later this year.

"This marks an important step towards a final investment decision in the second half of 2011 on one of Australia's biggest resource projects," Chevron Australia Managing Director Roy Krzywosinski said in a statement welcoming the EPA recommendation.

International oil companies are racing to develop gas reserves trapped below the seabed in Australia to capitalize on a shift away from crude oil and coal in North Asia, as the fossil fuels are blamed for a worsening pollution problem. In addition, the March 11 earthquake and tsunami in Japan have led many governments to relook plans to use more nuclear power, which could spur demand for alternative fuels such as LNG.

Australia, which currently has two operating LNG plants, could overtake Qatar to become the world's biggest exporter of LNG by the end of the decade if all the proposed projects are built.

Wheatstone is Chevron's second major LNG project it is developing in Australia, after the A$43 billion Gorgon project offshore Western Australia.

Chevron's proposal to build the Wheatstone plant with an output capacity of up to 25 million metric tons of LNG a year near the coastal town of Onslow should be allowed to proceed as long as the local environment is protected, EPA Chairman Paul Vogel said in statement.

Chevron plans to make a final investment decision on Wheatstone's first phase in the second half of 2011, subject to approvals from the Western Australian and federal Governments.

The project aims to deliver LNG--a natural gas supercooled to a liquid form so it can transported by ship--to customers in Japan and South Korea from 2016.

Chevron's proposal could be implemented with stringent conditions to limit the impact on the environment, which include risks from "one of Australia's largest marine dredging campaigns," Vogel said.

The EPA recommended that Chevron offset its reservoir gas emissions and be subject to strict dredging conditions to minimize disruptions to coral reefs and marine fauna, including whales and turtles.

The EPA's report to the Western Australian state government is now subject to a two-week public appeal period closing June 29, Vogel said.

"We believe the environmental and social impacts can be effectively managed and we will now review the EPA report," said Brian Smith, Chevron's general manager of Wheatstone.

"The front-end engineering and design phase of the Wheatstone Project is complete and we are continuing to work with government to obtain timely project approvals," he said in a statement.

Chevron is the operator and 73.6% owner of Wheatstone, alongside minority partners Apache Corp. (APA), Kuwait Foreign Petroleum Exploration Co. and Royal Dutch Shell PLC (RDSB).

Wood Group Wagners Wins Queensland GLNG Pipeline Project Management Contract

Brisbane-based Wood Group Wagners has been awarded the Project Management Services Contract for the GLNG Pipeline Project in Queensland, a development that will process coal seam gas (CSG) into liquefied natural gas (LNG).

Under the terms of this A$40million contract Wood Group Wagners will provide a more than 40 personnel to the GLNG pipeline project management team (PPMT), formed to manage, monitor and supervise the performance of the EPC Contract.

In addition, Wood Group Wagners will utilize its local and global resources to provide senior engineering and design, site construction, human resources and general administration personnel to the GLNG pipeline project management team.

The 420km pipeline is a major component of the overall GLNG development, which will transport CSG from the existing and future fields in the Roma, Fairview and Arcadia Valley areas, to a planned LNG plant on Curtis Island.

"We are delighted to have secured this contract with GLNG, our role in this project confirms our reputation as a value adding partner to major energy projects," said John Stark, General Manager Wood Group Wagners. "This builds on our recent success in securing several major CSG contracts and delivers on our promise to be a single source of solutions across entire project cycles."

Overall construction is due to commence this year with first cargoes scheduled to be exported from 2015.

Wood Group Wagners is a joint venture company established in Brisbane by Wood Group and Wagners to provide Queensland's gas producers with a flexible, fit-for-purpose solution for developing Coal Seam Gas.

Woodside Announces More Pluto LNG Delays, Cost Overruns

Woodside Petroleum Ltd. on June 17 announced a surprising six-month delay and additional A$900 million cost overrun for its Pluto gas export project in Western Australia state.

The first cargoes of liquefied natural gas are now expected to be shipped to Japanese customers Kansai Electric Power Co. and Toyko Gas Co. in March 2012, compared with previous guidance of September this year, Woodside said.

The delay is expected to result in a A$900 million cost increase, to A$14.9 billion, it added.

Less than a month after taking the reins from Don Voelte, new Woodside Chief Executive Peter Coleman said in a statement that he was "disappointed to have to advise of a change in the schedule."

Pluto's progress has been delayed several times in the past by strike action by construction workers, a shortage of skilled labor in Australia's booming economy and the reinstallation of flare towers that weren't cyclone-proof.

This time, Woodside said the delay has been caused by seven weeks of bad weather and "slower-than-expected progress" on the commissioning of the onshore LNG plant, suggesting that final adjustments have had to be made following a final checking process.

"While we would like to start up the project as quickly as possible, we will not be doing so until we are satisfied the commissioning work has been completed in a thorough and safe manner," Coleman said.

The delay is surprising because Voelte in April said it would be difficult to recover a four-week delay to the construction timetable, but that Woodside was still targeting delivery of the first cargo in September. The postponement to March is over six times longer than the four weeks suggested by Voelte.

"It's a major disappointment and probably doesn't help the whole sector," Southern Cross Equities Executive Director Charlie Aitken said.

At 0228 GMT, Woodside shares were down 3.8% at A$40.80 in an overall market up 0.6%.

Backup LNG supplies from external sources are available to meet scheduled deliveries to the project's Japanese customers in the event of a delay, Woodside said last year.

SBM Offshore Wins Major Order for Shell's Prelude FLNG

SBM Offshore has been awarded a contract and received the corresponding notice to proceed from Technip (part of the "TSC" Consortium with Samsung Heavy Industries) for the engineering, procurement, construction and integration (EPCI) of a major Turret Mooring System.

This Turret Mooring System will be a key component of the world's first floating liquefied natural gas (FLNG) facility, to be deployed by Shell Development (Australia) Pty Ltd (Shell) at its Prelude gas field off the northwest coast of Australia.

To be moored some 200 kilometers from the nearest land, the Prelude FLNG facility will produce gas from offshore fields and liquefy it onboard via a cooling process. TSC will undertake the detailed design of this innovative facility which will be built at the Samsung Heavy Industries shipyard in Geoje, Korea. SBM Offshore will supply the Turret Mooring System to the shipyard in Korea for integration into the facility.

The Shell Prelude FLNG facility will be the largest floating offshore facility in the world, measuring 488 meters from bow to stern and weighing (when fully loaded) close to 600,000 tonnes. The Turret Mooring System, which will permanently anchor the floating facility at its offshore location and allow it to weathervane, will be the largest SBM Offshore has ever designed and built, with overall dimensions exceeding 30 meters in diameter and 100 meters in height. The facilities will be able to withstand extreme mooring forces resulting from the cyclonic metocean environment.

Floating LNG is a breakthrough innovation that will allow the production, liquefaction, storage and transfer of LNG at sea, helping to open up new offshore natural gas fields that are currently too costly or difficult to develop.

Inpex Gets Environmental Nod for Australia $32.5 Bln Ichthys LNG Project

Australia on June 28 conditionally approved construction of Inpex Corp.'s multibillion dollar Ichthys gas export joint venture, moving it closer to providing Japan with alternative fuels in the wake of its nuclear power crisis.

Inpex and minority joint venture partner Total SA (TOT) this month agreed to sell gas from the Ichthys Field, located off Australia's northwestern coast, to companies in Japan and Taiwan, and said they are close to finalizing agreements with another five Japanese utilities.

Apart from crippling Japan's Fukushima Daiichi nuclear facility and shutting down several more there, the country's devastating March 11 earthquake and tsunami has tainted nuclear power's worldwide appeal. Germany last month said it would close all of its reactors and other countries have suspended plans for new reactor construction pending safety reviews.

Interest is particularly strong among Asian nations such as Japan and South Korea, whose domestic fossil fuel supplies are low, and China and India, where rapidly developing economies are creating a growing need for clean fuel.

Australia's vast gas reserves, stable political environment and proximity to Asia have attracted billions of dollars of investment from international energy companies including Chevron Corp. and Royal Dutch Shell PLC. Close to a dozen terminals are slated for Australia's coastline, potentially placing it above Qatar as the world's biggest LNG exporter by the end of the decade.

Inpex and Total have been targeting a late-2011 sign-off for construction of an export terminal in Darwin capable of producing 8.4 million metric tons of LNG each year, with the first cargo slated to be shipped from late 2016.

In 2008, Inpex estimated that Ichthys would cost US$20 billion to build, but this is likely to be revised higher when the company sanctions its construction later this year.

Like its rivals, Ichthys faces development risks.

Recent go-aheads for several rival developments are pushing up demand for labor, sparking warnings from analysts of potential delays and cost overruns.

The risk was demonstrated by Woodside Petroleum Ltd. this month when it announced a six-month delay and A$900 million cost blowout at its flagship Pluto LNG project in Western Australia state.

Citigroup estimates Ichthys will cost US$32.5 billion to build, making it the most expensive LNG project in Australia per ton of LNG output, mainly because of its isolated location and the 885 kilometer pipeline that will need to be constructed from the gas field to Darwin.

Despite this, the broker said the project's economics are saved by its high liquids content. Ichthys is expected to produce 100,000 barrels of condensate per day at peak production and 1.6 million tons of liquid petroleum gas each year.

Its progress may be negative for other Australian LNG projects including Woodside's proposed Browse development, which, like Ichthys, is also located in the remote Browse Basin, Citigroup analyst Mark Greenwood said.

It will highlight Browse's high cost and suck up resources. "Ichthys is an enormous project that will add further cost and schedule pressure to Australian LNG projects being constructed in parallel," he said.

Inpex must outline a strategy for mitigating or offsetting the impact of carbon dioxide emissions from the project among other environmental conditions.

Dredging and soil disposal, for example, must be conducted to protect marine life, including dolphins, dugongs and turtles.

Inpex Says It May Sell 10 Percent of Ichthys LNG Project in Australia

Inpex Corp. said it may sell 10 percent of its proposed Ichthys liquefied natural gas project in Australia as part of fuel-supply agreements.

The Japanese energy company currently owns 76 percent of the Ichthys LNG development in northern Australia, while its partner, Paris-based Total SA, has 24 percent.

Inpex agreed to supply LNG to Chubu Electric Power Co., Toho Gas Co. and CPC Corp. of Taiwan and is close to completing talks with five "major" Japanese utilities for further LNG sales, the company said June 24.

Inpex is in negotiations with all of those companies about the potential sale of a stake in the venture, spokesman Kazuhiko Itano said.

Chevron to Appeal Environmental Conditions for Wheatstone LNG

Chevron Corp. said July 1 it is appealing some conditions imposed on its proposed A$25 billion Wheatstone gas export project by Western Australia state's environment regulator.

San Ramon, Calif.-based Chevron said it won't publicly disclose the details of its appeal.

"We are confident that we can continue to demonstrate that the Wheatstone project can be developed in a manner that is environmentally responsible," a Chevron spokesman said in an e-mailed statement.

"Ultimately it will be the government's decision to give environmental approval to the project and we look forward to a timely decision by the State and Federal Ministers for the Environment," he said.

A final investment decision on the project's first two processing units with a combined annual capacity of 8.9 million metric tons of liquefied natural gas is still expected in the second half of 2011, Chevron said.

Chevron is the operator and 73.6% owner of Wheatstone, alongside minority partners Apache Corp. (APA), Kuwait Foreign Petroleum Exploration Co. and Royal Dutch Shell PLC (RDSB).

Wheatstone is Chevron's second major LNG project it is developing in Australia, after the A$43 billion Gorgon project offshore Western Australia.

CHINA

Black & Veatch, Chemtex to Build Two LNG Facilities in China’s Shaanxi Province

U.S. head-quartered Black & Veatch and Chemtex will design and build two new LNG facilities in China's Shaanxi province to provide natural gas for peak demand periods as well as vehicle fuel, according to a new statement by Black & Veatch in June.

The two facilities, to be located in Jingbian City and Yulin City, will be used to liquefy natural gas for vehicle fuel in the region, offsetting the use of diesel and gasoline. Based on the report, one liter of LNG is comparable to 0.6 liters of diesel in vehicle fuel use.

Black & Veatch and Chemtex will provide engineering, procurement and construction services for these two new LNG developments, which are marketed under the Jingbian Xingyuan LNG Project and the Yulin Yuanheng LNG Peak Shaving Project.

The Jingbian Xingyuan LNG Project, owned by Shaanxi Jingbian Xingyuan Industry Ltd., will have a capacity of 1.5 million cu m/day.

The Yulin Yuanheng LNG Peak Shaving Project, with the facility located in Ma Huangliang Industrial Park in Yulin City, will have a 1 million cu m/day capacity.

Financial details and timelines for construction of the LNG facilities were not available.

"The Black & Veatch-Chemtex team has won more than half of all new LNG projects in China since 2006, all of which use the PRICO process," said Brian Price, vice president and LNG technology manager for the company's energy business. PRICO is a natural gas liquefaction process patented by the company.

Including these two new LNG facilities, the Black & Veatch-Chemtex team has won five LNG projects in China since the beginning of 2011, and 13 since 2006.

"China's natural gas pipeline infrastructure is developing, and the country's size presents challenges in supplying much-needed clean fuel to local residents and businesses. Black & Veatch-Chemtex LNG facilities enable our clients to quickly move LNG to market," said Hoe Wai Cheong, managing director for Asia and Middle East, India, Europe and Africa in Black & Veatch's global energy business.

INDIA

India's East Coast to Get First LNG Import Terminal

The operator of Dhamra port in Orissa plans to build India's first liquefied natural gas terminal on the east coast at an estimated cost of ‘3,000-3,500 crore.

The move by Dhamra Port Co. Ltd (DPCL), a joint venture between Larsen and Toubro Ltd and Tata Steel Ltd, looks to tap growing demand for fuel from power plants and fertilizer units in the region, and comes at a time when the country faces a severe shortage in local gas supplies.

The proposed LNG import terminal is critical as output from the D6 block, India's biggest natural gas reservoir in the Krishna-Godavari basin run by Reliance Industries Ltd, has fallen short of initial estimates.

Against a targeted production of 60 million standard cubic meters per day (mscmd), output from the D6 block stands at around 51-52 mscmd and may dip further to 47 mscmd by 2013. A rise in production may not be possible until at least 2015, Reliance recently informed the government.

DPCL has invited a few Dutch and Belgium dredging companies operating in India, including Dredging International NV, Van Oord Dredging and Marine Contracting Co. NV and Jan De Nul NV, to submit price quotations to deepen the channel where the terminal will be built to allow LNG ships to dock, said two people familiar with the development.

Executives at each of these firms said invitations have been sent out to them by DPCL seeking budgetary estimates for dredging. None of the people agreed to be named.

DPCL has also started preliminary discussions with Petronet LNG Ltd, India's biggest LNG importer, to finalize a possible deal, under which Petronet will construct the berth, erect a LNG regasification terminal and operate the facility, said one of the persons familiar with the development.

"It is bad commercial relations to discuss anything until it is finalized," said Santosh Kumar Mohapatra, chief executive officer, DPCL.

"Petronet may set up an LNG terminal on India's eastern coast, possibly in Orissa," said A.K. Chopra, general manager, public relations, Petronet. "Discussions have started, but the port location is yet to be finalized."

The finalization of the site will depend on the demand for gas in the region and depth at the port where LNG ships can dock, he added.

Situated between Haldia and Paradip ports, Dhamra is one of India's deepest ports with a depth of 18m, allowing the biggest of the dry bulk ships with capacities to load up to 180,000 tonnes to dock. The port's master plan provides for 13 berths of various types, capable of handling 109 million tones (mt) a year.

The '2,460-crore first phase of the port, with a capacity to handle 27 mt of cargo, started commercial operations in May from two fully mechanized berths capable of handling coking coal, steam and thermal coal, limestone and iron ore.

Being a private port, Dhamra is free to set rates. Rates at Union government-controlled ports are set by the Tariff Authority for Major Ports.

India has an LNG import capacity of 13.5 million tonnes per annum (mtpa) through two terminals, accounting for about 20% of the country's gas requirements.

Petronet runs India's first LNG receiving and regasification terminal at Dahej in Gujarat having a capacity of 10 mtpa, equivalent to 40 mscmd of natural gas.

A joint venture of Shell Gas BV and Total Gaz Electricite Holdings France runs a 3.5 mtpa capacity LNG terminal at Hazira, also in Gujarat.

Petronet is constructing a new 5 mtpa LNG terminal at Kochi in Kerala that is expected to start operations in the third quarter of 2012.

Another LNG terminal at Dabhol in Maharashtra with a capacity of 2.5 mtpa is also likely to start in 2012.

All these LNG terminals are on the western coast.

"LNG receiving terminals were set up on the western coast because of their proximity to the market (customers)," said Petronet's Chopra.

"Now, market is coming up in other areas also, necessitating facilities on the eastern coast."

India's gas demand is expected to reach 381 mscmd by 2015, compared with a supply of 202.9 mscmd.

Gazprom Signs Supply Deals with Three Indian Firms and Considers Future Expansion Plans

Gazprom Global LNG has signed accords for the long-term supply of liquefied natural gas to GAIL (India) Ltd, Gujarat State Petroleum Corp. Ltd (GSPC) and Petronet LNG Ltd.

The deals have been signed through affiliate Gazprom Marketing and Trading Singapore Pte Ltd (GM&TS), a fully owned unit of Gazprom Marketing and Trading.

The Russian oil and gas company will supply 2.5 million tonnes per annum (mtpa) to each of them, the company said on its website. The current installed capacity at the two operational terminals at Dahej and Hazira in Gujarat is close to 14 mtpa, or nearly 50 million cubic meters a day (mcmd). While prices are yet to be negotiated, the supply will start from 2016 for 25 years. The Petronet supply deal was reported by Mint.

The total demand for gas in India is 180 mcmd and this is expected to rise to 325 mcmd by 2015, according to an industry expert close to the development.

"Of this, half the demand will be met by domestic gas, whereas half would be from imports (LNG). Currently, a major part of the North and West are covered by pipelines, and with the laying of more pipelines and city gas distribution, there will be a lot of new markets," he said.

At least half a dozen areas have been identified in the country for setting up LNG terminals, including Okhamadhi by the GVK Group and Pipavav by Mumbai-based Swan Energy Ltd, said a Gujarat state government official close to the development.

While GSPC will import the gas mainly through its proposed terminal at Mundra, where it has joined hands with the Adani Group, Petronet and GAIL will require gas on a long-term basis for its proposed terminals at Dabhol. Petronet, which is setting up an LNG terminal in Kochi, is also looking at expansion in Gujarat.

"This memorandum of understanding (MoU) is a key step in diversifying our LNG supply portfolio and this relation will go a long way in developing mutually beneficial relations between the two companies," said A.K. Balyan, managing director and chief executive of Petronet.

Earlier this year, Gazprom and GSPC had signed a supply deal.

"Following the successful signing in January this year of a structured deal to supply 0.3 million tonnes a year of LNG for the next two years, GSPC and Gazprom are now exploring the possibility of building further on this mutually beneficial relation. This MoU represents another significant step towards building upon the relation between GSPC and Gazprom," said Tapan Ray, managing director, GSPC. "We believe securing sufficient long-term LNG supplies is imperative for meeting the growing energy needs of our country."

The long-term LNG supply agreement is a natural step for all parties after a number of successful LNG cargo deliveries by Gazprom to its counterparties in India since 2007, the company said on June 2. The company sees India as a key market for LNG, along with Japan and other north Asian countries, as it continues to strengthen its presence and operations in Asia-Pacific.

"We are delighted that our successful partnership with GAIL, GSPC and Petronet has laid the foundations for these strategic LNG supply agreements," said Frederic Barnaud, president and managing director, Gazprom Global LNG. "Thanks to our Russian LNG portfolio, we are confident Gazprom will lead the strengthening growth of the LNG markets, in India and across the world."

MALAYSIA

Malaysia's Perak State to Set Up $1.9 Bln LNG Plant

The Malaysian state of Perak is planning to set up its first plant that will process and supply liquefied natural gas to countries in the South-east Asian region.

State executive counselor Hamidah Osman said the US$1.9 billion (5.8 billion ringgit) plant would be built on a 60ha piece of land in Tanjung Hantu, Manjung.

"It will have the capacity to produce about 8.7bil cubic meter of LNG for industrial and public usage locally and abroad," she said.

"It is expected to be operational within 15 months," she said.

Hamidah said the state government had issued a letter to Atigas Technology Sdn Bhd to start the project immediately.

The use of LNG is in line with the state's policy of moving towards green technology.

"LNG is cleaner. It is also cost-efficient," Hamidah said, adding that Singapore had also started to build a similar but smaller plant for its own consumption.

Managing director Tang Hock Leng said Atigas Technology would franchise kiosks that would sell the LNG to motorists.

He said the company might provide free installations of LNG converters on vehicles.

"We want the people to start using LNG," he said.

"There is no point if there are kiosks selling LNG, but no vehicles use it."

He pointed out that LNG could help motorists save up to 70% on gas consumption.

"A vehicle running on fuel may need to spend 100 ringgit on a trip as compared to one that used LNG and need to only spend 30 ringgit for the same journey."

PHILIPPINES

Foreign Companies Interested in Philippines Natural Gas Projects

Companies from Australia, Italy, China, including Hong Kong, and South Korea have signified their intentions to invest in the highly capital-intensive Philippine natural gas sector, expressing interest in either building a liquefied natural gas terminal, pipeline or a gas-fired power plant, the Department of Energy said.

Energy Undersecretary Jose M. Layug Jr. identified these foreign companies as First Pacific Capital, and Energy World from Australia; ENN Energy Holdings from China; Synergy International of Hong Kong; ENI-Saipem of Italy; and SK Engineering and Construction Co. Ltd., Korean Western Power, BW Ventures and Hyundai Merchant Marine, all from South Korea.

GN Power Ltd. of the Netherlands, which is currently building a 600-megawatt coal facility in Mariveles, Bataan, also plans to participate in the local natural gas industry. There are also three Indian companies interested in helping the Philippine government put up the necessary LNG infrastructure, but Layug did not identify them.

Apart from the foreign companies, local firms are likewise seeking active participation, including the state-run Philippine National Oil Co.; listed firm Abacus Consolidated Resources, which will be partnering with ENI-Saipem of Italy; and the Lopez-led First Gen Corp., Layug disclosed.

“We are completing our Master Plan for Natural Gas through technical assistance from Japan International Cooperation Agency (Jica) and World Bank by yearend. After we complete the plan, and the results are favorable, then we will conduct public bidding for such infrastructures next year,” Layug said.

The Department of Energy initially estimated that $5 billion in fresh investments would be needed to fully develop the country’s downstream natural gas industry.

Based on the original master-plan, investments were needed to construct 423 kilometers of transmission and 504 sq. km. of distribution pipelines. Priority projects include a 140-km pipeline from Bataan to Manila (BatMan 2); 40-km Edsa-Taft loop; 35 km from Sucat to Malaya; 40 km from Batangas to Cavite (BatCave); 35 km from Rosario to Biñan (RoBin); 100 km from Batangas to Manila (Batman 1); and the 30-km Calaca-Spurline (CatLine). These investments also included greenfield power plant projects that could generate a combined 3,000 MW and power plant conversion projects that could generate some 600 MW.

The expected JICA-WB Master Plan for Natural Gas will re-evaluate these opportunities and identify which infrastructure will be deemed, priority projects, and what kind of investments will be needed. It will also evaluate the viability of importing natural gas and the potential sources.

Possible LNG sources include Indonesia, Malaysia, Qatar, the United States and Australia, which is known to hold huge natural gas deposits, Layug said earlier. The Malampaya gas power project, which currently provides natural gas to three facilities in Luzon, will not be the main source of gas, he added.

“Malampaya will not have a role in the master-plan other than what they are providing for currently. The master-plan hopes to provide infrastructure for LNG imports which we expect to be much cheaper because worldwide, the price of LNG is going down. We will import LNG. There’s a lot of supply and the Philippines is being looked at by the LNG industry as a potential market—that’s why they’re knocking on our doors,” Layug said.

Energy Secretary Jose Rene D. Almendras has been pushing for alternative fuels such as natural gas given the global oil price volatility, to which the Philippines is highly vulnerable as it sources most of its fuel requirements abroad.

Natural gas is deemed to be among the more feasible alternatives that will allow the country to diversify its energy and transport fuel sources.

The country’s natural gas resources are estimated at 2.135 trillion cubic feet of natural gas.

Filinvest Eyes 200MW LNG Power Plant in Philippines Misamis Oriental

The energy unit of Filinvest Development Corp. is planning to set up a 200 megawatt liquefied natural gas power plant at the Phividec Industrial Estate-Misamis Oriental.

Brig. Gen. Triunfo P. Agustin (Ret.), chairman of the board of directors of the Phividec Industrial Authority said negotiations are now being finalized for the company´s acquisition of a lot within the 3,000 hectare PIE-MO, the country´s largest industrial estate.

The project will be undertaken by Strong Field Gas & Electric Corp., the newly formed energy subsidiary of FDC Utilities Inc. About 25 percent of the new firm´s P16-million authorized capital stock has been subscribed with 40,000 shares by FDC Utilities Inc. and the incorporators subscribing to a share each. Incorporators include Filinvest group´s Andrew Gotianun Sr., Mercedes Gotianun, Andrew Gotianun Jr., Lourdes Josephine Yap, and Jesus N. Alcordo.

The $200-million power plant will be part of the $1.8-B, 1650-MW "Greenfield" energy portfolio announced last May by FDC Utilities, Inc. The investment is based on the estimated cost of building an LNG power plant at $1 million a MW, excluding further capital expenditures for LNG terminals.

The Phividec Industrial Estate-Misamis Oriental already hosts one locator in energy generation with the 232MW coal-fired power plant of Steag State Power, Inc. which supplies 15-20% of Mindanao´s energy supply.

Commissioned in 2007, the plant is expanding its capacity by another 105-MW unit slated for completion by 2013. The plant is majority owned by Germany´s fifth largest power producer, Evonik Steag GmbH of Essen Germany with local partners Aboitiz Power Corp. and La Filipina Uy Gongco Corp.

The $600-million expansion will reportedly be undertaken by a new corporation with the current shareholders maintaining the same equity proportion in SPI: 51% for Evonik, 34% for APC and 15% for La Filipina.

Including the Steag expansion, there are now at least seven coal-fired power plants in the pipeline in Mindanao with a total planned installed capacity of 1,805MW and total capex of $3.81-billion.

Other proponents include Aboitiz Power Corp., Conal Holdings Corp., San Miguel Corporation, Sumitomo Taganito HPAL Nickel Corpoation and Sagittarius Mines, Inc. (SMI). Project locations include Sta. Cruz, Davao del Sur, Sarangani, General Santos City, Zamboanga City, Surigao City, and Malalag, Davao del Sur. Print Email

EUROPE / AFRICA / MIDDLE EAST

FRANCE

EDF, Partners To Invest EUR1B in Dunkirk LNG Terminal

French state-controlled power group Electricite de France SA (EDF.FR) June 28 said that it, oil major Total SA and Belgian gas distributor Fluxys SA, will invest together a total EUR1 billion in a liquefied natural gas terminal in Dunkirk, northern France.

Total holds a 10% interest in the terminal, Fluxys 25% and EDF 65%, the group said in a statement.

The plant, due to come on stream at the end of 2015, will have an annual regassification capacity of 13 billion cubic meters and will increase the import capacity for LNG into France by nearly 20%.

The three companies also signed a commercial agreement allowing Total to reserve up to 2 billion cubic meters a year of storage and regassification capacity from Dunkirk LNG, and for EDF to retain a capacity of nearly 8 bcm/year.

EDF and Total have also signed agreements with GRTgaz authorizing it to use the gas distribution network at the exit of the terminal, EDF said.

Dunkirk LNG reserves the right to eventually welcome other financial or sales partners to the project, it said.

Works on the site are due to start at the beginning of 2012.

Contracts have been awarded to three consortiums: Bessac-Razel-Soletanche will build a tunnel between the Gravelines nuclear power station and the terminal; Bouygues-Entrepose Contracting will build three LNG reservoirs; and Techint-Sener will be responsible for the unloading installations and the industrial processes linked to regassification, EDF said.

EDF said it will now be able to offer a "balanced and diversified portfolio" of natural gas and to better respond to the demands of end customers requiring dual fuel--electricity and gas--and to optimize the sourcing of its combined cycle gas, or CCG, plants.

EDF will bring into service three CCG in France by 2012, with a total capacity of 1,360 MW, along with a CCG plant with a capacity of 1,300 MW in the U.K.

GREECE

Wartsila Wins Five-year Technical Management Contract for Six LNG Carriers

Wartsila has been awarded a five-year technical management contract, based on Dynamic Maintenance Planning, covering six LNG carriers. The contract has been placed by the operator of the vessels, Ceres LNG Services Ltd, a Greek ship management company and a major marine service provider in LNG shipping.

The five-year contract covers engine Dynamic Maintenance Planning for a total of twenty-four Wartsila 50DF dual-fuel engines in six LNG carriers. Dynamic Maintenance Planning offers owners a significant reduction in operating costs by applying predictive maintenance principles and by optimizing engine performance. With this order, a total of 80 Wartsila 50DF engines powering LNG carriers are under Wartsila Dynamic Maintenance Planning contracts.

"Wartsila's Dynamic Maintenance Planning will enable our company and our customers to benefit from optimized availability, increased lifecycle efficiency, and reduced maintenance costs for our engines. Wartsila's technology, global presence, and local support will help us to achieve this task," says Sallis Theofanis, Ceres LNG Technical Manager.

Dynamic Maintenance Planning is based on the Condition Monitoring (CM) system developed by Wartsila. The engines' operational data and parameters are continuously fed into a database and then evaluated at Wartsila's CBM (Condition Based Maintenance) centre. The maintenance needs are thus predicted based on the actual condition of the equipment, while the optimal operational parameters can also be determined. The flexibility of this system — in conjunction with annual visits and inspections onboard the vessels, allows maintenance intervals to be amended according to actual need. Service work and spare parts availability can be arranged accordingly, which enables better service planning and the avoidance of unnecessary costs and downtime.

"With Dynamic Maintenance Planning we combine the latest in condition monitoring, predictive maintenance and efficient maintenance planning, with the latest in engine technology to achieve a complete system solution that maximizes the availability of the engines without compromising reliability," says Dimitris Mitsopoulos, Account Manager, Wartsila Services in Greece.

MOZAMBIQUE

Anadarko and Cove Energy JV Target Mozambique LNG Project Decision in 2013

A joint venture led by U.S. independent Anadarko Petroleum is targeting a final investment decision in 2013 on a proposed LNG project based on gas discovered in Mozambique's Rovuma Offshore Area 1, minority partner Cove Energy said June 27.

According to a statement released after UK-based Cove's annual general meeting, sufficient volumes of gas have been discovered in offshore Mozambique's Windjammer, Barquentine and Lagosta fields to prompt Anadarko to mobilize a full team to pursue the LNG project.

"Progress to date includes the identification of coastal land sites for the LNG facilities and a preliminary gas development plan," Cove added.

Appraisal drilling is currently underway, focused on proving sufficient resources in the Windjammer/Barquentine discovery area to lay the foundations for the first LNG train. Anadarko has previously said it believed the finds had combined reserves of at least 3 to 4 Tcf, enough to underpin a commercial LNG development.

Anadarko won the rights to explore in the Rovuma Basin in Mozambique's second licensing round in January 2006. The company operates and holds 36% of the block, alongside Japan's Mitsui & Co. (20%), India's Bharat Petroleum Corporation Limited (10%) and Videocon (10%), Mozambique's state-run ENH (15%), and Cove (8.5%).

"The beginning of appraisal drilling offshore Mozambique is another important milestone and is the start of a continuous sequence of exploration and appraisal wells scheduled to be drilled over the coming two years, complimented by a second deepwater rig arriving later this year," said Cove CEO John Craven. "The new and reprocessed 3D will ensure that we are equipped to optimally evaluate the numerous oil and gas prospects on the block," he added.

"We are also delighted with the significant progress made by the operator in pursuit of the LNG project, which is running concurrently with the appraisal drilling activity."

Cove Executive Chairman Michael Blaha said the company had undergone a transformation over the past year.

"After the Windjammer gas discovery, offshore Mozambique, followed by three additional gas discoveries, Cove has evolved from a small exploration company to a company with significant market value participating in a world class LNG project," he said. "Current activities focus on the appraisal of the existing discoveries to enable early certification of gas reserves."

Blaha added that this work was being undertaken simultaneously with the development of LNG sales contracts, front-end engineering, environmental impact studies and the establishing of financial, commercial and legal frameworks for the project.

Acquisition of a new 3-D seismic survey covering around 4,448 sq km over the southern and northern sections of Rovuma offshore block has also been completed. The data is being processed and will be integrated with reprocessed existing 3D data to obtain a consistent subsurface image across the entire deepwater hydrocarbon fairway, with final results expected in the fourth quarter of this year, Cove said.

Meanwhile, the company has accelerated exploration work at its deepwater blocks L5, L7, L11A, L11B and L12 offshore Kenya, with the acquisition of more than 3,500 sq km of new 3D seismic planned. At blocks L10A and L10B, a 3D seismic survey over the eastern section of the permits is planned later this year.

RUSSIA

Indian Consortium OVL to Bid for Stake in Yamal LNG

An Indian consortium led by ONGC Videsh Ltd, the overseas unit of state-owned Oil and Natural Gas Corp. Ltd (ONGC), plans to bid for less than 20% stake in an upstream hydrocarbon block-linked natural gas liquefaction project and liquefied natural gas marketing opportunity offered by Russian firm OAO Novatek in Yamal peninsula.

Its partners include GAIL (India) Ltd and Petronet LNG Ltd (PLL).

Novatek has a 51% stake in OAO Yamal LNG, which has the license for exploration and development of the South Tambeyskoye field located in the north-east of the peninsula.

"We are expected to make a submission of non-binding offer shortly," said Joeman Thomas, OVL's managing director. Mint had reported about the consortium plans on November 26.

India, relying on its historical association with Russia, believes it has a strategic advantage over main rival China, unlike in Africa. The region, Yamal-Nenets, located north-west of Siberia, accounts for nearly one-fifth of the world's natural gas production and supplies 90% of demand in the country.

McIlvaine Company,

Northfield, IL 60093-2743

Tel: 847-784-0012; Fax: 847-784-0061;

E-mail: editor@mcilvainecompany.com