Natural Gas Outlook This Week

Prices

Natural gas spot prices continued declining this week, reflecting moderating demand as temperatures warmed in key high-demand areas of the country. Spot prices at market locations across lower 48 States fell since last Wednesday, March 10, with decreases ranging between 4 and 26 cents. Prices at trading locations serving demand centers in the Northeast also fell significantly on the week, as spring-like temperatures arrived. The spot price at the Algonquin Citygate, which delivers natural gas to markets in New England, fell 19 cents or about 4 percent on the week. Transcontinental Pipeline’s delivery into New York City was priced at $4.58 per MMBtu yesterday, 18 cents, or 3.8 percent, lower than the previous Wednesday.

Prices at trading locations serving markets in California registered some of the biggest declines since last Wednesday, particularly the southern portion of the State where temperatures continued to moderate. Natural gas spot price at the Southern California Gas Company’s market location fell 22 cents or about 5 percent since last Wednesday, ending trading yesterday at $4.49 per MMBtu. Prices at the Pacific Gas and Electric trading location, which serves markets in northern California also decreased significantly on the week, falling by 21 cents. However, despite the significant price decline, this location was the highest-priced in the lower 48 States as of yesterday, ending trading at $4.81 per MMBtu. The high price at this location and its spread compared with the Henry Hub and trading locations in the Northeast is the result of several factors. These factors include BENTEK Energy estimates, which show that since the middle of 2009, electric generators in the Western United States have been using more natural gas compared with the 5-year (2005-2009) average. The increased power burn is likely the result of a reduction in hydroelectric power generation in the Pacific Northwest and California because of lower precipitation and drought conditions. Furthermore, natural gas is replacing the 1,100 megawatts of electric power that Unit 2 of the San Onofre Nuclear Generating Station (SONGS) previously generated. SONGS Unit 2 has been out of service since September 2009 for steam generator replacement.

While temperatures in the Rocky Mountain States increased slightly during the report week, they continued to hover in the 30s and 40s. Still, the price of natural gas fell substantially in a few market locations in the Rockies. The highest net weekly price drop occurred at Northwest Pipeline’s Sumas location, which fell by 26 cents or 5.7 percent per MMBtu since last Wednesday. The Sumas premium over Henry Hub decreased from 14 cents to 5 cents per MMBtu as of yesterday. Additionally, prices at Kingsgate in Idaho and Stanfield (for delivery into Oregon) fell by 23 and 22 cents per MMBtu, respectively. Overall, trading locations in the Rockies registered net weekly decreases between 4 and 26 cents per MMBtu.

The across-the-board price decreases likely resulted from the significant reduction in total U.S. demand. Total demand for the week ended March 17 fell by 8.6 percent compared with last week, according to BENTEK Energy. Consumption in the residential and commercial sectors fell by 12 percent, contributing to the week-to-week decline. The majority of the decrease in this sector occurred between Monday and Wednesday of this week, as temperatures rose in areas east of the Rockies. The electric power and industrial sectors also recorded demand decreases of 8.6 and 2.3 percent, respectively.

Natural gas supply exceeded total demand for 3 days this report week, the first time the estimated supply/demand balance was positive since November 26, 2009. However, total natural gas supply fell this week, a result of the decrease in Canadian and liquefied natural gas (LNG) sendout, according to BENTEK. Canadian imports decreased by almost 2 percent compared with last week, while LNG sendout fell by nearly 9 percent over the same period. U.S. natural gas production was flat compared with last week, with volumes totaling only 0.1 percent lower. Total supply of natural gas this week was 0.4 percent lower than last week and 2.2 percent lower than last year for the same week.

At the NYMEX, the price of the near-month contract for April delivery decreased by 26 cents during the report week to $4.303 per MMBtu. The price of the April futures contract has decreased fairly consistently since becoming the near-month contract on February 25, falling 46 cents during the period. Remaining contracts for delivery through the end (October 31, 2010) of the upcoming injection season posted similar decreases, ranging between 4.7 and 5.5 percent. Prices on the futures market likely reflect the arrival of spring-like temperatures and continued strength in natural gas production. With only about 2 weeks left in the traditional heating season, which will officially end on March 31, supplies of natural gas are relatively ample. Robust domestic production coupled with the possibility that natural gas inventories in underground storage may close the heating season at about last year’s level could provide considerable downward pressure on prices. Inventories of natural gas in underground storage ended the 2008-2009 heating season at 1,656 Bcf, the highest level since the 2005-2006 heating season ended with 1,692 Bcf of natural gas in storage. The 12-month strip traded yesterday at $4.919 per MMBtu, 22 cents or 4.3 percent lower than last Wednesday.

Storage

Working gas in storage decreased to 1,615 Bcf as of Friday, March 12, according to EIA’s Weekly Natural Gas Storage Report (see Storage Figure). The implied net withdrawal was 11 Bcf, significantly below both the 5-year (2005-2009) average withdrawal of 65 Bcf, and last year’s net withdrawal of 42 Bcf for the report week. The East and West regions both noted net withdrawals for the week; however, storage operators in the Producing region reported the first regional net injection of the season of 14 Bcf. This net injection in the Producing region reduced the storage deficit compared with last year to 135 Bcf, down from 145 Bcf last week. With less than 3 weeks left in the current heating season (November 1-March 31), natural gas stocks in underground storage are on pace to finish the heating season above the 5-year average. If the remaining withdrawals equal the 5-year average withdrawals and injections for the remainder of the month, natural gas stocks would end the heating season at 1,557 Bcf, about 73 Bcf above the 5-year average.

Temperatures in the country were generally warmer than normal for the week ended March 11, with total heating degree-days falling short of normal levels by about 10 percent. Based on the National Weather Service’s degree-day data, temperatures in the United States were 2 degrees warmer than normal, but 3 degrees colder than last year. Four Census Divisions in the Northeast and the Midwest recorded average temperatures that were more than 5 degrees warmer than normal (see Temperature Maps and Data). The West South Central Census Division, which roughly coincides with EIA’s Producing Region, also experienced above-normal temperatures. Despite relatively warmer temperatures in the Northeast and the Midwest, these areas remained cold and registered the lowest temperatures in the country for the week ended March 11. Elsewhere in the United States, average temperatures ranged between 39 and 67 degrees.

Other Market Trends

EIA Highlights Differences between Projections and Actual Values in AEO. On March 16, EIA released its Annual Energy Outlook (AEO) Retrospective Review, which presents a comparison between projected data for all fuel types in the AEO reference case and the actual outcomes from 1982 to 2009. The report measured the average absolute percent difference, which is the simple mean of the absolute values of the percentage difference between the reference case projection and the actual value. The report concluded that consumption forecasts for most fuel types were often far more accurate than price forecasts, as consumption is relatively more stable compared with energy prices. However, the fuel with the largest difference between projections and actual consumption was natural gas, the result of difficulty in forecasting the effects of regulatory changes in the 1980s. Regarding other natural gas data, EIA’s forecasts were generally 57.6 percent off for wellhead prices; 7.1 percent for consumption; 6.2 percent for production; and 15.6 percent for net imports when the time frame between 1982 and 2009 is analyzed. EIA noted that expectations of technological improvement within the natural gas industry embedded in early editions of the AEO were somewhat conservative, further affecting the accuracy of forecasts. Additionally, despite the large difference between projected and actual wellhead prices from 1982-2009, the error has decreased over time. For example, the AEO had an absolute relative error for natural gas wellhead prices of 7.5 percent in 2006, no error in 2007, and 0.2 percent in 2008. In general, longer-term price forecasts were more inaccurate.

Shale Will Play a Greater Role in Natural Gas Production. Speaking on March 12 to Clean Skies News at the Cambridge Energy Research Associates energy conference (CERAWeek) in Houston, Texas, EIA Administrator Richard Newell discussed increasing prospects for natural gas production from shale formations, as well as the role of natural gas in power generation. Newell noted that shale gas production comprises an increasing percentage share of dry natural gas production, totaling 11 percent in 2009. Over the next 25 years, shale is expected to account for more than 25 percent of dry natural gas production. Newell noted that the electric power sector will contribute substantially to growth in natural gas consumption. Newell also discussed the role renewable energy sources will play in reducing greenhouse gas emissions. A video of Newell speaking is available here: http://www.eia.doe.gov/neic/press/video/video.html

Natural Gas Transportation Update

- Southeast Supply Header, LLC (SESH) has begun planned maintenance on several compressor units, reducing available capacity through associated stations on its system. On March 15, work began at the Lucedale Compressor Station in Mississippi. SESH’s capacity through the Lucedale station during maintenance will likely be approximately 870,000 decatherms (Dth) per day, compared with normal capacity of about 1,060,000 Dth per day. From March 18–20, maintenance will occur at the Gwinville Compressor Station, also in Mississippi, where capacity will be limited to 920,000 Dth per day. Lastly, maintenance at the Delhi Compressor Station in Louisiana between March 22 and 27 will limit capacity through the Delhi and Gwinville compressor stations to 800,000 Dth per day. Normal operating capacity through the Delhi and Gwinville stations is 1,020,000 and 1,060,000 Dth per day, respectively.

- Gulf South Pipeline Company LP began maintenance on Unit #3 at Marksville Compressor Station in Louisiana on Tuesday, March 16. According to the pipeline company, work is expected to last 30 days, likely reducing capacity through the station by 150,000 Dth per day. The pipeline company moved up the maintenance from an original start day of March 29.

- Rockies Express Pipeline LLC (REX) on Monday, March 15, informed shippers that it had completed repairs at its compressor station in Cheyenne, Wyoming, returning capacity to 1,900,000 Dth per day. The capacity of REX’s segment 200 in Wyoming had been reduced to 1,550,000 Dth per day on March 7 because of repairs on a transformer at the compressor station.

- Columbia Gas Transmission, LLC on March 16 began planned maintenance on its pipeline in Green County, Pennsylvania. The maintenance will reduce capacity at an interconnect between Columbia and Texas Eastern Transmission near Waynesburg, Pennsylvania. According to BENTEK Energy, flows for March 18 are 80 million cubic feet (MMcf), down 60 MMcf from the 30-day average of 140 MMcf. Maintenance is scheduled to run through April 14, but minimal impact is expected because of below-normal demand in the Northeast, BENTEK said.

Source: U.S. Energy Information Administration

India's Third LNG Terminal Commissioning Delay

India's third terminal to import LNG will miss by a year the target to commission its first phase in March because of delays in starting dredging to desilt the ship channel, a senior executive at its owner said.

Due to delays in getting government clearances and a shortage of equipment, the dredging contractor, Gammon India Ltd., had to postpone its work, the executive at Ratnagiri Gas & Power Pvt. Ltd. told Dow Jones Newswires, asking not to be identified.

The terminal to handle 5.0 million metric tons of LNG a year was initially planned by Enron Corp. to import LNG for a power plant it was setting up in the western state of Maharashtra. It was also planning to lease out excess capacity. After the U.S. company's collapse, Ratnagiri Gas & Power took over the projects in 2005.

The delay in opening the terminal isn't expected to have any major impact on gas supplies as the local market is well fed with Reliance Industries Ltd. increasing output at its gas field in the Krishna-Godavari basin off the east coast. Ratnagiri Gas & Power also gets gas from Reliance to run its 2,150-megawatt power plant.

Also, Petronet LNG Ltd., India's largest LNG importer, has raised capacity at its Dahej terminal in the west coast to 11.5 MMTPA from 6.5 MMTPA.

QGC, BOC sign deal to produce LNG from coal seam gas

This is a joint venture between the Queensland Gas Company and gas company BOC. This plant will provide LNG to create fuel for trucks.


Premier Anna Bligh said it could be the start of a new industry, leading to heavy transport switching from diesel to LNG.

"LNG produces up to 25 per cent fewer emissions than diesel and is a proven safe alternative to other fossil fuels,'' she said.

"Through this agreement, Queensland will join the rest of Australia, as BOC develops a network of fuelling stations across the country for vehicles converted to run on LNG.''
Ms Bligh said QCG has agreed to supply gas to BOC from July 2011 and if the companies meet that deadline, Queensland will become the first in Australia to produce LNG from coal seam gas.

The plant will be built next to the Condamine Power Station, west of Chinchilla, with construction expected to start early next year.

CNOOC to build new LNG terminal

CNOOC Ltd is in talks with the relevant government authorities regarding the construction of a new liquefied natural gas terminal, Song Enlai, a senior executive at CNOOC said. CNOOC operates three LNG terminals, one in Guangdong Province, one in Fujian Province and one in Shanghai. Its fourth terminal, located in Zhejiang Province, is still under construction.

(Source: China Knowledge Online)

Adriatic LNG terminal will be operational in 2014

Croatia's energy firms power board HEP, gas pipeline operator Plinacro and INA will change their participation structure in an Adriatic liquefied natural gas (LNG) terminal project to help make it operational in 2014.

Location: Northern Adriatic island of Krk

Capacity: 15 BCM

Target Market: Central and southeastern Europe and Italy

Investment Expected: 800 million euros

The government is expected to adopt a decision on establishing the Croatian LNG consortium soon.

At the moment, four foreign energy firms keen to take part in the project are part of the Adria LNG consortium. They include Germany's E.ON-Ruhrgas, Austria's OMV, France's Total and Geoplin from Slovenia.

Croatian firms should join later this year and have a 25-percent stake in the joint venture. INA can have 14 percent while Plinacro and HEP will jointly have 11 percent.

The LNG project has moved slowly in recent years, largely due to a slow decision-making process within Croatia, but the foreign investors are keen to speed it up because of a strong competition looming on the Italian side of the Adriatic.

Approval for Mid-Atlantic LNG Import Deal

A U.S. subsidiary of Moscow-based OAO Gazprom, the world’s largest gas producer, won federal approval today to import liquefied natural gas into the U.S. Mid-Atlantic region.

The Federal Energy Regulatory Commission voted in favor of a deal between Gazprom Marketing & Trading USA Inc. and a U.S. affiliate of Oslo-based Statoil ASA to import the gas through Dominion Resources Inc.’s LNG terminal in Cove Point, Maryland. As much as 200 million cubic feet of gas a day would be imported under the Dec. 1 deal.

Surat LNG pipeline

The State Government has approved the first licence for a gas pipeline from the Surat Basin to Gladstone in central Queensland.

Arrow Energy is planning to build an LNG facility on Curtis Island near Gladstone and hopes to start exporting in 2012.

The Government has approved a 470 km pipeline from Dalby which will cost about $550 million.

Arrow Energy spokesman Gareth Quinn says the company is also planning to build a pipeline from Moranbah to Gladstone.

Arrow Energy to acquire Gladstone LNG

Liquefied Natural Gas Limited (LNG) has executed a conditional heads of agreement with Arrow Energy Limited to sell the entire Fisherman's Landing liquefied natural gas project (Gladstone LNG Project) through the sale of LNG's 100% owned subsidiary Gladstone LNG Pty., Ltd. for a combination of cash, milestone payments, royalties and Arrow options. The total transaction is valued at approximately AUD45 million ($39.4 million). All the companies are based in Australia.

Arrow Energy is an integrated energy company focused on the development of coal seam gas. LNG is engaged in the production and sale of liquefied natural gas in Australia.

The consideration will consist of $10 million licensing fee for Arrow's use of LNG's OSMR(R) technology for the first LNG train, with $5 million to be paid by Arrow to LNG Ltd by February 28, 2010 and a further $5 million payable at notice of readiness to proceed to construction of the first LNG train. An additional $10 million license fee is payable for each additional LNG train developed at the project site using the OSMR(R) technology.

Deal Value (US$ Million) 39.4

Deal Type                Acquisition

Sub-Category             100% Acquisition

Deal Status              Announced: 2010-02-11

Deal Participants

Target (Company)   Gladstone LNG Pty., Ltd.

Acquirer (Company) Arrow Energy Limited

Vendor (Company)   Liquefied Natural Gas Limited

First LNG Distribution Terminal in the Dominican Republic

AES Dominicana has inaugurated a LNG distribution terminal east of Santo Domingo, the first facility of its type in the Dominican Republic and Latin America. The LNG terminal will yield annual savings of more than $1 Bn, AES Dominicana officials said.

The terminal will allow the Dominican Republic to “significantly” reduce its high dependence on petroleum, AES Dominicana chief Marco De la Rosa said.

The LNG terminal, among other benefits, will allow the Dominican Republic to replace 35 percent of its fuel mix, create around 300 new direct and indirect jobs, and reduce emissions of CO2, the gas believed to contribute to global warming, by more than 300 tons annually.

The use of LNG “will help achieve total savings on the order of $1.1 billion annually, representing a sum relative to 2.5 percent of the gross domestic product,” the AES Dominicana chief said.

US Coast Guard clears Yemen LNG shipments

LNG shipments from Yemen have been cleared by the US Coast Guard for entry into the Distrigas terminal in Everett outside Boston, in the face of local opposition.

BW Gas and Höegh LNG ships chartered by Distrigas owner GDF Suez would begin calling from Yemen from the end of February. Distrigas has signed a 20-year contract with a Yemeni supplier and expects to bring in up to 30 shipments a year to its Everett facility. The imminent delivery would be only the second from Yemen to the United States. A tanker carrying Yemeni LNG arrived earlier this week in less-populous Sabine, Texas, according to John Healey, Coast Guard captain of the port of Boston, who said the Coast Guard spent a year reviewing security plans for the Yemeni shipments.

LNG Project in in central Queensland, Australia

 Australia Pacific LNG is one step closer to making the liquefied natural gas industry in central Queensland a reality, with the lodgement of its draft environmental impact statement (EIS) with the State Government.

The EIS covers the project's gas fields, a 450 km gas transmission pipeline and an LNG plant on Curtis Island in Gladstone.

Joint venture partner Origin Energy says it is a significant milestone for the project.

Origin's executive general manager, Paul Zealand, says the final investment decision for the project is expected by December this year, with the first gas to be exported in late 2014.

LNG offloading terminals in Orlovka bay, Gazprom

 Shtokman LNG offloading terminals will be located in Orlovka Bay as it was decided at Gazprom meeting. Alexey Miller, Chairman of the Gazprom Management Committee held a meeting on the Shtokman gas and condensate field development.

The meeting was attended by heads and experts from the Gazprom Administration subdivisions, subsidiaries, corporate research and design institutes and Shtokman Development AG, reads the press release of Gazprom.

The meeting discussed Shtokman project progress focusing on technology optimization within first phase of the Shtokman development. The idea is to raise the economic efficiency and to assure navigation safety of heavy-duty LNG carriers.

Based on the meeting results the decision was taken to position LNG offloading terminals in the northern part of the Orlovka Bay (Murmansk region, eastwards from Teriberka). The project operator will rely on this decision when planning its further activities.

Total may invest in new LNG project

Total could invest in a liquefied natural gas (LNG) plant project led by EDF in Dunkirk to offset possible job losses if the refiner decides next week to close a refinery in the same town, an industry source said.

Oil giant Total is considering permanently shutting its 137,000 barrels-per-day Dunkirk refinery in northern France, or a 13 percent share of the group's French output capacity, which could result in some 600 job losses, a source close to the situation said earlier this month.

Total is expected to make the announcement on the possible closure after an extraordinary meeting with unions on Feb. 1.

The French government has pressured Total to find an alternative industrial project to compensate for the possible job losses, three months before key regional elections.

EDF, which is planning to make a final investment decision on the Dunkirk LNG plant in the next six months, said at the end of 2009 that it was looking for financial partners for half of the 700-million euro investment.

The plant is expected to start running in 2014 and produce some 13 BCM of gas.

BPMigas rejects LNG project plan for Sengkang LNG project

Upstream oil and gas regulator BPMigas has rejected a plan of development (POD) for a liquefied natural gas (LNG) project proposed by Energy Equity Epic Sengkang, a subsidiary of Australia-based Energy World Corporation (EWC), on the grounds that the proposal is incomplete.

“The POD is not backed up with valid data. How can we approve the POD if we don’t even know

the reserve data?” BPMigas’s chairman, R. Priyono, told. Priyono said BPMigas rejected Energy Sengkang’s work program and budget (WPNB) for development of new gas reserves in the block.

“We cannot approve their WPNB for drilling activities, because they don’t follow the SOP [standard operating procedures]. It’s strange they want to drill without an initial seismic survey,” Priyono said.

EWC’s executive director Brian Allen said during a hearing with the House of Representatives Commission VII overseeing energy and mineral resources on Monday that the new reserves would be able to provide between 300 billion cubic feet (BCF) and 500 BCF of gas for the LNG plant

He said the proposed LNG development would cost EWC about US$500 million in investment.

To facilitate the financing and funding for the LNG project, part of the LNG would be exported.

Energy Sengkang is one of 232 oil and gas contractors operating in Indonesia. Based on their proposed work programs and budgets for 2010, the contractors plan to spend nearly US$16 billion in upstream activities in this coming year.

Origin seeks environmental nod for $31.3 Bn LNG project

Origin Energy said it had sought formal environmental clearance for its gas export project with U.S. ConocoPhillips.

Origin, the country's largest producer of coal seam gas, said the lodging of the draft environmental statement with the Queensland state government advances the $31.3 billion project towards a final investment decision by December this year and first LNG shipments by late 2014.

While the lodging of the environmental statement is a key project milestone, investors are still looking for firm gas sales before validating the project, analysts say. There are four other projects racing to start exporting Australian coal seam gas and the Origin/Conoco development is seen by some analysts as a falling behind the rivals as it was yet to lock in any gas sales.

Origin's project, also known as Australia Pacific LNG, will produce between 3.5-4 million tonnes per year (mtpy) of LNG in the first phase in 2014, before progressively expanding up to 14-16 mtpy.

PGN signs initial LNG contract with EEES

PT Perusahaan Gas Negara (PGN) signed an initial agreement to purchase up to 5 million metric tons of liquefied natural gas (LNG) per annum from Energy Equity Epic Sengkang Pty Ltd (EEES).

"PGN will receive between 1.5 and 5 million metric tons of LNG per annum *MTPA* from EEES. The LNG is expected to be delivered from 2012 as part of a five-year contract," PGN president director Hendi Prio Santoso said.

Hendi refused to divulge the contract's value, saying the pricing was one of the issues the two companies would finalize later.

Stewart Elliot, CEO of EEES's parent company Energy World Corporation Ltd, said EEES had produced a surplus of gas at its block in Sengkang, Central Sulawesi.The company was also planning to build an LNG plant, he added.

"We will build the LNG plant with a production capacity of 2 MTPA to begin with.
"We will then ramp up the capacity to 5 MTPA," he said.

Elliot added EEES would spend between US$400 million and $500 million to build the 2 MTPA plant.

EEES has been preparing for the plant's permit and putting together its component manufacturing.

"We expect the plant will start operating in 12 to 18 months from now," he added.

Hendi said the LNG would be supplied to PGN's LNG-receiving terminals it was planning to build in West Java and North Sumatra.

As has been reported earlier, PGN and state oil and gas company PT Pertamina have formed a consortium to build the two LNG-receiving terminals in those particular regions.

InterOil’s PNG LNG project seeks approval

Papua New Guinea’s second liquefied natural gas project is edging forward after Canadian independent InterOil and its joint venture partners submitted a project agreement to the government to build the proposed plant in Port Moresby.

InterOil said that both the Prime Minister of PNG, Michael Somare, as well as the Minister for Petroleum and Energy, William Duma, have stated their support for the proposed project and associated agreement.

The proposed project targets a $6 billion two train LNG facility, with each train capable of producing about 4 million tonnes of LNG per year. Current plans call for first production of LNG towards the end of 2014 or beginning of 2015.

At least 5000 jobs are expected to be created at peak construction of the InterOil facility. Economic returns from the project are expected to help fund public infrastructure and community services in Papua New Guinea, such as education and health, and provide income to land owners.

InterOil's partners in the project are Petromin PNG Holdings and Pacific LNG Operations.

Indonesia Tangguh begins trial at train 2

Indonesia's Energy Minister said trial runs at the second LNG train at the Tangguh project began last week and the first train would resume operations by the second week of October at the latest.

The Tangguh LNG plant in Papua, led by BP's Indonesian unit, started up this year but was temporarily shut in August to resolve technical problems.

"Second train commissioning started. Trial runs are on," the minister, Purnomo Yusgiantoro, told Reuters in an interview.

Indonesia's oil watchdog BPMIGAS said last week the LNG plant, which has a capacity to produce 7.6 million tonnes per year (tpy) via two trains, will ship only 16 cargoes of liquefied natural gas in 2009, well short of its previous estimate of 56 cargoes.

BPMIGAS monitors oil and gas firms operating in Indonesia.

Indonesia, the world's third-largest LNG exporter after Qatar and Malaysia, plans to use more natural gas at home to avoid costly oil prices as its own oil reserves dwindle.

Yusgiantoro said fertiliser customers had placed a request for 0.5 million tonnes of LNG from Donggi-Senoro project and the remaining 1.5 million tonnes was yet to be sold.

He said the promoters were still negotiating price and financing of the project.

The Donggi-Senoro project, which will require $1.7 billion for upstream activities and $2 billion for downstream, has been under threat since Vice President Jusuf Kalla said in June gas from the project should be sold to the domestic market.

Yusgiantoro said Indonesia, the world's largest thermal coal exporter, would export 150 million tonnes of coal annually from 2015. It exported 140.35 million tonnes of coal in 2008.

"We will increase it by 20 million tonnes to 30 million tonnes per year up to the level that it can be massively exported," Yusgiantoro said. Currently, Indonesia uses 40 percent of its output locally and exports the rest.

CNOOC Shanghai terminal to receive 1st LNG cargo

The Shanghai LNG project, a joint venture between CNOOC and Shenergy Group, is expected to receive its first cargo of liquefied natural gas (LNG) from Malaysia around Sept. 20, an industry source said.

The shipment would be about 80,000-90,000 cubic metres, the source said, adding that the fuel would be used later to test new facilities.

Previous imports from Malaysia were diverted to Wuhaogou, an existing small LNG terminal in the financial hub, which has two 50,000 cubic metre LNG tanks and one 20,000 cubic metre tank and serves as backup supplies for the city.

Wuhaogou is run by Shanghai Gas (Group) Co Ltd, a unit of Shenergy Group. The group controls Shenergy Company .

Under a long term contract, Malaysia's Petronas will supply 3.03 million tonnes of LNG a year to the new Shanghai terminal for 25 years starting from 2009.

China National Offshore Oil Corporation (CNOOC), parent of CNOOC Ltd, has one terminal in Guangdong and another in Fujian in operation.

Yemen LNG says to start producing in "coming weeks"

Yemen LNG expects to start production from its new gas liquefaction plant in the "coming weeks", the company's chief executive said.

The first cargo was originally scheduled to be exported in August, but start-up problems, including leaking valves and minor glitches, delayed first production.

"Well we are in the start-up phase at the moment, we are working very hard and should see (production) in the coming weeks," Joel Fort said.

"We are not yet producing LNG but we are flowing gas through the first LNG train at the moment."

The Total-led Yemen liquefied natural gas (LNG) project in Balhaf, is expected to help boost economic growth in the country to nearly 8 percent, almost double last year's gross domestic product.

Other investors in the project include U.S.-based Hunt Oil and Yemen Gas Co, which own 17.2 percent and 16.7 percent, respectively.

The project has the capacity to produce 6.7 million tonnes of LNG for export from the Gulf of Aden port of Balhaf.

At the end of 2008, Yemen held 17.3 trillion cubic feet (tcf) of proven natural gas reserves, according to the BP Statistical Review.