LNG UPDATE
August 2010
McIlvaine Company
TABLE OF CONTENTS
U.S. Alaska Legislators Seek Local Gas Assurances before Kenai Extension
Maine EP Board Postpones $920 Mln LNG Terminal Hearing
Calais LNG Seeks New Financial Backer by August 11
FERC Says Florida Gas, Williams Partners Can Connect to Gulf LNG
Kogas, Pemex Gas Forge LNG Pact
Hunt Oil’s Peru LNG Plant may Spur Gas Exploration and Investment
Hitachi, Toyo Engineering Target Sale of Small LNG Plants to Asia
CB&I Snags $190 Mln LNG Tank Contract in Asia Pacific
Beach Energy, Itochu Form Non-binding LNG MOU
Queensland LNG Back on Track with Govt Tax Concessions
Emerson Selected Main Automation Contractor for Shell Floating LNG Facility
Apache, Kufpec, Kogas Sign Wheatstone Deal
Santos Secures Billion Dollar Bank Loan to Help Fund LNG Growth
LNG Projects Cause Shutdown at Queensland Cougar Energy Plant
Chevron Targets 25 Mt/y Production Capacity at Wheatstone
China's CNOOC and Shaanxi Auto Join Forces on Heavy-Duty LNG Trucks
CNOOC Starts Operating 4 Gas-Fired Power Generators in Fujian
Kentz Clinches CB&I Papua New Guinea LNG Contract
Eidesvik Offshore Orders LNG-fuelled PSVs
Foster Wheeler Wins FEED Framework Agreement for Kårstø Project
Alderley Systems Secures Saipem Contract for Metering System at Algerian LNG Plant
Nigerian Operators Revive $20 Bln in Three Liquefaction Projects
Israel Says Additional Gas Terminals to be Built only on Future Discoveries
Shell Sees Qatari LNG, Pearl GTL Unit Completed by Year End with Production Ramp Up in 2011
Seven Alaska legislators have asked the state attorney general to oppose a two-year extension to a federal license for LNG exports from the ConocoPhillips and Marathon Oil LNG plant near Kenai until the companies agree to fulfill local gas supply requirements before exporting, the group said in a July 8 press conference.
"We support the export of surplus gas but local needs must be met first," said state Sen. Bill Wielechowski, speaking for himself and six other Democratic lawmakers.
The seven lawmakers sent a letter to the U.S. Department of Energy asking the agency to fulfill the intent of the federal Natural Gas Act that exports of gas are not allowed if there are domestic requirements.
Wielechowski also said state Attorney General Dan Sullivan will be asked to "aggressively" oppose the extension unless the license includes a provision on meeting local needs.
The request could put Sullivan at odds with Gov. Sean Parnell, a Republican, who supports the exports, apparently without the local supply guarantee.
It is unclear just what special leverage the state may have in the Energy Department's proceedings on the license extension other than commenting.
ConocoPhillips spokeswoman Natalie Lowman said the LNG plant owners have been reliable suppliers of gas to local utilities for years and will continue to be as long as the Kenai plant is operating.
"We recently agreed to a seven-year contract to supply Chugach Electric and now have a one-year contract with Enstar. We're now in discussions with Enstar to meet their other needs," Lowman said.
ConocoPhillips and Marathon filed an application for the license extension in early June, asking to extend the period of a previous extension granted in 2009. The current license, which allows the export of about 90 billion cubic feet of gas, expires in March 2011.
The extension would not increase the amount exported, however, since by 2011 the companies will actually have exported only about half the amount approved. The request for additional time, until March 2013, would allow the balance of the 90 billion cubic feet to be exported, ConocoPhillips has said in previous briefings.
However, Wielechowski questioned whether agreements made by ConocoPhillips and Marathon to secure the state's support for the 2009 license extension have been met.
One provision: ConocoPhillips and Marathon had agreed to accept gas at the LNG plant from other companies to provide a market for independent groups now exploring in Cook Inlet. It is unclear whether this requirement has been met, Wielechowski said.
Another provision required the two companies to drill new wells and to maintain current Inlet gas reserves, and this has not been met, he said.
Lowman said this isn't true. ConocoPhillips' commitment was to drill two wells. The company has actually drilled five since then, she said.
Wielechowski said Enstar Natural Gas Co., the regional gas utility, has had difficulty securing supply commitments from Cook Inlet producers and in short for part of its requirements beginning in 2011. In 2013 Enstar will be short of as much as one-third of its needs, he said.
Signing the letter to the Energy Department, besides Wielechowski, were state Reps. Les Gara, Berta Gardner, Chris Tuck and Pete Petersen, and Sens. Hollis French and Bettye Davis.
A week-long hearing on a proposed liquefied natural gas terminal did not begin as planned in Calais, ME July 19
The Maine Board of Environmental Protection granted the request by Calais LNG to postpone the hearing into the company's application for state permits for the proposed terminal across the St. Croix River from the port of Bayside.
On July 12, the Calais planning board granted the company a building permit for the US$920-million project inside city limits. It still needs state and federal approval.
On July 13, the company requested to postpone the state hearing to allow it more time to provide "certain relevant information" on marine resources, wetlands and soils, the Board of Environmental Protection said in a news release.
"Postponement at this point in the proceeding, comes at a considerable cost in time and resources to the Board and the other parties," board chairwoman Susan Lessard stated in the news release.
"However, since Calais LNG bears the burden of demonstrating that its proposed project meets the licensing criteria and since information needed for the Board to make a fully informed decision on the application is apparently lacking, I have reluctantly concluded that the hearing should be postponed," she said. The board did not set a new date for the hearing.
Calais LNG, backed financially by the investment banking firm Goldman Sachs of New York, hopes to get the approvals it needs to begin construction in the third quarter of next year. The company has spent $24 million already clearing regulatory hurdles.
The Canadian government says it will not allow LNG tankers to cross Canadian waters to get into Passamaquoddy Bay and up the St. Croix River.
The proponents of this and other LNG projects in Maine argue that Canada cannot prevent "innocent passage" of ships passing through Canadian waters to ports in Maine.
Supporters say LNG promises needed work in a poor region of the United States.
Opponents say LNG tankers will destroy opportunity in fisheries, aquaculture and tourism which depend on a clean environment.
Supporters, especially in Maine, contend that Canada would block LNG tankers from Passamaquoddy Bay to protect commercial interests, not the environment.
In a June 29 letter Neil LeBlanc, Canada's consul general to New England, restated Canada's stance to David P. Littell, commissioner of the Maine Department of Environmental Protection.
Although the hearing did not go ahead as planned, the Maine environmental board did visit the proposed Calais LNG site July 19.
A company hoping to build a liquefied natural gas terminal in Calais, Maine, is working to line up a new financial backer after the original partner opted to drop out of the project.
If a new backer is not found within three weeks, Calais LNG will withdraw its application from the Board of Environmental Protection, according to a letter sent July 21 to state regulators.
Calais LNG wrote to BEP chairwoman Sue Lessard that GS Power Holdings LLC -- a subsidiary of the global investment firm Goldman Sachs Group Inc. -- "is in the process of selling its interest in the project to a new financial partner."
No reason is given for GS Power Holdings' decision.
"In the event that the transaction noted above does not close by August 11, 2010, Calais LNG would expect to withdraw all Calais LNG applications filed with the Maine Board of Environmental Protection," attorney David Van Slyke wrote to Lessard.
Calais LNG has proposed to build a liquefied natural gas facility on a 330-acre site along the St. Croix River and Passamaquoddy Bay. The project is estimated to cost $800 million to $1 billion.
The latest development comes one week after BEP officials reluctantly agreed to the company's request to postpone a week of public hearings that had been scheduled to begin July 19.
At the time, Van Slyke had said Calais LNG needed more time to complete a number of tests, surveys and data collection for its proposed development before the hearings.
Calais LNG official Art Gelber declined to comment on the letter until Lessard had been given a chance to make a decision on the company's request to postpone a legal meeting scheduled for July 24.
But critics of the project seized on the letter and suggested that Calais LNG's financial situation may have been the real reason for postponing this week's public hearings.
Ronald Shems, an attorney for Save Passamaquoddy Bay 3-Nation Alliance, also noted that Calais LNG has been touting Goldman Sachs' involvement as proof of the project's strength.
"The fact that Goldman Sachs is pulling out speaks volumes to the project's merit," Shems said.
It was unclear on July 21 whether Goldman Sachs will have any additional involvement in the project other than through GS Power Holdings LLC. Calais LNG's website highlights in several places the role that Goldman Sachs is playing in the project.
"In the Calais LNG project, Goldman Sachs sees an opportunity to invest in a project that will supply much-needed, cost-effective, cleaner natural gas to areas including Maine, New Hampshire, and Boston where there is growing demand for natural gas and a shortage of supply," the site states.
Florida Gas Transmission Co. and Williams Partners L.P. on July 21 announced that the Federal Energy Regulatory Commission (FERC) has approved a proposal to connect the existing FGT and Transco natural gas pipeline systems with the new Gulf LNG Clean Energy import terminal being developed near Pascagoula, MS.
Additionally, FGT received FERC approval for its Mobile Bay Lateral Extension Project. FGT will build, own and operate an approximately 9-mile, 24-inch-diameter pipeline that would provide access to FGT's mainline by extending south from the current terminus of FGT's Mobile Bay Lateral to connect with the proposed Pascagoula Expansion Project and the jointly-owned Mobile Bay Lateral. This part of the expansion would also include some modifications to FGT's existing compressor station in that area.
The Pascagoula Expansion Project, a partnership between FGT and Williams' Transco pipeline, will consist of approximately 15.54 miles of 26-inch diameter pipe located in portions of Mobile County, Ala. (4.59 miles), and Jackson County, MS (10.95 miles). The $59 million pipeline project will have the capacity to transport approximately 810,000 dekatherms of natural gas per day by its in-service date in the late summer of 2011. The project has been fully contracted with Angola LNG Supply Services LLC. Construction is scheduled to begin in April 2011.
"The Pascagoula Expansion Project leverages existing pipeline infrastructure to provide robust southeastern markets with access to additional natural gas supplies," the project sponsors said in a statement. "We appreciate the FERC's thorough review of this project. With the certificate now in hand, we can move forward with linking to this important new supply source."
The Gulf LNG Clean Energy import terminal is currently under development and scheduled to be placed into service in the fall of 2011.
Angola LNG Supply Services LLC (ALSS) is a Delaware limited liability company owned by affiliates of Sonangol, Chevron, BP, Total and ENI. ALSS will purchase liquefied natural gas from a 5.2 million metric ton liquefaction plant currently under construction on the Congo River in northern Angola, and transport it to the U.S. via ships to a LNG receiving terminal under construction in Pascagoula, Miss. The ALSS offices are in Houston, Texas.
Williams owns 84 percent of Williams Partners, including the general-partner interest. Most of Williams' interstate gas pipeline and midstream assets are held through its ownership interest in Williams Partners.
The Transco pipeline is a 10,000-mile pipeline system which transports natural gas to markets throughout the northeastern and southeastern United States. The current system capacity is approximately 8.6 billion cubic feet per day.
Florida Gas Transmission Co., a subsidiary of Citrus Corp., operates a 5,000-mile natural gas pipeline system extending from south Texas to south Florida with mainline capacity of 2.1 billion cubic feet per day. Citrus Corp is 50 percent owned by Southern Union Co. and 50 percent owned by El Paso Corp.
State-run Korea Gas Corp., or Kogas, said July 2 that it has agreed with Pemex Gas, a unit of Mexico's state-run energy firm Petroleos Mexicanos, to cooperate on liquefied natural gas projects.
Under the agreement, the companies will share information on LNG pricing in the Asia-Pacific region and in Mexico, according to a statement from Kogas.
Kogas, South Korea's largest LNG supplier, also said it will jointly seek with Pemex Gas to secure LNG supply to Mexico's Razaro Cardenas LNG terminal, which is being jointly built by South Korean conglomerate STX Group.
The deal between Kogas and Pemex comes as South Korean President Lee Myung-Bak is on a visit to Mexico to promote trade between the two countries.
Kogas has been expanding its business abroad to widen its sources of revenue and find partners, as companies from South Korea and elsewhere in Asia also look to tie up global gas deals.
"This agreement will help us expand our business in the Mexican LNG market on the back of the joint project in which we're already involved," Jung Jae-Ho, an official on Kogas' LNG business team, said.
A consortium led by Kogas, Samsung C & T Corp. and a Japanese company is also building an LNG terminal in Manzanillo, Mexico.
Kogas is contracted to operate the Manzanillo terminal, due to be completed by August next year, for the next 20 years, supplying gas to Mexican state-run electricity provider Comision Federal de Electricidad, or CFE, Jung said.
The news of the Kogas-Pemex tieup comes on the same day that reports emerged that Japan's Tokyo Gas Co. is in discussions with PTT PCL about the possibility of the Japanese firm using its weight in the LNG market to help the Thai company buy supplies for a receiving terminal it is building.
Separately, STX Group said in a statement July 2 that it has signed an initial agreement to supply LNG to Pemex once an LNG terminal being built at Razaro Cardenas is completed, scheduled for the second half of 2014.
STX Group in February signed a joint development agreement to build the Razaro Cardenas terminal, which will have annual processing capacity of 3.8 million tons, according to the statement.
Hunt Oil Co.’s $3.8 billion Peru LNG plant may spur natural-gas exploration and attract investment to the Andean country, company Chairman Ray L. Hunt said July 6.
Peru is one of 18 countries worldwide to build a liquefied natural gas facility and has the largest such plant in South America, Hunt said. He spoke in Pampa Melchorita, Peru, during the opening ceremony for the plant, which has a capacity of 620 million cubic feet a day.
Peru has lined up another $10 billion in energy projects through 2016, including 68 exploration contracts that are expected to double the country’s oil and gas output, according to the Energy Ministry. Exploration by companies including Repsol YPF SA and Petroleo Brasileiro SA may double gas reserves to 30 trillion cubic feet, Peru’s President Alan Garcia said.
“This project will provide the market incentives needed to carry out new exploration activity in Peru to find additional natural gas,” Hunt said.
The plant, a joint venture with Repsol, Marubeni Corp. and SK Energy Co., will make its first LNG shipment this month, Hunt corporate affairs director David Lemor said in an interview.
Hitachi Ltd. and Toyo Engineering Corp. zare targeting a niche market that could meet a chunk of Asia's future natural gas consumption: small-scale liquefied natural gas plants.
The Japanese technology firms are betting that gas demand will grow so quickly that tapping major deposits alone won't be enough, and there will also be a need to focus on small-scale natural gas reserves, especially in Southeast Asia.
However, that strategy has several challenges. Small-scale plants will have to compete with several other new technologies that could swell regional gas supply, including the production of gas hydrates.
In addition, major energy consumers such as China are seeking to replicate the U.S. shale gas boom, which could drive down already-low natural gas prices further and throw the economics of small-scale LNG projects into doubt.
Tighter regulation of oil and gas exploration in the wake of BP PLC's major oil spill in the U.S. Gulf of Mexico could affect the viability of projects, while the cost of raw materials like steel used in plant construction has been on an upward curve in recent years.
Hitachi and Toyo officials are confident that they can overcome such challenges. Project costs can be kept down by shortening the design phase through the use of existing technology, such as Hitachi's electric motor and Chart Energy & Chemicals Inc.'s liquefaction processes, they say.
"Global demand for natural gas will continue rising, as natural gas is the most realistic source of clean energy. We can help promote" this trend by exploiting small- to medium-sized gas reserves, said Toshihiko Ito, Chief Strategic Officer of Hitachi's social infrastructure systems company.
Hitachi and Toyo say their technology is suitable for the development of gas fields with reserves of between 500 million cubic feet and 5 billion cubic feet of gas.
There are more than 1,300 gas fields of this size across the world, according to consultancy IHS. To put that in context, the Gorgon field--Australia's largest gas resource--contains an estimated 40 trillion cubic feet of gas.
Hiroshi Sato, general manager of Toyo's international sales and marketing, said a key difference between small-scale and larger projects was in approach.
Plants for the biggest projects are designed specifically for each gas field, with capacity tailored to the expected output.
But smaller projects have an advantage as planners "can decide on capacity first, and build a plant using ready-made modules," Sato said.
It takes about 35 months to design and build a small LNG plant, which is roughly half the time it takes to build a large terminal, he said.
In June, Hitachi and Toyo began a study for Eastern Star Gas Ltd. on the feasibility of an LNG export terminal at Newcastle, Australia's New South Wales state.
Eastern Star says the first stage of the project will have an annual capacity of 1 million metric tons of LNG, with construction costs at A$1 billion excluding a pipeline. First LNG shipments are targeted for 2014.
This plan is much smaller than the Chevron Corp.-led Gorgon project, which is estimated to cost A$43 billion and has a designed capacity of 15 million tons of LNG annually.
Hitachi and Toyo Engineering officials declined to discuss costs. But Hitachi's Ito said modular LNG technology "is more realistic than conventional" technology for an LNG terminal with an annual capacity as small as 1 million tons.
Marketing could be difficult as LNG produced from coal seam gas contains a lower calorific value per volume than conventional supply, meaning it produces less energy when burnt.
While this calorific value can be lifted by spiking with products such as ethane and butane, many LNG buyers in Japan continue to prefer imports of conventional supply. Japan is the largest LNG importing country by volume and represents roughly 40% of global demand.
However, Hitachi's Ito and Toyo Engineering's Sato said they aren't overly concerned, as some Japanese gas importers and users in other Asian countries like China are willing to use LNG made from coal seam gas.
Tokyo Gas Co., Japan's largest gas utility by sales volume, signed a preliminary agreement with BG Group PLC (BG.LN) in March to buy LNG from its proposed terminal at the port of Gladstone in Australia's Queensland state. The LNG will be made from coal seam gas.
CB&I announced July 27 that it has been awarded a contract, valued in excess of US$190 million, for two LNG storage tanks associated with a major liquefaction project in the Asia Pacific region. CB&I's scope of work includes the engineering, procurement, fabrication and construction of two 160,000 cubic meter LNG storage tanks. This project, which was awarded in the 3rd quarter, is scheduled to be completed in 2013.
Beach Energy Limited on July 6 announced that it has entered into a nonbinding memorandum of understanding (MOU) with Itochu Corp. of Japan to investigate and discuss the potential for a future business arrangement in connection with supply of gas from Beach's onshore Australian portfolio to a potential integrated LNG project.
Beach's Managing Director, Reg Nelson said "Beach has built a strong relationship with Itochu over a number of years and we are looking forward to working together to research the potential for us to jointly invest in an integrated LNG project opportunity."
Itochu is one of Japan's largest and diversified general trading companies. It has interests in many business sectors throughout the world, including energy and resources both in Australia and elsewhere.
Beach Energy Limited is a long-established oil and gas exploration and production company. Based in Adelaide, South Australia, the company has oil and gas reserves of 66 million barrels of oil equivalent (at 30 June 2009), an annual production in the 2008/09 Financial Year of 9.6 million barrels of oil equivalent and an active exploration program within a balanced global portfolio of tenements.
A green light for two Australian liquefied natural gas projects worth over A$20 billion is imminent, now that the government in Canberra has excluded coal seam gas from its proposed resources tax.
The changes announced by Prime Minister Julia Gillard July 2 are significant as analysts and industry officials had warned the nascent coal seam gas sector would be at a hefty competitive disadvantage to conventional LNG projects in Western Australia state unless they were subject to the same tax regime.
A joint venture between Santos Ltd. (STO.AU) and Malaysia's Petroliam Nasional Bhd. in Queensland State, and a standalone project of BG Group PLC (BG.LN), had been preparing to sign off on their investments in Queensland state when the previous administration of Kevin Rudd unveiled the contentious resource "super-profits" tax, or RSPT, on May 2.
The RSPT triggered concerns in the coal seam gas industry that investments would be delayed as companies took another look at their business case. Up to that point, both projects had only been awaiting environmental approval before going ahead.
Now, with the tax controversy cooling and both projects recently receiving environmental approval from the Queensland state government, all that's needed to make a final investment decision is a nod from Australia's federal government. That's expected within a couple of months for both projects.
Many analysts had argued that Queensland's coal seam gas-to-LNG sector, if subject to the RSPT in its original form, would struggle to compete with the LNG industry in Western Australia.
The Western Australian projects are offshore resources that are subject to the more attractive petroleum resource rent tax, or PRRT, which kicks in at a higher rate than the RSPT.
"That's not consistent and that's not fair," Wood Mackenzie Analyst Craig McMahon said in May.
Gillard announced that coal seam gas will now be treated under the PRRT, too.
The change will be particularly helpful for Santos, which was poised to sign a customer and sell down a stake in its project at the time the tax was flagged in May. China Petroleum & Chemical Corp. (SNP), known as Sinopec, has already said it's talking to Santos and analysts believe Korean and Japanese buyers could also be circling.
Selling down an interest of at least 9%, and possibly up to 20%, in the project would give Santos much-need capital to fund its share of the development without having to conduct another equity raising or borrow more money.
Two other proposed coal seam gas-to-LNG projects in Queensland will also benefit. Origin Energy Ltd. (ORG.AU) and ConocoPhillips (COP) haven't found a customer for their gas and Royal Dutch Shell PLC (RDSB) has a A$3.44 billion takeover offer for Arrow Energy Ltd. (AOE.AU) pending, with Arrow's gas supposed to feed its proposed LNG project.
Arrow shares rose 1.3% to A$4.86 July 2, while Santos and Origin were up 1.3% and 0.8% at A$12.49 and A$14.73, respectively.
The head of Shell's Australian operations, Ann Pickard, has previously described the PRRT as "a good profits-based tax."
Coal seam gas is currently subject to state royalty payments so each project will still pay more tax despite a switch to the PRRT is better than a switch to the RSPT.
Under the existing royalty regime, about 8% of revenues are paid to the state on top of the current 30% corporate tax rate.
The RSPT would have charged 40% on profits above the long term bond rate, or around 6%, but the PRRT charges 40% on profits on the long term bond rate plus 5%, or around 11%.
Citigroup Analyst Marie Miyashiro said this month that even under the PRRT, with an 11% allowance rate, the net present value of Origin's share of its LNG joint venture with ConocoPhillips falls by about 14% from the current royalty regime, compared to 17% slide under the RSPT.
Under the PRRT, Origin and ConocoPhillips' project would require a long-term oil price of US$38 a barrel to break even, Miyashiro said.
JPMorgan Energy Analyst Benjamin Wilson said the coal seam gas projects will probably view conversion to the PRRT as "an acceptable worst-case scenario."
Wilson reckons BG will be the first project to make a final investment decision.
"We think that Santos is well positioned to secure additional customers and proceed to FID shortly after BG," he says.
Emerson has been appointed by Technip Samsung Consortium to serve as Main Automation Contractor for the Shell Prelude project, which will potentially be the world's first Floating LNG (liquefied natural gas) development. Emerson Process Management was selected by Technip Samsung Consortium due to its Global Framework Agreement with Shell, announced in February 2010. This is the first project award for Emerson Process Management resulting from its Global Framework Agreement.
Supporting Technip Samsung Consortium, the project's overall front end engineering and design contractor, Emerson will be responsible for providing the strategy, design, and engineering of the process control and monitoring technologies to support the production facility.
Floating LNG unlocks gas reserves that would otherwise be stranded as they might be too far offshore. It is the next step in LNG production, which eliminates the need for transportation pipelines of gas to shore and onshore processing. The new production facility will operate as an integrated extraction, gas processing, and liquefaction plant, all directly above the gas reserves.
With rich experience in offshore production and project execution, plus global leadership in LNG automation, Emerson is perfectly positioned to support Shell’s goals for the initial construction project and long-term operational success.
"We are thrilled to support Shell's vision for Floating LNG production," said Steve Sonnenberg, president, Emerson Process Management. "Emerson's track record of successfully delivering innovative projects like this suits us well for the challenge."
The Shell Floating LNG facility is expected to have dimensions of 480 meters in length by 75 meters in width, with a production capacity of 3.5 million to 4 million tons of LNG per year, with the ability to also process and export liquefied petroleum gas and condensate depending on gas composition. When fully ballasted, the vessel will weigh an estimated 600,000 tons, and it also has the flexibility to relocate to another gas field once production at one gas field is complete.
The Floating LNG project is located in the remote Browse Basin off the coast of Western Australia. The project is currently in the engineering and design phase of development and subject to a final investment decision.
Shell and Emerson Process Management entered into a Global Framework Agreement earlier this year, positioning Emerson as a Main Automation Contractor for all of Shell's operating businesses. This agreement aligns with Shell's strategy to reduce traditional project bidding in favor of strategic relationships and is consistent with industry trends toward collaborative, performance-based engagements that improve value for both supplier and customer.
Apache Corp. on July 19 announced that its subsidiary -- together with a subsidiary of Kuwait Foreign Petroleum Exploration Co. k.s.c. (KUFPEC) -- has signed Heads of Agreement (HoAs) for the purchase of liquefied natural gas from the Wheatstone LNG project in Australia and an equity stake in the project by Korea Gas Corporation (KOGAS).
KOGAS expects to purchase 1.5 million tons per annum (mtpa) of LNG from Apache, KUFPEC and two Chevron Corp. subsidiaries for up to 20 years. Approximately 25 percent of the LNG is expected to be purchased from Apache and KUFPEC, with the remainder from Chevron, Wheatstone's operator.
Under the equity HoA and a related transaction with Chevron, KOGAS intends to acquire a 5-percent interest in the entire Wheatstone Project, comprising 5-percent interests in: Apache's and KUFPEC's offshore license WA-356-P, which contains the Julimar and Brunello fields; Chevron's Wheatstone field licenses; and the Wheatstone project facilities.
Including its equity participation and purchases from Apache, KUFPEC and Chevron, KOGAS expects to take delivery of a total of 1.95 mtpa of LNG from the Wheatstone project. Apache's share of the sales agreement with KOGAS is expected to be approximately 240,000 tons of LNG per year or 32 million cubic feet (MMcf) of natural gas per day.
Financial terms of the LNG sales and equity HoAs were not disclosed.
"Apache looks forward to working with KOGAS - the largest single LNG buyer in the world - as a project participant and LNG customer," said G. Steven Farris, Apache's chairman and chief executive officer. "These Heads of Agreement represent milestones in monetizing the Julimar and Brunello discoveries at prices linked to world oil prices and for Apache's participation as a foundation partner at Wheatstone; they also strengthen our role as a reliable future supplier of LNG."
Pending completion of final agreements with KOGAS, Apache owns a 65-percent interest in Julimar and Brunello, two of the company's largest discoveries; KUFPEC owns the remaining share.
Before the expected sell-down to KOGAS, Apache projected net sales at Wheatstone of approximately 190 MMcf of gas and 5,100 barrels of condensate per day with a 15-year production plateau.
In October 2009, Apache Julimar Pty Ltd, an Apache subsidiary, assumed a 16.25-percent equity interest in the Wheatstone project, and KUFPEC Australia (Julimar) Pty Ltd, a KUFPEC subsidiary, assumed an 8.75 percent interest in the project. These equity interests will be reduced as a consequence of KOGAS' participation. Chevron is responsible for marketing LNG from the Wheatstone Project.
The LNG facility's first phase will consist of two processing trains with a combined capacity of approximately 8.6 mtpa. It will be located at Ashburton North on the mainland of Western Australia. A final investment decision on the first phase of the project is slated for 2011, after front-end engineering and design is completed.
Apache and KUFPEC will develop facilities to supply gas from their Julimar and Brunello discoveries to Wheatstone. Apache will operate the design and construction phases of this part of the project.
Santos Ltd. said July 19 that it has secured a A$2 billion bank loan from nine lenders, increasing its capacity to fund its share of the construction of multibillion dollar liquefied natural gas plants in Queensland state and Papua New Guinea.
Santos said it will use the money to refinance A$700 million of existing undrawn bank facilities and increase its liquidity, giving it flexibility to fund its growth.
With the new facility, Santos said it will have A$6 billion of available funding capacity but wouldn't rule out raising more capital if it's needed.
Adelaide-based Santos owns 13.5% of the proposed US$15 billion PNG LNG project in Papua New Guinea and 60% of the proposed Gladstone LNG plant in Queensland, broadly estimated by analysts to cost between A$10 billion and A$15 billion to build.
A spokesman for the company said the debt raising gives Santos "significant additional liquidity", adding to existing facilities, last year's A$3 billion equity raising and several recent sales of non-core assets. He said the company has a number of funding options, "including an equity raising if needed".
Santos is currently in negotiations with a number of potential LNG buyers for the plant at Gladstone and has said it would like to sell any new customers some equity in the Gladstone project.
The need for another equity raising may be determined by the amount it manages to sell down, and for how much.
Santos Chief Executive David Knox said midway through last year that there was a "sporting chance" the company could cover its development costs without having to conduct another issue of new shares.
Despite the debt raising, CLSA energy analyst Di Brookman said Santos might still need to conduct a share issue around 2013, but much will depend on how much cash it gets for a piece of Gladstone, estimating that a 19.9% stake sale could bring in about A$800 million.
"If more project equity is sold the need for an issue could disappear," Brookman said.
Collaboration with rival projects at Gladstone, such as allowing rivals to build additional LNG production units on Santos' site, could also ameliorate any need for a share issue, she added.
China's Sinopec and Korea Gas Corp. have both confirmed that they've held offtake discussions with Santos. Media speculation has also pointed to possible LNG plant consolidation at Gladstone with rival project proposed Royal Dutch Shell PLC.
Santos responded to the speculation on July 9 by saying that its Gladstone project, being built in a joint venture with Malaysia's Petroliam Nasional Bhd., remains in "detailed ongoing discussions with a number of parties in relation to potential LNG sales, equity in the project and collaboration between projects".
The Santos spokesman declined to comment on how much Santos paid for its new loan, only saying that the lenders were a mix of existing and new, and local and offshore.
News of the loan turned Santos shares positive. They closed trading on July 19 up 0.4% at A$13.71 compared to a 1.5% fall in the broader market.
Coal Seam Gas (CSG) companies pushing to pipe liquefied natural gas from the Surat Basin to Gladstone have distanced themselves from a Kingaroy plant that has been shut down after tests found dangerous chemicals may had been leaked into underground water sources.
The Department of Environment and Resource Management (DERM) ordered Cougar Energy to close its underground coal gasification (UCG) plant near Kingaroy, after test bores detected benzene and toluene in the groundwater.
A spokesperson for QGC, the company behind the Queensland Curtis LNG (QCLNG) Project which was in mid-July asked by Federal Environment Minister Peter Garrett for more information on its environmental impacts, said UCG and coal seam gas extraction were not comparable processes as UCG burns coal underground while CSG extracts gas.
"We have long been concerned about the environmental acceptability of UCG and its potential to pollute groundwater," the QGC spokesperson said.
"QGC’s coal seam gas extraction operations in the Surat Basin do not involve the use of carcinogenic chemicals.
"We are confident that our operations pose no risk to groundwater supplies on which communities rely."
A spokesperson for Arrow, another company working on an LNG project in the Surat Basin, said DERM’s decision to close Cougar Energy’s USG plant has no bearing on Arrow Energy’s current activities or future plans.
"The coal seam gas and UCG industries are completely separate," the spokesperson said.
"It’s unfair to make any comparisons between the two because the technologies used by each industry in the gas extraction process are entirely different.
"We are increasing our stakeholder engagement activities and are currently preparing an Environmental Impact Statement which involves exhaustive studies to ensure appropriate measures are in place to minimize the impacts of our activities in the future.
"The Queensland Government has announced that it will enhance the existing groundwater management regime and Arrow has made a commitment to conducting extensive groundwater modeling, monitoring and consultation."
The construction schedule for the project will be finalized following the completion of Arrow’s takeover by Shell and PetroChina, due late next month.
On July 19, Natural Resources, Mines and Energy Minister Stephen Robertson met with senior representatives of the UCG sector in Queensland, to discuss the implications of the investigation underway at Cougar Energy’s trial plant near Kingaroy.
Mr Robertson told company representatives from Linc Energy, Carbon Energy - who run pilot projects near Chinchilla that while the circumstances of each project would be evaluated individually, Cougar Energy contamination incidents raised concerns for the whole sector.
"I indicated that the Government remained committed to undertaking a formal environmental evaluation of the UCG process at each site in Queensland, and our independent scientific expert panel will be undertaking a complete review of all three trials," Mr Robertson said.
The three UCG projects have been progressing under a supervised trial which was due to end in 2012.
"Today I made it clear that each company needs to understand we will take no risks when it comes to environmental performance and this will be the key factor in determining the future of Underground Coal Gasification in Queensland," Mr Robertson said.
Director-General John Bradley said the Department of Environment and Resource Management (DERM) had continued the review of water quality results received on July 18 and issued further statutory notices requiring the UCG companies to produce past water quality testing.
Farming groups have said the closure has justified farmers concerns about the environmental impacts of mining on agricultural land.
AgForce mining spokesman Drew Wagner said the farm organization has serious concerns about the government and resource industry’s lack of communication and understanding regarding the impact of resource exploration and extraction activities.
"AgForce continues to lead the way in voicing the concerns of farmers about the unknown consequences of resource extraction throughout the exponential growth of the coal seam gas industry, and today’s announcement is evidence that extraction activities have detrimental environmental concerns," Mr Wagner said.
"Although the Underground Coal Gasification process differs from the production of coal seam gas, it raises serious concerns about the lack of knowledge both the government and the resource industry have about the impact of mining practices on groundwater resources."
QFF CEO Dan Galligan said farmers have been very vocal in expressing that the underground water supply must be protected at all costs when underground gas is being extracted.
"The aquifer is a vital economic and environmental resource – and all sectors of the community deserve assurance that it is not being polluted.
LNP Shadow Minister for Natural Resources, Mines & Energy Jeff Seeney, who is the Member for Callide, said it wasn’t good enough for the Minister to ride into Kingaroy talking tough about the Cougar Energy coal gasification trial.
"There needs to be proper monitoring of all mining and gas activities especially in closely settled areas," Mr Seeney said.
"The Minister needs to ensure there are enough Departmental officers in the field to properly monitor all of the mining projects that are springing up across regional Queensland.
"This coal-to-gas project at Kingaroy was a trial of a new technology that had raised considerable concern … it should have been monitored more closely than most other mining projects.
"The fact that there was no Departmental officers monitoring this trial site raises questions about what monitoring the Department is doing in other areas.
"There are now serious questions about whether these Departments have the people with the skills to properly administer the mining boom," Mr Seeney said.
Chevron Corp. said July 26 its proposed Wheatstone liquefied natural gas plant will have a maximum annual production capacity of 25 million metric tons, which would surpass the Gorgon project as the biggest LNG development in Australia.
Developing the project at such a scale near the port of Onslow on the Pilbara coast, Western Australia, would reduce the need for future expansions by the company, and also "lessens the need for future LNG-related developments" nearby, Chevron said in a statement to regulators on the environmental impact of the Wheatstone project.
International energy companies are placing big bets on natural gas to capitalize on what they expect will be a surge in demand for cleaner-burning fuels. Australia's stable political environment, substantial gas reserves and proximity to fast-growing Asian economies make it an attractive place to invest, particularly with U.S. gas prices low in the wake of a flood of domestic gas supply.
In October, David O'Reilly, who was then Chevron's chairman and chief executive, said Australia by 2020 could drive profit for Chevron as much as U.S. operations do now. Chevron is also the operator of the Gorgon LNG project, which will have an annual processing capacity of 15 million tons of LNG and is utilizing reserves estimated around 40 trillion cubic feet of gas.
Chevron plans to build the Wheatstone plant in stages, but its comments recently suggest the U.S. oil major is confident of tying up additional volumes of gas from third parties or discovering vast new stores of gas in its offshore permits in Western Australia.
More than 6 trillion cubic feet of natural gas reserves have been discovered by Chevron and partners Apache Corp. and Kuwait Foreign Petroleum Exploration Co., or Kufpec, that will feed the Wheatstone project.
San Ramon, California-based Chevron this month announced two new natural gas strikes in waters close to Onslow, which it said underpinned its LNG projects in Western Australia, including Wheatstone.
Its plans for Wheatstone are also attracting the attention of competitors, including BHP Billiton PLC, which have undeveloped discoveries in the same area and are looking for cost-effective ways to bring that gas to market.
BHP Billiton Petroleum President Mike Yeager said in May that an option under consideration for its Scarborough gas discovery was to work with Chevron's Wheatstone project. BHP declined to comment further when contacted by Dow Jones Newswires recently.
In its environmental impact statement, Chevron said it remains on track to make a final investment decision on the Wheatstone project in the second half of 2011 and forecasts first gas production five years later.
The company has already concluded a string of offtake deals with North Asian consumers.
In July, Korea Gas Corp. signed a preliminary agreement with Chevron and partners to buy 1.5 million tons of LNG a year from Wheatstone over a period of up to 20 years.
Japanese utilities Tokyo Electric Power Co., known as Tepco, and Kyushu Electric Power Co. also have initial deals to buy LNG from Wheatstone.
The project includes a plant with a capacity of 625 million cubic feet of natural gas per day that will supply the domestic market, Chevron said. That's equivalent to around 15% of the project's LNG sales.
Chinese automaker Shaanxi Auto is cooperating with the CNOOC Gas and Power Group on a liquefied natural gas heavy-duty truck business, according to a report by 21st Century Business Herald.
Shaanxi Auto is responsible for developing LNG heavy-duty trucks for long-distance transportation companies, while CNOOC Gas and Power is expected to ensure LNG supply for the trucks by building LNG stations on their running routes.
Both the two companies refused to comment on the cooperation, saying only that the LNG vehicle technologies are mature now and they hope to gain the first-mover advantage in the LNG vehicle market.
Shaanxi Auto is applying to the central government to include LNG heavy-duty trucks into the new-energy vehicle subsidize program, Fu Guojian, a Shanghai dealer of Shaanxi Auto said, but refused to give the specific amount of the subsidy requested.
Huang Xianwen, director of a natural gas vehicle website in China, was confident about the development of the natural gas vehicle market. He predicted that China's natural gas vehicles in use would account for 30 per cent of the total vehicles in China by 2020.
In contrast, Sun Muzi, an auto analyst at Sinotrust Marketing Research and Consulting, was pessimistic about the development of the natural gas vehicle market, doubting the convenience of gas supply.
Zhou Ximin, deputy general manager of a gas company in Luoyang city of central China's Henan province, said that the biggest challenges for natural gas vehicle development are gas supply and future price changes, as under government control natural gas is likely to lose its price advantage over petroleum.
The CNOOC Gas and Power Group is a wholly owned subsidiary of the CNOOC Group, which is also the parent company of CNOOC Ltd.
Cnooc Gas & Power Group, a subsidiary of CNOOC, has started commercial operation of four gas-fired power generation units at its Putian plant in Fujian province, the company said in a statement on its official website.
Each of the four generators has a capacity of 390 megawatts and uses liquefied natural gas as feedstock from Cnooc's Fujian LNG gas terminal project, the company said.
Cnooc's Fujian LNG terminal has secured 2.6 million metric tons of LNG a year from Indonesia to supply to the domestic market under a long-term deal.
China Natural Gas Announces Successful Completion of Test Run and Ignition Ceremony of Jingbian LNG Terminal
China Natural Gas, Inc., a leading provider of compressed natural gas (CNG) for vehicular fuel and pipeline natural gas for industrial, commercial and residential use in Xi’an, China, announced July 3 that it successfully completed the single-machine test run and ignition ceremony of its Jingbian liquefied natural gas plant on June 30, 2010.
Mr. Qinan Ji, Chairman and CEO of China Natural Gas, commented, “It is with extraordinary pride that we happily announce the completion of the single-machine test run and ignition ceremony of the China Natural Gas Jingbian liquefied natural gas plant.
As a county, city and provincial-level key project, the plant endured once-in-a-century snowstorm, the May 12 earthquake, 2008 financial crisis and lasted 1,015 days to complete the single machine test run and ignition.
China Natural Gas recognized the accomplishment with an ignition ceremony at the plant, which marks a major milestone in its history and will soon activate an important asset in the future results of their business plan.
The plant is the only LNG plant in Shaanxi Province and one of the largest LNG plants in China.
China Natural Gas anticipates that the LNG plant will make a significant contribution to its business model by the end of the fiscal year 2010.
With the successful completion of the LNG plant single-machine test run and ignition, China Natural Gas is about to build its own LNG fueling stations, which will further its strategic vision of an integrated LNG operation that covers production, distribution and marketing.
They believe this strategy will place it in a highly advantageous position going forward in the competitive natural gas marketplace
Business Engineering and construction group Kentz has won a contract with Chicago Bridge and Iron and Clough to design and build a construction camp for a Papua New Guinea LNG project.
The Hides Gas Conditioning Plant project is an integrated development that includes gas production and processing facilities, onshore and offshore pipelines and liquefaction facilities with the capacity of 6.6million tonnes per year.
Participating interests include affiliates of ExxonMobil (including Esso Highlands Limited as operator, 33.2%), Oil Search Limited (29.0%) Independent Public Business Corporation (PNG Government, 16.6%), Santos Limited (13.5%), Nippon Oil Exploration (4.7%), Mineral Resources Development Company (PNG landowners, 2.8%) and Petromin PNG Holdings Limited (0.2%).
The first of Eidesvik's LNG-fuelled newbuilds will be delivered next year.
Kleven Maritime has entered into a contract with Eidesvik Offshore for the delivery of a VS 489 LNG design PSV. The contract also included an option for another similar vessel.
The vessels are to be outfitted at Kleven Verft in Ulsteinvik, Norway. Deliveries are set for the first quarter of 2011 and fourth quarter of 2012.
Kleven describes the new vessels as a new generation of environmentally friendly PSV with great emphasis on fuel economy, low emissions and large capacities both below and on deck.
Light ice class makes them suitable for northern waters. Sophisticated equipment for oil recovery and capacity for standby vessel further increases the market value. The new vessels will have a dead weight of 6,500 tonnes, length of 90m, beam of 21m, and deck space more than 1,050 m2.
Four LNG dual fuel engines will ensure low NOX emissions (an 85 per cent reduction) and significantly reduce CO2 emissions (a 25 per cent reduction).
The yard said a new state of the art ballast water treatment system would also be installed.
Wärtsilä is to supply the design, generators, automation and electrical power systems. The contracts will also provide orders for major local suppliers including Hareid Elektriske Teknikk and Brunvoll.
Foster Wheeler's Global Engineering and Construction Group has entered into a Framework Agreement, awarded by Statoil, acting on behalf of Gassco AS as operator for the Gassled joint venture, for front-end engineering design (FEED) services valid through 2013 to support the development of the Kårstø oil and gas processing plant in Norway. The Kårstø processing plant is ranked as the third largest liquid petroleum gas (LPG) export facility in the world. Statoil is modifying, on behalf of Gassco, the processing plant, via the Kårstø Life Extension project, to enable it to process new light oil/condensate production coming on stream in the Norwegian North Sea.
The Framework Agreement covers a series of different FEED projects. Foster Wheeler has been awarded the first FEED call-off contract for the Gudrun Onshore Modifications project, the objective of which is to enable the Kårstø plant to process light oil from the new Gudrun Field.
The Foster Wheeler contract value for the Gudrun Onshore Modifications FEED was not disclosed and will be included in the company's second-quarter 2010 bookings. The booking values for subsequent FEED awards will be recorded as individual call-off contracts are received.
"This Framework Agreement represents an important opportunity for Foster Wheeler to expand its relationship with Gassco and Statoil. We have the right upstream expertise and project execution skills to deliver high quality FEEDs for Gassco and Statoil and we also have a track record of project success in Norway and of building strong and long-lasting relationships through delivering excellence in alliance-type relationships," said Umberto della Sala, president and chief operating officer, Foster Wheeler AG.
Gassco is operator for the Kårstø terminal, which is owned by the Gassled joint venture, with Statoil as the technical service provider.
Alderley Systems has secured a contract worth more than six million pounds to provide a metering system at the new build LNG plant at Arzew in Algeria. Awarded by Italian company Saipem, the firm will design, manufacture and fabricate six metering skids at its UK systems workshop before shipping the equipment over to North Africa to be installed on site.
Construction of a new 4.7-million-tonne-a-year liquefaction train and associated infrastructure started on a brownfield site in the industrial zone of Arzew adjacent to the existing refinery in 2008. The plant at Arzew receives gas from the Gassi Touil fields in the Algerian desert.
Alderley's delivery is scheduled for mid 2011 and the team will be on site to commission the project at the beginning of 2012.
Chris McGeehan, managing director of Alderley Systems Group said, "This is a particularly exciting project for the team as we are using cryogenic metering of LNG at -160o C. Although this cutting edge technology is a fairly new concept, Alderley is leading the industry in this area and has already delivered several successful cryogenic LNG and the accompanying 'Boil Off Gas' metering packages in Qatar."
As part of the project at Arzew, Alderley Systems will deliver six ultrasonic metering packages consisting of a feed gas metering system, a butane metering system, a propane metering system, a gasoline metering system and two low temperature LNG metering systems. A further two metering control systems - one for the feed gas system and one for the five other systems, will also be supplied by the firm.
Chris continued, "Part of our success can be attributed to the fact that Alderley is a pioneering company. We are aware of the constant advances in metering technology and are using new innovations to our advantage.
Improving performance and increasing value for our clients has always been a priority. I'm pleased to say that this year so far has been very buoyant with several significant new pieces of business in the pipeline."
Following the government's overturn of an investments freeze in export gas projects, operators in the Nigerian petroleum industry are reactivating over $20 billion in three separate liquefaction projects.
The suspended projects which will soon see fresh investments include the seventh train of the Nigeria Liquefied Natural Gas (NLNG), the Brass LNG and the Olokola LNG.
The development came as NLNG breaks into the UK market with increasing traffic of LNG cargoes despite the reported downturn in the gas market in recent times.
The liquefaction projects are not new since they were already at initial site preparation stages before a policy shift resulted in ban on further investments in gas export projects.
Business Champion had reported that the present administration may have reversed previous policy directives issued the operators by former Petroleum Minister, Dr. Rilwan Lukman, which suspended gas export projects until domestic gas demand has been met.
The gas policy alteration which was announced by the sacked Group Managing Director of Nigerian National Petroleum Corporation (NNPC), Dr. Mohammed Barkindo, at an international conference in the Middle East caused investment freeze in the country as investors could no longer guarantee feedstock for the liquefaction projects.
But closer examination of the domestic gas policy and the implementation strategies had revealed that the export gas investment freeze had double standards that tended to favour certain investment groups over others, the most likely reason for the present administration to upturn it.
Investors whose monies had been stuck in some of the halted projects had protested the policy.
Managing Director of the Nigeria Liquefied Natural Gas (NLNG) Limited, Mr. Chima Ibeneche, had in calling for the reversal of the policy argued at an Industry conference that both the domestic and export gas projects could be pursued 'side by side.'
British Gas which is a new entrant in the Nigerian petroleum industry had reportedly threatened to pull its investments in Olokola LNG for reinvestments in Australia.
Arguments were also raised by multinational oil and gas producers who are under policy directive to valorize associated gas and cut emissions from flare booms that the ban on export projects at a time any alternative programme was yet to take off was defeating their efforts at flare reduction.
Part of publicized national aspirations in the petroleum industry is to commercialize the nation's vast natural gas resources estimated at 187 trillion standard cubic feet (TCF) and end routine flaring of associated gas.
Although the companies have repeatedly missed deadlines on gas flare out, all producers have been in a race to find commercial alternatives to gas flaring, and deep pocket investors have committed to liquefaction and export as viable ancillaries to oil production and export.
Apart from the six train NLNG operated by Shell on behalf of NNPC, Total and Eni, separate consortia have since initiated similar investments including the Olokola LNG (OKLNG) in Ondo State and the Brass LNG in Bayelsa State.
Attempts by the late President Umaru Yar'Adua's government to halt the planned seventh train by NLNG, the Ok-LNG and Brass LNG to secure gas feedstock for planned development of national distribution grid network was therefore criticized as illogical by experts who insist that there is enough feed-gas to drive all the projects.
Public presentations by former GMD of NNPC, Mr. Funso Kupolokun, noted that "Nigeria has abundant gas reserves which in energy terms are equivalent to its oil reserves. These reserves exceed the foreseeable needs of domestic, regional and international markets for gas."
According to the Kupolokun, "Although Nigeria is one of the most competitive sources of LNG to Europe and America, less than 40 percent of associated gas produced in Nigeria is commercialized. All the ongoing projects are expected to utilize 30-44 tcf of proven gas reserves of 187 tcf."
Mr. Ibeneche of NLNG had appealed to government to unlock investments in liquefaction and export in order to also generate the revenue needed to fund the white elephant Nigerian Gas MasterPlan (NGMP) for which the defunct Yar'Adua administration stopped export projects.
Part of the objectives for the development of the internal gas grid, according to NNPC, is to provide cheap, clean burning fuels for industrial consumption and to use it as incentive to develop industrial corridors along the pipeline routes.
However, with the change of government, the liquefaction projects appear to be back on track with Final Investment Decision (FID) for the Brass LNG becoming imminent.
Minister of Petroleum Resources, Mrs. Diezani Alison-Madueke, had said government hopes to see a final investment decision on the $6 billion Brass LNG by the end of 2010, and would also push ahead with the $7 billion Olokola LNG (OK-LNG) so it can fast-track commercial development of the country's natural gas resources.
Investment partners in the $6 billion Brass project, French Total, Italy's Eni and the US' ConocoPhillips, have so far delayed taking a final investment decision for a number of reasons, including issues relating to availability of gas for the plant.
Brass LNG involves building a two-train, 10 million metric tons per year gas liquefaction plant in southern Nigeria. Eni, Total and ConocoPhillips each have a 17 percent stake in the LNG, while NNPC controls 49 percent.
The four-train OK-LNG plant is to be built on the border of the southwest states of Ogun and Ondo by a joint venture of NNPC (46.75 percent), Chevron (19.5 percent), Shell (19.5 percent) and BG Group (14.25 percent).
OK-LNG was planned to start up with two trains of 6.3 million metric ton per year output capacity each. It would also produce 30,000 b/d of LPG and about 15,000 b/d of condensates.
Meanwhile the NLNG which is yet to achieve an FID on its seventh train has continued to recover its output to nameplate capacity of existing six trains after the downturn of 2009 when security tension in the Niger Delta affected both its feedstock and output.
NLNG has started a string of shipments that has started arriving in Europe while the UK's NBP gas hub emerged as one of the higher priced markets in Europe.
According to market reports, port data shows that NLNG vessels have added to receipts at UK terminals where cargo traffic is gathering momentum following a period of falling deliveries into Milford Haven's South Hook and Dragon terminals.
But that appears likely to change soon, given that a number of Nigerian shipments are headed to Dragon over the next few weeks.
Sources said the arrival of Nigeria's LNG Finima tanker June 3 marked the first-ever shipment from that country. And the arrival of two more tankers from Nigeria LNG's Bonny Island liquefaction plant signaled an emerging trend, sources said.
Nigeria's LNG Rivers, which can carry up to 137,231 cu m, was expected to berth Tuesday at Dragon. Another Nigerian cargo again aboard the LNG Finima was expected return to offload at Dragon on July 4, according to port data.
The trend in UK-bound Nigerian shipments comes after operator NLNG began ramping up production at its Bonny Island liquefaction plant, although a force majeure at the facility remains in effect.
Bonny Island's liquefaction capacity reportedly dropped to 50 percent last year, but is now increasing to between 70 percent and 80 percent of capacity.
NLNG first declared force majeure on LNG shipments in November 2008 because of the closure of the Shell operated Soku gas plant. As a result, NLNG had to forego production for 113 LNG cargoes and $2 billion (N300 billion) in revenue last year, a company official said.
As the highest-priced market in the Atlantic basin, the UK is attracting cargoes from as far afield as the Middle East and North Africa, which may also explain the flurry of Nigerian cargoes.
Israel will only build additional gas terminals if new discoveries are made, national infrastructure ministry director general Shaul Tsemach said July 6.
Tsemach said that the terminal for the Tamar field discovered last year should be located onshore in order to guarantee the gas reaches the local market in 2013 or 2014 at the very latest.
But, he said, Israel could not accommodate further onshore terminals.
He said, "Israel's coastal plain is far too crowded to accommodate all of the necessary infrastructure for the rapidly expanding natural gas industry," suggesting that future terminals will be built offshore.
His comments come as the country's national planning council is preparing to make a decision on the location of the planned natural gas receiving terminal for the Tamar and Dalit offshore fields.
Environmental groups and the Hof Hacarmel regional council have been campaigning against locating the terminal along the central Mediterranean coast at Dor. The council has been considering six onshore and one offshore option for location of the terminal.
Israeli energy industry sources have said that any further delay in deciding on a location of the terminal would impact the development of the Tamar field and the delivery of gas to Israeli customers.
Noble Energy and Israeli partners Delek Exploration, Avner Oil and Gas,
Isramco and Dor Gas have set a 2012 target for delivering gas from the field but the ministry believes this is overly optimistic.
In May, a ministry-commissioned study estimated the cost of producing natural gas from the Tamar field located off Israel's northern Mediterranean coast at $3.8 billion, $1 billion higher than estimates by the partners.
The report said that the cost could be even higher by $200-250 million if the onshore receiving terminal is not located at Dor, but at the existing terminal in Ashdodor at an offshore terminal.
The pressure at Tamar, which is among the highest in the world, is the major reason for the higher than expected cost of developing the field.
The report said the pressure issue will require construction of an offshore facility to reduce the gas pressure before its arrival onshore, in addition to the onshore gas pressure reduction facility at the receiving terminal. It also said that the need for the offshore facility could delay the delivery of gas to the Israeli market until 2015.
In March, Noble Energy chairman and CEO Charles Davidson said the final cost of developing Tamar will depend on the location of the onshore receiving terminal. Davidson said that the field will be completely subsea with the wells all along the ocean floor.
Plans call for initially drilling five wells with a daily production of 150 million cubic feet each at Tamar.
The field has estimated reserves of 238 billion cubic meters.
Major construction work at the Qatargas 4 liquefied natural gas facility and Pearl, the world's largest gas to liquids plant, will be completed by year end, with production ramping up in 2011, Royal Dutch Shell said on July 29.
Shell holds 30 percent of the 7.8 million tonne per year LNG project, known as train 7, with state-run Qatar Petroleum holding a 70 percent stake.
"Major construction at Pearl and Qatargas 4 will be completed by the end of this year with ramp up for both in 2011," Shell Chief Executive Peter Voser told journalists.
Qatargas, which is majority-owned by QP, said in mid June it was on track to start up train 7 by the last quarter of 2010, along with Qatargas 3 train 6 -- a 7.8 mpta facility in which Conoco (COP.N) holds a 30 percent stake.
When completed, trains 6 and 7 -- which are intended to supply Europe, Asia and the United States -- will cement Qatar's position as the world's biggest LNG exporter with an annual production capacity to 77 mpta.
LNG production facilities, known as trains, take several weeks to ramp up production because miles of pipes have to be cooled down before the gas can be chilled to liquid and such facilities have in the past begun producing gas before all construction was completed. Shell said in late 2009 it had delayed the start up of the $8 billion Qatargas 4 to late 2010, because contractors were struggling to keep up with the pace of developments in Qatar's booming gas industry.
The delay helped reduce oversupply in the global LNG market in early 2010, with widespread summer maintenance at existing Qatari production facilities helping drive up LNG spot prices and the UK gas market. [NG/GB]
Prices have fallen in the weeks since the maintenance outages ended, and the start up of two new big plants in early 2011 could drive down prices further.
Pearl, which is also a joint development by Qatar Petroleum and Shell, will process about three billion barrels-of-oil-equivalent over its lifetime from the huge North Field stretching from the Qatari coast into the Gulf.
Pearl GTL will produce diesel and kerosene, lubricant oils, naphtha and paraffin.
McIlvaine Company,
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